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

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

Entergy Corporation, Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., Entergy New Orleans, Inc., and System Energy Resources, Inc. separately file this combined Quarterly Report on Form 10-Q. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company reports herein only as to itself and makes no other representations whatsoever as to any other company. This combined Quarterly Report on Form 10-Q supplements and updates the Annual Report on Form 10-K for the calendar year ended December 31, 2002, and the Quarterly Reports on Form 10-Q for the quarters ended March 31, 2003 and June 30, 2003, filed by the individual registrants with the SEC, and should be read in conjunction therewith.

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

• resolution of pending and future rate cases and negotiations, including various performance-based rate discussions, and other regulatory decisions, including those related to Entergy's utility supply plan
• Entergy's ability to reduce its operation and maintenance costs, particularly at its Non-Utility Nuclear generating facilities, including the uncertainty of negotiations with unions to agree to such reductions
• the performance of Entergy's generating plants, and particularly the capacity factors at its nuclear generating facilities
• prices for power generated by Entergy's unregulated generating facilities, particularly the ability to extend or replace the existing power purchase agreements for the Non-Utility Nuclear plants, and the prices and availability of power Entergy must purchase for its utility customers
• Entergy's ability to develop and execute on a point of view regarding prices of electricity, natural gas, and other energy-related commodities
• Entergy-Koch's profitability in trading electricity, natural gas, and other energy-related commodities
• resolution of pending investigations of Entergy-Koch's past trading practices
• changes in the number of participants in the energy trading market, and in their creditworthiness and risk profile
• changes in the financial markets, particularly those affecting the availability of capital and Entergy's ability to refinance existing debt and to fund investments and acquisitions
• actions of rating agencies, including changes in the ratings of debt and preferred stock
• changes in inflation and interest rates
• Entergy's ability to purchase and sell assets at attractive prices and on other attractive terms
• volatility and changes in markets for electricity, natural gas, and other energy-related commodities
• changes in utility regulation, including the beginning or end of retail and wholesale competition, the ability to recover net utility assets and other potential stranded costs, and the establishment of SeTrans or another regional transmission organization
• changes in regulation of nuclear generating facilities and nuclear materials and fuel, including possible shutdown of Indian Point or other nuclear generating facilities
• changes in law resulting from proposed energy legislation
• changes in environmental, tax, and other laws, including requirements for reduced emissions of sulfur, nitrogen, carbon, and other substances
• the economic climate, and particularly growth in Entergy's service territory
• variations in weather, hurricanes, and other disasters
• advances in technology
• the potential impacts of threatened or actual terrorism and war
• the success of Entergy's strategies to reduce taxes
• the effects of litigation
• changes in accounting standards
• changes in corporate governance and securities law requirements
• Entergy's ability to attract and retain talented management and directors.

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

DEFINITIONS (Continued)

DEFINITIONS (Concluded)

Entergy's consolidated earnings applicable to common stock for the third quarter and nine months ended September 30, 2003 and 2002 were as follows:

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 "Critical Accounting Estimates - SFAS 143" below for discussion of the implementation of SFAS 143. Earnings for the nine months ended September 30, 2002 include net charges of $254.2 million net-of-tax reflecting the effect of Entergy's decision to discontinue additional greenfield power plant development and asset impairments resulting from the deteriorating economics of wholesale power markets principally in the United States and the United Kingdom. The net charges are discussed in more detail below in the Energy Commodity Services discussion. See Note 6 to the consolidated financial statements for more inf ormation concerning Entergy's operating segments and their financial results in 2003 and 2002.

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

The increase in earnings for the U.S. Utility in the third quarter of 2003 compared to the third quarter of 2002 from $243.7 million to $272.9 million was primarily due to an increase in net revenue and a decrease in interest charges, partially offset by an increase in depreciation and amortization expenses.

The decrease in earnings for the U.S. Utility for the nine months ended September 30, 2003 compared to the same period in 2002 from $540.9 million to $502.4 million was primarily due to a $107.7 million ($65.6 million net-of-tax) accrual of the loss that would be associated with a final, non-appealable decision disallowing abeyed River Bend plant costs. Also contributing to the decrease 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, combined with an increase in depreciation and amortization expenses. See "Critical Accounting Estimates - SFAS 143" below for discussion of the implementation of SFAS 143. Substantially offsetting the decrease in earnings were increased net revenue and decreased interest charges.

Third Quarter 2003 Compared to Third Quarter 2002

Operating income increased $32 million, or 6.3%, primarily due to an increase in net revenue that included the following:

• an increase of $22 million due to base rate increases at Entergy Mississippi and Entergy New Orleans that became effective in January 2003 and June 2003, respectively; and
• an increase of $27 million due to an increase in price applied to unbilled sales and more favorable volume, including the effect of weather, from unbilled sales.

The increase in operating income was partially offset by the following:

• an increase of $9 million in depreciation and amortization expense due to an increase in plant in service; and
• a decrease of $8 million due to the loss of the net revenue from three large industrial customers lost to cogeneration. The $8 million of lost net revenue represents less than 1% of the U.S. Utility's net revenue. Entergy expects to lose one additional customer to cogeneration in 2005. Current sales to that customer account for approximately $11 million of Entergy's net revenue annually. Entergy does not currently expect additional significant losses to cogeneration because of the current economics of the electricity markets and Entergy's marketing efforts in retaining industrial customers.

Nine Months Ended September 30, 2003 Compared to Nine Months Ended September 30, 2002

• an increase of $45 million in net revenue due to base rate increases at Entergy Mississippi and Entergy New Orleans that became effective in January 2003 and June 2003, respectively;
• an increase of $32 million in net revenue due to increased electricity usage of 779 GWh in the residential and commercial sectors; and
• an increase of $23 million in net revenue due to an increase in the price applied to unbilled sales.

The following items decreased operating income and partially offset the items that increased operating income for the period:

Third Quarter 2003 Compared to Third Quarter 2002

Interest and other charges decreased $10.9 million primarily due to the redemption and refinancing of long-term debt. Refer to Note 4 to the consolidated financial statements for detail of long-term debt issuances and retirements in 2003.

Nine Months Ended September 30, 2003 Compared to Nine Months Ended September 30, 2002

Miscellaneous income - net decreased $115.5 million primarily due to a $107.7 million accrual in the second quarter 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.

Interest charges decreased $24.9 million primarily due to:

• a decrease of $9.9 million in interest on long-term debt due to the redemption and refinancing of long-term debt. Refer to Note 4 to the consolidated financial statements for detail of long-term debt issuances and retirements in 2003;
• a decrease of $4.5 million at Entergy Arkansas due to an increase in interest expense in 2002 resulting from the true-up of the annual fuel recovery rider in March 2002; and
• a decrease of $4.2 million at Entergy New Orleans primarily due to interest accrued in 2002 for potential rate actions and refunds and a true-up of those accruals in May 2003.

Third Quarter 2003 Compared to Third Quarter 2002

Fuel recovery mechanisms at the domestic utility companies generally provide for the deferral of fuel and purchased power costs incurred above the amounts included in existing rates. Operating revenues in 2003 include an increase in fuel cost recovery revenue of $184.5 million and $5.4 million related to electric sales and gas sales, respectively, due to higher fuel costs resulting from increases in the market prices of natural gas and purchased power in 2003. The fuel recovery increase is offset by increased fuel and purchased power expenses.

Nine Months Ended September 30, 2003 Compared to Nine Months Ended September 30, 2002

Operating revenues in 2003 include an increase in fuel cost recovery revenue of $541.0 million and $45.8 million related to electric sales and gas sales, respectively, due to higher fuel costs resulting from increases in the market prices of natural gas and purchased power in 2003. The fuel recovery increase is offset by increased fuel and purchased power expenses.

Other operation and maintenance expenses decreased $159.1 million primarily due to decreased expenses at Entergy Arkansas. The March 2002 Settlement Agreement and 2001 earnings review that became final in the second quarter of 2002, allowing Entergy Arkansas to recover a large majority of 2000 and 2001 ice storm repair expenses through previously-collected transition cost account amounts, increased Entergy Arkansas expenses by $159.9 million in 2002. This increase in expenses in 2002 was offset by a regulatory credit resulting in a minimal effect on 2002 net income.

Following are key performance measures for Non-Utility Nuclear for the third quarter and nine months ended September 30, 2003 and 2002:

The decrease in earnings for Non-Utility Nuclear from $73.1 million to $59.6 million was primarily due to the lower capacity factor for the quarter, lower pricing, and increased amortization of nuclear refueling outage expenses. The lower capacity factor resulted primarily from unplanned outages and the widespread blackout that occurred in the Northeast in August 2003, which caused Entergy's three nuclear power plants in New York to go offline for a cumulative total of 10.5 days. The decrease was partially offset by the ongoing effect of applying SFAS 143 post-implementation lowering both depreciation of adjusted plant costs and accretion of decommissioning liabilities, and the inclusion of earnings from Vermont Yankee, acquired in July 2002.

1. Previously reported volumes, which included only U.S. trading, have been adjusted to reflect both U.S. and Europe volumes traded.

The decrease in earnings for Energy Commodity Services from $48.3 million to $36.3 million was primarily due to the gain of $25.7 million ($15.9 million net-of-tax) realized by the non-nuclear wholesale assets business in 2002 resulting from the sale of projects under development in Spain. Partially offsetting the decrease in earnings were higher earnings from Entergy's investment in Entergy-Koch. The income from Entergy's investment in Entergy-Koch was $9.6 million higher in 2003 primarily as a result of higher earnings at Entergy-Koch Trading (EKT). While volatility was down, trading results reflected strong earnings in point-of-view trading. In addition, EKT's physical optimization business continued to be a key driver of profitability, and its European business contributed increases as trading activities expanded beyond the United Kingdom. Earnings at Gulf South Pipeline were lower due to lower throughput and higher production costs. The decreased throughput was due to higher gas prices causing generally lower gas demand as industrial and power plant customers switched to fuel oil. Higher costs were primarily the result of incremental legal expenses in connection with Gulf South Pipeline's defense of a lawsuit which it believes has no merit.

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 allocate 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 thus far in 2003 and for all of 2002. Effective January 1, 2004, a revaluation of Entergy-Koch's assets for legal capital account purposes will occur, and future profit allocations will change after the revaluation. Management expects that, taking the various profit categories into account that are discussed further in the Form 10-K, Entergy's share of the future profit allocations beginning on January 1, 2004 will be approxima tely 50% of Entergy-Koch's total profits.

The increase in earnings for Energy Commodity Services from a $169.1 million loss to $178.7 million in earnings was primarily due to $391.6 million ($254.2 million net-of-tax) of charges recorded in 2002, including income of $28.0 million ($17.3 million net-of-tax) in the third quarter 2002, to reflect the effect of Entergy's decision to discontinue additional greenfield power plant development and to reflect asset impairments resulting from the deteriorating economics of wholesale power markets in the United States and United Kingdom. The charge consisted of the following:

• The power development business obtained contracts in October 1999 to acquire 36 turbines from General Electric. Entergy's rights and obligations under the contracts for 22 of the turbines were sold to an independent special-purpose entity in May 2001. $178.0 million of the charge was a provision for the net costs resulting from cancellation or sale of the turbines subject to purchase commitments with the special-purpose entity;
• $167.5 million of the charges resulted from the write-off of the equity investment in the Damhead Creek project and the impairment of the values of the Warren Power power plant, the Crete project, and the RS Cogen project. This portion of the charges reflected Entergy's estimate of the effects of reduced spark spreads in the United States and the United Kingdom;
• $39.1 million of the charges related to the restructuring of the non-nuclear wholesale assets business, including impairments of administrative fixed assets, estimated sub-lease losse s, and employee-related costs for approximately 135 affected employees;
• $32.7 million of the charges resulted from the write-off of capitalized project development costs for projects that would not be completed; and
• a gain of $25.7 million ($15.9 million net-of-tax) realized on the sale in August 2002 of the non-nuclear wholesale assets business' interest in projects under development in Spain.

Higher earnings from Entergy's investment in Entergy-Koch, as discussed above, also contributed to the increase in earnings for the period. The income from Entergy's investment in Entergy-Koch was $120.8 million higher in 2003 primarily as a result of higher earnings at EKT, which were driven by the factors discussed above.

Revenues for Energy Commodity Services decreased by $109.6 million primarily due to the sale of Damhead Creek in December 2002. The decrease had a minimal effect on earnings in 2003 because of a corresponding reduction in the expenses associated with owning and operating the plant.

See "Management's Financial Discussion and Analysis - Liquidity and Capital Resources" in the Form 10-K for a discussion of Entergy's capital structure, capital expenditure plans and other uses of capital, and sources of capital. Following are updates to that information and a discussion of Entergy's cash flow activity in 2003.

Entergy's capitalization is balanced between equity and debt, as shown in the following table. The reduction in the percentage of debt from the 2001 level is primarily the result of the sale of Damhead Creek in December 2002. Debt outstanding on the Damhead Creek facility was $458 million as of December 31, 2001.

Net debt consists of gross debt less cash and cash equivalents. Gross debt consists of notes payable, capital lease obligations, preferred stock with sinking fund, mandatorily redeemable preferred securities, and long-term debt, including the currently maturing portion. Net capital consists of net debt, common shareholders' equity, and preferred stock without sinking fund. The preferred stock with sinking fund and mandatorily redeemable preferred securities are included in gross debt pursuant to SFAS 150, which Entergy implemented in the third quarter 2003. The 2002 and 2001 ratios do not reflect those two types of securities as debt, but do include them in net capital, which is how Entergy presented those securities prior to implementation of SFAS 150.

As discussed in the Form 10-K, Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and Entergy Mississippi each had a 364-day credit facility due to expire in May 2003. In April 2003, Entergy Arkansas renewed its credit facility for the same amount, $63 million, until April 2004. In May 2003, Entergy Louisiana and Entergy Mississippi each renewed their facilities for the same amounts, $15 million and $25 million, respectively, until May 2004. Entergy Corporation also renewed its facility in May 2003 for the same amount, $1.45 billion, until May 2004. As of September 30, 2003, $405 million was outstanding on the Entergy Corporation credit facility. No borrowings were outstanding on the other facilities at September 30, 2003.

Following are the amounts of Entergy's planned construction and other capital investments by operating segment for 2003 through 2005, which reflect changes in management's estimate from the planned investments presented in the Form 10-K due mainly to the effect of actual spending in 2003 (the figures for 2003 include the effect of actual spending thus far in 2003):

See the Form 10-K for further discussion of Entergy's capital spending plans for 2003 through 2005.

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. At its July 2003 meeting, the Board increased Entergy's quarterly dividend per share by 29%, to $0.45. Entergy expects the next review of a potential dividend increase will occur in October 2004. Given the current number of Entergy common shares outstanding, Entergy expects the July 2003 dividend increase to result in an incremental annual increase in cash used of approximately $90 million.

As shown in Entergy's Statements of Cash Flows, cash flows for the nine months ended September 30, 2003 and 2002 were as follows:

• The U.S. Utility provided $1,177 million in operating cash flow in 2003 compared to providing $1,449 million in 2002. The decrease primarily resulted from higher payments for fuel during the period, which also significantly increased the amount of deferred fuel costs. Management expects that the deferred fuel costs will be recovered through regulatory recovery mechanisms currently in place.
• The Non-Utility Nuclear segment provided $198 million in operating cash flow in 2003 compared to providing $303 million in 2002 primarily due to increased nuclear refueling outage costs in 2003.
• The non-nuclear wholesale asset business used $75 million in operating cash flow in 2003 compared to using $27 million in 2002. The increase in cash used primarily resulted from a one-time $33 million payment related to a gas services and generation contract in the non-nuclear wholesale assets business.
• Operating cash flow used by the investment in Entergy-Koch, L.P. increased by $13 million. This increase was due to an increase in tax payments related to Entergy's investment in Entergy-Koch due to increased income from the investment. Almost entirely offsetting the increased tax payments was the receipt of a $75 million dividend from Entergy-Koch in 2003.

Recent tax legislation and elections

As discussed in the Form 10-K, Entergy Louisiana made a change in its method of accounting for tax purposes related to the contract to purchase power from the Vidalia project. This change provided cash flow benefits in 2001 and 2002.

In addition, due to book/tax timing differences associated with recent income tax legislation and certain income tax elections, Entergy could obtain cash flow benefits of $1 billion over the years 2003 through 2005. These timing differences will then reverse over the remaining life of Entergy's depreciable assets.

Net cash used in investing activities increased by $721 million for the nine months ended September 30, 2003 compared to the same period in 2002 primarily due to the following:

• System Energy had three-year letters of credit in place that were scheduled to expire in March 2003 securing certain of its obligations related to the sale-leaseback of a portion of Grand Gulf 1. System Energy replaced the letters of credit with new three-year letters of credit totaling approximately $198 million that are backed by cash collateral. System Energy used approximately $194 million in 2003 to provide this cash collateral.
• The non-nuclear wholesale asset business realized $244 million in net proceeds from sales of businesses in 2002.
• Temporary investments of $150 million matured in 2002, which provided cash flow in 2002.
• Entergy Gulf States has $87 million and Entergy Mississippi has $73 million of other regulatory investments in 2003 as a result of fuel cost under-recoveries. 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. See Note 2 to the consolidated financial statements in this report for discussion of the change in Entergy Mississippi's energy cost recovery rider.

Net cash used in financing activities decreased $264 million for the nine months ended September 30, 2003 compared to the same period in 2002 primarily due to the following:

• Net long-term debt retirements by the U.S. Utility segment were approximately $360 million in 2003 compared to net retirements of approximately $460 million in 2002. See Note 4 to the consolidated financial statements for the details of the long-term debt activity in 2003.
• Entergy Corporation issued $383 million of long-term notes in 2003.
• The non-nuclear wholesale asset business retired $268 million of long-term debt in 2002 related to the repurchase of the rights to acquire turbines discussed in Results of Operations above. Partially offsetting this was the retirement of the $79 million Top of Iowa wind project debt at its maturity in January 2003.
• Entergy repurchased $104 million of its common stock in 2002.

The items causing cash used to decrease in 2003 were partially offset by a decrease in the net borrowings under Entergy Corporation's credit facilities of $130 million in 2003 compared to an increase of $365 million in 2002.

Following is a summary of the activity for the nine months ended September 30, 2003 involving Entergy's long-term debt maturities.

See Note 4 to the consolidated financial statements for further details of long-term debt issuances and retirements in 2003.

On October 1, 2003, Entergy Louisiana purchased its $110.95 million 5.35% Series St. Charles Parish bonds from the holders, pursuant to a mandatory tender provision, and has not remarketed the bonds at this time. Entergy Louisiana used a combination of cash on hand and short-term borrowing to buy-in the bonds.

In July 2003, a principal payment of $102 million was made prior to maturity on Non-Utility Nuclear's notes payable to NYPA using money drawn on Entergy Corporation's 364-day credit facility. As a result of this payment, the letters of credit securing the note payable to NYPA will be resized in November 2003. Entergy expects that a portion of the cash collateral backing the letters of credit will be released at that time.

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

See Note 2 to the consolidated financial statements in the Form 10-K for a discussion of Entergy Gulf States' ninth and last required post-merger analysis filed with the LPSC in May 2002. In April 2003, the LPSC staff filed testimony in which it recommended that the LPSC require a rate refund of $30.3 million and a prospective rate reduction of $75.9 million, before taking into account the $11.5 million rate reduction that Entergy Gulf States implemented effective June 2002. In July 2003, Entergy Gulf States filed testimony rebutting the LPSC staff's testimony and supporting the filing. During discovery, the LPSC staff requested that Entergy Gulf States provide updated cost of service data to reflect changes in costs, revenues, and rate base through December 31, 2002. In September 2003, Entergy Gulf States supplied the updated data. The LPSC staff has not yet indicated whether the updated data will result in changes to its recommendations. A new procedural schedule has been estab lished that requires the LPSC staff to file testimony in December 2003. This testimony will also address new issues presented by the updated 2002 cost of service data. Hearings are scheduled for May 2004. Entergy Gulf States cannot predict the ultimate outcome of this proceeding.

See Note 2 to the consolidated financial statements in the Form 10-K for a discussion of the July 2002 settlement between Entergy Louisiana and the LPSC Staff. In accordance with the settlement, Entergy Louisiana filed a revenue requirement analysis in June 2003. The analysis reflected a revenue deficiency, but Entergy Louisiana has not requested a change in rates. Entergy Louisiana is expected to make a rate filing with the LPSC by mid-2004.

See Note 2 to the consolidated financial statements in the Form 10-K for a discussion of Entergy New Orleans' cost of service study and revenue requirement filed in May 2002 with the City Council for the 2001 test year, and the agreement in principle presented to the City Council in March 2003. In May 2003, the City Council approved the agreement in principle allowing for a $30.2 million increase in base rates effective June 1, 2003. The City Council also approved implementation of formula rate plans for electric and gas service that will be evaluated annually until 2005. The midpoint return on equity of both plans is 11.25%, with a target equity component of 42%. The electric plan provides for a bandwidth of 10.25% to 12.25% and the gas plan provides for a bandwidth of 11% to 11.5%, with earnings within those ranges not resulting in a change in rates. In addition, the City Council approved implementation of a generation performance-based rate calculation in the electric fuel adjust ment clause under which Entergy New Orleans will receive 10% of fuel and purchased power cost savings in excess of $20 million, subject to a 13.25% return on equity limitation for electric operations as provided for in the electric formula rate plan. Entergy New Orleans will bear 10% of any "negative" fuel and purchased power cost savings. Certain intervenors in the proceeding have appealed the City Council's approval to the Civil District Court for the Parish of Orleans. Entergy New Orleans and the City Council will oppose the appeal, but the outcome cannot be predicted.

In approving the agreement in principle, the City Council indicated that if the City Council decides in favor of the plaintiffs in either of the lawsuits described in Part I, Item 1 of the Form 10-K in the paragraphs entitled "Entergy New Orleans Fuel Clause Lawsuit" and "Entergy New Orleans Rate of Return Lawsuit," the effect of that decision on the rate agreement would have to be determined. The City Council also indicated that the Entergy New Orleans power agreements described in Part II, Item 5, "Generation" in this report are fundamental to the rate agreement, and a FERC decision or order requiring a material change in the power agreements may result in a City Council investigation to determine what prospective action, if any, would be warranted by any such FERC decision or order to preserve the benefits that were otherwise projected to accrue to customers under the rate settlement.

Power Generation

As discussed more fully in the Form 10-K, the sale of electricity from the power generation plants owned by Entergy's Non-Utility Nuclear business and Energy Commodity Services, unless otherwise contracted, is subject to the fluctuation of market power prices. Following is an updated summary of the amount of Non-Utility Nuclear's and Energy Commodity Services' output that is sold forward as of September 30, 2003 under physical or financial contracts at fixed prices (2003 represents the remainder of the year):

The Vermont Yankee acquisition included a 10-year PPA under which the former owners will buy the power produced by the plant, which is through the expiration 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 annually, 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, 12% in 2006, and 11% in 2007 is sold forward from Vermont Yankee after October 2005.

Included in the Non-Utility Nuclear planned generation sold forward percentages are contracts entered into in 2003 that are not unit contingent but are firm contracts containing liquidated damages provisions. These firm contracts are for 4% of Non-Utility Nuclear's planned generation in 2005, 4% in 2006, and 2% in 2007.

The increase in the Energy Commodity Services planned generation sold forward percentages from the percentages reported in the Form 10-K is attributable to the Entergy Louisiana and Entergy New Orleans contracts involving RS Cogen and Independence entered into in 2003 that are described more fully in Part II, Item 5, "Generation." As discussed in Part II, Item 5, these contracts are still subject to a FERC review proceeding scheduled for hearing in April 2004.

Marketing and Trading

As discussed in the Form 10-K, EKT uses value-at-risk models as one measure of the market risk of a loss in fair value for EKT's natural gas and power trading portfolio. EKT's value-at-risk measures, which it calls Daily Earnings at Risk (DE@R), for its trading portfolio were as follows (using a 97.5% confidence level):

Following are EKT's mark-to-market assets (liabilities) and the period within which the assets (liabilities) would be realized (paid) in cash if they are held to maturity and market prices are unchanged:

Following is a roll-forward of the change in the fair value of EKT's mark-to-market contracts for the nine months ended September 30, 2003:

See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Significant Factors and Known Trends, Transmission" in the Form 10-K for discussion of the proposed SeTrans RTO. At this time, management does not expect the proposed SeTrans RTO to become operational before the last half of 2005.

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 the proposal that Entergy Gulf States filed for an interim solution (retail open access without a FERC-approved RTO). The PUCT considered the proposal at a March 2003 hearing, and issued an order in April 2003. The order set forth a sequence of proceedings and activities designed to initiate an interim solution in the first half of 2004. These proceedings and activities include ruling on market protocols; initiating a proceeding to certify an independent organization to administer the market protocols and ensure nondiscriminatory access to transmission and distribution systems; resuming business separation proceedings; re-invigorating the pilot project; and initiating a market-readiness proceeding. In June 2003, the PUCT voted 2 to 1 to issue an order on rehearing in the interim solution procee ding. The PUCT issued the written order on rehearing in late-July 2003 in which it identified December 2004 as the target date for the beginning of the interim solution. Also in July 2003, the PUCT directed the parties to continue negotiations on unresolved issues in the market protocols docket. Several of the parties to that proceeding filed a settlement agreement with respect to the market protocols that the PUCT approved, after hearings, in an order issued in September 2003. Consistent with the order, Entergy Services has made a filing at the FERC requesting approval on an expedited basis of the market protocols subject to FERC jurisdiction.

In September 2003, the PUCT issued a written order that approved the Price to Beat (PTB) fuel factor for Entergy Gulf States, which is to be implemented upon the commencement of retail open access in its Texas service territory. This PTB fuel factor is subject to revision based on PUCT rules. The PUCT declined consideration of a request for rehearing sought by certain cities in Texas served by Entergy Gulf States and the Office of Public Utility Counsel. The period for appeal of the order remains open.

Federal legislation intended to facilitate wholesale competition in the electric power industry has been seriously considered by the last three United States Congresses, in both the House of Representatives and the Senate. In 2003, both the House and Senate have passed separate versions of comprehensive energy legislation. The bills contain electricity provisions that would, among other things, repeal PUHCA, repeal or modify PURPA, enact a mechanism for establishing enforceable reliability standards, provide FERC with new authority over utility mergers and acquisitions, and codify FERC's authority over market-based rates. The legislation is currently before a conference committee for resolution of the differences between the two bills.

See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Significant Factors and Known Trends, Nuclear Matters" in the Form 10-K for discussion of various issues related to Entergy owning and operating nuclear power plants, and in particular the Indian Point units. Regarding FEMA's February 2003 report, and FEMA possibly reevaluating its decision not to provide "reasonable assurance" regarding Indian Point's radiological emergency measures, in July 2003 FEMA sent a letter to the Governor of New York transmitting its determination of reasonable assurance that the off-site preparedness for the Indian Point units is adequate. FEMA stated that it had reasonable assurance that appropriate measures to protect the health and safety of surrounding communities can be taken and are capable of being implemented in the event of a radiological incident at Indian Point. After receiving FEMA's review of the Indian Point off-site emergency preparedness plans and procedures, the NRC st ated that it had determined that Indian Point's on-site emergency preparedness plans and procedures for radiological events meet the requisite criteria for reasonable assurance of adequate protection. The NRC then stated that its overall determination continues to be that Indian Point emergency preparedness is satisfactory and provides reasonable assurance of adequate protection. In August 2003, Westchester County filed an administrative appeal of FEMA's ruling stating that the emergency plans are adequate to protect the public health and safety.

As described in Part II, Item 5 herein, Entergy has filed with the FERC several agreements for the supply of power to Entergy Louisiana and Entergy New Orleans. The agreements involve power purchases from Entergy affiliates. In May 2003, the FERC accepted the agreements for filing, subject to refund, with the contracts becoming effective on June 1, 2003. The FERC also established a hearing process to review the agreements. Several parties have intervened or filed protests regarding the agreements filed with the FERC and the request-for-proposals process that led to the agreements, and the proceeding is set for hearing in April 2004.

In July 2003, Entergy announced an initiative to achieve productivity improvements with a goal of reducing costs, primarily in the Non-Utility Nuclear and U.S. Utility businesses, while maintaining reliability, safety, and service levels. As part of that initiative, Entergy is offering a voluntary severance program to employees in various departments targeting a reduction of approximately 1,000 employees with acceptances occurring in October through December 2003. Approximately 600 nuclear employees in total from the Non-Utility Nuclear and U.S. Utility businesses have accepted thus far, with additional offers currently in process to union employees in the Non-Utility Nuclear business. Additional Entergy departments also have offers in process. Management expects the voluntary severance program to cause severance expense for Entergy in the fourth quarter of 2003 of approximately $80 million to $105 million, after-tax.

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. Following is an update to the information provided in the Form 10-K.

As discussed in the Form 10-K, Entergy implemented SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. Implementation had the following effect on Entergy's financial statements:

• The net effect of implementing this standard for the rate-regulated portion of the domestic utility companies and System Energy was recorded as a regulatory asset, with no resulting impact on Entergy's net income. Assets and liabilities increased approximately $1.1 billion for the domestic utility companies and System Energy as a result of increasing the asset retirement obligations by $1.1 billion to their fair values as determined under SFAS 143, increasing utility plant by $288 million, reducing accumulated depreciation by $361 million, and recording the related regulatory assets of $422 million. The implementation of SFAS 143 for the portion of River Bend not subject to cost-based ratemaking decreased earnings by approximately $21 million net-of-tax ($0.09 per share) as a result of the one-time cumulative effect of accounting change.
• For the Non-Utility Nuclear business, the implementation of SFAS 143 resulted in a decrease in liabilities of approximately $520 million due to reductions in decommissioning liabilities, a decrease in assets of approximately $360 million, including a decrease in electric plant in service of $336 million, and an increase in earnings of approximately $160 million ($0.70 per share) as a result of the one-time cumulative effect of accounting change.

Also, Entergy expects 2003 earnings for the Non-Utility Nuclear business to increase by approximately $19 million after-tax because of the change in accretion of the decommissioning liability and depreciation of the adjusted plant costs. This effect will gradually decrease over future years as the accretion of the liability increases. Management expects that applying SFAS 143 post-implementation will have a minimal effect on ongoing earnings for the U.S. Utility business.

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Employment Litigation

Entergy Corporation and certain subsidiaries are defendants in numerous lawsuits filed by former employees asserting that they were wrongfully terminated and/or discriminated against on the basis of age, race, sex, or other protected characteristics. The defendant companies are vigorously defending these suits and deny any liability to the plaintiffs.

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

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 the proposal that Entergy Gulf States filed for an interim solution (retail open access without a FERC-approved RTO). The PUCT considered the proposal at a March 2003 hearing, and issued an order in April 2003. The order set forth a sequence of proceedings and activities designed to initiate an interim solution in the first half of 2004. These proceedings and activities include ruling on market protocols; initiating a proceeding to certify an independent organization to administer the market protocols and ensure nondiscriminatory access to transmission and distribution systems; resuming business separation proceedings; re-invigorating the pilot project; and initiating a market-readiness proceeding. In June 2003, the PUCT voted 2 to 1 to issue an order on rehearing in the interim solution proceeding. The PUCT issued the written order on rehearing in late-July 2003 in which it identified December 2004 as the target date for the beginning of the interim solution. Also in July 2003, the PUCT directed the parties to continue negotiations on unresolved issues in the market protocols docket. Several of the parties to that proceeding filed a settlement agreement with respect to the market protocols that the PUCT approved, after hearings, in an order issued in September 2003. Consistent with the order, Entergy Services has made a filing at the FERC requesting approval on an expedited basis of the market protocols subject to FERC jurisdiction.

In September 2003, the PUCT issued a written order that approved the Price to Beat (PTB) fuel factor for Entergy Gulf States, which is to be implemented upon the commencement of retail open access in its Texas service territory. This PTB fuel factor is subject to revision based on PUCT rules. The PUCT declined consideration of a request for rehearing sought by certain cities in Texas served by Entergy Gulf States and the Office of Public Utility Counsel. The period for appeal of the order remains open. Management cannot predict the ultimate outcome of this proceeding at this time.

In January 2001, Entergy Gulf States' filed a fuel reconciliation with the PUCT that covered the period from March 1999 through August 2000 and requested a surcharge. The case was argued before the Travis County Texas District Court in August 2003 challenging the PUCT's disallowance of approximately $4.2 million related to imputed capacity costs and its disallowance related to costs for energy delivered from the 30% non-regulated share of River Bend. The Travis County District Court judge affirmed the PUCT's order. In October 2003, Entergy Gulf States appealed this decision to the Court of Appeals.

In February 2003, Entergy Gulf States implemented a $54 million interim fuel surcharge authorized by the PUCT to collect under-recovered fuel costs from March through August 2002. The surcharge will be collected through December 2003.

In September 2003, Entergy Gulf States filed an application with the PUCT to implement an $87.3 million interim fuel surcharge, including interest, to collect under-recovered fuel and purchased power expenses incurred from September 2002 through August 2003. Hearings were held in October 2003 and the PUCT is expected to issue an order in December 2003. Entergy Gulf States has requested that the surcharge be collected over a twelve-month period beginning January 2004. The outcome of this proceeding cannot be predicted at this time.

In August 2000, the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Louisiana pursuant to a November 1997 LPSC general order. The time period that is the subject of the audit is January 1, 2000 through December 31, 2001. In September 2003, the LPSC staff issued its audit report and only recommended one material issue as disallowable. The issue, which was previously raised in the summer 2001 purchased power docket, relates to the alleged failure to uprate Waterford 3 in a timely manner. The LPSC staff has quantified the possible disallowance as between $7.6 and $14 million. Entergy Louisiana is currently evaluating the LPSC staff report and expects to contest the recommendation.

In May 2003, Entergy Mississippi filed and the MPSC approved a change in Entergy Mississippi's energy cost recovery rider. Under the MPSC's order, Entergy Mississippi has deferred until 2004 the collection of fuel under-recoveries for the first and second quarters of 2003 that would have been collected in the third and fourth quarters of 2003, respectively. The deferred amount of $77.6 million plus carrying charges will be collected through the energy cost recovery rider over a six-month period beginning January 2004.

See Note 2 to the consolidated financial statements in the Form 10-K for a discussion of the March 1998 PUCT disallowance of recovery of River Bend plant costs that had been held in abeyance since 1988, and subsequent proceedings. On July 11, 2003, the Third District Court of Appeals unanimously affirmed the judgment of the Travis County District Court that had affirmed the PUCT disallowance. In August 2003, Entergy Gulf States filed a petition for review by the Texas Supreme Court. Nevertheless, after considering the progress of the proceeding in light of the decision of the Court of Appeals, management has concluded that it is prudent to accrue for the loss that would be associated with a final, non-appealable decision disallowing the abeyed plant costs. The net carrying value of the abeyed plant costs was $107.7 million as of June 30, 2003, and after this accrual Entergy Gulf States provided for all potential loss related to current or past contested costs of construction o f the River Bend plant. Accrual of the loss was recorded in the second quarter 2003 and reduced net income by $65.6 million.

See Note 2 to the consolidated financial statements in the Form 10-K for a discussion of Entergy Gulf States' ninth and last required post-merger analysis filed with the LPSC in May 2002. In April 2003, the LPSC staff filed testimony in which it recommended that the LPSC require a rate refund of $30.3 million and a prospective rate reduction of $75.9 million, before taking into account the $11.5 million rate reduction that Entergy Gulf States implemented effective June 2002. In July 2003, Entergy Gulf States filed testimony rebutting the LPSC staff's testimony and supporting the filing. During discovery, the LPSC staff requested that Entergy Gulf States provide updated cost of service data to reflect changes in costs, revenues, and rate base through December 31, 2002. In September 2003, Entergy Gulf States supplied the updated data. The LPSC staff has not yet indicated whether the updated data will result in changes to its recommendations. A new procedural schedule has been established that requires the LPSC staff to file testimony in December 2003. This testimony will also address new issues presented by the updated 2002 cost of service data. Hearings are scheduled for May 2004. Entergy Gulf States cannot predict the ultimate outcome of this proceeding.

See Note 2 to the consolidated financial statements in the Form 10-K for a discussion of proceedings in Entergy Louisiana's second annual performance-based formula rate plan filing made with the LPSC for the 1996 test year. The case was argued before the U.S. Supreme Court in April 2003. The U.S. Supreme Court ruled in favor of Entergy Louisiana and reversed the LPSC's decision requiring an additional rate reduction and refund.

See Note 2 to the consolidated financial statements in the Form 10-K for a discussion of the July 2002 settlement between Entergy Louisiana and the LPSC Staff. In accordance with the settlement, Entergy Louisiana filed a revenue requirement analysis on June 27, 2003. The analysis reflected a deficiency, but Entergy Louisiana has not requested a change in rates. Entergy Louisiana is expected to make a rate filing with the LPSC by mid-2004.

See Note 2 to the consolidated financial statements in the Form 10-K for a discussion of Entergy New Orleans' cost of service study and revenue requirement filed in May 2002 with the City Council for the 2001 test year, and the agreement in principle presented to the City Council in March 2003. In May 2003, the City Council approved the agreement in principle allowing for the $30.2 million increase in base rates effective June 1, 2003. Certain intervenors have appealed the City Council's approval to Civil District Court for the Parish of Orleans. Entergy New Orleans and the City Council will oppose the appeal, but the outcome cannot be predicted.

Natural Gas

See Note 2 to the consolidated financial statements in the Form 10-K for a discussion of a resolution adopted in August 2001 by the City Council that ordered Entergy New Orleans to account for $36 million of certain natural gas costs charged to its gas distribution customers from July 1997 through May 2001. In May 2003, the City Council approved a settlement that resolved all matters relating to this proceeding. Pursuant to the resolution of the matter, effective with the first billing cycle in June 2003, Entergy New Orleans credited $14.6 million to the purchased gas adjustment clause account, decreasing the cost responsibility of the gas customers, and debited $6.7 million to the electric fuel adjustment clause account, which increased the cost responsibility of Entergy New Orleans' retail electric customers. Resolution of the matter also required that Entergy New Orleans forego recovery from its gas customers of approximately $3.6 million of gas costs, reflecting an adjustme nt that had been made in the purchased gas adjustment clause account as of January 2002.

Fuel Adjustment Clause Litigation

See "Fuel Adjustment Clause Litigation" in Note 2 to the consolidated financial statements in the Form 10-K for a discussion of the complaint filed by a group of ratepayers in state court in Orleans Parish and with the City Council regarding certain costs passed on to ratepayers in Entergy New Orleans' fuel adjustment filings with the City Council.

The following tables present Entergy's basic and diluted earnings per share (EPS) calculations included on the consolidated income statement:

Entergy's stock option and other stock compensation plans are discussed in Note 5 to the consolidated financial statements in the Form 10-K.

During the nine months ended September 30, 2003, Entergy Corporation issued 6,073,727 shares of its previously repurchased common stock to satisfy stock option exercises and other stock-based awards.

Entergy Corporation has in place a 364-day bank credit facility that expires in May 2004 with a borrowing capacity of $1.45 billion, of which $405 million was outstanding as of September 30, 2003. Although the Entergy Corporation credit line expires in May 2004, Entergy has the discretionary option to extend the period to repay the amount then outstanding for an additional 364-day term. Because of this option, which Entergy intends to exercise if it does not renew the credit line or obtain an alternative source of financing, the debt outstanding under the credit line is reflected in long-term debt on the balance sheet. The weighted-average interest rate on Entergy's outstanding borrowings under this facility as of September 30, 2003 was 2.45%. The commitment fee for this facility is currently 0.20% of the line amount. Commitment fees and interest rates on loans under the credit facility can fluctuate depending on the senior debt ratings of the domestic utility companies.

The short-term borrowings of Entergy's subsidiaries are limited to amounts authorized by the SEC. The current limits authorized are effective through November 30, 2004. In addition to borrowing from commercial banks, Entergy's subsidiaries are authorized to borrow from the Entergy System Money Pool (money pool). The money pool is an inter-company borrowing arrangement designed to reduce Entergy's subsidiaries' dependence on external short-term borrowings. Borrowings from the money pool and external borrowings combined may not exceed the SEC authorized limits. As of September 30, 2003, Entergy's subsidiaries' authorized limit was $1.6 billion and the outstanding borrowing from the money pool was $145.1 million. There were no borrowings outstanding from external sources.

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

The facilities have variable interest rates and the average commitment fee is 0.14%.

The following long-term debt has been issued by Entergy in 2003:

The following long-term debt has been retired by Entergy in 2003:

On October 1, 2003, Entergy Louisiana purchased its $110.95 million 5.35% Series St. Charles Parish bonds from the holders, pursuant to a mandatory tender provision, and has not remarketed the bonds at this time. Entergy Louisiana used a combination of cash on hand and short-term borrowing to buy-in the bonds.

On October 31, 2003, Entergy Corporation's Board of Directors declared a common stock dividend of $0.45 per share, payable on December 1, 2003, to holders of record as of November 12, 2003.

Entergy's reportable segments as of September 30, 2003 are U.S. Utility, Non-Utility Nuclear, and Energy Commodity Services. "All Other" includes the parent company, Entergy Corporation, and other business activity, including earnings on the proceeds of sales of previously-owned businesses.

Entergy's segment financial information for the third quarters of 2003 and 2002 is as follows:

Entergy's segment financial information for the nine months ended September 30, 2003 and 2002 is as follows:

Businesses marked with * are sometimes referred to as the "competitive businesses," with the exception of the parent company, Entergy Corporation. Eliminations are primarily intersegment activity.

Energy Commodity Services' net loss for the nine months ended September 30, 2002 includes charges of $391.6 million to operating expenses ($254.2 million net-of-tax) to reflect the effect of Entergy's decision to discontinue additional greenfield power plant development and to reflect asset impairments resulting from the deteriorating economics of wholesale power markets in the United States and the United Kingdom.

SFAS 143, "Accounting for Asset Retirement Obligations," which was implemented effective January 1, 2003, requires the recording of liabilities for all legal obligations associated with the retirement of long-lived assets that result from the normal operation of those assets. These liabilities are recorded at their fair values (which are likely to be the present values of the estimated future cash outflows) in the period in which they are incurred, with an accompanying addition to the recorded cost of the long-lived asset. The asset retirement obligation is accreted each year through a charge to expense, to reflect the time value of money for this present value obligation. The amounts added to the carrying amounts of the long-lived assets are depreciated over the useful lives of the assets. The net effect of implementing this standard for the rate-regulated business of the domestic utility companies and System Energy was recorded as a regulatory asset, with no resulting impact on E ntergy's net income. Entergy recorded these regulatory assets because existing rate mechanisms in each jurisdiction are based on the principle that Entergy will recover all ultimate costs of decommissioning from customers. As a result of this treatment, SFAS 143 is expected to be earnings neutral to the rate-regulated business of the domestic utility companies and System Energy. Assets and liabilities increased by approximately $1.1 billion for the domestic utility companies and System Energy as a result of recording the asset retirement obligations at their fair values of $1.1 billion as determined under SFAS 143, increasing utility plant by $288 million, reducing accumulated depreciation by $361 million and recording the related regulatory assets of $422 million. The implementation of SFAS 143 for the portion of River Bend not subject to cost-based ratemaking decreased earnings in the first quarter of 2003 by approximately $21 million net-of-tax ($0.09 per share) as a result of the one-time cumulative e ffect of accounting change. In accordance with ratemaking treatment and as required by SFAS 71, the depreciation provisions for Entergy's utility subsidiaries include a component for removal costs that are not asset retirement obligations under SFAS 143. Approximately 6% of the U.S. Utility's current depreciation rates, on a weighted average basis, represents a component for the net of salvage value and removal costs. Per regulatory accounting requirements, this component is included in accumulated depreciation on the balance sheet. For the Non-Utility Nuclear business, the implementation of SFAS 143 resulted in a decrease in liabilities of approximately $520 million due to reductions in decommissioning liabilities, a decrease in assets of approximately $360 million, including a decrease in electric plant in service of $336 million, and an increase in earnings in the first quarter of 2003 of approximately $160 million net-of-tax ($0.70 per share) as a result of the one-time cumulative effect of accountin g change. If SFAS 143 had been applied by Entergy during all prior periods, the following impacts would have resulted:

As discussed in Note 1 to the consolidated financial statements in the Form 10-K, Entergy applies the provisions of SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities," in accounting for investments in decommissioning trust funds. As a result, Entergy records the decommissioning trust funds at their fair value on the consolidated balance sheet. The fair value of the securities held in such funds differs from the amounts deposited plus the earnings on the deposits. In accordance with the regulatory treatment for decommissioning trust funds, the domestic utility companies and System Energy have recorded an offsetting amount of unrealized gains/(losses) on investment securities in other regulatory liabilities. For the nonregulated portion of River Bend, Entergy Gulf States has recorded an offsetting amount of unrealized gains/(losses) on investment securities in other deferred credits. Prior to the implementation of SFAS 143, the offsetting amount of unrealized g ains/(losses) on investment securities was recorded in accumulated depreciation for the rate-regulated business of the domestic utility companies. Decommissioning trust funds for Pilgrim, Indian Point 2, and Vermont Yankee do not receive regulatory treatment. Accordingly, unrealized gains and losses recorded on the assets in these trust funds are recognized as a separate component of shareholders' equity because these assets are classified as available for sale.

SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity," was issued in May 2003 and became effective July 1, 2003. This new standard requires mandatorily redeemable financial instruments to be classified and treated as liabilities in the presentation of financial position and results of operations. The only effect of implementing this new standard for Entergy is the inclusion of long-term debt, preferred stock with sinking fund, and company-obligated mandatorily redeemable preferred securities under the liabilities caption in Entergy's balance sheet. Entergy's results of operations and cash flows were not affected by this new standard.

Entergy has two plans that grant stock options, which are described more fully in Note 5 to the consolidated financial statements in the Form 10-K. Prior to 2003, Entergy applied the recognition and measurement principles of APB Opinion 25, "Accounting for Stock Issued to Employees," and related Interpretations in accounting for those plans. No stock-based employee compensation expense is reflected in 2002 net income as all options granted under those plans have an exercise price equal to the market value of the underlying common stock on the date of grant. Effective January 1, 2003, Entergy prospectively adopted the fair value based method of accounting for stock options prescribed by SFAS 123, "Accounting for Stock-Based Compensation." Awards under Entergy's plans vest over three years. Therefore, the cost related to stock-based employee compensation included in the determination of net income for 2003 is less than that which would have been recognized if the fair value based me thod had been applied to all awards since the original effective date of SFAS 123. The following table illustrates the effect on net income and earnings per share if Entergy would have historically applied the fair value based method of accounting to stock-based employee compensation.

__________________________________

In the opinion of the management of Entergy Corporation, the accompanying unaudited financial statements contain all adjustments (consisting primarily of normal recurring accruals and reclassification of previously reported amounts to conform to current classifications) necessary for a fair statement of the results for the interim periods presented. The business of the U.S. Utility segment, however, is subject to seasonal fluctuations with the peak periods occurring during the third quarter. The results for the interim periods presented should not be used as a basis for estimating results of operations for a full year.

Net income decreased $5.3 million primarily due to an increase in the effective income tax rate for the third quarter of 2003 compared to the third quarter of 2002.

Net income increased $27.3 million primarily due to the following:

• an increase in net base revenue;
• an increase in other net revenue items including transmission revenue, energy cost recovery true-up, and Grand Gulf retained share revenue;
• a decrease in other operation and maintenance expenses, a portion of which is offset by a corresponding decrease in other regulatory credits and has no effect on net income;
• an increase in net wholesale revenue;
• a decrease in other interest charges, a portion of which is offset by a corresponding decrease in other regulatory credits and has no effect on net income;
• a decrease in taxes other than income taxes; and
• the effect of the March 2002 settlement agreement and 2001 earnings review, the net impact of which is an $2.2 million increase in net income.

Net base revenue increased $10.4 million primarily due to increased electricity usage of 239 GWh in the residential and commercial sectors.

• expenses in 2002 of $159.9 million due to the March 2002 settlement agreement and 2001 earnings review allowing Entergy Arkansas to recover a large majority of 2000 and 2001 ice storm repair expenses through the previously-collected transition cost account amounts (offset in other regulatory credits as discussed above);
• a decrease of $7.5 million due to the 2002 accrual of the estimate of the liability for the future disposal of low-level radioactive waste materials; and
• decreases in administrative and general expenses offset by an increase in benefits cost.

Net wholesale revenue increased $8.2 million primarily due to an increase in sales volume and higher wholesale prices.

Interest charges decreased due to an increase in interest expense in 2002 resulting from a true-up of the annual fuel recovery rider in March 2002 of $4.5 million and interest recorded in 2002 of $4.1 million (offset in other regulatory credits as discussed above) on the transition cost account obligation, which is now terminated as a result of the March 2002 settlement agreement.

Taxes other than income taxes decreased $3.1 million primarily due to decreased sales and ad valorem taxes.

The increase in net income was partially offset by the following:

• a decrease in unbilled revenue of $10.5 million as a result of less favorable sales volume primarily due to the effect of colder winter weather in December 2002; and
• an increase in depreciation and amortization expenses of $10.3 million primarily due to an increase in plant in service.

The March 2002 settlement agreement is discussed further in Note 2 to the domestic utility companies and System Energy financial statements in the Form 10-K.

The effective income tax rates for the third quarters of 2003 and 2002 were 41.0% and 36.6%, respectively. The effective income tax rates for the nine months ended September 30, 2003 and 2002 were 39.8% and 38.7%, respectively. The difference in the effective income tax rate for the third quarter 2003 versus the federal statutory rate of 35.0% is primarily due to state income taxes net of federal in addition to depreciation book and tax differences. The effective income tax rate was lower in the third quarter of 2002 than in the third quarter of 2003 because of book and tax differences related to the March 2002 settlement agreement. The difference in the effective income tax rate for the nine months ended September 30, 2003 versus the federal statutory rate of 35.0% is primarily due to aforementioned differences, partially offset by the effect of flow-through book and tax differences related to liability reserve accruals and the amortization of investment tax credits.

Decommissioning expense increased $9.0 million due to the implementation of SFAS 143, "Accounting for Asset Retirement Obligations." The increase in decommissioning expense is offset by increases in other regulatory credits and interest and dividend income and has no effect on net income.

Decommissioning expense increased $26.9 million due to the implementation of SFAS 143, "Accounting for Asset Retirement Obligations." The increase in decommissioning expense is offset by corresponding increases in other regulatory credits and interest and dividend income and has no effect on net income.

Cash flows for the nine months ended September 30, 2003 and 2002 were as follows:

Cash flow from operations increased $26.7 million for the nine months ended September 30, 2003 compared to the nine months ended September 30, 2002 primarily due to income tax refunds received of $18.1 million during the nine months ended September 30, 2003 versus income taxes paid of $9.4 million during the nine months ended September 30, 2002. Money pool activity also contributed $57.2 million to the increase in cash flow from operations, as did an increase in net income as explained above. The increase in cash flow from operations was partially offset by an increase in deferred fuel costs for the nine months ended September 30, 2003 versus a decrease for the nine months ended September 30, 2002.

Entergy Arkansas' receivables from or (payables) to the money pool were as follows:

Recent tax legislation and elections

Due to book/tax timing differences associated with recent income tax legislation and certain income tax elections, Entergy Arkansas could obtain cash flow benefits of $305 million over the years 2003 through 2005. These timing differences will then reverse over the remaining life of Entergy Arkansas' depreciable assets.

The increase of $62.3 million in net cash used in investing activities for the nine months ended September 30, 2003 compared to the nine months ended September 30, 2002 was primarily due to the maturity of $38.4 million of other temporary investments in the first quarter of 2002. The increase was also due to an increase in under-recovered fuel and purchased power expenses of $14.7 million that have been deferred and are expected to be collected over a period greater than twelve months. See Note 1 to the domestic utility companies and System Energy financial statements in the Form 10-K for further discussion of the accounting for fuel costs.

The increase of $2.2 million in net cash used by financing activities for the nine months ended September 30, 2003 compared to the nine months ended September 30, 2002 was primarily due to the net redemption of $33.6 million more in long-term debt for the nine months ended September 30, 2003 compared to the nine months ended September 30, 2002, substantially offset by the payment of $30.8 million less in common stock dividends during the same period.

Entergy Arkansas has implemented a planned financing program to address its long-term debt maturities and to restructure its debt portfolio, which will result in extended maturities, lowered rates, and additional flexibility.

The following table lists First Mortgage Bonds issued by Entergy Arkansas in 2003:

The following table lists First Mortgage Bonds retired by Entergy Arkansas in 2003:

Entergy Arkansas used proceeds from a $100 million November 2002 issuance and the 2003 First Mortgage Bond issuances for the retirements in 2003.

See "Management's Financial Discussion and Analysis - Liquidity and Capital Resources" in the Form 10-K for a discussion of Entergy Arkansas' uses and sources of capital. Following is an update to the information provided in the Form 10-K.

In April 2003, Entergy Arkansas renewed its 364-day credit facility through April 30, 2004. The amount available under the credit facility is $63 million, of which none was drawn at September 30, 2003.

See "Management's Financial Discussion and Analysis - Significant Factors and Known Trends" in the Form 10-K for a discussion of utility restructuring, System Agreement proceedings, market and credit risks, state and local regulatory risks, nuclear matters, and environmental risks. Following are updates to the information provided in the Form 10-K.

As discussed in the Form 10-K, Entergy issued a Request for Proposal (RFP) to provide replacement steam generators for ANO 1. Two companies submitted bids in response to the RFP. Entergy subsequently entered into a contract with one of the companies for delivery of the replacement steam generators in August 2005 in time for installation during a scheduled refueling outage beginning in September 2005. The other company filed a lawsuit in federal district court in Virginia seeking a temporary and permanent injunction against the winning bidder claiming that the winning bidder was using the other company's proprietary information in the design and fabrication of the replacement generators. The lawsuit has been settled, and the litigation has been dismissed with prejudice. The dispute should not affect the delivery date or the cost of the steam generators.

In January 2003, Entergy Arkansas filed a Petition for Declaratory Order to request a finding by the APSC that replacement of the steam generators and reactor vessel closure head at ANO 1 is in the public interest. The APSC found that the replacement is in the public interest in a declaratory order issued in May 2003.

                                        ENTERGY ARKANSAS, INC.
                                           INCOME STATEMENTS
                    For the Three and Nine Months Ended September 30, 2003 and 2002
                                              (Unaudited)

                                        Three Months Ended      Nine Months Ended
                                        2003          2002      2003         2002
                                         (In Thousands)           (In Thousands)


         OPERATING REVENUES
Domestic electric                    $469,925       $474,873  $1,227,558   $1,220,622
                                     --------       --------  ----------   ----------
         OPERATING EXPENSES
Operation and Maintenance:
   Fuel, fuel-related expenses, and
     gas purchased for resale          30,581         76,005     107,669      249,468
   Purchased power                    139,829        102,485     363,295      262,440
   Nuclear refueling outage expenses    5,679          5,877      17,565       18,935
   Other operation and maintenance     93,632         94,501     259,445      430,616
Decommissioning                         8,971              -      26,915            -
Taxes other than income taxes           8,961          9,481      26,973       30,054
Depreciation and amortization          50,846         47,229     150,733      140,410
Other regulatory charges (credits) -   (4,364)           408     (20,896)    (175,314)
  net
                                     --------       --------  ----------   ----------
TOTAL                                 334,135        335,986     931,699      956,609
                                     --------       --------  ----------   ----------


OPERATING INCOME                      135,790        138,887     295,859      264,013
                                     --------       --------  ----------   ----------


            OTHER INCOME
Allowance for equity funds used         2,047          2,243       6,276        5,543
  during construction
Interest and dividend income            2,551            498       7,178        2,063
Miscellaneous - net                      (871)          (593)     (3,384)      (5,121)
                                     --------       --------  ----------   ----------
TOTAL                                   3,727          2,148      10,070        2,485
                                     --------       --------  ----------   ----------

     INTEREST AND OTHER CHARGES
Interest on long-term debt             21,465         22,189      64,093       63,574
Other interest - net                      613          1,174       2,743       12,222
Distributions on preferred              1,275          1,275       3,825        3,825
  securities of subsidiary
Allowance for borrowed funds used      (1,347)        (1,413)     (3,973)      (3,598)
  during construction
                                     --------       --------  ----------   ----------
TOTAL                                  22,006         23,225      66,688       76,023
                                     --------       --------  ----------   ----------

INCOME BEFORE INCOME TAXES            117,511        117,810     239,241      190,475


Income taxes                           48,192         43,146      95,240       73,725
                                     --------       --------  ----------   ----------

NET INCOME                             69,319         74,664     144,001      116,750

Preferred dividend requirements and     1,944          1,944       5,832        5,832
  other
                                     --------       --------  ----------   ----------

EARNINGS APPLICABLE TO
COMMON STOCK                          $67,375        $72,720    $138,169     $110,918
                                     ========       ========  ==========   ==========

See Notes to Respective Financial Statements.



                               ENTERGY ARKANSAS, INC.
                              STATEMENTS OF CASH FLOWS
                For the Nine Months Ended September 30, 2003 and 2002
                                     (Unaudited)

                                                         2003                  2002
                                                               (In Thousands)


              OPERATING ACTIVITIES
Net income                                               $144,001            $116,750

Noncash items included in net income:
  Other regulatory credits - net                          (20,896)           (175,314)
  Depreciation, amortization, and decommissioning         177,648             140,410
  Deferred income taxes and investment tax credits         (8,501)            (46,672)
  Allowance for equity funds used during                   (6,276)             (5,543)
    construction
Changes in working capital:
  Receivables                                             (52,150)            (16,899)
  Fuel inventory                                              542              (6,146)
  Accounts payable                                         (5,032)             15,750
  Taxes accrued                                            80,441             101,761
  Interest accrued                                         (1,514)             (4,001)
  Deferred fuel costs                                     (34,096)             66,838
  Other working capital accounts                            7,296              (3,079)
Provision for estimated losses and reserves                  (559)             (4,300)
Changes in other regulatory assets                        (11,425)            150,309
Other                                                      75,637             (11,495)
                                                        ---------            --------
Net cash flow provided by operating activities            345,116             318,369
                                                        ---------            --------


              INVESTING ACTIVITIES
Construction expenditures                                (214,716)           (194,349)
Allowance for equity funds used during                      6,276               5,543
  construction
Nuclear fuel purchases                                    (39,007)            (60,075)
Proceeds from sale/leaseback of nuclear fuel               39,007              60,075
Decommissioning trust contributions and realized
    change in trust assets                                 (5,753)            (16,255)
Changes in other temporary investments - net                    -              38,397
Other regulatory investments                              (14,739)                  -
                                                        ---------            --------
Net cash flow used in investing activities               (228,932)           (166,664)
                                                        ---------            --------


              FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt              361,819              94,405
Retirement of long-term debt                             (471,040)           (170,000)
Changes in short-term borrowings                                -                (667)
Dividends paid:
  Common stock                                            (64,000)            (94,800)
  Preferred stock                                          (5,832)             (5,832)
                                                        ---------            --------
Net cash flow used in financing activities               (179,053)           (176,894)
                                                        ---------            --------

Net decrease in cash and cash equivalents                 (62,869)            (25,189)

Cash and cash equivalents at beginning of period           95,513             103,466
                                                        ---------            --------

Cash and cash equivalents at end of period                $32,644             $78,277
                                                        =========            ========

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid/(received) during the period for:
  Interest - net of amount capitalized                    $67,240             $79,856
  Income taxes                                           ($18,078)             $9,356
 Noncash investing and financing activities:
  Change in unrealized appreciation/(depreciation) of
   decommissioning trust assets                            $9,000            ($37,298)
  Long-term debt refunded with proceeds from
   long-term debt issued in a prior period                      -            ($47,000)

See Notes to Respective Financial Statements.


                              ENTERGY ARKANSAS, INC.
                                  BALANCE SHEETS
                                      ASSETS
                     September 30, 2003 and December 31, 2002
                                   (Unaudited)

                                                     2003                    2002
                                                            (In Thousands)


             CURRENT ASSETS
Cash and cash equivalents:
  Cash                                              $32,644                $28,174
  Temporary cash investments - at cost,
    which approximates market                             -                 67,339
                                                 ----------             ----------
        Total cash and cash equivalents              32,644                 95,513
                                                 ----------             ----------
Accounts receivable:
  Customer                                           97,922                 67,674
  Allowance for doubtful accounts                    (7,826)                (8,031)
  Associated companies                               40,520                 32,352
  Other                                              28,089                 16,619
  Accrued unbilled revenues                          69,897                 67,838
                                                 ----------             ----------
    Total accounts receivable                       228,602                176,452
                                                 ----------             ----------
Deferred fuel costs                                   6,232                      -
Accumulated deferred income taxes                    14,237                  5,061
Fuel inventory - at average cost                     10,339                 10,881
Materials and supplies - at average cost             84,575                 78,533
Deferred nuclear refueling outage costs              16,587                 25,858
Prepayments and other                                 6,041                  8,335
                                                 ----------             ----------
TOTAL                                               399,257                400,633
                                                 ----------             ----------

     OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity                 11,215                 11,215
Decommissioning trust funds                         349,384                334,631
Non-utility property - at cost (less                  1,457                  1,460
  accumulated depreciation)
Other                                                 2,976                  2,976
                                                 ----------             ----------
TOTAL                                               365,032                350,282
                                                 ----------             ----------

             UTILITY PLANT
Electric                                          5,850,776              5,644,477
Property under capital lease                         27,628                 30,354
Construction work in progress                       238,499                132,792
Nuclear fuel under capital lease                     91,228                 88,101
Nuclear fuel                                          7,264                 10,543
                                                 ----------             ----------
TOTAL UTILITY PLANT                               6,215,395              5,906,267
Less - accumulated depreciation and               2,572,839              2,722,342
 amortization
                                                 ----------             ----------
UTILITY PLANT - NET                               3,642,556              3,183,925
                                                 ----------             ----------

    DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
  SFAS 109 regulatory asset - net                   117,348                111,748
  Unamortized loss on reacquired debt                39,109                 39,792
  Other regulatory assets                           333,176                130,689
Other                                                47,164                 39,899
                                                 ----------             ----------
TOTAL                                               536,797                322,128
                                                 ----------             ----------

TOTAL ASSETS                                     $4,943,642             $4,256,968
                                                 ==========             ==========

See Notes to Respective Financial Statements.



                              ENTERGY ARKANSAS, INC.
                                  BALANCE SHEETS
                       LIABILITIES AND SHAREHOLDERS' EQUITY
                     September 30, 2003 and December 31, 2002
                                   (Unaudited)

                                                      2003                  2002
                                                            (In Thousands)


          CURRENT LIABILITIES
Currently maturing long-term debt                       $ -               $255,000
Accounts payable:
  Associated companies                               78,587                 37,833
  Other                                              75,362                121,148
Customer deposits                                    37,393                 35,886
Taxes accrued                                        96,703                 16,262
Interest accrued                                     26,258                 27,772
Deferred fuel costs                                       -                 42,603
Obligations under capital leases                     59,069                 58,745
System Energy refund                                  3,465                  3,764
Other                                                18,299                 17,734
                                                 ----------             ----------
TOTAL                                               395,136                616,747
                                                 ----------             ----------

        NON-CURRENT LIABILITIES
Accumulated deferred income taxes and               867,822                821,829
  taxes accrued
Accumulated deferred investment tax                  74,518                 78,231
  credits
Obligations under capital leases                     59,788                 59,711
Other regulatory liabilities                         44,347                      -
Decommissioning                                     558,574                      -
Accumulated provisions                               30,904                 31,463
Long-term debt                                    1,276,060              1,125,000
Company-obligated mandatorily redeemable
  preferred securities of subsidiary trust holding
  solely junior subordinated deferrable              60,000                      -
  debentures
Other                                               156,184                117,847
                                                 ----------             ----------
TOTAL                                             3,128,197              2,234,081
                                                 ----------             ----------

Company-obligated mandatorily redeemable
  preferred securities of subsidiary trust holding
  solely junior subordinated deferrable                   -                 60,000
  debentures

          SHAREHOLDERS' EQUITY
Preferred stock without sinking fund                116,350                116,350
Common stock, $0.01 par value,
  authorized 325,000,000
  shares; issued and outstanding
  46,980,196 shares in 2003
  and 2002                                              470                    470
Paid-in capital                                     591,127                591,127
Retained earnings                                   712,362                638,193
                                                 ----------             ----------
TOTAL                                             1,420,309              1,346,140
                                                 ----------             ----------

Commitments and Contingencies

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY       $4,943,642             $4,256,968
                                                 ==========             ==========

See Notes to Respective Financial Statements.


                         ENTERGY ARKANSAS, INC.
                       SELECTED OPERATING RESULTS
    For the Three and Nine Months Ended September 30, 2003 and 2002
                              (Unaudited)


                                 Three Months Ended      Increase/
         Description              2003         2002     (Decrease)     %
                                   (In Millions)
Electric Operating Revenues:
  Residential                    $181.8      $193.3        ($11.5)    (6)
  Commercial                       89.6        93.7          (4.1)    (4)
  Industrial                       88.4        97.6          (9.2)    (9)
  Governmental                      4.4         4.1           0.3      7
                                 --------------------------------
    Total retail                  364.2       388.7         (24.5)    (6)
  Sales for resale
     Associated companies          52.7        33.0          19.7     60
     Non-associated companies      51.5        49.5           2.0      4
  Other                             1.5         3.7          (2.2)   (59)
                                 --------------------------------
    Total                        $469.9      $474.9         ($5.0)    (1)
                                 ================================
Billed Electric Energy
 Sales (GWh):
  Residential                     2,306       2,354           (48)    (2)
  Commercial                      1,609       1,617            (8)     -
  Industrial                      1,875       1,937           (62)    (3)
  Governmental                       77          70             7     10
                                 --------------------------------
    Total retail                  5,867       5,978          (111)    (2)
  Sales for resale
     Associated companies         1,529       1,436            93      6
     Non-associated companies     1,360       1,521          (161)   (11)
                                 --------------------------------
    Total                         8,756       8,935          (179)    (2)
                                 ================================


                                Nine Months Ended      Increase/
         Description             2003        2002     (Decrease)     %
                                   (In Millions)
Electric Operating Revenues:
  Residential                    $419.0      $442.8        ($23.8)    (5)
  Commercial                      222.8       237.0         (14.2)    (6)
  Industrial                      232.0       256.1         (24.1)    (9)
  Governmental                     11.4        11.9          (0.5)    (4)
                                 --------------------------------
    Total retail                  885.2       947.8         (62.6)    (7)
  Sales for resale
     Associated companies         168.6       126.1          42.5     34
     Non-associated companies     145.8       125.4          20.4     16
  Other                            28.0        21.3           6.7     31
                                 --------------------------------
    Total                      $1,227.6    $1,220.6          $7.0      1
                               ==================================

Billed Electric Energy
 Sales (GWh):
  Residential                     5,617       5,476           141      3
  Commercial                      4,065       3,967            98      2
  Industrial                      5,240       5,217            23      -
  Governmental                      204         194            10      5
                                 --------------------------------
    Total retail                 15,126      14,854           272      2
  Sales for resale
     Associated companies         5,283       5,322           (39)    (1)
     Non-associated companies     4,153       3,757           396     11
                                 --------------------------------
    Total                        24,562      23,933           629      3
                                 ================================

Entergy Gulf States experienced a significant decline in net income for the nine months ended September 30, 2003 primarily due to the $107.7 million accrual ($65.6 million net-of-tax) for the loss that would be associated with a final, non-appealable decision disallowing abeyed River Bend plant costs. See Note 2 to the domestic utility companies and System Energy financial statements for more details regarding the River Bend abeyed plant costs. Also, as discussed below in "Critical Accounting Estimates", net income for the nine months ended September 30, 2003 includes a one-time $21.3 million net-of-tax cumulative effect of accounting change due to the implementation of SFAS 143.

Operating income increased $20.5 million primarily due to:

• an increase of $12.6 million due to an increase in the price applied to unbilled sales in addition to more favorable volume on unbilled sales, including the effect of weather; and

• an increase of $9.9 million due to increased electricity usage of 151 GWh in the residential and commercial sectors.

The increase was partially offset by a decrease of $3.3 million due to the loss of two large industrial customers to cogeneration. The $3.3 million of lost net revenue represents approximately 1% of Entergy Gulf States' net revenue. Entergy Gulf States expects to lose one additional customer to cogeneration in 2005. Current sales to that customer account for approximately $11 million of Entergy Gulf States' net revenue annually. Entergy Gulf States does not currently expect additional significant losses to cogeneration because of the current economics of the electricity markets and Entergy Gulf States' marketing efforts in retaining industrial customers.

Operating income decreased $12.9 million primarily due to:

The decrease in operating income was partially offset by:

• an increase of $17.4 million due to increased electricity usage of 381 GWh in the residential and commercial sectors; and
• an increase of $10.7 million due to an increase in the price applied to unbilled sales.

The effective income tax rates for the third quarters of 2003 and 2002 were 31.4% and 38.0%, respectively. The difference in the third quarter 2003 effective income tax rate versus the federal statutory rate of 35.0% is primarily due to a downward revision in the estimate of federal income tax expense and flow-through book and tax timing differences. The difference in the third quarter 2002 effective income tax rate versus the federal statutory rate of 35.0% is primarily due to state income taxes.

The effective income tax rates for the nine months ended September 30, 2003 and 2002 were 21.8% and 38.4%, respectively. The difference in the effective income tax rate for the nine months ended September 30, 2003 versus the federal statutory rate of 35.0% is primarily due to the flow-through effect of book and tax timing differences, investment tax credit amortization, and a downward revision in the estimate of federal income tax expense. The difference in the effective income tax rate for the nine months ended September 30, 2002 versus the federal statutory rate of 35.0% is primarily due to state income taxes.

Miscellaneous income - net decreased $5.9 million primarily due to proceeds received in 2002 for the settlement of liability insurance coverage.

Interest expense on long-term debt increased $4.9 million primarily due to the issuance of $340 million of First Mortgage Bonds in November 2002, $600 million of First Mortgage Bonds in June 2003, and $440 million of First Mortgage Bonds in July 2003, partially offset by the retirement of $293 million of First Mortgage Bonds in March 2003 and $745 million of First Mortgage Bonds in the third quarter of 2003.

Miscellaneous income - net decreased $115.5 million primarily due to the $107.7 million accrual for the loss that would be associated with a final, non-appealable decision disallowing abeyed River Bend plant costs. See Note 2 to the domestic utility companies and System Energy financial statements for more details regarding the River Bend abeyed plant costs.

Interest expense on long-term debt increased $10.4 million primarily due to the issuance of $340 million of First Mortgage Bonds in November 2002, $600 million of First Mortgage Bonds in June 2003, and $440 million of First Mortgage Bonds in July 2003, partially offset by the retirement of $293 million of First Mortgage Bonds in March 2003 and $745 million of First Mortgage Bonds in the third quarter of 2003.

Operating revenues increased $128.3 million primarily due to:

• an increase of $123.8 million in fuel cost recovery revenues primarily due to higher fuel rates; and
• an increase of $12.6 million due to an increase in the price applied to unbilled sales in addition to more favorable volume on unbilled sales, including the effect of weather.

The increases were partially offset by a decrease in wholesale revenue of $5.3 million primarily due to decreased sales to adjoining utility systems.

Fuel and purchased power expenses increased primarily due to increases in the market prices of natural gas and purchased power.

Decommissioning expense increased $2 million primarily due to the implementation of SFAS 143. The increase in decommissioning expense is offset by increases in other regulatory credits and interest and dividend income and has no effect on net income.

Operating revenues increased $381.9 million primarily due to the following increases:

• $342.7 million in fuel cost recovery revenues primarily due to higher fuel rates;
• $27.7 million in wholesale revenue primarily due to increased volume to municipal and co-op customers and affiliated systems coupled with an increase in the average price of energy;
• $16.3 million in gas revenues primarily due to an increase in the market price of natural gas; and
• $10.7 million due to an increase in the price applied to unbilled sales.

The increases were partially offset by a decrease of $21.1 million due to base rate decreases effective June 2002 and January 2003. The January 2003 base rate decrease has a minimal impact on net income because it is offset by a decrease in depreciation expense associated with the license extension of River Bend as reflected in rates.

Fuel and purchased power expenses increased primarily due to increases in the market prices of natural gas and purchased power.

Decommissioning expense increased $6 million primarily due to the implementation of SFAS 143. The increase in decommissioning expense is offset by increases in other regulatory credits and interest and dividend income and has no effect on net income.

Cash flows for the nine months ended September 30, 2003 and 2002 were as follows:

Cash flow from operations decreased $205.9 million for the nine months ended September 30, 2003 compared to the same period in 2002 primarily due to money pool activity and higher working capital needs and increased vendor payments in 2003 relating to storm expense accruals in late-2002.

Money pool activity used $46.6 million of Entergy Gulf States' operating cash flow in 2003. See Note 4 to the domestic utility companies and System Energy financial statements in the Form 10-K for a description of the money pool.

Recent tax legislation and elections

Due to book/tax timing differences associated with recent income tax legislation and certain income tax elections, Entergy Gulf States could obtain cash flow benefits of $155 million over the years 2003 through 2005. These timing differences will then reverse over the remaining life of Entergy Gulf States' depreciable assets.

Net cash used in investing activities increased $101.7 million for the nine months ended September 30, compared to the same period of 2002 primarily due to the maturity of $44.6 million of other temporary investments that provided cash in 2002. The increase was also due to an increase in under-recovered fuel and purchased power expenses of $41.6 million in Texas that have been deferred and are expected to be collected over a period greater than twelve months. See Note 1 to the domestic utility companies and System Energy financial statements in the Form 10-K for further discussion of the accounting for fuel costs.

Financing Activities

Net cash used in financing activities decreased $149.7 million for the nine months ended September 30, 2003 compared to the same period of 2002 primarily due to the net retirement of $148 million of long-term debt in 2002 compared to $15.4 million in 2003. Also contributing to the decrease in cash used was a decrease in dividends paid of $18.5 million in 2003 compared to 2002.

Entergy Gulf States has implemented a planned financing program to address its 2004 long-term debt maturities and to restructure its debt portfolio, which resulted in extended maturities, lowered rates, and sufficient flexibility in its portfolio so that Entergy Gulf States can economically manage Texas utility restructuring to the extent it affects Entergy Gulf States' debt portfolio.

The following table lists First Mortgage Bonds issued by Entergy Gulf States in 2003:

The following table lists First Mortgage Bonds retired by Entergy Gulf States in 2003:

Entergy Gulf States plans to retire, at maturity, $292 million of 8.25% Series First Mortgage Bonds due April 1, 2004 using cash on hand and internally generated funds.

See "Management's Financial Discussion and Analysis - Liquidity and Capital Resources" in the Form 10-K for a discussion of Entergy Gulf States' uses and sources of capital. The following is an update to the Form 10-K.

Following are the amounts of Entergy Gulf States' planned construction and other capital investments for 2003 through 2005, which reflect changes in management's estimate from the planned investments presented in the Form 10-K due mainly to the effect of actual spending in 2003 (the figures for 2003 include the effect of actual spending thus far in 2003):

See the Form 10-K for further discussion of Entergy Gulf States' capital spending plans for 2003 through 2005.

See "Management's Financial Discussion and Analysis - Significant Factors and Known Trends" in the Form 10-K for a discussion of transition to retail competition, state and local regulatory risks, System Agreement proceedings, industrial, commercial, and wholesale customers, market and credit risks, nuclear matters, environmental risks, and litigation risks. Following are updates to the information provided in the Form 10-K.

See Note 2 to the domestic utility companies and System Energy's financial statements in this Form 10-Q for a discussion of Entergy Gulf States' ninth and last required post-merger analysis filed with the LPSC in May 2002. In April 2003, the LPSC staff filed testimony in which it recommended that the LPSC require a rate refund of $30.3 million and a prospective rate reduction of $75.9 million, before taking into account the $11.5 million rate reduction that Entergy Gulf States implemented effective June 2002. In July 2003, Entergy Gulf States filed testimony rebutting the LPSC staff's testimony and supporting the filing. During discovery, the LPSC staff requested that Entergy Gulf States provide updated cost of service data to reflect changes in costs, revenues, and rate base through December 31, 2002. In September 2003, Entergy Gulf States supplied the updated data. The LPSC staff has not yet indicated whether the updated data will result in changes to its recommendations. A new pro cedural schedule has been established that requires the LPSC staff to file testimony in December 2003. This testimony will also address new issues presented by the updated 2002 cost of service data. Hearings are scheduled for May 2004. Entergy Gulf States cannot predict the ultimate outcome of this proceeding.

In September 2003, Entergy Gulf States filed an application with the PUCT to implement an $87.3 million interim fuel surcharge, including interest, to collect under-recovered fuel and purchased power expenses incurred from September 2002 through August 2003. Hearings were held in October 2003 and the PUCT is expected to issue an order in December 2003. Entergy Gulf States has requested that the surcharge be collected over a twelve-month period beginning January 2004. The outcome of this proceeding cannot be predicted at this time.

See "Management's Financial Discussion and Analysis - Significant Factors and Known Trends" in the Form 10-K for a discussion of the status of retail open access in Entergy Gulf States' Texas service territory, and the proposal that Entergy Gulf States filed for an interim solution (retail open access without a FERC-approved RTO). The PUCT considered the proposal at a March 2003 hearing, and issued an order in April 2003. The order set forth a sequence of proceedings and activities designed to initiate an interim solution in the first half of 2004. These proceedings and activities include ruling on market protocols; initiating a proceeding to certify an independent organization to administer the market protocols and ensure nondiscriminatory access to transmission and distribution systems; resuming business separation proceedings; re-invigorating the pilot project; and initiating a market-readiness proceeding. In June 2003, the PUCT voted 2 to 1 to issue an order on rehearing in the interim solution proceeding. The PUCT issued the written order on rehearing in late-July 2003 in which it identified December 2004 as the target date for the beginning of the interim solution. Also in July 2003, the PUCT directed the parties to continue negotiations on unresolved issues in the market protocols docket. Several of the parties to that proceeding filed a settlement agreement with respect to the market protocols that the PUCT approved, after hearings, in an order issued in September 2003. Consistent with the order, Entergy Services has made a filing at the FERC requesting approval on an expedited basis of the market protocols subject to FERC jurisdiction.

In September 2003, the PUCT issued a written order that approved the Price to Beat (PTB) fuel factor for Entergy Gulf States, which is to be implemented upon the commencement of retail open access in its Texas service territory. This PTB fuel factor is subject to revision based on PUCT rules. The PUCT declined consideration of a request for rehearing sought by certain cities in Texas served by Entergy Gulf States and the Office of Public Utility Counsel. The period for appeal of the order remains open.

As discussed in the Form 10-K, Entergy Gulf States implemented SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. The net effect of implementing this standard for the portion of River Bend subject to cost-based ratemaking was recorded as a regulatory asset, with no resulting impact on Entergy Gulf States' net income. Assets and liabilities increased in 2003 as a result of increasing the asset retirement obligation by $129 million to its fair value as determined under SFAS 143, reducing accumulated depreciation by $63 million, and recording the related regulatory asset of $32 million. The net effect of implementing SFAS 143 for the portion of River Bend not subject to cost-based ratemaking resulted in an earnings decrease of $21 million net-of-tax as a result of a one-time cumulative effect of accounting change. Applying SFAS 143 is not expected to have a material effect on Entergy Gulf States' earnings on an ongoing basis after its implementation. < /P>

                           ENTERGY GULF STATES, INC.
                              INCOME STATEMENTS
        For the Three and Nine Months Ended September 30, 2003 and 2002
                                  (Unaudited)


                                         Three Months Ended     Nine Months Ended
                                           2003      2002        2003        2002
                                           (In Thousands)        (In Thousands)

          OPERATING REVENUES
Domestic electric                        $769,326  $642,940   $2,015,330  $1,649,729
Natural gas                                 7,856     5,909       46,841      30,587
                                         --------  --------   ----------  ----------
TOTAL                                     777,182   648,849    2,062,171   1,680,316
                                         --------  --------   ----------  ----------

          OPERATING EXPENSES
Operation and Maintenance:
   Fuel, fuel-related expenses, and
     gas purchased for resale             193,692   233,976      516,656     518,875
   Purchased power                        251,372    96,037      661,697     270,215
   Nuclear refueling outage expenses        3,193     3,056       10,852       9,135
   Other operation and maintenance        101,435   103,454      304,008     308,405
Decommissioning                             3,567     1,579       10,701       4,731
Taxes other than income taxes              31,612    32,823       90,414      94,134
Depreciation and amortization              50,039    51,154      147,941     151,847
Other regulatory charges (credits) -       (3,791)    1,227       (1,004)    (10,796)
  net
                                         --------  --------   ----------  ----------
TOTAL                                     631,119   523,306    1,741,265   1,346,546
                                         --------  --------   ----------  ----------

OPERATING INCOME                          146,063   125,543      320,906     333,770
                                         --------  --------   ----------  ----------

       OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during      4,084     2,988       10,258       7,971
 construction
Interest and dividend income                6,215     2,756       15,182       7,687
Miscellaneous - net                           990     6,922     (108,380)      7,147
                                         --------  --------   ----------  ----------
TOTAL                                      11,289    12,666      (82,940)     22,805
                                         --------  --------   ----------  ----------

      INTEREST AND OTHER CHARGES
Interest on long-term debt                 37,574    32,694      107,631      97,191
Other interest - net                        1,477     2,260        4,785       5,002
Distributions on preferred securities       1,859     1,859        5,578       5,578
 of subsidiary
Allowance for borrowed funds used          (3,410)   (2,540)      (8,651)     (7,153)
 during construction
                                         --------  --------   ----------  ----------
TOTAL                                      37,500    34,273      109,343     100,618
                                         --------  --------   ----------  ----------

INCOME BEFORE INCOME TAXES AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGE    119,852   103,936      128,623     255,957

Income taxes                               37,569    39,447       33,339      98,194
                                         --------  --------   ----------  ----------

INCOME BEFORE CUMULATIVE EFFECT
OF ACCOUNTING CHANGE                       82,283    64,489       95,284     157,763

CUMULATIVE EFFECT OF ACCOUNTING
CHANGE (net of income taxes of $12,713)         -         -      (21,333)          -
                                         --------  --------   ----------  ----------

NET INCOME                                 82,283    64,489       73,951     157,763

Preferred dividend requirements and         1,170     1,218        3,551       3,678
other
                                         --------  --------   ----------  ----------

EARNINGS APPLICABLE TO
COMMON STOCK                              $81,113   $63,271      $70,400    $154,085
                                         ========  ========   ==========  ==========
See Notes to Respective Financial Statements.



                                   ENTEGY GULF STATES, INC.
                                   STATEMENTS OF CASH FLOWS
                   For the Nine Months Ended September 30, 2003 and 2002
                                         (Unaudited)

                                                             2003          2002
                                                              (In Thousands)

               OPERATING ACTIVITIES
Net income                                                    $73,951    $157,763
Noncash items included in net income:
  Reserve for regulatory adjustments                           (9,806)      7,566
  Other regulatory credits - net                               (1,004)    (10,796)
  Depreciation, amortization, and decommissioning             158,642     156,578
  Deferred income taxes and investment tax credits            (18,240)    (38,938)
  Allowance for equity funds used during                      (10,258)     (7,971)
    construction
  Cumulative effect of accounting change                       21,333           -
Changes in working capital:
  Receivables                                                (141,817)    (37,577)
  Fuel inventory                                               (5,058)      1,687
  Accounts payable                                            (88,109)    (12,319)
  Taxes accrued                                                32,879     131,065
  Interest accrued                                              5,020       1,675
  Deferred fuel costs                                          30,253      43,035
  Other working capital accounts                               12,353       3,967
Provision for estimated losses and reserves                   108,196        (822)
Changes in other regulatory assets                             27,253      10,029
Other                                                          24,224      20,796
                                                             --------    --------
Net cash flow provided by operating activities                219,812     425,738
                                                             --------    --------

               INVESTING ACTIVITIES
Construction expenditures                                    (234,689)   (228,050)
Allowance for equity funds used during construction            10,258       7,971
Nuclear fuel purchases                                        (39,959)    (21,820)
Proceeds from sale/leaseback of nuclear fuel                   38,029      21,923
Decommissioning trust contributions and realized
    change in trust assets                                     (9,862)     (9,213)
Changes in other temporary investments - net                   (8,403)     44,643
Other regulatory investments                                  (86,854)    (45,262)
                                                             --------    --------
Net cash flow used in investing activities                   (331,480)   (229,808)
                                                             --------    --------

               FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt                1,032,778           -
Retirement of long-term debt                               (1,048,129)   (148,000)
Redemption of preferred stock                                  (3,450)     (1,858)
Dividends paid:
  Common stock                                                (56,700)    (75,200)
  Preferred stock                                              (3,551)     (3,678)
                                                             --------    --------
Net cash flow used in financing activities                    (79,052)   (228,736)
                                                             --------    --------

Net decrease in cash and cash equivalents                    (190,720)    (32,806)

Cash and cash equivalents at beginning of period              318,404     123,728
                                                             --------    --------

Cash and cash equivalents at end of period                   $127,684     $90,922
                                                             ========    ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid/(received) during the period for:
  Interest - net of amount capitalized                       $108,423    $102,066
  Income taxes                                                ($5,180)    $18,900
 Noncash investing and financing activities:
  Change in unrealized appreciation/(depreciation) of
   decommissioning trust assets                                $6,054    ($17,780)

See Notes to Respective Financial Statements.


                             ENTERGY GULF STATES, INC.
                                  BALANCE SHEETS
                                       ASSETS
                     September 30, 2003 and December 31, 2002
                                    (Unaudited)

                                                          2003         2002
                                                           (In Thousands)

                  CURRENT ASSETS
Cash and cash equivalents:
  Cash                                                     $35,116     $25,591
  Temporary cash investments - at cost,
    which approximates market                               92,568     292,813
                                                          --------    --------
        Total cash and cash equivalents                    127,684     318,404
                                                          --------    --------
Other temporary investments                                  8,403           -
Accounts receivable:
  Customer                                                 137,898      81,879
  Allowance for doubtful accounts                           (4,878)     (5,893)
  Associated companies                                      81,853      21,356
  Other                                                     28,019      40,156
  Accrued unbilled revenues                                131,800      95,377
                                                          --------    --------
    Total accounts receivable                              374,692     232,875
                                                          --------    --------
Deferred fuel costs                                        157,165     100,564
Accumulated deferred income taxes                                -       1,681
Fuel inventory - at average cost                            54,452      49,394
Materials and supplies - at average cost                   101,330      99,190
Prepayments and other                                       31,595      47,206
                                                          --------    --------
TOTAL                                                      855,321     849,314
                                                          --------    --------

          OTHER PROPERTY AND INVESTMENTS
Decommissioning trust funds                                256,651     240,735
Non-utility property - at cost (less accumulated           137,045     192,975
  depreciation)
Other                                                       19,472      18,108
                                                          --------    --------
TOTAL                                                      413,168     451,818
                                                          --------    --------

                   UTILITY PLANT
Electric                                                 8,140,872   7,895,009
Property under capital lease                                12,429      19,795
Natural gas                                                 64,430      60,810
Construction work in progress                              321,764     306,209
Nuclear fuel under capital lease                            64,664      41,447
                                                          --------    --------
TOTAL UTILITY PLANT                                      8,604,159   8,323,270
Less - accumulated depreciation and amortization         3,933,437   3,885,559
                                                          --------    --------
UTILITY PLANT - NET                                      4,670,722   4,437,711
                                                          --------    --------

         DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
  SFAS 109 regulatory asset - net                          449,052     452,887
  Unamortized loss on reacquired debt                       48,094      31,186
  Other regulatory assets                                  273,391     226,555
Long-term receivables                                       20,373      23,192
Other                                                       45,649      35,194
                                                          --------    --------
TOTAL                                                      836,559     769,014
                                                          --------    --------

TOTAL ASSETS                                            $6,775,770  $6,507,857
                                                        ==========  ==========
See Notes to Respective Financial Statements.


                               ENTERGY GULF STATES, INC.
                                    BALANCE SHEETS
                         LIABILITIES AND SHAREHOLDERS' EQUITY
                       September 30, 2003 and December 31, 2002
                                     (Unaudited)

                                                          2003         2002
                                                           (In Thousands)

                CURRENT LIABILITIES
Currently maturing long-term debt                         $292,000    $293,000
Accounts payable:
  Associated companies                                      74,678      51,383
  Other                                                     94,392     205,796
Customer deposits                                           51,283      48,061
Taxes accrued                                               68,793      35,914
Accumulated deferred income taxes                           16,715           -
Nuclear refueling outage costs                               4,987      14,244
Interest accrued                                            43,890      38,870
Obligations under capital leases                            36,920      36,157
Other                                                       20,358      15,441
                                                        ----------  ----------
TOTAL                                                      704,016     738,866
                                                        ----------  ----------

              NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued      1,319,925   1,310,028
Accumulated deferred investment tax credits                145,754     156,401
Obligations under capital leases                            40,174      25,085
Other regulatory liabilities                                 9,253       5,557
Decommissioning                                            293,650     148,728
Transition to competition                                   79,098      79,098
Regulatory reserves                                         34,932      44,738
Accumulated provisions                                      66,974      65,289
Long-term debt                                           1,964,144   1,959,288
Preferred stock with sinking fund                           20,877           -
Company-obligated mandatorily redeemable
  preferred securities of subsidiary trust holding
  solely junior subordinated deferrable debentures          85,000           -
Other                                                      226,581      93,396
                                                        ----------  ----------
TOTAL                                                    4,286,362   3,887,608
                                                        ----------  ----------

Preferred stock with sinking fund                                -      24,327
Company-obligated mandatorily redeemable
  preferred securities of subsidiary trust holding
  solely junior subordinated deferrable debentures               -      85,000

               SHAREHOLDERS' EQUITY
Preferred stock without sinking fund                        47,327      47,327
Common stock, no par value, authorized 200,000,000
  shares; issued and outstanding 100 shares in 2003        114,055     114,055
  and 2002
Paid-in capital                                          1,157,459   1,157,459
Retained earnings                                          463,629     449,929
Accumulated other comprehensive income                       2,922       3,286
                                                        ----------  ----------
TOTAL                                                    1,785,392   1,772,056
                                                        ----------  ----------

Commitments and Contingencies

         TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY     $6,775,770  $6,507,857
                                                        ==========  ==========
See Notes to Respective Financial Statements.



                          ENTERGY GULF STATES, INC.
           STATEMENTS OF RETAINED EARNINGS AND COMPREHENSIVE INCOME
        For the Three and Nine Months Ended September 30, 2003 and 2002
                                  (Unaudited)

                                                              Three Months Ended
                                                        2003                  2002
                                                              (In Thousands)
             RETAINED EARNINGS
Retained Earnings - Beginning of period         $422,116              $431,295
    Add  - Earnings applicable to common          81,113   $81,113      63,271     $63,271
     stock
    Deduct:
        Dividends declared on common stock        39,600                43,800
        Capital stock and other expenses               -                   (58)
                                                --------              --------
              Total                               39,600                43,742
                                                --------              --------
Retained Earnings - End of period               $463,629              $450,824
                                                ========              ========
      ACCUMULATED OTHER COMPREHENSIVE
          INCOME (Net of Taxes):
Balance at beginning of period:
  Accumulated derivative instrument fair          $2,753                $2,078
   value changes

Net derivative instrument fair value changes
  arising during the period                          169       169       1,954       1,954
                                                 -------   -------    --------     -------

Balance at end of period:
  Accumulated derivative instrument fair          $2,922                $4,032
    value changes	                                =======   -------    ========     -------
Comprehensive Income                                       $81,282                 $65,225
                                                           =======                 =======

                                                             Nine Months Ended
                                                         2003                  2002
                                                              (In Thousands)
             RETAINED EARNINGS
Retained Earnings - Beginning of period         $449,929              $371,939
    Add  - Earnings applicable to common          70,400   $70,400     154,085    $154,085
     stock
    Deduct:
        Dividends declared on common stock        56,700                75,200
                                                --------              --------
              Total                               56,700                75,200
                                                --------              --------
Retained Earnings - End of period               $463,629              $450,824
                                                ========              ========

      ACCUMULATED OTHER COMPREHENSIVE
          INCOME (Net of Taxes):
Balance at beginning of period:
  Accumulated derivative instrument fair          $3,286                   $ -
    value changes

Net derivative instrument fair value changes
  arising during the period                        (364)     (364)       4,032       4,032
                                                 -------   -------    --------     -------


Balance at end of period:
  Accumulated derivative instrument fair          $2,922                $4,032
    value changes                                =======   -------    ========     -------
Comprehensive Income                                       $70,036                $158,117
                                                           =======                 =======


See Notes to Respective Financial Statements.


			   ENTERGY GULF STATES, INC.
			  SELECTED OPERATING RESULTS
	For the Three and Nine Months Ended September 30, 2003 and 2002
			          (Unaudited)


                                Three Months Ended    Increase/
         Description             2003      2002      (Decrease)       %
                                   (In Millions)
Electric Operating Revenues:
  Residential                   $ 284.4    $ 234.4      $ 50.0         21
  Commercial                      182.6      146.5        36.1         25
  Industrial                      228.2      193.6        34.6         18
  Governmental                      9.9        9.1         0.8          9
                                ------------------------------
    Total retail                  705.1      583.6       121.5         21
  Sales for resale
     Associated companies          18.8       11.1         7.7         69
     Non-associated companies      35.0       48.0       (13.0)       (27)
  Other                            10.4        0.2        10.2      5,100
                                ------------------------------
    Total                       $ 769.3    $ 642.9      $126.4         20
                                ==============================
Billed Electric Energy
 Sales (GWh):
  Residential                     3,173      3,095          78          3
  Commercial                      2,333      2,260          73          3
  Industrial                      3,889      4,157        (268)        (6)
  Governmental                      115        127         (12)        (9)
                                ------------------------------
    Total retail                  9,510      9,639        (129)        (1)
  Sales for resale
     Associated companies           682        357         325         91
     Non-associated companies       564      1,214        (650)       (54)
                                ------------------------------
    Total                        10,756     11,210        (454)        (4)
                                ==============================


                                 Nine Months Ended     Increase/
         Description             2003        2002      (Decrease)     %
                                    (In Millions)
Electric Operating Revenues:
  Residential                    $ 645.8     $ 543.3      $ 102.5       19
  Commercial                       461.5       378.6         82.9       22
  Industrial                       640.0       519.7        120.3       23
  Governmental                      29.7        25.1          4.6       18
                                ---------------------------------
    Total retail                 1,777.0     1,466.7        310.3       21
  Sales for resale
     Associated companies           33.5        16.6         16.9      102
     Non-associated companies      122.3       111.5         10.8       10
  Other                             82.5        54.9         27.6       50
                                ---------------------------------
    Total                       $2,015.3   $ 1,649.7      $ 365.6       22
                                =================================
Billed Electric Energy
 Sales (GWh):
  Residential                      7,599       7,387          212        3
  Commercial                       6,147       5,978          169        3
  Industrial                      11,488      11,877         (389)      (3)
  Governmental                       363         355            8        2
                                ---------------------------------
    Total retail                  25,597      25,597            -        -
  Sales for resale
     Associated companies            943         486          457       94
     Non-associated companies      2,639       3,426         (787)     (23)
                                ---------------------------------
    Total                         29,179      29,509         (330)      (1)
                                =================================

Operating income decreased slightly primarily due to an increase in other operation and maintenance expenses offset by an increase in net revenue. Net revenue increased primarily due to an increase in the volume of unbilled sales, offset by decreased electricity usage of 527 GWh in the industrial sector, including the loss of a large industrial customer to co-generation.

Other operation and maintenance expenses increased primarily due to increased benefit costs.

Operating income decreased $30.3 million primarily due to:

The decrease in operating income was partially offset by an increase in net revenue of $17.1 million due to an increase in the price applied to unbilled sales.

Lower interest charges increased pre-tax earnings by $10.7 million primarily due to the redemption of $150 million of First Mortgage Bonds in June 2003 and the redemption of $15.3 million of First Mortgage Bonds in November 2002.

Lower interest charges increased pre-tax earnings by $16.9 million primarily due to decreased interest on long-term debt due to the redemption of $150 million of First Mortgage Bonds in June 2003 and the redemption of $187 million of First Mortgage Bonds from April through December of 2002, partially offset by the issuance of $150 million of First Mortgage Bonds in March 2002.

The effective income tax rates for the third quarters of 2003 and 2002 were 39.4% and 40.5%, respectively. The effective income tax rates for the nine months ended September 30, 2003 and 2002 were 39.1% and 39.0%, respectively. The differences in the effective income tax rates for the third quarters of 2003 and 2002 and the nine months ended September 30, 2003 and 2002 versus the federal statutory rate of 35.0% are primarily due to state income taxes and depreciation book and tax differences.

Operating revenues increased $118.4 million primarily due to:

• an increase of $73.7 million in fuel cost recovery revenues due to higher fuel rates;
• an increase of $45.2 million in wholesale revenue primarily due to increased sales to affiliated systems; and
• an increase of $9.1 million due to an increase in the volume of unbilled sales, including the effect of weather.

The increase was offset by decreased electricity usage in the service territory as discussed above.

Fuel and purchased power expenses increased primarily due to an increase in deferred fuel costs and an increase in the market prices of natural gas and purchased power.

Decommissioning expense increased $2.5 million primarily due to the implementation of SFAS 143, "Accounting for Asset Retirement Obligations," adopted in January 2003. See "Critical Accounting Estimates" for more details on SFAS 143. The increase in decommissioning expense is offset by regulatory credits and interest and dividend income and has no effect on net income.

Other regulatory credits increased $10.0 million primarily due to:

• a decrease of $4.2 million due to deferred capacity charges recorded in the third quarter as allowed by the LPSC related to resource planning;
• the amortization of $2.6 million of deferred capacity charges for the summer of 2001, which began in August 2002; and
• a decrease of $2.6 million due to the change in accounting for asset retirement obligations in compliance with SFAS 143, adopted in January 2003. This decrease has no effect on net income.

Operating revenues increased $297.0 million primarily due to:

• an increase of $226.8 million in fuel cost recovery revenues due to higher fuel rates; and
• an increase of $95.5 million in wholesale revenue primarily due to increased sales to affiliated systems.

The increase was partially offset by a decrease in the volume of unbilled sales and decreased electricity usage in the service territory as discussed above.

Fuel and purchased power expenses increased primarily due to increases in the market prices of natural gas and purchased power.

Decommissioning expense increased $7.6 million primarily due to the implementation of SFAS 143, "Accounting for Asset Retirement Obligations," adopted in January 2003. See "Critical Accounting Estimates" for more details on SFAS 143. The increase in decommissioning expense is offset by other regulatory credits and interest and dividend income and has no effect on net income.

• a decrease of $6.2 million due to the change in accounting for asset retirement obligations in compliance with SFAS 143, adopted in January 2003. This decrease has no effect on net income; and
• a decrease of $4.3 million due to deferred capacity charges recorded in the third quarter as allowed by the LPSC related to resource planning.

Cash flows for the nine months ended September 30, 2003 and 2002 were as follows: