Entergy - 10-Q quarterly report FY

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DEFINITIONS (Continued)

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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.

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. Due to the November 2006 expiration of contingencies on the sale of Entergy-Koch's trading business, and the corresponding release to Entergy-Koch of sales proceeds held in escrow, Entergy expects to record a gain related to this investment of approximately $60 million, net-of-tax, in the fourth quarter of 2006. 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.

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• A final confirmation order from the bankruptcy court approving the plan of reorganization;
• Implementation of a City Council resolution that is satisfactory to Entergy New Orleans regarding its formula rate plan gas and electric filings and its proposed storm cost recovery and storm reserve riders;
• Receipt by Entergy New Orleans of insurance proceeds of at least $250 million or assurance of such receipt, or alternatively, assurance that regulatory mechanisms will be put in place to cover any shortfall in insurance proceeds;
• Receipt by Entergy New Orleans of $200 million in CDBG funding and assurance that at a minimum an additional $200 million in CDBG funding will be available for future gas system rebuild or assurance from the City Council that an appropriate rate mechanism is in place to allow Entergy New Orleans to recover the costs thereof;
• No material adverse change shall have occurred from and after the confirmation date of the plan of reorganization; and
• Entergy New Orleans receives a final order from the FERC authorizing issuance of short-term debt securities under credit agreements, the Entergy System money pool, and unilateral arrangements with Entergy Corporation.

In addition, key factors that will continue to influence the timing and outcome of Entergy New Orleans' recovery efforts include the level of economic recovery of New Orleans and the number of customers that return to New Orleans, including the timing of their return. Entergy New Orleans currently estimates that approximately 85,000 electric customers and 65,000 gas customers have returned and are taking service. Prior to Hurricane Katrina, Entergy New Orleans had approximately 190,000 electric customers and 145,000 gas customers.

The bankruptcy judge set a date of April 19, 2006 by which creditors with prepetition claims against Entergy New Orleans, with certain exceptions, had to file their proofs of claim in the bankruptcy case. Approximately 550 claims, including amending 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. Several of the filed claims have been withdrawn. Entergy New Orleans currently estimates that the pre-petition claims that will be allowed in the bankruptcy case will approximate the pre-petition liabilities that have been classified as liabilities subject to compromise in Entergy New Orleans' Balance Sheet as of September 30, 2006. The plan of reorganization proposes to pay the third party pre-petition accounts payable in full in cash, to issue two-year notes in satisfaction of the affiliate pre-petition accounts payable, and proposes that the first mortgage bonds will remain outstanding with their current maturity dates and interest terms. The plan of reorganization proposes that Entergy New Orleans' preferred stock will also remain outstanding on its current dividend terms.

Municipalization is one potential outcome of Entergy New Orleans' recovery effort that may be pursued by a stakeholder or stakeholders, either in the reorganization process or after Entergy New Orleans exits from bankruptcy. In June 2006, the Louisiana Legislature passed a law that establishes a governance structure for a public power authority, if municipalization of Entergy New Orleans' utility business is pursued. Entergy New Orleans' settlement of its formula rate plan and storm cost and reserve rider proceedings, discussed further below, provides that Entergy New Orleans will work with the City Council to seek an exception to the Stafford Act that will afford Stafford Act protections to Entergy New Orleans if another catastrophic event affects Entergy New Orleans. The Stafford Act provides for restoration funding from the federal government for municipal utilities, but does not allow such funding for investor-owned utilities like Entergy New Orleans.

Since the filing of the bankruptcy proceedings, Entergy New Orleans had 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 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

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 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. Entergy New Orleans declared and paid the dividends due on July 1 and October 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.

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.

Results of Operations

Third Quarter 2006 Compared to Third Quarter 2005

Following are income statement variances for Utility, Non-Utility Nuclear, Parent & Other business segments, and Entergy comparing the third quarter 2006 to the third quarter 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 third quarter of 2006 to the third quarter of 2005.

The base revenues variance resulted primarily from increases effective October 2005 in the Louisiana jurisdiction of Entergy Gulf States 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 in the Texas jurisdiction of Entergy Gulf States 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 price applied to unbilled electric sales variance is due to higher base rates and 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 a decrease in net revenue of approximately $30 million for its annual results for 2006. See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates" herein.

The volume/weather variance resulted primarily from an increase in electricity usage, including increased usage during the unbilled sales period. Billed usage increased a total of 3% compared to the third quarter of 2005.

The pass-through rider revenue variance is due to a change in 2006 in the accounting for city franchise tax revenues in Arkansas as directed by the APSC. The change results in an increase in rider revenue with a corresponding increase in taxes other than income taxes, resulting in no effect on net income.

The purchased power capacity variance is primarily due to higher capacity charges and new purchased power contracts in 2006. A portion of the increase is due to the amortization of deferred capacity costs and is offset in base revenues due to base rate increases implemented to recover incremental deferred and ongoing purchased power capacity charges, as discussed above.

The net wholesale variance is primarily due to an October 2006 FERC order requiring Entergy Arkansas to make a refund to a coal plant co-owner as a result of a contract dispute. Refer to Note 2 to the consolidated financial statements for further discussion of the FERC's decision.

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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 a power uprate completed since the third quarter of 2005 and fewer outages. Following are key performance measures for Non-Utility Nuclear for the third quarters of 2006 and 2005:

Other Operation and Maintenance Expenses

Other operation and maintenance expenses increased for the Utility from $326 million in 2005 to $420 million in 2006 primarily due to the following:

• an increase of $29 million in payroll and benefits costs;
• the receipt in 2005 of proceeds of $16 million from a settlement, which is discussed in "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Central States Compact Claim" in the Form 10-K;
• an increase of $14 million due to the expensing of plant maintenance and distribution costs in 2006 versus the deferral or capitalization of storm costs in 2005;
• an increase of $6 million in nuclear costs as a result of higher NRC fees, security costs, and labor-related costs;
• an increase of $6 million related to loss reserves, primarily storm reserves. The increase in storm reserves does not include costs associated with Hurricanes Katrina and Rita; and
• an increase of $4 million in customer service support costs primarily due to an increase in contract costs.

Taxes Other Than Income Taxes

Taxes other than income taxes increased for the Utility from $82 million for the third quarter of 2005 to $118 million for the third quarter of 2006 primarily due to an increase in city franchise taxes in Arkansas due to a change in 2006 in the accounting for city franchise tax revenues as directed by the APSC. The change results in an increase in taxes other than income taxes with a corresponding increase in rider revenue, resulting in no effect on net income. Also contributing to the increase was higher franchise tax expense at Entergy Gulf States as a result of higher gross revenues.

Other Income

Other income increased for Non-Utility Nuclear primarily due to miscellaneous income of $27.0 million ($16.6 million net-of-tax) resulting from a reduction in the decommissioning liability for a plant as a result of revised decommissioning costs and changes in assumptions regarding the timing of when decommissioning of a plant will begin.

Income Taxes

Following are income statement variances for Utility, Non-Utility Nuclear, Parent & Other business segments, and Entergy comparing the nine months ended September 30, 2006 to the nine months ended September 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.

Net Revenue

Utility

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

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The base revenues variance resulted primarily from increases effective October 2005 in the Louisiana jurisdiction of Entergy Gulf States 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 in the Texas jurisdiction of Entergy Gulf States 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 volume/weather variance resulted primarily from increased electricity usage, including the effect of more favorable weather on billed sales, compared to the same period in 2005 and an increase in usage during the unbilled period. Billed usage increased a total of 2% in the residential and commercial sectors.

The pass-through rider revenue variance is due to a change in 2006 in the accounting for city franchise tax revenues in Arkansas as directed by the APSC. The change results in an increase in rider revenue with a corresponding increase in taxes other than income taxes, resulting in no effect on net income.

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. The increase was partially offset by the Entergy Arkansas energy cost recovery true-up made in the first quarter of 2005.

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 in early-2006 as allowed by the LPSC.

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 a decrease in net revenue of approximately $30 million for its annual results for 2006. See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates" herein.

The net wholesale variance is primarily due to an October 2006 FERC order requiring Entergy Arkansas to make a refund to a coal plant co-owner as a result of a contract dispute. Refer to Note 2 to the consolidated financial statements for further discussion of the FERC's decision.

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 nine months ended September 30, 2006 and 2005:

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.

As discussed in the Form 10-K, Entergy Corporation has in place two separate revolving credit facilities, a five-year credit facility and a three-year credit facility. The five-year credit facility expires in May 2010 and the three-year facility expires in December 2008. Entergy can issue letters of credit against the total borrowing capacity of both credit facilities. Following is a summary of the borrowings outstanding and capacity available under these facilities as of September 30, 2006:

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Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and Entergy Mississippi each has credit facilities available as of September 30, 2006 as follows:

See Note 4 to the consolidated financial statements for additional discussion of Entergy's 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 planned construction and other capital investments by operating segment for 2006 through 2008. Following are updates to that discussion:

In July 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 $380 million. Entergy's Non-Utility Nuclear business will acquire the plant, nuclear fuel, and other assets. In the near-term, Entergy intends to finance the acquisition through borrowings from Entergy Corporation's revolving credit facilities. As part of the purchase, Entergy's Non-Utility Nuclear business also executed a 15-year purchased power agreement with Consumers Energy for 100% of the plant's output, excluding any future uprates. Entergy's Non-Utility Nuclear business will assume responsibility for eventual decommissioning of the plant. Consumers Energy will retain $200 million of the current $566 million Palisades decommissioning trust fund balance, and Entergy may return approximately $100 million more 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 decommissioned Big Rock nuclear plant, which is located near Charlevoix, Michigan. Management expects to close the transaction in the second quarter 2007, pending the approvals of the NRC, the FERC, the Michigan Public Service Commission, and other regulatory agencies.

Entergy is developing its capital plan for 2007 through 2009 and currently anticipates making $5.2 billion in capital investments during that period, including approximately $2.5 billion ($2.3 billion for Utility and $0.2 billion for Non-Utility Nuclear) for maintenance of Entergy's existing assets. The remaining $2.7 billion ($1.9 billion for Utility and $0.8 billion for Non-Utility Nuclear) is associated with specific investments such as the pending Palisades acquisition, transmission upgrades, dry cask storage and license renewal projects at certain nuclear sites, environmental compliance spending, NYPA value sharing costs and other investments, such as potential opportunities through the Utility's supply plan initiatives that support its ability to meet load growth.

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The Pension Protection Act of 2006

The Pension Protection Act of 2006 was signed by the President on August 17, 2006. The intent of the legislation is to require companies to fund 100% of their pension liability; and then for companies to fund, on a going-forward basis, an amount generally estimated to be the amount that the pension liability increases each year due to an additional year of service by the employees eligible for pension benefits. The legislation requires that funding shortfalls be eliminated by companies over a seven-year period, beginning in 2008.

The Pension Protection Act also extended the provisions of the Pension Funding Equity Act that would have expired in 2006 had the Pension Protection Act not been enacted, which increased the allowed discount rate used to calculate the pension funding liability. Entergy is in the process of evaluating the effects of the new legislation, but expects that the implementation of the Pension Protection Act will not result in annual pension contributions going-forward that are materially higher than the levels required in 2005 and 2006.

Operating Activities

Entergy's cash flow provided by operating activities increased by $1,150 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005 primarily due to the following activity:

• Utility provided $1,683 million in cash from operating activities in 2006 compared to providing $821 million in 2005 primarily due to increased recovery of fuel costs, the receipt of an income tax refund (discussed below), and the effect in 2005 of a $90 million refund paid to customers in Louisiana, partially offset by storm restoration spending and an increase of $146 million in pension funding payments.
• Non-Utility Nuclear provided $648 million in cash from operating activities in 2006 compared to providing $394 million in 2005 primarily due to an increase in net revenue and an increase in income tax refunds received.

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, as discussed in the Form 10-K. In accordance with Entergy's intercompany tax allocation agreement, $273 million of the refund was distributed to the Utility (including Entergy New Orleans) in April 2006, with the remainder distributed primarily to Non-Utility Nuclear.

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 Note 2 to the financial statements 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 railroad delivery problems.

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 did 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.

In June 2006, Entergy Arkansas filed a motion with the APSC seeking again 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.

On June 7, 2006, Entergy Arkansas filed a cost of service study and testimony supporting the redetermined energy cost rate and testimony addressing the prospective elimination of the energy cost recovery rider as ordered by the APSC. A hearing was held in the APSC energy cost recovery investigation on October 12, 2006 and post-hearing briefs were filed by Entergy Arkansas, the APSC General Staff, the Arkansas Attorney General, and the Arkansas Electric Energy Consumers. No party recommended termination of the energy cost recovery rider in the fuel cost investigation proceeding. The timing of a decision in this proceeding is uncertain.

In August 2006, Entergy Arkansas filed with the APSC a request for a change in base rates. Entergy Arkansas requested a general base rate increase of $150 million (using an ROE of 11.25%), as well as recovery of FERC-allocated costs pursuant to the FERC decision on the System Agreement. Entergy Arkansas also requested a capacity management rider to recover incremental capacity costs. A procedural schedule has been established with hearings expected to begin in April 2007.

See "System Agreement Litigation" herein for a discussion of Entergy's compliance filing in that proceeding. If the FERC approves the compliance

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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 proposed in the August 2006 base rate case 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, would ensure that Entergy Arkansas customers pay only the amount allocated by the FERC.

Entergy Gulf States-Louisiana

In January 2006, Entergy Gulf States filed with the LPSC its gas rate stabilization plan. The filing showed a revenue deficiency of $4.1 million based on an ROE mid-point of 10.5%. On May 1, 2006, Entergy Gulf States implemented a $3.5 million rate increase pursuant to an uncontested agreement with the LPSC Staff.

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 revenue requirement increase of $36.8 million and calls for Entergy Gulf States to apply a refund liability of $0.7 million to capacity deferrals. The refund liability pertained to the periods 2004-2005 as well as the interim period in which a $37.2 million revenue increase was in place.

In May 2006, Entergy Gulf States made its formula rate plan filing with the LPSC for the 2005 test year. Entergy Gulf States modified the filing in August 2006 to reflect an 11.1% return on equity which is within the allowed bandwidth. The modified filing includes a formula rate plan increase of $17.2 million which provides for interim recovery of storm costs from Hurricanes Katrina and Rita and recovery of LPSC-approved incremental deferred and ongoing capacity costs. The increase was implemented, subject to refund, with the first billing cycle of September 2006.

Entergy Gulf States -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 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 Texas 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. 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 Enterg y 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 2006, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2005 test year. Entergy Louisiana modified the filing in August 2006 to reflect a 9.45% return on equity which is within the allowed bandwidth. The modified filing includes an increase of $24 million for interim recovery of storm costs from Hurricanes Katrina and Rita and a $120 million rate increase to recover LPSC-approved incremental deferred and ongoing capacity costs. The filing requested recovery of approximately $50 million for the amortization of capacity deferrals over a three-year period, including carrying charges, and approximately $70 million for ongoing capacity costs. The increase was implemented, subject to refund, with the first billing cycle of September 2006. Comments were provided by the LPSC Staff, which Entergy Louisiana is currently reviewing. Entergy Louisiana subsequently updated its formula rate plan rider to reflect adjustments proposed by the LPSC Staff with which it agrees. The adjusted return on equity of 9.56% remains within the allowed bandwidth. Ongoing and deferred incremental capacity costs were reduced to $119 million. The updated formula rate plan rider was implemented, subject to refund, with the first billing cycle of October 2006.

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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 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 was implemented in August 2006.

Entergy New Orleans

In June 2006, Entergy New Orleans made its annual formula rate plan filings with the City Council.  The filings presented 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 the City Council's June 2006 decision to allow recovery of all Grand Gulf costs through the fuel adjustment clause stays in place during the rate-effective period (a significant portion of Grand Gulf costs was previously recovered through base rates).

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 sought to recover the electric and gas restoration costs that it had actually spent through March 31, 2006. Entergy New Orleans also proposed semiannual filings to update the rider for additional restoration spending and also to consider the receipt of CDBG funds or insurance proceeds that it may receive. With the second rider, Entergy New Orleans sought to establish a storm reserve to provide for the risk of another storm.

In October 2006 the City Council approved a settlement agreement that resolves Entergy New Orleans' rate and storm-related rider filings by providing for phased-in rate increases, while taking into account with respect to storm restoration costs the anticipated receipt of CDBG funding as recommended by the Louisiana Recovery Authority. The settlement provides for a 0% increase in electric base rates through December 2007, with a $3.9 million increase implemented in January 2008. Recovery of all Grand Gulf costs through the fuel adjustment clause will continue. Gas base rates will increase by $4.75 million in November 2006, an additional $1.5 million in March 2007, and an additional $4.75 million in November 2007. The settlement calls for Entergy New Orleans to file a base rate case by July 31, 2008. Any storm costs in excess of CDBG funding and insurance proceeds will be addressed in that base rate case. A storm cost recovery rider is authorized but initially set at $0 because of the anticipated receipt of CDBG funding. The settlement also authorizes a $75 million storm reserve for damage from future storms, which will be created over a ten-year period through a storm reserve rider beginning in March 2007. These storm reserve funds will be held in a restricted escrow account.

Federal Regulation

System Agreement Litigation

See the Form 10-K for a discussion of the System Agreement litigation 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 to provide for the calculation of production costs, average production costs, and payments/receipts among the domestic utility companies to the extent required to maintain rough production cost equalization pursuant to the FERC's decision, and makes clear that all payments/receipts will be classified as energy costs. The payments/receipts would be based on calendar year 2006 production costs, with any payments/receipts among the domestic 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

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 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 utility 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 Syst em 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 decision 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 completion of briefing during the first half of 2007. 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 more than the Entergy System average production cost, with payments going first to those domestic utility companies whose total production costs are farthest above the Entergy System average. For purposes of the August 2006 Entergy Arkansas general base rate case filing discussed above in "State and Local Rate Regulation", an assessment of the potential effects of the FERC's June 2005 order, as amended by its December 2005 order on rehearing, was calculated on the basis of a 2006 test year, using a 2006 gas price that consisted of a non-we ighted average of twelve months of gas prices calculated as follows: January through May 2006 were actual, volume-weighted monthly averages of day-ahead cash prices as reported by Energy Intelligence Natural Gas Week; the June 2006 price was the First of the Month Index price as reported by Platts Inside FERC's Gas Market Report; the July 2006 price was the 5/31/06 NYMEX Henry Hub settlement price; and August through December 2006 were 30 calendar-day rolling averages as of May 31, 2006 of forward NYMEX Henry Hub gas contracts.  For example, the August 2006 price was an average of all the daily NYMEX settlement prices for the August 2006 contract for each trading day from the period 5/2/06 - - 5/31/06 inclusive.  A similar calculation was made using the daily settlements of the September 2006 through December 2006 NYMEX contracts to arrive at those monthly prices. This resulted in an average annual gas price of $7.49/mmBtu. If the FERC's June 2005 order, as amended by its December 2005 order on rehearing, becomes final and if an annual average gas price of $7.49/mmBtu occurs for 2006 as assumed, the following potential annual production cost reallocation among the domestic utility companies could result:

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If the actual, annual, average natural gas price deviates by $1/mmBtu up or down from the price assumed above, it is expected that Entergy Arkansas' annual payments will change in the same direction by approximately $70 to $80 million.

In 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 Entergy 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.

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.

In July 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 the 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 has acted prud ently. As further indicated in the domestic utility companies' answer, following the issuance of the FERC's System 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 to roughly equalize production costs. The domestic utility companies' answer further explains that based on well-established

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Supreme Court precedent, the FERC has exclusive jurisdiction over all inputs that will be included in the System Agreement bandwidth formula rates filed in 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 have intervened in the proceeding, including the MPSC, the LPSC, and the City Council. The LPSC's answer and comments in response to the APSC complaint ask the FERC to investigate whether Entergy Arkansas' withdrawal from the System Agreement is fair, just, and reasonable. In September 2006, the domestic utility companies, the APSC, and other intervenors in the proceeding filed responses to the answers and comments submitted by the various intervenors in July 2006. In their responses, the APSC and the LPSC, among others, argue that the FERC need not address at this time its jurisdiction over the matters raised by the complaint and further that the retail regulators are not preempted from exercising jurisdiction over those same production costs that are being considered in the proceeding. In October 2006, the domestic utility companies filed an answer to the other parties' September 2006 comments. In the October 2006 answer, the domestic utility companies explain, among other things, that the FERC must address the jurisdictional issues raised by the parties to the proceeding and that the LPSC's and APSC's view concerning jurisdiction and preemption are inconsistent with federal law and regulation.

APSC System Agreement Investigation

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 benefits 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 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 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 describe actions taken since December 19, 2005 to encourage or persuade the FERC to authorize Entergy Arkansas to exit the Entergy System Agreement sooner than 96 months, and to describe current and future actions related to development of a replacement system agreement. Responsive testimony was filed with the APSC in July and August 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. There is no further procedural schedule set in this investigation at this time.

MPSC System Agreement Inquiry

In response to an inquiry from the MPSC, Entergy Mississippi advised the MPSC of its view that it would be premature to decide at this time whether to terminate Entergy Mississippi's participation in the current System Agreement. Entergy Mississippi indicated that it would report to the MPSC during the first quarter of 2007 regarding its continuing evaluation of the issues concerning Entergy Mississippi's participation in the current System Agreement.

Independent Coordinator of Transmission (ICT)

In April 2006 the FERC issued an order approving with modification Entergy's ICT proposal filed in May 2005. In its order, the FERC: (1) approved the establishment of the ICT, 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 filed requests for rehearing of the FERC order.

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The proposed modifications include, among other things: (1) Entergy must file with the FERC the criteria used to grant and deny transmission service, including calculating available flowgate capacity; (2) the FERC extended the initial term of the ICT from two years to four years; and Entergy is precluded from terminating the ICT prior to the end of the four-year period; (3) the 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 process and models under the direction of the ICT; (4) with regard to any dispute between the ICT and Entergy concerning transmission service requests, transmission planning, and interconnection requests, the ICT'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 m ay reevaluate all approvals to proceed with the ICT. In September 2006, the FERC issued orders that generally denied the requests for rehearing relating to the ICT Proposal and related matters at the FERC. The domestic utility companies filed a request for clarification of two discrete issues arising from the FERC order on rehearing related to the ICT Proposal.

Entergy's domestic utility companies made their compliance filing with the FERC on May 24, 2006, including the executed ICT agreement with SPP. The domestic utility companies informed the FERC that, assuming they have received all required approvals, the domestic utility companies intend to install SPP as the ICT within 30 days of FERC approval of the ICT agreement. Several parties filed protests regarding the domestic utility companies' compliance filing. On October 18, 2006, the FERC accepted the domestic utility companies' compliance filing, with modification, and directed the domestic utility companies to install SPP as the ICT within 30 days of the order. The required changes to the compliance filing include, among others, the elimination of provisions that would have, in certain limited instances, allowed the ICT to be terminated during the initial four-year term. The domestic utility companies were also ordered to file certain additional information with the FERC and to sub mit the required changes to the compliance filing. The domestic utility companies anticipate installing the ICT within 30 days of the FERC order as directed by the FERC.

The LPSC voted to approve the ICT proposal in July 2006.

Available Flowgate Capacity (AFC) Proceeding

See the Form 10-K for a discussion of previous activity in this proceeding. Following the notification of the potential loss by the domestic utility companies of AFC data, a separate, non-public investigation was initiated by the FERC to review the domestic utility companies' record retention policies and practices. In October 2006, the FERC Office of Enforcement issued an audit report addressing the domestic utility companies' compliance with the FERC's records retention regulations. The audit report notes the following: (i) one instance where the domestic utility companies' treatment of a contract failed to comply with a FERC-imposed record retention period and notification requirement; (ii) one instance where the domestic utility companies temporarily lost an individual record but were subsequently able to reproduce it; (iii) four instances where records were retained for the full period required by the FERC, but may have been inadvertently lost prior to a retention period requir ed by a different agency or the domestic utility companies' internal retention requirements; and (iv) a limited number of instances where the domestic utility companies' internal policies could be improved. The findings and recommendations in the audit report, which were agreed to by the domestic utility companies, represent a consensual resolution of the audit. Although these findings are not indicative of any significant areas of non-compliance, the domestic utility companies believe that the audit staff's recommendations will improve the records retention program and therefore agreed to implement the audit staff's recommendations. Additionally, as previously reported in the Form 10-K, during SPP's independent audit of the AFC process limited instances were identified in which transmission service either was granted when there was insufficient transmission capacity or was not granted when there was sufficient transmission capacity. These instances were self-reported to the FERC enforcement staff. As a result of the domestic utility companies' further review of these transactions on a more detailed basis and after identifying another issue related to the design of the AFC computer software program, the domestic utility companies identified additional instances of incorrectly granting or rejecting transmission service requests. The identified instances now involve less than 1.8% of the total transmission service requests acted on during the period at issue.

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 The domestic utility companies also self-reported these additional instances to the FERC enforcement staff.  Although it has not evidenced its intent to do so, among the remedies available to the FERC is the ability to levy fines for these instances. The domestic utility companies are working with FERC enforcement staff to provide additional information related to these instances.

Market and Credit Risks

Commodity Price Risk

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 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 quarter of the year):

Excluding the generation associated with the pending Palisades acquisition, Non-Utility Nuclear's total percent of planned generation sold forward is 94% in 2007, 79% in 2008, 48% in 2009, and 25% in 2010.

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. Non-Utility Nuclear's calculation under the NYPA value sharing agreement shows that Non-Utility Nuclear owes NYPA $0 under that agreement for 2005. NYPA's calculation, under its interpretation of the agreement, shows that $90.5 million is due for 2005. Non-Utility Nuclear believes that its interpretation is correct, and has refused NYPA's demand for $90.5 million. As called for by the value sharing agreement, NYPA has filed a demand for arbitration against the Non-Utility Nuclear subsidiaries that own Fitzpatrick and Indian Point 3 to determine the amount owed, if any, for 2005.

Some of the agreements to sell the power produced by Entergy's Non-Utility Nuclear power plants contain provisions that require an Entergy subsidiary to provide collateral to secure its obligations under the agreements. The Entergy subsidiary will be required to provide collateral based upon the difference between the current market and contracted power prices in the regions where Non-Utility Nuclear sells power. The primary

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form of 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, 2006, based on power prices at that time, Entergy had in place as collateral $905 million of Entergy Corporation guarantees for wholesale transactions, including $85 million of guarantees that support letters of credit. The assurance requirement associated with Non-Utility Nuclear is estimated to increase by an amount up to $410 million if gas prices increase $1 per MMBtu in both the short- and long-term markets. In the event of a decrease in Entergy Corporation's credit rating to below investment grade, Entergy will 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 (2006 represents the remaining quarter of the year):

Excluding the capacity associated with the pending Palisades acquisition, Non-Utility Nuclear's total percent of planned capacity sold forward is 84% in 2007, 54% in 2008, 44% in 2009, and 23% in 2010. Excluding the generation and capacity associated with the pending Palisades acquisition, Non-Utility Nuclear's blended capacity and energy sold forward (based on revenues) is 91% in 2007, 74% in 2008, 45% in 2009, and 21% in 2010.

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. Following is an update to that discussion.

Unbilled Revenue

As 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.

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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 2007. The FASB's objective in issuing this interpretation is to increase comparability among companies in financial reporting of income taxes. FIN 48 establishes a "more-likely-than-not" recognition threshold that must be met before a tax 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, above what is payable on the tax return, is required to be recorded. Entergy does not expect that the adoption of FIN 48 will materially affect its financial position, results of operations, or cash flows.

In September 2006, FASB issued SFAS 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements Nos. 87, 88, 106 and 132(R)," to be effective December 31, 2006. SFAS 158 requires employers to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its balance sheet with the offset recorded to other comprehensive income. Entergy has previously disclosed its funded status in Note 10 to the consolidated financial statements in the Form 10-K. SFAS 158 also requires that changes in that funded status be recorded in other comprehensive income in the period in which the changes occur. Entergy's Utility business, with the exception of the Louisiana jurisdictions which provide for recovery of other postretirement benefit costs on a pay as you go basis, is generally allowed to recover pension and other postretirement benefit costs each period based upon costs calculated under S FAS 87 and SFAS 106. Entergy's analysis, including the regulatory accounting requirements to support recording the majority of the effect of adoption of SFAS 158 as a regulatory asset, is not yet complete.  Entergy does not expect the implementation of this standard, however, to materially affect Entergy's financial position or results of operations.

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