Back to GetFilings.com



Quick Links/Table of Contents

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  
June 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

Exact name of Registrant as specified in its charter,
State of incorporation, Address and Telephone number

IRS Employer
Identification No.

1-14766

Energy East Corporation
(A New York Corporation)
P. O. Box 12904
Albany, New York 12212-2904
(518) 434-3049
www.energyeast.com

14-1798693

1-5139

Central Maine Power Company
(A Maine Corporation)
83 Edison Drive
Augusta, Maine 04336
(207) 623-3521

01-0042740

1-3103-2

New York State Electric & Gas Corporation
(A New York Corporation)
P. O. Box 5224
Binghamton, New York 13902-5224
(607) 762-7200

15-0398550

1-672

Rochester Gas and Electric Corporation
(A New York Corporation)
89 East Avenue
Rochester, New York 14649
(585) 546-2700

16-0612110

Indicate by check mark whether each registrant (1) has 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 registrant was required to file such reports), and (2) has 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 Exchange Act).

Registrant

   

Energy East Corporation

Yes     X     

No             

Central Maine Power Company

Yes            

No     X      

New York State Electric & Gas Corporation

Yes            

No     X      

Rochester Gas and Electric Corporation

Yes            

No     X      

As of July 31, 2004, shares of common stock outstanding for each registrant were:

Registrant

Description

Shares

Energy East Corporation

Par value $.01 per share

146,706,572    

Central Maine Power Company

Par value $5 per share

31,211,471 (1)

New York State Electric & Gas Corporation

Par value $6.66 2/3 per share

64,508,477 (2)

Rochester Gas and Electric Corporation

Par value $5 per share

34,506,513 (2)

(1) All shares are owned by CMP Group, Inc., a wholly-owned subsidiary of Energy East Corporation.
(2) All shares are owned by RGS Energy Group, Inc. a wholly-owned subsidiary of Energy East Corporation.

This combined Form 10-Q is separately filed by Energy East Corporation, Central Maine Power Company, New York State Electric & Gas Corporation and Rochester Gas and Electric Corporation. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

 

 

 


Item

TABLE OF CONTENTS


Page

 

PART I - FINANCIAL INFORMATION

 

1
2

Financial Statements
Management's Discussion and Analysis of Financial Condition
    and Results of Operations

 
 

Energy East Corporation
  
Condensed Consolidated Statements of Income
  
Condensed Consolidated Balance Sheets
  
Condensed Consolidated Statements of Cash Flows
  
Condensed Consolidated Statements of Retained Earnings
  
Condensed Consolidated Statements of Comprehensive Income
  Management's Discussion and Analysis of Financial Condition
    and Results of Operations
  (a)
Liquidity and Capital Resources
  (b)
Results of Operations


1
2
4
5
5


6
16

 

Central Maine Power Company
  
Condensed Consolidated Statements of Income
  
Condensed Consolidated Balance Sheets
  
Condensed Consolidated Statements of Cash Flows
  
Condensed Consolidated Statements of Retained Earnings
  
Condensed Consolidated Statements of Comprehensive Income
  Management's Discussion and Analysis of Financial Condition
    and Results of Operations
  (a)
Liquidity and Capital Resources
  (b)
Results of Operations


19
20
22
22
22


23
24

 

New York State Electric & Gas Corporation
  
Condensed Statements of Income
  
Condensed Balance Sheets
  
Condensed Statements of Cash Flows
  
Condensed Statements of Retained Earnings
  
Condensed Statements of Comprehensive Income
  Management's Discussion and Analysis of Financial Condition
    and Results of Operations
  (a)
Liquidity and Capital Resources
  (b)
Results of Operations


25
26
28
29
29


30
31

 

Rochester Gas and Electric Corporation
  
Condensed Statements of Income
  
Condensed Balance Sheets
  
Condensed Statements of Cash Flows
  
Condensed Statements of Retained Earnings
  Management's Discussion and Analysis of Financial Condition
    and Results of Operations
  (a)
Liquidity and Capital Resources
  (b)
Results of Operations


33
34
36
36


37
38

 

 

 


Item

TABLE OF CONTENTS - continued


Page

1

Notes to Condensed Financial Statements

Forward-looking Statements

41

52

3

Quantitative and Qualitative Disclosures About Market Risk

53

4

Controls and Procedures

54

 

PART II - OTHER INFORMATION

 

2

Changes in Securities, Use and Proceeds and Issuer Purchases
of Equity Securities

54

4

Submission of Matters to a Vote of Security Holders

56

6

Exhibits and Reports on Form 8-K
(a) Exhibits
(b) Reports on Form 8-K

57

Signatures

58

Exhibit Index

59

PART I - FINANCIAL INFORMATION

Item 1.  Financial Statements

Energy East Corporation
Condensed Consolidated Statements of Income - (Unaudited
)

 

Three Months

Six Months

Periods ended June 30

2004

2003

2004

2003

(Thousands, except per share amounts)

       

Operating Revenues

       

  Sales and services

$980,566 

$979,113 

$2,561,639 

$2,483,944 

Operating Expenses

       

  Electricity purchased and fuel used in generation

338,253 

300,967 

734,906 

659,334 

  Natural gas purchased

169,700 

178,414 

669,549 

629,465 

  Other operating expenses

158,065 

199,916 

372,072 

394,539 

  Maintenance

42,814 

43,309 

85,476 

89,556 

  Depreciation and amortization

84,799 

73,774 

169,934 

149,107 

  Other taxes

58,248 

58,382 

133,670 

143,649 

  Gain on sale of generation assets

(319,487)

-      

(319,487)

-      

  Deferral of asset sale gain

214,368 

-      

214,368 

-      

      Total Operating Expenses

746,760 

854,762 

2,060,488 

2,065,650 

Operating Income

233,806 

124,351 

501,151 

418,294 

Other (Income)

(11,681)

(2,278)

(17,409)

(6,810)

Other Deductions

4,398 

1,261 

7,675 

3,048 

Interest Charges, Net

68,822 

68,090 

138,812 

135,825 

Preferred Stock Dividends of Subsidiaries

1,791 

8,739 

2,779 

17,157 

Income From Continuing Operations
  Before Income Taxes


170,476 


48,539 


369,294 


269,074 

Income Taxes

127,694 

20,206 

205,803 

109,050 

Income From Continuing Operations

42,782 

28,333 

163,491 

160,024 

Discontinued Operations

       

  (Loss) income from discontinued operations

(4,249)

(901)

(4,527)

5,058 

  Income taxes (benefits)

467 

(285)

346 

1,901 

(Loss) Income From Discontinued Operations

(4,716)

(616)

(4,873)

3,157 

Net Income

$38,066 

$27,717 

$158,618 

$163,181 

Earnings Per Share From Continuing
  Operations, basic


$.29 


$.19 


$1.12 


$1.10 

Earnings Per Share From Continuing
  Operations, diluted


$.29 


$.19 


$1.11 


$1.10 

Earnings Per Share From Discontinued
  Operations, basic


$(.03)


- -      


$(.03)


$.02 

Earnings Per Share From Discontinued
  Operations, diluted


$(.03)


- -      


$(.03)


..02 

Total Earnings Per Share, basic

$.26 

$.19 

$1.09 

$1.12 

Total Earnings Per Share, diluted

$.26 

$.19 

$1.08 

$1.12 

Dividends Paid Per Share

$.26 

$.25 

$.52 

$.50 

Average Common Shares Outstanding, basic

146,148 

145,415 

146,116 

145,256 

Average Common Shares Outstanding, diluted

146,596 

145,640 

146,512 

145,429 


The notes on pages 41 through 52 are an integral part of the financial statements.


Energy East Corporation
Condensed Consolidated Balance Sheets - (Unaudited)

June 30,
2004    

Dec. 31,
2003    

(Thousands)

   

Assets

   

Current Assets

   

 Cash and cash equivalents

$461,059

$113,187

 Special deposits

7,273

34,669

 Accounts receivable, net

600,846

753,328

 Fuel, at average cost

124,803

159,163

 Materials and supplies, at average cost

24,321

22,491

 Accumulated deferred income tax benefits, net

38,289

26,262

 Prepayments and other current assets

69,366

81,746

   Total Current Assets

1,325,957

1,190,846

Utility Plant, at Original Cost

   

 Electric

5,209,400

5,992,001

 Natural gas

2,453,826

2,405,795

 Common

408,831

361,737

8,072,057

8,759,533

 Less accumulated depreciation

2,523,200

3,216,927

   Net Utility Plant in Service

5,548,857

5,542,606

 Construction work in progress

69,042

235,503

   Total Utility Plant

5,617,899

5,778,109

Other Property and Investments, Net

190,382

465,609

Regulatory and Other Assets

   

 Regulatory Assets

   

  Nuclear plant obligations

379,367

414,432

  Unfunded future income taxes

114,542

254,977

  Unamortized loss on debt reacquisitions

48,595

47,509

  Environmental remediation costs

122,662

122,846

  Nonutility generator termination agreements

101,395

106,631

  Asset retirement obligation

-      

163,530

  Other

397,594

407,432

 Total regulatory assets

1,164,155

1,517,357

 Other Assets

   

  Goodwill, net

1,527,169

1,533,123

  Prepaid pension benefits

637,170

608,933

  Other

205,296

212,455

 Total other assets

2,369,635

2,354,511

   Total Regulatory and Other Assets

3,533,790

3,871,868

   Total Assets

$10,668,028

$11,306,432


The notes on pages 41 through 52 are an integral part of the financial statements.

 

Energy East Corporation
Condensed Consolidated Balance Sheets - (Unaudited)

 

June 30, 2004    

Dec. 31,  
2003    

(Thousands)

   

Liabilities

   

Current Liabilities

   

 Current portion of preferred stock of subsidiary subject to
  mandatory redemption requirements


- -      


$1,250 

 Current portion of long-term debt

$24,711 

30,989 

 Notes payable

31,201 

308,406 

 Accounts payable and accrued liabilities

390,469 

339,812 

 Interest accrued

47,395 

48,989 

 Taxes accrued

118,666 

43,710 

 Other

136,869 

191,873 

   Total Current Liabilities

749,311 

965,029 

Regulatory and Other Liabilities

   

 Regulatory liabilities

   

  Accrued removal obligation

735,879 

731,621 

  Deferred income taxes

14,858 

181,211 

  Gain on sale of generation assets

238,887 

129,640 

  Pension benefits

31,728 

51,970 

  Other

123,878 

96,509 

 Total regulatory liabilities

1,145,230 

1,190,951 

 Other liabilities

   

  Deferred income taxes

947,843 

853,489 

  Nuclear plant obligations

265,022 

277,643 

  Other postretirement benefits

424,817 

408,903 

  Asset retirement obligation

3,049 

437,076 

  Environmental remediation costs

147,897 

145,446 

  Other

365,769 

346,630 

 Total other liabilities

2,154,397 

2,469,187 

   Total Regulatory and Other Liabilities

3,299,627 

3,660,138 

 Debt owed to subsidiary holding solely parent debentures

355,670 

355,670 

 Preferred stock of subsidiary subject to mandatory
   redemption requirements


- -      


23,750 

 Other long-term debt

3,552,011 

3,638,426 

 Total long-term debt

3,907,681 

4,017,846 

   Total Liabilities

7,956,619 

8,643,013 

Commitments

-      

-      

Preferred Stock of Subsidiaries
 Redeemable solely at the option of subsidiaries


46,624 


91,095 

Common Stock Equity
 Common stock


1,467 


1,463 

 Capital in excess of par value

1,464,528 

1,458,802 

 Retained earnings

1,209,131 

1,126,457 

 Accumulated other comprehensive income (loss)

(2,931)

(11,214)

 Deferred compensation

(6,765)

(2,820)

 Treasury stock, at cost

(645)

(364)

   Total Common Stock Equity

2,664,785 

2,572,324 

   Total Liabilities and Stockholders' Equity

$10,668,028 

$11,306,432 


The
notes on pages 41 through 52 are an integral part of the financial statements.

 

 

Energy East Corporation
Condensed
Consolidated Statements of Cash Flows - (Unaudited)

Six months ended June 30

2004

2003

(Thousands)

   

  Net Cash Provided by Operating Activities

$405,808 

$377,971 

Investing Activities

   

 Proceeds from sale of generation assets

428,541 

-     

 Refund of excess decommissioning fund

76,593 

-     

 Utility plant additions

(123,554)

(112,955)

 Other property and investments additions

(2,045)

(13,631)

 Other property and investments sold

7,957 

5,054 

 Special deposits

27,396 

(81,134)

 Other

(3,501) 

(2,377)

   Net Cash Provided (Used) in Investing Activities

411,387 

(205,043)

Financing Activities

   

 Issuance of common stock

1,252 

2,466 

 Repurchase of common stock

(6,071)

-     

 Outstanding customer refund, overdraft

57,388 

-     

 Repayments of first mortgage bonds and preferred stock of
  subsidiaries, including net premiums


(162,053)


(115,270)

 Long-term note issuances

12,000 

196,986 

 Long-term note repayments

(12,778)

(6,140)

 Notes payable three months or less, net

(279,203)

(128,700)

 Notes payable issuances

3,000 

-     

 Notes payable repayments

(16,000)

(91,435)

 Dividends on common stock

(66,858)

(63,803)

   Net Cash Used in Financing Activities

(469,323)

(205,896)

Net Increase (Decrease) in Cash and Cash Equivalents

347,872 

(32,968)

Cash and Cash Equivalents, Beginning of Period

113,187 

250,490 

Cash and Cash Equivalents, End of Period

$461,059 

$217,522 


The notes on pages 41 through 52 are an integral part of the financial statements.


 

Energy East Corporation
Condensed
Consolidated Statements of Retained Earnings - (Unaudited)

Six months ended June 30

2004

2003

(Thousands)

   

Balance, Beginning of Period

$1,126,457

$1,061,428

     

Add net income

158,618

163,181

     

Deduct dividends on common stock

75,944

72,566

Balance, End of Period

$1,209,131

$1,152,043


The notes on pages 41 through 52 are an integral part of the financial statements.




Energy East Corporation
Condensed
Consolidated Statements of Comprehensive Income - (Unaudited)

 

Three Months

Six Months

Periods ended June 30

2004

2003

2004

2003

(Thousands)

       

Net income

$38,066 

$27,717 

$158,618 

$163,181 

Other comprehensive income, net of tax

       

  Net unrealized gains (losses) on investments,
   net of income tax (expense) for the
   three months of $- in 2004 and $(391) in
   2003 and for the six months of $- in 2004
   and $(642) in 2003





(947)





578 





(927)





964 

  Unrealized gains (losses) on derivatives
   qualified as hedges, net of income tax
   benefit (expense) for the three months of
   $(4,712) in 2004 and $4,737 in 2003 and for
   the six months of $(17,229) in 2004 and
   $(14,016) in 2003






7,104 






(7,012)






25,811 






21,808 

  Reclassification adjustment for derivative
   (gains) included in net income, net of
   income tax expense for the three
   months of $5,710 in 2004 and $2,544 in
   2003 and for the six months of $11,010 in
   2004 and $11,574 in 2003






(8,609)






(3,836)






(16,601)






(17,454)

  Net unrealized (losses) gains on derivatives
   qualified as hedges


(1,505)


(10,848)


9,210 


4,354 

    Total other comprehensive income (loss)

(2,452)

(10,270)

8,283 

5,318 

Comprehensive Income

$35,614 

$17,447 

$166,901 

$168,499 


The notes on pages 41 through 52 are an integral part of the financial statements.

Item 2.  Management's discussion and analysis of financial condition
             and results of operations

Energy East Corporation

Overview

Energy East Corporation's (Energy East or the company) management focuses its strategic efforts on those areas of the company that have the greatest effect on shareholder value. Efficient operations are a key aspect of increasing shareholder value. As discussed below, management has implemented plans to achieve savings through a company-wide restructuring, consolidation of utility support services and other changes.

In addition, because Energy East's primary operations - its electric and natural gas utility operations - are subject to rate regulation, the approved regulatory treatment on various matters could significantly affect the company's operations and, therefore, its financial position and results of operations. In May 2004 Rochester Gas and Electric Corporation (RG&E), an operating company of Energy East, received approval for long-term electric and natural gas rate plans. As a result, Energy East now has long-term rate plans for all of its major utility operating companies including New York State Electric & Gas Corporation (NYSEG), Central Maine Power Company (CMP), Connecticut Natural Gas Corporation (CNG), The Southern Connecticut Gas Company (SCG) and The Berkshire Gas Company (Berkshire Gas). The plans provide for sharing of achieved savings among customers and shareholders, allow for recovery of certain costs including exogenous and uncontrollable costs, and provide stable rates for customers a nd revenue predictability for those six operating companies.

Over the last several years Energy East has focused its strategic efforts on its electric and natural gas delivery operations, rather than on the more volatile electricity generation business, and has sought to rationalize its nonutility businesses to ensure they fit its strategic focus. As discussed below, RG&E successfully completed the sale of its Ginna nuclear generating station (Ginna) to Constellation Generation Group LLC (CGG) on June 10, 2004. In addition, on July 26, 2004, CMP Group, Inc. sold the majority of the assets of its subsidiary, Union Water Power Company (UWP).

The continuing evolution of the utility industry, particularly the electric utility industry, has resulted in several federal and state regulatory proceedings that could significantly affect operations, although the outcomes of those proceedings are difficult to predict. Those proceedings could have an effect on the nature of the electric and natural gas utility industry in New York and New England. Recent events in the proceedings are described below.

The company engages in various investing and financing activities to meet its strategic objectives. Investing activities are conducted primarily to maintain a reliable energy delivery infrastructure and are funded primarily with internally generated funds. Financing activities, therefore, are focused on maintaining adequate liquidity, improving credit quality and minimizing the cost of capital. As a result of the Ginna sale, the company will have funds available to reduce its outstanding debt as well as that of RG&E.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

(a) Liquidity and Capital Resources

Restructuring

In the first quarter of 2004 the company completed its consolidation of various accounting and finance functions. Energy East recognized a $4 million total liability for an enhanced severance program for 83 accounting and finance employees who were employed through March 31, 2004. The company recorded approximately $2 million of that liability as of the end of the fourth quarter of 2003 and recorded the remaining $2 million of the liability in the first quarter of 2004. The liability was entirely paid off as of June 30, 2004.

Electric Delivery Business

The company's electric delivery business consists primarily of its regulated electricity transmission, distribution and generation operations in upstate New York and Maine.

RG&E 2003 Electric and Natural Gas Rate Agreements: In May 2003 RG&E filed a rate case with the New York State Public Service Commission (NYPSC) to recover costs that RG&E has incurred and will continue to incur in providing safe and reliable electric and natural gas service. On May 20, 2004, the NYPSC approved Electric and Natural Gas Joint Proposals (Electric and Natural Gas Rate Agreements) that had been negotiated with Staff of the NYPSC and other interested parties and that address RG&E's electric and natural gas rates through 2008.

Key features of the Electric Rate Agreement include:

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

Key features of the Natural Gas Rate Agreement include:

The Electric and Natural Gas Rate Agreements resolve all outstanding issues in the RG&E Cost Deferral Petitions and the RG&E 2002 Electric and Gas Rate Proceeding. In addition, RG&E has withdrawn its appeal of an order the NYPSC issued in March 2003. (See report on Form 10-Q for Energy East and RG&E for the quarter ended March 31, 2004, Item 2, Electric Delivery Business - RG&E Cost Deferral Petitions and RG&E 2002 Electric and Gas Rate Proceeding.)

Sale of Ginna Station: On June 10, 2004, after receiving all regulatory approvals, RG&E sold Ginna to CGG. RG&E received at closing $429 million in cash. RG&E's Electric Rate Agreement resolves all regulatory and ratemaking aspects related to the sale of Ginna. On May 20, 2004, the NYPSC issued an order approving the sale of Ginna. RG&E's Electric Rate Agreement provides for an ASGA, established at the time of closing in the amount of approximately $357 million, and addresses the disposition of the asset sale gain. (See RG&E 2003 Electric and Natural Gas Rate Agreements and Note 2 to the Condensed Financial Statements.)

Upon closing of the Ginna sale, RG&E transferred $201 million of decommissioning funds to CGG, which will take responsibility for all future decommissioning funding. This amount fully meets the Nuclear Regulatory Commission's decommissioning funding requirements for Ginna. RG&E retained $77 million in excess decommissioning funds, which is part of the ASGA. The sale agreement includes a 10-year, fixed-price power purchase agreement that calls for CGG to provide electricity to RG&E at 90% of the plant's output.

RG&E Electric Rate Unbundling: In June 2003, as required by NYPSC's Order issued March 7, 2003, RG&E filed documentation with the NYPSC to unbundle commodity charges from delivery charges and to create electric commodity options for all customers. The Electric Rate Agreement provides for that unbundling and for the commodity options. Beginning January 1, 2005, customers will have an opportunity to choose to purchase commodity service from RG&E at a fixed rate or at a price that varies monthly based on the market price of electricity. Alternatively, customers may continue to choose to purchase their commodity service from an ESCO.

 

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

RG&E Transmission Project: In September 2003 RG&E applied to the NYPSC for approval to upgrade its electric transmission system. The project includes building or rebuilding 38 miles of transmission lines and upgrading substations in the Rochester, NY, area in order to assure adequate service to customers after the planned closing of RG&E's 257 megawatt coal-fired Russell Station in 2007. The estimated cost of the multi-year project is $75 million. Construction on the project is expected to begin in the spring of 2005.

CMP Alternative Rate Plan: In September 2000 the Maine Public Utilities Commission (MPUC) approved CMP's Alternative Rate Plan (ARP 2000). ARP 2000 applies only to CMP's state jurisdictional distribution revenue requirement and excludes revenue requirements related to stranded costs and transmission services. ARP 2000 began January 1, 2001, and continues through December 31, 2007, with price changes, if any, occurring on July 1, in the years 2002 through 2007. Effective July 1, 2004, CMP's distribution prices decreased by about 1% as a result of inflation being less than the productivity offset for 2004. In addition, CMP decreased its transmission rates to eliminate billings for congestion costs that have been fully recovered and, pursuant to its formula rate approved by the Federal Energy Regulatory Commission (FERC), to reflect CMP's and the New England Power Pool's actual costs for 2003.

NYPSC Collaborative on End State of Energy Competition: In March 2000 the NYPSC instituted a proceeding to address the future of competitive electricity and natural gas markets, including the role of regulated utilities in those markets. Other objectives of the proceeding include identifying and suggesting actions to eliminate obstacles to the development of those competitive markets and providing recommendations concerning Provider of Last Resort and related issues. In January 2004 the NYPSC issued a Notice seeking additional comments in light of the passage of time and the evolution of competitive markets. In March and April 2004 NYSEG and RG&E submitted comments supporting periodic assessment of the retail competitive marketplace and opposing the adoption of any policies restricting customer choice of supplier or limiting the availability of supply options from any particular supplier. NYSEG and RG&E believe that the NYPSC should not adopt a single end state vis ion for New York and should maintain flexibility by addressing each utility in the context of that utility's unique circumstances.

Regional Transmission Organization: ISO New England and the New England transmission owners, including CMP, made a joint regional transmission organization (RTO) filing with FERC in October 2003. On March 24, 2004, the FERC issued an order (RTO Order) accepting the six-state New England RTO filing submitted by ISO New England and the New England transmission owners, subject to certain conditions. FERC approved a proposed 50 basis point incentive adder to the ROE component, to be recovered in RTO New England's rates for regional network service. The FERC accepted a proposed 100 basis point ROE adder to reward new transmission investment for regional network services (RNS) facilities, subject to suspension, hearing and application of the FERC's Pricing Policy Statement when it is issued. The FERC also accepted, subject to suspension and hearing, the transmission owners' proposed base level ROE of 12.8% on RNS facilities but not on local network system (LNS) facilities. To pro vide parties an opportunity to resolve matters, the FERC instituted settlement procedures covering all matters set for hearing. The initial settlement discussions did not produce a resolution and the parties are conducting discovery of the issues set for hearing. CMP and the other New England transmission owners have requested rehearing on the issue of whether LNS facilities will earn the 12.8% base ROE and incentive adders, and clarification on

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

other aspects of the FERC's RTO Order. In addition, ISO New England and the New England transmission owners, including CMP, made a joint compliance filing as required by the RTO Order. At this time, CMP and the other New England transmission owners have informed the FERC that it needs to resolve the issues in the request for rehearing and clarification before the New England transmission owners can make a final decision regarding whether and when to join the RTO.

CMP Collective Bargaining Agreement: Effective April 30, 2004, the union contract expired between CMP and the local union of the International Brotherhood of Electrical Workers. On May 5, 2004, the union membership voted to accept CMP's offer for a new contract, which expires on April 30, 2009. The contract provides for wage increases of 3.25% in 2004, 3.0% in each year 2005, 2006 and 2007, and 2.75% in 2008. It also includes provisions for active employees to contribute to medical insurance plans at a level reflecting CMP's cost-sharing philosophy for all such plans by the end of the contract period and for employees who retire on or after July 1, 2005, to contribute toward the cost of medical insurance according to a predetermined schedule.

CMP Stranded Cost Proceeding: Through its stranded cost rates, CMP recovers the above-market costs of its purchased power agreements, as well as costs incurred to decommission and dismantle the nuclear facilities in which CMP has an ownership share, pursuant to Maine statute. The current stranded cost rates were set in 2003 and are scheduled to be updated in February 2005. CMP filed revised stranded cost estimates in July 2004, as ordered by the MPUC. CMP expects an MPUC order setting new stranded cost rates in February 2005.

CMP Nuclear Costs: CMP has ownership interests in three nuclear facilities in New England that have been permanently shutdown, and are in the process of being decommissioned: Maine Yankee Atomic Power Company (38% owned), Connecticut Yankee Atomic Power Company (6% owned) and Yankee Atomic Electric Power Company (9.5% owned) (the Yankee companies). The Yankee companies filed litigation in 1998 charging that the federal government breached contracts it entered into with each of the Yankee companies in 1983 to begin removing spent nuclear fuel from the Maine Yankee, Connecticut Yankee and Yankee Rowe nuclear plants, which are owned by the Yankee companies, no later than January 31, 1998, in return for payments by each of the Yankee companies. Two federal courts found that the federal government did breach its contracts with the Yankee companies and other utilities. A trial to determine the monetary damages owed to the Yankee companies for the Department of Energy's (DOE) co ntinued failure to remove spent nuclear fuel began in the U.S. Court of Federal Claims in July 2004. The Yankee companies' individual damage claims are specific to each plant and include costs through 2010, the earliest date the DOE expects that it will begin removing fuel. The Yankee companies' damage claims total approximately $550 million and CMP's sponsor-weighted share is approximately $90 million. The claims also note additional costs that will be incurred for each year that fuel remains at the sites beyond 2010. If the Yankee companies prevail in these cases, any damages awarded by the Court of Federal Claims would be credited to their respective decommissioning or spent fuel trust funds and any remaining funds would be returned to electric customers when decommissioning is complete.

 

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

Pursuant to a year 2000 settlement (2000 Settlement) in a prior FERC rate case, Connecticut Yankee, on July 1, 2004, filed a revised schedule of decommissioning charges to be collected from its wholesale customers, based on an updated estimate of the costs of decommissioning. Estimated decommissioning and long-term spent fuel storage costs for the period 2000 through 2023 increased by approximately $390 million in 2003 dollars compared to the April 2000 estimate of $434 million approved by the FERC in the 2000 Settlement. The revised estimate reflects the fact that Connecticut Yankee is now self-performing all work to complete the decommissioning of the plant and the termination of Bechtel Power Corporation (Bechtel), the turnkey decommissioning contractor, in July 2003. In addition, the revised estimate contains increases in the projected costs of spent fuel storage, security, and liability and property insurance. The estimated remaining decommissioning and long-term spent fuel storage costs as of Decemb er 31, 2003, are approximately $504 million in 2003 dollars.

Connecticut Yankee is seeking recovery of incremental decommissioning costs and other damages from Bechtel and, if necessary, its surety. In turn, Bechtel has filed a complaint in Connecticut Superior Court seeking damages of $93 million for wrongful termination of the decommissioning contract. Connecticut Yankee has filed counterclaims for excess completion costs and other damages. Discovery is underway and a trial has been scheduled for May 2006.

The revised schedule for decommissioning collections is based on the 2003 estimate. Under the revised schedule, increased collections of $93 million annually would commence in January 2005 and extend through December 2010. Any increase in rates approved by the FERC will be charged to Connecticut Yankee's owners, including CMP, whose share of a $93 million increase would be approximately $6 million. Under prior regulatory settlements, CMP is allowed to defer any increased decommissioning costs for future recovery.

On June 10, 2004, the Connecticut Department of Public Utility Control (DPUC) and the Connecticut Office of Consumer Counsel filed a petition with the FERC asking the FERC to determine that, if it should find any of Connecticut Yankee's decommissioning costs were not prudently incurred, the owners may not recover those costs in rates that are ultimately charged to retail customers but must be borne by the owners of Connecticut Yankee. Connecticut Yankee and its owners, including CMP, filed protests to contest this petition. CMP cannot predict the outcome of these proceedings.

Natural Gas Delivery Business

The company's natural gas delivery business consists of its regulated natural gas transportation, storage and distribution operations in New York, Connecticut, Maine and Massachusetts.

Natural Gas Supply Agreements: Energy East's natural gas companies - NYSEG, RG&E, SCG, CNG, Berkshire Gas and Maine Natural Gas - have a three-year strategic alliance with BP Energy Company, effective April 1, 2004, for the acquisition of natural gas supply and optimization of transportation and storage services.

 

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

NYSEG Natural Gas Rate Plan: NYSEG's Natural Gas Rate Plan, which became effective October 1, 2002, freezes overall delivery rates through December 31, 2008, implements a natural gas supply charge to collect the actual costs of natural gas and contains an earnings sharing mechanism. The earnings sharing mechanism requires equal sharing of earnings between NYSEG customers and shareholders of ROEs in excess of 11.5% for the 27-month period ended December 31, 2004, and in excess of 12.5% for each of the calendar years from 2005 through 2008. For purposes of earnings sharing, NYSEG is required to use the lower of its actual equity or a 45% equity ratio, which approximates $250 million.

On June 30, 2004, NYSEG filed a Joint Proposal executed by NYSEG and other parties, resolving outstanding issues in NYSEG's Natural Gas Rate Plan related to its natural gas delivery rate design, natural gas economic development plan and its natural gas Affordable Energy Program. Pursuant to NYSEG's Natural Gas Rate Plan, delivery rate designs in the Joint Proposal were developed for each of the remaining years on an overall revenue neutral manner, consistent with the billing units and firm delivery revenues contained in NYSEG's Natural Gas Rate Plan. The company expects the NYPSC to address the Joint Proposal at its open session on September 22, 2004.

RG&E 2003 Electric and Natural Gas Rate Agreements: See Electric Delivery Business.

NYPSC Collaborative on End State of Energy Competition: See Electric Delivery Business.

SCG Request for Recovery of Exogenous Costs: In December 2003 SCG filed an application with the DPUC to recover approximately $21 million of exogenous costs under its approved Incentive Rate Plan (IRP). The exogenous costs to be recovered include qualified pension and other postretirement benefits expenses, taxes, uncollectible expense and the cost of SCG's Customer Hardship Arrearage Forgiveness Program. Those costs were the result of events that were unanticipated and beyond SCG's control. SCG's IRP decision from the DPUC allows SCG to petition for relief from substantial and material costs resulting from such exogenous events. The DPUC established a docket for this proceeding and hearings were held in April 2004. A DPUC draft decision in this proceeding is now scheduled to be released some time in August. SCG cannot predict the outcome of this proceeding.

CNG's Purchased Gas Adjustment Clause: In April 2002 the DPUC initiated a semiannual review of CNG's Purchased Gas Adjustment Clause (PGA). The DPUC issued its draft decision in December 2002, disallowing approximately $1 million of natural gas costs that would be returned to customers through the PGA. As a result, on December 31, 2002, CNG set up a reserve to recognize a potential $1 million liability for this disallowance. In May 2004 the DPUC issued its final decision in a subsequent PGA case that clarified a number of issues and allowed CNG to reverse the $1 million reserve.

Connecticut Merger-Enabled Gas Supply Savings and Gas Cost Reduction Plan Filings: In 2001 CNG and SCG submitted filings to the DPUC regarding merger-enabled gas supply savings (MEGS) and a gas-cost reduction plan, which covered the initial period April 1, 2001, through September 30, 2001. CNG provided calculations for total MEGS of $1.3 million and SCG provided calculations for total MEGS of $2.2 million. In February 2003, based on its understanding of the components of the MEGS, the DPUC issued a draft decision on CNG's and SCG's filed MEGS and gas-cost reduction plan results, modifying the MEGS amounts to

 

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

$134,000 for CNG and $9,000 for SCG. CNG and SCG filed comments and additional detail with regard to the draft decision. On March 26, 2004, the DPUC issued a notice that encouraged the parties to settle the MEGS issue, which resulted in the assignment of Prosecutorial Staff of the DPUC to assist in the settlement process. The docket was suspended to allow the settlement process to proceed. CNG and SCG are diligently working toward settlement of the issues but cannot predict the final outcome of these proceedings.

Other Businesses

Sale of Other Businesses: The company continues to rationalize its nonutility businesses to ensure that they fit its strategic focus. On July 26, 2004, UWP, a subsidiary of CMP Group, Inc., sold all of the assets related to its utility locating and construction businesses. The after tax loss resulting from the sale is estimated at $5 million and includes a reduction in the goodwill that was assigned to UWP at the time of Energy East's purchase of CMP Group.

Other Matters

Accounting Issues

FIN 46R: In December 2003 the Financial Accounting Standards Board (FASB) issued its revised FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin (ARB) No. 51 (FIN 46R). FIN 46R addresses consolidation of variable interest entities. A variable interest entity is an entity that is not controllable through voting interests and/or in which the equity investor does not bear the residual economic risks and rewards. The company was required to apply FIN 46R to all entities subject to the interpretation as of March 31, 2004. (See Note 7 to the Condensed Financial Statements.)

FASB Staff Position No. FAS 106-2: In May 2004 the FASB issued its FASB Staff Position (FSP) No. FAS 106-2, which addresses how and when a plan sponsor should account for the federal subsidy introduced by the Medicare Prescription Drug, Improvement and Modernization Act of 2003 and could require the plan sponsor to change previously reported information. FSP No. FAS 106-2 is effective for the first interim or annual period beginning after June 15, 2004. When FSP No. FAS 106-2 becomes effective it supersedes FSP No. FAS 106-1. The company, CMP, NYSEG and RG&E will apply FSP No. 106-2 beginning July 1, 2004. (See Note 9 to the Condensed Financial Statements.)

Investing and Financing Activities

Investing Activities: Capital spending for the first six months of 2004 was $124 million, including nuclear fuel. Capital spending is projected to be $345 million for 2004, including nuclear fuel, and is expected to be paid for primarily with internally generated funds. Capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates and merger integration.

 

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

Financing Activities: The financing activities discussed below include those activities necessary for the company and its subsidiaries to maintain adequate liquidity, improve credit quality and ensure access to capital markets. Activities include maintenance of credit facilities, minimal common stock issuances and various medium-term and long-term debt arrangements. They also include the steps taken at RG&E to revise its capital structure as a result of the Ginna sale. (See RG&E Financing Activities.)

During the six months ended June 30, 2004, the company issued 444,122 shares of common stock, at an average price of $23.15 per share, through its Investor Services Program (formerly known as the Dividend Reinvestment and Stock Purchase Plan). The shares issued were original issue shares.

In July 2004 the company replaced its $150 million 364-day revolving credit facility with a $150 million five-year revolving credit facility that expires in July 2009.

During the first quarter of 2004 the company awarded 242,038 shares of its common stock, issued out of its treasury stock, to certain employees through its Restricted Stock Plan and recorded deferred compensation of $6 million based on the market price per share of common stock on the dates of the awards, which averaged $23.90.

NYSEG Financing Activities: In May 2004 NYSEG entered into forward starting swaps on three adjustable-rate pollution control notes to fix the interest rates on the anniversary dates of the notes. NYSEG will receive the Bond Market Association Municipal Swap rate, an indexed floating rate, and pay fixed rates on the notional amounts as follows: 4.387% on $60 million (anniversary date March 15, 2005), 4.330% on $30 million (anniversary date October 15, 2004) and 4.390% on $42 million (anniversary date December 1, 2004).

In July 2004 NYSEG and RG&E replaced their joint 364-day revolving credit facility, which was due to expire in December 2004, with a five-year $230 million revolving credit facility with certain banks. NYSEG is permitted to borrow up to $180 million under the facility, RG&E is permitted to borrow up to $75 million, and NYSEG and RG&E are allowed to issue letters of credit totaling up to $40 million, not to exceed a combined total of $230 million.

In August 2004 NYSEG expects to refund $204 million of tax-exempt fixed-rate pollution control notes that have interest rates ranging from 5.70% to 6.05% with proceeds from the issuance of $204 million of multi-mode tax-exempt pollution control notes, which will initially be in a Dutch Auction mode. In July 2004 NYSEG entered into a forward starting swap to fix the interest rate on one of the tax-exempt pollution control notes in the Dutch Auction mode. NYSEG will pay a fixed rate of 3.80% and will receive 67% of the one-month LIBOR rate on a notional amount of $70 million.

RG&E Financing Activities: On March 1, 2004, RG&E redeemed, at par, as required by a mandatory sinking fund provision, $1.25 million of 6.60% Series V preferred stock, Par Value $100, using available cash. On May 5, 2004, RG&E redeemed, at par, the remaining $23.75 million of the 6.60% Series V preferred stock, using available cash. The 6.60% Series V preferred stock, because it was mandatorily redeemable, was classified as a liability as of July 1, 2003, in accordance with FASB Statement of Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

On May 5, 2004, RG&E redeemed its remaining preferred stock, including: $12 million of 4% Series F (120,000 shares), $8 million of 4.10% Series H (80,000 shares), $6 million of 4 3/4% Series I (60,000 shares), $5 million of 4.10% Series J (50,000 share), $6 million of 4.95% Series K (60,000 shares) and $10 million of 4.55% Series M (100,000 shares), all redeemed at a premium. On May 6, 2004, RG&E redeemed, at a premium, $40 million of 7.45% Series first mortgage bonds due July 2023, and the following Series of first mortgage bonds due March 2023: $33 million of 7.64%, $5 million of 7.66%, and $12 million of 7.67%. Those redemptions were financed through available cash and a short-term credit facility. The short-term credit facility was repaid with proceeds from the sale of Ginna.

In July 2004 RG&E and NYSEG replaced their joint 364-day revolving credit facility, which was due to expire in December 2004, with a five-year $230 million revolving credit facility with certain banks. RG&E is permitted to borrow up to $75 million under the facility, NYSEG is permitted to borrow up to $180 million, and RG&E and NYSEG are allowed to issue letters of credit totaling up to $40 million, not to exceed a combined total of $230 million.

In August 2004 RG&E expects to refund $60 million of fixed-rate tax-exempt mortgage bonds that have rates ranging from 6.35% to 6.5% with proceeds from the issuance of $60 million of multi-mode tax-exempt pollution control notes, which will initially be in a Dutch Auction mode.

In the second quarter of 2004, RG&E declared common dividends of $170 million in order to rebalance its capital structure after the Ginna sale. These funds will be used to reduce debt outstanding at Energy East.

Other Financing Activities:

In the second quarter of 2004 Berkshire Gas, CNG and SCG renewed their joint $105 million 364-day revolving credit facility. The amounts the companies are permitted to borrow up to: Berkshire Gas - $15 million, CNG - $50 million and SCG - $55 million, not to exceed a combined total of $105 million.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

(b) Results of Operations

Three months ended June 30

     2004     

     2003     

Change

(Thousands, except per share amounts)

Operating Revenues

$980,566

$979,113

-   

Operating Income

$233,806

$124,351

88% 

Income from Continuing Operations

$42,782

$28,333

49% 

Net Income

$38,066

$27,717

37% 

Average Common Shares Outstanding, basic

146,148

145,415

1% 

Earnings Per Share from Continuing Operations, basic and diluted

$.29

$.19

53% 

Earnings Per Share, basic and diluted

$.26

$.19

37% 

Dividends Paid Per Share

$.26

$.25

4% 

Earnings from continuing operations were 29 cents per share for the quarter ended June 30, 2004, compared to 19 cents per share for the quarter ended June 30, 2003. The increase is primarily due to one-time effects from the sale of Ginna and the approval of RG&E's Electric and Natural Gas Rate Agreements, which increased earnings 7 cents per share. The one-time effects include the flow-through of excess deferred taxes and investment tax credits and the elimination of certain reserves established pending regulatory determination. Ongoing effects from RG&E's Electric and Natural Gas Rate Agreements added 5 cents per share to earnings, and include increases as a result of RG&E's electric retail access surcharge and natural gas merchant function charge, and annual credits to RG&E from the ASGA as provided in the Electric Rate Agreement. (See RG&E 2003 Electric and Natural Gas Rate Agreements.) Lower stock-based compensation expenses contributed another 5 cents per share to earnings. Those increases were partially offset by a decrease of 5 cents per share from lower natural gas deliveries due to milder weather.

Six months ended June 30

     2004     

     2003     

Change

(Thousands, except per share amounts)

Operating Revenues

$2,561,639

$2,483,944

3% 

Operating Income

$501,151

$418,294

20% 

Income from Continuing Operations

$163,491

$160,024

2% 

Net Income

$158,618

$163,181

(3%)

Average Common Shares Outstanding, basic

146,116

145,256

1% 

Earnings Per Share from Continuing Operations, basic

$1.12

$1.10

2% 

Earnings Per Share from Continuing Operations, diluted

$1.11

$1.10

1% 

Earnings Per Share, basic

$1.09

$1.12

(3%)

Earnings Per Share, diluted

$1.08

$1.12

(4%)

Dividends Paid Per Share

$.52

$.50

4% 

Earnings from continuing operations were $1.12 per share for the six months ended June 30, 2004, compared to $1.10 per share for the six months ended June 30, 2003. The increase is primarily the result of the second quarter effects of the sale of Ginna and RG&E's Electric and Natural Gas Rate Agreements discussed above, and because of integration savings and other cost reductions. Earnings were reduced 5 cents per share due to the accumulated effects of stock-based compensation expenses as a result of the changes in the market value of Energy East stock during the first two quarters of 2004 as compared to the same periods last year. Earnings were reduced another 9 cents per share because of lower natural gas deliveries due to milder weather.

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

Operating Results for the Electric Delivery Business

Three months ended June 30

     2004     

     2003     

Change

(Thousands)

Retail Deliveries - Megawatt-hours

7,295

7,141

2% 

Operating Revenues

$641,057

$640,035

-    

Operating Expenses

$425,098

$536,329

(21%)

Operating Income

$215,959

$103,706

108% 

Operating revenues for the second quarter of 2004 decreased $1 million primarily as a result of lower revenues of $10 million due to a change in market structure for RG&E that allows ESCOs to provide electricity and $5 million because of lower prices for CMP's retail customers. Those decreases were partially offset by higher retail deliveries of $10 million and higher wholesale revenues of $9 million for NYSEG.

Operating expenses decreased $111 million primarily due to RG&E's recognition of a $319 million pretax gain on the Ginna sale, partially offset by RG&E's deferral of the gain net of tax of $214 million.

Six months ended June 30

     2004     

     2003     

Change

(Thousands)

Retail Deliveries - Megawatt-hours

15,345

15,231

1% 

Operating Revenues

$1,371,652

$1,398,748

(2%)

Operating Expenses

$1,012,909

$1,139,237

(11%)

Operating Income

$358,743

$259,511

38% 

Operating revenues for the six months decreased $27 million. The primary factors were revenue decreases of approximately $21 million because of rate reductions for CMP to reflect lower amortization of storm and demand-side management costs; and $22 million due to a change in market structure for RG&E that allows ESCOs to provide electricity, resulting in lower retail revenues offset by higher wholesale revenues and lower fuel costs. Those decreases were partially offset by increased retail deliveries of $4 million, increased wholesale revenues of $8 million and an $8 million increase in transmission revenues for NYSEG.

Operating expenses for the six months decreased $126 million primarily due to RG&E's recognition of a $319 million pretax gain on the Ginna sale, partially offset by RG&E's deferral of the gain net of tax of $214 million. In addition, operating expenses for the first quarter of 2004 decreased $15 million primarily due to a reduction in purchased power costs.

 

Management's discussion and analysis of financial condition and results of operations

Energy East Corporation

Operating Results for the Natural Gas Delivery Business

Three months ended June 30

     2004     

     2003     

Change

(Thousands

Retail Deliveries - Dekatherms

35,952 

39,026 

(8%) 

Operating Revenues

$240,282 

$264,054 

(9%) 

Operating Expenses

$232,485 

$244,033 

(5%) 

Operating Income

$7,797 

$20,021 

(61%) 

Operating revenues decreased $24 million for the second quarter of 2004 primarily due to lower deliveries that reduced revenues $40 million, partially offset by higher gas costs that are passed on to customers that increased revenues $16 million.

Operating expenses decreased $12 million compared to the prior year quarter. The primary cause was a decrease in volume of natural gas purchases of $14 million. This decrease was offset by higher natural gas prices of $10 million. Lower wholesale volumes decreased expenses $4 million for the quarter.

Six months ended June 30

     2004     

     2003     

Change

(Thousands

Retail Deliveries - Dekatherms

123,549

128,242

(4%)

Operating Revenues

$922,006

$904,167

2% 

Operating Expenses

$789,191

$751,569

5% 

Operating Income

$132,815

$152,598

(13%)

Operating revenues increased $18 million for the six months compared to the prior year period. The increase is primarily due to an $80 million increase in revenues due to higher natural gas costs, which are passed on to customers, partially offset by lower deliveries of $40 million. Other items, including lower transportation revenues and wholesale entitlements further decreased revenues.

Operating expenses increased $42 million for the six months ended June 30, 2004, primarily due to higher natural gas prices of $62 million, partially offset by fewer purchases of natural gas of $28 million as a result of lower deliveries.


Item 1.  Financial Statements

Central Maine Power Company
Condensed Consolidated Statements of Income - (Unaudited)

 

Three Months

Six Months

Periods ended June 30

2004

2003

2004

2003

(Thousands)

       

Operating Revenues

       

  Sales and services

$129,748 

$135,259 

$292,498 

$311,676 

Operating Expenses

       

  Electricity purchased

57,422 

60,048 

120,395 

120,686 

  Other operating expenses

37,825 

41,817 

79,484 

88,305 

  Maintenance

7,016 

8,765 

14,841 

16,135 

  Depreciation and amortization

13,173 

10,145 

21,297 

20,365 

  Other taxes

3,317 

3,448 

8,324 

10,404 

      Total Operating Expenses

118,753 

124,223 

244,341 

255,895 

Operating Income

10,995 

11,036 

48,157 

55,781 

Other (Income)

(1,032)

(761)

(2,083)

(1,748)

Other Deductions

164 

420 

299 

799 

Interest Charges, Net

6,131 

6,614 

12,272 

13,287 

Income Before Income Taxes

5,732 

4,763 

37,669 

43,443 

Income Taxes

2,302 

1,942 

13,412 

16,520 

Net Income

3,430 

2,821 

24,257 

26,923 

Preferred Stock Dividends

361 

361 

721 

721 

Earnings Available for Common Stock

$3,069 

$2,460 

$23,536 

$26,202 


The notes on pages 41 through 52 are an integral part of the financial statements.

 

Central Maine Power Company
Condensed Consolidated Balance Sheets - (Unaudited)

 

June 30, 2004    

Dec. 31,  
2003    

(Thousands)

   

Assets

   

Current Assets

   

 Cash and cash equivalents

$14,970

$11,627

 Accounts receivable, net

100,153

113,992

 Materials and supplies, at average cost

6,734

6,571

 Accumulated deferred income tax benefits, net

1,232

1,232

 Prepayments and other current assets

4,153

7,135

   Total Current Assets

127,242

140,557

Utility Plant, at Original Cost

   

 Electric

1,358,980

1,337,931

 Less accumulated depreciation

466,103

451,407

   Net Utility Plant in Service

892,877

886,524

 Construction work in progress

14,818

15,953

   Total Utility Plant

907,695

902,477

Other Property and Investments, Net

23,975

25,475

Regulatory and Other Assets

   

 Regulatory assets

   

  Nuclear plant obligations

160,322

173,548

  Unfunded future income taxes

104,276

104,276

  Unamortized loss on debt reacquisitions

8,059

8,646

  Demand-side management program costs

4,589

5,281

  Environmental remediation costs

1,613

2,614

  Nonutility generator termination agreement

5,319

5,944

  Other

74,390

65,145

 Total regulatory assets

358,568

365,454

 Other assets

   

  Goodwill, net

324,938

324,938

  Prepaid pension benefits

35,897

29,623

  Other

10,189

18,329

 Total other assets

371,024

372,890

   Total Regulatory and Other Assets

729,592

738,344

   Total Assets

$1,788,504

$1,806,853


The notes on pages 41 through 52 are an integral part of the financial statements.

 

 

Central Maine Power Company
Condensed Consolidated Balance Sheets - (Unaudited)

 

June 30, 2004    

Dec. 31,  
2003    

(Thousands)

   

Liabilities

   

Current Liabilities

   

 Current portion of long-term debt

$3,007 

$2,999 

 Notes payable

25,000 

15,000 

 Accounts payable and accrued liabilities

53,211 

45,815 

 Interest accrued

5,471 

5,397 

 Taxes accrued

2,626 

1,206 

 Other

24,192 

48,322 

   Total Current Liabilities

113,507 

118,739 

Regulatory and Other Liabilities

   

 Regulatory liabilities

   

  Accrued removal obligation

84,096 

80,128 

  Deferred income taxes

78,748 

77,849 

  Gain on sale of generation assets

58,674 

76,998 

  Other

21,708 

17,127 

 Total regulatory liabilities

243,226 

252,102 

 Other liabilities

   

  Deferred income taxes

75,272 

65,555 

  Nuclear plant obligations

160,322 

173,548 

  Other postretirement benefits

75,258 

73,181 

  Environmental remediation costs

2,867 

3,017 

  Other

114,062 

113,880 

 Total other liabilities

427,781 

429,181 

   Total Regulatory and Other Liabilities

671,007 

681,283 

 Long-term debt

313,046 

314,511 

   Total Liabilities

1,097,560 

1,114,533 

Commitments

-      

-      

Preferred Stock
 Preferred stock


35,571 


35,571 

Common Stock Equity
 Common stock


156,057 


156,057 

 Capital in excess of par value

482,882 

482,794 

 Retained earnings

33,608 

35,072 

 Accumulated other comprehensive (loss)

(17,174)

(17,174)

   Total Common Stock Equity

655,373 

656,749 

   Total Liabilities and Stockholder's Equity

$1,788,504 

$1,806,853 


The notes on pages 41 through 52 are an integral part of the financial statements.

 


Central Maine Power Company
Condensed Consolidated Statements of Cash Flows - (Unaudited
)

Six months ended June 30

2004

2003

(Thousands)

   

   Net Cash Provided by Operating Activities

$42,853 

$49,218 

Investing Activities

   

 Utility plant additions

(24,506)

(12,847)

 Other

2,220 

119 

   Net Cash Used in Investing Activities

(22,286)

(12,728)

Financing Activities

   

 Long-term note repayments

(1,503)

(1,486)

 Notes payable three months or less, net

10,000 

-      

 Dividends on common and preferred stock

(25,721)

(25,721)

   Net Cash Used in Financing Activities

(17,224)

(27,207)

Net (Decrease) Increase in Cash and Cash Equivalents

3,343 

9,283 

Cash and Cash Equivalents, Beginning of Period

11,627 

20,415 

Cash and Cash Equivalents, End of Period

$14,970 

$29,698 


The notes on pages 41 through 52 are an integral part of the financial statements.

Central Maine Power Company
Condensed Consolidated Statements of Retained Earnings - (Unaudited)

Six months ended June 30

2004

2003

(Thousands)

   

Balance, Beginning of Period

$35,072

$31,682

Add net income

24,257

26,923

 

59,329

58,605

Deduct Dividends on Capital Stock

   

 Preferred

721

721

 Common

25,000

25,000


25,721

25,721

Balance, End of Period

$33,608

$32,884


The notes on pages 41 through 52 are an integral part of the financial statements.

Central Maine Power Company
Condensed Consolidated Statements of Comprehensive Income - (Unaudited)

 

Three Months

Six Months

Periods ended June 30

2004

2003

2004

2003

(Thousands)

       

Net income

$3,430

$2,821 

$24,257

$26,923 

Other comprehensive income, net of tax

       

  Net unrealized (losses) on derivatives qualified as
   hedges, net of income tax benefit of $-
for the
   three months in 2004 and $624 in 2003, and $-

   for the six months in 2004 and $631 in 2003




- -    




(904)




- -    




(915)

    Total other comprehensive income

-    

(904)

-    

(915)

Comprehensive Income

$3,430

$1,917 

$24,257

$26,008 


The notes on pages 41 through 52 are an integral part of the financial statements.


Item 2.  Management's discussion and analysis of financial condition
             and results of operations

Central Maine Power Company

(a) Liquidity and Capital Resources

Restructuring

See Energy East's Item 2(a), Restructuring, for this discussion.

Electric Delivery Business

CMP's electric delivery business consists of its regulated electricity transmission and distribution operations.

CMP Alternative Rate Plan: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.

Regional Transmission Organization: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.

CMP Collective Bargaining Agreement: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.

CMP Stranded Cost Proceeding: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.

CMP Nuclear Costs: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.

Other Matters

Accounting Issues

FIN 46R: See Energy East's Item 2(a), Other Matters, for this discussion. (See Note 7 to the Condensed Financial Statements.)

FASB Staff Position No. FAS 106-2: See Energy East's Item 2(a), Other Matters, for this discussion. (See Note 9 to the Condensed Financial Statements.)

Investing Activities

Capital spending for the first six months of 2004 was $25 million. Capital spending is projected to be $50 million for 2004, and is expected to be paid for primarily with internally generated funds. Capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates and merger integration.


Management's discussion and analysis of financial condition and results of operations

Central Maine Power Company

(b) Results of Operations

Three months ended June 30

     2004     

     2003     

Change

(Thousands)

     

Retail Deliveries - Megawatt-hours

2,124

2,110

1% 

Operating Revenues

$129,748

$135,259

(4%)

Operating Expenses

$118,753

$124,223

(4%)

Operating Income

$10,995

$11,036

-   

Earnings Available for Common Stock

$3,069

$2,460

25% 

Earnings for the quarter increased less than $1 million. A slight decrease in operating income was offset by higher other income and lower interest expense.

Operating revenues for the quarter decreased by $6 million due primarily to rate reductions totaling $5 million reflecting lower amortization of storm and demand-side management costs.

Operating expenses decreased $5 million for the quarter primarily due to lower amortization of ice storm and other costs of $4 million and lower NUG costs of $2 million.

Six months ended June 30

     2004     

     2003     

Change

(Thousands)

     

Retail Deliveries - Megawatt-hours

4,459

4,373

2% 

Operating Revenues

$292,498

$311,676

(6%)

Operating Expenses

$244,341

$255,895

(5%)

Operating Income

$48,157

$55,781

(14%)

Earnings Available for Common Stock

$23,536

$26,202

(10%)

Earnings for the six months decreased $3 million compared to the prior year period primarily as a result of lower operating revenues.

Operating revenues for the six months decreased $19 million due primarily to a $23 million decrease because of rate reductions reflecting mainly lower amortization of storm and demand-side management costs. That decrease was partially offset by an increase of $4 million for higher deliveries resulting from economic growth.

Operating expenses for the six months decreased $12 million primarily due to lower amortization of ice storm and other costs of $8 million and a decrease in other taxes of $2 million.

Item 1.  Financial Statements

New York State Electric & Gas Corporation
Condensed Statements of Income - (Unaudited)

 

Three Months

Six Months

Periods ended June 30

2004

2003

2004

2003

(Thousands)

       

Operating Revenues

       

  Electric

$358,521 

$338,353 

$762,505 

$744,320 

  Natural Gas

69,974 

75,011 

258,204 

244,775 

      Total Operating Revenues

428,495 

413,364 

1,020,709 

989,095 

Operating Expenses

       

  Electricity purchased

193,753 

179,603 

422,430 

398,114 

  Natural gas purchased

41,452 

43,569 

173,747 

150,626 

  Other operating expenses

51,642 

52,685 

110,984 

100,499 

  Maintenance

19,195 

17,034 

34,095 

38,430 

  Depreciation and amortization

25,849 

25,063 

51,214 

49,995 

  Other taxes

25,669 

25,291 

56,081 

60,664 

      Total Operating Expenses

357,560 

343,245 

848,551 

798,328 

Operating Income

70,935 

70,119 

172,158 

190,767 

Other (Income)

(216)

(184)

(172)

(2,108)

Other Deductions

454 

(1,553)

172 

(1,297)

Interest Charges, Net

18,597 

21,022 

37,398 

40,360 

Income Before Income Taxes

52,100 

50,834 

134,760 

153,812 

Income Taxes

21,204 

20,911 

50,947 

63,272 

Net Income

30,896 

29,923 

83,813 

90,540 

Preferred Stock Dividends

99 

99 

198 

198 

Earnings Available for Common Stock

$30,797 

$29,824 

$83,615 

$90,342 


The notes on pages 41 through 52 are an integral part of the financial statements.

New York State Electric & Gas Corporation
Condensed Balance Sheets - (Unaudited)

 

June 30, 
2004    

Dec. 31,  
2003    

(Thousands)

   

Assets

   

Current Assets

   

 Cash and cash equivalents

$17,460

$14,458

 Special deposits

5,094

30,353

 Accounts receivable, net

237,317

290,166

 Fuel, at average cost

26,815

43,207

 Materials and supplies, at average cost

6,052

5,893

 Accumulated deferred income tax benefits, net

5,415

5,500

 Prepayments

21,981

28,917

   Total Current Assets

320,134

418,494

Utility Plant, at Original Cost

   

 Electric

2,652,953

2,593,090

 Natural gas

698,092

688,705

 Common

139,745

120,584

 

3,490,790

3,402,379

 Less accumulated depreciation

1,183,927

1,144,385

   Net Utility Plant in Service

2,306,863

2,257,994

 Construction work in progress

12,749

55,638

   Total Utility Plant

2,319,612

2,313,632

Other Property and Investments, Net

37,886

37,872

Regulatory and Other Assets

   

 Regulatory assets

   

  Unfunded future income taxes

44,261

42,366

  Unamortized loss on debt reacquisitions

36,996

38,863

  Environmental remediation costs

74,409

74,734

  Deferred income taxes

63,794

71,095

  Other

41,827

53,238

 Total regulatory assets

261,287

280,296

 Other assets

   

  Goodwill, net

11,199

11,199

  Prepaid pension benefits

474,770

450,817

  Other

99,097

75,255

 Total other assets

585,066

537,271

   Total Regulatory and Other Assets

846,353

817,567

   Total Assets

$3,523,985

$3,587,565


The notes on pages 41 through 52 are an integral part of the financial statements.

 

 

New York State Electric & Gas Corporation
Condensed Balance Sheets - (Unaudited)

 

June 30, 
2004    

Dec. 31,  
2003    

(Thousands)

   

Liabilities

   

Current Liabilities

   

 Current portion of long-term debt

$338 

$710

 Notes payable

6,197 

41,400

 Accounts payable and accrued liabilities

143,611 

148,918

 Interest accrued

8,748 

10,068

 Taxes accrued

13,350 

15,367

 Other

27,904 

74,819

   Total Current Liabilities

200,148 

291,282

Regulatory and Other Liabilities

   

 Regulatory liabilities

   

  Gain on sale of generation assets

52,809 

52,642

  Accrued removal obligation

314,463 

304,065

  Other

21,363 

21,571

 Total regulatory liabilities

388,635 

378,278

 Other liabilities

   

  Deferred income taxes

532,176 

522,919

  Other postretirement benefits

214,795 

208,393

  Asset retirement obligation

382 

377

  Environmental remediation costs

97,075 

97,400

  Other

59,386 

50,840

 Total other liabilities

903,814 

879,929

   Total Regulatory and Other Liabilities

1,292,449 

1,258,207

 Long-term debt

1,065,829 

1,065,590

   Total Liabilities

2,558,426 

2,615,079

Commitments

-      

-      

Preferred Stock
 Redeemable solely at NYSEG's option


10,159 


10,159

Common Stock Equity
 Common stock


430,057 


430,057

 Capital in excess of par value

277,543 

277,462

 Retained earnings

212,663 

229,048

 Accumulated other comprehensive income

35,137 

25,760

   Total Common Stock Equity

955,400 

962,327

   Total Liabilities and Stockholder's Equity

$3,523,985 

$3,587,565


The notes on pages 41 through 52 are an integral part of the financial statements.

 

 

New York State Electric & Gas Corporation
Condensed Statements of Cash Flows - (Unaudited
)

Six months ended June 30

2004

2003

(Thousands)

   

   Net Cash Provided by Operating Activities

$164,178 

$107,090 

Investing Activities

   

 Utility plant additions

(50,662)

(38,836)

 Proceeds from sale of utility plant

-      

211 

 Special deposits

25,259 

(81,128)

 Other

(17)

   Net Cash Used in Investing Activities

(25,402)

(119,770)

Financing Activities

   

 Notes payable three months or less, net

(35,203)

5,000 

 Repayments of first mortgage bonds, including net premiums

-      

(74,390)

 Long-term note issuances

(373)

196,986 

 Dividends on common and preferred stock

(100,198)

(90,198)

   Net Cash Used in Financing Activities

(135,774)

37,398 

Net Increase (Decrease) in Cash and Cash Equivalents

3,002 

24,718 

Cash and Cash Equivalents, Beginning of Period

14,458 

11,490 

Cash and Cash Equivalents, End of Period

$17,460 

$36,208 


The notes on pages 41 through 52 are an integral part of the financial statements.

 

New York State Electric & Gas Corporation
Condensed Statements of Retained Earnings - (Unaudited)

Six months ended June 30

2004

2003

(Thousands)

   

Balance, Beginning of Period

$229,048

$206,519

Add net income

83,813

90,540

 

312,861

297,059

Deduct Dividends on Capital Stock

   

 Preferred

198

198

 Common

100,000

90,000


100,198

90,198

Balance, End of Period

$212,663

$206,861


The notes on pages 41 through 52 are an integral part of the financial statements.



New York State Electric & Gas Corporation
Condensed Statements of Comprehensive Income - (Unaudited)

 

Three Months

Six Months

Periods ended June 30

2004

2003

2004

2003

(Thousands)

       

Net income

$30,896 

$29,923 

$83,813 

$90,540 

Other comprehensive income, net of tax

       

  Net unrealized gains on investments, net of
   income tax benefit for the three months of $-

   in 2004 and $(173) in 2003 and for the six months
   of $- in 2004 and $(166) in 2003




- -      




260 




- -      




250 

  Unrealized (losses) gains on derivatives qualified
   as hedges, net of income tax benefit (expense)
   for the three months of $(4,712) in 2004 and
   $2,565 in 2003 and for the six months of
   $(17,229) in 2004 and $(16,184) in 2003





7,105 





(3,868)





25,979 





24,402 

  Reclassification adjustment for derivative (gains)
   included in net income, net of income tax
   expense for the three months of $5,710
   in 2004 and $2,563 in 2003 and for the six
   months of $11,010 in 2004 and $11,590 in 2003





(8,609)





(3,864)





(16,601)





(17,476)

  Net unrealized (losses) gains on derivatives
   qualified as hedges


(1,504)


(7,732)


9,378 


6,926 

    Total other comprehensive income

(1,504)

(7,472)

9,378 

7,176 

Comprehensive Income

$29,392 

$22,451 

$93,191 

$97,716 


The notes on pages 41 through 52 are an integral part of the financial statements.

Item 2.  Management's discussion and analysis of financial condition
             and results of operations

New York State Electric & Gas Corporation

(a) Liquidity and Capital Resources

Restructuring

See Energy East's Item 2(a), Restructuring, for this discussion.

Electric Delivery Business

NYSEG's electric delivery business principally consists of its regulated transmission and distribution operations. It also generates electricity primarily from its hydroelectric stations.

NYPSC Collaborative on End State of Energy Competition: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.

Natural Gas Delivery Business

NYSEG's natural gas delivery business consists of its regulated transportation, storage and distribution operations.

Natural Gas Supply Agreements: See Energy East's Item 2(a), Natural Gas Delivery Business, for this discussion.

NYSEG Natural Gas Rate Plan: See Energy East's Item 2(a), Natural Gas Delivery Business, for this discussion.

NYPSC Collaborative on End State of Energy Competition: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.

Other Matters

Accounting Issues

FIN 46R: See Energy East's Item 2(a), Other Matters, for this discussion. (See Note 7 to the Condensed Financial Statements.)

FASB Staff Position No. FAS 106-2: See Energy East's Item 2(a), Other Matters, for this discussion. (See Note 9 to the Condensed Financial Statements.)

Investing and Financing Activities

Investing Activities: Capital spending for the first six months of 2004 was $51 million. Capital spending is projected to be $113 million for 2004 and is expected to be paid for primarily with internally generated funds. Capital spending will be primarily for necessary improvements to existing facilities, the extension of energy delivery service, compliance with environmental requirements and governmental mandates and merger integration.

Financing Activities: See Energy East's Item 2(a), NYSEG Financing Activities, for this discussion.

Management's discussion and analysis of financial condition and results of operations

New York State Electric & Gas Corporation

(b) Results of Operations

Three months ended June 30

     2004     

     2003     

Change

(Thousands)

     

Operating Revenues

$428,495

$413,364 

4% 

Operating Income

$70,935

$70,119 

1% 

Earnings Available for Common Stock

$30,797

$29,824 

3% 

Second quarter 2004 earnings increased $1 million as compared to the prior year. An increase in earnings as a result of higher electricity deliveries due to weather was substantially offset by a decrease in earnings due to lower natural gas wholesale deliveries.

Six months ended June 30

     2004     

     2003     

Change

(Thousands)

     

Operating Revenues

$1,020,709

$989,095 

3% 

Operating Income

$172,158

$190,767 

(10%)

Earnings Available for Common Stock

$83,615

$90,342 

(7%)

Earnings decreased $7 million for the six months primarily due to lower deliveries in the first quarter because of warmer winter weather in 2004.

Operating Results for the Electric Delivery Business

Three months ended June 30

     2004     

     2003     

Change

(Thousands)

     

Retail Deliveries - Megawatt-hours

3,472

3,362 

3% 

Operating Revenues

$358,521

$338,353 

6% 

Operating Expenses

$293,592

$276,011 

6% 

Operating Income

$64,929

$62,342 

4% 

The $20 million increase in operating revenues for the quarter was primarily due to increased retail deliveries of $10 million and higher wholesale revenues of $9 million.

Operating expenses increased $18 million for the quarter primarily due to higher purchased power costs of $14 million as a result of higher retail and wholesale sales.

 

Management's discussion and analysis of financial condition and results of operations

New York State Electric & Gas Corporation

Six months ended June 30

     2004     

     2003     

Change

(Thousands)

     

Retail Deliveries - Megawatt-hours

7,448

7,408 

1%  

Operating Revenues

$762,505

$744,320 

2%  

Operating Expenses

$626,937

$600,753 

4%  

Operating Income

$135,568

$143,567 

(6%) 

The $18 million increase in operating revenues for the six months was primarily due to higher retail deliveries of $4 million, increased wholesale revenues of $8 million and an $8 million increase in transmission revenues.

Operating expenses increased $26 million for the six months primarily due to higher purchased power costs of $21 million as a result of higher deliveries.

Operating Results for the Natural Gas Delivery Business

Three months ended June 30

     2004     

     2003     

Change

(Thousands)

     

Retail Deliveries - Dekatherms

10,096

11,301 

(11%) 

Operating Revenues

$69,974

$75,011 

(7%) 

Operating Expenses

$63,968

$67,234 

(5%) 

Operating Income

$6,006

$7,777 

(23%) 

Operating revenues decreased $5 million for the quarter primarily as a result of an $8 million reduction due to lower retail deliveries and an $5 million decrease in wholesale revenues. Those decreases were partially offset by higher revenues of $8 million as a result of higher market prices that were passed on to customers.

Operating expenses decreased $3 million for the quarter, primarily due to lower natural gas purchases of $2 million.

Six months ended June 30

     2004     

     2003     

Change

(Thousands)

     

Retail Deliveries - Dekatherms

35,440

37,809 

(6%) 

Operating Revenues

$258,204

$244,775 

5%  

Operating Expenses

$221,614

$197,575 

12%  

Operating Income

$36,590

$47,200 

(22%) 

Operating revenues increased $13 million for the six months primarily due to higher natural gas prices of $43 million that were passed on to customers. This increase was somewhat offset by a $15 million decrease because of lower wholesale sales, and a $15 million decrease due to lower retail deliveries because of warmer weather.

Operating expenses for the six months increased $24 million primarily due to higher natural gas purchases of $23 million; reflecting higher prices offset by lower purchase volumes.

Item 1.  Financial Statements

Rochester Gas and Electric Corporation
Condensed Statements of Income - (Unaudited)

 

Three Months

Six Months

Periods ended June 30

2004

2003

2004

2003

(Thousands)

       

Operating Revenues

       

  Electric

$160,209 

$166,384 

$324,393 

$342,678 

  Natural Gas

63,520 

62,228 

212,682 

212,628 

      Total Operating Revenues

223,729 

228,612 

537,075 

555,306 

Operating Expenses

       

  Electricity purchased and fuel used in generation

43,161 

34,025 

69,792 

76,458 

  Natural gas purchased

35,092 

33,545 

134,174 

131,250 

  Other operating expenses

34,266 

64,846 

90,736 

155,328 

  Maintenance

13,183 

14,017 

28,461 

27,450 

  Depreciation and amortization

31,984 

25,688 

67,977 

52,913 

  Other taxes

18,929 

19,457 

38,969 

43,792 

  Gain on sale of generation assets

(319,487)

-      

(319,487)

-      

  Deferral of asset sale gain

214,368 

-      

214,368 

-      

      Total Operating Expenses

71,496 

191,578 

324,990 

487,191 

Operating Income

152,233 

37,034 

212,085 

68,115 

Other (Income)

(7,437)

(423)

(8,100)

(2,541)

Other Deductions

1,570 

815 

1,943 

963 

Interest Charges, Net

13,696 

12,405 

27,800 

46,387 

Income Before Income Taxes

144,404 

24,237 

190,442 

23,306 

Income Taxes

115,475 

9,564 

135,573 

7,143 

Net Income

28,929 

14,673 

54,869 

16,163 

Preferred Stock Dividends

1,315 

925 

1,828 

1,850 

Earnings Available for Common Stock

$27,614 

$13,748 

$53,041 

$14,313 


The notes on pages 41 through 52 are an integral part of the financial statements.

 

 

Rochester Gas and Electric Corporation
Condensed Balance Sheets - (Unaudited)

 

June 30, 
2004    

Dec. 31,  
2003    

(Thousands)

   

Assets

   

Current Assets

   

 Cash and cash equivalents

$265,626

$13,596

 Special deposits

-      

3,706

 Accounts receivable, net

121,075

156,038

 Advance to affiliate

25,000

-      

 Fuel, at average cost

28,727

29,310

 Materials and supplies, at average cost

8,683

7,016

 Accumulated deferred income tax benefits, net

20,831

12,154

 Prepayments and other current assets

9,323

13,232

   Total Current Assets

479,265

235,052

Utility Plant, at Original Cost

   

 Electric

1,197,468

2,060,980

 Natural gas

548,144

522,409

 Common

174,283

158,804

 

1,919,895

2,742,193

 Less accumulated depreciation

505,687

1,271,462

   Net Utility Plant in Service

1,414,208

1,470,731

 Construction work in progress

38,005

160,595

   Total Utility Plant

1,452,213

1,631,326

Other Property and Investments, Net

13,280

287,385

Regulatory and Other Assets

   

 Regulatory assets

   

  Nuclear plant obligations

218,556

240,884

  Unfunded future income taxes

-      

50,265

  Environmental remediation costs

12,247

11,475

  Unamortized loss on debt reacquisitions

3,541

-      

  Nonutility generator termination agreement

96,076

100,687

  Asset retirement obligation

-      

163,530

  Other

152,172

174,998

 Total regulatory assets

482,592

741,839

 Other assets

   

  Prepaid pension benefits

28,033

16,524

  Other

36,796

48,704

 Total other assets

64,829

65,228

   Total Regulatory and Other Assets

547,421

807,067

   Total Assets

$2,492,179

$2,960,830


The notes on pages 41 through 52 are an integral part of the financial statements.

 

 

Rochester Gas and Electric Corporation
Condensed Balance Sheets - (Unaudited)

 

June 30, 
2004    

Dec. 31,  
2003    

(Thousands)

   

Liabilities

   

Current Liabilities

   

Current portion of preferred stock subject to mandatory
   redemption requirements


- -      


$1,250 

 Accounts payable and accrued liabilities

$131,065 

77,476 

 Interest accrued

10,552 

11,540 

 Taxes accrued

71,976 

24,130 

 Other

52,806 

29,642 

   Total Current Liabilities

266,399 

144,038 

Regulatory and Other Liabilities

   

 Regulatory liabilities

   

  Unfunded future income taxes

87,379 

-      

  Accrued removal obligation

169,618 

185,472 

  Deferred income taxes

5,471 

186,571 

  Gain from sale of generation assets

127,403 

-      

  Other

37,851 

46,173 

 Total regulatory liabilities

427,722 

418,216 

 Other liabilities

   

  Deferred income taxes

170,865 

72,568 

  Nuclear waste disposal

104,699 

104,095 

  Other postretirement benefits

73,664 

71,956 

  Environmental remediation costs

26,357 

22,356 

  Asset retirement obligation

2,171 

436,096 

  Other

45,925 

39,831 

 Total other liabilities

423,681 

746,902 

   Total Regulatory and Other Liabilities

851,403 

1,165,118 

 Preferred stock subject to mandatory redemption requirements

-      

23,750 

 Other long-term debt

736,563 

826,511 

   Total long-term debt

736,563 

850,261 

   Total Liabilities

1,854,365 

2,159,417 

Commitments

-      

-      

Preferred Stock

   

 Redeemable solely at the option of RG&E

-      

47,000 

Common Stock Equity

   

 Common stock

194,429 

194,429 

 Capital in excess of par value

556,550 

556,190 

 Retained earnings

4,073 

121,032 

 Treasury stock, at cost

(117,238)

(117,238)

   Total Common Stock Equity

637,814 

754,413 

   Total Liabilities and Stockholder's Equity

$2,492,179 

$2,960,830 


The notes on pages 41 through 52 are an integral part of the financial statements.

Rochester Gas and Electric Corporation
Condensed Statements of Cash Flows - (Unaudited
)

Six months ended June 30

2004

2003

(Thousands)

   

   Net Cash Provided by Operating Activities

$85,551 

$139,955 

Investing Activities

   

 Proceeds from sale of generation assets

428,541 

-      

 Refund of excess decommissioning fund

76,593 

-      

 Advance to affiliate

(25,000)

-      

 Utility plant additions

(32,361)

(40,044)

 Nuclear generating plant decommissioning fund

(8,560)

(8,662)

 Other

3,706 

(2,052)

   Net Cash Provided by (Used in) Investing Activities

442,919 

(50,758)

Financing Activities

   

 Repayments of first mortgage bonds and preferred stock

(162,000)

(40,000)

 Outstanding customer refund, overdraft

57,388 

-      

 Repayment of promissory notes

-      

(79,935)

 Dividends on common and preferred stock

(171,828)

(31,850)

   Net Cash Used in Financing Activities

(276,440)

(151,785)

Net Increase (Decrease) in Cash and Cash Equivalents

252,030 

(62,588)

Cash and Cash Equivalents, Beginning of Period

13,596 

86,385 

Cash and Cash Equivalents, End of Period

$265,626 

$23,797 


The notes on pages 41 through 52 are an integral part of the financial statements.





Rochester Gas and Electric Corporation
Condensed Statements of Retained Earnings - (Unaudited)

Six months ended June 30

2004

2003

(Thousands)

   

Balance, Beginning of Period

$121,032 

$154,267

Add net income

54,869 

16,163

 

175,901 

170,430

Deduct Dividends on Capital Stock

   

 Preferred

1,828 

1,850

 Common

170,000 

30,000


171,828 

31,850

Balance, End of Period

$4,073 

$138,580


The notes on pages 41 through 52 are an integral part of the financial statements.

 

Item 2.  Management's discussion and analysis of financial condition
             and results of operations

Rochester Gas and Electric Corporation

(a) Liquidity and Capital Resources

Restructuring

See Energy East's Item 2(a), Restructuring, for this discussion.

Electric Delivery Business

RG&E's electric delivery business consists of its regulated transmission and distribution operations. It also generates electricity from its one coal-fired plant, three gas turbines and several smaller hydroelectric stations.

RG&E 2003 Electric and Natural Gas Rate Agreements: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.

Sale of Ginna Station: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.

RG&E Electric Rate Unbundling: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.

RG&E Transmission Project: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.

NYPSC Collaborative on End State of Energy Competition: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.

Natural Gas Delivery Business

RG&E's natural gas delivery business consists of its regulated transportation, storage and distribution operations.

Natural Gas Supply Agreements: See Energy East's Item 2(a), Natural Gas Delivery Business, for this discussion.

RG&E 2003 Electric and Natural Gas Rate Agreements

: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.

NYPSC Collaborative on End State of Energy Competition: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.

Other Matters

Accounting Issues

FASB Staff Position No. FAS 106-2: See Energy East's Item 2(a), Other Matters, for this discussion. (See Note 9 to the Condensed Financial Statements.)

 

Management's discussion and analysis of financial condition and results of operations

Rochester Gas and Electric Corporation

Investing and Financing Activities

Investing Activities: Capital spending for the first six months of 2004 was $32 million, including nuclear fuel. Capital spending is projected to be $123 million for 2004, including nuclear fuel, and is expected to be paid for primarily with internally generated funds. Capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates and merger integration.

Financing Activities: See Energy East's Item 2(a), RG&E Financing Activities, for this discussion.

(b) Results of Operations

Three months ended June 30

     2004     

     2003     

Change

(Thousands)

     

Operating Revenues

$223,729

$228,612

(2%)

Operating Income

$152,233

$37,034

311% 

Earnings Available for Common Stock

$27,614

$13,748

101% 

Earnings increased $14 million for the quarter primarily due to one-time effects from the sale of Ginna and the approval of RG&E's Electric and Natural Gas Rate Agreements, which increased earnings $10 million. The one-time effects include the flow-through of excess deferred taxes and investment tax credits and the elimination of certain reserves established pending regulatory determination. Ongoing effects from RG&E's Electric and Natural Gas Rate Agreements added $7 million to earnings, and include increases as a result of RG&E's electric retail access surcharge and natural gas merchant function charge, and annual credits to RG&E from the ASGA as provided in the Electric Rate Agreement. (See RG&E 2003 Electric and Natural Gas Rate Agreements.)

Six months ended June 30

     2004     

     2003     

Change

(Thousands)

     

Operating Revenues

$537,075

$555,306

(3%)

Operating Income

$212,085

$68,115

211% 

Earnings Available for Common Stock

$53,041

$14,313

271% 

Earnings for the six months increased $39 million primarily due to the second quarter effects of the sale of Ginna and RG&E's Electric and Natural Gas Rate Agreements discussed above that added $17 million to earnings and the recognition of the terms and conditions of the NYPSC rate order for RG&E, which became effective in January 2003, and reduced earnings by $30 million in the first quarter of 2003. The January 2003 rate order included $26 million for excess earnings and related interest.

 

Management's discussion and analysis of financial condition and results of operations

Rochester Gas and Electric Corporation

Operating Results for the Electric Delivery Business

Three months ended June 30

     2004     

     2003     

Change

(Thousands)

     

Retail Deliveries - Megawatt-hours

1,699

1,669

2% 

Operating Revenues

$160,209

$166,384

(4%)

Operating Expenses

$14,603

$136,048

(89%)

Operating Income

$145,606

$30,336

380% 

The $6 million decrease in operating revenues for the quarter is primarily due to a change in market structure that allows ESCOs to provide electricity, which reduced retail revenues by $41 million and increased wholesale revenues by $27 million. That decrease was partially offset by higher retail deliveries that added $3 million to revenues.

Operating expenses decreased $121 million for the quarter primarily due to RG&E's recognition of a $319 million pretax gain on the Ginna sale, partially offset by RG&E's deferral of the gain net of tax of $214 million. The remaining $16 million reduction was primarily the result of lower electricity purchases as a result of the change in market structure and the net effects of the Ginna sale that reduced operating expenses and increased purchased power costs.

Six months ended June 30

     2004     

     2003     

Change

(Thousands)

     

Retail Deliveries - Megawatt-hours

3,439

3,450

-    

Operating Revenues

$324,393

$342,678

(5%)

Operating Expenses

$144,345

$309,196

(53%)

Operating Income

$180,048

$33,482

438% 

Operating revenues for the six months decreased $18 million due a change in market structure that allows ESCOs to provide electricity, which reduced retail revenues by $77 million and increased wholesale revenues by $55 million.

Operating expenses decreased $165 million for the six primarily due to RG&E's recognition of a $319 million pretax gain on the Ginna sale, partially offset by RG&E's deferral of the gain net of tax of $214 million. An additional decrease of $30 million resulted from the recognition of the terms and conditions of the NYPSC rate order for RG&E, which became effective in January 2003, and increased operating expenses by $30 million in 2003. The remaining $25 million reduction was primarily the result of lower electricity purchases as a result of the change in market structure, and the net effects of the Ginna sale that reduced operating expenses and increased purchased power costs.

 

Management's discussion and analysis of financial condition and results of operations

Rochester Gas and Electric Corporation

Operating Results for the Natural Gas Delivery Business

Three months ended June 30

     2004     

     2003     

Change

(Thousands)

     

Retail Deliveries - Dekatherms

8,529

9,314

(8%)

Operating Revenues

$63,520

$62,228

2% 

Operating Expenses

$56,893

$55,530

2% 

Operating Income

$6,627

$6,698

(1%)

Operating revenues increased $1 million for the quarter. Higher market prices for natural gas purchased of $9 million that were passed on to customers were offset by lower deliveries that reduced revenues $7 million.

Operating expenses increased $1 million for the quarter primarily due to higher market prices for purchased natural gas that were offset by fewer purchases because of lower deliveries.

Six months ended June 30

     2004     

     2003     

Change

(Thousands)

     

Retail Deliveries - Dekatherms

32,677

34,347

(5%)

Operating Revenues

$212,682

$212,628

-    

Operating Expenses

$180,645

$177,995

1% 

Operating Income

$32,037

$34,633

(7%)

Operating revenues remained relatively flat for the six months. Higher market prices for natural gas purchased of $13 million that were passed on to customers were offset by lower deliveries that reduced revenues $13 million.

Operating expenses increased $3 million for the quarter primarily due to higher market prices for purchased natural gas that were offset by lower operating costs.

Item 1.  Financial Statements

Notes to Condensed Financial Statements
for
Energy East Corporation
Central Maine Power Company
New York State Electric & Gas Corporation
Rochester Gas and Electric Corporation

Notes to Condensed Financial Statements of Registrants:

Registrant

Applicable Notes

Energy East

1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11

CMP

1, 3, 4, 7, 8, 9, 10, 11

NYSEG

1, 3, 4, 7, 8, 9, 10, 11

RG&E

1, 2, 3, 4, 8, 9, 10, 11

Note 1. Unaudited Condensed Financial Statements

The accompanying unaudited condensed financial statements reflect all adjustments necessary, in the opinion of the management of the registrants, for a fair presentation of the interim results. All such adjustments are of a normal, recurring nature. The year-end condensed balance sheet data presented in this quarterly report was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.

Energy East's financial statements and CMP's financial statements consolidate their majority-owned subsidiaries after eliminating all intercompany transactions.

The accompanying unaudited financial statements for each registrant should be read in conjunction with the financial statements and notes contained in the report on Form 10-K filed by each registrant for the year ended December 31, 2003. Due to the seasonal nature of the registrants' operations, financial results for interim periods are not necessarily indicative of trends for a 12-month period.

Reclassifications: Certain amounts have been reclassified in the company's unaudited financial statements to conform to the 2004 presentation and to reflect discontinued operations.

Note 2. Sale of Ginna Nuclear Generating Station

On June 10, 2004, after receiving all regulatory approvals, RG&E sold Ginna to CGG. RG&E received at closing $429 million in cash. The gain on the sale of Ginna of $319 million net of income taxes of $105 million equals the $214 million deferral of asset sale gain, as reflected on RG&E's statement of income.

RG&E's Electric Rate Agreement resolves all regulatory and ratemaking aspects related to the sale of Ginna, including providing for an ASGA, established at the time of closing in the amount of $357 million, and addressing the disposition of the asset sale gain. Upon closing of the Ginna sale, RG&E transferred $201 million of decommissioning funds to CGG, which will take responsibility for all future decommissioning funding. RG&E retained $77 million in excess decommissioning funds, which was credited to customers as part of the ASGA.

A summary of information on the sale of Ginna and the related ASGA at the time of the sale follows (in thousands):

Cash proceeds

$428,541 

Net book value of property sold, excluding decommissioning reserve

(184,564)

Decommissioning reserve

311,571 

Decommissioning funds

(277,113)

Excess decommissioning funds retained

76,593 

Miscellaneous assets and liabilities, including deferred selling costs

(35,541)

Gain on sale of generation assets, deferred

319,487 

Income taxes payable

(105,119)

Deferral of asset sale gain

214,368 

Regulatory liability equal to deferred income taxes on the deferred asset sale gain

143,000 

Balance at closing, Gain from sale of generation assets, deferred

$357,368 

The ASGA was adjusted subsequent to the sale to reflect provisions of RG&E's Electric Rate Agreement, including refunds due to customers. Adjustments to the ASGA to reconcile to the balance of the deferred regulatory liability as of June 30, 2004, were as follows (in thousands):

Gain from sale of generation assets, deferred

$357,368 

Regulatory liability equal to deferred income taxes on the deferred asset sale gain

(143,000)

Refund to customers June 2004

(60,003)

Refund to customers January 2005 - Other current liability

(24,997)

Other

(1,965)

Balance at June 30, 2004, Gain from sale of generation assets

$127,403 

In addition, the company's and RG&E's effective tax rate was significantly affected by the sale of Ginna. Due to the regulatory accounting for the gain on the sale, any gain in excess of what was required to offset income taxes payable on the sale was required to be deferred. Therefore, RG&E recorded pretax income of $105,119 and income tax expense of $105,119 resulting in a 100% effective tax rate on this income, increasing the effective tax rate from an expected rate of 39% for the company and 41% for RG&E, to an effective rate of 56% for the company and 71% for RG&E.

 

Note 3. Restructuring

The company recognized a $4 million total liability for an enhanced severance program for 83 accounting and finance employees who were employed through March 31, 2004. During the fourth quarter of 2003, 40%, or approximately $2 million, of the estimated liability was charged to other operating expenses and represented the company's cumulative expense and liability as of December 31, 2003. The remaining $2 million of the liability was charged to other operating expenses in the first quarter of 2004. The total liability includes $0.9 million for CMP, $0.9 million for NYSEG and $1.4 million for RG&E. Approximately $3 million of the total cost was incurred by the electric delivery business and $1 million by the natural gas delivery business. The liability was paid off as of June 30, 2004.

Note 4. Other (Income) and Other Deductions

 

Three Months

Six Months

Periods ended June 30

2004

2003

2004

2003

(Thousands)

       

Energy East

       

 Interest income

$(959)

$(1,086)

$(1,365)

$(2,355)

 Allowance for funds used during construction

(160)

(422)

(262)

(966)

 Gains from the sale of nonutility property

(1,159)

(5)

(1,236)

(59)

 Earnings from equity investments

(852)

(884)

(2,557)

(2,542)

 2003 RG&E Electric and Natural Gas
  Rate Agreement


(6,117)


- -     


(6,117)


- -     

 Miscellaneous

(2,434)

119 

(5,872)

(888)

  Total other (income)

$(11,681)

$(2,278)

$(17,409)

$(6,810)

 Losses from disposition of property

$3,474 

-     

$4,048 

-     

 Miscellaneous

924 

$1,261 

3,627 

$3,048 

  Total other deductions

$4,398 

$1,261 

$7,675 

$3,048 

CMP

       

 Interest income

$(20)

$(162)

$(34)

$(418)

 Earnings from equity investments

(217)

(480)

(513)

(1,018)

 Miscellaneous

(795)

(119)

(1,536)

(312)

  Total other (income)

$(1,032)

$(761)

$(2,083)

$(1,748)

 Miscellaneous

$164 

$420 

$299 

$799 

  Total other deductions

$164 

$420 

$299 

$799 

NYSEG

       

 Interest income

$(58)

$(274)

$(119)

$(652)

 Miscellaneous

(158)

90 

(53)

(1,456)

  Total other (income)

$(216)

$(184)

$(172)

$(2,108)

 Miscellaneous

$454 

$(1,553)

$172 

$(1,297)

  Total other deductions

$454 

$(1,553)

$172 

$(1,297)

RG&E

       

 Interest income

$(794)

$(236)

$(462)

$(1,947)

 2003 RG&E Electric and Natural Gas
  Rate Agreement


(6,117)


- -     


(6,117)


- -     

 Miscellaneous

(526)

(187)

(1,521)

(594)

  Total other (income)

$(7,437)

$(423)

$(8,100)

$(2,541)

 Losses from disposition of property

$3,158 

-     

$3,158 

-     

 Miscellaneous

(1,588)

$815 

(1,215)

$963 

  Total other deductions

$1,570 

$815 

$1,943 

$963 

 

Note 5. Basic and Diluted Earnings per Share

Basic earnings per share (EPS) is determined by dividing net income by the weighted-average number of shares of common stock outstanding during the period. The weighted-average common shares outstanding for diluted EPS include the incremental effect of restricted stock and stock options issued and exclude stock options issued in tandem with stock appreciation rights (SARs). However, all stock options are issued in tandem with SARs and, historically, substantially all stock option plan participants have exercised the SARs instead of the stock options. The numerator used in calculating both basic and diluted EPS for each period is the reported net income.

The reconciliation of basic and dilutive average common shares for each period follows:

 

Three Months

Six Months

Periods ended June 30

2004

2003

2004

2003

(Thousands)

       

  Basic average common shares outstanding

146,148 

145,415 

146,116 

145,256 

  Restricted stock awards

448 

225 

396 

173 

  Potentially dilutive common shares

302 

107 

266 

127 

  Options issued with SARs

(302)

(107)

(266)

(127)

  Dilutive average common shares outstanding

146,596 

145,640 

146,512 

145,429 

Options to purchase shares of common stock are excluded from the determination of EPS when the exercise price of an option is greater than the average market price of a common share during the period. Shares excluded from the EPS calculation for the three months ended June 30 were: 0.7 million in 2004 and 5.2 million in 2003, and for the six months ended June 30 were: 1.3 million in 2004 and 5.2 million in 2003.

During the first quarter of 2004 the company awarded 242,038 shares of its common stock, issued out of its treasury stock, to certain employees through its Restricted Stock Plan and recorded deferred compensation of $6 million based on the market price per share of common stock on the dates of the awards, which averaged $23.90.

 

Note 6. Discontinued Operations

In keeping with its focus on regulated electric and natural gas delivery businesses, during recent years the company has been systematically exiting certain noncore businesses. In June 2004 UWP, a subsidiary of CMP Group, Inc., reached an agreement to sell the assets associated with its utility locating and construction divisions. The sale was completed on July 26, 2004. In 2003 Berkshire Propane, Inc., a subsidiary of Berkshire Energy Resources, sold its assets and Energetix, a subsidiary of RGS Energy Group, Inc. which is a wholly-owned subsidiary of Energy East, sold its Griffith Oil Co., Inc. All three businesses were previously reported in the company's Other business segment. Certain financial information concerning the businesses for the three months and six months ended June 30, 2004 and 2003, is shown in the table below.

 

 

Three Months

Six Months

Periods ended June 30

2004

2003

2004

2003

(Thousands)

       

Certain Divisions of Union Water Power Co.

       

  Revenues

$8,157 

$6,969 

$13,175 

$10,432 

  Income (loss) from businesses held for sale
   (including estimated loss on disposal in
   2004 of $5,500)



$(4,249)



$619 



$(4,527)



$(1,375)

  Income taxes (benefits)

467 

100 

346 

(712)

  Income (loss) from discontinued operations

$(4,716)

$519 

$(4,873)

$(663)

Griffith Oil Co., Inc.

       

  Revenues

-     

$83,922 

-     

$211,544 

  Income (loss) from businesses sold

-     

$(1,503)

-     

$5,916 

  Income taxes (benefits)

-     

(671)

-     

2,107 

  Income (loss) from discontinued operations

-     

$(832)

-     

$3,809 

Berkshire Propane, Inc.

       

  Revenues

-     

$1,041 

-     

$4,472 

  Income (loss) from businesses sold

-     

$(17)

-     

$517 

  Income taxes

-     

286 

-     

506 

  Income (loss) from discontinued operations

-     

$(303)

-     

$11 

Note 7. FIN 46R

In December 2003 the FASB issued its revised FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51 (FIN 46R). FIN 46R addresses consolidation of variable interest entities. A variable interest entity is an entity that is not controllable through voting interests and/or in which the equity investor does not bear the residual economic risks and rewards. FIN 46R requires a business enterprise to consolidate a variable interest entity if that enterprise has a variable interest that will absorb a majority of the entity's expected losses. The company was required to apply FIN 46R to all entities subject to the interpretation as of March 31, 2004.

 

CMP and NYSEG have independent, ongoing, power purchase contracts with various nonutility generators (NUGs). (See report on Form 10-K for Energy East, CMP and NYSEG for fiscal year ended December 31, 2003, Item 7 - Liquidity and Capital Resources, Contractual Obligations and Commercial Commitments.) CMP and NYSEG were not involved in the formation of and do not have ownership interests in any NUGs. The company evaluated each of CMP's and NYSEG's power purchase contracts with NUGs with respect to FIN 46R. Most of the power purchase contracts were determined not to be variable interests due to one of the following reasons: the contract is based on a fixed price or a market price and there is no other involvement with the NUG, the contract is short-term in duration, the contract is for a minor portion of the NUG's capacity or the NUGs are either governmental organizations or individuals.

The companies are not able to apply FIN 46R to seven remaining NUGs because they are unable to obtain the information necessary to: (1) determine if the NUGs are variable interest entities, (2) determine if either CMP or NYSEG is a NUG's primary beneficiary or (3) perform the accounting required to consolidate any of the seven NUGs. CMP requested necessary information from four NUGs and NYSEG requested information from three NUGs. Three of the NUGs responded but none provided the requested information. The companies will continue to make efforts to obtain information, including from the four NUGs that did not respond to the request.

The companies purchase electricity from the seven NUGs at above-market prices. CMP and NYSEG are not exposed to any loss as a result of their involvement with NUGs because they are allowed to recover through rates the cost of their purchases. Also, they are under no obligation to a NUG if it decides not to operate for any reason. The combined contractual capacity for the four NUGS from which CMP purchases electricity is approximately 22 MW. CMP's purchases from the four NUGs totaled $7 million for the six months ended June 30, 2004, and $5 million for the six months ended June 30, 2003. The combined contractual capacity for the three NUGS from which NYSEG purchases electricity is approximately 494 MW. NYSEG's purchases from the three NUGs totaled $172 million for the six months ended June 30, 2004, and $169 million for the six months ended June 30, 2003.

CMP and NYSEG did not consolidate any NUGs as of June 30, 2004.

Note 8. Accounts Receivable

Accounts receivable for the companies include unbilled revenues as follows: Energy East - consolidated unbilled revenues of $86 million at June 30, 2004, and $219 million at December 31, 2003; CMP - consolidated unbilled revenues of $13 million at June 30, 2004, and $25 million at December 31, 2003; NYSEG - unbilled revenues of $43 million at June 30, 2004, and $72 million at December 31, 2003; RG&E - unbilled revenues of $20 million at June 30, 2004, and $50 million at December 31, 2003.

 

Note 9. Retirement Benefits

Components of net periodic benefit cost

 

Pension Benefits

Postretirement Benefits

Three months ended June 30

2004

2003

2004

2003

(Thousands)

       

Energy East

       

  Service cost

$7,807 

$7,606 

$1,407 

$1,501 

  Interest cost

32,931 

33,008 

8,987 

9,446 

  Expected return on plan assets

(51,742)

(51,309)

(672)

(786)

  Amortization of prior service cost

1,161 

1,246 

(1,713)

(1,723)

  Recognized net actuarial (gain) loss

(210)

(596)

1,583 

2,254 

  Amortization of transition (asset) obligation

(307)

(1,809)

1,984 

2,016 

  Curtailment

-      

202 

-      

(307)

Net periodic benefit cost

$(10,360)

$(11,652)

$11,576 

$12,401 

CMP

       

  Service cost

$1,017 

$1,107 

$353 

$399 

  Interest cost

3,506 

3,429 

2,067 

1,976 

  Expected return on plan assets

(3,852)

(3,688)

(265)

(379)

  Amortization of prior service cost

50 

61 

(157)

(164)

  Recognized net actuarial (gain) loss

1,277 

1,103 

695 

539 

  Curtailment

-      

202 

-      

(307)

Net periodic benefit cost

$1,998 

$2,214 

$2,693 

$2,064 

NYSEG

       

  Service cost

$4,471 

$4,053 

$793 

$777 

  Interest cost

17,421 

17,072 

4,506 

5,012 

  Expected return on plan assets

(30,968)

(30,231)

-     

-     

  Amortization of prior service cost

1,084 

1,166 

(1,532)

(1,540)

  Recognized net actuarial (gain) loss

(2,758)

(4,071)

808 

1,431 

  Amortization of transition (asset) obligation

(307)

(1,809)

1,983 

2,016 

Net periodic benefit cost

$(11,057)

$(13,820)

$6,558 

$7,696 

RG&E

       

  Service cost

$1,234 

$1,572 

$243 

$292 

  Interest cost

7,435 

8,086 

1,502 

1,562 

  Expected return on plan assets

(12,136)

(12,823)

-     

-     

  Unrecognized transition obligation

-     

-     

514 

621 

  Amortization of prior service cost

306 

365 

277 

335 

  Recognized net actuarial (gain) loss

(1,788)

(2,062)

(110)

(69)

Net periodic benefit cost

$(4,949)

$(4,862)

$2,426 

$2,741 

 

 

 

Pension Benefits

Postretirement Benefits

Six months ended June 30

2004

2003

2004

2003

(Thousands)

       

Energy East

       

  Service cost

$16,055 

$15,608 

$3,250 

$3,343 

  Interest cost

65,492 

66,245 

18,369 

18,356 

  Expected return on plan assets

(103,060)

(102,087)

(1,336)

(1,400)

  Amortization of prior service cost

2,325 

2,493 

(3,424)

(3,440)

  Recognized net actuarial (gain) loss

(535)

(3,093)

3,795 

3,365 

  Amortization of transition (asset) obligation

(615)

(3,619)

4,001 

4,033 

  Curtailment

-      

202 

-      

(307)

Net periodic benefit cost

$(20,338)

$(24,251)

$24,655 

$23,950 

CMP

       

  Service cost

$2,118 

$2,206 

$839 

$907 

  Interest cost

6,968 

6,787 

4,110 

3,957 

  Expected return on plan assets

(7,444)

(7,053)

(520)

(582)

  Amortization of prior service cost

99 

109 

(314)

(321)

  Recognized net actuarial (gain) loss

2,420 

2,000 

1,271 

1,047 

  Curtailment

-      

202 

-      

(307)

Net periodic benefit cost

$4,161 

$4,251 

$5,386 

$4,701 

NYSEG

       

  Service cost

$9,054 

$8,434 

$1,745 

$1,616 

  Interest cost

34,435 

33,928 

9,413 

9,413 

  Expected return on plan assets

(61,908)

(60,333)

-      

-      

  Amortization of prior service cost

2,167 

2,329 

(3,065)

(3,079)

  Recognized net actuarial (gain) loss

(6,144)

(8,355)

2,227 

1,885 

  Amortization of transition (asset) obligation

(615)

(3,619)

4,000 

4,033 

Net periodic benefit cost

$(23,011)

$(27,616)

$14,320 

$13,868 

RG&E

       

  Service cost

$2,740 

$3,143 

$515 

$584 

  Interest cost

14,902 

16,172 

3,027 

3,124 

  Expected return on plan assets

(24,592)

(25,646)

-      

-      

  Unrecognized transition obligation

-      

-      

1,059 

1,242 

  Amortization of prior service cost

631 

731 

571 

670 

  Recognized net actuarial (gain) loss

(3,453)

(4,124)

(132)

(138)

Net periodic benefit cost

$(9,772)

$(9,724)

$5,040 

$5,482 

In April of 2004 Energy East contributed $19 million to its retirement benefit plans, including $11 million for CMP.

In December 2003 President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act introduces a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.

In May 2004 the FASB issued its FASB Staff Position (FSP) No. FAS 106-2, which addresses how and when a plan sponsor should account for the federal subsidy introduced by the Act and could require the plan sponsor to change previously reported information. FSP No. FAS 106-2 is effective for the first interim or annual period beginning after June 15, 2004. When FSP No. FAS 106-2 becomes effective it supersedes FSP No. FAS 106-1. The company, CMP, NYSEG and RG&E will apply FSP No. 106-2 beginning July 1, 2004. However, since detailed regulations necessary to implement the Act have not been issued, the companies are unable to conclude whether the benefits provided by their plans are actuarially equivalent to Medicare Part D under the Act. Any measures of the accumulated pension benefit obligation or net periodic postretirement benefit cost in the companies' financial statements or accompanying notes do not reflect any amount associated with the subsidy because the companies' are unable to conclude whether the benefits provided by their plans are actuarially equivalent to Medicare Part D. The companies have not yet determined the potential effects of the Act on their future postretirement costs, including the participation rates in their benefit plans, or whether any amendments to their benefit plans are appropriate given the provisions of the Act.

Note 10. Goodwill and Intangible Assets

The companies no longer amortize goodwill effective January 1, 2002, and do not amortize intangible assets with indefinite lives (unamortized intangible assets). RG&E has no goodwill or intangible assets with indefinite lives. The companies test both goodwill and unamortized intangible assets for impairment at least annually. The companies amortize intangible assets with finite lives (amortized intangible assets) and review them for impairment. Annual impairment testing was completed and it was determined that there was no impairment of goodwill or unamortized intangible assets for the companies at September 30, 2003.

Changes in the carrying amounts of Energy East's goodwill, by operating segment, from January 1, 2004, to June 30, 2004, are shown in the table below.

 

Electric
     Delivery     

Natural Gas
    Delivery    


     Other     


     Total     

(Thousands)

       

Balance, January 1, 2004

$844,531 

$677,119 

$11,473 

$1,533,123 

Goodwill related to
  businesses held for sale


- -      


- -      


(5,500)


(5,500)

Preacquisition income tax
  adjustment


(40)


(531)


117 


(454)

Balance, June 30, 2004

$844,491 

$676,588 

$6,090 

$1,527,169 

The carrying amount of CMP's goodwill, which is included in its electric delivery operating segment, was $325 million as of June 30, 2004, and January 1, 2004. The carrying amount of NYSEG's goodwill, which is included in its natural gas delivery operating segment, was $11 million as of June 30, 2004, and January 1, 2004.

The company's unamortized intangible assets had a carrying amount of $10 million at June 30, 2004, and December 31, 2003, and primarily consisted of pension assets. The company's amortized intangible assets had a gross carrying amount of $31 million at June 30, 2004, and December 31, 2003, and primarily consisted of investments in pipelines. Accumulated amortization was $13 million at June 30, 2004, and $12 million at December 31, 2003. Estimated amortization expense for intangible assets for the next five years is approximately $3 million for 2004, $2 million for 2005, and $1 million each year for 2006 through 2008.

CMP's unamortized intangible assets consist of pension assets and had a carrying amount of $2 million at June 30, 2004, and December 31, 2003. CMP's amortized intangible assets had a gross carrying amount and accumulated amortization of less than $0.3 million at June 30, 2004, and December 31, 2003, and primarily consisted of technology rights. Estimated amortization expense for intangible assets is $26 thousand for the years 2004 through 2006, and $8 thousand for 2007, after which amortization will be complete.

 

NYSEG's unamortized intangible assets had a carrying amount of $1.4 million at June 30, 2004, and December 31, 2003, and primarily consisted of pension assets, franchises and consents. NYSEG's amortized intangible assets had a gross carrying amount of $1.8 million at June 30, 2004, and $1.5 million at December 31, 2003, and accumulated amortization of $1 million at June 30, 2004, and December 31, 2003, and consisted of hydroelectric licenses. Estimated amortization expense for intangible assets for the next five years is $41 thousand for the years 2004 through 2006, $38 thousand for 2007 and $35 thousand for 2008.

RG&E's amortized intangible assets consist of water rights, and had a gross carrying amount of $3 million and accumulated amortization of $2 million at June 30, 2004, and December 31, 2003. Estimated amortization expense for intangible assets is $78 thousand for each of the next five years, 2004 through 2008.

Note 11. Segment Information

Energy East's electric delivery business consists of its regulated transmission, distribution and generation operations in Maine and New York; and its natural gas delivery business consists of its regulated transportation, storage and distribution operations in Connecticut, Maine, Massachusetts and New York. Other includes: the company's corporate assets, interest income, interest expense and operating expenses; intersegment eliminations; and nonutility businesses.

CMP's electric delivery business, which it conducts in Maine, consists of its regulated transmission and distribution operations.

NYSEG's electric delivery business consists of its regulated transmission, distribution and generation operations. Its natural gas delivery business consists of its regulated transportation, storage and distribution operations. NYSEG operates in the State of New York. Other includes NYSEG's corporate assets.

RG&E's electric delivery business consists of its regulated transmission, distribution and generation operations. Its natural gas delivery business consists of its regulated transportation, storage and distribution operations. RG&E operates in the State of New York. Other includes RG&E's corporate assets.

 

Selected information for Energy East's, CMP's, NYSEG's and RG&E's business segments is:

 

Electric
     Delivery     

Natural Gas
    Delivery    


     Other     


     Total     

(Thousands)

       

Three Months Ended

       

June 30, 2004

       

  Operating Revenues
   Energy East
   CMP
   NYSEG
   RG&E


$641,057
$129,748
$358,521
$160,209


$240,282 
- -      
$69,974 
$63,520 


$99,227 
- -      
- -      
- -      


$980,566
$129,748
$428,495
$223,729

  Net Income (Loss)
   Energy East
   CMP
   NYSEG
   RG&E


$41,986
$3,430
$30,184
$27,464


$(12,431)
- -      
$712 
$1,465 


$8,511 
- -      
- -      
- -      


$38,066
$3,430
$30,896
$28,929

June 30, 2003

       

  Operating Revenues
   Energy East
   CMP
   NYSEG
   RG&E


$640,035
$135,259
$338,353
$166,384


$264,054 
- -      
$75,011 
$62,228 


$75,024 
- -      
- -      
- -      


$979,113
$135,259
$413,364
$228,612

  Net Income (Loss)
   Energy East
   CMP
   NYSEG
   RG&E


$29,900
$2,821
$28,130
$12,030


$(602)
- -      
$1,793 
$2,643 


$(1,581)
- -      
- -      
- -      


$27,717
$2,821
$29,923
$14,673

 

 

 

Electric
     Delivery     

Natural Gas
    Delivery    


     Other     


     Total     

(Thousands)

       

Six Months Ended

       

June 30, 2004

       

  Operating Revenues
   Energy East
   CMP
   NYSEG
   RG&E


$1,371,652 
$292,498 
$762,505 
$324,393 


$922,006
- -      
$258,204
$212,682


$267,981 
- -      
- -      
- -      


$2,561,639
$292,498
$1,020,709
$537,075

  Net Income (Loss)
   Energy East
   CMP
   NYSEG
   RG&E


$113,512 
$24,257 
$67,161 
$41,143 


$54,171
- -      
$16,652
$13,726


$(9,065)
- -      
- -      
- -      


$158,618
$24,257
$83,813
$54,869

June 30, 2003

       

  Operating Revenues
   Energy East
   CMP
   NYSEG
   RG&E


$1,398,748 
$311,676 
$744,320 
$342,678 


$904,167
- -      
$244,775
$212,628


$181,029 
- -      
- -      
- -      


$2,483,944
$311,676
$989,095
$555,306

  Net Income (Loss)
   Energy East
   CMP
   NYSEG
   RG&E


$92,575 
$26,923 
$67,722 
$(2,319)


$65,623
- -      
$22,818
$18,482


$158,618 
- -      
- -      
- -      


$163,181
$26,923
$90,540
$16,163

Total Assets

       

June 30, 2004
   Energy East
   CMP
   NYSEG
   RG&E


$6,736,575 
$1,788,504 
$2,466,720 
$1,923,840 


$3,644,236
- -      
$1,057,265
$568,339


$287,217 
- -      
- -      
- -      


$10,668,028
$1,788,504
$3,523,985
$2,492,179

December 31, 2003
   Energy East
   CMP
   NYSEG
   RG&E


$7,293,829 
$1,806,853 
$2,664,449 
$2,288,175 


$3,536,280
- -      
$870,464
$590,555


$476,323 
- -      
$52,652 
$82,100 


$11,306,432
$1,806,853
$3,587,565
$2,960,830

Forward-looking Statements

This Form 10-Q contains certain forward-looking statements that are based upon management's current expectations and information that is currently available. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements in certain circumstances. Whenever used in this report, the words "estimate," "expect," "believe," or similar expressions are intended to identify such forward-looking statements.

In addition to the assumptions and other factors referred to specifically in connection with such statements, factors that involve risks and uncertainties and that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others: the deregulation and continued regulatory unbundling of a vertically integrated industry; the companies' ability to compete in the rapidly changing and increasingly competitive electricity and/or natural gas utility markets; regulatory uncertainty in a politically-charged environment of changing energy prices; the operation of the New York Independent System Operator and ISO New England, Inc.; the operation of a regional transmission organization; the ability to recover nonutility generator and other costs; changes in fuel supply or cost and the success of strategies to satisfy power requirements; the company's ability to expand its products and services, including its energy infrastructure in the Northeast; the compa ny's ability to integrate the operations of Berkshire Energy Resources, CMP Group, Inc., Connecticut Energy Corporation, CTG Resources, Inc, RGS Energy Group, Inc., and NYSEG; the company's ability to achieve enterprise-wide integration synergies; market risk; the ability to obtain adequate and timely rate relief; nuclear or environmental incidents; legal or administrative proceedings; changes in the cost or availability of capital; growth in the areas in which the companies are doing business; weather variations affecting customer energy usage; authoritative accounting guidance; acts of terrorists; and other considerations, such as the effect of the volatility in the equity markets on pension benefit cost, that may be disclosed from time to time in the companies' publicly disseminated documents and filings. The companies undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

(See report on Form 10-K for Energy East, CMP, NYSEG and RG&E for fiscal year ended December 31, 2003, Item 7A - Quantitative and Qualitative Disclosures About Market Risk.)

Commodity Price Risk: NYSEG and RG&E use electricity contracts, both physical and financial, to manage fluctuations in the cost of electricity. The cost or benefit of those contracts is included in the amount expensed for electricity purchased when the electricity is sold.

NYSEG's current electric rate plan offers retail customers choice in their electricity supply including a variable rate option, an option to purchase electricity supply from an alternative energy company, and a bundled rate option. Approximately 38% of NYSEG's total electric load is now provided by an alternative energy company or at the market price. NYSEG's exposure to fluctuations in the market price of electricity is limited to the load required to serve those customers who select the bundled rate option, which combines delivery and supply service at a fixed price. For 2004 the customer supply cost component is based on average electricity forward prices for 2003 and 2004 available during September 2002, plus 35% to cover the costs and risk that NYSEG is assuming by providing a bundled rate option to retail customers. NYSEG actively hedges the load required to serve customers who select the bundled rate option. As of July 30, 2004, NYSEG's load was 98% hedged for on-peak periods and 92% hedged for off - -peak periods in 2004. A fluctuation of $1.00 per megawatt-hour in the price of electricity would change earnings by $0.25 million for August through December 2004. The percentage of NYSEG's hedged load is based on NYSEG's load forecasts, which include certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in the load compared to the load forecast.

Under the terms of its Electric Rate Agreement RG&E is allowed to recover its actual fuel expenses effective May 1, 2004, and the earnings risks related to changes in market value of electricity are eliminated. Beginning January 1, 2005, in accordance with its Electric Rate Agreement, RG&E will offer its retail customers choice in their electricity supply including a variable price option, an option to purchase electricity supply from an alternative energy company and a fixed price option. RG&E's exposure to fluctuations in the market price of electricity will be limited to the load required to serve those customers who select the fixed rate option, which combines delivery and supply service at a bundled price.

NYSEG and RG&E use natural gas futures and forwards to manage fluctuations in natural gas commodity prices and provide price stability to customers. The cost or benefit of natural gas futures and forwards is included in the commodity cost when the related sales commitments are fulfilled. NYSEG and RG&E are allowed to pass all actual natural gas commodity costs through to customers.

Item 4.  Controls and Procedures

The principal executive officers and principal financial officers of Energy East, CMP, NYSEG and RG&E evaluated the effectiveness of their respective company's disclosure controls and procedures as of the end of the period covered by this report. "Disclosure controls and procedures" are controls and other procedures of a company that are designed to ensure that information required to be disclosed by the company in the reports that it files or submits under the Securities Exchange Act of 1934, within the time periods specified in the Securities and Exchange Commission's rules and forms, is recorded, processed, summarized and reported, and is accumulated and communicated to the company's management, including its principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. Based on their evaluation, they concluded that their respective company's disclosure controls and procedures are effective.

Energy East, CMP, NYSEG and RG&E each maintain a system of internal control over financial reporting designed to provide reasonable assurance to its management and board of directors regarding the preparation of reliable published financial statements and the safeguarding of assets against loss or unauthorized use. Each company's system of internal control over financial reporting contains self-monitoring mechanisms and actions are taken to correct deficiencies as they are identified. There were no changes in the companies' internal control over financial reporting that occurred during each company's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the respective company's internal control over financial reporting. On January 1, 2004, Energy East commenced using a new accounting system to record and report financial transactions. The system change was undertaken to standardize accounting systems and to consolidate the accounting functions for Energ y East's principal operating companies, including CMP, NYSEG and RG&E.

 

PART II - OTHER INFORMATION

Item 2.  Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

(a) Changes in Rights of Holders of Energy East Common Stock

On June 18, 2004, the stockholders of the company approved amendments to the Certificate of Incorporation to eliminate the classification of the Board of Directors and to eliminate cumulative voting in the election of directors. On June 21, 2004, the company filed an Amendment to the Certificate of Incorporation to reflect the changes. All directors will be elected annually beginning at the 2005 Annual Meeting.

 

(e) Issuer Purchases of Equity Securities

Energy East Corporation







Period




(a)
Total number
of shares
purchased





(b)
Average price
paid per share

(c)
Total number
of shares
purchased as
part of publicly
announced plans
or programs

(d)
Maximum
number of shares
that may yet be
purchased under
the plans or
programs

Month #1
  (April 1, 2004 to   April 30, 2004)



4,034(1)



$24.30



- -



- -

Month #2
  (May 1, 2004 to   May 31, 2004)



6,503(1)



$22.60



- -



- -

Month #3
  (June 1, 2004 to   June 30, 2004)



9,721(2)



$23.54



- -



- -

  Total

20,258   

$23.39

-

-

(1) Represents shares of the company's common stock (Par Value $.01) purchased in open-market transactions on behalf of the company's Employees' Stock Purchase Plan.
(2) Includes 4,549 shares of the company's common stock (Par Value $.01) purchased in open-market transactions on behalf of the company's Employees' Stock Purchase Plan; and 5,172 shares of the company's common stock (Par Value $.01) that were awarded through the company's Restricted Stock Plan and upon vesting of shares of restricted stock were withheld to satisfy tax withholding obligations.

Rochester Gas and Electric Corporation







Period




(a)
Total number
of shares
purchased





(b)
Average price
paid per share

(c)
Total number
of shares
purchased as
part of publicly
announced plans
or programs

(d)
Maximum
number of shares
that may yet be
purchased under
the plans or
programs

Month #1
  (April 1, 2004 to   April 30, 2004)


None


   

Month #2
  (May 1, 2004 to   May 31, 2004)



470,000 (1)



$102.31



- -



- -

Month #3
  (June 1, 2004 to   June 30, 2004)


None


   

  Total

470,000    

$102.31

-

-

(1) These share purchases were a redemption of all of RG&E's remaining preferred stock, all Par Value $100. (See Energy East's Part I, Item 2(a) - RG&E Financing Activities.)

CMP and NYSEG had no issuer purchases of equity securities during the quarter ended June 30, 2004.

 

Item 4.  Submission of Matters to a Vote of Security Holders

Energy East Corporation

Energy East's Annual Meeting of Stockholders was held on June 18, 2004. The following matters were voted on:

(a)  The election of four directors:

Nominees

Votes For

Votes Withheld

Richard Aurelio

126,363,429

4,134,624

James A. Carrigg

126,050,963

4,447,090

David M. Jagger

125,642,840

4,855,213

Ben E. Lynch

125,253,822

5,244,231

(b)  Approval of an amendment to the Certificate of Incorporation to eliminate the classification of the Board of Directors:

Shares For:

123,959,588

Shares Against:

4,664,053

Shares Abstain:

1,874,412

(c)  Approval of an amendment to the Certificate of Incorporation to eliminate cumulative voting in the election of directors:

Shares For:

80,144,510

Shares Against:

26,967,131

Shares Abstain:

1,881,723

Broker Nonvoted:

21,504,689

(d) Approval of an existing employee stock purchase plan:

Shares For:

103,745,975

Shares Against:

3,712,018

Shares Abstain:

1,535,371

Broker Nonvoted:

21,504,689

(e) Ratification of the appointment of PricewaterhouseCoopers LLP as independent public accountants:

Shares For:

126,296,571

Shares Against:

3,107,602

Shares Abstain:

1,093,880

 

Central Maine Power Company

CMP's Annual Meeting of Stockholders was held on June 18, 2004. The election of three directors was voted on:

Nominees

Votes For

Votes Withheld

Sara J. Burns

3,121,680   

-

Kenneth M. Jasinski

3,121,680   

-

Wesley W. von Schack

3,121,680   

-

New York State Electric & Gas Corporation

On June 18, 2004, RGS Energy Group, Inc., a wholly-owned subsidiary of Energy East Corporation and the owner of all of the outstanding shares of NYSEG's common stock, by written consent in lieu of the annual meeting of stockholders, elected Kenneth M. Jasinski, James P. Laurito, Wesley W. von Schack and Denis Wickham directors of NYSEG. Mr. Wickham retired on July 1, 2004, in accordance with his previously announced plans.

Rochester Gas and Electric Corporation

On June 18, 2004, RGS Energy Group, Inc., a wholly-owned subsidiary of Energy East Corporation and the owner of all of the outstanding shares of RG&E's common stock, by written consent in lieu of the annual meeting of stockholders, elected Kenneth M. Jasinski, James P. Laurito, Wesley W. von Schack and Denis Wickham directors of RG&E. Mr. Wickham retired on July 1, 2004, in accordance with his previously announced plans.

Item 6.  Exhibits and Reports on Form 8-K

(a)  Exhibits - See Exhibit Index.

(b)  The following reports on Form 8-K were filed or furnished during the quarter:

Energy East filed four reports on Form 8-K. One report, dated May 7, 2004, was furnished to report certain information under Item 7, "Financial Statements and Exhibits," Item 9, "Regulation FD Disclosure," and Item 12, " Results of Operation and Financial Condition," Two other reports, dated May 19, 2004, and May 24, 2004, were filed to report certain information under Item 5, "Other Events," and Item 7, "Financial Statements and Exhibits." Another report, dated June 10, 2004, was filed to report certain information under Item 5, "Other Events."

RG&E filed three reports on Form 8-K. Two reports, dated May 19, 2004, and May 24, 2004, were filed to report certain information under Item 5, "Other Events," and Item 7, "Financial Statements and Exhibits." Another report, dated June 10, 2004, was filed to report certain information under Item 5, "Other Events."

 

Signatures

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.




Date:  August 5, 2004

ENERGY EAST CORPORATION
                  (Registrant)

By   /s/Robert E. Rude                                             
           Robert E. Rude
           Vice President and Controller
           (Principal Accounting Officer)





Date:  August 5, 2004

CENTRAL MAINE POWER COMPANY
                  (Registrant)

By   /s/Robert S. Mahoney                                       
           Robert S. Mahoney
           Vice President - Controller
            & Treasurer, Clerk
           (Principal Financial Officer)





Date:  August 5, 2004

NEW YORK STATE ELECTRIC & GAS CORPORATION
                  (Registrant)

By   /s/Joseph J. Syta                                              
           Joseph J. Syta
           Vice President - Controller & Treasurer
           (Principal Financial Officer)





Date:  August 5, 2004

ROCHESTER GAS AND ELECTRIC CORPORATION
                  (Registrant)

By   /s/Joseph J. Syta                                              
           Joseph J. Syta
           Vice President - Controller & Treasurer
           (Principal Financial Officer)

 

EXHIBIT INDEX

(a) (1) The following exhibits are delivered with this report:

Registrant

Exhibit No.

Description of Exhibit

Energy East Corporation

3-5 - 

Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on June 21, 2004.

 

(A)10-21 - 

Amended and Restated Employment Agreement dated as of July 1, 2004, by an among the Company, Energy East Management Corporation and W. W. von Schack.

 

(A)10-22 - 

Supplemental Executive Retirement Plan Amendment No. 2.

 

31-1 - 

Certification under Section 302 of the Sarbanes-Oxley Act of 2002.

 

31-2 - 

Certification under Section 302 of the Sarbanes-Oxley Act of 2002.

 

32* - 

Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.

Central Maine Power

31-1 - 

Certification under Section 302 of the Sarbanes-Oxley Act of 2002.

 Company

31-2 - 

Certification under Section 302 of the Sarbanes-Oxley Act of 2002.

 

32* - 

Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.

New York State Electric

31-1 - 

Certification under Section 302 of the Sarbanes-Oxley Act of 2002.

 & Gas Corporation

31-2 - 

Certification under Section 302 of the Sarbanes-Oxley Act of 2002.

 

32* - 

Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.

Rochester Gas and

31-1 - 

Certification under Section 302 of the Sarbanes-Oxley Act of 2002.

 Electric Corporation

31-2 - 

Certification under Section 302 of the Sarbanes-Oxley Act of 2002.

 

32* - 

Certifications under Section 906 of the Sarbanes-Oxley Act of 2002.

*Furnished pursuant to Regulation S-K Item 601(b)(32).

(a) (2) The following exhibits are incorporated herein by reference:

Registrant

Exhibit No.

Filed in

As Exhibit No.

Energy East Corporation

3-1 - 

Restated Certificate of Incorporation of the Company pursuant to Section 807 of the Business Corporation Law filed in the Office of the Secretary of State of the State of New York on April 23, 1998 - Post-effective Amendment No.1 to Registration No. 033-54155





4-1

 

3-2 - 

Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on April 26, 1999 - Company's 10-Q for the quarter ended March 31, 1999 - File No. 1-14766





3-3

Central Maine Power
Company

(A)10-27 - 

Energy East Corporation's Supplemental Executive Retirement Plan Amendment No. 2 - Energy East Corporation's 10-Q for the quarter ended June 30, 2004 - File No. 1-14766




10-22

New York State Electric
& Gas Corporation

(A)10-34 - 

Energy East Corporation's Supplemental Executive Retirement Plan Amendment No. 2 - Energy East Corporation's 10-Q for the quarter ended June 30, 2004 - File No. 1-14766




10-22

 

 

Registrant

Exhibit No.

Filed in

As Exhibit No.

Rochester Gas and
Electric Corporation

(A)10-27 - 

Energy East Corporation's Supplemental Executive Retirement Plan - Energy East Corporation's 10-Q for the quarter ended September 30, 2001 - File No. 1-14766




10-33

 

(A)10-28 - 

Energy East Corporation's Supplemental Executive Retirement Plan Amendment No. 1 - Energy East Corporation's 10-K for the year ended December 31, 2001 - File No. 1-14766




10-5

 

(A)10-29 - 

Energy East Corporation's Supplemental Executive Retirement Plan Amendment No. 2 - Energy East Corporation's 10-Q for the quarter ended June 30, 2004 - File No. 1-14766




10-22

_________________________________
(A) Management contract or compensatory plan or arrangement.

Energy East agrees to furnish to the Commission, upon request, a copy of (i) the Five-Year Revolving Credit Agreement among Energy East, certain lenders, Wachovia Bank, National Association, as Administrative Agent, JP Morgan Chase Bank, as Syndication Agent and Citibank, N.A., KeyBank N.A. and UBS Loan Finance, LLC, as Co-Documentation Agents, dated as of July 21, 2004; and (ii) the Revolving Credit Agreement among NYSEG, RG&E, certain lenders, JP Morgan Chase Bank, as Administrative Agent, Wachovia Bank, National Association, as Syndication Agent and Citibank, N.A., KeyBank N.A. and UBS Loan Finance, LLC, as Co-Documentation Agents, dated as of July 21, 2004 (the "Joint Revolving Credit Agreement"). The total amount of securities under each such document does not exceed 10% of the total assets of Energy East.

NYSEG agrees to furnish to the Commission, upon request, a copy of the Joint Revolving Credit Agreement. The total amount of securities issuable by NYSEG under the Joint Revolving Credit Agreement does not exceed 10% of the total assets of NYSEG.

RG&E agrees to furnish to the Commission, upon request, a copy of the Joint Revolving Credit Agreement. The total amount of securities issuable by RG&E under the Joint Revolving Credit Agreement does not exceed 10% of the total assets of RG&E.