Entergy - 10-Q quarterly report FY

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

ENTERGY CORPORATION AND SUBSIDIARIES
INDEX TO QUARTERLY REPORT ON FORM 10-Q
September 30, 2004

DEFINITIONS (Continued)

DEFINITIONS (Concluded)

Entergy's income before taxes is discussed below according to the operating segments listed above. Earnings for the nine months ended September 30, 2003 include the $142.9 million net-of-tax cumulative effect of changes in accounting principle that increased earnings in the first quarter of 2003, almost entirely resulting from the implementation of SFAS 143. See Note 9 to the consolidated financial statements in the Form 10-K for further discussion of the implementation of SFAS 143. See Note 7 to the consolidated financial statements herein for more information concerning Entergy's operating segments and their financial results in 2004 and 2003.

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

U.S. UTILITY

The decrease in earnings for the U.S. Utility for the third quarter of 2004 compared to the third quarter of 2003 from $272.9 million to $258.0 million was primarily due to a decrease in net revenue, primarily caused by milder weather, and an increase in other operation and maintenance expenses, partially offset by decreased interest charges and an increase in miscellaneous income.

The increase in earnings for the U.S. Utility for the nine months ended September 30, 2004 compared to the same period in 2003 from $502.4 million to $568.7 million was primarily due to the $107.7 million ($65.6 million net-of-tax) accrual in 2003 of the loss that would be associated with a final, non-appealable decision disallowing abeyed River Bend plant costs. Also contributing to the increase was the $21.3 million net-of-tax cumulative effect of a change in accounting principle that reduced earnings at Entergy Gulf States in the first quarter of 2003 upon implementation of SFAS 143, an increase in miscellaneous income, and a decrease in interest charges. A decrease in net revenue and an increase in other operation and maintenance expenses partially offset the increase in earnings.

Net Revenue

Third Quarter 2004 Compared to Third Quarter 2003

Net revenue, which is Entergy's measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing the third quarter of 2004 to the third quarter of 2003.

The volume/weather variance resulted primarily from the effect of milder weather on sales during the third quarter of 2004 compared to the third quarter of 2003, partially offset by an increase in billed usage of 481 GWh in the industrial sector.

The price applied to unbilled sales variance resulted primarily from an increase in the fuel price applied to unbilled sales.

The 2004 deferral variance is due to the deferral of fossil plant maintenance expenses and voluntary severance plan expenses in accordance with a stipulation approved by the City Council in August 2004 in connection with the Entergy New Orleans formula rate plans. The stipulation allows for the recovery of these costs through the amortization of a regulatory asset. The fossil plant maintenance and voluntary severance plan costs are being amortized over five-year periods that became effective January 2003 and January 2004, respectively. The Entergy New Orleans formula rate plans are discussed in Note 2 to the consolidated financial statements.

Gross operating revenues, fuel and purchased power costs, and other regulatory credits

Gross operating revenues include an increase in fuel cost recovery revenues of $161.8 million primarily due to higher fuel rates resulting from increases in the market prices of non-associated purchased power and natural gas and collections of previous deferrals of fuel costs. As such, this revenue increase is offset by increased fuel and purchased power expenses.

The net increase in other regulatory credits was primarily due to the following:

• the deferral of fossil plant maintenance and voluntary severance plan costs at Entergy New Orleans as a result of a stipulation approved by the City Council in August 2004, as discussed above;
• cessation of the Grand Gulf Accelerated Recovery Tariff that was suspended in July 2003; and
• the deferral in the third quarter of 2004 of $5.8 million of capacity charges at Entergy Louisiana related to generation resource planning as allowed by the LPSC.

Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003

Following is an analysis of the change in net revenue comparing the nine months ended September 30, 2004 to the nine months ended September 30, 2003.

The deferred fuel cost revisions variance resulted primarily from a revision in 2003 to an unbilled sales pricing estimate to more closely align the fuel component of that pricing with expected recoverable fuel costs at Entergy Louisiana. Deferred fuel cost revisions also decreased net revenue due to a revision in 2004 to the estimate of fuel costs filed for recovery at Entergy Arkansas in the March 2004 energy cost recovery rider.

The price applied to unbilled sales variance resulted from a decrease in fuel price in 2004 caused primarily by the effect of nuclear plant outages in 2003 on average fuel costs.

The summer capacity charges variance was due to the amortization in 2003 at Entergy Gulf States and Entergy Louisiana of capacity charges for the summer of 2001 that had been deferred. Entergy Gulf States' amortization began in June 2002 and ended in May 2003. Entergy Louisiana's amortization began in August 2002 and ended in July 2003.

Base rates increased net revenue due to a base rate increase at Entergy New Orleans that became effective in June 2003.

Gross operating revenues, fuel and purchased power expenses, and other regulatory charges (credits)

Gross operating revenues include an increase in fuel cost recovery revenues of $318.3 million primarily due to higher fuel rates resulting from increases in the market prices of non-associated purchased power and natural gas and collections of previous deferrals of fuel costs. As such, this revenue increase is offset by increased fuel and purchased power expenses.

The net increase in other regulatory credits was primarily due to the following:

• cessation of the Grand Gulf Accelerated Recovery Tariff that was suspended in July 2003;
• the amortization in 2003 of deferred capacity charges for summer 2001 power purchases at Entergy Gulf States and Entergy Louisiana;
• the deferral in 2004 of $11.6 million of capacity charges related to generation resource planning as allowed by the LPSC; and
• the deferral of fossil plant maintenance and voluntary severance plan costs at Entergy New Orleans as a result of a stipulation approved by the City Council in August 2004, as discussed above.

Other Income Statement Variances

Third Quarter 2004 Compared to Third Quarter 2003

Other operation and maintenance expenses increased for the third quarter primarily due to an increase of $10.9 million in benefits costs in 2004.

Depreciation and amortization expenses increased for the third quarter primarily due to higher depreciation of Grand Gulf 1 in the third quarter of 2004 due to a higher scheduled sale-leaseback principal payment, in addition to an increase in plant in service.

Other income increased for the third quarter primarily due to a reduction in the decommissioning liability for River Bend, as discussed in Note 1 to the consolidated financial statements.

Interest and other charges decreased for the third quarter primarily due to a decrease in interest on long-term debt as a result of the net retirement and refinancing of long-term debt in 2003 and the first six months of 2004. See Note 5 to the consolidated financial statements in the Form 10-K and Note 4 to the consolidated financial statements herein for detail of long-term debt.

Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003

Other operation and maintenance expenses increased for the nine months ended September 30, 2004 primarily due to the following:

• an increase of $27.6 million as a result of higher benefits costs in 2004;
• an increase of $16.5 million as a result of higher customer service support costs in 2004; and
• an increase of $12.0 million as a result of higher co-owner credits at certain plants in 2003.

Depreciation and amortization expenses increased for the nine months ended September 30, 2004 primarily due to higher depreciation of Grand Gulf 1 in the third quarter of 2004 due to a higher scheduled sale-leaseback principal payment, in addition to an increase in plant in service.

Other income increased for the nine months ended September 30, 2004 primarily due to the following:

• a $107.7 million accrual in June 2003 for the loss that would be associated with a final, non-appealable decision disallowing abeyed River Bend plant costs. See Note 2 to the consolidated financial statements for more details regarding the River Bend abeyed plant costs;
• a reduction in the decommissioning liability for River Bend, as discussed in Note 1 to the consolidated financial statements; and
• a reduction in the loss provision for an environmental clean-up site. During the second quarter of 2004, the provision was reduced by approximately $10 million based upon activities performed to date and the estimate of the remaining likely exposure associated with the ten-year groundwater monitoring study.

Interest and other charges decreased for the nine months ended September 30, 2004 primarily due to a decrease in interest on long-term debt as a result of the net retirement and refinancing of long-term debt in 2003 and the first six months of 2004. See Note 5 to the consolidated financial statements in the Form 10-K and Note 4 to the consolidated financial statements herein for detail of long-term debt.

Third Quarter 2004 Compared to Third Quarter 2003

The decrease for Energy Commodity Services from $36.3 million in earnings to a $38.9 million loss was primarily due to lower earnings from Entergy's investment in Entergy-Koch. Entergy's investment in Entergy-Koch generated a loss in the third quarter 2004 primarily as a result of the inability of Entergy-Koch Trading (EKT) to apply hedge accounting to certain contracts, as follows:

• After entering into the agreement to sell its energy trading business, EKT was required to mark-to-market all of its derivative cash flow hedges of natural gas in storage through current earnings while the related physical natural gas is accounted for at cost. Prior to the sale agreement, EKT could use cash flow hedge accounting to defer certain of the derivative mark-to-market effects until the period in which the related physical natural gas was resold because the forecasted sale transactions were probable of occurring. This accounting treatment occurred because it was determined that EKT could no longer represent that the forecasted transactions were probable of occurring because of the pending sale of the energy trading business.
• For derivative contracts that EKT was required to mark-to-market even before it entered into the energy trading business sale agreement, the mark-to-market value of certain contracts entered into to hedge physical gas storage positions decreased because of rising natural gas prices. These contracts do not meet the requirements under SFAS 133 for deferring the mark-to-market change in equity rather than recording it in income. The decrease in the mark-to-market value of the contracts was not offset by the gain in value of the physical gas storage positions, because the physical gas storage positions are accounted for at cost.

The effect of these two factors will reverse with the closing of the energy trading business sale because the sale agreement provides for the proceeds of the sale to reflect the fair value of all trading assets and liabilities transferred to the seller.

As discussed in the Form 10-K, Entergy accounts for its 50% share in Entergy-Koch under the equity method of accounting. Earnings from Entergy-Koch are reported as equity in earnings of unconsolidated equity affiliates in the financial statements. Certain terms of the partnership arrangement allocated income from various sources, and the taxes on that income, on a significantly disproportionate basis through 2003. Losses and distributions from operations are allocated to the partners equally. Substantially all of Entergy-Koch's profits were allocated to Entergy in 2003, 2002, and 2001. Effective January 1, 2004, a revaluation of Entergy-Koch's assets for legal capital account purposes occurred, and profit allocations changed after the revaluation. The profit allocations other than for weather trading and international trading became equal. Profit allocations for weather trading and international trading remain disproportionate to the ownership interests. The weather trading and int ernational trading allocations are unequal only within a specified range, such that the overall earnings allocation should not materially differ from 50/50. Earnings allocated under the terms of the partnership agreement constitute equity, not subject to reallocation, for the partners.

Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003

The decrease for Energy Commodity Services from $178.7 million in earnings to a $19.6 million loss was primarily due to lower earnings from Entergy's investment in Entergy-Koch. The income from Entergy's investment in Entergy-Koch was lower primarily as a result of lower earnings at EKT, resulting primarily from the inability to apply hedge accounting discussed above and also from reduced volatility, which contributed to lower point-of-view trading profits.

Income Taxes

Liquidity and Capital Resources

See "Management's Financial Discussion and Analysis - Liquidity and Capital Resources" in the Form 10-K for a discussion of Entergy's capital structure, capital expenditure plans and other uses of capital, and sources of capital. Following are updates to the information presented in the Form 10-K.

Capital Structure

In May 2004, Entergy Corporation renewed its 364-day bank credit facility with two separate facilities, a 364-day credit facility and a 3-year credit facility. The 364-day credit facility has a borrowing capacity of $485 million and expires in May 2005. As of September 30, 2004, no borrowings were outstanding on this facility. The 3-year credit facility has a borrowing capacity of $965 million and expires in May 2007. As of September 30, 2004, $100 million in borrowings were outstanding on this facility. Entergy also has the ability to issue letters of credit against the 3-year facility and its $965 million in borrowing capacity, and $40 million had been issued against this facility at September 30, 2004.

In April 2004, Entergy Arkansas renewed its 364-day credit facility, increasing the amount to $85 million, until April 2005. In May 2004, Entergy Mississippi renewed its credit facility for its then-existing amount, $25 million, and the renewed facility expires in May 2005. As of September 30, 2004, the amounts outstanding on the Entergy Arkansas and Entergy Mississippi credit facilities were $85 million and $25 million, respectively.

In July 2004, Entergy Louisiana renewed its credit facility and Entergy New Orleans entered into a separate credit facility with the same lender. Both facilities will expire in April 2005. Entergy Louisiana can borrow up to $15 million and Entergy New Orleans can borrow up to $14 million under their respective credit facilities, but at no time can the total amount borrowed under these facilities by the two companies combined exceed $15 million. As of September 30, 2004, no borrowings were outstanding under these facilities.

As discussed in the Form 10-K, Entergy guaranteed the obligations of EntergyShaw to construct a 550 MW electric power plant located in Harrison County, Texas. EntergyShaw is an unconsolidated joint venture in which Entergy owns a 50% member interest. The power plant commenced commercial operation in June 2003, the base warranty period for the construction expired in June 2004, and management does not expect any material liability on the warranty.

Capital Expenditure Plans and Other Uses of Capital

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 Entergy's planned construction and other capital investments by operating segment for 2004 through 2006. Entergy Louisiana now expects to complete the purchase of the Perryville plant in mid-2005 for $183.5 million. Therefore, Entergy now expects to spend approximately $385 million for Capital Commitments in the U.S. Utility segment in 2004 and approximately $479 million for Capital Commitments in the U.S. Utility segment in 2005-2006.

Dividends and Stock Repurchases

In late July 2004, the Board approved a program under which Entergy Corporation will repurchase up to $1.5 billion of its common stock. The program is effective immediately and extends through the end of 2006. This repurchase program is incremental to the existing authority discussed in the Form 10-K to repurchase shares to fund the exercise of employee stock options. The amount of repurchases under the program may vary as a result of material changes in business results or capital spending, or as a result of material new investment opportunities.

On October 20, 2004, the Board increased Entergy's quarterly dividend per share by 20%, to $0.54. Declarations of dividends on Entergy's common stock are made at the discretion of the Board. Among other things, the Board evaluates the level of Entergy's common stock dividends based upon Entergy's earnings, financial strength, and future investment opportunities.

Cash Flow Activity

As shown in Entergy's Statements of Cash Flows, cash flows for the nine months ended September 30, 2004 and 2003 were as follows:

Operating Activities

Entergy's cash flow provided by operating activities increased by $538 million for the nine months ended September 30, 2004 compared to the nine months ended September 30, 2003 primarily due to the following:

• The U.S. Utility provided $1,295 million in cash from operating activities, compared to providing $1,177 million in 2003. The increase resulted primarily from improved recovery of fuel costs.
• The Non-Utility Nuclear business provided $425 million in cash from operating activities, compared to providing $198 million in 2003. The increase resulted primarily from lower refueling outage cash costs and increases in generation and contract pricing that led to an increase in revenues.
• Entergy's investment in Entergy-Koch, L.P. provided $9 million in cash from operating activities, compared to using $56 million in 2003. The Entergy-Koch investment provided more cash flow in 2004 even though dividends received from Entergy-Koch were $26 million in 2004 compared to $75 million in 2003, because tax payments related to the investment were higher in 2003 because of higher net income from the investment in 2003.
• The non-nuclear wholesale asset business used $38 million in cash from operating activities, compared to using $75 million in 2003. The decrease in cash used resulted primarily from a one-time $33 million payment in 2003 related to a generation contract.
• The parent company, Entergy Corporation, provided $28 million in cash from operating activities in 2004 compared to using $47 million in 2003 primarily due to lower tax payments.

Investing Activities

Net cash used in investing activities decreased by $470 million for the nine months ended September 30, 2004 compared to the nine months ended September 30, 2003 primarily due to the following:

• System Energy used approximately $193 million in March 2003 to provide cash collateral for letters of credit that secured certain of its obligations related to the sale-leaseback of a portion of Grand Gulf 1. (In December 2003, System Energy replaced the cash-backed letters of credit with syndicated bank letters of credit that expire in May 2007.)
• Construction expenditures were $107 million lower in 2004 than in 2003, including decreases of $23 million in the U.S. Utility business, $37 million in the Non-Utility Nuclear business, and $42 million in the non-nuclear wholesale asset business.
• Temporary investments of $50 million with initial maturities of greater than 90 days matured in the first quarter of 2004.
• Entergy Arkansas used $15 million, Entergy Gulf States used $87 million, and Entergy Mississippi used $73 million for other regulatory investments in 2003 as a result of fuel cost under-recovery. In 2004, Entergy Arkansas used $17 million and Entergy Gulf States used $46 million for other regulatory investments related to fuel cost under-recovery. See Note 1 to the consolidated financial statements in the Form 10-K for discussion of the accounting treatment of these fuel cost under-recoveries.

Management believes that any changes in the allocation of production costs resulting from a FERC decision and related retail proceedings should result in similar rate changes for retail customers. Therefore, management does not believe that this proceeding at the FERC will have a material effect on the financial condition of any of the domestic utility companies, although the outcome of the FERC proceeding and related retail proceedings cannot be predicted at this time.

Entergy Arkansas filed its initial testimony in response to the APSC's February Order of Investigation discussed in the Form 10-K. The testimony emphasizes that the ALJ's Initial Decision is not a final order by the FERC; briefly discusses some of the aspects of the Initial Decision that are included in Entergy's exceptions filed with the FERC; emphasizes that Entergy will seek to reverse the production cost-related portions of the Initial Decision; and states that Entergy Arkansas believes that it is premature, before the FERC makes a decision, for Entergy Arkansas to determine whether its continued participation in the System Agreement is appropriate.

In addition, as discussed in the Form 10-K, the APSC had publicly announced its intention to initiate an inquiry into Entergy Louisiana's Vidalia purchased power contract. In April 2004, the APSC commenced the investigation and requested historical documents, records, and information from Entergy Arkansas, which Entergy Arkansas has provided to the APSC.

Also in April 2004, the APSC issued an order directing Entergy Arkansas to show cause why Entergy Arkansas should not have to indemnify and hold its customers harmless from any adverse financial effects related to Entergy Louisiana's pending acquisition of the Perryville power plant, or show that the Perryville unit will produce economic benefits for Entergy Arkansas' customers. Entergy Arkansas filed a response in May 2004 stating that Entergy will seek to reverse the production cost-related portions of the ALJ's Initial Decision in the System Agreement proceeding at the FERC, that the Perryville acquisition is part of Entergy's request for proposal generation planning process, that Entergy Arkansas is not in a position to indemnify its retail customers from actions taken by the FERC, and that the Perryville acquisition is expected to reduce the domestic utility companies' overall production costs. Procedural schedules have not been established in these APSC investigations.

Also in April 2004, the City Council issued a resolution directing Entergy New Orleans and Entergy Louisiana to notify the City Council and obtain prior approval for any action that would materially modify, amend, or terminate the System Agreement for one or more of the domestic utility companies. Entergy New Orleans and Entergy Louisiana appealed to state court the City Council's resolution on the basis that the imposition of this requirement with respect to the System Agreement, a FERC-approved tariff, exceeds the City Council's jurisdiction and authority. In July 2004, the City Council answered the appeal and filed a third party demand and counterclaim against Entergy, the domestic utility companies, Entergy Services, and System Energy, seeking a declaratory judgment that Entergy and its subsidiaries cannot terminate the System Agreement until obligations owed under the March 2003 Agreement in Principle are satisfied. In August 2004, Entergy New Orleans and En tergy Louisiana, as well as the named third party defendants, filed pleadings objecting to the City Council's third party demand and counterclaim on various grounds, including federal preemption.

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. Accordingly, because the price is not fixed, the table above does not report power from that plant as sold forward after October 2005. Approximately 2% of Non-Utility Nuclear's planned generation in 2005, 13% in 2006, 12% in 2007, and 12% in 2008 is under contract from Vermont Yankee after October 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 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 business sells its 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, 2004, based on power prices at that time, Entergy had in place as collateral $458 million of Entergy Corporation guarantees and $20 million of letters of credit. Upon a significant 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 Independent System Operators in their area. Following is an updated summary of the amount of the Non-Utility Nuclear business' installed capacity that is 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, 2004:

Utility Restructuring

Transmission

See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Significant Factors and Known Trends, Transmission" in the Form 10-K for discussion of Entergy's contemplated independent transmission entity proposal.

Entergy proposes to have the ICT administer a transmission expansion pricing protocol that will increase the efficiency of transmission pricing on the Entergy system and that will be designed to protect Entergy's native load customers from bearing the cost of transmission upgrades not required to reliably serve these customers' needs. Entergy intends for the ICT to determine whether transmission upgrades associated with new requests for service should be funded directly by the party requesting such service or by a broader group of transmission customers, including Entergy's native load customers. This determination would be made in accordance with protocols approved by the FERC and any party contesting such determination, including Entergy, would be required to seek review at the FERC. Technical conferences regarding the ICT proposal, or various components thereof, were held in July, August, September, and October 2004. Entergy has also responded to discovery requests that resulted from these conferences.

Entergy has requested that the FERC provide its retail regulators sufficient time to review the proposal and provide their comments prior to the FERC ruling on the proposal. In March 2004, the APSC initiated a proceeding to review Entergy's proposal and compare the benefits of such a proposal to the alternative of Entergy joining the Southwest Power Pool RTO. The APSC sought comments from all interested parties on this issue, with initial comments due in May 2004 and reply comments due in June 2004. Various parties, including the APSC General Staff, filed comments opposing the ICT proposal. A public hearing has not been scheduled by the APSC at this time, although Entergy has responded to various APSC data requests. In May 2004, Entergy Mississippi filed a petition for review with the MPSC requesting MPSC support for the ICT proposal. A hearing in that proceeding was held in August. Additionally, Entergy Louisiana and Entergy Gulf States have filed an application with the LPSC r equesting that the LPSC find that the proposal is a prudent and appropriate course of action. No procedural schedule has been established for that proceeding; however, a meeting among Entergy, its retail regulators, and other market participants to discuss certain aspects of the ICT proposal is scheduled for November 2004.

FERC's Supply Margin Assessment

As discussed in the Form 10-K, in November 2001, FERC issued an order that established a new generation market power screen (called Supply Margin Assessment) for purposes of evaluating a utility's request for market-based rate authority, applied that new screen to the Entergy System (among others), determined that Entergy and the others failed the screen within their respective control areas, and ordered these utilities to implement certain mitigation measures as a condition to their continued ability to buy and sell at market-based rates. Among other things, the mitigation measures would require that Entergy transact at cost-based rates when it sells in the hourly wholesale market within its control area. Entergy requested rehearing of the order, and FERC delayed the implementation of certain mitigation measures until such time as it had the opportunity to consider the rehearing request. In June 2003, the FERC proposed and ultimately adopted new market behavior rules and tariff prov isions that would be applied to any market-based sale. Entergy modified its market-based rate tariffs to reflect the new provisions but requested rehearing of FERC's order.

In April 2004, the FERC issued its Order on Rehearing and Modifying Interim Generation Market Power Analysis and Mitigation Policy. In its Order on Rehearing, the FERC established a new interim generation market power analysis that will consider two indicative market power screens: (1) the pivotal supplier screen that is designed to measure an applicant's market power based on the applicant's share of uncommitted capacity at the time of the control area market's annual peak demand; and (2) the market share screen that is designed to evaluate an applicant's market share of uncommitted capacity on a seasonal basis. An integrated utility's native load obligation will be reflected in both screens; however, the proxy for native load obligation differs between the screens. For the uncommitted pivotal supplier screen, the proxy for native load is the average of the daily native load peaks during the month in which the annual peak load day occurs; for the uncommitted market share screen th e proxy for native load is the minimum peak load day for each season. In the event an applicant fails either of these screens, there will be a rebuttable presumption that market power exists. The applicant will then have the opportunity to either: (1) submit a more detailed market power analysis that reflects market prices and measures an applicant's "economic capacity" and "available economic capacity" under the "delivered price test;" or (2) propose case-specific mitigation tailored to the applicant's specific circumstances or adopt cost-based rates for sales within the applicant's control area. In its Order on Rehearing, the FERC also determined: (1) that transmission market power and the need to employ an independent entity to operate and administer an applicant's OASIS site is more properly considered in other proceedings, to the extent appropriate, and would not be considered in evaluating an applicant's generation market power for purposes of granting market-based rate authority; and (2) to elimina te the exemption from the generation market power analysis for sales within an RTO/ISO that had approved market monitoring. Several parties, including Entergy, filed for rehearing of the April 2004 Order. Among other things, Entergy argued that the market share screen is overly conservative and overstates vertically integrated utilities' ability to exercise market power. On July 8, 2004, the FERC issued an order on rehearing reaffirming the use of the pivotal supplier and market share screens and clarified certain instructions for performing such analysis. With regard to the delivered price test analysis, the FERC declined to make a determination on whether an applicant's native load obligations should be included in the delivered price analysis, but instead indicated that it would evaluate the arguments of both the applicant and intervenors as to which measure (one with or without native load obligations) more accurately reflects market conditions. Entergy appealed the April and July orders to the Unit ed States Court of Appeals for the District of Columbia Circuit.

Entergy filed with the FERC its generation market power analysis pursuant to the two indicative screens in August 2004. Entergy's analysis indicated that it passed the pivotal supplier screen for all relevant geographical regions, but failed the market share screen within its control area. At the same time, Entergy submitted the results of the delivered price test for Entergy, which indicate that Entergy does not have market power in any wholesale market when Entergy's native load obligations are reflected. In late October 2004, the FERC sent a letter to Entergy regarding its filing that requests more information from Entergy concerning the filing.

Interconnection Orders

See the Form 10-K for discussion of the order on rehearing issued by FERC on March 5, 2004 that modified Order 2003 to, among other things, eliminate the requirement that the generation owners receive their money back in no more than five years and to include a requirement that the generation owners receive credits only when transmission service is taken from the specific generating facility served by the interconnection or upgrade. In addition, the order on rehearing clarified that a transmission provider continues to have the option to charge a transmission rate that is the higher of the incremental cost rate for network upgrades required to interconnect a generating facility or an embedded cost rate so as to ensure that "other transmission customers, including a Transmission Provider's native load, will not subsidize Network Upgrades required to interconnect merchant generation." Consistent with the principles articulated in the order on rehearing, Entergy incorporated into its re cent ICT filing an approach to the pricing of transmission expansion that protects the transmission provider's native load customers from the effects of service requests by other transmission customers and provides more efficient price signals for resource procurement and siting decisions. In addition, the transmission expansion pricing protocol included in the ICT filing proposes that the ICT review all costs that were previously charged to interconnecting customers for interconnection facilities to determine whether, under the proposed pricing policy, such costs were properly classified as Supplemental Upgrades that are directly assigned to the interconnecting generator or whether such costs were properly Base Plan Upgrades that are rolled into transmission rates for all customers. Any payments made by an interconnecting generator that have not already been refunded to that customer through crediting for transmission service will be subject to the cost assignment by the ICT.

Also see the Form 10-K for a discussion of the proceedings involving the interconnection agreements with certain generators interconnecting to the domestic utility companies' transmission system. In June 2004, a FERC ALJ issued an Initial Decision in a proceeding involving a complaint filed by one of the generators. In the complaint, the generator was seeking to modify its previous interconnection agreement in order to obtain more favorable transmission crediting provisions contained in Entergy's current pro forma interconnection and operating agreement. In the Initial Decision, the ALJ determined that the generator is entitled to obtain the benefits of Entergy's current pro forma interconnection and operating agreement. Entergy has filed a brief on exceptions with the FERC opposing the Initial Decision. In October 2004, Union Power Partners, L.P., the owner of a nominal 2,200 MW generating facility in Arkansas, filed a complaint with the FERC seeking to obtain transmission credit s for approximately $26 million of transmission upgrades that previously were directly assigned to Union Power. The case is pending before the FERC.

Retail-Texas

See Note 2 to the consolidated financial statements in the Form 10-K for a discussion of the status of retail open access in Entergy Gulf States' Texas service territory and Entergy Gulf States' independent organization request. On March 15, 2004, the PUCT issued a preliminary order in Entergy Gulf States' independence proceeding in which the PUCT determined, among other things, that the ultimate question in the proceeding is whether Entergy Gulf States' proposed independent organization, Entergy Transmission Organization, is sufficiently independent of any producer or seller of electricity that its decisions will not be unduly influenced by any producer or seller. After a hearing held in June 2004 on the merits, in July 2004 the PUCT denied Entergy's application to certify Entergy's transmission organization as an independent organization under Texas law. In its order, the PUCT also ordered: the cessation of efforts to develop an interim solution for retail open access in Enterg y Gulf States' Texas service territory, termination of the pilot project in that territory, and a delay in retail open access in that territory until either a FERC-approved RTO is in place or some other independent transmission entity is certified under Texas law. Several parties filed motions for rehearing on the termination of the pilot program aspect of the order, claiming the issue was not properly a part of the proceeding. In September 2004, the PUCT denied these motions for rehearing.

Nuclear Matters

See the Form 10-K for the discussion of the review by the Federal Emergency Management Agency (FEMA) of the emergency evacuation plans for Indian Point, and Westchester County's appeal to FEMA of FEMA's notice of certification of the Indian Point Emergency Plan. In June 2004, FEMA issued letters rejecting Westchester County's appeal and reaffirming its certification.

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, impairment of long-lived assets, mark-to-market derivative instruments, pension and other postretirement costs, and other contingencies.

New Accounting Pronouncements

The FASB's Emerging Issues Task Force (EITF) recently issued EITF 03-1, "The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments". EITF 03-1 provides guidance for determining whether an impairment is other than temporary for investments accounted for in accordance with SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities". EITF deliberations on the recognition and measurement guidance in EITF 03-1 continue. Entergy does not expect the current effect of EITF 03-1 to be material to Entergy because the majority of its' nuclear decommissioning trust investments, accounted for under SFAS 115, are in market index or mutual-type funds whose aggregate market value exceeds cost.