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ENTERGY MISSISSIPPI, LLC - Quarter Report: 2004 September (Form 10-Q)

__________________________________________________________________________________________

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

(Mark One)

 

X

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

   
 

For the Quarterly Period Ended September 30, 2004

 

OR

 

TRANSITION REPORT PURSUANT TO SECTION 13
OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

   
 

For the transition period from ____________ to ____________

Commission
File Number

Registrant, State of Incorporation,
Address of Principal Executive Offices and Telephone Number

I.R.S. Employer
Identification No.

1-11299

ENTERGY CORPORATION
(a Delaware corporation)
639 Loyola Avenue
New Orleans, Louisiana 70113
Telephone (504) 576-4000

72-1229752

1-10764

ENTERGY ARKANSAS, INC.
(an Arkansas corporation)
425 West Capitol Avenue, 40th Floor
Little Rock, Arkansas 72201
Telephone (501) 377-4000

71-0005900

1-27031

ENTERGY GULF STATES, INC.
(a Texas corporation)
350 Pine Street
Beaumont, Texas 77701
Telephone (409) 838-6631

74-0662730

1-8474

ENTERGY LOUISIANA, INC.
(a Louisiana corporation)
4809 Jefferson Highway
Jefferson, Louisiana 70121
Telephone (504) 840-2734

72-0245590

1-31508

ENTERGY MISSISSIPPI, INC.
(a Mississippi corporation)
308 East Pearl Street
Jackson, Mississippi 39201
Telephone (601) 368-5000

64-0205830

0-5807

ENTERGY NEW ORLEANS, INC.
(a Louisiana corporation)
1600 Perdido Street, Building 505
New Orleans, Louisiana 70112
Telephone (504) 670-3674

72-0273040

1-9067

SYSTEM ENERGY RESOURCES, INC.
(an Arkansas corporation)
Echelon One
1340 Echelon Parkway
Jackson, Mississippi 39213
Telephone (601) 368-5000

72-0752777

__________________________________________________________________________________________

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.

Yes

X

No

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

 

Yes

No

Entergy Corporation

Ö

 

Entergy Arkansas, Inc.

 

Ö

Entergy Gulf States, Inc.

 

Ö

Entergy Louisiana, Inc.

 

Ö

Entergy Mississippi, Inc.

 

Ö

Entergy New Orleans, Inc.

 

Ö

System Energy Resources, Inc.

 

Ö

Common Stock Outstanding

 

Outstanding at October 29, 2004

Entergy Corporation

($0.01 par value)

223,544,623

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, 2003, and the Quarterly Reports on Form 10-Q for the quarters ended March 31, 2004 and June 30, 2004, filed by the individual registrants with the SEC, and should be read in conjunction therewith.

 

 

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

 

 

Page Number

   

Definitions

1

Entergy Corporation and Subsidiaries

 
 

Management's Financial Discussion and Analysis

 
   

Results of Operations

4

   

Liquidity and Capital Resources

10

   

Significant Factors and Known Trends

13

   

Critical Accounting Estimates

20

 

Consolidated Statements of Income

21

 

Consolidated Statements of Cash Flows

22

 

Consolidated Balance Sheets

24

 

Consolidated Statements of Retained Earnings, Comprehensive Income, and
Paid-In Capital

26

 

Selected Operating Results

27

 

Notes to Consolidated Financial Statements

28

Entergy Arkansas, Inc.

 
 

Management's Financial Discussion and Analysis

 
   

Results of Operations

41

   

Liquidity and Capital Resources

43

   

Significant Factors and Known Trends

44

   

Critical Accounting Estimates

46

 

Income Statements

47

 

Statements of Cash Flows

49

 

Balance Sheets

50

 

Selected Operating Results

52

Entergy Gulf States, Inc.

 
 

Management's Financial Discussion and Analysis

 
   

Results of Operations

53

   

Liquidity and Capital Resources

56

   

Significant Factors and Known Trends

57

   

Critical Accounting Estimates

60

 

Income Statements

61

 

Statements of Cash Flows

63

 

Balance Sheets

64

 

Statements of Retained Earnings and Comprehensive Income

66

 

Selected Operating Results

67

Entergy Louisiana, Inc.

 
 

Management's Financial Discussion and Analysis

 
   

Results of Operations

68

   

Liquidity and Capital Resources

70

   

Significant Factors and Known Trends

71

   

Critical Accounting Estimates

73

 

Income Statements

74

 

Statements of Cash Flows

75

 

Balance Sheets

76

 

Selected Operating Results

78

Entergy Mississippi, Inc.

 
 

Management's Financial Discussion and Analysis

 
   

Results of Operations

79

   

Liquidity and Capital Resources

81

   

Significant Factors and Known Trends

83

Critical Accounting Estimates

85

 

Income Statements

86

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

 

 

Page Number

   
 

Statements of Cash Flows

87

 

Balance Sheets

88

 

Selected Operating Results

90

Entergy New Orleans, Inc.

 
 

Management's Financial Discussion and Analysis

 
   

Results of Operations

91

   

Liquidity and Capital Resources

93

   

Significant Factors and Known Trends

94

   

Critical Accounting Estimates

96

 

Income Statements

97

 

Statements of Cash Flows

99

 

Balance Sheets

100

 

Selected Operating Results

102

System Energy Resources, Inc.

 
 

Management's Financial Discussion and Analysis

 
   

Results of Operations

103

   

Liquidity and Capital Resources

103

   

Significant Factors and Known Trends

104

   

Critical Accounting Estimates

104

 

Income Statements

105

 

Statements of Cash Flows

107

 

Balance Sheets

108

Notes to Respective Financial Statements

110

Item 4. Controls and Procedures

123

Part II. Other Information

 
 

Item 1. Legal Proceedings

124

 

Item 2. Unregistered Sales of Equity Securities and Use Of Proceeds

125

 

Item 5. Other Information

125

 

Item 6. Exhibits

129

Signature

131

 

 

FORWARD-LOOKING INFORMATION

In this filing and from time to time, Entergy makes statements concerning its expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. Such statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Although Entergy believes that these forward-looking statements and the underlying assumptions are reasonable, it cannot provide assurance that they will prove correct. Except to the extent required by the federal securities laws, Entergy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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 System Agreement and 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, the ability to extend or replace the existing purchased power agreements for those facilities, including 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
  • the ability to sell Entergy-Koch's Gulf South Pipeline at an attractive price and the amount of cash that Entergy-Koch is able to distribute to Entergy as a result of Entergy-Koch business sales
  • 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, and changes in the rating agencies' ratings criteria
  • 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, uranium, and other energy-related commodities
  • changes in utility regulation, including the beginning or end of retail and wholesale competition, the ability to recover net utility assets and other potential stranded costs, the establishment of a regional transmission organization that includes Entergy's utility service territory, and the establishment of market power criteria by the FERC
  • changes in regulation of nuclear generating facilities and nuclear materials and fuel, including possible shutdown of Indian Point or other nuclear generating facilities
  • uncertainty regarding the establishment of permanent sites for spent nuclear fuel storage and disposal
  • resolution of pending or future applications for license extensions of 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, mercury, 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 effects of threatened or actual terrorism and war
  • the success of Entergy's strategies to reduce current tax payments
  • the effects of litigation and government investigations
  • changes in accounting standards, corporate governance, and securities law requirements
  • Entergy's ability to attract and retain talented management and directors.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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DEFINITIONS

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

Abbreviation or Acronym

Term

   

ALJ

Administrative Law Judge

ANO 1 and 2

Units 1 and 2 of Arkansas Nuclear One Steam Electric Generating Station (nuclear)

APSC

Arkansas Public Service Commission

BCF

One billion cubic feet of natural gas

BCF/D

One billion cubic feet of natural gas per day

Board

Board of Directors of Entergy Corporation

capacity factor

Actual plant output divided by maximum potential plant output for the period

City Council or Council

Council of the City of New Orleans, Louisiana

DOE

United States Department of Energy

domestic utility companies

Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, collectively

EPA

United States Environmental Protection Agency

EPDC

Entergy Power Development Corporation, a wholly-owned subsidiary of Entergy Corporation

electricity marketed

Total physical volume marketed by Entergy-Koch in the U.S. and Europe during the period

electricity volatility

Measure of price fluctuation over time using standard deviation of daily price differences for into-Cinergy power prices for the upcoming month

Energy Commodity Services

Entergy's business segment that is focused almost exclusively on providing energy commodity trading and gas transportation and storage services through Entergy-Koch, LP and also includes Entergy's non-nuclear wholesale assets business

Entergy

Entergy Corporation and its direct and indirect subsidiaries

Entergy Corporation

Entergy Corporation, a Delaware corporation

Entergy-Koch

Entergy-Koch, L.P., a joint venture equally owned by subsidiaries of Entergy and Koch Industries, Inc.

FEMA

Federal Emergency Management Agency

FERC

Federal Energy Regulatory Commission

FitzPatrick

James A. FitzPatrick nuclear power plant, 825 MW facility located near Oswego, New York, purchased in November 2000 from NYPA by Entergy's Non-Utility Nuclear business

Form 10-K

The combined Annual Report on Form 10-K for the year ended December 31, 2003 of Entergy, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy

gain/loss days

Ratio of the number of days when Entergy-Koch recognized a net gain from commodity trading activities to the number of days when Entergy-Koch recognized a net loss from commodity trading activities

gas marketed

Total physical volume marketed by Entergy-Koch in the U.S. and Europe during the period

gas volatility

Measure of price fluctuation over time using standard deviation of daily price differences for Henry Hub natural gas prices for the upcoming month

DEFINITIONS (Continued)

Abbreviation or Acronym

Term

Grand Gulf 1

Unit No. 1 of the Grand Gulf Nuclear Generating Station

GWh

Gigawatt hour(s), which equals one million kilowatt-hours

Indian Point 2

Indian Point Energy Center Unit 2 - nuclear power plant, 984 MW facility located in Westchester County, New York, purchased in September 2001 from Consolidated Edison by Entergy's Non-Utility Nuclear business

Indian Point 3

Indian Point Energy Center Unit 3 - nuclear power plant, 994 MW facility located in Westchester County, New York, purchased in November 2000 from NYPA by Entergy's Non-Utility Nuclear business

kW

Kilowatt

kWh

Kilowatt-hour(s)

LDEQ

Louisiana Department of Environmental Quality

LPSC

Louisiana Public Service Commission

Mcf

1,000 cubic feet of gas

miles of pipeline

Total miles of transmission and gathering pipeline

MMBtu

One million British Thermal Units

MPSC

Mississippi Public Service Commission

MW

Megawatt(s), which equals one thousand kilowatt(s)

MWh

Megawatt-hours

Net debt ratio

Gross debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents

Net MW in operation

Installed capacity owned or operated

Net revenue

Operating revenue net of fuel, fuel-related, and purchased power expenses; other regulatory credits; and amortization of rate deferrals

Non-Utility Nuclear

Entergy's business segment that owns and operates five nuclear power plants and sells electric power produced by those plants to wholesale customers

NRC

Nuclear Regulatory Commission

NYPA

New York Power Authority

Pilgrim

Pilgrim Nuclear Station, 688 MW facility located in Plymouth, Massachusetts, purchased in July 1999 from Boston Edison by Entergy's Non-Utility Nuclear business

production cost

Cost in $/MMBtu associated with delivering gas, excluding the cost of the gas

PPA

Purchased power agreement

PRP

Potentially responsible party (a person or entity that may be responsible for remediation of environmental contamination)

PUCT

Public Utility Commission of Texas

PUHCA

Public Utility Holding Company Act of 1935, as amended

PURPA

Public Utility Regulatory Policies Act of 1978

River Bend

River Bend Steam Electric Generating Station (nuclear)

RTO

Regional transmission organization

SEC

Securities and Exchange Commission

SFAS

Statement of Financial Accounting Standards as promulgated by the Financial Accounting Standards Board

SMEPA

South Mississippi Electric Power Agency, which owns a 10% interest in Grand Gulf 1

DEFINITIONS (Concluded)

Abbreviation or Acronym

Term

   

spark spread

The dollar difference between electricity prices per unit and natural gas prices after assuming a conversion ratio for the number of natural gas units necessary to generate one unit of electricity

System Agreement

Agreement, effective January 1, 1983, as modified, among the domestic utility companies relating to the sharing of generating capacity and other power resources

System Energy

System Energy Resources, Inc.

System Fuels

System Fuels, Inc.

throughput

Gas in BCF/D transported through a pipeline during the period

TWh

Terawatt-hour(s), which equals one billion kilowatt-hours

Unit Power Sales Agreement

Agreement, dated as of June 10, 1982, as amended and approved by FERC, among Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy, relating to the sale of capacity and energy from System Energy's share of Grand Gulf 1

UK

The United Kingdom of Great Britain and Northern Ireland

U.S. Utility

Entergy's business segment that generates, transmits, distributes, and sells electric power, with a small amount of natural gas distribution

Vermont Yankee

Vermont Yankee nuclear power plant, 510 MW facility located in Vernon, Vermont, purchased in July 2002 from Vermont Yankee Nuclear Power Corporation by Entergy's Non-Utility Nuclear business

Waterford 3

Unit No. 3 (nuclear) of the Waterford Steam Electric Generating Station, 100% owned or leased by Entergy Louisiana

weather-adjusted usage

Electric usage excluding the effects of deviations from normal weather

ENTERGY CORPORATION AND SUBSIDIARIES

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

 

Results of Operations

Entergy's consolidated earnings applicable to common stock for the third quarter and nine months ended September 30, 2004 and 2003 were as follows:

Third Quarter

Nine Months Ended

Operating Segment

 

2004

 

2003

2004

2003

(In Thousands)

 

 

 

 

 

U.S. Utility

 

$258,048 

 

$272,937 

$568,669 

$502,441 

Non-Utility Nuclear

 

63,713 

 

59,606 

195,541 

301,451 

Energy Commodity Services

 

(38,935)

 

36,330 

(19,632)

178,696 

Parent & Other

 

(582)

 

(3,099)

10,009 

(16,165)

Total

 

$282,244 

 

$365,774 

$754,587 

$966,423 

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

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

U.S. UTILITY

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

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

Net Revenue

Third Quarter 2004 Compared to Third Quarter 2003

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

  

 

Amount

  

 

(In Millions)

 

 

 

2003 net revenue

 

$1,232.2 

Volume/weather

 

(31.7)

Price applied to unbilled sales

 

15.0 

2004 deferrals

 

7.8 

Other

 

(2.9)

2004 net revenue

 

$1,220.4 

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

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

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

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

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

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

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

 

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

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

  

 

Amount

  

 

(In Millions)

 

 

 

2003 net revenue

 

$3,280.4 

Deferred fuel cost revisions

 

(46.3)

Price applied to unbilled sales

 

(28.0)

Summer capacity charges

 

17.4 

Base rates

 

11.1 

Other

 

11.1 

2004 net revenue

 

$3,245.7 

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

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

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

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

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

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

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

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

 

Other Income Statement Variances

Third Quarter 2004 Compared to Third Quarter 2003

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

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

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

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

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

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

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

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

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

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

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

 

NON-UTILITY NUCLEAR

Following are key performance measures for Non-Utility Nuclear for the third quarter and nine months ended September 30, 2004 and 2003:

 

 

Third Quarter

 

Nine Months Ended

 

 

2004

 

2003

 

2004

 

2003

 

 

 

 

 

 

 

 

 

Net MW in operation at September 30

 

4,001

 

4,001

 

4,001

 

4,001

Generation in GWh for the period

 

8,075

 

8,246

 

24,957

 

23,676

Capacity factor for the period

 

91.6%

 

93.6%

 

94.7%

 

90.5%

Average realized price per MWh

 

$43.38

 

$40.96

 

$41.43

 

$39.69

Third Quarter 2004 Compared to Third Quarter 2003

The increase in earnings for Non-Utility Nuclear from $59.6 million to $63.7 million was primarily due to miscellaneous income resulting from a reduction in the decommissioning liability for a plant, as discussed in Note 1 to the consolidated financial statements. Also contributing to the increase were increased revenues due to higher contract pricing and the addition of a support services contract for the Cooper Nuclear Station, partially offset by lower generation due to planned and unplanned outages during the third quarter of 2004. Partially offsetting the increase in earnings were higher operation and maintenance expenses, which increased by $9 million, primarily due to higher benefits costs.

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

The decrease in earnings for Non-Utility Nuclear from $301.5 million to $195.5 million was primarily due to the $160.3 million net-of-tax cumulative effect of a change in accounting principle that increased earnings in the first quarter of 2003 upon implementation of SFAS 143. See Note 9 to the consolidated financial statements in the Form 10-K for further discussion of the implementation of SFAS 143. Earnings before the cumulative effect of accounting change increased by $54.3 million. The increase was due to higher revenues, which increased by $94 million, resulting from increased generation in 2004 due to fewer planned and unplanned outages in 2004 and power uprates completed in 2003, higher contract pricing, and the addition of a support services contract for the Cooper Nuclear Station. Miscellaneous income from the reduction in decommissioning liability mentioned above and lower operation and maintenance expenses, which decreased by $17 million, also contributed to the increase in earnings before the cumulative effect of accounting change. Partially offsetting this increase was higher depreciation expense, which increased by $9 million.

ENERGY COMMODITY SERVICES

Sales of Entergy-Koch Businesses

On November 1, 2004, Entergy-Koch sold its energy trading business to Merrill Lynch & Co. The sale came after a review of strategic alternatives for enhancing the value of Entergy-Koch, LP. After the strategic review, Entergy concluded that Entergy-Koch's trading business would be more valuable if owned by a third party. Entergy and Koch Industries have also commenced a competitive process to sell the Gulf South Pipeline, which management expects to conclude in the first half of 2005.

Entergy expects to receive its share of sale proceeds from the Entergy-Koch energy trading business sale as well as the planned sale of Gulf South Pipeline as cash distributions from Entergy-Koch over a time period from the closings on such sales through 2006, with the majority of the distributions occurring in 2005. Entergy expects the Entergy-Koch business sales to ultimately result in net cash distributions to Entergy of approximately $1 billion, comprised of the after-tax cash from the distributions of the sale proceeds and the eventual liquidation of Entergy-Koch. Entergy will account for these cash distributions as reductions of Entergy's approximately $1 billion equity investment in Entergy-Koch, its unconsolidated affiliate. Entergy's equity investment includes its cash investments in Entergy-Koch, the value of its assets contributed to Entergy-Koch, the earnings and losses recorded from its investment in Entergy-Koch, including disproportionate income sharing, less dividends received from Entergy-Koch.

The estimated amount of net cash distributions to Entergy may vary depending on the results of the competitive process to sell Gulf South Pipeline. When the results of this competitive process are determined, management will revise the estimated net cash distributions and will compare them to Entergy's equity investment to determine whether book gain or loss exists. If an impairment in Entergy's investment occurs, Entergy will record the impairment loss at that time. If management expects a net gain, Entergy will not record the gain until it is realized. Management does not currently expect Entergy to experience a significant gain or loss from the sales of Entergy-Koch's businesses and Entergy-Koch's subsequent liquidation.

Results of Operations

Following are key performance measures for Entergy-Koch's operations for the third quarter and nine months ended September 30, 2004 and 2003:

 

 

 

Third Quarter

 

Nine Months Ended

 

 

 

2004

 

2003

 

2004

 

2003

Entergy-Koch Trading

 

 

 

 

 

 

 

 

 

  Gas volatility

 

 

41%

 

39%

 

42%

 

62%

  Electricity volatility

 

 

36%

 

34%

 

34%

 

62%

  Gas marketed (BCF/D)

 

 

5.4

 

5.8

 

5.8

 

6.3

  Electricity marketed (GWh)

 

 

82,858

 

105,184

 

289,206

 

329,528

  Gain/loss days

 

 

0.9

 

1.7

 

1.3

 

1.5

Gulf South Pipeline

 

 

 

 

 

 

 

 

 

  Throughput (BCF/D)

 

 

1.76

 

1.84

 

1.96

 

1.98

  Production cost ($/MMBtu)

 

 

$0.167

 

$0.171

 

$0.160

 

$0.137

Third Quarter 2004 Compared to Third Quarter 2003

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

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

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

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

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

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

Income Taxes

The effective income tax rates for the third quarters of 2004 and 2003 were 37.8% and 37.3%, respectively. The effective income tax rates for the nine months ended September 30, 2004 and 2003 were 36.7% and 37.6%, respectively. The decrease in the effective income tax rate for the nine months ended September 30, 2004 is primarily due to the favorable settlement of various tax audit issues and higher pre-tax income in 2003 decreasing the effect of flow-through and permanent differences. The favorable settlement is reported in Parent and Other and is the primary reason for the increase in earnings for that part of Entergy's business in 2004.

Liquidity and Capital Resources

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

Capital Structure

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

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

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

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

Capital Expenditure Plans and Other Uses of Capital

See the table in the Form 10-K under "Liquidity and Capital Resources - Capital Expenditure Plans and Other Uses of Capital," which sets forth the amounts of Entergy's planned construction and other capital investments by operating segment for 2004 through 2006. Entergy Louisiana now expects to complete the purchase of the Perryville plant in mid-2005 for $183.5 million. Therefore, Entergy now expects to spend approximately $385 million for Capital Commitments in the U.S. Utility segment in 2004 and approximately $479 million for Capital Commitments in the U.S. Utility segment in 2005-2006.

Dividends and Stock Repurchases

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

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

Cash Flow Activity

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

 

 

2004

 

2003

 

 

(In Millions)

 

 

 

 

 

Cash and cash equivalents at beginning of period

 

$692 

 

$1,335 

 

 

 

 

 

Cash flow provided by (used in):

 

 

 

 

 

Operating activities

 

1,714 

 

1,176 

 

Investing activities

 

(1,082)

 

(1,552)

 

Financing activities

 

(735)

 

(383)

Effect of exchange rates on cash and cash equivalents

 

(1)

 

Net decrease in cash and cash equivalents

 

(104)

 

(757)

 

 

 

 

 

Cash and cash equivalents at end of period

 

$588 

 

$578 

Operating Activities

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

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

Investing Activities

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

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

Financing Activities

Net cash used in financing activities increased by $352 million for the nine months ended September 30, 2004 compared to the nine months ended September 30, 2003 primarily due to the following:

    • Entergy Corporation issued $383 million of long-term notes in 2003.
    • Entergy Corporation repurchased $416 million of its common stock in 2004. In addition to the share repurchase program discussed above, and as discussed in the Form 10-K, in accordance with Entergy's stock option plans, Entergy periodically grants stock options to its employees, which may be exercised to obtain shares of Entergy's common stock. According to the plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy's management has been authorized to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans.
    • Entergy Corporation paid $45 million more in common stock dividends in 2004 than in 2003. As discussed in the Form 10-K, at its July 2003 meeting the Board increased Entergy's quarterly common stock dividend per share by 29%, to $0.45.

Offsetting the factors that caused an increase in cash used in financing activities in 2004 were the following:

    • Retirements of long-term debt net of issuances by the U.S. Utility segment used $334 million in 2004 and used $360 million in 2003. See Note 4 to the consolidated financial statements for the details of the long-term debt activity in 2004.
    • In 2004, Entergy Corporation borrowed $100 million on its 364-day credit facility, Entergy Arkansas borrowed $85 million on its credit facility, and Entergy Mississippi borrowed $25 million on its credit facility. In 2003, Entergy Corporation had decreased the net borrowings on its credit facility by $130 million.
    • The non-nuclear wholesale asset business retired the $79 million Top of Iowa wind project debt at its maturity in January 2003.

Significant Factors and Known Trends

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.

Rate Regulation and Fuel-Cost Recovery

See the Form 10-K for the chart summarizing material rate proceedings. Following are updates to that chart.

Base rates in Entergy Gulf States' Texas jurisdiction are currently set at rates approved by the PUCT in June 1999. As further discussed below in "Utility Restructuring, Retail-Texas," in July 2004 the PUCT issued a written order that continued the delay in retail open access in Entergy Gulf States' Texas service territory. Entergy Gulf States filed a rate case and a fuel reconciliation proceeding with the PUCT in August 2004. Entergy Gulf States' fuel reconciliation filing made in conjunction with the base rate case seeks to reconcile approximately $288 million in fuel and purchased power costs incurred during the period September 2003 through March 2004. In October 2004, the PUCT issued a written order in which it dismissed the rate case indicating that Entergy Gulf States is still subject to a rate freeze based on an agreement in 2001 stipulating that a rate freeze would remain in effect until retail open access commenced in Entergy Gulf States' service territory. Entergy Gulf States intends to file a motion for rehearing and intends to pursue other available remedies. Refer to Note 2 to the consolidated financial statements for further information on the base rate and fuel reconciliation filings with the PUCT.

See the Form 10-K for discussion of Entergy Louisiana's rate filing with the LPSC requesting a base rate increase. In August 2004, the LPSC Staff filed testimony in which it recommended up to a $19.5 million rate increase for Entergy Louisiana, assuming that the Perryville acquisition is approved in time for the Perryville costs to be included in rates set in this proceeding. Additional issues and updates that will be evaluated in connection with this proceeding are likely to result in revisions to the LPSC Staff's recommendation.  These issues may reduce the amount of the recommended rate increase or cause it to become a recommendation for a rate decrease. Hearings are currently set for December 2004.

Entergy Mississippi made its formula rate plan filing with the MPSC in March 2004 based on a 2003 test year. In April 2004, the MPSC approved a joint stipulation between the Mississippi Public Utilities Staff and Entergy Mississippi that provides for no change in rates based on an adjusted return on common equity midpoint of 10.77%, establishing an allowed annual regulatory earnings range of 9.5% to 12.1%.

In April 2004, Entergy New Orleans made filings with the City Council as required by the earnings review process prescribed by the Gas and Electric Formula Rate Plans approved by the Council in 2003. In August 2004, the City Council approved an unopposed settlement among Entergy New Orleans, the Council Advisors, and the intervenors in connection with the Gas and Electric Formula Rate Plans. In accordance with the resolution approving the settlement agreement, Entergy New Orleans' gas and electric base rates remain unchanged from levels set in May 2003.

In June 2004, Entergy Gulf States and Entergy Louisiana filed a proposed settlement with the LPSC that would resolve, among other dockets, Entergy Gulf States' ninth post-merger analysis and dockets established to consider issues concerning the companies' power purchases for the summers of 2001, 2002, and 2003. The proposed settlement included an offer to refund approximately $64 million to Entergy Gulf States' Louisiana customers and $1 million to Entergy Louisiana's customers, with no change in either company's current base rates.  The settlement also proposed a formula rate plan for Entergy Gulf States' Louisiana operations. At its September 2004 Business and Executive Session, the LPSC consolidated various dockets that were the subject of the proposed settlement. The LPSC directed its staff to preside over settlement discussions and to submit any proposed settlement to the LPSC for its consideration.

System Agreement Litigation

See the Form 10-K for a discussion of the proceeding commenced at the FERC by the LPSC regarding production cost equalization under the System Agreement, the ALJ's Initial Decision in the proceeding, and the "Order of Investigation" issued by the APSC. Several parties, including Entergy, the LPSC, the APSC, the MPSC, the City Council, and the FERC Staff, filed briefs on exceptions in response to the ALJ's Initial Decision. Entergy's exceptions to the ALJ's Initial Decision include: the practical effect of the Initial Decision is full production cost equalization, which was rejected in the Initial Decision and previously has been rejected by the FERC; resource planning for the Entergy System would be impeded if the Initial Decision were adopted; the remedy in the Initial Decision is inconsistent with the history, structure, and precedent regarding the System Agreement; the Initial Decision's remedy ignores the historical pattern of production cost disparities on the Entergy System and would result in substantial, sudden transfers of costs between groups of Entergy customers; the numerical standards proposed in the Initial Decision are arbitrary and are so complex that they will be difficult to implement; the Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the full costs of the Vidalia project should be included in Entergy Louisiana's production costs for purposes of calculating relative production costs; and the Initial Decision erroneously adopted a new method of calculating reserve sharing costs rather than the current method.

As reported in the Form 10-K, if the FERC grants the relief requested by the LPSC in the proceeding, the relief may result in a material increase in the total production costs the FERC allocates to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in the total production costs the FERC allocates to companies whose costs currently are projected to exceed that average.   If the FERC adopts the ALJ's Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of Entergy System average total production cost. The ALJ's Initial Decision would reallocate production costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth. This would be accomplished by payments from domestic utility companies whose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost.

An assessment of the potential effects of the ALJ's Initial Decision requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power.  Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation.  Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas' total production costs are below the average production costs of the domestic utility companies.  Considerable uncertainty exists regarding future gas prices. Annual average gas prices have varied significantly over recent years, ranging from $1.92/mmBtu to $5.48/mmBtu for the 1994-2003 period, and averaging $2.99/mmBtu during the ten-year period 1994-2003 and $3.77/mmBtu during the five-year period 1999-2003.  Recent market conditions have resulted in gas prices that have averaged $5.58/MMBtu for the twelve months ended September 2004. Based upon analyses considering the effect on future production costs if the FERC adopts the ALJ's Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could result assuming annual average gas prices range from $6.39/mmBtu in 2005 declining to $4.97/mmBtu by 2009:

 


Range of Annual Payments or (Receipts)

 

Average Annual Payments or (Receipts) for 2005-2009 Period

 

(In Millions)

 

(In Millions)

       

Entergy Arkansas

$154 to $281 

 

$215 

Entergy Gulf States

($130) to ($15)

 

($63)

Entergy Louisiana

($199) to ($98)

 

($141)

Entergy Mississippi

($16) to $8 

 

$1 

Entergy New Orleans

($17) to ($5)

 

($12)

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

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

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

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

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

Market and Credit Risks

Commodity Price Risk

Power Generation

As discussed more fully in the Form 10-K, the sale of electricity from the power generation plants owned by Entergy's Non-Utility Nuclear business and Energy Commodity Services, unless otherwise contracted, is subject to the fluctuation of market power prices. Following is an updated summary of the amount of Non-Utility Nuclear's output that is sold forward as of September 30, 2004 under physical or financial contracts at fixed prices (2004 represents the remainder of the year):

 

 

2004

 

2005

 

2006

 

2007

 

2008

Non-Utility Nuclear:

 

 

 

 

 

 

 

 

 

% of planned generation sold forward

100%

 

93%

 

66%

 

39%

 

17%

Planned generation (TWh)

8

 

34

 

35

 

34

 

34

Average contracted price per MWh

$38

 

$39

 

$39

 

$39

 

$40

The Vermont Yankee acquisition included a 10-year PPA under which the former owners will buy the power produced by the plant, which is through the expiration in 2012 of the current operating license for the plant. The PPA includes an adjustment clause under which the prices specified in the PPA will be adjusted downward monthly, beginning in November 2005, if power market prices drop below PPA prices. Accordingly, because the price is not fixed, the table above does not report power from that plant as sold forward after October 2005. Approximately 2% of Non-Utility Nuclear's planned generation in 2005, 13% in 2006, 12% in 2007, and 12% in 2008 is under contract from Vermont Yankee after October 2005.

Some of the agreements to sell the power produced by Entergy's Non-Utility Nuclear power plants contain provisions that require an Entergy subsidiary to provide collateral to secure its obligations under the agreements. The Entergy subsidiary may be required to provide collateral based upon the difference between the current market and contracted power prices in the regions where the Non-Utility Nuclear business sells its power.  The primary form of the collateral to satisfy these requirements would be an Entergy Corporation guaranty. Cash and letters of credit are also acceptable forms of collateral. At September 30, 2004, based on power prices at that time, Entergy had in place as collateral $458 million of Entergy Corporation guarantees and $20 million of letters of credit. Upon a significant decrease in Entergy Corporation's credit rating to specified levels below investment grade, Entergy may be required to replace Entergy Corporation guarantees with cash or letters of credit under some of the agreements.

 

In addition to selling the power produced by its plants, the Non-Utility Nuclear business sells installed capacity to load-serving distribution companies in order for those companies to meet requirements placed on them by the Independent System Operators in their area. Following is an updated summary of the amount of the Non-Utility Nuclear business' installed capacity that is sold forward, and the blended amount of the Non-Utility Nuclear business' planned generation output and installed capacity that is currently sold forward, as of September 30, 2004:

 

 

2004

 

2005

 

2006

 

2007

 

2008

Non-Utility Nuclear:

 

 

 

 

 

 

 

 

 

 

Percent of capacity sold forward:

 

 

 

 

 

 

 

 

 

 

 

Bundled capacity and energy contracts

 

55%

 

16%

 

13%

 

13%

 

13%

 

Capacity contracts

 

41%

 

47%

 

32%

 

13%

 

0%

 

Total

 

96%

 

63%

 

45%

 

26%

 

13%

Planned MW in operation

 

4,061

 

4,158

 

4,203

 

4,203

 

4,203

Average capacity contract price per kW per month

 

$0.5

 

$1.3

 

$1.2

 

$1.3

 

N/A

Blended Capacity and Energy (based on revenues)

 

 

 

 

 

 

 

 

 

 

% of planned energy and capacity sold forward

 

99%

 

93%

 

73%

 

45%

 

26%

Average contract revenue per MWh

 

$39

 

$40

 

$39

 

$39

 

$40

Utility Restructuring

Transmission

See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Significant Factors and Known Trends, Transmission" in the Form 10-K for discussion of Entergy's contemplated independent transmission entity proposal. In April 2004, Entergy filed a proposal with the FERC to commit voluntarily to retain an independent entity ("Independent Coordinator of Transmission" or "ICT") to oversee the granting of transmission or interconnection service on Entergy's transmission system, to implement a transmission pricing structure that ensures that Entergy's retail native load customers are required to pay for only those upgrades necessary to reliably serve their needs, and to have the ICT serve as the security coordinator for the Entergy region. Assuming applicable regulatory support and approvals can be obtained, Entergy proposes to contract with the ICT to oversee the granting of transmission service on the Entergy system as well as the implementation of the proposed weekly procurement process. The proposal was structured to not transfer control of Entergy's transmission system to the ICT, but rather to vest with the ICT broad oversight authority over transmission planning and operations.

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

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

FERC's Supply Margin Assessment

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

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

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

In a companion order, the FERC initiated a rulemaking proceeding to address, among other things, whether the FERC should retain or modify its existing four-prong test for evaluating market-based rate applications (i.e., whether the applicant has generation or transmission market power, whether the applicant can erect barriers to entry, and whether there are affiliate abuse or reciprocal dealing concerns), and whether the FERC should adopt different approaches for affiliate transactions. Initially, the FERC will hold a series of technical conferences to determine the issues that need to be considered and the procedural direction the rulemaking should take. The first of these technical conferences was held in June 2004. In October 2004, the FERC also issued a proposed rule to standardize and clarify the reporting requirements when a market-based rate seller has a change in status, such as changes in ownership or control of generation or transmission facilities or changes in certain affiliate relationships. Comments on the proposed rule are currently due in November 2004.

Interconnection Orders

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

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

Retail-Texas

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

Nuclear Matters

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

Critical Accounting Estimates

See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates" in the Form 10-K for a discussion of the estimates and judgments necessary in Entergy's accounting for nuclear decommissioning costs, impairment of long-lived assets, mark-to-market derivative instruments, pension and other postretirement costs, and other contingencies.

New Accounting Pronouncements

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

 

ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
           
                 
    Three Months Ended   Nine Months Ended
    2004   2003   2004   2003
    (In Thousands, Except Share Data)
                 
OPERATING REVENUES                
Domestic electric   $2,389,276    $2,235,618    $6,042,652    $5,763,298 
Natural gas   33,628    25,866    155,591    139,803 
Competitive businesses   540,677    438,641    1,501,985    1,188,659 
TOTAL   2,963,581    2,700,125    7,700,228    7,091,760 
                 
OPERATING EXPENSES                
Operating and Maintenance:                
  Fuel, fuel-related expenses, and                
   gas purchased for resale   805,886    596,046    1,844,381    1,480,101 
  Purchased power   598,997    541,308    1,603,957    1,359,273 
  Nuclear refueling outage expenses   43,378    40,154    124,084    119,298 
  Provision for turbine commitments, asset impairments,                
   and restructuring charges         (7,743)
  Other operation and maintenance   582,240    542,601    1,651,239    1,629,716 
Decommissioning   37,747    35,929    113,192    107,787 
Taxes other than income taxes   112,568    105,360    313,153    303,601 
Depreciation and amortization   236,325    220,667    662,614    637,159 
Other regulatory charges (credits) - net   (25,032)   (945)   (57,009)   18,581 
TOTAL   2,392,109    2,081,120    6,255,611    5,647,773 
                 
OPERATING INCOME   571,472    619,005    1,444,617    1,443,987 
                 
OTHER INCOME                
Allowance for equity funds used during construction   13,093    9,936    28,572    26,962 
Interest and dividend income   20,993    24,040    75,067    83,792 
Equity in earnings (loss) of unconsolidated equity affiliates   (72,015)   60,099    (31,908)   258,451 
Miscellaneous - net   41,254    7,932    59,993    (83,904)
TOTAL   3,325    102,007    131,724    285,301 
                 
INTEREST AND OTHER CHARGES                
Interest on long-term debt   113,489    123,169    349,160    367,550 
Other interest - net   6,879    13,345    26,657    42,636 
Allowance for borrowed funds used during construction   (8,394)   (7,968)   (18,519)   (21,136)
TOTAL   111,974    128,546    357,298    389,050 
                 
INCOME BEFORE INCOME TAXES AND                
CUMULATIVE EFFECT OF ACCOUNTING CHANGES   462,823    592,466    1,219,043    1,340,238 
                 
Income taxes   174,776    220,816    446,968    499,068 
                 
INCOME BEFORE CUMULATIVE EFFECT                
OF ACCOUNTING CHANGES   288,047    371,650    772,075    841,170 
                 
CUMULATIVE EFFECT OF ACCOUNTING                
CHANGES (net of income taxes of $93,754)         142,922 
                 
CONSOLIDATED NET INCOME   288,047    371,650    772,075    984,092 
                 
Preferred dividend requirements and other   5,803    5,876    17,488    17,669 
                 
EARNINGS APPLICABLE TO                
COMMON STOCK   $282,244    $365,774    $754,587    $966,423 
                 
Earnings per average common share before cumulative                
effect of accounting changes:                
  Basic   $1.24    $1.60    $3.30    $3.64 
  Diluted   $1.22    $1.57    $3.24    $3.57 
Earnings per average common share:                
  Basic   $1.24    $1.60    $3.30    $4.27 
  Diluted   $1.22    $1.57    $3.24    $4.19 
Dividends declared per common share   $0.45    $0.45    $1.35    $1.15 
                 
Average number of common shares outstanding:                
  Basic   226,882,474    228,105,505    228,614,245    226,145,567 
  Diluted   231,127,583    232,515,434    232,863,075    230,388,260 
                 
See Notes to Consolidated Financial Statements.                

 

ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2004 and 2003
(Unaudited)
         
    2004   2003
    (In Thousands)
   
OPERATING ACTIVITIES        
Consolidated net income   $772,075    $984,092 
Noncash items included in net income:        
  Reserve for regulatory adjustments   5,559    (9,806)
  Other regulatory charges (credits) - net   (57,009)   18,581 
  Depreciation, amortization, and decommissioning   775,806    744,946 
  Deferred income taxes and investment tax credits   146,636    999,496 
  Cumulative effect of accounting changes     (142,922)
  Equity in undistributed earnings (loss) of unconsolidated equity affiliates   58,191    (179,253)
  Provision for turbine commitments, asset impairments, and restructuring charges     (7,743)
Changes in working capital:        
  Receivables   (342,935)   (327,439)
  Fuel inventory   (20,709)   (28,101)
  Accounts payable   (14,785)   (282,127)
  Taxes accrued   314,741    (548,941)
  Interest accrued   14,024    (15,387)
  Deferred fuel   180,425    (58,505)
  Other working capital accounts   (7,383)   (20,785)
Provision for estimated losses and reserves   (14,921)   130,444 
Changes in other regulatory assets   8,354    23,460 
Other   (104,404)   (103,930)
Net cash flow provided by operating activities   1,713,665    1,176,080 
         
INVESTING ACTIVITIES        
Construction/capital expenditures   (944,812)   (1,051,649)
Allowance for equity funds used during construction   28,572    26,962 
Nuclear fuel purchases   (152,082)   (190,243)
Proceeds from sale/leaseback of nuclear fuel   74,779    119,174 
Proceeds from sale of assets and businesses   21,978    25,987 
Investment in non-utility properties   (20,132)   (47,733)
Increase in other investments   (11,340)   (171,045)
Changes in other temporary investments   50,000    (15,602)
Decommissioning trust contributions and realized change in trust assets   (65,996)   (65,754)
Other regulatory investments   (62,531)   (174,163)
Other     (8,643)
Net cash flow used in investing activities   (1,081,564)   (1,552,709)
         
See Notes to Consolidated Financial Statements.        
         
 
 
ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2004 and 2003
(Unaudited)
         
    2004   2003
    (In Thousands)
         
FINANCING ACTIVITIES        
Proceeds from the issuance of:        
  Long-term debt   345,356    2,067,393 
  Common stock and treasury stock   140,345    198,466 
Retirement of long-term debt   (689,266)   (2,238,430)
Repurchase of common stock   (416,269)  
Redemption of preferred stock   (3,450)   (3,450)
Changes in credit line borrowings - net   209,925    (130,000)
Dividends paid:        
  Common stock   (304,509)   (259,854)
  Preferred stock   (17,488)   (17,669)
Net cash flow used in financing activities   (735,356)   (383,544)
         
Effect of exchange rates on cash and cash equivalents   (1,137)   2,389 
         
Net decrease in cash and cash equivalents   (104,392)   (757,784)
         
Cash and cash equivalents at beginning of period   692,233    1,335,328 
         
Cash and cash equivalents at end of period   $587,841    $577,544 
         
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:        
Cash paid during the period for:        
  Interest - net of amount capitalized   $346,138    $409,518 
  Income taxes   $32,802    $180,390 
         
See Notes to Consolidated Financial Statements.        

 

ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2004 and December 31, 2003
(Unaudited)
         
    2004   2003
    (In Thousands)
         
CURRENT ASSETS        
Cash and cash equivalents:        
  Cash   $124,346    $115,112 
  Temporary cash investments - at cost,        
   which approximates market   463,495    576,813 
  Special deposits   -    308 
     Total cash and cash equivalents   587,841    692,233 
Other temporary investments   -    50,000 
Notes receivable   2,110    1,730 
Accounts receivable:        
  Customer   614,717    398,091 
  Allowance for doubtful accounts   (24,983)   (25,976)
  Other   284,758    246,824 
  Accrued unbilled revenues   471,785    384,860 
    Total receivables   1,346,277    1,003,799 
Deferred fuel costs   128,079    245,973 
Accumulated deferred income taxes   53,422    - 
Fuel inventory - at average cost   131,191    110,482 
Materials and supplies - at average cost   567,001    548,921 
Deferred nuclear refueling outage costs   102,242    138,836 
Prepayments and other   171,097    127,270 
TOTAL   3,089,260    2,919,244 
         
OTHER PROPERTY AND INVESTMENTS        
Investment in affiliates - at equity   1,141,060    1,053,328 
Decommissioning trust funds   2,379,555    2,278,533 
Non-utility property - at cost (less accumulated depreciation)   222,942    262,384 
Other   97,153    152,681 
TOTAL   3,840,710    3,746,926 
         
PROPERTY, PLANT AND EQUIPMENT        
Electric   28,761,055    28,035,899 
Property under capital lease   740,397    751,815 
Natural gas   255,280    236,622 
Construction work in progress   1,276,917    1,380,982 
Nuclear fuel under capital lease   262,840    278,683 
Nuclear fuel   281,706    234,421 
TOTAL PROPERTY, PLANT AND EQUIPMENT   31,578,195    30,918,422 
Less - accumulated depreciation and amortization   13,099,440    12,619,625 
PROPERTY, PLANT AND EQUIPMENT - NET   18,478,755    18,298,797 
         
DEFERRED DEBITS AND OTHER ASSETS        
Regulatory assets:        
  SFAS 109 regulatory asset - net   804,336    830,539 
  Other regulatory assets   1,359,820    1,425,145 
Long-term receivables   41,536    20,886 
Goodwill   377,172    377,172 
Other   946,340    935,501 
TOTAL   3,529,204    3,589,243 
         
TOTAL ASSETS   $28,937,929    $28,554,210 
         
See Notes to Consolidated Financial Statements.        
 
 
 
ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
September 30, 2004 and December 31, 2003
(Unaudited)
         
    2004   2003
    (In Thousands)
         
CURRENT LIABILITIES        
Currently maturing long-term debt   $429,481    $524,372 
Notes payable   110,273    351 
Accounts payable   786,437    796,572 
Customer deposits   214,989    199,620 
Taxes accrued    231,326    224,926 
Accumulated deferred income taxes   -     22,963 
Nuclear refueling outage costs   18,126    8,238 
Interest accrued   153,233    139,603 
Obligations under capital leases   154,620    159,978 
Other    299,976    205,600 
TOTAL   2,398,461    2,282,223 
         
NON-CURRENT LIABILITIES        
Accumulated deferred income taxes and taxes accrued   5,242,297    4,779,513 
Accumulated deferred investment tax credits   404,481    420,248 
Obligations under capital leases   138,296    153,898 
Other regulatory liabilities   334,716    291,239 
Decommissioning and retirement cost liabilities   2,064,542    2,242,312 
Transition to competition   79,101    79,098 
Regulatory reserves   75,087    69,528 
Accumulated provisions   492,434    506,960 
Long-term debt   7,219,611    7,322,940 
Preferred stock with sinking fund   17,402    20,852 
Other   1,296,575    1,347,404 
TOTAL   17,364,542    17,233,992 
         
Preferred stock without sinking fund   334,337    334,337 
         
SHAREHOLDERS' EQUITY        
Common stock, $.01 par value, authorized 500,000,000        
 shares; issued 248,174,087 shares in 2004 and in 2003   2,482    2,482 
Paid-in capital   4,818,848    4,767,615 
Retained earnings   4,948,690    4,502,508 
Accumulated other comprehensive loss   (68,337)   (7,795)
Less - treasury stock, at cost (22,928,539 shares in 2004 and        
 19,276,445 shares in 2003)   861,094    561,152 
TOTAL   8,840,589    8,703,658 
         
Commitments and Contingencies        
         
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY   $28,937,929    $28,554,210 
         
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 Nine Months Ended September 30, 2004 and 2003
(Unaudited)
                     
        Three Months Ended
         
        2004   2003
        (In Thousands)
RETAINED EARNINGS                    
Retained Earnings - Beginning of period       $4,768,336        $4,382,757     
  Add - Earnings applicable to common stock       282,244    $282,244    365,774    $365,774 
  Deduct:                    
    Dividends declared on common stock       102,196        102,611     
    Capital stock and other expenses       (306)       1,040     
      Total       101,890        103,651     
Retained Earnings - End of period       $4,948,690        $4,644,880     
                     
ACCUMULATED OTHER COMPREHENSIVE                    
INCOME (LOSS) (Net of Taxes):                    
Balance at beginning of period                    
  Accumulated derivative instrument fair value changes       ($119,541)       $17,490     
  Other accumulated comprehensive income (loss) items       24,340        (10,937)    
     Total       (95,201)       6,553     
                     
Net derivative instrument fair value changes                    
 arising during the period       20,005    20,005    (874)   (874)
                     
Foreign currency translation adjustments       (1,264)   (1,264)   1,539    1,539 
                     
Net unrealized investment gains (losses)       8,123    8,123    (10,983)   (10,983)
                     
Balance at end of period:                    
  Accumulated derivative instrument fair value changes       ($99,536)       $16,616     
  Other accumulated comprehensive income (loss) items       31,199        (20,381)    
     Total       ($68,337)       ($3,765)    
Comprehensive Income           $309,108        $355,456 
                     
PAID-IN CAPITAL                    
Paid-in Capital - Beginning of period       $4,819,044        $4,690,152     
  Add: Common stock issuances related to stock plans       (196)       6,446     
Paid-in Capital - End of period       $4,818,848        $4,696,598     
                     
                     
                     
                     
        Nine Months Ended
        2004   2003
        (In Thousands)
RETAINED EARNINGS                    
Retained Earnings - Beginning of period       $4,502,508        $3,938,693     
  Add - Earnings applicable to common stock       754,587    $754,587    966,423    $966,423 
  Deduct:                    
    Dividends declared on common stock       308,416        259,955     
    Capital stock and other expenses       (11)       281     
     Total       308,405        260,236     
Retained Earnings - End of period       $4,948,690        $4,644,880     
                     
ACCUMULATED OTHER COMPREHENSIVE                    
INCOME (LOSS) (Net of Taxes):                    
Balance at beginning of period                    
  Accumulated derivative instrument fair value changes       ($25,811)       $17,313     
  Other accumulated comprehensive income (loss) items       18,016        (39,673)    
     Total       (7,795)       (22,360)    
                     
Net derivative instrument fair value changes                    
 arising during the period       (73,725)   (73,725)   (697)   (697)
                     
Foreign currency translation adjustments       1,137    1,137    3,249    3,249 
                     
Net unrealized investment gains (losses)       12,046    12,046    16,043    16,043 
                     
Balance at end of period:                    
  Accumulated derivative instrument fair value changes       ($99,536)       $16,616     
  Other accumulated comprehensive income (loss) items       31,199        (20,381)    
     Total       ($68,337)       ($3,765)    
Comprehensive Income           $694,045        $985,018 
                     
PAID-IN CAPITAL                    
Paid-in Capital - Beginning of period       $4,767,615        $4,666,753     
  Add: Common stock issuances related to stock plans       51,233        29,845     
Paid-in Capital - End of period       $4,818,848        $4,696,598     
                     
                     
See Notes to Consolidated Financial Statements.                    

 

ENTERGY CORPORATION AND SUBSIDIARIES
SELECTED OPERATING RESULTS
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
 
                 
    Three Months Ended   Increase/    
Description   2004   2003   (Decrease)   %
    (In Millions)    
Electric Operating Revenues:                
  Residential   $979    $928   $51    5 
  Commercial    616    561   55    10 
  Industrial   637    566   71    13 
  Governmental   57    56   1    2 
     Total retail   2,289    2,111   178    8 
  Sales for resale   102    102   -    - 
  Other   (2)   23   (25)   (109)
     Total   $2,389    $2,236   $153    7 
                 
Billed Electric Energy                
 Sales (GWh):                
  Residential   10,738    10,763   (25)   - 
  Commercial   7,753    7,539   214    3 
  Industrial   10,456    9,975   481    5 
  Governmental   714    737   (23)   (3)
     Total retail   29,661    29,014   647    2 
  Sales for resale   2,040    2,093   (53)   (3)
     Total   31,701    31,107   594    2 
                 
                 
    Nine Months Ended   Increase/    
Description   2004   2003   (Decrease)   %
    (In Millions)    
Electric Operating Revenues:                
  Residential   $2,191   $2,111   $80    4 
  Commercial   1,530   1,427   103    7 
  Industrial   1,710   1,562   148    9 
  Governmental   150   152   (2)   (1)
     Total retail   5,581   5,252   329    6 
  Sales for resale   305   303   2    1 
  Other   157   208   (51)   (25)
     Total   $6,043   $5,763   $280    5 
                 
Billed Electric Energy                
 Sales (GWh):                
  Residential   25,375   25,776   (401)   (2)
  Commercial   19,860   19,525   335    2 
  Industrial   29,868   28,855   1,013    4 
  Governmental   1,924   2,033   (109)   (5)
     Total retail   77,027   76,189   838    1 
  Sales for resale   6,825   7,196   (371)   (5)
     Total   83,852   83,385   467    1 
                 
                 

 

ENTERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1. COMMITMENTS AND CONTINGENCIES

Sales Warranties and Indemnities

See Notes 9 and 14 to the consolidated financial statements in the Form 10-K for information on certain warranties made by Entergy or its subsidiaries in the Saltend sales transaction. Entergy has now reached an agreement with the purchasers that resolves its potential liability on the warranties.

Nuclear Insurance and Spent Nuclear Fuel

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 associated with Entergy's nuclear power plants.

The Property Insurance Policy was renewed on April 1, 2004 with the following changes: 1) the deductibles for Indian Point 2 and 3 (each unit has a separate parameter), FitzPatrick, Pilgrim, and Vermont Yankee increased to $2.5 million per occurrence for other than turbine/generator damage; and 2) the deductibles for ANO 1 and 2, Grand Gulf 1, River Bend, and Waterford 3 increased to $5 million per occurrence for turbine/generator damage and $5 million per occurrence for other than turbine/generator damage.

Under Nuclear Electric Insurance Limited's (NEIL) Accidental Outage Coverage program, FitzPatrick's and Pilgrim's weekly indemnity decreased to $4 million and Vermont Yankee's weekly indemnity decreased to $3.5 million.

Under the property damage and accidental outage insurance programs, Entergy's nuclear plants could be subject to assessments should losses exceed the accumulated funds available from NEIL. As of September 30, 2004, the maximum amount of such possible assessments per occurrence was $68.9 million for the Non-Utility Nuclear plants and $50.8 million for the U.S. Utility plants.

Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are responsible for their own spent fuel storage. Current on-site spent fuel storage capacity at Grand Gulf I, River Bend, and Waterford 3 is estimated to be sufficient until approximately 2007, 2005, and 2012, respectively, at which time dry cask storage facilities will be placed into service. An ANO storage facility using dry casks began operation in 1996, has been expanded since, and will be further expanded as needed. The spent fuel storage capacity at Pilgrim is licensed to provide enough storage capacity until approximately 2012. The first dry spent fuel storage casks were loaded at FitzPatrick in 2002, and further casks will be loaded there as needed. Indian Point and Vermont Yankee currently have sufficient spent fuel storage capacity until approximately 2006, at which time management expects planned dry cask storage capacity to begin operation.

Nuclear Decommissioning Costs

See Note 9 to the consolidated financial statements in the Form 10-K for information on nuclear decommissioning costs. 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. 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 an increase in earnings in 2003 of approximately $155 million net-of-tax ($0.67 per share) as a result of a one-time cumulative effect of accounting change.

In accordance with a new decommissioning cost study for ANO 1 and 2, in the first quarter of 2004 Entergy Arkansas recorded a revision to its estimated decommissioning cost liability. The revised estimate resulted in a $107.7 million reduction in its decommissioning liability, along with a $19.5 million reduction in utility plant and an $88.2 million reduction in the related regulatory asset.

In the third quarter of 2004, Entergy Gulf States recorded a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for River Bend that reflected a life extension for the plant. The revised estimate resulted in a $116.8 million reduction in decommissioning liability, along with a $31.3 million reduction in utility plant, a $40.1 million reduction in the related regulatory asset and a regulatory liability of $17.7 million. For the portion of River Bend not subject to cost-based ratemaking, the revised estimate resulted in the elimination of the asset retirement cost that had been recorded at the time of adoption of SFAS 143 with the remainder recorded as miscellaneous income of $27.7 million.

In the third quarter of 2004 Entergy's Non-Utility Nuclear business recorded a reduction of $20.3 million in decommissioning liability to reflect changes in assumptions regarding the timing of when decommissioning of a plant will begin. Entergy considered the assumptions as part of recent studies evaluating the economic effect of the plant in its region. The revised estimate resulted in miscellaneous income of $20.3 million, reflecting the excess of the reduction in the liability over the amount of undepreciated asset retirement cost recorded at the time of adoption of SFAS 143.

As discussed in the Form 10-K, the Energy Policy Act of 1992 contains a provision that assesses domestic nuclear utilities with fees for the decontamination and decommissioning (D&D) of the DOE's past uranium enrichment operations. The Energy Policy Act calls for cessation of annual D&D assessments no later than October 24, 2007. Entergy will oppose any attempts to extend the assessments past this date, but cannot state with certainty that an extension will not be made.

CashPoint Bankruptcy

The domestic utility companies entered an agreement with CashPoint Network Services (CashPoint) under which CashPoint was to manage a network of payment agents through which Entergy's utility customers could pay their bills. The payment agent system allows customers to pay their bills at various commercial or governmental locations, rather than sending payments by mail. Approximately one-third of Entergy's utility customers use payment agents.

On April 19, 2004, CashPoint failed to pay funds due to the domestic utility companies that had been collected through payment agents. The domestic utility companies then obtained a temporary restraining order from the Civil District Court for the Parish of Orleans, State of Louisiana, enjoining CashPoint from distributing funds belonging to Entergy, except by paying those funds to Entergy. On April 22, 2004, a petition for involuntary Chapter 7 bankruptcy was filed against CashPoint by other creditors in the United States Bankruptcy Court for the Southern District of New York. In response to these events, the domestic utility companies expanded an existing contract with another company to manage all of their payment agents. The domestic utility companies filed proofs of claim in the CashPoint bankruptcy proceeding in September 2004. Although Entergy cannot precisely determine at this time the amount that CashPoint owes to the domestic utility companies that may not be repaid, it has accrued an estimate of loss based on current information. If no cash is repaid to the domestic utility companies, an event Entergy does not believe is likely, the current estimate of maximum exposure to loss is approximately $25 million.

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 deny any liability to the plaintiffs.

 

NOTE 2. RATE AND REGULATORY MATTERS

Electric Industry Restructuring and the Continued Application of SFAS 71

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

Texas

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

In view of the PUCT order to delay retail open access in the Texas service territory, Entergy Gulf States filed a retail electric rate case and fuel reconciliation proceeding with the PUCT in August 2004 seeking the following:

  • approval of a base rate increase of $42.6 million annually for the Texas retail jurisdiction;
  • approval to implement a $14.1 million per year rider to recover, over a 15-year period, $110.9 million of incurred costs related to its efforts to transition to a competitive retail market in accordance with the Texas restructuring law;
  • proposed $11.3 million franchise fee rider to recover payments to municipalities charging such fees; and
  • a requested return on equity of 11.5%.

In addition, Entergy Gulf States' fuel reconciliation filing made in conjunction with the base rate case seeks to reconcile approximately $288 million in fuel and purchased power costs incurred during the period September 2003 through March 2004. The PUCT requested that the parties submit briefs addressing threshold issues related to whether Entergy Gulf States has the right to file a base rate case and what relief is available, if the PUCT were to determine that Entergy Gulf States' base rates are subject to the rate freeze imposed in December 2001 in connection with the market readiness docket initiated by the PUCT Staff. The PUCT considered these issues in September 2004. In October 2004, the PUCT issued a written order in which it dismissed the rate case indicating that Entergy Gulf States is still subject to a rate freeze based on an agreement in 2001 stipulating that a rate freeze would remain in effect until retail open access commenced in Entergy Gulf States' service territory. Entergy Gulf States intends to file a motion for rehearing and also intends to pursue other available remedies.

Deferred Fuel Costs

In September 2004, Entergy Gulf States filed an application with the PUCT to implement a $27. 8 million interim fuel surcharge, including interest, to collect under-recovered fuel and purchased power expenses incurred from September 2003 through July 2004. Entergy Gulf States proposes to collect the surcharge over a six-month period beginning January 2005. Hearings are expected to occur in November 2004. Amounts collected though the interim fuel surcharge are subject to final reconciliation in a future fuel reconciliation proceeding.

In March 2004, Entergy Arkansas filed with the APSC its energy cost recovery rider for the period April 2004 through March 2005. The filed energy cost rate, which accounts for 12 percent of a typical residential customer's bill using 1,000 kWh per month, increased 16 percent due primarily to the elimination of a credit contained in the prior year's rate to refund previously over-recovered fuel costs. Also included in this year's energy cost calculation is a decrease in rates of $3.9 million as a result of the operation of a revised energy allocation method between the retail and wholesale sectors resulting from the approval of a life-of-resources power purchase agreement with Entergy New Orleans.

In March 2004, Entergy Gulf States filed with the PUCT a fuel reconciliation case covering the period September 2000 through August 2003. Entergy Gulf States is reconciling $1.43 billion of fuel and purchased power costs on a Texas retail basis. The reconciliation includes $8.6 million of under-recovered costs that Entergy Gulf States is asking to roll into its fuel over/under-recovery balance to be addressed in the next appropriate fuel proceeding. This case involves imputed capacity and River Bend payment issues similar to those decided adversely in the January 2001 proceeding, discussed below, which is now on appeal. The PUCT Staff has quantified these issues at $11.2 million. Hearings occurred in October 2004 and a final PUCT decision is expected in the first quarter of 2005.

See Note 2 to the consolidated financial statements in the Form 10-K for a discussion of Entergy Gulf States' January 2001 fuel reconciliation case filed with the PUCT covering the period from March 1999 through August 2000 and subsequent proceedings at Travis County District Court and the Third District Court of Appeals. Entergy Gulf States appealed to the Court of Appeals the disallowance of approximately $4.2 million related to imputed capacity costs and the disallowance related to costs for energy delivered from the 30% non-regulated share of River Bend. Oral argument before the appellate court occurred in September 2004.

As discussed in Note 2 to the consolidated financial statements in the Form 10-K, 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 recommended a disallowance with regard to one item. The issue relates to the alleged failure to uprate Waterford 3 in a timely manner, a claim that also has been raised in the summer 2001, 2002, and 2003 purchased power proceedings. The LPSC staff has quantified the possible disallowance as between $7.6 and $14 million. Entergy Louisiana notified the LPSC that it will contest the recommendation. The procedural schedule in the case has been suspended. A status conference for the purpose of establishing a new procedural schedule will be set when the current hearings in the Power Purchase Agreement proceedings at the FERC are concluded. The FERC hearings in that matter are expected to conclude in November 2004.

Retail Rate Proceedings

Filings with the PUCT and Texas Cities

Recovery of River Bend Costs

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 at Travis County District Court and the Third District Court of Appeals that affirmed the PUCT disallowance. In September 2004, the Texas Supreme Court denied Entergy Gulf States' petition for review, and Entergy Gulf States filed a motion for rehearing. In October 2004, the Texas Supreme Court requested that the other parties file responses to Entergy Gulf States' motion, and the matter is pending.

Filings with the LPSC

Annual Earnings Reviews (Entergy Gulf States)

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 the LPSC staff's December 2003 testimony, the staff recommended an annual rate refund of approximately $30 million effective June 2002 and a prospective rate reduction of approximately $50 million. Hearings concluded in May 2004.

Proposed Settlement (Entergy Gulf States and Entergy Louisiana)

In June 2004, Entergy Gulf States and Entergy Louisiana filed a proposed settlement with the LPSC that would resolve, among other dockets, Entergy Gulf States' ninth post-merger analysis and dockets established to consider issues concerning the companies' power purchases for the summers of 2001, 2002, and 2003. The proposed settlement included an offer to refund approximately $64 million to Entergy Gulf States' Louisiana customers and $1 million to Entergy Louisiana's customers, with no change in either company's current base rates.  The settlement also proposed a formula rate plan for Entergy Gulf States' Louisiana operations. At its September 2004 Business and Executive Session, the LPSC consolidated various dockets that were the subject of proposed settlement. The LPSC directed its staff to preside over settlement discussions and to submit any proposed settlement to the LPSC for its consideration.

Retail Rates

(Entergy Gulf States)

In July 2004, Entergy Gulf States filed with the LPSC an application for a change in its rates and charges seeking an increase of $9.1 million in gas base rates in order to allow Entergy Gulf States an opportunity to earn a fair and reasonable rate of return. Entergy Gulf States is also seeking approval of certain proposed rate design, rate schedule, and policy changes. A procedural schedule has not been established.

(Entergy Louisiana)

See Note 2 to the consolidated financial statements in the Form 10-K for Entergy Louisiana's rate filing with the LPSC requesting a base rate increase. In August 2004, the LPSC Staff filed testimony in which it recommended up to a $19.5 million rate increase for Entergy Louisiana, assuming that the Perryville acquisition is approved in time for the Perryville costs to be included in rates set in this proceeding. Additional issues and updates that will be evaluated in connection with this proceeding are likely to result in revisions to the LPSC Staff's recommendation. These issues may reduce the amount of the recommended rate increase or cause it to become a recommendation for a rate decrease. Hearings are currently scheduled to begin in December 2004.

Filings with the City Council

Formula Rate Plan Filings

In April 2004, Entergy New Orleans made filings with the City Council as required by the earnings review process prescribed by the Gas and Electric Formula Rate Plans approved by the Council in 2003. The filings showed an increase in Entergy New Orleans' electric revenues of $1.15 million and an increase in Entergy New Orleans' gas revenues of $32,000 is warranted. The Council Advisors and intervenors reviewed the filings, and filed their recommendations in July 2004. In August 2004, in accordance with the City Council's requirements for the formula rate plans, Entergy New Orleans made a filing with the City Council reflecting the parties' concurrence that no change in Entergy New Orleans' electric or gas rates is warranted. Later in August 2004, the City Council approved an unopposed settlement among Entergy New Orleans, the Council Advisors, and the intervenors in connection with the Gas and Electric Formula Rate Plans. In accordance with the resolution approving the settlement agreement, Entergy New Orleans' gas and electric base rates remain unchanged from levels set in May 2003. The resolution ordered Entergy New Orleans to defer $5.96 million of fossil plant maintenance expense incurred in 2003 and to record on its books a regulatory asset in that amount to be amortized over a five-year period effective January 2003. Entergy New Orleans also was ordered to defer $3.86 million relating to voluntary severance plan costs allocated to its electric operations and $0.99 million allocated to its gas operations, which amounts were accrued on its books in 2003, and to record on its books regulatory assets in those amounts to be amortized over five years effective January 2004.

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. In February 2004, the City Council approved a resolution that results in a refund to customers of $11.3 million, including interest, during the months of June through September 2004. The resolution concludes, among other things, that the record does not support an allegation that Entergy New Orleans' actions or inactions, either alone or in concert with Entergy or any of its affiliates, constituted a misrepresentation or a suppression of the truth made in order to obtain an unjust advantage of Entergy New Orleans, or to cause loss, inconvenience or harm to its ratepayers. Management believes that it has adequately provided for the liability associated with this proceeding. The plaintiffs have appealed the City Council resolution to the state court in Orleans Parish. Oral argument on the plaintiffs' appeal is scheduled for February 2005. In addition, in March 2004, the plaintiffs supplemented and amended the class action petition that had been filed in state court in April 1999. This proceeding has been stayed pending resolution of plaintiffs' appeal in the proceeding commenced with the City Council.

 

NOTE 3. COMMON EQUITY

Common Stock

Earnings per Share

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

 

 

For the Three Months Ended September 30,

 

 

2004

 

2003

 

 

(In Millions, Except Per Share Data)

 

 

 

 

$/share

 

 

 

$/share

Income before cumulative effect of accounting change less preferred dividends and Earnings applicable to common stock

 



$282.2 

     



$365.8

   
                 

Average number of common shares outstanding - basic

 


226.9 

 


$1.24 

 


228.1

 


$1.60 

Average dilutive effect of:

               

 

Stock Options (1)

 

4.0 

 

(0.022)

 

4.2

 

(0.029)

 

Deferred Units

 

0.2 

 

(0.001)

 

0.2

 

(0.001)

Average number of common shares outstanding - diluted

 


231.1 

 


$1.22 

 


232.5

 


$1.57 

 

 

 

 

 

 

 

 

 

 

 

For the Nine Months Ended September 30,

 

 

2004

 

2003

 

 

(In Millions, Except Per Share Data)

 

 

 

 

$/share

 

 

 

$/share

Income before cumulative effect of accounting change less preferred dividends

 


$754.6 

 

 

 


$823.5

 

 

                 

Average number of common shares outstanding - basic

 


228.6 

 


$3.30 

 


226.1

 


$3.64 

Average dilutive effect of:

 

 

 

 

 

 

 

 

 

Stock Options (1)

 

4.1 

 

(0.057)

 

4.0

 

(0.063)

 

Deferred Units

 

0.2 

 

(0.003)

 

0.3

 

(0.005)

Average number of common shares outstanding - diluted

 


232.9 

 


$3.24 

 


230.4

 


$3.57 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings applicable to common stock

 

$754.6 

 

 

 

$966.4

 

 

                 

Average number of common shares outstanding - basic

 


228.6 

 


$3.30 

 


226.1

 


$4.27 

Average dilutive effect of:

 

 

 

 

 

 

 

 

 

Stock Options (1)

 

4.1 

 

(0.057)

 

4.0

 

(0.074)

 

Deferred Units

 

0.2 

 

(0.003)

 

0.3

 

(0.006)

Average number of common shares outstanding - diluted

 


232.9 

 


$3.24 

 


230.4

 


$4.19 

 

 

 

 

 

 

 

 

 

(1)

Options to purchase 1,850,701 shares of common stock at various prices were outstanding at September 30, 2004 that were not included in the computation of diluted earnings per share because the exercise prices were greater than the average market price of the common shares at the end of the period. At September 30, 2003 all outstanding options, totaling 16,031,768, were included in the computation of diluted earnings per share as a result of the average market price of the common shares being greater than the exercise prices.

Entergy's stock option and other stock compensation plans are discussed in Note 8 to the consolidated financial statements in the Form 10-K.

For the nine months ended September 30, 2004, Entergy Corporation issued 3,729,906 shares of its previously repurchased common stock to satisfy stock option exercises and other stock-based awards and repurchased 7,382,000 shares of common stock for a total purchase price of $416.3 million.

Retained Earnings

On October 20, 2004, Entergy Corporation's Board of Directors declared a common stock dividend of $0.54 per share, payable on December 1, 2004, to holders of record as of November 17, 2004.

 

NOTE 4. LINES OF CREDIT, RELATED SHORT-TERM BORROWINGS, AND LONG-TERM DEBT

In May 2004, Entergy Corporation renewed its 364-day bank credit facility into two separate facilities, a 364-day credit facility and a 3-year credit facility. The 364-day credit facility has a borrowing capacity of $485 million and expires in May 2005. As of September 30, 2004, no borrowings were outstanding on this facility. The 3-year credit facility has a borrowing capacity of $965 million and expires in May 2007. As of September 30, 2004, $100 million in borrowings were outstanding on this facility. Entergy also has the ability to issue letters of credit against the 3-year credit facility and its $965 million borrowing capacity, and $40 million had been issued against this facility at September 30, 2004. Although the Entergy Corporation 364-day credit facility expires in May 2005, 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, any debt outstanding under the credit facilities is reflected in long-term debt on the balance sheet. The average commitment fee for the facilities is currently 0.14% of the line amount. Commitment fees and interest rates on loans under the credit facilities 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, 2004, Entergy's subsidiaries' authorized limit was $1.6 billion and the outstanding borrowing from the money pool was $239.4 million. In August 2004, Entergy filed with the SEC to extend the authorization period for the current short-term borrowing limits and the money pool borrowing arrangement.

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans each have separate short-term credit facilities available as follows:


Company

 


Expiration Date

 

Amount of
Facility

 

Amount Drawn as of
September 30, 2004

 

 

 

 

 

 

 

Entergy Arkansas

 

April 2005

 

$85 million

 

$85 million

Entergy Louisiana

 

April 2005

 

$15 million

 

-

Entergy Mississippi

 

May 2005

 

$25 million

 

$25 million

Entergy New Orleans

 

April 2005

 

$14 million

 

-

The combined amount borrowed by Entergy Louisiana and Entergy New Orleans under these facilities at any one time cannot exceed $15 million. The facilities have variable interest rates and the average commitment fee is 0.15%.

The following long-term debt has been issued by Entergy in 2004:

 

Issue Date

 

Amount

 

 

 

(In Thousands)

U.S. Utility

 

 

 

Mortgage Bonds:

 

 

 

5.50% Series due April 2019, Entergy Louisiana

March 2004

 

$100,000

6.25% Series due April 2034, Entergy Mississippi

April 2004

 

$100,000

4.65% Series due May 2011, Entergy Mississippi

April 2004

 

$80,000

5.60% Series due September 2024, Entergy New Orleans

August 2004

 

$35,000

5.65% Series due September 2029, Entergy New Orleans

August 2004

 

$40,000

Issuances after balance sheet date:

 

 

 

6.40% Series due October 2034, Entergy Louisiana

October 2004

 

$70,000

6.38% Series due November 2034, Entergy Arkansas

October 2004

 

$60,000

5.09% Series due November 2014, Entergy Louisiana

October 2004

 

$115,000

4.875% Series due November 2011, Entergy Gulf States

October 2004

 

$200,000

Other Long-term Debt:

 

 

 

4.60% Series due April 2022, Entergy Mississippi

September 2004

 

$16,030

 

The following long-term debt has been retired by Entergy in 2004:

 

Retirement Date

 

Amount

 

 

 

(In Thousands)

U.S. Utility

 

 

 

Mortgage Bonds:

 

 

 

8.25% Series due April 2004, Entergy Gulf States

April 2004

 

$292,000

6.20% Series due May 2004, Entergy Mississippi

May 2004

 

$75,000

6.45% Series due April 2008, Entergy Mississippi

May 2004

 

$80,000

7.70% Series due July 2023, Entergy Mississippi

May 2004

 

$60,000

8.0% Series due March 2023, Entergy New Orleans

September 2004

 

$45,000

7.55% Series due September 2023, Entergy New Orleans

September 2004

 

$30,000

Other Long-term Debt:

 

 

 

Grand Gulf Lease Obligation payment

N/A

 

$6,348

Waterford 3 Lease Obligation payment

N/A

 

$14,809

Retirements after balance sheet date:

 

 

 

7.0% Series due April 2022, Entergy Mississippi

October 2004

 

$7,935

7.0% Series due April 2022, Entergy Mississippi

October 2004

 

$8,095

In September 2004, Entergy Gulf States purchased its $62 million of 5.65% Series West Feliciana Parish bonds from the holders, pursuant to a mandatory tender provision, and has not remarketed the bonds at this time. Entergy Gulf States used a combination of cash on hand and short-term borrowings to buy-in the bonds.

In October 2004, Entergy Arkansas issued $60 million of 6.38% Series First Mortgage Bonds due November 1, 2034. In November 2004, Entergy Arkansas plans to use the proceeds to redeem the $61.9 million of 8.5% Series Junior Subordinated Deferrable Interest Debentures due 2045.

In October 2004, Entergy Gulf States issued $200 million of 4.875% Series of First Mortgage Bonds due November 1, 2011. Entergy Gulf States plans to use the proceeds to redeem, prior to maturity, $200 million of 5.2% Series of First Mortgage Bonds due December 3, 2007.

In October 2004, Entergy Louisiana issued $70 million of 6.40% Series of First Mortgage Bonds due October 1, 2034. In November 2004, Entergy Louisiana plans to use the proceeds to redeem $72.2 million of 9.0% Series Junior Subordinated Deferrable Interest Debentures due 2045.

In October 2004, Entergy Louisiana issued $115 million of 5.09% Series of First Mortgage Bonds due November 1, 2014. Entergy Louisiana plans to use the proceeds to redeem, prior to maturity, $115 million of 6.5% Series of First Mortgage Bonds due March 1, 2008.

 

NOTE 5. STOCK-BASED COMPENSATION

As described more fully in Note 8 to the consolidated financial statements in the Form 10-K, Entergy grants stock options to key employees of the Entergy subsidiaries. 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 the stock option grants. 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 stock-based compensation plans vest over three years. Therefore, the cost related to stock-based employee compensation included in the determination of net income for 2003 and 2004 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.

   

Three Months Ended September 30,

 

Nine Months Ended September 30,

   

2004

 

2003

 

2004

 

2003

   

(In Thousands, Except Per Share Data)

                 

Earnings applicable to common stock

 

$282,244

 

$365,774

 

$754,587

 

$966,423

Add: Stock-based compensation expense included in earnings applicable to common stock, net of related tax effects

 



1,389

 



692

 



3,752

 



2,113

Deduct: Total stock-based employee
compensation expense determined under fair value method for all awards, net of related tax effects

 



4,271

 



6,117

 



12,398

 



18,388

                 

Pro forma earnings applicable to common stock

 

$279,362

 

$360,349

 

$745,941

 

$950,148

                 

Earnings per average common share:

               
 

Basic

 

$1.24

 

$1.60

 

$3.30

 

$4.27

 

Basic - pro forma

 

$1.23

 

$1.58

 

$3.26

 

$4.20

                   
 

Diluted

 

$1.22

 

$1.57

 

$3.24

 

$4.19

 

Diluted - pro forma

 

$1.21

 

$1.55

 

$3.20

 

$4.12

 

NOTE 6. RETIREMENT AND OTHER POSTRETIREMENT BENEFITS

Components of Net Pension Cost

Entergy's pension cost, including amounts capitalized, for the third quarters of 2004 and 2003 included the following components:

 

 

2004

 

2003

 

 

(In Thousands)

 

 

 

 

 

Service cost - benefits earned during the period

 

$19,132 

 

$14,430 

Interest cost on projected benefit obligation

 

37,005 

 

30,363 

Expected return on assets

 

(38,324)

 

(36,702)

Amortization of transition asset

 

(190)

 

(180)

Amortization of prior service cost

 

1,286 

 

1,362 

Amortization of loss

 

5,425 

 

1,146 

Net pension costs

 

$24,334 

 

$10,419 

 

Entergy's pension cost, including amounts capitalized, for the nine months ended September 30, 2004 and 2003, included the following components:

 

 

2004

 

2003

 

 

(In Thousands)

 

 

 

 

 

Service cost - benefits earned during the period

 

$56,394 

 

$46,576 

Interest cost on projected benefit obligation

 

108,999 

 

97,867 

Expected return on assets

 

(115,628)

 

(119,914)

Amortization of transition asset

 

(572)

 

(582)

Amortization of prior service cost

 

4,112 

 

4,418 

Amortization of loss

 

14,233 

 

3,244 

Net pension costs

 

$67,538 

 

$31,609 

Components of Net Other Postretirement Benefit Cost

Entergy's other postretirement benefit cost, including amounts capitalized, for the third quarters of 2004 and 2003 included the following components:

 

 

2004

 

2003

 

 

(In Thousands)

 

 

 

 

 

Service cost - benefits earned during the period

 

$7,737 

 

$10,533 

Interest cost on APBO

 

13,450 

 

13,284 

Expected return on assets

 

(4,707)

 

(3,828)

Amortization of transition obligation

 

756 

 

2,868 

Amortization of prior service cost

 

(1,306)

 

249 

Amortization of loss

 

5,489 

 

4,440 

Net other postretirement benefit cost

 

$21,419 

 

$27,546 

Entergy's other postretirement benefit cost, including amounts capitalized, for the nine months ended September 30, 2004 and 2003, included the following components:

 

 

2004

 

2003

 

 

(In Thousands)

 

 

 

 

 

Service cost - benefits earned during the period

 

$25,590 

 

$29,445 

Interest cost on APBO

 

41,183 

 

39,378 

Expected return on assets

 

(14,034)

 

(11,884)

Amortization of transition obligation

 

2,203 

 

8,604 

Amortization of prior service cost

 

(2,804)

 

747 

Amortization of loss

 

16,916 

 

11,610 

Net other postretirement benefit cost

 

$69,054 

 

$77,900 

Employer Contributions

Entergy previously disclosed in its 2003 Form 10-K that it expected to contribute $110 million to its pension plans in 2004. In April 2004, the President signed the Pension Funding Equity Act of 2004 into law, which reduced Entergy's estimated 2004 required pension contribution to $72.8 million. As of September 30, 2004, Entergy has contributed $69.0 million to its pension plans. Therefore, Entergy presently anticipates contributing an additional $3.8 million to fund its pension plans in 2004.

 

Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act)

As disclosed in Note 11 to the consolidated financial statements in the Form 10-K, Entergy elected to record an estimate of the effects of the Medicare Act in December 2003. In August 2004, the Centers for Medicare and Medicaid Services issued proposed regulations to implement the new Medicare law. Based on actuarial analysis at September 30, 2004, the estimated effect of future Medicare subsidies reduced the January 1, 2004 Accumulated Postretirement Benefit Obligation by $128 million and reduced the third quarter 2004 and nine months ended September 30, 2004 other postretirement benefit cost by $5.8 million and $12.8 million, respectively.

 

NOTE 7. BUSINESS SEGMENT INFORMATION

Entergy's reportable segments as of September 30, 2004 are U.S. Utility, Non-Utility Nuclear, and Energy Commodity Services. "All Other" includes the parent company, Entergy Corporation, and other business activity, including the Competitive Retail Services business, which has higher revenues in 2004 as its number of customers has increased, and earnings on the proceeds of sales of previously-owned businesses.

Entergy's segment financial information for the third quarters of 2004 and 2003 is as follows:

 



U. S. Utility

 


Non-Utility
Nuclear*

 

Energy
Commodity
Services *

 



All Other*

 



Eliminations

 



Consolidated

 

(In Thousands)

2004

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

$2,423,366 

 

$350,343

 

$66,193

 

$140,756 

 

($17,077)

 

$2,963,581

Equity in earnings (loss) of

 

 

 

 

 

 

 

 

 

 

 

  unconsolidated equity affiliates

 

-

 

(72,015)

 

 

 

(72,015)

Income Taxes (Benefit)

161,477 

 

45,108

 

(30,529)

 

(1,280)

 

 

174,776

Net Income (Loss)

263,851 

 

63,713

 

(38,935)

 

(582)

 

 

288,047

 

 

 

 

 

 

 

 

 

 

 

 

2003

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

$2,262,026 

 

$337,728

 

$48,195

 

$69,550 

 

($17,374)

 

$2,700,125

Equity in earnings of

 

 

 

 

 

 

 

 

 

 

 

  unconsolidated equity affiliates

 

-

 

60,099

 

 

(1) 

 

60,099

Income Taxes (Benefit)

172,484 

 

39,284

 

19,705

 

(10,657)

 

 

220,816

Net Income (Loss)

278,813 

 

59,606

 

36,330

 

(3,099)

 

 

371,650

Entergy's segment financial information for the nine months ended September 30, 2004 and 2003 is as follows:

 



U. S. Utility

 


Non-Utility
Nuclear*

 

Energy
Commodity
Services *

 



All Other*

 



Eliminations

 



Consolidated

 

(In Thousands)

2004

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

$6,199,528 

 

$1,033,936

 

$165,476

 

$351,140 

 

($49,852)

 

$7,700,228

Equity in earnings (loss) of

 

 

 

 

 

 

 

 

 

 

 

  unconsolidated equity affiliates

 

-

 

(31,908)

 

 

 

(31,908)

Income Taxes (Benefit)

358,007 

 

129,441

 

(20,195)

 

(20,285)

 

 

446,968

Net Income (Loss)

586,157 

 

195,541

 

(19,632)

 

10,009 

 

 

772,075

Total Assets

22,652,954 

 

4,481,272

 

2,200,880

 

1,029,416 

 

(1,426,593)

 

28,937,929

 

 

 

 

 

 

 

 

 

 

 

 

2003

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

$5,904,584 

 

$939,615

 

$149,074

 

$122,201 

 

($23,714)

 

$7,091,760

Equity in earnings of

 

 

 

 

 

 

 

 

 

 

 

  unconsolidated equity affiliates

 

-

 

258,451

 

1

 

(1)

 

258,451

Income Taxes (Benefit)

331,152 

 

91,371

 

106,621

 

(30,076)

 

 

499,068

Cumulative effect of

 

 

 

 

 

 

 

 

 

 

 

  accounting changes, net of tax

(21,333)

 

160,360

 

3,895

 

 

 

142,922

Net Income (Loss)

520,110 

 

301,451

 

178,696

 

(16,165)

 

 

984,092

Total Assets

22,449,508 

 

4,243,000

 

2,062,239

 

1,698,101 

 

(1,885,018)

 

28,567,830

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.

__________________________________

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.

ENTERGY ARKANSAS, INC.

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

 

Results of Operations

Net Income

Third Quarter 2004 Compared to Third Quarter 2003

Net income decreased $1.4 million primarily due to a decrease in net revenue, partially offset by a lower effective income tax rate.

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

Net income decreased $13.5 million primarily due to a decrease in net revenue and an increase in other operation and maintenance expenses, partially offset by a decrease in interest charges and a lower effective income tax rate.

Net Revenue

Third Quarter 2004 Compared to Third Quarter 2003

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

 

 

Amount

 

 

(In Millions)

 

 

 

2003 net revenue

 

$303.9 

Volume/weather

 

(13.1)

Net wholesale revenue

 

4.7 

Other

 

1.9 

2004 net revenue

 

$297.4 

The volume/weather variance primarily resulted from the effect of milder weather on sales during the third quarter of 2004 compared to the third quarter of 2003.

The net wholesale revenue variance resulted primarily from reduced losses associated with substitute energy provided to the co-owners of Entergy Arkansas' coal plants.

Fuel and purchased power expenses

Fuel and purchased power expenses increased primarily due to increased recovery of deferred fuel and purchased power costs.

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

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

 

 

Amount

 

 

(In Millions)

 

 

 

2003 net revenue

 

$777.5 

Deferred fuel cost revisions

 

(16.9)

Other

 

(8.3)

2004 net revenue

 

$752.3 

Deferred fuel cost revisions decreased net revenue due to a revised estimate of fuel costs filed for recovery at Entergy Arkansas in the March 2004 energy cost recovery rider, which reduced net revenue by $11.5 million. The remainder of the variance is due to the 2002 energy cost recovery true-up, made in the first quarter of 2003, which increased net revenue in 2003.

Fuel and purchased power expenses

Fuel and purchased power expenses increased primarily due to increased recovery of deferred fuel and purchased power costs primarily due to the true-ups to the 2003 and 2002 energy cost recovery rider filings.

Other Income Statement Variances

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

Other operation and maintenance expenses increased primarily due to:

    • an increase of $7.7 million in customer service support costs; and
    • an increase of $5.2 million in benefits costs.

Interest charges decreased primarily due to the refinancing of First Mortgage Bonds in mid-2003.

Income Taxes

The effective income tax rates for the third quarters of 2004 and 2003 were 36.4% and 41.0%, respectively. The effective income tax rates for the nine months ended September 30, 2004 and 2003 were 36.4% and 39.8%, respectively. The differences in the effective income tax rates for the third quarter of 2003 and the nine months ended September 30, 2003 versus the federal statutory rate of 35% are primarily due to book and tax differences related to utility plant items and state income taxes, partially offset by flow-through book and tax differences and the amortization of investment tax credits.

Liquidity and Capital Resources

Cash Flow

Cash flows for the nine months ended September 30, 2004 and 2003 were as follows:

 

 

2004

 

2003

 

 

(In Thousands)

 

 

 

 

 

Cash and cash equivalents at beginning of period

 

$8,834 

 

$95,513 

 

 

 

 

 

Cash flow provided by (used in):

 

 

 

 

 

Operating activities

 

212,350 

 

345,116 

 

Investing activities

 

(198,145)

 

(228,932)

 

Financing activities

 

12,568 

 

(179,053)

Net increase (decrease) in cash and cash equivalents

 

26,773 

 

(62,869)

 

 

 

 

 

Cash and cash equivalents at end of period

 

$35,607 

 

$32,644 

Operating Activities

Cash flow from operations decreased $132.8 million for the nine months ended September 30, 2004 compared to the nine months ended September 30, 2003 primarily due to money pool activity. Money pool activity used $109.2 million of Entergy Arkansas' operating cash flows in the nine months ended September 30, 2004 and provided $46.9 million in the nine months ended September 30, 2003. This decrease was partially offset by increased recovery of deferred fuel costs.

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

September 30,
2004

 

December 31,
2003

 

September 30,
2003

 

December 31,
2002

(In Thousands)

 

 

 

 

 

 

 

$40,064

 

($69,153)

 

($42,665)

 

$4,279

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.

Investing Activities

Net cash used in investing activities decreased $30.8 million for the nine months ended September 30, 2004 compared to the nine months ended September 30, 2003 primarily due to a decrease in construction expenditures resulting from less independent power producer-related work performed in 2004 combined with lower spending on customer support projects in 2004.

Financing Activities

Financing activities provided $12.6 million for the nine months ended September 30, 2004 compared to using $179.1 million for the nine months ended September 30, 2003 primarily due to the net retirement of $109.2 million of First Mortgage Bonds for the nine months ended September 30, 2003 and an $85 million borrowing made on Entergy Arkansas' 364-day credit facility during the nine months ended September 30, 2004.

Uses and Sources of Capital

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 2004, Entergy Arkansas renewed its 364-day credit facility through April 30, 2005 and increased the amount available to $85 million. The facility was fully drawn at September 30, 2004.

In October 2004, Entergy Arkansas issued $60 million of 6.38% Series First Mortgage Bonds due November 1, 2034. Entergy Arkansas plans to use the proceeds to redeem in November 2004 the $61.9 million of 8.5% Series Junior Subordinated Deferrable Interest Debentures due 2045.

Significant Factors and Known Trends

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. The following is an update to the Form 10-K.

System Agreement Proceedings

See the Form 10-K for a discussion of the proceeding commenced at the FERC by the LPSC regarding production cost equalization under the System Agreement, the ALJ's Initial Decision in the proceeding, and the "Order of Investigation" issued by the APSC. Several parties, including Entergy, the LPSC, the APSC, the MPSC, the City Council, and the FERC Staff, filed briefs on exceptions in response to the ALJ's Initial Decision. Entergy's exceptions to the ALJ's Initial Decision include: the practical effect of the Initial Decision is full production cost equalization, which was rejected in the Initial Decision and previously has been rejected by the FERC; resource planning for the Entergy System would be impeded if the Initial Decision were adopted; the remedy in the Initial Decision is inconsistent with the history, structure, and precedent regarding the System Agreement; the Initial Decision's remedy ignores the historical pattern of production cost disparities on the Entergy System and would result in substantial, sudden transfers of costs between groups of Entergy customers; the numerical standards proposed in the Initial Decision are arbitrary and are so complex that they will be difficult to implement; the Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the full costs of the Vidalia project should be included in Entergy Louisiana's production costs for purposes of calculating relative production costs; and the Initial Decision erroneously adopted a new method of calculating reserve sharing costs rather than the current method.

As reported in the Form 10-K, if the FERC grants the relief requested by the LPSC in the proceeding, the relief may result in a material increase in the total production costs the FERC allocates to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in the total production costs the FERC allocates to companies whose costs currently are projected to exceed that average.   If the FERC adopts the ALJ's Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of Entergy System average total production cost. The ALJ's Initial Decision would reallocate production costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth. This would be accomplished by payments from domestic utility companies whose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost.

An assessment of the potential effects of the ALJ's Initial Decision requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power.  Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation.  Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas' total production costs are below the average production costs of the domestic utility companies.  Considerable uncertainty exists regarding future gas prices. Annual average gas prices have varied significantly over recent years, ranging from $1.92/mmBtu to $5.48/mmBtu for the 1994-2003 period, and averaging $2.99/mmBtu during the ten-year period 1994-2003 and $3.77/mmBtu during the five-year period 1999-2003.  Recent market conditions have resulted in gas prices that have averaged $5.58/MMBtu for the twelve months ended September 2004. Based upon analyses considering the effect on future production costs if the FERC adopts the ALJ's Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could result assuming annual average gas prices range from $6.39/mmBtu in 2005 declining to $4.97/mmBtu by 2009:

 


Range of Annual Payments or (Receipts)

 

Average Annual Payments or (Receipts) for 2005-2009 Period

 

(In Millions)

 

(In Millions)

       

Entergy Arkansas

$154 to $281 

 

$215 

Entergy Gulf States

($130) to ($15)

 

($63)

Entergy Louisiana

($199) to ($98)

 

($141)

Entergy Mississippi

($16) to $8 

 

$1 

Entergy New Orleans

($17) to ($5)

 

($12)

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

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

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

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

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

Critical Accounting Estimates

See "Management's Financial Discussion and Analysis - Critical Accounting Estimates" in the Form 10-K for a discussion of the estimates and judgments necessary in Entergy Arkansas' accounting for nuclear decommissioning costs and pension and other retirement costs. Following is an update to the information provided in the Form 10-K.

Nuclear Decommissioning Costs

In the first quarter of 2004, in accordance with a new decommissioning cost study for ANO 1 and 2, Entergy Arkansas recorded a revision to its estimated decommissioning cost liability. The revised estimate resulted in a $107.7 million reduction in its decommissioning liability, along with a $19.5 million reduction in utility plant and an $88.2 million reduction in the related regulatory asset.

 

ENTERGY ARKANSAS, INC.
INCOME STATEMENTS
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
         
    Three Months Ended   Nine Months Ended
    2004   2003   2004   2003
    (In Thousands)   (In Thousands)
                 
OPERATING REVENUES                
Domestic electric   $481,103    $469,925    $1,250,072    $1,227,558 
                 
OPERATING EXPENSES                
Operation and Maintenance:                
  Fuel, fuel-related expenses, and                
    gas purchased for resale   46,546    30,581    141,649    107,669 
  Purchased power   141,147    139,829    371,303    363,295 
  Nuclear refueling outage expenses   6,328    5,679    18,118    17,565 
  Other operation and maintenance   96,125    93,632    274,781    259,445 
Decommissioning   7,851    8,971    24,920    26,915 
Taxes other than income taxes   10,062    8,961    28,356    26,973 
Depreciation and amortization   53,081    50,846    153,018    150,733 
Other regulatory credits - net   (3,947)   (4,364)   (15,217)   (20,896)
TOTAL   357,193    334,135    996,928    931,699 
                 
OPERATING INCOME   123,910    135,790    253,144    295,859 
                 
OTHER INCOME                
Allowance for equity funds used during construction   3,781    2,047    8,428    6,276 
Interest and dividend income   1,718    2,551    6,729    7,178 
Miscellaneous - net   (3,631)   (871)   (5,178)   (3,384)
TOTAL   1,868    3,727    9,979    10,070 
                 
INTEREST AND OTHER CHARGES   
Interest on long-term debt   19,818    22,740    59,335    67,918 
Other interest - net   1,162    613    3,211    2,743 
Allowance for borrowed funds used during construction   (1,988)   (1,347)   (4,568)   (3,973)
TOTAL   18,992    22,006    57,978    66,688 
                 
INCOME BEFORE INCOME TAXES   106,786    117,511    205,145    239,241 
                 
Income taxes   38,842    48,192    74,649    95,240 
                 
NET INCOME   67,944    69,319    130,496    144,001 
                 
Preferred dividend requirements and other   1,944    1,944    5,832    5,832 
                 
EARNINGS APPLICABLE TO                
COMMON STOCK   $66,000    $67,375    $124,664    $138,169 
                 
See Notes to Respective Financial Statements.                
                 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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ENTERGY ARKANSAS, INC.
STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2004 and 2003
(Unaudited)
         
    2004   2003
    (In Thousands)
         
OPERATING ACTIVITIES        
Net income   $130,496    $144,001 
Noncash items included in net income:        
  Other regulatory credits - net   (15,217)   (20,896)
  Depreciation, amortization, and decommissioning   177,938    177,648 
  Deferred income taxes and investment tax credits   57,454    (8,501)
Changes in working capital:        
  Receivables   (78,342)   (52,150)
  Fuel inventory   (1,467)   542 
  Accounts payable   (76,547)   (5,032)
  Taxes accrued   18,226    115,992 
  Interest accrued   4,135    (1,514)
  Deferred fuel costs   5,629    (34,096)
  Other working capital accounts   (3,747)   7,296 
Provision for estimated losses and reserves   (8,540)   (559)
Changes in other regulatory assets   16,108    (11,425)
Other   (13,776)   33,810 
Net cash flow provided by operating activities   212,350    345,116 
         
INVESTING ACTIVITIES        
Construction expenditures   (184,041)   (214,716)
Allowance for equity funds used during construction   8,428    6,276 
Nuclear fuel purchases   (8,101)   (39,007)
Proceeds from sale/leaseback of nuclear fuel   8,101    39,007 
Decommissioning trust contributions and realized        
  change in trust assets   (5,927)   (5,753)
Other regulatory investments   (16,605)   (14,739)
Net cash flow used in investing activities   (198,145)   (228,932)
         
FINANCING ACTIVITIES        
Proceeds from the issuance of long-term debt   -    361,819 
Retirement of long-term debt   -    (471,040)
Changes in short-term borrowings   85,000    - 
Dividends paid:        
  Common stock   (66,600)   (64,000)
  Preferred stock   (5,832)   (5,832)
Net cash flow provided by (used in) financing activities   12,568    (179,053)
         
Net increase (decrease) in cash and cash equivalents   26,773    (62,869)
         
Cash and cash equivalents at beginning of period   8,834    95,513 
         
Cash and cash equivalents at end of period   $35,607    $32,644 
         
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:        
Cash paid/(received) during the period for:        
  Interest - net of amount capitalized   $53,847    $67,240 
  Income taxes   ($5,400)   ($18,078)
         
See Notes to Respective Financial Statements.        
         

 

ENTERGY ARKANSAS, INC.
BALANCE SHEETS
ASSETS
September 30, 2004 and December 31, 2003
(Unaudited)
 
  2004   2003
  (In Thousands)
         
CURRENT ASSETS        
Cash and cash equivalents:        
  Cash   $6,921    $8,834 
  Temporary cash investments - at cost,        
   which approximates market   28,686    - 
     Total cash and cash equivalents   35,607    8,834 
Accounts receivable:        
  Customer   111,609    69,036 
  Allowance for doubtful accounts   (9,270)   (9,020)
  Associated companies   78,705    50,390 
  Other   31,107    30,930 
  Accrued unbilled revenues   72,259    64,732 
     Total accounts receivable   284,410    206,068 
Deferred fuel costs   21,533    10,557 
Accumulated deferred income taxes   17,103    18,362 
Fuel inventory - at average cost   8,189    6,722 
Materials and supplies - at average cost   82,834    80,506 
Deferred nuclear refueling outage costs   23,098    19,793 
Prepayments and other   91,699    23,938 
TOTAL   564,473    374,780 
         
OTHER PROPERTY AND INVESTMENTS        
Investment in affiliates - at equity   11,212    11,212 
Decommissioning trust funds   371,653    360,485 
Non-utility property - at cost (less accumulated depreciation)   1,454    1,456 
Other   4,832    4,832 
TOTAL   389,151    377,985 
          
UTILITY PLANT        
Electric   6,078,413    5,948,090 
Property under capital lease   21,811    24,047 
Construction work in progress   233,308    238,807 
Nuclear fuel under capital lease   75,372    102,691 
Nuclear fuel   13,441    7,466 
TOTAL UTILITY PLANT   6,422,345    6,321,101 
Less - accumulated depreciation and amortization   2,749,541    2,627,441 
UTILITY PLANT - NET   3,672,804    3,693,660 
         
DEFERRED DEBITS AND OTHER ASSETS        
Regulatory assets:        
  SFAS 109 regulatory asset - net   120,930    128,311 
  Other regulatory assets   368,277    437,544 
Other   46,852    45,798 
TOTAL   536,059    611,653 
         
TOTAL ASSETS   $5,162,487    $5,058,078 
         
See Notes to Respective Financial Statements.        
 
 
 
ENTERGY ARKANSAS, INC.
BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
September 30, 2004 and December 31, 2003
(Unaudited)
 
  2004   2003
  (In Thousands)
 
CURRENT LIABILITIES        
Currently maturing long-term debt   $147,000   $ -
Notes payable   85,000   -
Accounts payable:        
  Associated companies   33,550   106,958
  Other   89,499   92,638
Customer deposits   40,910   37,693
Interest accrued   25,559   21,424
Obligations under capital leases   59,365   59,089
Other   22,722   16,924
TOTAL   503,605   334,726
         
NON-CURRENT LIABILITIES        
Accumulated deferred income taxes and taxes accrued   1,126,449   996,455
Accumulated deferred investment tax credits   69,659   73,280
Obligations under capital leases   37,818   67,648
Other regulatory liabilities   58,164   52,923
Decommissioning   484,763   567,546
Accumulated provisions   31,609   40,149
Long-term debt   1,192,916   1,338,378
Other   204,667   192,200
TOTAL   3,206,045   3,328,579
         
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 2004        
  and 2003   470   470
Paid-in capital   591,127   591,127
Retained earnings   744,890   686,826
TOTAL   1,452,837   1,394,773
         
Commitments and Contingencies        
         
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY   $5,162,487   $5,058,078
         
See Notes to Respective Financial Statements.        

 

ENTERGY ARKANSAS, INC.
SELECTED OPERATING RESULTS
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
 
 
    Three Months Ended   Increase/    
Description   2004   2003   (Decrease)   %
    (In Millions)        
Electric Operating Revenues:                
  Residential   $ 178   $ 182   ($ 4)   (2)
  Commercial   93   90   3    3 
  Industrial   92   88   4    5 
  Governmental   5   4   1    25 
    Total retail   368   364   4    1 
  Sales for resale                
    Associated companies   63   53   10    19 
    Non-associated companies   49   52   (3)   (6)
  Other   1   1   -    - 
     Total   $ 481   $ 470   $ 11    2 
                 
Billed Electric Energy                
 Sales (GWh):                
  Residential   2,188   2,306   (118)   (5)
  Commercial   1,615   1,609   6    - 
  Industrial   1,831   1,875   (44)   (2)
  Governmental   79   77   2    3 
    Total retail   5,713   5,867   (154)   (3)
  Sales for resale                
    Associated companies   1,848   1,529   319    21 
    Non-associated companies   1,232   1,360   (128)   (9)
     Total   8,793   8,756   37    - 
                 
                 
    Nine Months Ended   Increase/    
Description   2004   2003   (Decrease)   %
    (In Millions)        
Electric Operating Revenues:                
  Residential   $ 424   $ 419   $ 5    1 
  Commercial   231   223   8    4 
  Industrial   237   232   5    2 
  Governmental   13   11   2    18 
     Total retail   905   885   20    2 
  Sales for resale                
    Associated companies   172   169   3    2 
    Non-associated companies   141   146   (5)   (3)
  Other   32   28   4    14 
     Total   $ 1,250   $ 1,228   $ 22    2 
                 
Billed Electric Energy                
 Sales (GWh):                
  Residential   5,508   5,617   (109)   (2)
  Commercial   4,101   4,065   36    1 
  Industrial   5,192   5,240   (48)   (1)
  Governmental   210   204   6    3 
     Total retail   15,011   15,126   (115)   (1)
  Sales for resale                
    Associated companies   5,033   5,283   (250)   (5)
    Non-associated companies   3,765   4,153   (388)   (9)
     Total   23,809   24,562   (753)   (3)
                 
                 

 

ENTERGY GULF STATES, INC.

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

 

Results of Operations

Net Income

Third Quarter 2004 Compared to Third Quarter 2003

Net income of $82.5 million remained relatively unchanged. Increased miscellaneous income resulting from a revision of the decommissioning liability for River Bend, which is discussed below, and decreased interest charges on long-term debt were offset by increased other operation and maintenance expenses and a lower effective tax rate in 2003.

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

Net income increased $105.8 million primarily due to:

    • a $107.7 million accrual ($65.6 million net-of-tax) in June 2003 for the loss that would be associated with a final, non-appealable decision disallowing abeyed River Bend plant costs. See Note 2 to the domestic utility companies and System Energy financial statements for more details regarding the River Bend abeyed plant costs;
    • a one-time $21.3 million net-of-tax cumulative effect of accounting change in 2003 due to the implementation of SFAS 143;
    • increased miscellaneous income resulting from a revision of the decommissioning liability for River Bend, as discussed below;
    • increased miscellaneous income resulting from a reduction in the loss provision for an environmental clean-up site; and
    • decreased interest charges on long-term debt.

The increase was partially offset by increased other operation and maintenance expenses.

Net Revenue

Third Quarter 2004 Compared to Third Quarter 2003

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

 

 

Amount

 

 

(In Millions)

 

 

 

2003 net revenue

 

$335.9 

Fuel recovery revenues

 

(9.1)

Volume/weather

 

2.3 

Other

 

0.6 

2004 net revenue

 

$329.7 

Fuel recovery revenues represent an under-recovery of fuel charges that are recovered in base rates.

The volume/weather variance resulted from increased usage of 475 GWh in the industrial and commercial sectors and the effect of more favorable weather in the Texas jurisdiction compared to the same period in 2003.

Gross operating revenues and fuel and purchased power expenses

Gross operating revenues increased primarily due to an increase of $51.7 million in fuel cost recovery revenues due to higher fuel rates.

Fuel and purchased power expenses increased primarily due to an increase in the market price of natural gas and increases in electric generation and power purchases.

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

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

 

 

Amount

 

 

(In Millions)

 

 

 

2003 net revenue

 

$884.8 

Net wholesale revenue

 

13.2 

Volume/weather

 

8.1 

Fuel recovery revenues

 

(13.5)

Other

 

(3.8)

2004 net revenue

 

$888.8 

The net wholesale revenue variance resulted from increased volume and higher pricing associated with sales to municipal and co-op customers and affiliated systems.

The volume/weather variance resulted from increased usage of 881 GWh in the industrial and commercial sectors, partially offset by decreased residential usage due to the effect of milder weather on billed sales as compared to the same period in 2003.

Fuel recovery revenues represent an under-recovery of fuel charges that are recovered in base rates.

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

Gross operating revenues increased primarily due to an increase of $92.7 million in fuel cost recovery revenues due to higher fuel rates.

Fuel and purchased power expenses increased primarily due to increased recovery of deferred fuel due to higher fuel rates, an increase in electric generation, and increases in the market prices of natural gas and purchased power.

Other regulatory credits increased primarily due to the amortization in 2003 of deferred capacity charges for the summer of 2001compared to the absence of amortization in 2004. The amortization of these charges began in June 2002 and ended in May 2003.

 

Other Income Statement Variances

Third Quarter 2004 Compared to Third Quarter 2003

Other operation and maintenance expenses increased primarily due to:

    • an increase of $4.4 million in benefits costs; and
    • an increase of $1.8 million due to uncollectible accounts expense.

Miscellaneous income - net increased $25.3 million primarily due to a revision to the estimated decommissioning cost liability for River Bend in accordance with a new decommissioning cost study that reflected a life extension for the plant. For the portion of River Bend not subject to cost-based ratemaking, the revised estimate resulted in the elimination of the asset retirement cost that had been recorded at the time of adoption of SFAS 143 with the remainder recorded as miscellaneous income of $27.7 million.

Interest on long-term debt decreased $10.1 million primarily due to the financing program and debt restructuring implemented in 2003, which resulted in extended maturities and lowered interest rates in Entergy Gulf States' debt portfolio.

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

Other operation and maintenance expenses increased primarily due to:

    • an increase of $8.2 million in benefits costs; and
    • an increase of $3.9 million in customer service support costs.

This was partially offset by a decrease of $4.9 million in lower nuclear material and labor costs due to a reduction in staff in 2004.

Miscellaneous income - net increased $147.2 million primarily due to:

    • the $107.7 million accrual in June 2003 for the loss that would be associated with a final, non-appealable decision disallowing abeyed River Bend plant costs. See Note 2 to the domestic utility companies and System Energy financial statements for more details regarding the River Bend abeyed plant costs.
    • the River Bend decommissioning cost liability revision discussed above; and
    • a reduction in the loss provision of approximately $10 million related to an environmental clean-up site.

Interest on long-term debt decreased $19.3 million primarily due to the financing program and debt restructuring implemented in 2003, which resulted in extended maturities and lowered interest rates in Entergy Gulf States' debt portfolio.

Income Taxes

The effective income tax rates for the third quarters of 2004 and 2003 were 38.1% and 31.3%, respectively. The difference in the effective income tax rate for the third quarter of 2004 versus the federal statutory rate of 35% is primarily due to state income taxes and book and tax differences related to utility plant items, partially offset by the amortization of investment tax credits. The difference in the third quarter 2003 effective income tax rate versus the federal statutory rate of 35% is primarily due to a downward revision in the estimate of federal income tax expense and flow-through book and tax differences.

The effective income tax rates for the nine months ended September 30, 2004 and 2003 were 36.8% and 21.8%, respectively. The difference in the effective income tax rate for the nine months ended September 30, 2004 versus the federal statutory rate of 35% is primarily due to state income taxes, partially offset by the amortization of investment tax credits. The difference in the effective income tax rate for the nine months ended September 30, 2003 versus the federal statutory rate of 35% is primarily due to the flow-through effect of book and tax differences, investment tax credit amortization, and a downward revision in the estimate of federal income tax expense.

Liquidity and Capital Resources

Cash Flow

Cash flows for the nine months ended September 30, 2004 and 2003 were as follows:

 

 

2004

 

2003

 

 

(In Thousands)

 

 

 

 

 

Cash and cash equivalents at beginning of period

 

$206,030 

 

$318,404 

 

 

 

 

 

Cash flow provided by (used in):

 

 

 

 

 

Operating activities

 

503,662 

 

219,812 

 

Investing activities

 

(263,690)

 

(331,480)

 

Financing activities

 

(434,920)

 

(79,052)

Net decrease in cash and cash equivalents

 

(194,948)

 

(190,720)

 

 

 

 

 

Cash and cash equivalents at end of period

 

$11,082 

 

$127,684 

Operating Activities

Cash flow from operations increased $283.9 million in the nine months ended September 30, 2004 compared to the same period of 2003 primarily due to money pool activity which provided $170.1 million of Entergy Gulf States' operating cash flows for the nine months ended September 30, 2004 compared to using $46.6 million for the nine months ended September 30, 2003. Also contributing to the increase was decreased vendor payments. Entergy Gulf States' receivables from or (payables to) the money pool were as follows:

September 30,
2004

 

December 31,
2003

 

September 30,
2003

 

December 31,
2002

(In Thousands)

 

 

 

 

 

 

 

($100,722)

 

$69,354

 

$64,773

 

$18,131

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.

Investing Activities

Net cash used in investing activities decreased $67.8 million for the nine months ended September 30, 2004 compared to the same period of 2003 primarily due to a $40.9 million decrease in under-recovered fuel and purchased power expenses in Texas that have been deferred and are being 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. Also contributing to the decrease in cash used in investing activities was the net change in other temporary investments of $31.9 million.

 

Financing Activities

Net cash used in financing activities increased $355.9 million in the nine months ended September 30, 2004 compared to the same period of 2003 primarily due to the net redemption of $338.6 million more in long-term debt in 2004 as well as increased common stock dividend payments of $17.4 million.

Uses and Sources of Capital

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

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

In September 2004, Entergy Gulf States purchased its $62 million 5.65% Series tax-exempt bonds from the holders, pursuant to a mandatory tender provision, and has not remarketed the bonds at this time. Entergy Gulf States used a combination of cash on hand and short-term borrowing to buy-in the bonds.

In October 2004, Entergy Gulf States issued $200 million 4.875% Series of First Mortgage Bonds due November 1, 2011. Entergy Gulf States plans to use the proceeds to redeem, prior to maturity, $200 million 5.2% Series of First Mortgage Bonds due December 3, 2007.

Significant Factors and Known Trends

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.

Rate Proceedings

In June 2004, Entergy Gulf States and Entergy Louisiana filed a proposed settlement with the LPSC that would resolve, among other dockets, Entergy Gulf States' ninth post-merger analysis and dockets established to consider issues concerning the companies' power purchases for the summers of 2001, 2002, and 2003. The proposed settlement included an offer to refund approximately $64 million to Entergy Gulf States' Louisiana customers and $1 million to Entergy Louisiana's customers, with no change in either company's current base rates.  The settlement also proposed a formula rate plan for Entergy Gulf States' Louisiana operations. At its September 2004 Business and Executive Session, the LPSC consolidated various dockets that were the subject of proposed settlement. The LPSC directed its staff to preside over settlement discussions and to submit any proposed settlement to the LPSC for its consideration.

In July 2004, Entergy Gulf States filed with the LPSC an application for a change in its rates and charges seeking an increase of $9.1 million in gas base rates in order to allow Entergy Gulf States an opportunity to earn a fair and reasonable rate of return. Entergy Gulf States is also seeking approval of certain proposed rate design, rate schedule and policy changes. A procedural schedule has not been established.

Transition to Retail Competition

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

In view of the PUCT order of delay in retail open access in the Texas service territory, Entergy Gulf States filed a retail electric rate case and fuel reconciliation proceeding with the PUCT in August 2004 seeking the following:

  • approval of a base rate increase of $42.6 million annually for the Texas retail jurisdiction;
  • approval to implement a $14.1 million per year rider to recover, over a 15-year period, $110.9 million of incurred costs related to its efforts to transition to a competitive retail market in accordance with the Texas restructuring law;
  • proposed $11.3 million franchise fee rider to recover payments to municipalities charging such fees; and
  • a requested return on equity of 11.5%.

In addition, Entergy Gulf States' fuel reconciliation filing made in conjunction with the base rate case seeks to reconcile approximately $288 million in fuel and purchased power costs incurred during the period September 2003 through March 2004. Although the case was initially assigned to the State Office of Administrative Hearings, the PUCT ordered that the case be returned to the PUCT. The PUCT requested that the parties submit briefs addressing threshold issues related to whether Entergy Gulf States has the right to file a base rate case and what relief is available, if the PUCT were to determine that Entergy Gulf States' base rates are subject to the rate freeze imposed in December 2001 in connection with the market readiness docket initiated by the PUCT Staff. The PUCT considered these issues in September 2004. In October 2004, the PUCT issued a written order in which it dismissed the rate case indicating that Entergy Gulf States is still subject to a rate freeze based on an agreement in 2001 stipulating that a rate freeze would remain in effect until retail open access commenced in Entergy Gulf States' service territory. Entergy Gulf States intends to file a motion for rehearing and intends to pursue other available remedies.

See "Management's Financial Discussion and Analysis - Significant Factors and Known Trends" in the Form 10-K for a discussion of the Entergy Gulf States business separation proceeding at the LPSC. In September 2004, a status conference was held before an ALJ in joint proceedings before the LPSC concerning the proposed jurisdictional separation of Entergy Gulf States. In the status conference, the LPSC staff asserted that uncertainty with respect to retail open access in Texas should not control whether or when the LPSC should require the jurisdictional separation of Entergy Gulf States and recommended that an investigation concerning the proposed jurisdictional separation proceed. A procedural schedule was established and hearings are expected to begin in June 2005. In October 2004, Entergy Gulf States filed a preliminary methodology that could be used to separate Entergy Gulf States into two vertically integrated companies, should its regulators determine that this is in the public interest.

System Agreement Proceedings

See the Form 10-K for a discussion of the proceeding commenced at the FERC by the LPSC regarding production cost equalization under the System Agreement, the ALJ's Initial Decision in the proceeding, and the "Order of Investigation" issued by the APSC. Several parties, including Entergy, the LPSC, the APSC, the MPSC, the City Council, and the FERC Staff, filed briefs on exceptions in response to the ALJ's Initial Decision. Entergy's exceptions to the ALJ's Initial Decision include: the practical effect of the Initial Decision is full production cost equalization, which was rejected in the Initial Decision and previously has been rejected by the FERC; resource planning for the Entergy System would be impeded if the Initial Decision were adopted; the remedy in the Initial Decision is inconsistent with the history, structure, and precedent regarding the System Agreement; the Initial Decision's remedy ignores the historical pattern of production cost disparities on the Entergy System and would result in substantial, sudden transfers of costs between groups of Entergy customers; the numerical standards proposed in the Initial Decision are arbitrary and are so complex that they will be difficult to implement; the Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the full costs of the Vidalia project should be included in Entergy Louisiana's production costs for purposes of calculating relative production costs; and the Initial Decision erroneously adopted a new method of calculating reserve sharing costs rather than the current method.

As reported in the Form 10-K, if the FERC grants the relief requested by the LPSC in the proceeding, the relief may result in a material increase in the total production costs the FERC allocates to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in the total production costs the FERC allocates to companies whose costs currently are projected to exceed that average.   If the FERC adopts the ALJ's Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of Entergy System average total production cost. The ALJ's Initial Decision would reallocate production costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth. This would be accomplished by payments from domestic utility companies whose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost.

An assessment of the potential effects of the ALJ's Initial Decision requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power.  Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation.  Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas' total production costs are below the average production costs of the domestic utility companies.  Considerable uncertainty exists regarding future gas prices. Annual average gas prices have varied significantly over recent years, ranging from $1.92/mmBtu to $5.48/mmBtu for the 1994-2003 period, and averaging $2.99/mmBtu during the ten-year period 1994-2003 and $3.77/mmBtu during the five-year period 1999-2003.  Recent market conditions have resulted in gas prices that have averaged $5.58/MMBtu for the twelve months ended September 2004. Based upon analyses considering the effect on future production costs if the FERC adopts the ALJ's Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could result assuming annual average gas prices range from $6.39/mmBtu in 2005 declining to $4.97/mmBtu by 2009:

 


Range of Annual Payments or (Receipts)

 

Average Annual Payments or (Receipts) for 2005-2009 Period

 

(In Millions)

 

(In Millions)

       

Entergy Arkansas

$154 to $281 

 

$215 

Entergy Gulf States

($130) to ($15)

 

($63)

Entergy Louisiana

($199) to ($98)

 

($141)

Entergy Mississippi

($16) to $8 

 

$1 

Entergy New Orleans

($17) to ($5)

 

($12)

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

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

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

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

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

Critical Accounting Estimates

See "Management's Financial Discussion and Analysis - Critical Accounting Estimates" in the Form 10-K for a discussion of the estimates and judgments necessary in Entergy Gulf States' accounting for nuclear decommissioning costs, the application of SFAS 71, and pension and other postretirement costs.

Nuclear Decommissioning Costs

In the third quarter of 2004, Entergy Gulf States recorded a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for River Bend that reflected a life extension for the plant. The revised estimate resulted in a $116.8 million reduction in decommissioning liability, along with a $31.3 million reduction in utility plant, a $40.1 million reduction in the related regulatory asset and a regulatory liability of $17.7 million. For the portion of River Bend not subject to cost-based ratemaking, the revised estimate resulted in the elimination of the asset retirement cost that had been recorded at the time of adoption of SFAS 143 with the remainder recorded as miscellaneous income of $27.7 million.

ENTERGY GULF STATES, INC.
INCOME STATEMENTS
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
 
  Three Months Ended   Nine Months Ended
    2004   2003   2004   2003
    (In Thousands)   (In Thousands)
                 
OPERATING REVENUES                
Domestic electric   $831,377    $769,326    $2,118,031    $2,015,330 
Natural gas   9,253    7,856    46,908    46,841 
TOTAL   840,630    777,182    2,164,939    2,062,171 
                 
OPERATING EXPENSES                
Operation and Maintenance:                
  Fuel, fuel-related expenses, and                
   gas purchased for resale   249,603    193,692    559,277    516,656 
  Purchased power   263,553    251,372    725,610    661,697 
  Nuclear refueling outage expenses   4,503    3,193    10,868    10,852 
  Other operation and maintenance   110,564    101,435    314,198    304,008 
Decommissioning   3,867    3,567    11,395    10,701 
Taxes other than income taxes   31,001    31,612    88,058    90,414 
Depreciation and amortization   51,924    50,039    146,253    147,941 
Other regulatory credits - net   (2,223)   (3,791)   (8,701)   (1,004)
TOTAL   712,792    631,119    1,846,958    1,741,265 
                 
OPERATING INCOME   127,838    146,063    317,981    320,906 
                 
OTHER INCOME                
Allowance for equity funds used during construction   4,140    4,084    9,187    10,258 
Interest and dividend income   3,058    6,215    10,079    15,182 
Miscellaneous - net   26,284    990    38,780    (108,380)
TOTAL   33,482    11,289    58,046    (82,940)
                 
INTEREST AND OTHER CHARGES  
Interest on long-term debt   29,361    39,433    93,900    113,209 
Other interest - net   1,822    1,477    4,542    4,785 
Allowance for borrowed funds used during construction   (3,076)   (3,410)   (6,843)   (8,651)
TOTAL   28,107    37,500    91,599    109,343 
                 
INCOME BEFORE INCOME TAXES AND                
CUMULATIVE EFFECT OF ACCOUNTING CHANGE   133,213    119,852    284,428    128,623 
                 
Income taxes   50,757    37,569    104,653    33,339 
                 
INCOME BEFORE CUMULATIVE EFFECT                
OF ACCOUNTING CHANGE   82,456    82,283    179,775    95,284 
                 
CUMULATIVE EFFECT OF ACCOUNTING                
CHANGE (net of income taxes of $12,713)         (21,333)
                 
NET INCOME   82,456    82,283    179,775    73,951 
                 
Preferred dividend requirements and other   1,097    1,170    3,370    3,551 
                 
EARNINGS APPLICABLE TO                
COMMON STOCK   $81,359    $81,113    $176,405    $70,400 
                 
See Notes to Respective Financial Statements.                
                 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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ENTERGY GULF STATES, INC.
STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2004 and 2003
(Unaudited)
         
    2004   2003
    (In Thousands)
         
OPERATING ACTIVITIES        
Net income   $179,775    $73,951 
Noncash items included in net income:        
  Reserve for regulatory adjustments   12,406    (9,806)
  Other regulatory credits   (8,701)   (1,004)
  Depreciation, amortization, and decommissioning   157,648    158,642 
  Deferred income taxes and investment tax credits   21,796    (18,240)
  Cumulative effect of accounting change    -    21,333 
Changes in working capital:        
  Receivables   (73,723)   (141,817)
  Fuel inventory   3,934    (5,058)
  Accounts payable   90,932    (88,109)
  Taxes accrued   117,049    72,234 
  Interest accrued   (4,386)   5,020 
  Deferred fuel costs   57,680    30,253 
  Other working capital accounts   5,852    12,353 
Provision for estimated losses and reserves   (12,253)   108,196 
Changes in other regulatory assets   (2,427)   27,253 
Other   (41,920)   (25,389)
Net cash flow provided by operating activities   503,662    219,812 
         
INVESTING ACTIVITIES        
Construction expenditures   (241,828)   (234,689)
Allowance for equity funds used during construction   9,187    10,258 
Nuclear fuel purchases   (12,551)   (39,959)
Proceeds from sale/leaseback of nuclear fuel   12,549    38,029 
Decommissioning trust contributions and realized        
  change in trust assets   (8,700)   (9,862)
Changes in other temporary investments - net   23,579    (8,403)
Other regulatory investments   (45,926)   (86,854)
Net cash flow used in investing activities   (263,690)   (331,480)
         
FINANCING ACTIVITIES        
Proceeds from the issuance of long-term debt   -    1,032,778 
Retirement of long-term debt   (354,000)   (1,048,129)
Redemption of preferred stock   (3,450)   (3,450)
Dividends paid:        
  Common stock   (74,100)   (56,700)
  Preferred stock   (3,370)   (3,551)
Net cash flow used in financing activities   (434,920)   (79,052)
         
Net decrease in cash and cash equivalents   (194,948)   (190,720)
         
Cash and cash equivalents at beginning of period   206,030    318,404 
         
Cash and cash equivalents at end of period   $11,082    $127,684 
         
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:        
Cash paid/(received) during the period for:        
  Interest - net of amount capitalized   $97,688    $108,423 
  Income taxes   -    ($5,180)
         
See Notes to Respective Financial Statements.        
         

 

ENTERGY GULF STATES, INC.
BALANCE SHEETS
ASSETS
September 30, 2004 and December 31, 2003
(Unaudited)
         
    2004   2003
  (In Thousands)
       
CURRENT ASSETS            
Cash and cash equivalents:            
  Cash       $10,139    $20,754 
  Temporary cash investments - at cost,            
   which approximates market       943    185,276 
     Total cash and cash equivalents       11,082    206,030 
  Other temporary investments         23,579 
  Accounts receivable:            
    Customer       177,844    115,729 
    Allowance for doubtful accounts       (4,578)   (4,856)
    Associated companies       19,536    76,726 
    Other       65,202    27,243 
    Accrued unbilled revenues       145,003    114,442 
     Total accounts receivable       403,007    329,284 
Deferred fuel costs       106,695    118,449 
Accumulated deferred income taxes       10,952    6,116 
Fuel inventory - at average cost       46,929    50,863 
Materials and supplies - at average cost       107,262    99,357 
Prepayments and other       27,605    51,236 
TOTAL       713,532    884,914 
             
OTHER PROPERTY AND INVESTMENTS        
Decommissioning trust funds       281,745    267,917 
Non-utility property - at cost (less accumulated depreciation)       92,224    139,911 
Other       21,965    21,852 
TOTAL       395,934    429,680 
             
UTILITY PLANT        
Electric       8,346,214    8,208,394 
Property under capital lease       1,858    11,009 
Natural gas       76,769    69,180 
Construction work in progress       311,628    325,888 
Nuclear fuel under capital lease       74,358    63,684 
TOTAL UTILITY PLANT       8,810,827    8,678,155 
Less - accumulated depreciation and amortization       4,020,113    3,953,275 
UTILITY PLANT - NET       4,790,714    4,724,880 
             
DEFERRED DEBITS AND OTHER ASSETS        
Regulatory assets:            
  SFAS 109 regulatory asset - net       442,121    442,062 
  Other regulatory assets       281,745    320,363 
Long-term receivables       24,648    19,375 
Other       38,430    33,588 
TOTAL       786,944    815,388 
             
TOTAL ASSETS       $6,687,124    $6,854,862 
             
See Notes to Respective Financial Statements.            
 
 
 
ENTERGY GULF STATES, INC.
BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
September 30, 2004 and December 31, 2003
(Unaudited)
 
    2004   2003
  (In Thousands)
 
CURRENT LIABILITIES        
Currently maturing long-term debt       $98,000   $354,000
Accounts payable:            
  Associated companies       179,872   84,000
  Other       151,620   156,166
Customer deposits       51,796   47,044
Taxes accrued       20,780   -
Nuclear refueling outage costs       18,126   8,238
Interest accrued       32,190   36,970
Obligations under capital leases       28,446   34,075
Other       14,020   14,755
TOTAL       594,850   735,248
             
NON-CURRENT LIABILITIES        
Accumulated deferred income taxes and taxes accrued       1,522,000   1,422,776
Accumulated deferred investment tax credits       140,043   144,323
Obligations under capital leases       54,002   40,618
Other regulatory liabilities       36,890   13,885
Decommissioning and retirement cost liabilities       148,816   298,785
Transition to competition       79,098   79,098
Regulatory reserves       69,749   57,343
Accumulated provisions       67,253   75,868
Long-term debt       1,891,435   1,989,613
Preferred stock with sinking fund       17,402   20,852
Other       224,013   233,985
TOTAL       4,250,701   4,377,146
             
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 2004 and 2003       114,055   114,055
Paid-in capital       1,157,484   1,157,484
Retained earnings       521,995   419,690
Accumulated other comprehensive income       712   3,912
TOTAL       1,841,573   1,742,468
             
Commitments and Contingencies            
             
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY       $6,687,124   $6,854,862
             
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, 2004 and 2003
(Unaudited)
                     
         
        Three Months Ended
        2004   2003
        (In Thousands)
RETAINED EARNINGS                    
Retained Earnings - Beginning of period       $483,836        $422,116    
                     
  Add: Net Income       82,456    $82,456   82,283   $82,283
                     
  Deduct:                    
    Dividends declared on common stock       43,200        39,600    
    Preferred dividend requirements and other       1,097    1,097    1,170   1,170
        44,297        40,770    
                     
Retained Earnings - End of period       $521,995        $463,629    
                     
ACCUMULATED OTHER COMPREHENSIVE                    
INCOME (Net of Taxes):                    
Balance at beginning of period:                    
  Accumulated derivative instrument fair value changes       $4,168        $2,753    
                     
Net derivative instrument fair value changes                    
 arising during the period       (3,456)   (3,456)   169   169
                     
Balance at end of period:                    
  Accumulated derivative instrument fair value changes       $712        $2,922    
Comprehensive Income           $77,903        $81,282
                     
                     
        Nine Months Ended
        2004   2003
        (In Thousands)
RETAINED EARNINGS                    
Retained Earnings - Beginning of period       $419,690        $449,929     
                     
  Add: Net Income       179,775    $179,775    73,951    $73,951 
                     
  Deduct:                    
    Dividends declared on common stock       74,100        56,700     
    Preferred dividend requirements and other       3,370    3,370    3,551    3,551 
        77,470        60,251     
                     
Retained Earnings - End of period       $521,995       
$463,629 
   
                     
ACCUMULATED OTHER COMPREHENSIVE                    
INCOME (Net of Taxes):                    
Balance at beginning of period:                    
  Accumulated derivative instrument fair value changes       $3,912        $3,286     
                     
Net derivative instrument fair value changes                    
 arising during the period       (3,200)   (3,200)   (364)   (364)
                     
Balance at end of period:                    
  Accumulated derivative instrument fair value changes       $712        $2,922     
Comprehensive Income          
$173,205 
     
$70,036 
                     
                     
See Notes to Respective Financial Statements.                    

 

ENTERGY GULF STATES, INC.
SELECTED OPERATING RESULTS
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
 
                 
    Three Months Ended   Increase/    
Description   2004   2003   (Decrease)   %
    (In Millions)        
Electric Operating Revenues:                
  Residential   $297   $284   $13    5 
  Commercial   196   183   13    7 
  Industrial   263   228   35    15 
  Governmental   10   10   -     - 
    Total retail   766   705   61    9 
  Sales for resale                
    Associated companies   18   19   (1)   (5)
    Non-associated companies   40   35   5    14 
  Other   7   10   (3)   (30)
     Total   $831   $769   $62    8 
                 
Billed Electric Energy                
 Sales (GWh):                
  Residential   3,225   3,173   52    2 
  Commercial   2,443   2,333   110    5 
  Industrial   4,254   3,889   365    9 
  Governmental   111   115   (4)   (3)
    Total retail   10,033   9,510   523    5 
  Sales for resale                
    Associated companies   617   682   (65)   (10)
    Non-associated companies   653   564   89    16 
     Total   11,303   10,756   547    5 
                 
                 
    Nine Months Ended   Increase/    
Description   2004   2003   (Decrease)   %
    (In Millions)        
Electric Operating Revenues:                
  Residential   $666   $646   $20    3 
  Commercial   493   461   32    7 
  Industrial   708   640   68    11 
  Governmental   28   30   (2)   (7)
    Total retail   1,895   1,777   118    7 
  Sales for resale                
    Associated companies   39   34   5    15 
    Non-associated companies   132   122   10    8 
  Other   52   82   (30)   (37)
     Total   $2,118   $2,015   $103    5 
                 
Billed Electric Energy                
 Sales (GWh):                
  Residential   7,481   7,599   (118)   (2)
  Commercial   6,290   6,147   143    2 
  Industrial   12,226   11,488   738    6 
  Governmental   325   363   (38)   (10)
    Total retail   26,322   25,597   725    3 
  Sales for resale                
    Associated companies   1,167   943   224    24 
    Non-associated companies   2,659   2,639   20    1 
    Total   30,148   29,179   969    3 
                 

 

ENTERGY LOUISIANA, INC.

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

 

Results of Operations

Net Income

Third Quarter 2004 Compared to Third Quarter 2003

Net income decreased $12.4 million primarily due to decreased net revenue and increased other operation and maintenance expenses.

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

Net income decreased $37.0 million primarily due to decreased net revenue and increased other operation and maintenance expenses, partially offset by decreased interest charges.

Net Revenue

Third Quarter 2004 Compared to Third Quarter 2003

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

 

 

Amount

 

 

(In Millions)

 

 

 

2003 net revenue

 

$268.4 

Volume/weather

 

(8.9)

Other

 

(2.3)

2004 net revenue

 

$257.2 

The volume/weather variance resulted primarily from the effect of milder weather on sales during the third quarter of 2004 compared to the third quarter of 2003, partially offset by increased usage of 104 GWh in the industrial sector.

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

Gross operating revenues increased primarily due to an increase of $28.8 million in fuel cost recovery revenues due to higher fuel rates, partially offset by a decrease of $8.9 million due to unfavorable weather/volume, as discussed above.

Fuel and purchased power expenses increased primarily due to:

    • increased recovery of deferred fuel and purchased power costs; and
    • an increase in the market prices of natural gas, oil, and purchased power.

Other regulatory credits increased primarily due to the deferral in the third quarter of 2004 of $5.8 million of capacity charges related to generation resource planning as allowed by the LPSC.

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

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

 

 

Amount

 

 

(In Millions)

 

 

 

2003 net revenue

 

$758.9 

Price applied to unbilled sales

 

(29.8)

Deferred fuel cost revisions

 

(29.4)

Summer capacity charges

 

11.8 

Other

 

(4.0)

2004 net revenue

 

$707.5 

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

The deferred fuel cost revisions variance resulted from a revised unbilled sales pricing estimate made in the first quarter of 2003 to more closely align the fuel component of that pricing with expected recoverable fuel costs.

The summer capacity charges variance is due to the amortization in 2003 of deferred capacity charges for the summer of 2001 compared to the absence of the amortization in 2004. The amortization of these capacity charges began in August 2002 and ended in July 2003.

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

Gross operating revenues increased primarily due to an increase of $87.0 million in fuel cost recovery revenues due to higher fuel rates. The increase was partially offset by the following:

    • a decrease of $29.8 million in the price applied to unbilled sales, as discussed above; and
    • a decrease of $22.4 million in gross wholesale revenue due to decreased sales to affiliated systems.

Fuel and purchased power expenses increased primarily due to:

    • increased recovery of deferred fuel and purchased power costs; and
    • an increase in the market prices of natural gas and purchased power.

Other regulatory charges decreased primarily due to:

    • the amortization in 2003 of $11.8 million of deferred capacity charges, as discussed above; and
    • the deferral in 2004 of $11.6 million of capacity charges related to generation resource planning as allowed by the LPSC.

Other Income Statement Variances

Third Quarter 2004 Compared to Third Quarter 2003

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

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

Other operation and maintenance expenses increased primarily due to:

    • an increase in customer service support costs; and
    • an increase in benefit costs.

Interest charges decreased primarily due to the redemption of $150 million of First Mortgage Bonds in June 2003, partially offset by the issuance of $100 million of First Mortgage Bonds in March 2004.

Income Taxes

The effective income tax rates for the third quarters of 2004 and 2003 were 38.6% and 39.4%, respectively. The effective income tax rates for the nine months ended September 30, 2004 and 2003 were 38.3% and 39.1%, respectively. The differences in the effective income tax rates for the third quarter of 2004 and the nine months ended September 30, 2004 versus the federal statutory rate of 35% are primarily due to book and tax differences related to utility plant items and state income taxes, partially offset by the amortization of investment tax credits. The differences in the effective income tax rates for the third quarter and nine months ended September 30, 2003 are primarily due to book and tax differences related to utility plant items and state income taxes.

Liquidity and Capital Resources

Cash Flow

Cash flows for the nine months ended September 30, 2004 and 2003 were as follows:

 

 

2004

 

2003

 

 

(In Thousands)

 

 

 

 

 

Cash and cash equivalents at beginning of period

 

$8,787 

 

$311,800 

 

 

 

 

 

Cash flow provided by (used in):

 

 

 

 

 

Operating activities

 

214,798 

 

260,919 

 

Investing activities

 

(154,928)

 

(173,411)

 

Financing activities

 

(17,385)

 

(331,051)

Net increase (decrease) in cash and cash equivalents

 

42,485 

 

(243,543)

 

 

 

 

 

Cash and cash equivalents at end of period

 

$51,272 

 

$68,257 

Operating Activities

Cash flow from operations decreased $46.1 million for the nine months ended September 30, 2004 compared to the nine months ended September 30, 2003 primarily due to money pool activity, which used $107.1 million of Entergy Louisiana's operating cash flows in the first nine months of 2004 compared to using $15.4 million in the first nine months of 2003. The decrease was partially offset by the increased collection of deferred fuel costs. Entergy Louisiana's receivables from or (payables to) the money pool were as follows:

September 30,
2004

 

December 31,
2003

 

September 30,
2003

 

December 31,
2002

(In Thousands)

 

 

 

 

 

 

 

$65,773

 

($41,317)

 

$34,260

 

$18,854

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.

Investing Activities

Cash used by investing activities decreased $18.5 million for the nine months ended September 30, 2004 compared to the nine months ended September 30, 2003 primarily due to decreased spending on distribution, transmission, and nuclear projects, partially offset by increased spending at certain fossil plants.

Financing Activities

Cash used by financing activities decreased $313.7 million for the nine months ended September 30, 2004 compared to the nine months ended September 30, 2003 primarily due to:

    • the issuance of $100 million of 5.5% Series First Mortgage Bonds in March 2004;
    • the retirement of $150 million of 8.5% Series First Mortgage Bonds in June 2003;
    • a principal payment of $14.8 million in 2004 for the Waterford Lease Obligation compared to a principal payment of $35.4 million in 2003; and
    • a decrease of $43.9 million in common stock dividends paid.

Uses and Sources of Capital

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

Entergy Louisiana now expects to complete the purchase of the Perryville plant in mid-2005 for $183.5 million. Therefore, Entergy Louisiana now expects to spend approximately $271 million for construction and capital investment in 2004 and approximately $559 million for construction and capital investment in 2005-2006.

In May 2004, Entergy Louisiana extended the maturity date of its 364-day credit facility from May 2004 to July 2004. In July 2004, Entergy Louisiana renewed the facility and Entergy New Orleans entered into a separate credit facility with the same lender. Both facilities will expire in April 2005. Entergy Louisiana can borrow up to $15 million and Entergy New Orleans can borrow up to $14 million under their respective credit facilities, but at no time can the total amount borrowed under these facilities by the two companies combined exceed $15 million. As of September 30, 2004, no borrowings were outstanding under these facilities.

In October 2004, Entergy Louisiana issued $70 million 6.40% Series of First Mortgage Bonds due October 1, 2034. Entergy Louisiana plans to use the proceeds to redeem in November 2004 $72.2 million 9.0% Series Junior Subordinated Deferrable Interest Debentures due 2045.

In October 2004, Entergy Louisiana issued $115 million 5.09% Series of First Mortgage Bonds due November 1, 2014. Entergy Louisiana plans to use the proceeds to redeem, prior to maturity, $115 million 6.5% Series of First Mortgage Bonds due March 1, 2008.

Significant Factors and Known Trends

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

Rate Proceedings

See "Management's Financial Discussion and Analysis - Rate Proceedings" in the Form 10-K for discussion of Entergy Louisiana's rate filing with the LPSC requesting a base rate increase. In August 2004, the LPSC Staff filed testimony in which it recommended up to a $19.5 million rate increase for Entergy Louisiana, assuming that the Perryville acquisition is approved in time for the Perryville costs to be included in rates set in this proceeding. Additional issues and updates that will be evaluated in connection with this proceeding are likely to result in revisions to the LPSC Staff's recommendation.  These issues may reduce the amount of the recommended rate increase or cause it to become a recommendation for a rate decrease. Hearings are currently set for December 2004.

System Agreement Proceedings

See the Form 10-K for a discussion of the proceeding commenced at the FERC by the LPSC regarding production cost equalization under the System Agreement, the ALJ's Initial Decision in the proceeding, and the "Order of Investigation" issued by the APSC. Several parties, including Entergy, the LPSC, the APSC, the MPSC, the City Council, and the FERC Staff, filed briefs on exceptions in response to the ALJ's Initial Decision. Entergy's exceptions to the ALJ's Initial Decision include: the practical effect of the Initial Decision is full production cost equalization, which was rejected in the Initial Decision and previously has been rejected by the FERC; resource planning for the Entergy System would be impeded if the Initial Decision were adopted; the remedy in the Initial Decision is inconsistent with the history, structure, and precedent regarding the System Agreement; the Initial Decision's remedy ignores the historical pattern of production cost disparities on the Entergy System and would result in substantial, sudden transfers of costs between groups of Entergy customers; the numerical standards proposed in the Initial Decision are arbitrary and are so complex that they will be difficult to implement; the Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the full costs of the Vidalia project should be included in Entergy Louisiana's production costs for purposes of calculating relative production costs; and the Initial Decision erroneously adopted a new method of calculating reserve sharing costs rather than the current method.

As reported in the Form 10-K, if the FERC grants the relief requested by the LPSC in the proceeding, the relief may result in a material increase in the total production costs the FERC allocates to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in the total production costs the FERC allocates to companies whose costs currently are projected to exceed that average.   If the FERC adopts the ALJ's Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of Entergy System average total production cost. The ALJ's Initial Decision would reallocate production costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth. This would be accomplished by payments from domestic utility companies whose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost.

An assessment of the potential effects of the ALJ's Initial Decision requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power.  Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation.  Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas' total production costs are below the average production costs of the domestic utility companies.  Considerable uncertainty exists regarding future gas prices. Annual average gas prices have varied significantly over recent years, ranging from $1.92/mmBtu to $5.48/mmBtu for the 1994-2003 period, and averaging $2.99/mmBtu during the ten-year period 1994-2003 and $3.77/mmBtu during the five-year period 1999-2003.  Recent market conditions have resulted in gas prices that have averaged $5.58/MMBtu for the twelve months ended September 2004. Based upon analyses considering the effect on future production costs if the FERC adopts the ALJ's Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could result assuming annual average gas prices range from $6.39/mmBtu in 2005 declining to $4.97/mmBtu by 2009:

 


Range of Annual Payments or (Receipts)

 

Average Annual Payments or (Receipts) for 2005-2009 Period

 

(In Millions)

 

(In Millions)

       

Entergy Arkansas

$154 to $281 

 

$215 

Entergy Gulf States

($130) to ($15)

 

($63)

Entergy Louisiana

($199) to ($98)

 

($141)

Entergy Mississippi

($16) to $8 

 

$1 

Entergy New Orleans

($17) to ($5)

 

($12)

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

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

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

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

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

Critical Accounting Estimates

See "Management's Financial Discussion and Analysis - Critical Accounting Estimates" in the Form 10-K for a discussion of the estimates and judgments necessary in Entergy Louisiana's accounting for nuclear decommissioning costs and pension and other retirement costs.

ENTERGY LOUISIANA, INC.
INCOME STATEMENTS
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
 
  Three Months Ended   Nine Months Ended
    2004   2003   2004   2003
    (In Thousands)   (In Thousands)
                 
OPERATING REVENUES                
Domestic electric   $668,240    $646,503    $1,711,797    $1,678,444 
                 
OPERATING EXPENSES                
Operation and Maintenance:                
  Fuel, fuel-related expenses, and                
   gas purchased for resale   249,879    198,955    517,543    417,953 
  Purchased power   173,732    184,250    509,564    500,152 
  Nuclear refueling outage expenses   3,500    2,745    10,132    8,235 
  Other operation and maintenance   90,703    85,626    262,072    250,198 
Decommissioning   5,534    5,142    16,333    15,427 
Taxes other than income taxes   19,262    18,240    53,595    52,754 
Depreciation and amortization   51,051    48,439    145,588    143,411 
Other regulatory charges (credits) - net   (12,551)   (5,126)   (22,835)   1,416 
TOTAL   581,110    538,271    1,491,992    1,389,546 
                 
OPERATING INCOME   87,130    108,232    219,805    288,898 
                 
OTHER INCOME                
Allowance for equity funds used during construction   2,606    1,962    5,475    5,095 
Interest and dividend income   1,831    1,333    5,489    6,865 
Miscellaneous - net   (531)   (871)   (387)   (2,746)
TOTAL   3,906    2,424    10,577    9,214 
                 
INTEREST AND OTHER CHARGES  
Interest on long-term debt   17,655    16,036    51,991    57,686 
Other interest - net   894    831    2,952    2,497 
Allowance for borrowed funds used during construction   (1,569)   (1,629)   (3,450)   (3,970)
TOTAL   16,980    15,238    51,493    56,213 
                 
INCOME BEFORE INCOME TAXES   74,056    95,418    178,889    241,899 
                 
Income taxes   28,560    37,555    68,468    94,516 
                 
NET INCOME   45,496    57,863    110,421    147,383 
                 
Preferred dividend requirements and other   1,678    1,678    5,035    5,035 
                 
EARNINGS APPLICABLE TO                
COMMON STOCK   $43,818    $56,185    $105,386    $142,348 
                 
See Notes to Respective Financial Statements.                

 

ENTERGY LOUISIANA, INC.
STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2004 and 2003
(Unaudited)
         
    2004   2003
    (In Thousands)
         
OPERATING ACTIVITIES        
Net income   $110,421    $147,383 
Noncash items included in net income:        
  Other regulatory charges (credits) - net   (22,835)   1,416 
  Depreciation, amortization, and decommissioning   161,921    158,838 
  Deferred income taxes and investment tax credits   12,133    786,652 
Changes in working capital:        
  Receivables   (92,848)   (84,832)
  Accounts payable   (78,456)   (23,120)
  Taxes accrued   94,398    (658,113)
  Interest accrued   (3,258)   (10,646)
  Deferred fuel costs   35,725    (61,672)
  Other working capital accounts   (2,404)   19,514 
Provision for estimated losses and reserves   5,181    7,628 
Changes in other regulatory assets   (12,031)   16,174 
Other   6,851    (38,303)
Net cash flow provided by operating activities   214,798    260,919 
         
INVESTING ACTIVITIES        
Construction expenditures   (149,184)   (162,944)
Allowance for equity funds used during construction   5,475    5,095 
Nuclear fuel purchases    -    (32,241)
Proceeds from the sale/leaseback of nuclear fuel     32,241 
Decommissioning trust contributions and realized        
 change in trust assets   (11,219)   (11,118)
Changes in other temporary investments     (4,444)
Net cash flow used in investing activities   (154,928)   (173,411)
         
FINANCING ACTIVITIES        
Proceeds from the issuance of long-term debt   99,159    - 
Retirement of long-term debt   (14,809)   (185,416)
Dividends paid:        
  Common stock   (96,700)   (140,600)
  Preferred stock   (5,035)   (5,035)
Net cash flow used in financing activities   (17,385)   (331,051)
         
Net increase (decrease) in cash and cash equivalents   42,485    (243,543)
         
Cash and cash equivalents at beginning of period   8,787    311,800 
         
Cash and cash equivalents at end of period   $51,272    $68,257 
         
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:        
Cash paid during the period for:        
  Interest - net of amount capitalized   $56,217    $47,234 
         
See Notes to Respective Financial Statements.        

 

ENTERGY LOUISIANA, INC.
BALANCE SHEETS
ASSETS
September 30, 2004 and December 31, 2003
(Unaudited)
     
    2004   2003
  (In Thousands)
         
CURRENT ASSETS        
Cash and cash equivalents:        
  Cash   $4,178    $8,787 
  Temporary cash investments - at cost,        
   which approximates market   47,094   
     Total cash and cash equivalents   51,272    8,787 
Accounts receivable:        
  Customer   131,486    93,393 
  Allowance for doubtful accounts   (3,545)   (4,487)
  Associated companies   66,749    9,074 
  Other   6,038    12,334 
  Accrued unbilled revenues   140,598    138,164 
     Total accounts receivable   341,326    248,478 
Deferred fuel costs     30,609 
Accumulated deferred income taxes   13,899   
Materials and supplies - at average cost   79,215    74,349 
Deferred nuclear refueling outage costs   9,112    19,226 
Prepayments and other   45,411    67,623 
TOTAL   540,235    449,072 
         
OTHER PROPERTY AND INVESTMENTS        
Investment in affiliates - at equity   14,230    14,230 
Decommissioning trust funds   165,564    151,996 
Non-utility property - at cost (less accumulated depreciation)   21,208    21,307 
Other   2,169    2,177 
TOTAL   203,171    189,710 
         
UTILITY PLANT        
Electric   5,967,419    5,836,914 
Property under capital lease   250,102    250,102 
Construction work in progress   150,273    172,405 
Nuclear fuel under capital lease   40,073    65,066 
TOTAL UTILITY PLANT   6,407,867    6,324,487 
Less - accumulated depreciation and amortization   2,786,871    2,686,778 
UTILITY PLANT - NET   3,620,996    3,637,709 
         
DEFERRED DEBITS AND OTHER ASSETS        
Regulatory assets:        
  SFAS 109 regulatory asset - net   157,602    156,111 
  Other regulatory assets   234,659    217,689 
Long-term receivables   10,140    1,511 
Other   22,113    22,737 
TOTAL   424,514    398,048 
         
TOTAL ASSETS   $4,788,916    $4,674,539 
         
See Notes to Respective Financial Statements.        
 
 
 
ENTERGY LOUISIANA, INC.
BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
September 30, 2004 and December 31, 2003
(Unaudited)
 
    2004   2003
  (In Thousands)
 
CURRENT LIABILITIES        
Currently maturing long-term debt   $55,000    $14,809 
Accounts payable:        
  Associated companies   40,535    101,191 
  Other   104,075    121,875 
Customer deposits   63,909    61,215 
Accumulated deferred income taxes     566 
Interest accrued   16,971    20,229 
Deferred fuel costs   5,116   
Obligations under capital leases   35,506    35,506 
Other   6,987    5,110 
TOTAL   328,099    360,501 
         
NON-CURRENT LIABILITIES        
Accumulated deferred income taxes and taxes accrued   1,818,503    1,728,156 
Accumulated deferred investment tax credits   97,412    101,258 
Obligations under capital leases   4,567    29,560 
Other regulatory liabilities   16,610    12,204 
Decommissioning and retirement cost liabilities   372,148    352,120 
Accumulated provisions   91,715    86,534 
Long-term debt   932,739    887,687 
Other   49,899    47,981 
TOTAL   3,383,593    3,245,500 
         
         
SHAREHOLDERS' EQUITY        
Preferred stock without sinking fund   100,500    100,500 
Common stock, no par value, authorized 250,000,000        
 shares; issued 165,173,180 shares in 2004 and 2003   1,088,900    1,088,900 
Capital stock expense and other   (1,718)   (1,718)
Retained earnings   9,542    856 
Less - treasury stock, at cost (18,202,573 shares in 2004 and 2003)   120,000    120,000 
TOTAL   1,077,224    1,068,538 
         
Commitments and Contingencies        
         
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY   $4,788,916    $4,674,539 
         
See Notes to Respective Financial Statements.        

 

ENTERGY LOUISIANA, INC.
SELECTED OPERATING RESULTS
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
 
                 
    Three Months Ended   Increase/    
Description   2004   2003   (Decrease)   %
    (In Millions)        
Electric Operating Revenues:                
  Residential   $266    $251   $15   
  Commercial   149    138   11   
  Industrial   212    199   13   
  Governmental   10    12   (2)   (17)
     Total retail   637    600   37   
  Sales for resale                
    Associated companies   38    38    
    Non-associated companies     4   (1)   (25)
  Other   (10)   5   (15)   (300)
     Total   $668    $647   $21   
                 
Billed Electric Energy                
 Sales (GWh):                
  Residential   2,907    2,811   96   
  Commercial   1,684    1,611   73   
  Industrial   3,430    3,326   104   
  Governmental   115    135   (20)   (15)
     Total retail   8,136    7,883   253   
  Sales for resale                
    Associated companies   483    533   (50)   (9)
    Non-associated companies   43    44   (1)   (2)
     Total   8,662    8,460   202   
                 
                 
    Nine Months Ended   Increase/    
Description   2004   2003   (Decrease)   %
    (In Millions)        
Electric Operating Revenues:                
  Residential   $598   $575   $23   
  Commercial   380   356   24   
  Industrial   589   541   48   
  Governmental   28   32   (4)   (13)
     Total retail   1,595   1,504   91   
  Sales for resale                
    Associated companies   75   98   (23)   (23)
    Non-associated companies   10   10    
  Other   32   66   (34)   (52)
     Total   $1,712   $1,678   $34   
                 
Billed Electric Energy                
 Sales (GWh):                
  Residential   6,802   6,847   (45)   (1)
  Commercial   4,324   4,230   94   
  Industrial   9,836   9,668   168   
  Governmental   328   390   (62)   (16)
     Total retail   21,290   21,135   155   
  Sales for resale                
    Associated companies   905   1,321   (416)   (31)
    Non-associated companies   147   113   34    30 
     Total   22,342   22,569   (227)   (1)
                 
                 

ENTERGY MISSISSIPPI, INC.

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

 

Results of Operations

Net Income

Third Quarter 2004 Compared to Third Quarter 2003

Net income increased $2.1 million primarily due to increased net revenue, partially offset by an increase in other operation and maintenance expenses.

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

Net income decreased $3.2 million primarily due to increases in other operation and maintenance expenses and taxes other than income taxes, partially offset by increases in net revenue and interest and dividend income.

Net Revenue

Third Quarter 2004 Compared to Third Quarter 2003

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

   

Amount

   

(In Millions)

     

2003 net revenue

 

$124.6 

Price applied to unbilled sales

 

4.4 

Net wholesale revenue

 

3.5 

Volume/weather

 

(2.2)

Other

 

0.6 

2004 net revenue

 

$130.9 

The price applied to unbilled sales variance resulted primarily from an increase in Grand Gulf price applied to unbilled sales.

The net wholesale revenue variance resulted from increased net generation resulting in more energy available for resale sales, partially offset by a decrease in the average price of energy supplied to affiliated sales.

The volume/weather variance resulted primarily from decreased usage due to the effect of milder weather on sales as compared to the same period in 2003.

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

Gross operating revenues increased primarily due to an increase in fuel cost recovery revenues due to higher fuel rates, along with net revenue items described above. This increase was partially offset by a decrease of $6.3 million in Grand Gulf revenue as a result of the cessation of the Grand Gulf Accelerated Tariff in July 2003.

Fuel and purchased power expenses increased primarily due to increased recovery of fuel and purchased power costs.

Other regulatory charges decreased as a result of decreased recovery of deferred capacity charges related to the Grand Gulf rate rider.

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

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

   

Amount

   

(In Millions)

     

2003 net revenue

 

$329.5 

Net wholesale revenue

 

2.4 

Volume/weather

 

2.0 

Other

 

1.0 

2004 net revenue

 

$334.9 

The net wholesale revenue variance resulted from an increase in energy available for resale sales, partially offset by a decrease in the average price of energy supplied for affiliated sales.

The volume/weather variance resulted from an increase in weather-adjusted usage of 117 GWh, partially offset by the effect of milder weather on billed sales.

Gross operating revenues and fuel and purchased power expenses

Gross operating revenues increased primarily due to an increase of $130.4 million in fuel cost recovery revenues due to higher fuel rates, along with the net revenue items described above. This increase was partially offset by a decrease of $39.3 million in Grand Gulf revenue as a result of the cessation of the Grand Gulf Accelerated Tariff in July 2003.

Fuel and purchased power expenses increased primarily due to an increase in recovery of fuel and purchased power costs, an increase in electric net generation, and an increase in the market prices of natural gas, oil, and non-associated purchased power.

Other Income Statement Variances

Third Quarter 2004 Compared to Third Quarter 2003

Other operation and maintenance expenses increased primarily due to an increase of $1.4 million in plant maintenance expenses and an increase of $1.0 million in pension costs.

Taxes other than income taxes increased primarily due to a higher assessment of ad valorem and franchise taxes compared to the same period in 2003.

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

Other operation and maintenance expenses increased primarily due to:

    • an increase of $6.0 million in customer service costs; and
    • an increase of $1.4 million in plant maintenance expenses.

Taxes other than income taxes increased primarily due to a higher assessment of ad valorem and franchise taxes compared to the same period in 2003.

Other income increased primarily due to increased interest income on the deferred fuel balance.

Interest and other charges decreased primarily due to redemption of $330 million of First Mortgage Bonds during the nine months ended September 30, 2003, partially offset by the issuance of $180 million of First Mortgage Bonds during the nine months ended September 30, 2004.

Income Taxes

The effective income tax rates for the third quarters of 2004 and 2003 were 36.7% and 39.5%, respectively. The effective income tax rates for the nine months ended September 30, 2004 and 2003 were 36.2% and 37.3%, respectively.

Liquidity and Capital Resources

Cash Flow

Cash flows for the nine months ended September 30, 2004 and 2003 were as follows:

 

 

2004

 

2003

 

 

(In Thousands)

 

 

 

 

 

Cash and cash equivalents at beginning of period

 

$63,838 

 

$147,721 

 

 

 

 

 

Cash flow provided by (used in):

 

 

 

 

 

Operating activities

 

123,086 

 

131,932 

 

Investing activities

 

(102,830)

 

(198,306)

 

Financing activities

 

(51,813)

 

(66,701)

Net decrease in cash and cash equivalents

 

(31,557)

 

(133,075)

 

 

 

 

 

Cash and cash equivalents at end of period

 

$32,281 

 

$14,646 

Operating Activities

Cash flow from operations decreased $8.8 million for the nine months ended September 30, 2004 compared to the nine months ended September 30, 2003 primarily due to money pool activities, partially offset by increased recovery of deferred fuel and purchased power costs.

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

September 30,
2004

 

December 31,
2003

 

September 30,
2003

 

December 31,
2002

(In Thousands)

 

 

 

 

 

 

 

$39,510

 

$22,076

 

($19,277)

 

$8,702

Money pool activity used $17.4 million of Entergy Mississippi's cash flow for the nine months ended September 30, 2004 compared to providing $28 million for the nine months ended September 30, 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.

Investing Activities

Net cash used in investing activities decreased $95.5 million for the nine months ended September 30, 2004 compared to the nine months ended September 30, 2003 primarily due to cash used in 2003 for other regulatory investments of $72.6 million as a result of under-recovered fuel and purchased power costs. Also contributing to the decrease in cash used was decreased capital expenditures of $15 million and other temporary investment of $7.5 million that provided cash upon maturity.

Financing Activities

Net cash used in financing activities decreased $14.9 million for the nine months ended September 30, 2004 compared to the nine months ended September 30, 2003 primarily due to a $25 million draw on Entergy Mississippi's short-term bank credit facility, partially offset by increased dividends paid.

Uses and Sources of Capital

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

Entergy Mississippi issued $180 million of First Mortgage Bonds in 2004 as follows:

Issue Date

 

Description

 

Maturity

 

Amount

           

(In Thousands)

 

 

 

 

 

 

 

April 2004

 

6.25% Series

 

April 2034

 

$100,000

April 2004

 

4.65% Series

 

May 2011

 

80,000

 

 

 

 

 

 

$180,000

In September 2004, Entergy Mississippi issued $16 million of Mississippi Business Finance Corporation 4.60% Series Pollution Control Revenue Refunding Bonds (Entergy Mississippi, Inc Project) Series 2004 due April 2022. The proceeds from this issuance were used to redeem, prior to maturity, $7.9 million of 7.0% Series Washington County Bonds due April 2022 and $8.1 million of 7.0% Series Warren County Bonds due April 2022. The issuance is not reported in the cash flow statement because the proceeds from the issuance were placed in trust and were never held as cash by Entergy Mississippi.

Together with other available funds, proceeds from the issuances in April 2004 were used to retire or redeem the following:

Retirement Date

 

Description

 

Maturity

 

Amount

           

(In Thousands)

 

 

 

 

 

 

 

May 2004

 

6.20% Series

 

May 2004

 

$75,000

May 2004

 

6.45% Series

 

April 2008

 

80,000

May 2004

 

7.70% Series

 

July 2023

 

60,000

 

 

 

 

 

 

$215,000

 

In May 2004, Entergy Mississippi renewed its credit facility for the same amount, $25 million, which is due to expire in May 2005. The facility was fully drawn at September 30, 2004.

 

Significant Factors and Known Trends

See "Management's Financial Discussion and Analysis - Significant Factors and Known Trends" in the Form 10-K for a discussion of utility restructuring, state and local rate regulation, System Agreement proceedings, market and credit risks, state and local regulatory risks, and litigation risks. The following are updates to the Form 10-K.

State and Local Rate Regulation

As discussed in Note 2 to the domestic utility companies and System Energy financial statements in the Form 10-K, Entergy Mississippi made its anticipated formula rate plan filing with the MPSC in March 2004 based on a 2003 test year. In April 2004, the MPSC approved a joint stipulation entered into between the Mississippi Public Utilities Staff and Entergy Mississippi that provides for no change in rates based on an adjusted return on common equity midpoint of 10.77%, establishing an allowed annual regulatory earnings range of 9.5% to 12.1%.

System Agreement Proceedings

See the Form 10-K for a discussion of the proceeding commenced at the FERC by the LPSC regarding production cost equalization under the System Agreement, the ALJ's Initial Decision in the proceeding, and the "Order of Investigation" issued by the APSC. Several parties, including Entergy, the LPSC, the APSC, the MPSC, the City Council, and the FERC Staff, filed briefs on exceptions in response to the ALJ's Initial Decision. Entergy's exceptions to the ALJ's Initial Decision include: the practical effect of the Initial Decision is full production cost equalization, which was rejected in the Initial Decision and previously has been rejected by the FERC; resource planning for the Entergy System would be impeded if the Initial Decision were adopted; the remedy in the Initial Decision is inconsistent with the history, structure, and precedent regarding the System Agreement; the Initial Decision's remedy ignores the historical pattern of production cost disparities on the Entergy System and would result in substantial, sudden transfers of costs between groups of Entergy customers; the numerical standards proposed in the Initial Decision are arbitrary and are so complex that they will be difficult to implement; the Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the full costs of the Vidalia project should be included in Entergy Louisiana's production costs for purposes of calculating relative production costs; and the Initial Decision erroneously adopted a new method of calculating reserve sharing costs rather than the current method.

As reported in the Form 10-K, if the FERC grants the relief requested by the LPSC in the proceeding, the relief may result in a material increase in the total production costs the FERC allocates to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in the total production costs the FERC allocates to companies whose costs currently are projected to exceed that average.   If the FERC adopts the ALJ's Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of Entergy System average total production cost. The ALJ's Initial Decision would reallocate production costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth. This would be accomplished by payments from domestic utility companies whose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost.

An assessment of the potential effects of the ALJ's Initial Decision requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power.  Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation.  Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas' total production costs are below the average production costs of the domestic utility companies.  Considerable uncertainty exists regarding future gas prices. Annual average gas prices have varied significantly over recent years, ranging from $1.92/mmBtu to $5.48/mmBtu for the 1994-2003 period, and averaging $2.99/mmBtu during the ten-year period 1994-2003 and $3.77/mmBtu during the five-year period 1999-2003.  Recent market conditions have resulted in gas prices that have averaged $5.58/MMBtu for the twelve months ended September 2004. Based upon analyses considering the effect on future production costs if the FERC adopts the ALJ's Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could result assuming annual average gas prices range from $6.39/mmBtu in 2005 declining to $4.97/mmBtu by 2009:

 


Range of Annual Payments or (Receipts)

 

Average Annual Payments or (Receipts) for 2005-2009 Period

 

(In Millions)

 

(In Millions)

       

Entergy Arkansas

$154 to $281 

 

$215 

Entergy Gulf States

($130) to ($15)

 

($63)

Entergy Louisiana

($199) to ($98)

 

($141)

Entergy Mississippi

($16) to $8 

 

$1 

Entergy New Orleans

($17) to ($5)

 

($12)

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

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

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

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

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

Critical Accounting Estimates

See "Management's Financial Discussion and Analysis - Critical Accounting Estimates" in the Form 10-K for a discussion of the estimates and judgments necessary in Entergy Mississippi's accounting for pension and other retirement costs.

ENTERGY MISSISSIPPI, INC.
INCOME STATEMENTS
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
 
    Three Months Ended   Nine Months Ended
    2004   2003     2004   2003
    (In Thousands)     (In Thousands)
                   
OPERATING REVENUES                  
Domestic electric   $390,337    $309,739      $916,740    $799,007 
                   
OPERATING EXPENSES                  
Operation and Maintenance:                  
  Fuel, fuel-related expenses, and                  
   gas purchased for resale   122,086    36,565      254,432    98,954 
  Purchased power   132,108    135,781      325,401    357,654 
  Other operation and maintenance   46,590    42,108      128,473    119,669 
Taxes other than income taxes   14,919    12,704      41,481    35,686 
Depreciation and amortization   17,388    16,619      48,013    46,230 
Other regulatory charges-net   5,243    12,789      2,055    12,920 
TOTAL   338,334    256,566      799,855    671,113 
                   
OPERATING INCOME   52,003    53,173      116,885    127,894 
                   
OTHER INCOME                  
Allowance for equity funds used during construction   1,503    978      3,137    2,785 
Interest and dividend income   459    70      2,004    641 
Miscellaneous - net   (568)   (610)     (1,044)   (1,962)
TOTAL   1,394    438      4,097    1,464 
                   
INTEREST AND OTHER CHARGES            
Interest on long-term debt   9,855    10,984      31,831    32,940 
Other interest - net   573    791      1,513    2,425 
Allowance for borrowed funds used during construction   (1,043)   (832)     (2,245)   (2,435)
TOTAL   9,385    10,943      31,099    32,930 
                   
INCOME BEFORE INCOME TAXES   44,012    42,668      89,883    96,428 
                   
Income taxes   16,139    16,864      32,564    35,958 
                   
NET INCOME   27,873    25,804      57,319    60,470 
                   
Preferred dividend requirements and other   842    842      2,527    2,527 
                   
EARNINGS APPLICABLE TO                  
COMMON STOCK   $27,031    $24,962      $54,792    $57,943 
                   
See Notes to Respective Financial Statements.                  

 

ENTERGY MISSISSIPPI, INC.
STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2004 and 2003
(Unaudited)
         
    2004   2003
    (In Thousands)
         
OPERATING ACTIVITIES        
Net income   57,319    $60,469 
Noncash items included in net income:        
  Other regulatory charges - net   2,055    12,920 
  Depreciation and amortization   48,013    46,230 
  Deferred income taxes and investment tax credits   42,127    31,035 
  Allowance for equity funds used during construction   (3,137)   (2,785)
Changes in working capital:        
  Receivables   (66,227)   (31,242)
  Fuel inventory   (727)   79 
  Accounts payable   (8,617)   (3,003)
  Taxes accrued   (15,385)   (26)
  Interest accrued   2,380    (3,933)
  Deferred fuel costs   72,173    9,856 
  Other working capital accounts   (15,115)   17,992 
Provision for estimated losses and reserves   (794)   1,251 
Changes in other regulatory assets   (138)   8,388 
Other   9,159    (15,299)
Net cash flow provided by operating activities   123,086    131,932 
         
INVESTING ACTIVITIES        
Construction expenditures   (113,473)   (128,521)
Allowance for equity funds used during construction   3,137    2,785 
Changes in other temporary investments - net   7,506    - 
Other regulatory investments   -    (72,570)
Net cash flow used in investing activities   (102,830)   (198,306)
         
FINANCING ACTIVITIES        
Proceeds from the issuance of long-term debt   178,550    292,426 
Retirement of long-term debt   (218,136)   (330,000)
Changes in credit borrowings   25,000   
Dividends paid:        
  Common stock   (34,700)   (26,600)
  Preferred stock   (2,527)   (2,527)
Net cash flow used in financing activities   (51,813)   (66,701)
         
Net decrease in cash and cash equivalents   (31,557)   (133,075)
         
Cash and cash equivalents at beginning of period   63,838    147,721 
         
Cash and cash equivalents at end of period   $32,281    $14,646 
         
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:        
Cash paid/(received) during the period for:        
  Interest - net of amount capitalized   $31,765    $37,534 
  Income taxes   $2,950    ($2,169)
         

 

ENTERGY MISSISSIPPI, INC.
BALANCE SHEETS
ASSETS
September 30, 2004 and December 31, 2003
(Unaudited)
     
  2004   2003
  (In Thousands)
         
CURRENT ASSETS        
Cash and cash equivalents:        
  Cash   $3,992    $6,381 
  Temporary cash investment - at cost,        
   which approximates market   28,289    57,457 
     Total cash and cash equivalents   32,281    63,838 
Other temporary investments     7,506 
Accounts receivable:        
  Customer   105,576    59,729 
  Allowance for doubtful accounts   (1,592)   (1,375)
  Associated companies   41,195    25,935 
  Other   5,728    6,400 
  Accrued unbilled revenues   37,218    31,209 
     Total accounts receivable   188,125    121,898 
Deferred fuel costs   16,905    89,078 
Accumulated deferred income taxes   19,373   
Fuel inventory - at average cost   5,804    5,077 
Materials and supplies - at average cost   18,660    17,682 
Prepayments and other   27,617    9,583 
TOTAL   308,765    314,662 
         
OTHER PROPERTY AND INVESTMENTS        
Investment in affiliates - at equity   5,531    5,531 
Non-utility property - at cost (less accumulated depreciation)   6,466    6,466 
TOTAL   11,997    11,997 
         
UTILITY PLANT        
Electric   2,354,001    2,243,852  
Property under capital lease   105    136  
Construction work in progress   94,938    108,829  
TOTAL UTILITY PLANT   2,449,044    2,352,817  
Less - accumulated depreciation and amortization   873,161    837,492  
UTILITY PLANT - NET   1,575,883    1,515,325  
         
DEFERRED DEBITS AND OTHER ASSETS        
Regulatory assets:        
  SFAS 109 regulatory asset - net   23,740    28,964  
  Other regulatory assets   68,893    58,287  
Long-term receivable   4,752    -  
Other   24,224    20,064  
TOTAL   121,609    107,315  
         
TOTAL ASSETS   $2,018,254    $1,949,299  
         
See Notes to Respective Financial Statements.        
 
 
 
ENTERGY MISSISSIPPI, INC.
BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
September 30, 2004 and December 31, 2003
(Unaudited)
     
  2004   2003
  (In Thousands)
 
CURRENT LIABILITIES        
Currently maturing long-term debt   $ -      $75,000  
Notes payable   25,000     -  
Accounts payable:        
  Associated companies   68,078     62,705  
  Other   14,222     28,212  
Customer deposits   36,110     33,861  
Taxes accrued   49,357     39,041  
Accumulated deferred income taxes   -     7,120  
Interest accrued   16,152     13,772  
Obligations under capital leases   36     41  
Other   4,215     2,567  
TOTAL   213,170     262,319  
         
NON-CURRENT LIABILITIES        
Accumulated deferred income taxes and taxes accrued   423,451     385,395  
Accumulated deferred investment tax credits   14,038     15,092  
Obligations under capital leases   69     95  
Accumulated provisions   6,082     6,876  
Long-term debt   711,085     654,956  
Other   65,783     60,082  
TOTAL   1,220,508     1,122,496  
         
SHAREHOLDERS' EQUITY        
Preferred stock without sinking fund   50,381     50,381  
Common stock, no par value, authorized 15,000,000        
 shares; issued and outstanding 8,666,357 shares in 2004 and 2003   199,326     199,326  
Capital stock expense and other   (59)   (59)
Retained earnings   334,928     314,836  
TOTAL   584,576     564,484  
         
Commitments and Contingencies        
         
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY   $2,018,254     $1,949,299  
         
See Notes to Respective Financial Statements.        

 

ENTERGY MISSISSIPPI, INC.
SELECTED OPERATING RESULTS
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
 
                   
    Three Months Ended   Increase/    
Description   2004     2003   (Decrease)   %
    (In Millions)        
Electric Operating Revenues:                  
  Residential   $ 167     $ 143   $ 24    17 
  Commercial   124     100   24    24 
  Industrial   59     43   16    37 
  Governmental   11     9     22 
    Total retail   361     295   66    22 
  Sales for resale                  
    Associated companies   13     3   10    333 
    Non-associated companies   10     7     43 
  Other   6     5     20 
     Total   $ 390     $ 310   $80    26 
                   
Billed Electric Energy                  
 Sales (GWh):                  
  Residential   1,658     1,731   (73)   (4)
  Commercial   1,330     1,341   (11)   (1)
  Industrial   773     779   (6)   (1)
  Governmental   114     112    
    Total retail   3,875     3,963   (88)   (2)
  Sales for resale                  
    Associated companies   107     -   107   
    Non-associated companies   132     117   15    13 
     Total   4,114     4,080   34   
                   
                   
    Nine Months Ended   Increase/    
Description   2004     2003   (Decrease)   %
    (In Millions)        
Electric Operating Revenues:                  
  Residential   $ 363     $ 327   $ 36     11 
  Commercial   297     260   37    14 
  Industrial   150     128   22    17 
  Governmental   29     24     21 
    Total retail   839     739   100    14 
  Sales for resale                  
    Associated companies   24     12   12    100 
    Non-associated companies   22     17     29 
  Other   32     31    
     Total   $ 917     $ 799   $ 118    15 
                   
Billed Electric Energy                  
 Sales (GWh):                  
  Residential   3,956     4,047   (91)   (2)
  Commercial   3,395     3,385   10   
  Industrial   2,195     2,159   36   
  Governmental   295     302   (7)   (2)
    Total retail   9,841     9,893   (52)   (1)
  Sales for resale                  
    Associated companies   185     24   161    671 
    Non-associated companies   299     269   30    11 
     Total   10,325     10,186   139   
                   
                   

 

ENTERGY NEW ORLEANS, INC.

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

 

Results of Operations

Net Income

Third Quarter 2004 Compared to Third Quarter 2003

Net income decreased $0.9 million primarily due to a decrease in net revenue and an increase in other operation and maintenance expense.

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

Net income increased $13.3 million primarily due to an increase in net revenue.

Net Revenue

Third Quarter 2004 Compared to Third Quarter 2003

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

   

Amount

   

(In Millions)

     

2003 net revenue

 

$72.2 

Volume/weather

 

(9.9)

2004 deferrals

 

7.8 

Other

 

0.8 

2004 net revenue

 

$70.9 

The volume/weather variance resulted primarily from less favorable weather on sales during the third quarter of 2004 compared to the third quarter of 2004.

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

Other regulatory credits

Other regulatory credits increased primarily due to a stipulation approved by the City Council in August 2004, as discussed above.

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

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

   

Amount

   

(In Millions)

     

2003 net revenue

 

$172.8 

Base rates

 

11.1 

2004 deferrals

 

7.8 

2004 net revenue

 

$191.7 

The increase in base rates was effective June 2003. The rate increase is discussed in Note 2 to the domestic utility companies and System Energy financial statements in the Form 10-K.

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

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

Gross operating revenues increased primarily due to an increase of $40.4 million in gross wholesale revenue as a result of increased sales to affiliates. The increase is also attributable to the increase in base rates, as mentioned above.

Fuel and purchased power expenses increased primarily due to an increase in electricity generated and power purchases.

Other regulatory credits increased primarily due to a stipulation approved by the City Council in August 2004, as discussed above.

Other Income Statement Variances

Third Quarter 2004 Compared to Third Quarter 2003

Other operation and maintenance expenses increased primarily due to increases in customer service and outside services expenses.

Interest on long-term debt decreased primarily due to long-term debt refinancing in the third quarter of 2003.

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

The increase in miscellaneous income is primarily due to an asbestos insurance settlement in April 2004.

Other interest increased primarily due to a true-up of potential rate actions and refunds in May 2003. The true-up decreased other interest charges in 2003.

 

Income Taxes

The effective income tax rates for the third quarters of 2004 and 2003 were 37.8% and 41.0%, respectively. The effective income tax rates for the nine months ended September 30, 2004 and 2003 were 38.3% and 41.4%, respectively. The differences in the effective income tax rates for the periods presented versus the federal statutory rate of 35% are primarily due to book and tax differences related to utility plant items and state income taxes.

Liquidity and Capital Resources

Cash Flow

Cash flows for the nine months ended September 30, 2004 and 2003 were as follows:

 

 

2004

 

2003

 

 

(In Thousands)

 

 

 

 

 

Cash and cash equivalents at beginning of period

 

$4,669 

 

$66,247 

 

 

 

 

 

Cash flow provided by (used in):

 

 

 

 

 

Operating activities

 

40,693 

 

(7,663)

 

Investing activities

 

(34,640)

 

(44,256)

 

Financing activities

 

(10,686)

 

(3,725)

Net decrease in cash and cash equivalents

 

(4,633)

 

(55,644)

 

 

 

 

 

Cash and cash equivalents at end of period

 

$36 

 

$10,603 

Operating Activities

Entergy New Orleans provided $40.6 million of cash flow from operating activities for the nine months ended September 30, 2004 compared to using $7.7 million of cash for the nine months ended September 30, 2003 primarily due to increased net income and the timing of receivable collections.

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

September 30,
2004

 

December 31, 2003

 

September 30,
2003

 

December 31,
2002

(In Thousands)

 

 

 

 

 

 

 

($2,147)

 

$1,783

 

($21,859)

 

$3,500

Money pool activity provided $3.9 million of Entergy New Orleans' operating cash flows for the nine months ended September 30, 2004 and provided $25.4 million of Entergy New Orleans' operating cash flows for the nine months ended September 30, 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.

Investing Activities

Net cash used in investing activities decreased $9.6 million for the nine months ended September 30, 2004 compared to the nine months ended September 30, 2003 primarily due to decreased capital expenditures related to a turbine inspection project at a fossil plant in 2003 and decreased software project costs.

Financing Activities

Net cash used in financing activities increased $7.0 million for the nine months ended September 30, 2004 compared to the nine months ended September 30, 2003 primarily due to:

    • the issuance of $35 million of 5.60% Series First Mortgage Bonds in August 2004.
    • the issuance of $40 million of 5.65% Series First Mortgage Bonds in August 2004.
    • the redemption of $30 million in principal amount of 7.55% series of General and Refunding Mortgage Bonds in September 2004.
    • the redemption of $45 million in principal amount of 8.00% series of General and Refunding Mortgage Bonds in September 2004.
    • an increase of $2.2 million in common stock dividends paid.

Uses and Sources of Capital

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

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

Significant Factors and Known Trends

See "Management's Financial Discussion and Analysis - Significant Factors and Known Trends" in the Form 10-K for a discussion of System Agreement proceedings, market and credit risks, state and local regulatory risks, environmental risks, and litigation risks. The following is an update to the Form 10-K.

System Agreement Proceedings

See the Form 10-K for a discussion of the proceeding commenced at the FERC by the LPSC regarding production cost equalization under the System Agreement, the ALJ's Initial Decision in the proceeding, and the "Order of Investigation" issued by the APSC. Several parties, including Entergy, the LPSC, the APSC, the MPSC, the City Council, and the FERC Staff, filed briefs on exceptions in response to the ALJ's Initial Decision. Entergy's exceptions to the ALJ's Initial Decision include: the practical effect of the Initial Decision is full production cost equalization, which was rejected in the Initial Decision and previously has been rejected by the FERC; resource planning for the Entergy System would be impeded if the Initial Decision were adopted; the remedy in the Initial Decision is inconsistent with the history, structure, and precedent regarding the System Agreement; the Initial Decision's remedy ignores the historical pattern of production cost disparities on the Entergy System and would result in substantial, sudden transfers of costs between groups of Entergy customers; the numerical standards proposed in the Initial Decision are arbitrary and are so complex that they will be difficult to implement; the Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the full costs of the Vidalia project should be included in Entergy Louisiana's production costs for purposes of calculating relative production costs; and the Initial Decision erroneously adopted a new method of calculating reserve sharing costs rather than the current method.

As reported in the Form 10-K, if the FERC grants the relief requested by the LPSC in the proceeding, the relief may result in a material increase in the total production costs the FERC allocates to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in the total production costs the FERC allocates to companies whose costs currently are projected to exceed that average.   If the FERC adopts the ALJ's Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of Entergy System average total production cost. The ALJ's Initial Decision would reallocate production costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth. This would be accomplished by payments from domestic utility companies whose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost.

An assessment of the potential effects of the ALJ's Initial Decision requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power.  Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation.  Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas' total production costs are below the average production costs of the domestic utility companies.  Considerable uncertainty exists regarding future gas prices. Annual average gas prices have varied significantly over recent years, ranging from $1.92/mmBtu to $5.48/mmBtu for the 1994-2003 period, and averaging $2.99/mmBtu during the ten-year period 1994-2003 and $3.77/mmBtu during the five-year period 1999-2003.  Recent market conditions have resulted in gas prices that have averaged $5.58/MMBtu for the twelve months ended September 2004. Based upon analyses considering the effect on future production costs if the FERC adopts the ALJ's Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could result assuming annual average gas prices range from $6.39/mmBtu in 2005 declining to $4.97/mmBtu by 2009:

 


Range of Annual Payments or (Receipts)

 

Average Annual Payments or (Receipts) for 2005-2009 Period

 

(In Millions)

 

(In Millions)

       

Entergy Arkansas

$154 to $281 

 

$215 

Entergy Gulf States

($130) to ($15)

 

($63)

Entergy Louisiana

($199) to ($98)

 

($141)

Entergy Mississippi

($16) to $8 

 

$1 

Entergy New Orleans

($17) to ($5)

 

($12)

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

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

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

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

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

Formula Rate Plan Filings

In conformance with the City Council's May 2003 resolution discussed in the Form 10-K, in April 2004, Entergy New Orleans made filings with the City Council as required by the earnings review process prescribed by the Gas and Electric Formula Rate Plans approved by the Council. The filings showed an increase in Entergy New Orleans' electric revenues of $1.15 million and an increase in Entergy New Orleans gas revenues of $32,000 were warranted. The Council Advisors and intervenors reviewed the filings, and filed their recommendations in July 2004. In August 2004, in accordance with the City Council's requirements for the formula rate plans, Entergy New Orleans made a filing with the City Council reflecting the parties' concurrence that no change in Entergy New Orleans' electric or gas rates is warranted. Later in August 2004, the City Council approved an unopposed settlement among Entergy New Orleans, the Council Advisors, and the intervenors in connection with the Gas and Electric Formula Rate Plans. In accordance with the resolution approving the settlement agreement, Entergy New Orleans' gas and electric base rates remain unchanged from levels set in May 2003. The resolution ordered Entergy New Orleans to defer $5.96 million of fossil plant maintenance expense incurred in 2003 and to record on its books a regulatory asset in that amount to be amortized over a five-year period effective January 2003. Entergy New Orleans also was ordered to defer $3.86 million relating to voluntary severance plan costs allocated to its electric operations and $0.99 million allocated to its gas operations, which amounts were accrued on its books in 2003, and to record on its books regulatory assets in those amounts to be amortized over five years effective January 2004.

Critical Accounting Estimates

See "Management's Financial Discussion and Analysis - Critical Accounting Estimates" in the Form 10-K for a discussion of the estimates and judgments necessary in Entergy New Orleans' accounting for pension and other retirement costs.

 

ENTERGY NEW ORLEANS, INC.
INCOME STATEMENTS
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
                 
  Three Months Ended   Nine Months Ended
    2004   2003   2004   2003
    (In Thousands)   (In Thousands)
                 
OPERATING REVENUES                
Domestic electric   $175,661    $185,741    $447,458    $405,761 
Natural gas   24,375    18,010    108,682    92,961 
TOTAL   200,036    203,751    556,140    498,722 
                 
OPERATING EXPENSES                
Operation and Maintenance:                
  Fuel, fuel-related expenses, and                
   gas purchased for resale   68,210    65,182    177,799    158,025 
  Purchased power   68,193    65,687    192,510    169,428 
  Other operation and maintenance   25,691    24,251    74,242    74,687 
Taxes other than income taxes   12,977    12,115    33,041    32,496 
Depreciation and amortization   7,803    7,578    21,603    21,985 
Other regulatory charges (credits) - net   (7,288)   708    (5,872)   (1,551)
TOTAL   175,586    175,521    493,323    455,070 
                 
OPERATING INCOME   24,450    28,230    62,817    43,652 
                 
OTHER INCOME                
Allowance for equity funds used during construction   735    554    1,150    1,706 
Interest and dividend income   214    152    541    506 
Miscellaneous - net   (204)   (522)   608    (1,071)
TOTAL   745    184    2,299    1,141 
                 
INTEREST AND OTHER CHARGES          
Interest on long-term debt   4,161    4,621    11,871    13,571 
Other interest - net   426    447    1,381    (95)
Allowance for borrowed funds used during construction   (612)   (564)   (1,024)   (1,745)
TOTAL   3,975    4,504    12,228    11,731 
                 
INCOME BEFORE INCOME TAXES   21,220    23,910    52,888    33,062 
                 
Income taxes   8,031    9,792    20,266    13,691 
                 
NET INCOME   13,189    14,118    32,622    19,371 
                 
Preferred dividend requirements and other   241    241    724    724 
                 
EARNINGS APPLICABLE TO                
COMMON STOCK   $12,948    $13,877    $31,898    $18,647 
                 
See Notes to Respective Financial Statements.                

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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ENTERGY NEW ORLEANS, INC.
STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2004 and 2003
(Unaudited)
         
    2004   2003
    (In Thousands)
OPERATING ACTIVITIES        
Net income   $32,622    $19,370 
Noncash items included in net income:        
  Other regulatory credits - net   (5,872)   (1,551)
  Depreciation and amortization   21,603    21,985 
  Deferred income taxes and investment tax credits   24,261    9,371 
Changes in working capital:        
  Receivables   (2,157)   (56,400)
  Fuel inventory   (370)   (2,243)
  Accounts payable   (18,859)   16,709 
  Taxes accrued   2,392    5,079 
  Interest accrued   (3,776)   (3,754)
  Deferred fuel costs   9,218    (2,845)
  Other working capital accounts   (7,017)   (3,658)
Provision for estimated losses and reserves   (820)   (2,163)
Changes in other regulatory assets   (5,990)   (4,524)
Other   (4,542)   (3,039)
Net cash flow provided by (used in) operating activities   40,693    (7,663)
         
INVESTING ACTIVITIES        
Construction expenditures   (36,396)   (45,962)
Allowance for equity funds used during construction   1,150    1,706 
Changes in other temporary investments - net   606    - 
Net cash flow used in investing activities   (34,640)   (44,256)
         
FINANCING ACTIVITIES        
Proceeds from the issuance of long-term debt   72,725     - 
Retirement of long-term debt   (77,487)   - 
Dividends paid:        
  Common stock   (5,200)   (3,001)
  Preferred stock   (724)   (724)
Net cash flow used in financing activities   (10,686)   (3,725)
         
Net decrease in cash and cash equivalents   (4,633)   (55,644)
         
Cash and cash equivalents at beginning of period   4,669    66,247 
         
Cash and cash equivalents at end of period   $36    $10,603 
         
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:        
Cash paid/(received) during the period for:        
  Interest - net of amount capitalized   $16,577    $16,753 
  Income taxes   ($5,010)    - 
         
See Notes to Respective Financial Statements.        

 

ENTERGY NEW ORLEANS, INC.
BALANCE SHEETS
ASSETS
September 30, 2004 and December 31, 2003
(Unaudited)
 
  2004   2003
  (In Thousands)
         
CURRENT ASSETS        
Cash and cash equivalents:        
  Cash   $36    $28 
  Temporary cash investments - at cost,        
   which approximates market     4,641 
     Total cash and cash equivalents   36    4,669 
  Other temporary investments     606 
  Accounts receivable:        
    Customer   63,573    44,663 
    Allowance for doubtful accounts   (3,365)   (3,104)
    Associated companies   1,106    24,697 
    Other   5,950    10,057 
    Accrued unbilled revenues   32,319    21,113 
       Total accounts receivable   99,583    97,426 
Accumulated deferred income taxes   833    460 
Fuel inventory - at average cost   5,950    5,580 
Materials and supplies - at average cost   9,994    8,660 
Prepayments and other   10,356    8,050 
TOTAL   126,752    125,451 
         
OTHER PROPERTY AND INVESTMENTS        
Investment in affiliates - at equity   3,259    3,259 
         
UTILITY PLANT        
Electric   694,428    666,122 
Natural gas

S

178,080    167,011 
Construction work in progress   36,223    45,061 
TOTAL UTILITY PLANT   908,731    878,194 
Less - accumulated depreciation and amortization   436,492    420,745 
UTILITY PLANT - NET   472,239    457,449 
         
DEFERRED DEBITS AND OTHER ASSETS        
Regulatory assets:        
  Other regulatory assets   36,192    27,222 
Long term receivables   3,541    - 
Other   11,144    6,438 
TOTAL   50,877    33,660 
         
TOTAL ASSETS   $653,127    $619,819 
         
See Notes to Respective Financial Statements.        
 
 
 
ENTERGY NEW ORLEANS, INC.
BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
September 30, 2004 and December 31, 2003
(Unaudited)
 
  2004   2003
  (In Thousands)
 
CURRENT LIABILITIES        
Currently maturing long-term debt   $30,000   $-
Accounts payable:        
  Associated companies   28,685   35,008
  Other   30,182   42,718
Customer deposits   16,711   15,575
Taxes accrued   3,574   -
Interest accrued   2,436   6,212
Deferred fuel costs   11,938   2,720
Energy Efficiency Program provision   6,538   6,356
Other   2,618   2,088
TOTAL   132,682   110,677
         
NON-CURRENT LIABILITIES        
Accumulated deferred income taxes and taxes accrued   59,283   39,486
Accumulated deferred investment tax credits   4,107   4,441
SFAS 109 regulatory liability - net   38,875   40,543
Other regulatory liabilities   3,541   954
Accumulated provisions   -   820
Long-term debt   199,892   229,217
Other   35,714   41,346
TOTAL   341,412   356,807
         
         
SHAREHOLDERS' EQUITY        
Preferred stock without sinking fund   19,780   19,780
Common stock, $4 par value, authorized 10,000,000        
  shares; issued and outstanding 8,435,900 shares in 2004        
  and 2003   33,744   33,744
Paid-in capital   36,294   36,294
Retained earnings   89,215   62,517
TOTAL   179,033   152,335
         
Commitments and Contingencies        
         
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY   $653,127   $619,819
         
See Notes to Respective Financial Statements.        
         

 

ENTERGY NEW ORLEANS, INC.
SELECTED OPERATING RESULTS
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
 
                 
    Three Months Ended   Increase/    
Description   2004   2003   (Decrease)   %
    (In Millions)    
Electric Operating Revenues:                
  Residential   $71    $68   $3    4 
  Commercial   54    50   4    8 
  Industrial   11    8   3    38 
  Governmental   22    22   -    - 
     Total retail   158    148   10    7 
  Sales for resale                
    Associated companies   22    28   (6)   (21)
    Other   (4)   10   (14)   (140)
     Total   $176    $186   ($10)   (5)
                 
Billed Electric Energy                
 Sales (GWh):                
  Residential   761    742   19    3 
  Commercial   681    646   35    5 
  Industrial   168    106   62    58 
  Governmental   296    298   (2)   (1)
    Total retail   1,906    1,792   114    6 
  Sales for resale                
    Associated companies   280    403   (123)   (31)
    Non-associated companies   7    9   (2)   (22)
     Total   2,193    2,204   (11)  

- 

                 
                 
    Nine Months Ended   Increase/    
Description   2004   2003   (Decrease)   %
    (In Millions)    
Electric Operating Revenues:                
  Residential   $142   $144   ($2)   (2)
  Commercial   130   127   3    2 
  Industrial   25   21   4    19 
  Governmental   53   54   (1)   (2)
     Total retail   350   346   4    1 
  Sales for resale                
    Associated companies   79   38   41    108 
    Non-associated companies   1   1   -    - 
  Other   18   21   (3)   (14)
     Total   $448   $406   $42    10 
                 
Billed Electric Energy                
 Sales (GWh):                
  Residential   1,628   1,665   (37)   (2)
  Commercial   1,751   1,698   53    3 
  Industrial   418   299   119    40 
  Governmental   766   775   (9)   (1)
     Total retail   4,563   4,437   126    3 
  Sales for resale                
    Associated companies   1,030   527   503    95 
    Non-associated companies   22   23   (1)   (4)
     Total   5,615   4,987   628    13 
                 
                 

 

SYSTEM ENERGY RESOURCES, INC.

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

 

Results of Operations

System Energy's principal asset consists of a 90% ownership and leasehold interest in Grand Gulf 1. The capacity and energy from its 90% interest is sold under the Unit Power Sales Agreement to its only four customers, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. System Energy's operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% interest in Grand Gulf 1 pursuant to the Unit Power Sales Agreement. Payments under the Unit Power Sales Agreement are System Energy's only source of operating revenues. Net income remained relatively unchanged for the third quarter, decreasing $1.0 million, and increased slightly by $2.6 million for the nine months ended September 30, 2004, compared to the same respective periods in 2003. The increase for the nine months ended is primarily due to an increase in rate base in 2004 resulting in higher operating income.

Liquidity and Capital Resources

Cash Flow

Cash flows for the nine months ended September 30, 2004 and 2003 were as follows:

 

 

2004

 

2003

 

 

(In Thousands)

 

 

 

 

 

Cash and cash equivalents at beginning of period

 

$52,536 

 

$113,159 

 

 

 

 

 

Cash flow provided by (used in):

 

 

 

 

 

Operating activities

 

138,336 

 

226,485 

 

Investing activities

 

(32,739)

 

(222,267)

 

Financing activities

 

(96,749)

 

(83,475)

Net increase (decrease) in cash and cash equivalents

 

8,848 

 

(79,257)

 

 

 

 

 

Cash and cash equivalents at end of period

 

$61,384 

 

$33,902 

Operating Activities

Cash flow from operations decreased $88.1 million for the nine months ended September 30, 2004 compared to the same period in 2003 primarily due to money pool activity as explained below, the cessation of the Entergy Mississippi GGART, and income tax payments of $5 million. System Energy collected $21.7 million in 2003 from Entergy Mississippi in conjunction with the GGART, which provided for the acceleration of Entergy Mississippi's Grand Gulf purchased power obligations. The MPSC authorized the cessation of the GGART effective July 1, 2003, and System Energy has begun crediting Entergy Mississippi for the return of the prepayment. System Energy credited an additional $11.7 million in 2004 compared to 2003. See Note 2 to the domestic utility companies and System Energy financial statements in the Form 10-K for further discussion of the GGART. Partially offsetting the decrease in operating cash flows was a decrease in interest paid during 2004.

System Energy's receivables from the money pool were as follows:

September 30,
2004

 

December 31,
2003

 

September 30,
2003

 

December 31,
2002

(In Thousands)

 

 

 

 

 

 

 

$85,644

 

$19,064

 

$24,791

 

$7,046

Money pool activity used $66.6 million of System Energy's operating cash flows for the nine months ended September 30, 2004 and used $17.7 million for the same period 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.

Investing Activities

The decrease of $189.5 million in net cash used in investing activities for the nine months ended September 30, 2004 compared to the same period in 2003 was primarily due to cash collateral of $194 million provided in 2003. 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 were backed by cash collateral. In December 2003, System Energy replaced the cash-backed letters of credit with syndicated bank letters of credit that expire in May 2007. Offsetting the cash collateral provided in 2003 was an increase in construction expenditures due to the reclassification of inventory items to capital in addition to facilities upgrades projects begun in late-2003.

Financing Activities

The increase of $13.3 million in net cash used by financing activities for the nine months ended September 30, 2004 compared to the same period in 2003 was primarily due to:

    • $13.3 million in bond premium and costs related to System Energy refunding the bonds associated with its Grand Gulf Lease Obligation in May 2004; and
    • $5 million of increased dividends paid.

The increase was partially offset by a decrease of $5 million in the January 2004 principal payment made on the Grand Gulf 1 sale-leaseback compared to the January 2003 principal payment.

Uses and Sources of Capital

See "Management's Financial Discussion and Analysis - Liquidity and Capital Resources" in the Form 10-K for a discussion of System Energy's uses and sources of capital.

Significant Factors and Known Trends

See "Management's Financial Discussion and Analysis - Significant Factors and Known Trends" in the Form 10-K for a discussion of market risks, nuclear matters, litigation risks, and environmental risks.

Critical Accounting Estimates

See "Management's Financial Discussion and Analysis - Critical Accounting Estimates" in the Form 10-K for a discussion of the estimates and judgments necessary in System Energy's accounting for nuclear decommissioning costs and pension and other retirement costs.

SYSTEM ENERGY RESOURCES, INC.
INCOME STATEMENTS
For the Three and Nine Months Ended September 30, 2004 and 2003
(Unaudited)
 
  Three Months Ended   Nine Months Ended
    2004   2003   2004   2003
    (In Thousands)   (In Thousands)
                 
OPERATING REVENUES  

 

 

 

 

 

 

 

Domestic electric   $144,052    $141,239    $403,939    $427,988  
                 
OPERATING EXPENSES                
Operation and Maintenance:                
  Fuel, fuel-related expenses, and                
    gas purchased for resale   10,411    11,180    27,935    31,364 
  Nuclear refueling outage expenses   3,087    3,264    9,604    9,430 
  Other operation and maintenance   26,677    22,196    71,315    68,140 
Decommissioning   5,911    5,450    17,416    16,350 
Taxes other than income taxes   6,504    6,203    18,660    18,887 
Depreciation and amortization   36,125    28,317    88,495    80,563 
Other regulatory charges (credits) - net   (4,264)   (1,162)   (6,439)   27,695 
TOTAL   84,451    75,448    226,986    252,429 
                 
OPERATING INCOME   59,601    65,791    176,953    175,559 
                 
OTHER INCOME                
Allowance for equity funds used during construction   328    310    1,196    842 
Interest and dividend income   1,536    1,505    4,461    5,123 
Miscellaneous - net   (136)   (210)   (508)   (952)
TOTAL   1,728    1,605    5,149    5,013 
                 
INTEREST AND OTHER CHARGES          
Interest on long-term debt   14,361    16,799    45,550    45,873 
Other interest - net     371    362    1,481 
Allowance for borrowed funds used during construction   (107)   (184)   (387)   (361)
TOTAL   14,260    16,986    45,525    46,993 
                 
INCOME BEFORE INCOME TAXES   47,069    50,410    136,577    133,579 
                 
Income taxes   19,564    21,895    58,873    58,509 
                 
NET INCOME   $27,505    $28,515    $77,704    $75,070 
                 
See Notes to Respective Financial Statements.                
                 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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SYSTEM ENERGY RESOURCES, INC.
STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2004 and 2003
(Unaudited)
         
    2004   2003
    (In Thousands)
         
OPERATING ACTIVITIES        
Net income   $77,704    $75,070 
Noncash items included in net income:        
  Other regulatory charges (credits) - net   (6,439)   27,695 
  Depreciation, amortization, and decommissioning   105,911    96,913 
  Deferred income taxes and investment tax credits   (169,859)   (24,557)
Changes in working capital:        
  Receivables   (61,512)   (7,870)
  Accounts payable   (14,736)   (9,038)
  Taxes accrued   217,522    77,814 
  Interest accrued   50    (20,608)
  Other working capital accounts   (1,570)   (2,676)
Provision for estimated losses and reserves   (2,341)   72 
Changes in other regulatory assets   21,589    29,382 
Other   (27,983)   (15,712)
Net cash flow provided by operating activities   138,336    226,485 
         
INVESTING ACTIVITIES        
Construction expenditures   (25,078)   (9,705)
Allowance for equity funds used during construction   1,196    842 
Nuclear fuel purchases   (45,528)  
Proceeds from sale/leaseback of nuclear fuel   45,709   
Decommissioning trust contributions and realized        
  change in trust assets   (15,520)   (15,852)
Changes in other temporary investments - net   6,482    (3,216)
Increase in other cash investments     (194,336)
Net cash flow used in investing activities   (32,739)   (222,267)
         
FINANCING ACTIVITIES        
Retirement of long-term debt   (6,348)   (11,375)
Other financing activities   (13,301)  
Dividends paid:        
  Common stock   (77,100)   (72,100)
Net cash flow used in financing activities   (96,749)   (83,475)
         
Net increase (decrease) in cash and cash equivalents   8,848    (79,257)
         
Cash and cash equivalents at beginning of period   52,536    113,159 
         
Cash and cash equivalents at end of period   $61,384    $33,902 
         
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:        
Cash paid during the period for:        
  Interest - net of amount capitalized   $41,531    $65,053 
  Income taxes   $5,250   
         
See Notes to Respective Financial Statements.        
         

 

SYSTEM ENERGY RESOURCES, INC.
BALANCE SHEETS
ASSETS
September 30, 2004 and December 31, 2003
(Unaudited)
             
    2004   2003
  (In Thousands)
             
CURRENT ASSETS            
Cash and cash equivalents:            
  Cash       $63   $2,918
  Temporary cash investments - at cost,            
   which approximates market       61,321   49,618
Total cash and cash equivalents       61,384   52,536
Other temporary investments       -   6,482
Accounts receivable:            
  Associated companies       133,627   72,477
  Other       2,139   1,777
    Total accounts receivable       135,766   74,254
Materials and supplies - at average cost       52,415   63,047
Deferred nuclear refueling outage costs       12,550   2,979
Prepayments and other       54,447   1,031
TOTAL       316,562   200,329
             
OTHER PROPERTY AND INVESTMENTS        
Decommissioning trust funds       191,937   172,916
             
UTILITY PLANT        
Electric       3,237,006   3,205,895
Property under capital lease       466,521   466,521
Construction work in progress       24,873   31,344
Nuclear fuel under capital lease       73,036   47,242
TOTAL UTILITY PLANT       3,801,436   3,751,002
Less - accumulated depreciation and amortization       1,755,559   1,672,658
UTILITY PLANT - NET       2,045,877   2,078,344
             
DEFERRED DEBITS AND OTHER ASSETS        
Regulatory assets:            
  SFAS 109 regulatory asset - net       98,819   115,633
  Other regulatory assets       305,776   301,233
Other       14,192   12,269
TOTAL       418,787   429,135
             
TOTAL ASSETS       $2,973,163   $2,880,724
             
See Notes to Respective Financial Statements.            
 
 
 
SYSTEM ENERGY RESOURCES, INC.
BALANCE SHEETS
LIABILITIES AND SHAREHOLDER'S EQUITY
September 30, 2004 and December 31, 2003
(Unaudited)
             
    2004   2003
  (In Thousands)
 
CURRENT LIABILITIES        
Currently maturing long-term debt       $25,266   $6,348
Accounts payable - other       15,519   30,255
Taxes accrued       -   55,585
Accumulated deferred income taxes       4,657   942
Interest accrued       29,673   29,623
Obligations under capital leases       31,266   31,266
Other       1,776   1,971
TOTAL       108,157   155,990
             
NON-CURRENT LIABILITIES        
Accumulated deferred income taxes and taxes accrued       422,111   290,964
Accumulated deferred investment tax credits       76,481   79,088
Obligations under capital leases       41,770   15,976
Other regulatory liabilities       214,161   213,093
Decommissioning       329,875   312,459
Accumulated provisions       1,441   3,782
Long-term debt       857,197   882,401
Other       28,130   33,735
TOTAL       1,971,166   1,831,498
             
             
SHAREHOLDER'S EQUITY        
Common stock, no par value, authorized 1,000,000 shares;            
  issued and outstanding 789,350 shares in 2004 and 2003       789,350   789,350
Retained earnings       104,490   103,886
TOTAL       893,840   893,236
             
Commitments and Contingencies            
             
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY       $2,973,163   $2,880,724
             
See Notes to Respective Financial Statements.            
             
             

ENTERGY ARKANSAS, ENTERGY GULF STATES, ENTERGY LOUISIANA, ENTERGY MISSISSIPPI, ENTERGY NEW ORLEANS, AND SYSTEM ENERGY

NOTES TO RESPECTIVE FINANCIAL STATEMENTS

(Unaudited)

 

NOTE 1. COMMITMENTS AND CONTINGENCIES

Nuclear Insurance and Spent Nuclear Fuel (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

See Note 9 to the domestic utility companies and System Energy 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 associated with Entergy Arkansas', Entergy Gulf States', Entergy Louisiana's, and System Energy's nuclear power plants. The following are updates to the Form 10-K.

The Property Insurance Policy renewed on April 1, 2004 with the following changes: the deductibles for ANO 1 and 2, Grand Gulf 1, River Bend, and Waterford 3 increased to $5 million per occurrence for turbine/generator damage and $5 million per occurrence for other than turbine/generator damage.

Under the property damage and accidental outage insurance programs, Entergy nuclear plants could be subject to assessments should losses exceed the accumulated funds available from NEIL. As of September 30, 2004, the maximum amount of such possible assessments per occurrence were $15.1 million for Entergy Arkansas, $11.1 million for Entergy Gulf States, $13.0 million for Entergy Louisiana, $0.06 million for Entergy Mississippi, $0.06 million for Entergy New Orleans, and $11.5 million for System Energy.

Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are responsible for their own spent fuel storage. Current on-site spent fuel storage capacity at Grand Gulf I, River Bend, and Waterford 3 is estimated to be sufficient until approximately 2007, 2005, and 2012, respectively, at which time dry cask storage facilities will be placed into service. An ANO storage facility using dry casks began operation in 1996, has been expanded since, and will be further expanded as needed.

Nuclear Decommissioning and Other Retirement Costs (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

See Note 9 to the domestic utility companies and System Energy financial statements in the Form 10-K for information on nuclear decommissioning costs. 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. 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 as a result of a one-time cumulative effect of accounting change.

In accordance with a new decommissioning cost study for ANO 1 and 2, in the first quarter of 2004 Entergy Arkansas recorded a revision to its estimated decommissioning cost liability. The revised estimate resulted in a $107.7 million reduction in its decommissioning liability, along with a $19.5 million reduction in utility plant and an $88.2 million reduction in the related regulatory asset.

In the third quarter of 2004, Entergy Gulf States recorded a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for River Bend that reflected a life extension for the plant. The revised estimate resulted in a $116.8 million reduction in decommissioning liability, along with a $31.3 million reduction in utility plant, a $40.1 million reduction in the related regulatory asset and a regulatory liability of $17.7 million. For the portion of River Bend not subject to cost-based ratemaking, the revised estimate resulted in the elimination of the asset retirement cost that had been recorded at the time of adoption of SFAS 143 with the remainder recorded as miscellaneous income of $27.7 million.

In accordance with ratemaking treatment and as required by SFAS 71, the depreciation provisions for the domestic utility companies and System Energy include a component for removal costs that are not asset retirement obligations under SFAS 143. In accordance with regulatory accounting principles, Entergy has recorded a regulatory asset (liability) to reflect its estimate of the difference between estimated incurred removal costs and estimated removal costs recovered in rates previously recorded as a component of accumulated depreciation.

As discussed in the Form 10-K, the Energy Policy Act of 1992 contains a provision that assesses domestic nuclear utilities with fees for the decontamination and decommissioning (D&D) of the DOE's past uranium enrichment operations. The Energy Policy Act calls for cessation of annual D&D assessments not later than October 24, 2007. Entergy will oppose any attempts to extend the assessments past this date, but cannot state with certainty that an extension will not be made.

CashPoint Bankruptcy (Entergy Arkansas, Entergy Louisiana, Entergy Gulf States, Entergy New Orleans, and Entergy Mississippi)

The domestic utility companies entered an agreement with CashPoint Network Services (CashPoint) under which CashPoint was to manage a network of payment agents through which Entergy's utility customers could pay their bills. The payment agent system allows customers to pay their bills at various commercial or governmental locations, rather than sending payments by mail. Approximately one-third of Entergy's utility customers use payment agents.

On April 19, 2004, CashPoint failed to pay funds due to the domestic utility companies that had been collected through payment agents. The domestic utility companies then obtained a temporary restraining order from the Civil District Court for the Parish of Orleans, State of Louisiana, enjoining CashPoint from distributing funds belonging to Entergy, except by paying those funds to Entergy. On April 22, 2004, a petition for involuntary Chapter 7 bankruptcy was filed against CashPoint by other creditors in the United States Bankruptcy Court for the Southern District of New York. In response to these events, the domestic utility companies expanded an existing contract with another company to manage all of their payment agents. The domestic utility companies filed proofs of claim in the CashPoint bankruptcy proceeding in September 2004. Although Entergy cannot precisely determine at this time the amount that CashPoint owes to the domestic utility companies that may not be repaid, it has accrued an estimate of loss based on current information. If no cash is repaid to the domestic utility companies, an event Entergy does not believe is likely, the current estimates of maximum exposure to loss are approximately as follows:

 

 

Amount

 

 

(In Millions)

 

 

 

Entergy Arkansas

 

$1.8

Entergy Gulf States

 

$7.7

Entergy Louisiana

 

$8.8

Entergy Mississippi

 

$4.3

Entergy New Orleans

 

$2.4

Environmental Issues

(Entergy Gulf States)

See Note 9 to the domestic utility companies and System Energy financial statements in the Form 10-K for information related to the designation of Entergy Gulf States as a PRP for the cleanup of certain hazardous waste disposal sites. During the second quarter of 2004, the reserve balance previously recorded was reduced to approximately $1.5 million based upon activities performed to date and the best estimate of the remaining likely exposure associated with the ten-year groundwater monitoring study.

(Entergy Louisiana and Entergy New Orleans)

During 1993, the LDEQ issued new rules for solid waste regulation, including regulation of wastewater impoundments. Entergy Louisiana and Entergy New Orleans have determined that certain of their power plant wastewater impoundments were affected by these regulations and have chosen to upgrade or close them. Recorded liabilities in the amounts of $5.8 million for Entergy Louisiana and $0.5 million for Entergy New Orleans existed at September 30, 2004 for wastewater upgrades and closures. Completion of this work is awaiting LDEQ approval.

City Franchise Ordinances (Entergy New Orleans)

Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to franchise ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans' electric and gas utility properties.

Employment Litigation (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy 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 deny any liability to the plaintiffs.

Asbestos and Hazardous Material Litigation (Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans)

Numerous lawsuits have been filed in federal and state courts in Texas, Louisiana, and Mississippi primarily by contractor employees in the 1950-1980 timeframe against Entergy Gulf States, Entergy Louisiana, Entergy New Orleans, and Entergy Mississippi, as premises owners of power plants, for damages caused by alleged exposure to asbestos or other hazardous material. Generally, many other defendants are named in these lawsuits as well. Presently there are approximately 460 lawsuits involving approximately 10,000 claims. Reserves have been established that should be adequate to cover any exposure. Additionally, negotiations continue with insurers to recover more reimbursement, while new coverage is being secured to minimize anticipated future potential exposures. Management believes that loss exposure has been and will continue to be handled successfully so that the ultimate resolution of these matters will not be material, in the aggregate, to the financial position or results of operation of the domestic utility companies involved in these lawsuits.

 

NOTE 2. RATE AND REGULATORY MATTERS

Electric Industry Restructuring and the Continued Application of SFAS 71

Previous developments and information related to electric industry restructuring are presented in Note 2 to the domestic utility companies and System Energy financial statements in the Form 10-K.

Texas (Entergy Gulf States)

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

In view of the PUCT order to delay retail open access in the Texas service territory, Entergy Gulf States filed a retail electric rate case and fuel reconciliation proceeding with the PUCT in August 2004 seeking the following:

  • approval of a base rate increase of $42.6 million annually for the Texas retail jurisdiction;
  • approval to implement a $14.1 million per year rider to recover, over a 15-year period, $110.9 million of incurred costs related to its efforts to transition to a competitive retail market in accordance with the Texas restructuring law;
  • proposed $11.3 million franchise fee rider to recover payments to municipalities charging such fees; and
  • a requested return on equity of 11.5%.

In addition, Entergy Gulf States' fuel reconciliation filing made in conjunction with the base rate case seeks to reconcile approximately $288 million in fuel and purchased power costs incurred during the period September 2003 through March 2004. The PUCT requested that the parties submit briefs addressing threshold issues related to whether Entergy Gulf States has the right to file a base rate case and what relief is available, if the PUCT were to determine that Entergy Gulf States' base rates are subject to the rate freeze imposed in December 2001 in connection with the market readiness docket initiated by the PUCT Staff. The PUCT considered these issues in September 2004. In October 2004, the PUCT issued a written order in which it dismissed the rate case indicating that Entergy Gulf States is still subject to a rate freeze based on an agreement in 2001 stipulating that a rate freeze would remain in effect until retail open access commenced in Entergy Gulf States' service territory. Entergy Gulf States intends to file a motion for rehearing and intends to pursue other available remedies.

Deferred Fuel Costs

(Entergy Arkansas)

In March 2004, Entergy Arkansas filed with the APSC its energy cost recovery rider for the period April 2004 through March 2005. The filed energy cost rate, which accounts for 12 percent of a typical residential customer's bill using 1,000 kWh per month, increased 16 percent due primarily to the elimination of a credit contained in the prior year's rate to refund previously over-recovered fuel costs. Also included in this year's energy cost calculation is a decrease in rates of $3.9 million as a result of the operation of a revised energy allocation method between the retail and wholesale sectors resulting from the approval of a life-of-resources power purchase agreement with Entergy New Orleans.

(Entergy Gulf States)

In September 2004, Entergy Gulf States filed an application with the PUCT to implement a $27. 8 million interim fuel surcharge, including interest, to collect under-recovered fuel and purchased power expenses incurred from September 2003 through July 2004. Entergy Gulf States proposes to collect the surcharge over a six-month period beginning January 2005. Hearings are expected to occur in November 2004. Amounts collected though the interim fuel surcharge are subject to final reconciliation in a future fuel reconciliation proceeding.

In March 2004, Entergy Gulf States filed with the PUCT a fuel reconciliation case covering the period September 2000 through August 2003. Entergy Gulf States is reconciling $1.43 billion of fuel and purchased power costs on a Texas retail basis. The reconciliation includes $8.6 million of under-recovered costs that Entergy Gulf States is asking to roll into its fuel over/under-recovery balance to be addressed in the next appropriate fuel proceeding. This case involves imputed capacity and River Bend payment issues similar to those decided adversely in the January 2001 proceeding, discussed below, which is now on appeal. The PUCT Staff has quantified these issues at $11.2 million. Hearings occurred in October 2004 and a final PUCT decision is expected in the first quarter of 2005.

See Note 2 to the domestic utility and System Energy financial statements in the Form 10-K for a discussion of Entergy Gulf States' January 2001 fuel reconciliation case filed with the PUCT covering the period from March 1999 through August 2000 and subsequent proceedings at Travis County District Court and the Third District Court of Appeals. Entergy Gulf States appealed to the Court of Appeals the disallowance of approximately $4.2 million related to imputed capacity costs and the disallowance related to costs for energy delivered from the 30% non-regulated share of River Bend. Oral argument before the appellate court occurred in September 2004.

(Entergy Louisiana)

As discussed in Note 2 to the domestic utility companies and System Energy financial statements in the Form 10-K, 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 recommended a disallowance with regard to one item. The issue relates to the alleged failure to uprate Waterford 3 in a timely manner, a claim that also has been raised in the summer 2001, 2002, and 2003 purchased power proceedings. The LPSC staff has quantified the possible disallowance as between $7.6 and $14 million. Entergy Louisiana notified the LPSC that it will contest the recommendation. The procedural schedule in the case has been suspended. A status conference for the purpose of establishing a new procedural schedule will be set when the current hearings in the Power Purchase Agreement proceedings at the FERC are concluded. The FERC hearings in that matter are expected to conclude in November 2004.

Retail Rate Proceedings

Filings with the PUCT and Texas Cities (Entergy Gulf States)

Recovery of River Bend Costs

See Note 2 to the domestic utility companies and System Energy 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 at Travis County District Court and the Third District Court of Appeals that affirmed the PUCT disallowance. In September 2004, the Texas Supreme Court denied Entergy Gulf States' petition for review, and Entergy Gulf States filed a motion for rehearing. In October 2004, the Texas Supreme Court requested that the other parties file responses to Entergy Gulf States' motion, and the matter is pending.

 

Filings with the LPSC

Annual Earnings Reviews (Entergy Gulf States)

See Note 2 to the domestic utility companies and System Energy 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 the LPSC staff's December 2003 testimony, the staff recommended an annual rate refund of approximately $30 million effective June 2002, and a prospective rate reduction of approximately $50 million. Hearings concluded in May 2004.

Proposed Settlement (Entergy Gulf States and Entergy Louisiana)

In June 2004, Entergy Gulf States and Entergy Louisiana filed a proposed settlement with the LPSC that would resolve, among other dockets, Entergy Gulf States' ninth post-merger analysis and dockets established to consider issues concerning the companies' power purchases for the summers of 2001, 2002, and 2003. The proposed settlement included an offer to refund approximately $64 million to Entergy Gulf States' Louisiana customers and $1 million to Entergy Louisiana's customers, with no change in either company's current base rates.  The settlement also proposed a formula rate plan for Entergy Gulf States' Louisiana operations. At its September 2004 Business and Executive Session, the LPSC consolidated various dockets that were the subject of proposed settlement. The LPSC directed its staff to preside over settlement discussions and to submit any proposed settlement to the LPSC for its consideration.

Retail Rates

(Entergy Gulf States)

In July 2004, Entergy Gulf States filed with the LPSC an application for a change in its rates and charges seeking an increase of $9.1 million in gas base rates in order to allow Entergy Gulf States an opportunity to earn a fair and reasonable rate of return. Entergy Gulf States is also seeking approval of certain proposed rate design, rate schedule, and policy changes. A procedural schedule has not been established.

(Entergy Louisiana)

See Note 2 to the domestic utility companies and System Energy financial statements in the Form 10-K for Entergy Louisiana's rate filing with the LPSC requesting a base rate increase. In August 2004, the LPSC Staff filed testimony in which it recommended a $19.5 million rate increase for Entergy Louisiana, assuming that the Perryville acquisition is approved in time for the Perryville costs to be included in rates set in this proceeding. Additional issues and updates that will be evaluated in connection with this proceeding are likely to result in revisions to the LPSC Staff's recommendation.  These issues may reduce the amount of the recommended rate increase or cause it to become a recommendation for a rate decrease. Hearings are currently set for December 2004.

Filings with the City Council (Entergy New Orleans)

Formula Rate Plan Filings

In conformance with the City Council's May 2003 resolution discussed in Note 2 to the domestic utility companies and System Energy financial statements in the Form 10-K, in April 2004, Entergy New Orleans made filings with the City Council as required by the earnings review process prescribed by the Gas and Electric Formula Rate Plans approved by the City Council in 2003. The filing showed an increase in Entergy New Orleans' electric revenues of $1.15 million and an increase in Entergy New Orleans' gas revenues of $32,000 is warranted. The Council Advisors and intervenors reviewed the filings, and filed their recommendations in July 2004. In August 2004, in accordance with the City Council's requirements for the formula rate plans, Entergy New Orleans made a filing with the City Council reflecting the parties' concurrence that no change in Entergy New Orleans' electric or gas rates is warranted. Later in August 2004, the City Council approved an unopposed settlement among Entergy New Orleans, the Council Advisors, and the intervenors in connection with the Gas and Electric Formula Rate Plans. In accordance with the resolution approving the settlement agreement, Entergy New Orleans' gas and electric base rates remain unchanged from levels set in May 2003. The resolution ordered Entergy New Orleans to defer $3.86 million relating to voluntary severance plan costs allocated to its electric operations and $0.99 million allocated to its gas operations, which amounts were accrued on its books in 2003, and to record on its books regulatory assets in those amounts to be amortized over five years effective January 2004. Entergy New Orleans also was ordered to defer $5.96 million of fossil plant maintenance expense incurred in 2003 and to record on its books a regulatory asset in that amount to be amortized over a five-year period effective January 2003.

Fuel Adjustment Clause Litigation

See "Fuel Adjustment Clause Litigation" in Note 2 to the domestic utility companies and System Energy 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. In February 2004, the City Council approved a resolution that results in a refund to customers of $11.3 million, including interest, during the months of June through September 2004. The resolution concludes, among other things, that the record does not support an allegation that Entergy New Orleans' actions or inactions, either alone or in concert with Entergy or any of its affiliates, constituted a misrepresentation or a suppression of the truth made in order to obtain an unjust advantage of Entergy New Orleans, or to cause loss, inconvenience or harm to its ratepayers. Management believes that it has adequately provided for the liability associated with this proceeding. The plaintiffs have appealed the City Council resolution to the state court in Orleans Parish. Oral argument on the plaintiffs' appeal is scheduled for February 2005. In addition, in March 2004, the plaintiffs supplemented and amended the class action petition that had been filed in state court in April 1999. This proceeding has been stayed pending resolution of plaintiffs' appeal in the proceeding commenced with the City Council.

 

NOTE 3. LINES OF CREDIT, RELATED SHORT-TERM BORROWINGS, AND LONG-TERM DEBT

The short-term borrowings of the domestic utility companies and System Energy 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, the domestic utility companies and System Energy are authorized to borrow from the Entergy System Money Pool (money pool). The money pool is an inter-company borrowing arrangement designed to reduce the domestic utility companies' dependence on external short-term borrowings. Borrowings from the money pool and external borrowings combined may not exceed the SEC authorized limits. In August 2004, Entergy filed with the SEC to extend the authorization period for the current short-term borrowing limits and the money pool borrowing arrangement. The following are the combined short-term borrowings from the money pool and external borrowings, and the SEC-authorized limits for short-term borrowings for the domestic utility companies and System Energy as of September 30, 2004:

 

 

Authorized

 

Borrowings

 

 

(In Millions)

 

 

 

 

 

Entergy Arkansas

 

$235

 

-

Entergy Gulf States

 

$340

 

$100.7

Entergy Louisiana

 

$225

 

-

Entergy Mississippi

 

$160

 

-

Entergy New Orleans

 

$100

 

$2.1

System Energy

 

$140

 

-

 

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans each have separate short-term credit facilities available as follows:


Company

 


Expiration Date

 

Amount of
Facility

 

Amount Drawn as of
September 30, 2004

 

 

 

 

 

 

 

Entergy Arkansas

 

April 2005

 

$85 million

 

$85 million

Entergy Louisiana

 

April 2005

 

$15 million

 

-

Entergy Mississippi

 

May 2005

 

$25 million

 

$25 million

Entergy New Orleans

 

April 2005

 

$14 million

 

-

The combined amount borrowed by Entergy Louisiana and Entergy New Orleans under these facilities at any one time cannot exceed $15 million. The facilities have variable interest rates and the average commitment fee is 0.15%.

The following long-term debt has been issued by the domestic utility companies and System Energy in 2004:

 

Issue Date

 

Amount

 

 

 

(In Thousands)

Mortgage Bonds and Other Long-Term Debt:

 

 

 

 

 

 

 

Entergy Arkansas

 

 

 

Issuance after balance sheet date:

 

 

 

6.38% Series due November 2034

October 2004

 

$60,000

 

 

 

 

Entergy Gulf States

 

 

 

Issuance after balance sheet date:

 

 

 

4.875% Series due November 2011

October 2004

 

$200,000

 

 

 

 

Entergy Louisiana

 

 

 

5.50% Series due April 2019

March 2004

 

$100,000

Issuances after balance sheet date:

 

 

 

6.40% Series due October 2034

October 2004

 

$70,000

5.09% Series due November 2014

October 2004

 

$115,000

       
Entergy Mississippi      

6.25% Series due April 2034

April 2004

 

$100,000

4.65% Series due May 2011

April 2004

 

$80,000

4.60% Series due April 2022

September 2004

 

$16,030

       
Entergy New Orleans      

5.60% Series due September 2024

August 2004

 

$35,000

5.65% Series due September 2029

August 2004

 

$40,000

 

The following long-term debt has been retired by the domestic utility companies and System Energy in 2004:

 

Retirement Date

 

Amount

 

 

 

(In Thousands)

Mortgage Bonds and Other Long-Term Debt :

 

 

 

 

 

 

 

Entergy Gulf States

 

 

 

8.25% Series due April 2004

April 2004

 

$292,000

 

 

 

 

Entergy Louisiana

 

 

 

Waterford 3 Lease Obligation payment

N/A

 

$14,809

 

 

 

 

Entergy Mississippi

 

 

 

6.20% Series due May 2004

May 2004

 

$75,000

6.45% Series due April 2008

May 2004

 

$80,000

7.70% Series due July 2023

May 2004

 

$60,000

Retirements after balance sheet date:

 

 

 

7.0% Series due April 2022

October 2004

 

$7,935

7.0% Series due April 2022

October 2004

 

$8,095

 

 

 

 

Entergy New Orleans

 

 

 

8.0% Series due March 2023

September 2004

 

$45,000

7.55% Series due September 2023

September 2004

 

$30,000

 

 

 

 

System Energy

 

 

 

Grand Gulf Lease Obligation payment

N/A

 

$6,348

In September 2004, Entergy Gulf States purchased its $62 million of 5.65% Series West Feliciana Parish bonds from the holders, pursuant to a mandatory tender provision, and has not remarketed the bonds at this time. Entergy Gulf States used a combination of cash on hand and short-term borrowings to buy-in the bonds.

In October 2004, Entergy Arkansas issued $60 million of 6.38% Series First Mortgage Bonds due November 1, 2034. In November 2004, Entergy Arkansas plans to use the proceeds to redeem the $61.9 million of 8.5% Series Junior Subordinated Deferrable Interest Debentures due 2045.

In October 2004, Entergy Gulf States issued $200 million of 4.875% Series of First Mortgage Bonds due November 1, 2011. Entergy Gulf States plans to use the proceeds to redeem, prior to maturity, $200 million of 5.2% Series of First Mortgage Bonds due December 3, 2007.

In October 2004, Entergy Louisiana issued $70 million of 6.40% Series of First Mortgage Bonds due October 1, 2034. In November 2004, Entergy Louisiana plans to use the proceeds to redeem $72.2 million of 9.0% Series Junior Subordinated Deferrable Interest Debentures due 2045.

In October 2004, Entergy Louisiana issued $115 million of 5.09% Series of First Mortgage Bonds due November 1, 2014. Entergy Louisiana plans to use the proceeds to redeem, prior to maturity, $115 million of 6.5% Series of First Mortgage Bonds due March 1, 2008.

Audit of Entergy Louisiana Governmental Bond 7.0% Series due 2022 (Entergy Louisiana)

The $24 million of 7.0% Series Governmental Bonds due 2022 listed in the Form 10-K were issued by St. Charles Parish, Louisiana in 1992 (the "Bonds"). The Bonds were issued to finance previously unfinanced costs of the acquisition by Entergy Louisiana of certain solid waste disposal facilities at Waterford 3. In November 2000, the Internal Revenue Service (IRS), as part of its ongoing enforcement program, notified St. Charles Parish that an audit of the Bonds had been initiated. In January 2002, the IRS notified St. Charles Parish of a preliminary adverse determination that interest on the Bonds is not excludable from gross income under the Internal Revenue Code of 1986, as amended. The stated basis for this determination was that, because the waste that the facilities disposed of was radioactive, it did not constitute "solid waste" within the meaning of the Internal Revenue Code and therefore the facilities did not qualify as solid waste disposal facilities within the meaning of that provision. In October 2004, the IRS notified St. Charles Parish that the IRS Office of Chief Counsel had issued a "technical advice" that concurred with the preliminary adverse determination. St. Charles Parish and Entergy Louisiana continue to contest this matter before the IRS.

 

NOTE 4. RETIREMENT AND OTHER POSTRETIREMENT BENEFITS

Components of Net Pension Cost

The domestic utility companies' and System Energy's pension cost/(income), including amounts capitalized, for the third quarters of 2004 and 2003, included the following components:

 

 

Entergy

 

Entergy

 

Entergy

 

Entergy

 

Entergy

 

System

2004

 

Arkansas

 

Gulf States

 

Louisiana

 

Mississippi

 

New Orleans

 

Energy

 

 

(In Thousands)

Service cost - benefits earned

 

 

 

 

 

 

 

 

 

 

 

 

  during the period

 

$2,945 

 

$2,405 

 

$1,747 

 

$900 

 

$391 

 

$836 

Interest cost on projected

 

 

 

 

 

 

 

 

 

 

 

 

  benefit obligation

 

8,962 

 

7,117 

 

5,444 

 

2,978 

 

1,116 

 

1,296 

Expected return on assets

 

(9,249)

 

(9,941)

 

(6,949)

 

(3,681)

 

(491)

 

(1,148)

Amortization of transition asset

 

 

 

 

 

 

(79)

Amortization of prior service cost

 

416 

 

378 

 

163 

 

128 

 

57 

 

17 

Amortization of loss

 

933 

 

(204)

 

231 

 

123 

 

272 

 

238 

Net pension cost/(income)

 

$4,007 

 

($245)

 

$636 

 

$448 

 

$1,345 

 

$1,160 

 

 

Entergy

 

Entergy

 

Entergy

 

Entergy

 

Entergy

 

System

2003

 

Arkansas

 

Gulf States

 

Louisiana

 

Mississippi

 

New Orleans

 

Energy

 

 

(In Thousands)

Service cost - benefits earned

 

 

 

 

 

 

 

 

 

 

 

 

  during the period

 

$2,730 

 

$1,719 

 

$1,377 

 

$567 

 

$360 

 

$693 

Interest cost on projected

 

 

 

 

 

 

 

 

 

 

 

 

  benefit obligation

 

8,265 

 

6,036 

 

4,449 

 

1,914 

 

918 

 

996 

Expected return on assets

 

(10,506)

 

(9,228)

 

(6,771)

 

(2,724)

 

(681)

 

(942)

Amortization of transition asset

 

 

 

 

 

 

(81)

Amortization of prior service cost

 

462 

 

417 

 

162 

 

102 

 

60 

 

21 

Net pension cost/(income)

 

$951 

 

($1,056)

 

($783)

 

($141)

 

$657 

 

$687 

 

 

The domestic utility companies' and System Energy's pension cost/(income), including amounts capitalized, for the nine months ended September 30, 2004 and 2003, included the following components:

 

 

Entergy

 

Entergy

 

Entergy

 

Entergy

 

Entergy

 

System

2004

 

Arkansas

 

Gulf States

 

Louisiana

 

Mississippi

 

New Orleans

 

Energy

 

 

(In Thousands)

Service cost - benefits earned

 

 

 

 

 

 

 

 

 

 

 

 

  during the period

 

$8,871 

 

$7,275 

 

$5,187 

 

$2,800 

 

$1,241 

 

$2,506 

Interest cost on projected

 

 

 

 

 

 

 

 

 

 

 

 

  benefit obligation

 

26,194 

 

21,335 

 

15,806 

 

8,760 

 

3,198 

 

3,760 

Expected return on assets

 

(27,783)

 

(29,763)

 

(20,681)

 

(11,065)

 

(2,043)

 

(3,236)

Amortization of transition asset

 

 

 

 

 

 

(239)

Amortization of prior service cost

 

1,250 

 

1,308 

 

541 

 

410 

 

171 

 

53 

Amortization of loss

 

2,565 

 

470 

 

607 

 

537 

 

480 

 

542 

Net pension cost

 

$11,097 

 

$625 

 

$1,460 

 

$1,442 

 

$3,047 

 

$3,386 

 

 

 

Entergy

 

Entergy

 

Entergy

 

Entergy

 

Entergy

 

System

2003

 

Arkansas

 

Gulf States

 

Louisiana

 

Mississippi

 

New Orleans

 

Energy

 

 

(In Thousands)

Service cost - benefits earned

 

 

 

 

 

 

 

 

 

 

 

 

  during the period

 

$7,426 

 

$6,113 

 

$4,521 

 

$2,665 

 

$1,100 

 

$2,021 

Interest cost on projected

 

 

 

 

 

 

 

 

 

 

 

 

  benefit obligation

 

22,481 

 

21,468 

 

14,607 

 

9,018 

 

2,804 

 

2,906 

Expected return on assets

 

(28,576)

 

(32,824)

 

(22,233)

 

(12,830)

 

(2,079)

 

(2,746)

Amortization of transition asset

 

 

 

 

 

 

(237)

Amortization of prior service cost

 

1,256 

 

1,487 

 

534 

 

482 

 

180 

 

59 

Net pension cost/(income)

 

$2,587 

 

($3,756)

 

($2,571)

 

($665)

 

$2,005 

 

$2,003 

Components of Net Other Postretirement Benefit Cost

The domestic utility companies' and System Energy's other postretirement benefit cost, including amounts capitalized, for the third quarters of 2004 and 2003, included the following components:

 

 

Entergy

 

Entergy

 

Entergy

 

Entergy

 

Entergy

 

System

2004

 

Arkansas

 

Gulf States

 

Louisiana

 

Mississippi

 

New Orleans

 

Energy

 

 

(In Thousands)

Service cost - benefits earned

 

 

 

 

 

 

 

 

 

 

 

 

  during the period

 

$965 

 

$1,333 

 

$592 

 

$303 

 

$166 

 

$347 

Interest cost on APBO

 

2,518 

 

2,763 

 

1,660 

 

806 

 

801 

 

358 

Expected return on assets

 

(1,553)

 

(1,248)

 

 

(639)

 

(565)

 

(340)

Amortization of transition obligation

 

266 

 

1,147 

 

301 

 

108 

 

530 

 

Amortization of prior service cost

 

 

 

24 

 

 

 

(90)

Amortization of loss

 

985 

 

404 

 

502 

 

375 

 

131 

 

89 

Net other postretirement benefit cost

 

$3,189 

 

$4,399 

 

$3,079 

 

$957 

 

$1,072 

 

$367 

 

 

 

Entergy

 

Entergy

 

Entergy

 

Entergy

 

Entergy

 

System

2003

 

Arkansas

 

Gulf States

 

Louisiana

 

Mississippi

 

New Orleans

 

Energy

 

 

(In Thousands)

Service cost - benefits earned

 

 

 

 

 

 

 

 

 

 

 

 

  during the period

 

$1,923 

 

$1,491 

 

$1,104 

 

$528 

 

$324 

 

$471 

Interest cost on APBO

 

2,718 

 

2,775 

 

1,788 

 

885 

 

891 

 

363 

Expected return on assets

 

(1,158)

 

(1,098)

 

 

(522)

 

(492)

 

(258)

Amortization of transition obligation

 

987 

 

1,452 

 

744 

 

375 

 

669 

 

54 

Amortization of prior service cost

 

63 

 

69 

 

36 

 

21 

 

24 

 

Amortization of loss

 

858 

 

255 

 

342 

 

300 

 

105 

 

99 

Net other postretirement benefit cost

 

$5,391 

 

$4,944 

 

$4,014 

 

$1,587 

 

$1,521 

 

$735 

The domestic utility companies' and System Energy's other postretirement benefit cost, including amounts capitalized, for the nine months ended September 30, 2004 and 2003, included the following components:

 

 

Entergy

 

Entergy

 

Entergy

 

Entergy

 

Entergy

 

System

2004

 

Arkansas

 

Gulf States

 

Louisiana

 

Mississippi

 

New Orleans

 

Energy

 

 

(In Thousands)

Service cost - benefits earned

 

 

 

 

 

 

 

 

 

 

 

 

  during the period

 

$3,424 

 

$4,277 

 

$1,925 

 

$1,024 

 

$548 

 

$1,076 

Interest cost on APBO

 

7,745 

 

8,575 

 

5,004 

 

2,387 

 

2,438 

 

1,117 

Expected return on assets

 

(4,684)

 

(3,739)

 

 

(1,923)

 

(1,689)

 

(966)

Amortization of transition obligation

 

743 

 

3,442 

 

901 

 

319 

 

1,588 

 

10 

Amortization of prior service cost

 

71 

 

 

80 

 

30 

 

29 

 

(265)

Amortization of loss

 

3,170 

 

1,567 

 

1,522 

 

1,072 

 

387 

 

320 

Net other postretirement benefit cost

 

$10,469 

 

$14,122 

 

$9,432 

 

$2,909 

 

$3,301 

 

$1,292 

 

 

Entergy

 

Entergy

 

Entergy

 

Entergy

 

Entergy

 

System

2003

 

Arkansas

 

Gulf States

 

Louisiana

 

Mississippi

 

New Orleans

 

Energy

 

 

(In Thousands)

Service cost - benefits earned

 

 

 

 

 

 

 

 

 

 

 

 

  during the period

 

$5,203 

 

$4,123 

 

$3,026 

 

$1,458 

 

$858 

 

$1,309 

Interest cost on APBO

 

8,058 

 

8,209 

 

5,258 

 

2,625 

 

2,667 

 

1,065 

Expected return on assets

 

(3,542)

 

(3,314)

 

 

(1,622)

 

(1,518)

 

(802)

Amortization of transition obligation

 

2,963 

 

4,356 

 

2,232 

 

1,125 

 

2,007 

 

162 

Amortization of prior service cost

 

187 

 

207 

 

108 

 

63 

 

70 

 

18 

Amortization of loss

 

2,122 

 

593 

 

812 

 

748 

 

247 

 

231 

Net other postretirement benefit cost

 

$14,991 

 

$14,174 

 

$11,436 

 

$4,397 

 

$4,331 

 

$1,983 

Employer Contributions

In April 2004, the President signed the Pension Funding Equity Act of 2004 into law, which reduced Entergy's estimated 2004 required pension contribution. The domestic utility companies and System Energy expect to contribute the following to pension plans in 2004:

 

 

Entergy

 

Entergy

 

Entergy

 

Entergy

 

Entergy

 

System

 

 

Arkansas

 

Gulf States

 

Louisiana

 

Mississippi

 

New Orleans

 

Energy

 

 

(In Thousands)

Expected 2004 pension contributions

 

 

 

 

 

 

 

 

 

 

 

 

  disclosed in Form 10-K

 

$5,342

 

$37

 

$8,630

 

$2,989

 

$4,678

 

$5,369

Revised expected 2004 pension

 

 

 

 

 

 

 

 

 

 

 

 

  contributions

 

$5,342

 

$17

 

$3,907

 

$1,823

 

$2,118

 

$3,742

Contributions made in the nine months
  ended September 30, 2004

 


$5,342

 


$17

 


$3,907

 


$1,823

 


$2,118

 


$3,742

Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act)

As disclosed in Note 11 to the domestic utility companies and System Energy's financial statements in the Form 10-K, Entergy elected to record an estimate of the effects of the Medicare Act in December 2003. In August 2004, the Centers for Medicare and Medicaid Services issued proposed regulations to implement the new Medicare law. Based on actuarial analysis at September 30, 2004, the estimated effect of future Medicare subsidies reduced the January 1, 2004 Accumulated Postretirement Benefit Obligation (APBO), third quarter 2004 other postretirement benefit cost, and nine months ended September 30, 2004 other postretirement benefit cost for the domestic utility companies and System Energy as follows:

 

 

Entergy

 

Entergy

 

Entergy

 

Entergy

 

Entergy

 

System

 

 

Arkansas

 

Gulf States

 

Louisiana

 

Mississippi

 

New Orleans

 

Energy

 

 

(In Thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Reduction in 1/1/2004 APBO

 

($28,824)

 

($25,603)

 

($16,194)

 

($9,888)

 

($8,035)

 

($3,811)

Reduction in third quarter 2004

 

 

 

 

 

 

 

 

 

 

 

 

  other postretirement benefit cost

 

($1,249)

 

($1,101)

 

($688)

 

($414)

 

($312)

 

($204)

Reduction in nine months ended
  September 30, 2004 other
  postretirement benefit cost

 



($2,524)

 



($2,476)

 



($1,525)

 



($820)

 



($717)

 



($418)

__________________________________

In the opinion of the management of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy, 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 domestic utility companies and System Energy is subject to seasonal fluctuations, however, 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.

 

Item 4. Controls and Procedures

Disclosure Controls and Procedures

As of September 30, 2004, evaluations were performed under the supervision and with the participation of Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy Resources (individually "Registrant" and collectively the "Registrants") management, including their respective Chief Executive Officers (CEO) and Chief Financial Officers (CFO). The evaluations assessed the effectiveness of the Registrants' disclosure controls and procedures. Based on the evaluations, each CEO and CFO has concluded that, as to the Registrant or Registrants for which they serve as CEO or CFO, the Registrants' disclosure controls and procedures are effective to ensure that information required to be disclosed by each Registrant in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.

Changes in Internal Control Over Financial Reporting

In management's evaluation of the Registrants' disclosure controls and procedures, management identified the following initiative as a change that is reasonably likely to affect the Registrants' internal control over financial reporting. Over the last two years, Entergy has been working on an initiative to streamline financial processes, automate and enhance internal controls, and implement or update the systems that support these processes.  During the first quarter 2004, the first phase of this effort was completed, the primary focus of which was an upgrade of the existing financial information systems, data warehouse, and financial reporting tools, as well as an update of Entergy's chart of accounts. The implemented product suite includes additional controls and edits that are applied to transactions at the point of entry. Entergy implemented the second phase of this project during the third quarter 2004, which resulted in new tools for managing intercompany cost allocation processes and the modification of transaction systems which interface to Entergy's financial systems to incorporate the updated chart of accounts.  These changes embed additional automated controls into Entergy's systems and processes. This completes the work contemplated for 2004. Entergy has implemented a moratorium on changes to information technology components during the fourth quarter 2004, other than emergency repairs.

 

ENTERGY CORPORATION AND SUBSIDIARIES

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

See "PART I, Item 1, Litigation" in the Form 10-K for a discussion of legal proceedings affecting Entergy. Following are updates to that discussion.

Entergy New Orleans Rate of Return Lawsuit (Entergy Corporation and Entergy New Orleans)

See "PART I, Item 1, Entergy New Orleans Rate of Return Lawsuit" in the Form 10-K for a discussion of the motion filed by the City Council Advisors to bifurcate the hearing for the motions filed by the plaintiffs. In April 2004, the City Council adopted a resolution granting the Advisors' motion to bifurcate and a hearing is set in April 2005 on the merits of the issue of the proper effect to be given to the 1922 Ordinance in setting lawful rates.

Texas Power Price Lawsuit (Entergy Corporation, Entergy Arkansas and Entergy Gulf States)

See "Part I, Item 1, Texas Power Price Lawsuit" in the Form 10-K for a discussion of the litigation pending in state court in Chambers County, Texas by Texas residents on behalf of a purported class apparently of the Texas retail customers of Entergy Gulf States who were billed and paid for electric power from January 1, 1994 to the present. Originally Entergy Gulf States was not a named defendant but was alleged to be a co-conspirator. The court has granted the request of Entergy Gulf States to intervene in the suit to protect its interests. In addition, the Entergy defendants have filed a motion seeking to have the court dismiss all claims due to lack of subject matter jurisdiction. A hearing was held on October 5, 2004.

Murphy Oil Lawsuit (Entergy Corporation)

See "Part I, Item 1, Murphy Oil Lawsuit" in the Form 10-K for a discussion of the litigation commenced by residents located near the Murphy Oil Refinery in Meraux, Louisiana in which Murphy Oil filed a cross-claim against Entergy Louisiana seeking recovery of any damages Murphy Oil has paid to the plaintiffs. Claiborne P. Deming, who is a director of Entergy Corporation, is the President and Chief Executive Officer of Murphy Oil. Murphy Oil and other defendants settled with the plaintiffs for $8.8 million, but Entergy Louisiana did not participate in the settlement. After trial for the remaining parties in the proceeding, the judge issued a decision finding Entergy Louisiana 40% responsible and awarding monetary damages, which total approximately $11 million with interest against Entergy Louisiana. Entergy Louisiana intends to appeal the judgment. Entergy Louisiana has insurance in place for claims of this type, and management does not expect a material adverse financial effect from this decision.

Fiber Optic Cable Litigation (Entergy Corporation, Entergy Gulf States, Entergy Louisiana, and Entergy Mississippi)

See "PART I, Item 1, Fiber Optic Cable Litigation" in the Form 10-K for a discussion of the litigation pending in the United States District Court in Beaumont, Texas pertaining to the alleged installment by defendants of fiber optic cable across plaintiffs' property without obtaining appropriate easements. In April 2004, the court entered an order denying the plaintiffs' request for class certification. The plaintiffs have appealed this decision to the U.S. Fifth Circuit Court of Appeals.

With respect to the lawsuit against Entergy Louisiana, Entergy Services, ETHC and Entergy Technology Company pending in state court in St. James Parish, Louisiana purportedly on behalf of all property owners in Louisiana who have conveyed easements to the defendants, the state district judge has entered an order certifying a class. Entergy is seeking appellate review of this order.

Several property owners filed a lawsuit in August 2004 against Entergy Mississippi in state court in Montgomery County, Mississippi alleging that Entergy Mississippi installed fiber optic cable across their properties without obtaining appropriate easements. The plaintiffs seek actual damages for the use of the land, a share of the profits made through use of the fiber optic cables, and $20 million in punitive damages. In addition, in August 2004, a separate lawsuit containing allegations similar to the lawsuit pending in Montgomery County, Mississippi was filed by several property owners in state court in Leflore County, Mississippi. The plaintiffs seek actual damages for the use of the land, a share of the profits made through use of the fiber optic cables, and an unspecified amount of punitive damages.

Michoud Plant Wildlife Inspection (Entergy New Orleans)

In March 2004, agents of the United States Fish and Wildlife Service conducted an inspection of Entergy New Orleans' Michoud power plant and found a number of dead brown pelicans near the facility's water intake structure and fish-return trough. Brown pelicans are an endangered species in Louisiana. The United States Attorney's Office for the Eastern District of Louisiana (Attorney's Office) issued a grand jury subpoena to an Entergy New Orleans employee in May 2004 to give evidence regarding the cause of death of the pelicans. The Attorney's Office then agreed to meet with Entergy New Orleans rather than requiring the employee to testify. As a result of that meeting, Entergy New Orleans conducted an internal investigation of the matter and submitted a report to the Attorney's Office in August 2004. Entergy New Orleans also constructed an engineered walkway and cover over the intake structure and feeding trough to eliminate pelican access to the area. Entergy New Orleans continues negotiations with the Attorney's Office regarding final resolution of this matter.

Item 2. Unregistered Sales of Equity Securities and Use Of Proceeds

Issuer Purchases of Equity Securities (1)

Period

 

Total Number of
Shares Purchased

 

Average Price Paid
per Share

 

Total Number of
Shares Purchased as Part of a Publicly
Announced Plan

 

Maximum $ Amount
of Shares that May
Yet to be Purchased Under the Plan

 

 

 

 

 

 

 

 

 

7/01/2004-7/31/2004

 

-

 

-

 

-

 

-

8/01/2004-8/31/2004

 

-

 

-

 

-

 

-

9/01/2004-9/30/2004

 

2,382,000

 

$60.87

 

1,541,732

 

$1,406,154,773

Total

 

2,382,000

 

$60.87

 

1,541,732

 

$1,406,154,773

(1)

In accordance with Entergy's stock option plans, Entergy periodically grants stock options to its employees, which may be exercised to obtain shares of Entergy's common stock. According to the plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. See Note 8 to the consolidated financial statements in the Form 10-K for additional discussion of the stock option plans. Entergy's management has been authorized to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans, and this authorization does not have an expiration date. In August 2004, Entergy announced a program under which Entergy Corporation will repurchase up to $1.5 billion of its common stock. The program extends through the end of 2006. This repurchase program is incremental to the existing authority to repurchase shares to fund the exercise of employee stock options. The amount of repurchases under the program may vary as a result of material changes in business results or capital spending, or as a result of material new investment opportunities.

 

Item 5. Other Information

Property and Other Generation Resources

See "PART I, Item 1, Generating Stations" in the Form 10-K for discussion of the agreement that Entergy Louisiana signed in January 2004 to acquire the Perryville power plant from a subsidiary of Cleco Corporation. As reported in the Form 10-K, the plant's owner is in Chapter 11 bankruptcy proceedings. In April 2004, the bankruptcy court approved Entergy Louisiana's agreement to acquire the plant. In March 2004, Entergy Gulf States and Entergy Louisiana filed with the LPSC for its approval of the acquisition and long-term cost-of-service power purchase agreement, and hearings were scheduled for November 2004, but the procedural schedule has been suspended. Entergy has proposed a new hearing date in the first quarter 2005. In October 2004, Entergy Louisiana signed an amendment to the acquisition agreement to remove certain interconnection facilities and address some other matters. None of these amendments changed the terms of the acquisition materially. The FERC issued an order in October 2004 disclaiming jurisdiction over the acquisition. Assuming regulatory approvals, Entergy Louisiana expects the Perryville acquisition to close in mid-2005.

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

Also see "PART I, Item 1, Generating Stations" in the Form 10-K for discussion of the affiliate purchase transactions that resulted from Entergy's requests for proposals for supply-side resources. In the proceeding at the FERC to review the justness and reasonableness of the affiliate agreements, in March 2004 the FERC staff filed testimony that claims Entergy conveyed undue preference to its affiliates in the bidding process. Hearings in the proceeding commenced in June 2004 and are ongoing.

Wholesale Rate Matters

See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - Significant Factors and Known Trends" in this report for updates of the information contained in " PART I, Item 1, Wholesale Rate Matters" regarding the System Agreement, Transmission, FERC's Supply Margin Assessment, and Interconnection Orders.

 

FERC Reviews of Transmission

In August 2002, the FERC initiated audits and reviews of Entergy's compliance with Order Nos. 888 and 889 and its open access transmission tariff, and in March 2004 a separate audit was initiated concerning Entergy's administration of the Generator Operating Limits ("GOL") processes.  Entergy has responded to numerous FERC data requests and the FERC staff members have interviewed several employees.  The FERC staff has provided Entergy with preliminary draft reports of their findings and recommendations on the issues that they have been examining. The GOL draft audit report identifies and alleges certain input and modeling errors in the implementation of the GOL process (which was replaced in April 2004) and preliminarily recommends, among other things, that Entergy employ an independent third party to conduct certain transmission access modeling. Entergy believes that these recommendations are based on a number of inaccuracies and has and will continue to provide comments on the various findings and the recommendations.  Separately, the FERC investigation staff has provided to Entergy its preliminary findings in a non-public draft report identifying certain areas of concern related to Entergy's compliance with certain provisions of its open access transmission tariff, including the time it took for Entergy to process requests to interconnect generating facilities to Entergy's transmission system and the processing of system impact studies related to the granting of transmission service. Entergy has submitted a comprehensive response to the specific concerns identified by the investigation staff but, at this point, believes that it has complied with the provisions of its open access transmission tariff, including the interconnection and system impact study provisions. These draft reports are not final reports; they may be modified by the FERC staff based on Entergy's responses or otherwise.  In addition, Entergy has the ability to appeal the final reports to the full FERC.

 

FERC Review of Certain Wholesale Transactions

The FERC is currently reviewing certain wholesale sales and purchases involving EPMC that occurred during the 1998-2001 time period. EPMC was an Entergy subsidiary engaged in non-regulated wholesale marketing and trading activities prior to the formation of Entergy-Koch. Entergy is working with the FERC investigation staff to provide information regarding these transactions.

 

Regulation of the Nuclear Power Industry

Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. See "PART I, Item 1, Nuclear Waste Policy Act of 1982," for further discussion of this Act. The fees payable to the DOE may be adjusted in the future to assure full recovery of the DOE's costs, and Entergy cannot state with certainty that the fees will not be increased in the future.

The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. DOE will now proceed with the licensing and, if the license is granted by the NRC and if Congress appropriates adequate funds to DOE to complete the project, eventual construction of the repository will begin and receipt of spent fuel may begin as early as approximately 2010, according to the DOE. Considerable uncertainty remains regarding the time frame under which the DOE will begin to accept spent fuel from Entergy's facilities for storage or disposal, and could be several years after 2015. Additional uncertainty was added on July 9, 2004, when the U.S. Court of Appeals vacated a portion of the EPA nuclear waste disposal standard regarding the required compliance period for the repository. It is not known what impact this will have on the Yucca Mountain schedule, but further delays are possible as the EPA and NRC work to reestablish a standard. As a result of the delays in establishing a permanent repository, future expenditures will be required to increase spent fuel storage capacity at Entergy's nuclear plant sites.

Environmental Regulation

See "PART I, Item 1, Clean Air Act and Subsequent Amendments, Ozone Non-attainment" in the Form 10-K for information related to Louisiana and Texas emission control strategies to address continued ozone non-attainment status of areas in and around Houston-Galveston, Texas; Beaumont-Port Arthur, Texas; and Baton Rouge, Louisiana. The EPA has now reclassified the Beaumont-Port-Arthur area from "moderate" to "serious" and has reclassified the Baton Rouge area from "serious" to "severe". These actions require that Texas and Louisiana revise their respective plans to restrict the emission of certain air pollutants and to make progress toward eventual attainment of national standards. The Louisiana plan revisions were due in June 2004; however, because of legal and environmental regulatory disputes over a requirement for reformulated gasoline in the Baton Rouge area unrelated to Entergy's interests in the state implementation plan, the State has chosen to delay the submittal.  The Texas plan revisions must be submitted in April 2005. The content or effect of these developing plans is not fully known, but Entergy Gulf States continues to monitor events in these areas. If new NOx control equipment is required to be installed, the cost could be as much as $1.6 million for the facilities in Louisiana in 2004 and early 2005. Information recently published by the State of Texas in support of the state implementation plan indicates that new NOx control equipment will not be required at Entergy Gulf States' Texas facilities.

In April 2004, the EPA issued a final rule, effective June 15, 2005, stating that areas designated as non-attainment under a new "8-hour ozone standard" shall have one year to adjust to the new requirements. For Louisiana, the Baton Rouge area is to be classified as a marginal non-attainment area under the new standard with an attainment date of June 2007. For Texas, the Beaumont-Port Arthur area was designated as a marginal non-attainment area under the new standard with an attainment date of June 2007 and the Houston-Galveston area was designated as moderate non-attainment under the new standard with an attainment date of June 2010. Entergy continues to monitor these regulatory activities and to plan for necessary future action at its facilities.

See "PART I, Item 1, Clean Water Act, 316(b) Cooling Water Intake Structures" in the Form 10-K for information related to the draft permit issued by the New York State Department of Environmental Conservation (NYDEC) indicating that closed cycle cooling would be considered the "best technology available" for minimizing perceived adverse environmental impacts attributable to the intake and discharge of cooling water at large existing power plants. Entergy is currently in various stages of the discharge permitting process at two sites and has adopted a strategy for Pilgrim and Indian Point as a result of recent developments. Pilgrim expects to request from the EPA the full 3-1/2 year schedule for compliance demonstration as is outlined in the new 316(b) rule and will also pursue appropriate supplementation of the existing record regarding perceived impacts, options and costs. Indian Point is involved in an administrative permitting process with the New York environmental authority for renewal of the Indian Point 2 and 3 discharge permits. In November 2003, NYDEC issued a draft permit indicating that closed cycle cooling would be considered the "best technology available" for minimizing perceived adverse environmental impacts attributable to the intake and discharge of cooling water at Indian Point 2 and 3. The draft permit would require Entergy to take certain steps to assess the feasibility of retrofitting the site to install cooling towers before re-licensing Indian Point 2 and 3, whose current licenses with the NRC expire in 2013 and 2015. The draft permit could also require, upon its becoming effective, the facilities to take an annual 42 unit-day outage and provide a payment into a NYDEC account until the start of cooling tower construction. Entergy is participating in the administrative process in order to have the draft permit modified prior to final issuance, and opposes any requirement to install cooling towers or begin annual forced outages at Indian Point 2 and 3. The EPA finalized new 316(b) regulations in July 2004. Entergy Corporation, other industry members and industry groups, environmental groups, and a coalition of northeastern and mid-Atlantic states have challenged various aspects of the rule. This challenge currently is lodged in the United States Court of Appeals for the Ninth Circuit in San Francisco, although a motion to transfer the case to the Second Circuit in New York City has been filed. Entergy will continue to participate in and monitor this proceeding.

Earnings Ratios (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

The domestic utility companies and System Energy have calculated ratios of earnings to fixed charges and ratios of earnings to combined fixed charges and preferred dividends pursuant to Item 503 of Regulation S-K of the SEC as follows:

 

Ratios of Earnings to Fixed Charges

 

Twelve Months Ended

 

December 31,

 

September 30,

 

1999

 

2000

 

2001

 

2002

 

2003

 

2004

                       

Entergy Arkansas

2.08

 

3.01

 

3.29

 

2.79

 

3.17

 

3.04

Entergy Gulf States

2.18

 

2.60

 

2.36

 

2.49

 

1.51

 

2.59

Entergy Louisiana

3.48

 

3.33

 

2.76

 

3.14

 

3.93

 

3.32

Entergy Mississippi

2.44

 

2.33

 

2.14

 

2.48

 

3.06

 

3.03

Entergy New Orleans

3.00

 

2.66

 

(b)

 

(c)

 

1.73

 

2.83

System Energy

1.90

 

2.41

 

2.12

 

3.25

 

3.66

 

3.76

 

Ratios of Earnings to Combined Fixed Charges
and Preferred Dividends

 

Twelve Months Ended

 

December 31,

 

September 30,

 

1999

 

2000

 

2001

 

2002

 

2003

 

2004

                       

Entergy Arkansas

1.80

 

2.70

 

2.99

 

2.53

 

2.79

 

2.66

Entergy Gulf States (a)

1.86

 

2.39

 

2.21

 

2.40

 

1.45

 

2.48

Entergy Louisiana

3.09

 

2.93

 

2.51

 

2.86

 

3.46

 

2.91

Entergy Mississippi

2.18

 

2.09

 

1.96

 

2.27

 

2.77

 

2.73

Entergy New Orleans

2.74

 

2.43

 

(b)

 

(c)

 

1.59

 

2.51

(a)

"Preferred Dividends" in the case of Entergy Gulf States also include dividends on preference stock for the twelve months ended December 31, 1999, which was redeemed in July 2000.

(b)

Earnings for the twelve months ended December 31, 2001, for Entergy New Orleans were not adequate to cover fixed charges and combined fixed charges and preferred dividends by $6.6 million and $9.5 million, respectively.

(c)

Earnings for the twelve months ended December 31, 2002, for Entergy New Orleans were not adequate to cover fixed charges and combined fixed charges and preferred dividends by $0.7 million and $3.4 million, respectively.

Item 6. Exhibits

Exhibits*

 

4(a) -

Twelfth Supplemental Indenture, dated as of August 1, 2004, to Entergy New Orleans' Mortgage and Deed of Trust, dated as of May 1, 1987.

     
 

4(b) -

Thirteenth Supplemental Indenture, dated as of August 15, 2004, to Entergy New Orleans' Mortgage and Deed of Trust, dated as of May 1, 1987.

     

**

4(c) -

Twenty-fourth Supplemental Indenture, dated as of September 1, 2004, to Entergy Mississippi's Mortgage and Deed of Trust, dated as of February 1, 1988 (filed as Exhibit A-3(c) to Rule 24 Certificate dated October 4, 2004 in File No. 70-10157).

     

**

4(d) -

Fifty-eighth Supplemental Indenture, dated as of October 1, 2004, to Entergy Louisiana's Mortgage and Deed of Trust, dated as of April 1, 1944 (filed as Exhibit A-3(b) to Rule 24 Certificate dated October 15, 2004 in File No. 70-10086).

     
 

4(e) -

Sixty-second Supplemental Indenture, dated as of October 1, 2004, to Entergy Arkansas' Mortgage and Deed of Trust, dated as of October 1, 1944.

     

**

4(f) -

Fifty-ninth Supplemental Indenture, dated as of October 15, 2004, to Entergy Louisiana's Mortgage and Deed of Trust, dated as of April 1, 1944 (filed as Exhibit A-3(c) to Rule 24 Certificate dated October 26, 2004 in File No. 70-10086).

     

**

4(g) -

Sixty-seventh Supplemental Indenture, dated as of October 1, 2004, to Entergy Gulf States' Indenture of Mortgage, dated as of September 1, 1926 (filed as Exhibit A-3(i) to Rule 24 Certificate dated November 4, 2004 in File No. 70-10158).

     
 

31(a) -

Rule 13a-14(a)/15d-14(a) Certification for Entergy Corporation.

     
 

31(b) -

Rule 13a-14(a)/15d-14(a) Certification for Entergy Corporation.

     
 

31(c) -

Rule 13a-14(a)/15d-14(a) Certification for Entergy Arkansas.

     
 

31(d) -

Rule 13a-14(a)/15d-14(a) Certification for Entergy Gulf States.

     
 

31(e) -

Rule 13a-14(a)/15d-14(a) Certification for Entergy Gulf States and Entergy Louisiana.

     
 

31(f) -

Rule 13a-14(a)/15d-14(a) Certification for Entergy Mississippi.

     
 

31(g) -

Rule 13a-14(a)/15d-14(a) Certification for Entergy New Orleans.

     
 

31(h) -

Rule 13a-14(a)/15d-14(a) Certification for System Energy.

     
 

31(i) -

Rule 13a-14(a)/15d-14(a) Certification for Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans.

     
 

31(j) -

Rule 13a-14(a)/15d-14(a) Certification for System Energy.

     
 

32(a) -

Section 1350 Certification for Entergy Corporation.

     
 

32(b) -

Section 1350 Certification for Entergy Corporation.

     
 

32(c) -

Section 1350 Certification for Entergy Arkansas.

     
 

32(d) -

Section 1350 Certification for Entergy Gulf States.

     
 

32(e) -

Section 1350 Certification for Entergy Gulf States and Entergy Louisiana.

     
 

32(f) -

Section 1350 Certification for Entergy Mississippi.

     
 

32(g) -

Section 1350 Certification for Entergy New Orleans.

     
 

32(h) -

Section 1350 Certification for System Energy.

     
 

32(i) -

Section 1350 Certification for Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans.

     
 

32(j) -

Section 1350 Certification for System Energy.

     
 

99(a) -

Entergy Arkansas' Computation of Ratios of Earnings to Fixed Charges and of Earnings to Combined Fixed Charges and Preferred Dividends, as defined.

     
 

99(b) -

Entergy Gulf States' Computation of Ratios of Earnings to Fixed Charges and of Earnings to Combined Fixed Charges and Preferred Dividends, as defined.

     
 

99(c) -

Entergy Louisiana's Computation of Ratios of Earnings to Fixed Charges and of Earnings to Combined Fixed Charges and Preferred Dividends, as defined.

     
 

99(d) -

Entergy Mississippi's Computation of Ratios of Earnings to Fixed Charges and of Earnings to Combined Fixed Charges and Preferred Dividends, as defined.

     
 

99(e) -

Entergy New Orleans' Computation of Ratios of Earnings to Fixed Charges and of Earnings to Combined Fixed Charges and Preferred Dividends, as defined.

     
 

99(f) -

System Energy's Computation of Ratios of Earnings to Fixed Charges, as defined.

___________________________

Pursuant to Item 601(b)(4)(iii) of Regulation S-K, Entergy Corporation agrees to furnish to the Commission upon request any instrument with respect to long-term debt that is not registered or listed herein as an Exhibit because the total amount of securities authorized under such agreement does not exceed ten percent of the total assets of Entergy Corporation and its subsidiaries on a consolidated basis.

*

Reference is made to a duplicate list of exhibits being filed as a part of this report on Form 10-Q for the quarter ended September 30, 2004, which list, prepared in accordance with Item 102 of Regulation S-T of the SEC, immediately precedes the exhibits being filed with this report on Form 10-Q for the quarter ended September 30, 2004.

   

**

Incorporated herein by reference as indicated.

SIGNATURE

 

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.

ENTERGY CORPORATION
ENTERGY ARKANSAS, INC.
ENTERGY GULF STATES, INC.
ENTERGY LOUISIANA, INC.
ENTERGY MISSISSIPPI, INC.
ENTERGY NEW ORLEANS, INC.
SYSTEM ENERGY RESOURCES, INC.

 

/s/ Nathan E. Langston
Nathan E. Langston
Senior Vice President and Chief Accounting Officer
(For each Registrant and for each as
Principal Accounting Officer)

 

Date: November 5, 2004