ENTERGY NEW ORLEANS, LLC - Quarter Report: 2003 June (Form 10-Q)

• The U.S. Utility provided $509 million in operating cash flow in 2003 compared to providing $722 million in 2002. The decrease primarily resulted from higher payments for fuel during the period, which 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 $73 million in operating cash flow in 2003 compared to providing $165 million in 2002 primarily due to increased nuclear refueling outage costs in 2003.
• The non-nuclear wholesale asset business used $59 million in operating cash flow in 2003 compared to using $22 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.

The decrease was partially offset by an increase of $15.0 million in operating cash flow provided by Entergy-Koch, L.P. This increase was due to the receipt of a $75 million dividend from Entergy-Koch, partially offset by an increase in tax payments of $59 million related to Entergy's investment in Entergy-Koch due to increased income from the investment.

Tax 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 expects to 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 $642 million for the six months ended June 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 $193 million in March 2003 to provide this cash collateral.
• Temporary investments of $150 million matured in 2002, which provided cash flow in 2002.
• Entergy Gulf States had $70 million and Entergy Mississippi had $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.
• The Non-Utility Nuclear segment purchased $33 million more nuclear fuel in 2003 than in 2002 to provide for its scheduled refueling outages.

Financing activities provided $351 million in cash for the six months ended June 30, 2003 compared to using $325 million in 2002 primarily due to:

• Net long-term debt issuances by the U.S. Utility segment were $333 million in 2003 compared to net retirements of $403 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 $233 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.

The items providing cash in 2003 were partially offset by a decrease in the net borrowings under Entergy Corporation's credit facilities of $140 million in 2003 compared to an increase of $355 million in 2002.

Following is a summary of the activity through June 30, 2003 involving Entergy's 2003 and 2004 long-term debt maturities.

Thus far in 2003, including issuances subsequent to June 30, the U.S. Utility has issued $1.8 billion of debt with maturities ranging from 2007 to 2033. Approximately $555 million of the proceeds of the debt issued in 2003 were used for retirements in 2003, and Entergy plans to use the remainder to meet remaining 2003 and 2004 maturities as they occur, with the exception of a $150 million Entergy Louisiana maturity that is expected to be met with internally-generated funds. The Energy Commodity Services debt maturity was paid in January 2003 using money drawn on Entergy Corporation's 364-day credit facility. See Note 4 to the consolidated financial statements for further details of long-term debt issuances and retirements in 2003.

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. The following are updates to the Form 10-K.

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.

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 adjustment 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 it 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 June 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.

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 February 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 six months ended June 30, 2003 (in millions):

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 mid-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 proceeding. The PUCT issued the written order on rehearing in late-July 2003 in which it identified December 2004 as the target date for 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 on the market protocols that will be the subject of a PUCT hearing scheduled for August 20, 2003.

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 now expected to go before a conference committee in the fall of 2003 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 stated 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.

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 February 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 will offer a voluntary severance program to employees targeting a reduction of approximately 1,000 employees. The voluntary severance program will likely result in restructuring charges for Entergy in the second half of 2003, although the amount of these charges cannot be estimated at this time.

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. The following is an update to 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 a 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 a 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 SFAS 143 implementation to have a minimal effect on ongoing earnings for the U.S. Utility business.

                    ENTERGY CORPORATION AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF INCOME
         For the Three and Six Months Ended June 30, 2003 and 2002
                                (Unaudited)

                                                               Three Months Ended             Six Months Ended
                                                               2003          2002            2003          2002
                                                                      (In Thousands, Except Share Data)
OPERATING REVENUES
Domestic electric                                           $1,925,941   $1,686,758      $3,527,679    $3,087,767
Natural gas                                                     33,698       24,982         113,936        71,360
Competitive businesses                                         394,270      384,841         750,017       798,288
                                                            ----------   ----------      ----------    ----------
TOTAL                                                        2,353,909    2,096,581       4,391,632     3,957,415
                                                            ----------   ----------      ----------    ----------

                  OPERATING EXPENSES
Operating and Maintenance:
   Fuel, fuel-related expenses, and
     gas purchased for resale                                  496,014      471,413         884,055       940,274
   Purchased power                                             440,473      233,518         809,172       403,004
   Nuclear refueling outage expenses                            40,251       24,687          79,144        49,874
   Provision for turbine commitments, asset impairments
     and restructuring charges                                       -       18,169          (7,743)      419,542
   Other operation and maintenance                             571,010      727,017       1,095,909     1,251,369
Decommissioning                                                 34,361       18,193          71,859        36,381
Taxes other than income taxes                                  100,505       82,194         198,242       184,565
Depreciation and amortization                                  205,446      205,876         416,492       410,999
Other regulatory charges (credits) - net                         4,273     (170,645)         19,526      (169,082)
                                                            ----------   ----------      ----------    ----------
TOTAL                                                        1,892,333    1,610,422       3,566,656     3,526,926
                                                            ----------   ----------      ----------    ----------

OPERATING INCOME                                               461,576      486,159         824,976       430,489
                                                            ----------   ----------      ----------    ----------

                     OTHER INCOME
Allowance for equity funds used during construction              9,740        8,323          17,027        15,004
Gain on sale of assets                                             761        1,009           1,062         1,674
Interest and dividend income                                    29,927       27,710          59,751        51,237
Equity in earnings of unconsolidated equity affiliates          70,292       16,007         198,353        83,250
Miscellaneous - net                                           (104,212)       1,624         (92,896)       (1,628)
                                                            ----------   ----------      ----------    ----------
TOTAL                                                            6,508       54,673         183,297       149,537
                                                            ----------   ----------      ----------    ----------

              INTEREST AND OTHER CHARGES
Interest on long-term debt                                     117,227      121,393         234,962       244,919
Other interest - net                                            16,247       24,902          29,291        40,381
Distributions on preferred securities of subsidiaries            4,709        4,709           9,419         9,419
Allowance for borrowed funds used during construction           (7,449)      (6,291)        (13,168)      (11,930)
                                                            ----------   ----------      ----------    ----------
TOTAL                                                          130,734      144,713         260,504       282,789
                                                            ----------   ----------      ----------    ----------

INCOME BEFORE INCOME TAXES AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGES                        337,350      396,119         747,769       297,237

Income taxes                                                   125,833      148,534         278,251       122,636
                                                            ----------   ----------      ----------    ----------

INCOME BEFORE CUMULATIVE EFFECT
OF ACCOUNTING CHANGES                                          211,517      247,585         469,518       174,601

CUMULATIVE EFFECT OF ACCOUNTING
CHANGES (net of income taxes of $93,754)                             -            -         142,922             -
                                                            ----------   ----------      ----------    ----------

CONSOLIDATED NET INCOME                                        211,517      247,585         612,440       174,601

Preferred dividend requirements and other                        5,876        5,932          11,792        11,872
                                                            ----------   ----------      ----------    ----------

EARNINGS APPLICABLE TO
COMMON STOCK                                                  $205,641     $241,653        $600,648      $162,729
                                                            ==========   ==========      ==========    ==========
Earnings per average common share before cumulative
effect of accounting changes:
    Basic                                                        $0.91        $1.08           $2.03         $0.73
    Diluted                                                      $0.89        $1.06           $1.99         $0.72
Earnings per average common share:
    Basic                                                        $0.91        $1.08           $2.67         $0.73
    Diluted                                                      $0.89        $1.06           $2.61         $0.72
Dividends declared per common share                              $0.35        $0.33           $0.70         $0.66

Average number of common shares outstanding:
    Basic                                                  226,609,159  224,330,654     225,149,356   223,143,647
    Diluted                                                231,579,242  228,847,752     229,916,344   227,588,889

See Notes to Consolidated Financial Statements.




                    ENTERGY CORPORATION AND SUBSIDIARIES
                    CONSOLIDATED STATEMENTS OF CASH FLOWS
               For the Six Months Ended June 30, 2003 and 2002
                                 (Unaudited)

                                                                                       2003          2002
                                                                                          (In Thousands)

                              OPERATING ACTIVITIES
Consolidated net income                                                                $612,440      $174,601
Noncash items included in net income:
  Reserve for regulatory adjustments                                                    (12,080)       12,684
  Other regulatory charges (credits) - net                                               19,526      (169,082)
  Depreciation, amortization, and decommissioning                                       488,351       447,380
  Deferred income taxes and investment tax credits                                      185,872      (171,328)
  Allowance for equity funds used during construction                                   (17,027)      (15,004)
  Cumulative effect of accounting changes                                              (142,922)            -
  Gain on sale of assets - net                                                           (1,062)       (1,674)
  Equity in undistributed earnings of unconsolidated equity affiliates                 (123,352)      (82,962)
  Provision for turbine commitments, asset impairments, and restructuring charges        (7,743)      419,542
Changes in working capital:
  Receivables                                                                          (268,990)     (139,808)
  Fuel inventory                                                                        (25,078)       (7,332)
  Accounts payable                                                                     (153,778)       (9,974)
  Taxes accrued                                                                         (12,266)      255,629
  Interest accrued                                                                      (28,685)      (31,416)
  Deferred fuel                                                                         (96,306)          549
  Other working capital accounts                                                        (81,639)      (43,475)
Provision for estimated losses and reserves                                             110,868        (8,576)
Changes in other regulatory assets                                                       (2,218)      186,824
Other                                                                                    81,352       (13,595)
                                                                                    -----------     ---------
Net cash flow provided by operating activities                                          525,263       802,983
                                                                                    -----------     ---------

                              INVESTING ACTIVITIES
Construction/capital expenditures                                                      (678,162)     (736,670)
Allowance for equity funds used during construction                                      17,027        15,004
Nuclear fuel purchases                                                                 (126,446)     (161,090)
Proceeds from sale/leaseback of nuclear fuel                                             39,089       132,472
Proceeds from sale of businesses                                                         25,414       147,115
Investment in other non-regulated/non-utility properties                                (47,542)      (19,057)
Decrease (increase) in other investments                                               (167,054)       39,460
Proceeds from other temporary investments                                                     -       150,000
Decommissioning trust contributions and realized change in trust assets                 (49,597)      (27,894)
Other regulatory investments                                                           (142,219)      (29,755)
Other                                                                                    (5,603)       (2,690)
                                                                                    -----------     ---------
Net cash flow used in investing activities                                           (1,135,093)     (493,105)
                                                                                    -----------     ---------

See Notes to Consolidated Financial Statements.



                 ENTERGY CORPORATION AND SUBSIDIARIES
                CONSOLIDATED STATEMENTS OF CASH FLOWS
           For the Six Months Ended June 30, 2003 and 2002
                              (Unaudited)

                                                                           2003          2002
                                                                             (In Thousands)

                        FINANCING ACTIVITIES
Proceeds from the issuance of:
  Long-term debt                                                          1,482,495       299,431
  Common stock                                                              176,765       112,705
Retirement of long-term debt                                               (996,761)     (910,908)
Redemption of preferred stock                                                (2,250)       (1,403)
Changes in short-term borrowings - net                                     (140,000)      334,333
Dividends paid:
  Common stock                                                             (157,355)     (147,329)
  Preferred stock                                                           (11,792)      (11,872)
                                                                         ----------      --------
Net cash flow provided by (used in) financing activities                    351,102      (325,043)
                                                                         ----------      --------

Effect of exchange rates on cash and cash equivalents                         1,181        (5,748)
                                                                         ----------      --------

Net decrease in cash and cash equivalents                                  (257,547)      (20,913)

Cash and cash equivalents at beginning of period                          1,335,328       751,573
                                                                         ----------      --------
Cash and cash equivalents at end of period                               $1,077,781      $730,660
                                                                         ==========      ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
  Cash paid during the period for:
    Interest - net of amount capitalized                                   $291,950      $333,750
    Income taxes                                                            $91,282       $33,877
  Noncash investing and financing activities:
     Change in unrealized appreciation/(depreciation) of
       decommissioning trust assets                                         $29,674      ($28,584)
     Long-term debt refunded with proceeds from
       long-term debt issued in prior period                                      -      ($47,000)

See Notes to Consolidated Financial Statements.




                 ENTERGY CORPORATION AND SUBSIDIARIES
                     CONSOLIDATED BALANCE SHEETS
                                ASSETS
                  June 30, 2003 and December 31, 2002
                             (Unaudited)

                                                                         2003        2002
                                                                          (In Thousands)

                         CURRENT ASSETS
Cash and cash equivalents:
  Cash                                                                  $115,063     $169,788
  Temporary cash investments - at cost,
   which approximates market                                             962,535    1,165,260
  Special deposits                                                           183          280
                                                                     -----------  -----------
     Total cash and cash equivalents                                   1,077,781    1,335,328
                                                                     -----------  -----------
Notes receivable                                                          44,693        2,078
Accounts receivable:
  Customer                                                               438,461      323,215
  Allowance for doubtful accounts                                        (22,741)     (27,285)
  Other                                                                  281,422      244,621
  Accrued unbilled revenues                                              431,532      319,133
                                                                     -----------  -----------
     Total receivables                                                 1,128,674      859,684
                                                                     -----------  -----------
Deferred fuel costs                                                      294,179       55,653
Fuel inventory - at average cost                                         121,546       96,467
Materials and supplies - at average cost                                 547,253      525,900
Deferred nuclear refueling outage costs                                  174,542      163,646
Prepayments and other                                                    157,733      166,827
                                                                     -----------  -----------
TOTAL                                                                  3,546,401    3,205,583
                                                                     -----------  -----------

                 OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity                                     975,907      824,209
Decommissioning trust funds                                            2,196,536    2,069,198
Non-utility property - at cost (less accumulated depreciation)           239,405      297,294
Other                                                                    453,627      270,889
                                                                     -----------  -----------
TOTAL                                                                  3,865,475    3,461,590
                                                                     -----------  -----------

                 PROPERTY, PLANT AND EQUIPMENT
Electric                                                              27,056,949   26,789,538
Property under capital lease                                             761,039      746,624
Natural gas                                                              214,458      209,969
Construction work in progress                                          1,590,926    1,232,891
Nuclear fuel under capital lease                                         264,013      259,433
Nuclear fuel                                                             278,071      263,609
                                                                     -----------  -----------
TOTAL PROPERTY, PLANT AND EQUIPMENT                                   30,165,456   29,502,064
Less - accumulated depreciation and amortization                      12,265,459   12,307,112
                                                                     -----------  -----------
PROPERTY, PLANT AND EQUIPMENT - NET                                   17,899,997   17,194,952
                                                                     -----------  -----------

                DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
  SFAS 109 regulatory asset - net                                        834,362      844,105
  Unamortized loss on reacquired debt                                    149,147      155,161
  Other regulatory assets                                              1,190,030      738,328
Long-term receivables                                                     22,852       24,703
Goodwill                                                                 377,172      377,172
Other                                                                    947,025      946,375
                                                                     -----------  -----------
TOTAL                                                                  3,520,588    3,085,844
                                                                     -----------  -----------

TOTAL ASSETS                                                         $28,832,461  $26,947,969
                                                                     ===========  ===========
See Notes to Consolidated Financial Statements.



                 ENTERGY CORPORATION AND SUBSIDIARIES
                      CONSOLIDATED BALANCE SHEETS
                 LIABILITIES AND SHAREHOLDERS' EQUITY
                 June 30, 2003 and December 31, 2002
                              (Unaudited)

                                                                         2003          2002
                                                                           (In Thousands)

                      CURRENT LIABILITIES
Currently maturing long-term debt                                        $776,896    $1,191,320
Notes payable                                                                 351           351
Accounts payable                                                          701,689       855,446
Customer deposits                                                         206,101       198,442
Taxes accrued                                                             289,299       385,315
Accumulated deferred income taxes                                         118,243        26,468
Nuclear refueling outage costs                                              2,566        14,244
Interest accrued                                                          146,754       175,440
Obligations under capital leases                                          153,106       153,822
Other                                                                     122,571       171,341
                                                                      -----------   -----------
TOTAL                                                                   2,517,576     3,172,189
                                                                      -----------   -----------

             DEFERRED CREDITS AND OTHER LIABILITIES
Accumulated deferred income taxes and taxes accrued                     4,565,754     4,250,800
Accumulated deferred investment tax credits                               430,909       447,925
Obligations under capital leases                                          156,960       155,943
Other regulatory liabilities                                              276,513       185,579
Decommissioning                                                         2,113,263     1,565,997
Transition to competition                                                  79,098        79,098
Regulatory reserves                                                        44,358        56,438
Accumulated provisions                                                    418,995       389,868
Other                                                                   1,299,515     1,145,232
                                                                      -----------   -----------
TOTAL                                                                   9,385,365     8,276,880
                                                                      -----------   -----------

Long-term debt                                                          7,863,613     7,086,999
Preferred stock with sinking fund                                          22,077        24,327
Preferred stock without sinking fund                                      334,337       334,337
Company-obligated mandatorily redeemable
  preferred securities of subsidiary trusts holding
  solely junior subordinated deferrable debentures                        215,000       215,000

                      SHAREHOLDERS' EQUITY
Common stock, $.01 par value, authorized 500,000,000
  shares; issued 248,174,087 shares in 2003 and in 2002                     2,482         2,482
Paid-in capital                                                         4,690,152     4,666,753
Retained earnings                                                       4,382,757     3,938,693
Accumulated other comprehensive income (loss)                               6,553       (22,360)
Less - treasury stock, at cost (20,347,971 shares in 2003 and
  25,752,410 shares in 2002)                                              587,451       747,331
                                                                      -----------   -----------
TOTAL                                                                   8,494,493     7,838,237
                                                                      -----------   -----------

Commitments and Contingencies

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                            $28,832,461   $26,947,969
                                                                      ===========   ===========
See Notes to Consolidated Financial Statements.


                      ENTERGY CORPORATION AND SUBSIDIARIES
          CONSOLIDATED STATEMENTS OF RETAINED EARNINGS, COMPREHENSIVE
                        INCOME, AND PAID-IN CAPITAL
           For the Three and Six Months Ended June 30, 2003 and 2002
                                (Unaudited)

                                                                                Three Months Ended
                                                                              2003                    2002
                                                                                   (In Thousands)
                       RETAINED EARNINGS
Retained Earnings - Beginning of period                             $4,255,378              $3,486,122
    Add  - Earnings applicable to common stock                         205,641    $205,641     241,653    $241,653
    Deduct:
        Dividends declared on common stock                              79,192                  74,093
        Capital stock and other expenses                                  (930)                   (159)
                                                                    ----------              ----------
              Total                                                     78,262                  73,934
                                                                    ----------              ----------
Retained Earnings - End of period                                   $4,382,757              $3,653,841
                                                                    ==========              ==========
               ACCUMULATED OTHER COMPREHENSIVE
                 INCOME (LOSS) (Net of Taxes):
Balance at beginning of period
  Accumulated derivative instrument fair value changes                 $16,696                ($17,631)
  Other accumulated comprehensive income (loss) items                  (52,221)                (10,048)
                                                                    ----------              ----------
     Total                                                             (35,525)                (27,679)
                                                                    ----------              ----------

Net derivative instrument fair value changes
  arising during the period                                                794         794      14,003      14,003

Foreign currency translation adjustments                                 1,554       1,554       2,101     (64,233)

Net unrealized investment gains (losses)                                39,730      39,730      (5,666)     (5,666)
                                                                    ----------    --------  ----------    --------

Balance at end of period:
  Accumulated derivative instrument fair value changes                 $17,490                 ($3,628)
  Other accumulated comprehensive income (loss) items                  (10,937)                (13,613)
                                                                    ----------              ----------
     Total                                                              $6,553                ($17,241)
                                                                    ===========   --------  ==========    --------
Comprehensive Income                                                              $247,719                $185,757
                                                                                  ========                ========
                        PAID-IN CAPITAL
Paid-in Capital - Beginning of period                               $4,674,510              $4,663,931
  Add:  Common stock issuances related to stock plans                   15,642                   2,823
                                                                    ----------              ----------
Paid-in Capital - End of period                                     $4,690,152              $4,666,754
                                                                    ==========              ==========



                                                                                  Six Months Ended
                                                                              2003                    2002
                                                                                   (In Thousands)
                       RETAINED EARNINGS
Retained Earnings - Beginning of period                             $3,938,693              $3,638,448
    Add  - Earnings applicable to common stock                         600,648    $600,648     162,729    $162,729
    Deduct:
        Dividends declared on common stock                             157,343                 147,355
        Capital stock and other expenses                                  (759)                    (19)
                                                                    ----------              ----------
              Total                                                    156,584                 147,336
                                                                    ----------              ----------
Retained Earnings - End of period                                   $4,382,757              $3,653,841
                                                                    ==========              ==========
               ACCUMULATED OTHER COMPREHENSIVE
                 INCOME (LOSS) (Net of Taxes):
Balance at beginning of period
     Accumulated derivative instrument fair value changes              $17,313                ($17,973)
     Other accumulated comprehensive income (loss) items               (39,673)                (70,821)
                                                                    ----------              ----------
     Total                                                             (22,360)                (88,794)
                                                                    ----------              ----------

Net derivative instrument fair value changes
  arising during the period                                                177         177      14,345      14,345

Foreign currency translation adjustments                                 1,710       1,710      68,057       1,723

Net unrealized investment gains (losses)                                27,026      27,026     (10,849)    (10,849)
                                                                    ----------    --------  ----------    --------

Balance at end of period:
     Accumulated derivative instrument fair value changes              $17,490                 ($3,628)
     Other accumulated comprehensive income (loss) items               (10,937)                (13,613)
                                                                    ----------              ----------
     Total                                                              $6,553                ($17,241)
                                                                    ==========    --------  ==========    --------
Comprehensive Income                                                              $629,561                $167,948
                                                                                  ========                ========
                        PAID-IN CAPITAL
Paid-in Capital - Beginning of period                               $4,666,753              $4,662,704
  Add:  Common stock issuances related to stock plans                   23,399                   4,050
                                                                    ----------              ----------
Paid-in Capital - End of period                                     $4,690,152              $4,666,754
                                                                    ==========              ==========

See Notes to Consolidated Financial Statements.


                   ENTERGY CORPORATION AND SUBSIDIARIES
                       SELECTED OPERATING RESULTS
       For the Three and Six Months Ended June 30, 2003 and 2002
                               (Unaudited)


                                    Three Months Ended     Increase/
          Description               2003         2002     (Decrease)       %
                                      (In Millions)
Domestic Electric Operating Revenues:
  Residential                     $ 618.7      $ 549.6       $ 69.1        13
  Commercial                        469.6        405.6         64.0        16
  Industrial                        544.9        465.7         79.2        17
  Governmental                       51.1         43.1          8.0        19
                                 ----------------------------------
    Total retail                  1,684.3      1,464.0        220.3        15
  Sales for resale                  102.2         84.9         17.3        20
  Other                             139.4        137.8          1.6         1
                                 ----------------------------------
    Total                        $1,925.9    $ 1,686.7      $ 239.2        14
                                 ==================================
Billed Electric Energy
 Sales (GWh):
  Residential                       7,170        7,202          (32)        -
  Commercial                        6,164        6,112           52         1
  Industrial                        9,556       10,294         (738)       (7)
  Governmental                        664          654           10         2
                                 ----------------------------------
    Total retail                   23,554       24,262         (708)       (3)
  Sales for resale                  2,590        2,444          146         6
                                 ----------------------------------
    Total                          26,144       26,706         (562)       (2)
                                 ==================================

                                   Six Months Ended       Increase/
          Description              2003         2002     (Decrease)       %
                                     (In Millions)
Domestic Electric Operating Revenues:
  Residential                   $ 1,182.9    $ 1,051.2      $ 131.7        13
  Commercial                        865.4        762.5        102.9        13
  Industrial                        996.2        861.8        134.4        16
  Governmental                       95.3         81.7         13.6        17
                                 ----------------------------------
    Total retail                  3,139.8      2,757.2        382.6        14
  Sales for resale                  199.1        154.6         44.5        29
  Other                             188.8        176.0         12.8         7
                                 ----------------------------------
    Total                        $3,527.7    $ 3,087.8      $ 439.9        14
                                 ==================================
Billed Electric Energy
 Sales (GWh):
  Residential                      15,013       14,476          537         4
  Commercial                       11,986       11,710          276         2
  Industrial                       18,880       19,884       (1,004)       (5)
  Governmental                      1,297        1,271           26         2
                                 ----------------------------------
    Total retail                   47,176       47,341         (165)        -
  Sales for resale                  5,103        4,658          445        10
                                 ----------------------------------
    Total                          52,279       51,999          280         1
                                 ==================================

See Note 9 to the consolidated financial statements in the Form 10-K for information on certain warranties made by Entergy or its subsidiaries in the CitiPower and Saltend sales transactions. Regarding the CitiPower warranties and the tax matters described in the Form 10-K, after extended negotiations with the Australian Taxation Office, a settlement agreement was reached in which the Australian Taxation Office agreed to a deduction that reduced the amount of the assessments to A$5.1 million ($3.2 million). Additionally, a settlement agreement was reached with CitiPower in which Entergy agreed to pay the full amount of the amended assessments and CitiPower agreed to pay its own costs and expenses with respect to the Australian Taxation Office negotiations and assessments.

See Note 9 to the consolidated financial statements in the Form 10-K for information on nuclear liability, property and replacement power insurance, related NRC regulations, and the disposal of spent nuclear fuel and other high-level radioactive waste associated with Entergy's nuclear power plants.

Entergy's nuclear owner/licensees are members of certain insurance programs, underwritten by Nuclear Electric Insurance Limited (NEIL), that provide coverage for property damage, including decontamination and premature decommissioning expense, to members' nuclear generating plants. Beginning April 1, 2003, Entergy is insured against such losses up to $1.6 billion for each of its nuclear units, except for FitzPatrick, Pilgrim, and Vermont Yankee, which are insured for $1.115 billion, and Indian Point 2 and 3 which are insured for $2.3 billion in property damages. In addition, certain of Entergy's nuclear owner/licensees are members of the NEIL insurance program that covers some of the replacement power and business interruption costs incurred due to prolonged nuclear unit outages. Under the property damage and replacement power/business interruption insurance programs, these Entergy subsidiaries could be subject to assessments if losses exceed the accumulated funds available to the insurers. Beginning April 1, 2003, the maximum amounts of such possible assessments are $54.0 million for the U.S. Utility segment and $84.5 million for the Non-Utility Nuclear segment.

Regarding the spent nuclear fuel storage capacity reported in the Form 10-K, current on-site spent nuclear fuel storage capacity at Grand Gulf 1 is now estimated to be sufficient until approximately 2007, at which time dry cask storage facilities will be placed into service. Current on-site spent nuclear fuel storage capacity at Indian Point is now estimated to be sufficient until 2006, at which time planned additional dry cask storage capacity is to begin operation.

See Note 9 to the consolidated financial statements in the Form 10-K for information on nuclear decommissioning costs. As discussed in Note 7, Entergy implemented SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. The implementation of this new accounting standard resulted in a reevaluation of Entergy's decommissioning liabilities. Additionally, future decommissioning expense under this new standard will represent the accretion of this liability at the applicable discount rate, and will no longer be equal to the amounts collected in rates for decommissioning for the rate-regulated portion of the U.S. Utility's nuclear plants, as was the case before the implementation of SFAS 143. For these plants, the net difference between the accretion expense and depreciation expense under SFAS 143 and the earnings on the decommissioning trust funds and collections in rates will be recorded as a regulatory charge or credit, except for the non-rate-regulated portion of River Bend. The table below summarizes the activity in the decommissioning liabilities during the first six months of 2003:

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 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 on the market protocols that will be the subject of a PUCT hearing scheduled for August 20, 2003.

In February 2003, Entergy Gulf States implemented a $54 million 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 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. The LPSC staff has submitted several requests for information from Entergy Louisiana. Initially, it was expected that the LPSC staff would issue its audit report in the spring of 2003. That date has been delayed until the fall of 2003, following which a procedural schedule will be established.

In January 2003, the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States and its affiliates pursuant to a November 1997 LPSC general order. The audit will include a review of the reasonableness of charges flowed by Entergy Gulf States through its fuel adjustment clause in Louisiana for the period January 1, 1995 through December 1, 2002. Discovery is underway, but a procedural schedule has not yet been established.

In May 2003, Entergy Mississippi filed and the MPSC approved a change in Entergy Mississippi's energy cost recovery rider. Entergy Mississippi will defer until 2004 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.

The APSC ordered Entergy Arkansas to use a 20-year life extension assumption for ANO 1 and 2 which resulted in the cessation of the collection of funds to decommission ANO 1 and 2 effective in 2001, and the APSC approved the continued cessation of collection of funds during 2003. Every five years, Entergy Arkansas is required by the APSC to update the estimated costs to decommission ANO. In March 2003, Entergy Arkansas filed with the APSC its third five-year estimate of ANO decommissioning costs. The updated estimate indicated the current cost to decommission the two ANO units would be $936 million compared to $813 million in the 1997 estimate. The new estimate is currently under review by the APSC and if approved will be used in the next annual determination of the nuclear decommissioning rate rider. The APSC has scheduled hearings to consider the study for September 2003.

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. In July 2003, Entergy Gulf States filed testimony in which it rebutted the testimony of the LPSC staff. Hearings are scheduled for October 2003.

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.

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 adjustment 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 six months ended June 30, 2003, Entergy Corporation issued 5,404,439 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 $395 million was outstanding as of June 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 June 30, 2003 was 2.24%. 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 June 30, 2003, Entergy's subsidiaries' authorized limit was $1.6 billion and the outstanding borrowing from the money pool was $148.1 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 0.13%.

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 July 27, 2003, Entergy Corporation's Board of Directors declared a common stock dividend of $0.45 per share, payable on September 1, 2003, to holders of record as of August 12, 2003.

Entergy's reportable segments as of June 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 second quarters of 2003 and 2002 is as follows (in thousands):

Entergy's segment financial information for the six months ended June 30, 2003 and 2002 is as follows (in thousands):

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 six months ended June 30, 2002 includes charges of $419.5 million to operating expenses ($271.5 million net-of-tax), including $18.1 million ($10.6 million net-of-tax) in the second quarter, 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 Entergy'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 a 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 in the first quarter of 2003 of approximately $160 million net-of-tax ($0.70 per share) as a result of a one-time cumulative effect of accounting 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 Investments for Certain 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 gains/(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 is effective as of 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 will be 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 will not be 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 method 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 increased primarily due to the following:

• a decrease in other operation and maintenance expenses, a portion of which is offset by a decrease in other regulatory credits and has no effect on net income;
• a decrease in other interest charges, a portion of which is offset by a decrease in other regulatory credits and has no effect on net income;
• an increase in net wholesale revenue; and
• the effect of the March 2002 settlement agreement and 2001 earnings review, the net impact of which is an $8.5 million increase in net income.

Other operation and maintenance expenses decreased $173.8 million primarily due to:

• decreased expenses 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 in 2002 (offset in other regulatory credits as discussed above);
• a decrease of $7.9 million due to lower customer service support costs;
• a decrease of $2.0 million due to decreased vegetation spending; and
• a decrease of $1.5 million due to lower nuclear maintenance expenses.

An increase in interest expense in 2002 resulting from the true-up of the annual fuel recovery rider in March 2002 decreased other interest charges by $4.5 million. A decrease of $2.5 million (offset in other regulatory credits as discussed above) due to the elimination of the transition cost account obligation as a result of the March 2002 settlement agreement also decreased other interest charges.

Net wholesale revenue increased $3.9 million primarily due to an increase in sales volume to non-associated companies and higher wholesale prices.

Other miscellaneous deductions decreased $2.4 million primarily due to the reversal in the second quarter of 2002 of the first quarter 2002 recording of 2000 ice storm expenses in other operation and maintenance expenses of $2.7 million, as recommended by the APSC staff as part of the March 2002 settlement agreement.

The increase in net income was partially offset by an increase in interest on long-term debt, a decrease in unbilled revenue, and an increase in depreciation and amortization expenses.

Interest on long-term debt increased $2.6 million primarily due to the issuance of the following:

• $150 million of 5.4% Series First Mortgage Bonds in May 2003;
• $100 million of 5.9% Series First Mortgage Bonds in June 2003; and
• $115 million of 5.0% Series First Mortgage Bonds in June 2003.

Unbilled revenue decreased $2.1 million primarily due to less favorable wholesale sales volume.

Depreciation and amortization expenses increased $2.0 million primarily due to an increase in plant in service.

Net income increased primarily due to the following:

• an increase in net base revenue;
• a decrease in other operation and maintenance expenses, a portion of which is offset by a 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 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 $8.5 million increase in net income.

Net base revenue increased $13.9 million primarily due to increased electricity usage of 295 GWh in the residential and commercial sectors.

• decreased expenses 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 in 2002 (offset in other regulatory credits as discussed above);
• a decrease of $5.0 million due to decreased vegetation spending; and
• a decrease of $4.2 million due to lower nuclear maintenance expenses.

Net wholesale revenue increased $7.4 million primarily due to an increase in sales volume to non-associated companies and higher wholesale prices.

An increase in interest expense in 2002 resulting from the true-up of the annual fuel recovery rider as mentioned above decreased other interest charges by $4.5 million. A decrease of $4.1 million (offset in other regulatory credits as discussed above) due to the elimination of the transition cost account obligation as a result of the March 2002 settlement agreement also decreased other interest charges.

Taxes other than income taxes decreased $2.6 million primarily due to the accrual of sales tax on the System Energy refund in 2002 refunded to customers but not recoverable from the state of Arkansas because of the statute of limitations.

Other miscellaneous deductions decreased $2.0 million primarily due to the reversal in the second quarter of 2002 of the first quarter 2002 recording of 2000 ice storm expenses in other operation and maintenance expenses of $2.7 million as mentioned above.

The increase in net income was partially offset by a decrease in unbilled revenue and an increase in depreciation and amortization expenses.

Unbilled revenue decreased $10.6 million due to less favorable sales volume primarily due to the effect of colder winter weather in December 2002.

Depreciation and amortization expenses increased $6.7 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 second quarters of 2003 and 2002 were 37.1% and 53.4%, respectively. The effective income tax rates for the six months ended June 30, 2003 and 2002 were 38.6% and 42.1%, respectively. The difference in the effective income tax rate for the second quarter 2002 versus the federal statutory rate of 35.0% is primarily due to the effect of flow-through and permanent book and tax timing differences related to the March 2002 settlement agreement in addition to depreciation book and tax timing differences. The difference in the effective income tax rate for the six months ended June 30, 2002 versus the federal statutory rate of 35.0% is primarily due to the aforementioned book and tax timing differences, partially offset by book and tax timing differences related to research and experimental expenses consistent with amended tax returns.

Operating revenues increased $27.0 million primarily due to the establishment of an $18.1 million provision for rate refund in 2002 in accordance with the March 2002 settlement agreement and 2001 earnings review. The provision was offset by an increase in other regulatory credits and had no effect on net income in 2002.

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.

Operating revenues increased $11.9 million primarily due to the aforementioned establishment of a $18.1 million provision for rate refund in 2002 in accordance with the March 2002 settlement and 2001 earnings review. The provision was offset by an increase in other regulatory credits and had no effect on net income in 2002.

Decommissioning expense increased $17.9 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.

Cash flows for the six months ended June 30, 2003 and 2002 were as follows: