ENTERGY MISSISSIPPI, LLC - Quarter Report: 2005 September (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 an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

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 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 Entergy must purchase for its utility customers
• 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 effects 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
• the outcome of the Chapter 11 bankruptcy proceeding of Entergy New Orleans, and the impact, if any, 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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Certain abbreviations or acronyms used in the text are defined below:

DEFINITIONS (Continued)

DEFINITIONS (Concluded)

In August and September 2005, Hurricane Katrina and Hurricane Rita caused catastrophic damage to portions of Entergy'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. The storms and flooding resulted in widespread power outages, significant damage to distribution, transmission, generation, and gas infrastructure, and the loss of sales and customers due to mandatory evacuations and the destruction of homes and businesses. Total restoration costs for the repair and/or replacement of Entergy's electric and gas facilities damaged by Hurricanes Katrina and Rita and business continuity costs are estimated to be in the range of $1.1 billion to $1.4 billion. The cost estimates do not include other potential incremental losses, such as the losses resulting from the loss of sales and customers.  Entergy plans to pursue a broad range of initiatives to recover storm restoration and business continuity costs and incremental losses. Initiatives include obtaining reimbursement of certain costs covered by insurance, obtaining assistance through federal legislation for Hurricane Rita as well as Hurricane Katrina, and pursuing recovery through existing or new rate mechanisms regulated by the FERC and local regulatory bodies. 

Entergy has recorded accruals for the estimated storm restoration costs.  As of September 30, 2005, Entergy recorded an increase of $585.5 million in construction work in progress and $514.5 million in other regulatory assets, with a corresponding increase of $1.1 billion in accounts payable.  In accordance with its accounting policies, and based on historic treatment of such costs in its service territories and communications with local regulators, Entergy recorded these assets because management believes that recovery through some form of regulatory mechanism is probable. Because Entergy has not gone through the regulatory process regarding these storm costs, however, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs and incremental losses it may ultimately recover, or the timing of such recovery.

The temporary power outages associated with the hurricanes in the affected service territory caused Entergy Louisiana's and Entergy New Orleans' sales volume and receivable collections to be lower than normal in September 2005. Revenues are expected to continue to be affected for a period of time that cannot yet be estimated as a result of the 36,000 customers at Entergy Louisiana and 87,000 customers at Entergy New Orleans that are unable to accept electric and gas service and as a result of changes in load patterns that could occur, including the effect of residential customers who can accept electric and gas service not permanently returning to their homes. As reported in the Form 10-K, as of December 31, 2004 Entergy Louisiana had 662,000 electric customers and Entergy New Orleans had 189,000 electric customers and 145,000 gas customers. Restoration for many of the customers who are unable to accept service will follow major repairs or reconstruction of customer facilities, and will be contingent on validation by local authorities of habitability and electrical safety of customers' structures. Annual non-fuel revenues associated with customers who are currently unable to accept electric and gas service are estimated to be $171 million. Entergy's estimate of the revenue impact is subject to change, however, because of a range of uncertainties, in particular the timing of when individual customers will return to service.

Entergy's non-nuclear property insurance program provides coverage up to $400 million on an Entergy system-wide basis, subject to a $20 million per occurrence self-insured retention, for all risks coverage for direct physical loss or damage, including boiler and machinery breakdown.  Covered property generally includes power plants, substations, facilities, inventories, and gas distribution-related properties. Excluded property generally

includes above-ground transmission and distribution lines, poles, and towers. The primary property program (excess of the deductible) is placed through Oil Insurance Limited ($250 million layer) with the excess program ($150 million layer) placed on a quota share basis through Underwriters at Lloyds (50%) and Hartford Steam Boiler Inspection and Insurance Company (50%).  There is an aggregation limit of $1 billion for all parties insured by OIL for any one occurrence. Coverage is in place for Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy Gulf States, and Entergy New Orleans. Entergy is currently evaluating the amount of the covered losses for Entergy and each of the affected domestic utility companies

Because of the effects of Hurricane Katrina, on September 23, 2005, Entergy New Orleans filed a voluntary petition in the United States Bankruptcy Court for the Eastern District of Louisiana seeking reorganization relief under the provisions of Chapter 11 of the United States Bankruptcy Code (Case No. 05-17697). Entergy owns 100 percent of the common stock of Entergy New Orleans, has continued to supply operating management, and has provided debtor-in-possession financing to Entergy New Orleans and, accordingly, believes these factors represent significant influence over Entergy New Orleans. However, uncertainties surrounding the nature, timing, and specifics of the bankruptcy proceedings have caused Entergy to deconsolidate Entergy New Orleans and reflect Entergy New Orleans' financial results under the equity method of accounting 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 for 2005 being presented as "Equity in earnings (loss) 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. Entergy reviewed the value of its investment in Entergy New Orleans to determine if an impairment had occurred as a result of the storm, the flood, the power outages, restoration costs and changes in customer load. Entergy determined that as of September 30, 2005, no impairment had occurred because, as discussed above, management believes that recovery is probable.  Entergy will continue to assess the carrying value of its investment in Entergy New Orleans as developments occur in Entergy New Orleans' recovery efforts.

Entergy's consolidated earnings applicable to common stock for the third quarter and nine months ended September 30, 2005 and 2004 were as follows:

Entergy's income before taxes is discussed below according to the operating segments listed above. See Note 8 to the consolidated financial statements herein for more information concerning Entergy's operating segments and their financial results in 2005 and 2004.

As discussed above, due to the filing for bankruptcy protection under Chapter 11 by Entergy New Orleans, it has been deconsolidated retroactive to January 1, 2005, and its 2005 results of operations are presented as a component of Equity in Earnings of Unconsolidated Equity Affiliate.  The variance explanations in this ENTERGY CORPORATION AND SUBSIDIARIES - MANAGEMENT'S DISCUSSION AND ANALYSIS - Results of Operations, reflect the 2004 results of operations of Entergy New Orleans consistent with the 2005 presentation as Equity in Earnings of Unconsolidated Equity Affiliate. Entergy's as reported consolidated results for 2004 and the amounts included for Entergy New Orleans, which exclude inter-company items, are set forth in the table below (in thousands).

*Reflects the effects of deconsolidation of Entergy New Orleans for 2004. The adjustment includes intercompany eliminations.

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

The increase in earnings for the U.S. Utility for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004 from $568.7 million to $601.1 million was primarily due to higher net revenue partially offset by higher other operation and maintenance expenses and lower other income.

Net revenue, which is Entergy's measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related expenses and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing the third quarter of 2005 to the third quarter of 2004.

The volume/weather variance is primarily due to more favorable weather, partially offset by a decrease in weather-adjusted electricity usage totaling 242 GWh in the residential, commercial, and governmental sectors. The decrease in weather-adjusted usage is primarily due to Hurricane Katrina and Hurricane Rita. Industrial sales volume also declined primarily due to the expected loss of one large customer to cogeneration.

Gross operating revenues increased from $2.3 billion for the third quarter 2004 to $2.5 billion for the third quarter 2005. The increase includes an increase in fuel cost recovery revenues of $100.5 million resulting primarily from increases in the market prices of natural gas and purchased power. As such, this revenue increase is offset by an increase in fuel and purchased power expenses. An increase in gross wholesale revenue and the volume/weather variance, discussed above, also contributed to the increase in gross operating revenues. Gross wholesale revenues increased $37 million primarily due to an increase in the average price of energy.

Net revenue, which is Entergy's measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related expenses and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory credits. Following is an analysis of the change in net revenue comparing the nine months ended September 30, 2005 to the nine months ended September 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. 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 volume/weather variance resulted primarily from more favorable weather. Billed usage increased a total of 1,007 GWh in the residential and commercial sectors. The increase was partially offset by decreased usage during the unbilled period and a decrease in industrial sales volume due to the expected loss of one large customer to cogeneration. 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 to a 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 is due to the 2004 energy cost recovery true-up, made in the first 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 Gulf States.

Gross operating revenues increased from $5.9 billion for the nine months ended September 30, 2004 to $6.3 billion for the nine months ended September 30, 2005. The increase includes an increase in fuel cost recovery revenues of $256.3 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. An increase in gross wholesale revenues and the factors that increased net revenue discussed above also contributed to the increase in gross operating revenues. Gross wholesale revenues increased $31 million primarily due to an increase in the average price of energy supplied for resale sales.

Other operation and maintenance expenses decreased from $369.4 million for the third quarter 2004 to $326.1 million for the third quarter 2005 primarily due to:

• a decrease of $15.7 million related to proceeds received from a settlement, which is discussed further in "Significant Factors and Known Trends - Central States Compact Claim;" and
• a decrease of $14.4 million due to a shift in labor and material costs from normal maintenance work to storm restoration work.

Other income decreased from $54.4 million for the third quarter 2004 to $42.6 million for the third quarter 2005 primarily due to:

• a revision in 2004 to the estimated decommissioning cost liability for River Bend in accordance with a new decommissioning cost study that reflected a life extension for the plant. For the portion of River Bend not subject to cost-based ratemaking, the revised estimate resulted in the elimination of the asset retirement cost that had been recorded at the time of adoption of SFAS 143 with the remainder recorded as miscellaneous income of $27.7 million;
• a decrease of $6.5 million in equity in earnings of Entergy New Orleans, which is now reported as an unconsolidated equity affiliate. The decrease in earnings is primarily a result of lower net revenue and a higher effective income tax rate partially offset by lower other operation and maintenance expenses; and
• a decrease of $6.5 million in the allowance for equity funds used during construction as a result of an adjustment for prior years to include short-term debt in the calculation of the allowance for equity funds used during construction rate for the years 2001 through 2004 in addition to lower construction expenditures.

The decrease was partially offset by an increase of $22.1 million in interest and dividend income due to proceeds from the radwaste settlement, which is discussed further in "Significant Factors and Known Trends - Central States Compact Claim," and increased interest on temporary cash investments.

Other operation and maintenance expenses increased from $1.05 billion for the nine months ended September 30, 2004 to $1.08 billion for the nine months ended September 30, 2005 primarily due to:

• an increase of $32.3 million in payroll and benefits costs;
• an increase of $11.9 million in fossil expenses as a result of additional planned off-peak fossil generation maintenance outages;
• an increase of $10.2 million in nuclear expenses for contract and material costs associated with maintenance outages and nuclear refueling outage pre-work; 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.

The increase was partially offset by:

• a decrease of $14.4 million due to a shift in labor and material costs from normal maintenance work to storm restoration work; and
• a decrease of $15.7 million related to proceeds received from the radwaste settlement, which is discussed further in "Significant Factors and Known Trends - Central States Compact Claim."

Taxes other than income taxes increased from $230.2 million for the nine months ended September 30, 2004 to $239.5 million for the nine months ended September 30, 2005 due primarily to higher employment taxes and higher assessed values for ad valorem tax purposes in 2005.

Other income decreased from $117.5 million for the nine months ended September 30, 2004 to $101.1 million for the nine months ended September 30, 2005 primarily due to:

• a revision in 2004 to the estimated decommissioning cost liability for River Bend in accordance with a new decommissioning cost study that reflected a life extension for the plant. For the portion of River Bend not subject to cost-based ratemaking, the revised estimate resulted in the elimination of the asset retirement cost that had been recorded at the time of adoption of SFAS 143 with the remainder recorded as miscellaneous income of $27.7 million;
• a decrease of $11.9 million in equity in earnings of Entergy New Orleans, which is now reported as an unconsolidated equity affiliate. The decrease in earnings is primarily a result of lower net revenue and higher depreciation and amortization expenses; and
• 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.

The decrease was partially offset by an increase of $32.5 million in interest and dividend income due to proceeds from the radwaste settlement, which is discussed further in "Significant Factors and Known Trends - Central States Compact Claim" and increased interest on temporary cash investments.

Interest on long-term debt decreased from $282.6 million for the nine months ended September 30, 2004 to $270.3 million for the nine months ended September 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.

Following are key performance measures for Non-Utility Nuclear for the third quarter and nine months ended September 30, 2005 and 2004:

The increase in earnings for Non-Utility Nuclear from $63.7 million to $69.3 million was primarily due to an increase in revenues due to power uprates at several plants, lower operation and maintenance expenses, and the effects of higher generation associated with fewer planned and unplanned refueling and maintenance outages. The increase in earnings was partially offset by miscellaneous income of $11.9 million net-of-tax resulting from a reduction in the decommissioning liability for a plant in 2004.

The increase in earnings for Non-Utility Nuclear from $195.5 million to $205.5 million was primarily due to miscellaneous income of $15.8 million net-of-tax resulting from a reduction in the decommissioning liability for a plant in 2005, as discussed in Note 1 to the consolidated financial statements. Also contributing to the increase in earnings was higher pricing in its contracts to sell power and power uprates at several plants. The increase in earnings was partially offset by miscellaneous income of $11.9 million net-of-tax resulting from a reduction in the decommissioning liability for a plant in 2004.

The increase in earnings for Parent Company & Other Business Segments from a $9.6 million loss to $1.5 million in earnings was primarily due to a loss in 2004 from Entergy's investment in Entergy-Koch as a result of the inability of Entergy-Koch Trading to apply hedge accounting to certain contracts and $14.4 million of tax benefits in 2005 from the American Job Creations Act of 2004. Partially offsetting the increase was the favorable settlement of a tax issue, which increased earnings by $11 million in the first quarter of 2004.

The effective income tax rates for the nine months ended September 30, 2005 and 2004 were 35.7% and 36.7%, respectively. The difference in the effective income tax rate for the nine months ended September 30, 2005 versus the federal statutory rate of 35.0% is primarily due to state income taxes and regulatory plant differences on utility plant items, partially offset by 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 nine months ended September 30, 2004 versus the federal statutory rate of 35.0% is primarily due to state income taxes and regulatory plant differences on utility plant items, partially offset by the favorable settlement of a tax audit issue and investment tax credit amortization.

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.

The Form 10-K reported that Entergy expected to contribute $185.9 million in 2005 to its pension plans. Entergy has elected to make additional contributions, and now expects to contribute $253.3 million to its pension plans in 2005 and early 2006 in accordance with recent pension funding relief issued by the IRS. Entergy contributed $146.2 million to its pension plans during the nine months ended September 30, 2005.

As discussed in the Form 10-K, in 2003, the domestic utility companies and System Energy filed, with the IRS, notification of a change in tax accounting method for their respective calculations of cost of goods sold. The adjustment implemented a simplified method of allocation of overhead to the production of electricity, which is provided under the IRS capitalization regulations.  The cumulative adjustment placing these companies on the new methodology resulted in a $2.8 billion deduction on Entergy's 2003 income tax return.  There was no tax cash benefit from the method change in 2003.  In addition, on a consolidated basis, no cash tax benefit was realized in 2004 and none will be realized in 2005.  The Internal Revenue Service has issued new proposed regulations effective in 2005 that may preclude most of the benefit of this tax accounting method change.

As discussed above, Hurricanes Rita and Katrina impacted Entergy's service territory.  Total restoration costs for the repair and/or replacement of Entergy's electric and gas facilities damaged by Hurricanes Katrina and Rita and business continuity costs are estimated to be in the range of $1.1 billion to $1.4 billion. The cost estimates do not include other potential incremental losses, such as the losses resulting from the loss of sales and customers. As a result of power outages associated with the hurricanes in the affected service territory, revenues were lower and receivable collections were significantly lower than normal in September 2005. Entergy expects that revenues will continue to be affected by the estimated 123,000 customers that are unable to accept electric and/or gas service for a period of time that cannot yet be estimated. Entergy plans to pursue a broad range of initiatives to recover storm restoration costs. Initiatives include obtaining reimbursement of certain costs covered by insurance, obtaining assistance through federal legislation for Hurricane Rita as well as Hurricane Katrina, and pursuing recovery through existing or new rate mechanisms regulated by the FERC and local regulatory bodies. Because Entergy has not gone through the regulatory process regarding these storm costs, there is an element of risk regarding their recovery, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs and incremental losses it may ultimately recover, or the timing of such recovery.

In addition to storm restoration costs, Hurricanes Katrina and Rita have had three impacts that have affected the U.S. Utility's liquidity position. The Entergy New Orleans bankruptcy caused fuel and power suppliers to increase their scrutiny of the remaining domestic utility companies with the concern that one of them could suffer similar impacts, particularly after Hurricane Rita. As a result, some suppliers began requiring accelerated payments and decreased credit lines. The hurricanes damaged certain gas supply lines, thereby decreasing the number of potential suppliers. Finally, the hurricanes exacerbated a market run up in natural gas and power prices, thereby increasing the U.S. Utility's accounts payable, which consumed available credit lines more quickly. The U.S. Utility managed through these events, adequately supplied the Entergy System with fuel and power, and expects to have adequate liquidity and credit to continue supplying the Entergy System with fuel and power.

Entergy has announced a new financing plan to source from $2.5 to $3.0 billion through a combination of debt and equity linked securities intended to provide adequate liquidity and capital resources to Entergy and its subsidiaries while storm restoration cost recovery is pursued. In addition, the plan is intended to provide adequate liquidity and capital resources to support Entergy Nuclear and the competitive retail business. The plan, which Entergy expects to implement over the next several months, will include 1) increasing the capacity on Entergy Corporation's credit revolver by up to $1.5 billion; 2) issuing $0.5 to $1.0 billion of equity linked securities; 3) issuing up to $0.5 billion of new debt at various utility operating companies; and 4) providing funding in the amount of $300 million from Entergy Corporation to Entergy Gulf States.

Borrowings under the DIP credit agreement are due in full, and the agreement will terminate, at the earliest of (i) August 23, 2006, or such later date as Entergy Corporation shall agree to in its sole discretion, (ii) December 10, 2005, if a final order that is satisfactory to Entergy Corporation approving the DIP Credit Agreement shall not have been entered on or prior to such date, (iii) the acceleration of the loans and the termination of the DIP credit agreement in accordance with its terms, (iv) the date of the closing of a sale of all or substantially all of Entergy New Orleans' assets pursuant to section 363 of the United States Bankruptcy Code or a confirmed plan of reorganization, or (v) the effective date of a plan of reorganization in Entergy New Orleans' bankruptcy case.

As security for Entergy Corporation as the lender, all borrowings by Entergy New Orleans under the DIP credit agreement are: (i) entitled to superpriority administrative claim status pursuant to section 364(c)(1) of the Bankruptcy Code; (ii) secured by a perfected first priority lien on all unencumbered property of Entergy New Orleans pursuant to section 364(c)(2) of the Bankruptcy Code; (iii) secured by a perfected junior lien pursuant to section 364(c)(3) of the Bankruptcy Code on all property of Entergy New Orleans subject to perfected and non-avoidable liens that existed as of the date Entergy New Orleans filed its bankruptcy petition; and (iv) secured by a perfected first priority, senior priming lien pursuant to section 364(d)(1) of the Bankruptcy Code on all property of Entergy New Orleans that is subject to valid, perfected and non-avoidable liens that existed as of the date Entergy New Orleans filed its bankruptcy petition; provided, however, that the superpriority liens granted to Entergy Corporation pursuant to section 364(d)(1) of the Bankruptcy Code shall not be effective unless and until the bankruptcy court issues a final order approving the DIP credit agreement, in which case such priming liens shall be deemed to have been effective as of the date Entergy New Orleans filed its bankruptcy petition.  The bankruptcy court scheduled a hearing for December 7, 2005 to consider entry of an order granting final approval of the DIP Credit Agreement, including the priority and lien status of the indebtedness under that agreement.

The interest rate on borrowings under the DIP credit agreement will be the average interest rate of borrowings outstanding under Entergy Corporation's $2 billion revolving credit facility, which currently is approximately 4.6% per annum.

Events of default under the DIP credit agreement include: failure to make payment of any installment of principal or interest when due and payable; the occurrence of a change of control of Entergy New Orleans; the failure of Entergy Corporation to receive, on or prior to November 30, 2005, approval from the SEC regarding the charging of interest under the DIP credit agreement; failure by either Entergy New Orleans or Entergy Corporation to receive other necessary governmental approvals and consents; the occurrence of an event having a materially adverse effect on Entergy New Orleans or its prospects; and customary bankruptcy-related defaults, including, without limitation, appointment of a trustee, "responsible person," or examiner with expanded powers, conversion of Entergy New Orleans' chapter 11 case to a case under chapter 7 of the Bankruptcy Code, and the interim or final orders approving the DIP Credit Agreement being stayed or modified or ceasing to be in full force and effect.

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 September 30, 2005 is primarily the result of increased debt outstanding due to additional borrowings on Entergy Corporation's $2 billion revolving credit facility along with a decrease in shareholders' equity, primarily due to repurchases of common stock, both of which are discussed below.

In May 2005, Entergy Corporation terminated its 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 five-year revolving credit facility, which expires in May 2010. As of September 30, 2005, $1.07 billion in borrowings were outstanding on this facility. Entergy also has the ability to issue letters of credit against the borrowing capacity of the credit facility, and letters of credit totaling $209 million had been issued against this facility at September 30, 2005. The total unused capacity for this facility as of September 30, 2005 was approximately $721 million. 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.

Entergy Arkansas, Entergy Louisiana and Entergy Mississippi each have 364-day credit facilities available as follows:

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

As discussed in the Form 10-K, Entergy's ability to guarantee obligations of Entergy's non-utility subsidiaries is also limited by SEC regulations under PUHCA. In September 2005, the SEC issued an order, effective through the effective date of PUHCA repeal, February 8, 2006, that increases the amount of guarantees that Entergy can issue for the benefit of its non-utility companies from $2 billion to $3 billion.

See the table in the Form 10-K under "Liquidity and Capital Resources - Capital Expenditure Plans and Other Uses of Capital," which sets forth the amounts of planned construction and other capital investments by operating segment for 2005 through 2007.

As a result of Hurricanes Katrina and Rita, Entergy is currently reassessing its planned levels of construction and other capital investments. Significant construction expenditures are expected due to the restoration and replacement of damaged equipment and assets.

In March 2005, Entergy Mississippi signed an agreement to purchase for $88 million the Attala power plant, a 480 MW natural gas-fired, combined-cycle generating facility owned by Central Mississippi Generating Company (CMGC). Entergy Mississippi plans to invest approximately $20 million in facility upgrades at the Attala plant plus $3 million in other costs, bringing the total capital cost 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 previously executed a purchased power agreement in July 2004 for 100 percent of the plant's output, and this agreement will expire upon the close of the acquisition or in March 2008, whichever occurs earlier.

Cash Flow Activity

As shown in Entergy's Statements of Cash Flows, cash flows for the nine months ended September 30, 2005 and 2004 were as follows:

Entergy's cash flow provided by operating activities decreased by $606 million for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004 primarily due to a decrease at the U.S. Utility. The U.S. Utility provided $821 million in cash from operating activities in 2005 compared to providing $1.3 billion in 2004. The decrease resulted primarily from the disruption of collection of receivables due to Hurricanes Katrina and Rita and changes in the timing of fuel cost recovery compared to the prior period. Also contributing to the decrease in the U.S. Utility segment were an increase of $93 million in income tax payments, an increase of $78 million in pension plan contributions, and the $90 million refund to customers in the Louisiana jurisdiction made as a result of an LPSC-approved settlement. The Non-Utility Nuclear segment also contributed to the decrease. The Non-Utility Nuclear segment provided $394 million in cash from operating activities in 2005 compared to providing $425 million in 2004.

Investing activities used $1.2 billion of cash for the nine months ended September 30, 2005 compared to using $943 million of cash for the nine months ended September 30, 2004 primarily due to the following activity:

Financing activities provided $84 million of cash for the nine months ended September 30, 2005 compared to using $735 million of cash for the nine months ended September 30, 2004 primarily due to the following activity:

• Net issuances of long-term debt by the U.S. Utility segment provided $165 million during the nine months ended September 30, 2005 compared to retirements of long-term debt net of issuances using $334 million during the nine months ended September 30, 2004. See Note 4 to the consolidated financial statements for the details of long-term debt activity in 2005.
• Entergy Corporation increased the net borrowings on its credit facility by $1.02 billion during the nine months ended September 30, 2005 compared to $100 million during the nine months ended September 30, 2004. See Note 4 to the consolidated financial statements for a description of the Entergy Corporation credit facility.
• Entergy Corporation repurchased $878 million of its common stock during the nine months ended September 30, 2005 compared to $416 million during the nine months ended September 30, 2004. See Part II, Item 2 herein and in the First and Second Quarter 2005 Forms 10-Q for details regarding Entergy Corporation's common stock repurchases in 2005.
• Net borrowings on credit facilities in the U.S. Utility segment increased by $40 million during the nine months ended September 30, 2005 compared to $110 million during the nine months ended September 30, 2004. See Note 4 to the consolidated financial statements for a description of the Entergy Corporation credit facility.

In March 2005, the LPSC approved a settlement proposal to resolve various dockets covering a range of issues for Entergy Gulf States and Entergy Louisiana. 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 related to the nuclear plant uprates at issue in these cases, and an LPSC docket concerning retail issues 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 $2 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 issued 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. The LPSC has filed a motion to dismiss the appeal, which is pending. On October 14, 2005, Entergy Gulf States intervened in the case and filed exceptions seeking summary dismissal. A hearing on the exceptions filed by the LPSC and Entergy Gulf States was set for October 31, 2005, but was continued at the request of counsel for the plaintiffs.

In June 2005, Entergy Gulf States made its formula rate plan filing with the LPSC for the test year ending December 31, 2004. The filing shows a net revenue deficiency of $2.58 million indicating that no refund liability exists. The filing also indicates that a prospective rate increase of $23.8 million is required in order for Entergy Gulf States to earn the authorized ROE mid-point of 10.65%. A revision to the filing was made in September 2005 resulting in a $37.2 million base rate increase effective with the first billing cycle of October 2005. The base rate increase consists of two components. The first is a base rate increase of approximately $21.1 million due to the formula rate plan 2004 test year revenue requirement that reflects certain adjustments. The second component of the increase is the recovery of the annual revenue requirement of $16.1 million associated with the purchase of power from the Perryville generating station, which purchase was approved by the LPSC. Subject to the consideration of comments filed by the LPSC staff and intervenors in the third quarter 2005, additional rate changes associated with the formula rate plan may take effect with the first billing cycle in November 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 July 2005 and refunded excess revenue collected during May 2005, including interest, in August 2005.

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%.

Entergy Gulf States filed with the PUCT in July 2005 a request for implementation 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' obligation to purchase power from Entergy Louisiana's recently acquired Perryville plant, over what is already in Entergy Gulf States' base rates. Entergy Gulf States reached an initial agreement with parties that the date upon which cost recovery and cost reconciliation would begin is 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. A further non-unanimous settlement was reached with most of the parties that allows for the rider to be implemented effective December 1, 2005 and collect $18 million annually. The settlement also provides for a fuel reconciliation to be filed by Entergy Gulf States by May 15, 2006 that will resolve the remaining issues in the case with the exception of the amount of purchased power in current base rates and the costs to which load growth is attributed, both of which were settled. The hearing with respect to the non-unanimous settlement, which was opposed by the Office of Public Utility Counsel, was conducted on October 19, 2005 before the ALJ who will issue a proposal for decision which could either recommend to the PUCT acceptance or rejection of the settlement. 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 to file for recovery of transition to competition costs.

In May 2005, the MPSC approved a joint stipulation entered into between the Mississippi Public Utilities Staff and Entergy Mississippi regarding Entergy Mississippi's annual formula rate plan filing that provides for no change in rates based on a performance adjusted ROE mid-point of 10.50%, establishing an allowed regulatory earnings range of 9.1% to 11.9%.

In April 2005, Entergy New Orleans made its annual scheduled formula rate plan filings with the City Council.  The filings showed that a decrease of $0.2 million in electric revenues was warranted and an increase of $3.9 million in gas revenues was warranted. In addition, in May 2005, Entergy New Orleans filed with the City Council a request for continuation of the formula rate plan and generation performance-based rate plan (G-PBR) for an additional three years. The filing requested a target equity component of the capital structure of 45%, an increase from the current target of 42%. In August 2005, Entergy New Orleans, the City Council advisors, and the intervenors entered into an agreement in principle which provided, among other things, for a reduction in Entergy New Orleans' electric base rates of $2.5 million and no change in Entergy New Orleans' gas base rates. The agreement provided for the continuation of the electric and gas formula rate plans for two more annual cycles, effective September 1, 2005, with a target equity ratio of 45% as well as a mid-point return on equity of 10.75%, and a 100 basis point band-width around the mid-point for electric operations and a 50 basis point band-width around the mid-point for gas operations. The agreement in principle also called for the continuation and modification of the G-PBR by separating the operation of the G-PBR from the formula rate plan so that the core business' electric rates are not set on a prospective basis by reference to G-PBR earnings. The agreement in principle provides for a $4.5 million cap on Entergy New Orleans' share of G-PBR savings. The G-PBR plan has been temporarily suspended due to impacts from Hurricane Katrina.

On June 1, 2005, the FERC issued 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 terms of the System Agreement, which has been approved by the FERC. The System Agreement litigation proceedings are described in the Form 10-K.

The FERC decision concluded, among other things, that:

• The System Agreement no longer roughly equalizes production costs among the domestic utility companies.
• In order to reach rough production cost equalization, 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 cost 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 for that year but 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 production costs.
• The remedy ordered by FERC calls for no refunds and would be effective based on the calendar year 2006 production costs with the first potential reallocation payments, if required, expected to be made in 2007.

The FERC's June 2005 order would reallocate 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 more than 11% above Entergy System average production costs. An assessment of the potential effects of the FERC's June 2005 order requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include 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 Arkansas is the least 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 costs of the domestic utility companies.  Considerable uncertainty exists regarding future gas prices. Annual average Henry Hub gas prices have varied significantly over recent years, ranging from $1.72/mmBtu to $5.85/mmBtu for the 1995-2004 period, and averaging $3.43/mmBtu during the ten-year period 1995-2004 and $4.58/mmBtu during the five-year period 2000-2004.  Recent market conditions have resulted in 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, which is the annual period closest to the time that the FERC's order was issued, forward gas contracts for each 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). If the FERC's June 2005 order becomes final and if gas prices occur similar to the NYMEX average closing prices given, the following potential annual production cost reallocations among the domestic utility companies could result during the 2007-2010 period:

If natural gas prices deviate by $1/mmBtu up or down from the NYMEX average closing prices given above, it is expected that Entergy Arkansas' annual payments will change in the same direction by approximately $60 to $70 million.

Various pending motions for rehearing and clarification of the FERC's June 2005 order were filed by parties to the proceeding, including the LPSC, the APSC, the MPSC, and the City Council, and by Entergy Services, Inc., on behalf of the domestic utility companies. Among other things, the LPSC's motion urged the FERC to "clarify" that the FERC's order requires the payments and receipts, to the extent any are required, 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 urging the FERC to reject this interpretation and instead find that 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. On September 27, 2005 the LPSC filed a Petition for Writ of Mandamus with the U.S. Court of Appeals for the D.C. Circuit urging the appeals court to order the FERC to "implement a remedy no later than January 1, 2006," or to "at least clarify its ruling by November 15, 2005 concerning the effective date of the rate remedy provided in FERC's June 2005 order." The appeals court has requested the FERC respond to the petition by November 5, 2005 and has also granted requests of the APSC, MPSC, and the domestic utility companies to be authorized to submit a response by that date as well.

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 for a discussion of the petition for declaratory order that Entergy filed with the FERC in January 2005 regarding Entergy's 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 conditions." 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.

On 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. 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, 2005 the FERC issued an order clarifying certain aspects of its March 22 order. In the May 12 order, the FERC indicated that (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 the 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, protests, and comments were filed by interested parties on August 5, 2005. Entergy filed a response to the various pleadings on August 22, 2005. As discussed below in "Available Flowgate Capacity Proceedings," on October 31, 2005 the domestic utility companies notified parties to the ICT proceeding of the potential loss of historical data related to Entergy's calculation of available transfer capability for its transmission system.

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 was held during the week of October 16, 2005. Post-hearing briefs are currently scheduled to be filed on November 7, 2005, with reply briefs scheduled to be filed November 14, 2005.

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 control 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. On November 1, 2005, Entergy submitted proposed cost-based rates for both the domestic utility companies and Entergy's non-regulated entities that sell at wholesale within the Entergy control area. Additionally, Entergy reserves its right to request market-based rate authority for sales within its control area in the future. The relinquishment of market-based rates for sales within the Entergy control area is not expected 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.

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.

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 would 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 with the establishment of the ICT. See "Transmission" above for further discussion of AFC.

On October 31, 2005, the domestic utility companies notified participants in the ICT proceeding that certain historic data related to the hourly AFC models may have been inadvertently lost due to errors in the implementation of a data archiving process. The data at issue is certain hourly AFC data for the nine-month period April 27, 2004 through January 31, 2005. Although Entergy is continuing to pursue all avenues for recovery and retrieval of the historic hourly data, it is difficult to predict whether and to what extent these efforts will ultimately be successful. Since discovering the potential loss of data, the domestic utility companies have taken steps to ensure that these errors cannot recur and to ensure that the current AFC hourly data, including the hourly data from February 1, 2005 forward, is adequately protected and retained. Entergy self-reported the event to the FERC's Office of Market Oversight and Investigations and is providing information to the investigation staff concerning this event. Additionally, Entergy will request that the ICT review the current process for retaining AFC-related data as part of its independent review discussed above.

Previous developments and information related to electric industry restructuring are presented in Note 2 to the consolidated financial statements in the Form 10-K. The following are updates to the Form 10-K.

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

• Entergy Gulf States is authorized by the legislation to proceed with a jurisdictional separation into two vertically integrated utilities, one subject solely to the retail jurisdiction of the LPSC and one subject solely to 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," 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.

As authorized by the legislation discussed above, in August 2005, Entergy Gulf States filed with the PUCT an application for recovery of its transition to competition costs. Entergy Gulf States requested recovery of $189 million in transition to competition costs through implementation of a 15-year rider to be effective no later than March 1, 2006. The $189 million represents transition to competition costs Entergy Gulf States incurred 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 transition to competition costs through February 28, 2006. The $189 million is before any gross-up for taxes or carrying costs over the 15-year recovery period. This matter has been set for hearing beginning in February 2006, with a PUCT decision expected during the third quarter of 2006. In addition, the ALJ is scheduled to conduct a hearing on November 14, 2005 with respect to the proposed implementation on an interim rider which would become effective in March 2006 to collect transition to competition costs.

The Energy Policy Act of 2005 became law in August 2005. The legislation contains electricity provisions that, among other things:

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. FERC has proposed rules to implement the repeal of PUHCA. The Energy Policy Act of 2005 requires that these rules be adopted by December 8, 2005. Among other matters, the proposed rules cover the maintenance and retention of books and records and accounting, the allocation of costs for non-power goods or services provided by affiliated service companies and the appropriate pricing mechanism for those goods and services, and the effect of the savings provision in the Energy Policy Act of 2005 which permits continued reliance on certain PUHCA rules and orders after the effective date of PUHCA repeal. In Entergy's response in the FERC rulemaking proceeding, Entergy indicated that (a) FERC should only require the maintenance and retention of those books and records that are relevant to costs incurred by, and the jurisdictional rates of, electric utility and natural gas companies, as specified in the Energy Policy Act of 2005, (b) FERC should not require, but instead permit, the filing with FERC of affiliate cost allocation agreements for non-power goods and services and the price for those goods and services should be the SEC's cost standard under PUHCA and (c) under the savings provision, certain orders issued by the SEC under PUHCA with a term past February 8, 2006 (the date PUHCA repeal is effective) should continue to be in effect until the end of the term in the order.

Power Generation

As discussed more fully in the Form 10-K, the sale of electricity from the power generation plants owned by Entergy's Non-Utility Nuclear business and Energy Commodity Services, unless otherwise contracted, is subject to the fluctuation of market power prices. Following is an updated summary of the amount of Non-Utility Nuclear's output that is sold forward as of September 30, 2005 under physical or financial contracts (2005 represents the remainder of the year):

The Vermont Yankee acquisition included a 10-year PPA under which the former owners will buy the power produced by the plant, which is through the expiration in 2012 of the current operating license for the plant. The PPA includes an adjustment clause under which the prices specified in the PPA will be adjusted downward monthly, beginning in November 2005, if power market prices drop below PPA prices.

Non-Utility Nuclear's purchase of the Fitzpatrick and Indian Point 3 plants from NYPA included a value sharing agreement with NYPA. Under the value sharing agreement, to the extent that the average annual price of the energy sales from each of the two plants exceeds specified strike prices, the Non-Utility Nuclear business will pay 50% of the additional revenue to NYPA. The annual energy sales subject to the value sharing agreement are limited to the lesser of actual generation or generation assuming an 85% capacity factor based on the plants' capacities at the time of the purchase. The value sharing agreement is effective through 2014, which is the end of the current operating licenses for the plants. The strike prices for Fitzpatrick range from $37.51/MWh in 2005 increasing by approximately 3.5% each year to $51.30/MWh in 2014, and the strike prices for Indian Point 3 range from $42.26/MWh in 2005 increasing by approximately 3.5% each year to $57.77/MWh in 2014.

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 may 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 sell 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 forms of collateral.  At September 30, 2005, based on power prices at that time, Entergy had in place as collateral $1,681 million of Entergy Corporation guarantees, $206.3 million of which support letters of credit. The assurance requirement associated with Non-Utility Nuclear is estimated to increase by an amount up to $425 million if gas prices increase $1 per MMBtu across the entire forward curve. In the event of a decrease in Entergy Corporation's credit rating to specified levels below investment grade, Entergy may be required to replace Entergy Corporation guarantees with cash or letters of credit under some of the agreements.

In 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 the amount of the Non-Utility Nuclear business' installed capacity that is currently sold forward, and the blended amount of the Non-Utility Nuclear business' planned generation output and installed capacity that is currently sold forward as of September 30, 2005:

The Low-Level Radioactive Waste Policy Act 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 early 1988, 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 of 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 $145 million, including interest, to the Compact, and the Compact distributed from the settlement proceeds $23.6 million to Entergy Arkansas, $19.9 million to Entergy Gulf States, and $19.4 million to Entergy Louisiana.  The proceeds caused an increase in pre-tax earnings of $28.7 million.

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, pension and other postretirement benefits, and other contingencies. The following is an update to the information provided in the Form 10-K.

In the first quarter of 2005, Entergy's Non-Utility Nuclear business recorded a reduction of $26.0 million in its decommissioning cost liability in conjunction with a new decommissioning cost study as a result of revised decommissioning costs and changes in assumptions regarding the timing of the decommissioning of a plant. The revised estimate resulted in miscellaneous income of $26.0 million ($15.8 million net-of-tax), reflecting the excess of the reduction in the liability over the amount of undepreciated assets.

In the second quarter of 2005, Entergy Louisiana recorded a revision 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.

In the third quarter of 2005, Entergy Arkansas recorded a revision to its estimated decommissioning cost liability for ANO 2 in accordance with the receipt of approval by the NRC of Entergy Arkansas' application for a life extension for the unit. The revised estimate resulted in an $87.2 million reduction in its decommissioning liability, along with a corresponding reduction in the related regulatory asset.

In the third quarter of 2005, System Energy recorded a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for Grand Gulf.  The revised estimate resulted in a $41.4 million reduction in the decommissioning cost liability for Grand Gulf, along with a $39.7 million reduction in utility plant and a $1.7 million reduction in the related regulatory asset.