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 March 31, 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 | Exact name of Registrant as specified in its charter, | IRS Employer |
1-14766 | Energy East Corporation | 14-1798693 |
1-5139 | Central Maine Power Company | 01-0042740 |
1-3103-2 | New York State Electric & Gas Corporation | 15-0398550 |
1-672 | Rochester Gas and Electric Corporation | 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 April 30, 2004, shares of common stock outstanding for each registrant were:
Registrant | Description | Shares |
Energy East Corporation | Par value $.01 per share | 146,484,753 |
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 byEnergy East Corporation, Central Maine Power Company, New York State Electric & Gas Corporation andRochester 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.
| TABLE OF CONTENTS - continued |
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1 | Notes to Condensed Financial Statements | 38 |
3 | 46 | |
4 | 47 | |
PART II - OTHER INFORMATION | ||
2 | Changes in Securities, Use and Proceeds and Issuer Purchases |
|
6 | Exhibits and Reports on Form 8-K |
|
50 | ||
51 | ||
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Energy East Corporation | ||
Three months ended March 31 | 2004 | 2003 |
(Thousands, except per share amounts) | ||
Operating Revenues | ||
Sales and services | $1,586,091 | $1,508,295 |
Operating Expenses | ||
Electricity purchased and fuel used in generation | 396,654 | 358,368 |
Natural gas purchased | 499,849 | 451,051 |
Other operating expenses | 218,408 | 199,701 |
Maintenance | 43,212 | 46,204 |
Depreciation and amortization | 85,498 | 75,759 |
Other taxes | 75,446 | 85,290 |
Total Operating Expenses | 1,319,067 | 1,216,373 |
Operating Income | 267,024 | 291,922 |
Other (Income) | (5,639) | (4,652) |
Other Deductions | 3,145 | 1,878 |
Interest Charges, Net | 69,990 | 67,736 |
Preferred Stock Dividends of Subsidiaries | 988 | 8,419 |
Income From Continuing Operations |
|
|
Income Taxes | 77,988 | 88,032 |
Income From Continuing Operations | 120,552 | 130,509 |
Discontinued Operations |
|
|
Income From Discontinued Operations | - | 4,955 |
Net Income | $120,552 | $135,464 |
Earnings Per Share From Continuing |
|
|
Earnings Per Share From Continuing |
|
|
Earnings Per Share From Discontinued |
|
|
Total Earnings Per Share, basic | $.83 | $.93 |
Total Earnings Per Share, diluted | $.82 | $.93 |
Dividends Paid Per Share | $.26 | $.25 |
Average Common Shares Outstanding, basic | 146,085 | 145,096 |
Average Common Shares Outstanding, diluted | 146,428 | 145,215 |
Thenotes on pages 38 through 45 are an integral part of the financial statements.
Thenotes on pages 38 through 45 are an integral part of the financial statements.
Energy East Corporation | ||||
March 31, 2004 | Dec. 31, | |||
(Thousands) | ||||
Liabilities | ||||
Current Liabilities | ||||
Current portion of preferred stock of subsidiary subject to |
|
| ||
Current portion of long-term debt | 31,060 | 30,989 | ||
Notes payable | 189,825 | 308,406 | ||
Accounts payable and accrued liabilities | 384,157 | 339,812 | ||
Interest accrued | 69,986 | 48,989 | ||
Taxes accrued | 108,205 | 43,710 | ||
Other | 143,650 | 191,873 | ||
Total Current Liabilities | 928,133 | 965,029 | ||
Regulatory and Other Liabilities | ||||
Regulatory liabilities | ||||
Accrued removal obligation | 745,441 | 731,621 | ||
Deferred income taxes | 184,143 | 181,211 | ||
Gain on sale of generation assets | 120,034 | 129,640 | ||
Pension benefits | 47,109 | 51,970 | ||
Other | 93,716 | 96,509 | ||
Total regulatory liabilities | 1,190,443 | 1,190,951 | ||
Other liabilities | ||||
Deferred income taxes | 851,734 | 853,489 | ||
Nuclear plant obligations | 271,823 | 277,643 | ||
Other postretirement benefits | 442,755 | 408,903 | ||
Asset retirement obligation | 442,871 | 437,076 | ||
Environmental remediation costs | 144,392 | 145,446 | ||
Other | 345,178 | 346,630 | ||
Total other liabilities | 2,498,753 | 2,469,187 | ||
Total Regulatory and Other Liabilities | 3,689,196 | 3,660,138 | ||
Debt owed to subsidiary holding solely parent debentures | 355,670 | 355,670 | ||
Preferred stock of subsidiary subject to mandatory |
|
| ||
Other long-term debt | 3,642,113 | 3,638,426 | ||
Total long-term debt | 4,020,283 | 4,017,846 | ||
Total Liabilities | 8,637,612 | 8,643,013 | ||
Commitments | - | - | ||
Preferred Stock of Subsidiaries |
|
| ||
Common Stock Equity |
|
| ||
Capital in excess of par value | 1,464,408 | 1,458,802 | ||
Retained earnings | 1,209,034 | 1,126,457 | ||
Accumulated other comprehensive income (loss) | (479) | (11,214) | ||
Deferred compensation | (8,529) | (2,820) | ||
Treasury stock, at cost | (640) | (364) | ||
Total Common Stock Equity | 2,665,259 | 2,572,324 | ||
Total Liabilities and Stockholders' Equity | $11,393,913 | $11,306,432 | ||
Thenotes on pages 38 through 45 are an integral part of the financial statements.
Thenotes on pages 38 through 45 are an integral part of the financial statements.
Thenotes on pages 38 through 45 are an integral part of the financial statements.
Thenotes on pages 38 through 45 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. Energy East has long-term rate plans for 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 stranded costs, and provide stable rates for customers and revenue predictability for those five operating companies. Rochester Gas and Electric Corporation (RG&E) has reached agreement with various parties for a similar long-term plan, and expects approval of the plan by the New York State Public Service Commission (NYPSC) in the second quarter of 2004.
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, during 2003 the company reached an agreement to sell its Ginna nuclear generating station (Ginna) and expects to complete the sale by the end of June 2004, subject to approval by several regulatory agencies.
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 primarily for maintaining 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.
(a) Liquidity and Capital Resources
Energy East initiated a corporate restructuring in 2002 designed to improve organizational efficiency and effectiveness. The savings from the initiative are essential for the company to meet the rate reduction or efficiency targets imputed in utility rates by regulators, as well as to
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
meet the expectations of customers and investors. Integration savings are expected to be approximately $100 million annually by 2006. Those savings, which include reductions in operating expenses and capital expenditures, will come from the consolidation of functions such as accounting, finance, information services and supply chain that were completed in 2003, as well as the implementation of other merger-enabled initiatives across the company's six operating utilities.
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.
Electric Delivery Business
The company's electric delivery business consists primarily of its regulated electricity generation, transmission and distribution operations in upstate New York and Maine.
Joint Proposals in RG&E 2003 Electric and Gas Rate Proceeding: In May 2003 RG&E filed a rate case with the NYPSC to recover costs that RG&E has incurred and will continue to incur in providing safe and reliable electric and natural gas service. The filing proposed an annual increase in electric rates of $105 million, or 16.2%, and an annual increase in natural gas rates of $25 million, or 7.6% overall and 19.7% on delivery rates. RG&E submitted various rate revisions based on continued review of its filing, requesting in February 2004 an $80 million annual electric rate increase and a $21 million annual natural gas rate increase. The filing cited inadequate rate relief from the NYPSC's Order issued March 7, 2003 (see RG&E 2002 Electric and Gas Rate Proceeding), increased costs (see RG&E Cost Deferral Petitions) and the need for a fair and reasonable return on equity (ROE) of 11.25%.
In December 2003 Chairman Flynn of the NYPSC issued a one-Commissioner order transferring the ratemaking treatment for the sale of Ginna from RG&E's pending Section 70 filing (see Sale of Ginna Station and Relicensing) to the pending electric rate proceeding.
Staff of the NYPSC (NYPSC Staff) filed their litigation case under this proceeding on December 31, 2003, proposing to hold electric revenues constant through an electric base rate reduction of $7 million, an acceleration of the amortization of the Nine Mile Point 2 nuclear generating station (NMP2) regulatory asset, and the implementation of a $7 million retail access surcharge. The NYPSC Staff also proposed a natural gas delivery rate reduction of $7 million and the implementation of a $7 million merchant function charge.
On March 9, 2004, RG&E announced that it had reached agreement with various parties, including the NYPSC Staff, on Electric and Natural Gas Joint Proposals (Joint Proposals) that address RG&E electric and natural gas rates through 2008. The Joint Proposals were filed with the NYPSC on March 9, 2004, and the parties are requesting approval by the end of May 2004. The Joint Proposals resolve: the RG&E 2003 Electric and Gas Rate Proceeding; remaining issues related to the RG&E 2002 Electric and Gas Rate Proceeding and RG&E's five-year rate plan ended June 30, 2002; rate treatment concerning the sale of Ginna; recovery of certain deferred costs; and the unbundling of electric rates.
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
Key features of the Electric Joint Proposal include:
- Freezing electric delivery rates through December 2008, except for the implementation of a retail access surcharge effective May 1, 2004, that is expected to recover $7 million annually.
- Allowing RG&E to recover its actual electricity supply costs beginning in May 2004.
- Refunding to customers over the term of the plan $110 million of an estimated $360 million gain from the sale of Ginna, including refunding $60 million shortly after the closing, and refunding the remaining $50 million over the following three years. (See Sale of Ginna Station and Relicensing.)
- Establishing an Asset Sale Gain Account (ASGA) with the net proceeds from the Ginna sale. Portions of the ASGA would be used as follows:
- To cover $6 million of replacement purchased power costs incurred during the 2003 Ginna refueling outage;
- To offset a $2 million annual increase in electric delivery rates;
- To compensate RG&E for maximizing the sale value of Ginna through a credit to RG&E of $3.3 million annually over the term of the settlement; and
- RG&E estimates that at the end of 2008 $121 million will remain in the ASGA, which may be used at the discretion of the NYPSC for rate moderation, among other things.
- Establishing an earnings sharing mechanism to allow customers and stockholders to share equally in earnings over 12.25%.
- Creating and expanding initiatives to enable energy services companies (ESCOs) in RG&E's service territory to attract new customers. RG&E would be allowed to increase its earning sharing threshold to 12.50% by meeting standards designed to measure improvements in its retail access program, including assisting customer migration.
- Ensuring that RG&E continues to maintain the high quality of service and reliability that it currently provides by specifying service quality and reliability standards and capital investment objectives.
Key features of the Natural Gas Joint Proposal include:
- Freezing natural gas delivery rates through December 2008, except for the implementation of a merchant function charge that is expected to recover $7 million annually beginning May 1, 2004.
- Implementing a weather normalization adjustment to protect both customers and RG&E from certain costs that fluctuate due to swings in temperature outside a normal range.
- Implementing gas cost incentive mechanisms to provide a means of sharing with customers future gas supply cost savings achieved by RG&E.
- Establishing provisions similar to those in the Electric Joint Proposal regarding earnings sharing and service quality and reliability. The level for earnings sharing is 12.00%, with the opportunity to increase to 12.25% if certain customer migration targets are achieved.
RG&E 2002 Electric and Gas Rate Proceeding: In February 2002 RG&E filed a request with the NYPSC for new electric and natural gas rates to go into effect on January 15, 2003. The single year filing, as updated, supported a $40 million increase in annual electric rates and a $19 million increase in annual natural gas rates.
In March 2003 the NYPSC issued an order (Order) in the proceeding authorizing a $16 million electric revenue requirement reduction and limiting the natural gas rate increase to $6 million. The NYPSC also credited to customers $55 million of electric earnings that, according to the
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
NYPSC, exceeded a preset level under the five-year rate plan that expired on June 30, 2002, subject to a final audit of the fifth year amount. The NYPSC also ignored the costs of replacement power that were incurred during the required Ginna refueling outage in the fall of 2003.
RG&E was disappointed with the Order because it ignored the record that was developed in the proceeding, reversed many of the recommendations of the ALJ without adequate explanation and did not provide adequate revenue for RG&E to earn its authorized rate of return. In May 2003 RG&E began a proceeding to appeal the most objectionable errors in the Order. RG&E has agreed to withdraw its appeal in the event that the Joint Proposals are approved.
RG&E Cost Deferral Petitions: In April 2003 RG&E filed a letter with the NYPSC requesting the deferral of costs, including interest, for restoration work resulting from a severe ice storm in April 2003 and replacement purchased power costs incurred in 2003 in connection with a scheduled refueling outage for Ginna. The deferred costs are $36 million for repairs required due to the ice storm and $15 million for the Ginna replacement purchased power. Recovery of those costs is provided for in the Electric Joint Proposal.
In May 2003 RG&E filed a letter with the NYPSC seeking deferral and true up of an estimated $9 million of pension costs in accordance with the NYPSC's Statement of Policy Concerning the Accounting and Ratemaking Treatment for Pensions and Post Retirement Benefits Other than Pensions. The request covers the 16-month period from January 1, 2003, through May 1, 2004. The Joint Proposals provide for recovery of incremental pension costs for the period July 1, 2003, to December 31, 2003, estimated at $2 million, and will reconcile pension costs according to the NYPSC's pension policy statement, beginning January 1, 2004.
Sale of Ginna Station and Relicensing: In November 2003 RG&E announced an agreement to sell Ginna to Constellation Generation Group LLC (CGG). In December 2003 RG&E and CGG jointly filed a revised Section 70 petition with the NYPSC that includes, among other things, all the transaction documents and details of the auction process. The Electric Joint Proposal includes the accounting and ratemaking treatment for the sale and an incentive payment to RG&E of $3.3 million annually over the term of the plan for maximizing the proceeds from the sale of Ginna.
The sale of Ginna is subject to approvals by several regulatory agencies, including the NYPSC, the Nuclear Regulatory Commission (NRC) and the Federal Energy Regulatory Commission (FERC). The outcome of these proceedings cannot be determined at this time. The sale is also conditioned on receiving reasonably satisfactory accounting and ratemaking treatment from the NYPSC. Assuming the Joint Proposals are approved, RG&E expects to complete the sale of Ginna by the end of June 2004.
Upon closing of the proposed Ginna sale, RG&E will transfer approximately $202 million of decommissioning funds to CGG, which will take responsibility for all future decommissioning funding. The amount is expected to fully meet the NRC's decommissioning funding requirements for Ginna. RG&E projects that it will retain $59 million in excess decommissioning funds, to be credited to customers as part of the ASGA. The sale agreement includes a 10-year purchase power agreement so that RG&E's customers will continue to receive the benefit of power from Ginna.
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
Ginna's operating license expires in 2009. In July 2002 RG&E filed a license renewal application with the NRC, which, if approved, would extend the license to September 19, 2029. The NRC has deemed the application complete. The NRC held two sets of public meetings in 2002 and two in 2003. In April 2004 the Advisory Committee on Reactor Safeguards met and recommended approval of the renewal of the operating license for an additional 20 years beyond its current license term. A final decision on this matter is expected by the end of June 2004. As part of the Electric Joint Proposal, depreciation rates and decommissioning costs for Ginna were revised to reflect the new expected license life.
RG&E Electric Rate Unbundling: In June 2003, as required by the 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 Joint Proposal provides for that unbundling and for the commodity options. Beginning January 1, 2005, customers would 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.
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. In March 2004 CMP submitted its annual ARP filing proposing a decrease of 0.5% on the distribution portion of rates, which is the result of inflation being less than the productivity offset for 2004 and adjustments to prior years' inflation estimates.
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 vision for New York and should maintain flexibility by addressing each utility in the context of that utility's unique circumstances.
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
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 accepted the six-state RTO filing submitted by ISO New England and the New England transmission owners, subject to certain conditions. The 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, 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. The transmission owners had requested a midpoint ROE of 12.8%. To provide parties an opportunity to resolve matters, the FERC instituted settlement procedures covering all matters set for hearing. CMP is considering the FERC's order and is working with the other New England transmission owners and ISO New England to evaluate the FERC order and develop appropriate responses.
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 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 plans at a level reflecting CMP's cost-sharing philosophy for all 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 coverage according to a predetermined schedule.
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.
Joint Proposals in RG&E 2003 Electric and Gas Rate Proceeding: See Electric Delivery Business.
RG&E 2002 Electric and Gas Rate Proceeding: 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 Connecticut Department of Public Utility Control (DPUC) to recover exogenous costs of approximately $21 million under its approved Incentive Rate Plan (IRP). The recovery of exogenous costs is for qualified pension and other postretirement benefits expense, taxes, uncollectible expense and the Customer Hardship Arrearage Forgiveness Program. Those
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
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 has established a docket for this proceeding
and initial interrogatories have been issued. Hearings were held in April 2004. SCG cannot predict the outcome of this proceeding at this time.
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, at December 31, 2002, CNG recognized a liability of $1 million for those costs. In May 2003 the DPUC issued its final decision in the matter, modifying the draft decision and removing the disallowance. The DPUC also notified CNG concerning transactions reviewed in an August 2003 semiannual review, for which a final decision is due in mid-2004. The DPUC issued a draft decision in April 2004 that would allow CNG to collect the $1 million. CNG is retaining its $1 million reserve contingency to cover the period November 1, 2001, through October 31, 2003, pending final approval of the draft decision. CNG cannot predict the final outcome of this proceeding.
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 $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 procee d. CNG and SCG are diligently working toward settlement of the issues, but cannot predict the final outcome of these proceedings.
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 5 to the Condensed Financial Statements.)
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
Investing and Financing Activities
Investing Activities: Capital spending for the first three months of 2004 was $57 million, including nuclear fuel. Capital spending is projected to be $345 million for 2004, including nuclear fuel, and is expected to be paid for 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: 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.
During the three months ended March 31, 2004, the company issued 212,736 shares of common stock, at an average price of $23.59 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 February 2004 the company awarded 240,138 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 of $23.89 per share of common stock on the date of the award.
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 its remaining preferred stock, including: $12 million of 4% Series F, $8 million of 4.10% Series H, $6 million of 4 3/4% Series I, $5 million of 4.10% Series J, $6 million of 4.95% Series K and $10 million of 4.55% Series M, all redeemed at a premium; and $23.75 million of 6.60% Series V, redeemed at par. 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 short-term credit facilities.
Management's discussion and analysis of financial condition and results of operations
Energy East Corporation
Three months ended March 31 | 2004 | 2003 | Change |
(Thousands, except per share amounts) | |||
Operating Revenues | $1,586,091 | $1,508,295 | 5% |
Operating Income | $267,024 | $291,922 | (9%) |
Income from Continuing Operations | $120,552 | $130,509 | (8%) |
Net Income | $120,552 | $135,464 | (11%) |
Average Common Shares Outstanding, basic | 146,085 | 145,096 | 1% |
Earnings Per Share from Continuing Operations, basic | $.83 | $.90 | (8%) |
Earnings Per Share, basic | $.83 | $.93 | (11%) |
Dividends Paid Per Share | $.26 | $.25 | 4% |
Earnings of 83 cents per share for the quarter ended March 31, 2004, were 7 cents lower than earnings from continuing operations of 90 cents per share for the quarter ended March 31, 2003. Earnings decreased primarily because of an increase in the market value of Energy East's common stock during the first quarter this year (as compared to a decline in the first quarter of 2003), which resulted in higher stock-based compensation of 10 cents per share. The company's stock price increased from $22.40 per share to $25.36 per share in the first quarter of 2004, resulting in an expense of $12 million. The stock price decreased from $22.09 per share to $17.80 per share in the first quarter of 2003, resulting in a benefit of $11 million.
The operating companies experienced a modest decrease in deliveries as natural gas retail deliveries declined 1.8% and electric retail deliveries declined 0.5% for the quarter, primarily because of warmer winter weather in 2004 as compared to 2003. This reduced earnings 6 cents per share. That reduction was offset by integration savings and other cost reductions of 7 cents per share.
Operating Results for the Electric Delivery Business
Three months ended March 31 | 2004 | 2003 | Change |
(Thousands) | |||
Retail Deliveries - Megawatt-hours | 8,051 | 8,090 | - |
Operating Revenues | $730,595 | $758,713 | (4%) |
Operating Expenses | $587,811 | $602,908 | (3%) |
Operating Income | $142,784 | $155,805 | (8%) |
Operating revenues for the first quarter of 2004 decreased $28 million. The primary factors were rate reductions for CMP of approximately $18 million to reflect lower operating costs and amortization, and $8 million due to a change in market structure for RG&E that allows ESCOs to provide electricity. The results of this change were lower retail revenues offset by higher wholesale revenues and lower fuel costs. The net revenue reduction for the quarter was $8 million.
Operating expenses decreased $15 million primarily due to a $16 million reduction in purchased power costs. The $16 million reduction was the result of a $9 million adjustment for amounts owed to the New York Independent System Operator and lower load requirements at RG&E as a result of the change in market structure.
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 March 31 | 2004 | 2003 | Change |
(Thousands | |||
Retail Deliveries - Dekatherms | 87,597 | 89,216 | (2%) |
Operating Revenues | $681,724 | $640,112 | 7% |
Operating Expenses | $556,706 | $507,537 | 10% |
Operating Income | $125,018 | $132,575 | (6%) |
Operating revenues increased $42 million for the first quarter of 2004. The increase resulted from higher gas costs, which are passed on to customers.
Operating expenses increased $49 million compared to the prior year quarter. The primary cause was an increase in natural gas purchases of $37 million. Operations and maintenance costs also increased by $10 million compared to the prior year quarter.
Item 1. Financial Statements
Thenotes on pages 38 through 45 are an integral part of the financial statements.
Central Maine Power Company | ||
March 31, 2004 | Dec. 31, | |
(Thousands) | ||
Liabilities | ||
Current Liabilities | ||
Current portion of long-term debt | $3,000 | $2,999 |
Notes payable | 18,000 | 15,000 |
Accounts payable and accrued liabilities | 59,852 | 45,815 |
Interest accrued | 2,124 | 5,397 |
Taxes accrued | 7,355 | 1,206 |
Other | 30,342 | 48,322 |
Total Current Liabilities | 120,673 | 118,739 |
Regulatory and Other Liabilities | ||
Regulatory liabilities | ||
Accrued removal obligation | 82,335 | 80,128 |
Deferred income taxes | 78,367 | 77,849 |
Gain on sale of generation assets | 67,948 | 76,998 |
Other | 19,034 | 17,127 |
Total regulatory liabilities | 247,684 | 252,102 |
Other liabilities | ||
Deferred income taxes | 69,915 | 65,555 |
Nuclear plant obligations | 167,434 | 173,548 |
Other postretirement benefits | 74,373 | 73,181 |
Environmental remediation costs | 2,958 | 3,017 |
Other | 112,099 | 113,880 |
Total other liabilities | 426,779 | 429,181 |
Total Regulatory and Other Liabilities | 674,463 | 681,283 |
Long-term debt | 313,781 | 314,511 |
Total Liabilities | 1,108,917 | 1,114,533 |
Commitments | - | - |
Preferred Stock |
|
|
Capital in excess of par value | (2,582) | (2,582) |
Common Stock Equity |
|
|
Capital in excess of par value | 485,316 | 485,376 |
Retained earnings | 30,539 | 35,072 |
Accumulated other comprehensive (loss) | (17,174) | (17,174) |
Total Common Stock Equity | 654,738 | 659,331 |
Total Liabilities and Stockholder's Equity | $1,796,644 | $1,806,853 |
Thenotes on pages 38 through 45 are an integral part of the financial statements.
Thenotes on pages 38 through 45 are an integral part of the financial statements.
Thenotes on pages 38 through 45 are an integral part of the financial statements.
Thenotes on pages 38 through 45 are an integral part of the financial statements.
Thenotes on pages 38 through 45 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.
Other Matters
Accounting Issues
FIN 46R: See Energy East's Item 2(a),Other Matters, for this discussion. (See Note 5 to the Condensed Financial Statements.)
Investing Activities
Capital spending for the first three months of 2004 was $10 million. Capital spending is projected to be $50million for 2004, and is expected to be paid for 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
Three months ended March 31 | 2004 | 2003 | Change |
(Thousands) | |||
Retail Deliveries - Megawatt-hours | 2,335 | 2,264 | 3% |
Operating Revenues | $162,750 | $176,418 | (8%) |
Operating Expenses | $125,588 | $131,672 | (5%) |
Operating Income | $37,162 | $44,746 | (17%) |
Earnings Available for Common Stock | $20,467 | $23,742 | (14%) |
Earnings for the quarter decreased approximately $3 million, primarily as a result of lower operating revenues.
The $14 million reduction in operating revenues for the quarter was due primarily to an $18 million decrease because of rate reductions that were substantially allocated to winter months, partially offset by an increase of $4 million for higher deliveries resulting from economic growth.
The $6 million decrease in operating expenses for the quarter was primarily the result of lower amortization of ice storm, demand-side management costs of $4 million and decreases in depreciation and other taxes.
Item 1. Financial Statements
Thenotes on pages 38 through 45 are an integral part of the financial statements.
Thenotes on pages 38 through 45 are an integral part of the financial statements.
New York State Electric & Gas Corporation | ||
March 31, 2004 | Dec. 31, | |
(Thousands) | ||
Liabilities | ||
Current Liabilities | ||
Current portion of long-term debt | $710 | $710 |
Notes payable | - | 41,400 |
Accounts payable and accrued liabilities | 162,046 | 148,918 |
Interest accrued | 18,688 | 10,068 |
Taxes accrued | 40,266 | 15,367 |
Other | 19,328 | 74,819 |
Total Current Liabilities | 241,038 | 291,282 |
Regulatory and Other Liabilities | ||
Regulatory liabilities | ||
Gain on sale of generation assets | 52,085 | 52,642 |
Accrued removal obligation | 309,349 | 304,065 |
Other | 21,547 | 21,571 |
Total regulatory liabilities | 382,981 | 378,278 |
Other liabilities | ||
Deferred income taxes | 520,378 | 522,919 |
Other postretirement benefits | 216,155 | 208,393 |
Asset retirement obligation | 382 | 377 |
Environmental remediation costs | 97,400 | 97,400 |
Other | 57,103 | 50,840 |
Total other liabilities | 891,418 | 879,929 |
Total Regulatory and Other Liabilities | 1,274,399 | 1,258,207 |
Long-term debt | 1,065,710 | 1,065,590 |
Total Liabilities | 2,581,147 | 2,615,079 |
Commitments | - | - �� |
Preferred Stock |
|
|
Common Stock Equity |
|
|
Capital in excess of par value | 277,495 | 277,462 |
Retained earnings | 231,866 | 229,048 |
Accumulated other comprehensive income | 36,642 | 25,760 |
Total Common Stock Equity | 976,060 | 962,327 |
Total Liabilities and Stockholder's Equity | $3,567,366 | $3,587,565 |
Thenotes on pages 38 through 45 are an integral part of the financial statements.
Thenotes on pages 38 through 45 are an integral part of the financial statements.
Thenotes on pages 38 through 45 are an integral part of the financial statements.
Thenotes on pages 38 through 45 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.
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 5 to the Condensed Financial Statements.)
Investing Activities
Capital spending for the first three months of 2004 was $22 million. Capital spending is projected to be $113 million for 2004 and is expected to be paid for 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.
Management's discussion and analysis of financial condition and results of operations
New York State Electric & Gas Corporation
Three months ended March 31 | 2004 | 2003 | Change |
(Thousands) | |||
Operating Revenues | $592,214 | $575,732 | 3% |
Operating Income | $101,223 | $120,648 | (16%) |
Earnings Available for Common Stock | $52,818 | $60,518 | (13%) |
First quarter 2004 earnings decreased $8 million as compared to the prior year quarter primarily due to lower deliveries because of warmer winter weather in 2004.
Operating Results for the Electric Delivery Business
Three months ended March 31 | 2004 | 2003 | Change |
(Thousands) | |||
Retail Deliveries - Megawatt-hours | 3,976 | 4,046 | (2%) |
Operating Revenues | $403,984 | $405,968 | - |
Operating Expenses | $333,345 | $324,742 | 3% |
Operating Income | $70,639 | $81,226 | (13%) |
The $2 million decrease in operating revenues for the quarter was primarily due to lower deliveries because of warmer winter weather in 2004.
Operating expenses increased $9 million for the quarter primarily due to increased purchased power costs of $10 million.
Operating Results for the Natural Gas Delivery Business
Three months ended March 31 | 2004 | 2003 | Change |
(Thousands) | |||
Retail Deliveries - Dekatherms | 25,344 | 26,509 | (4%) |
Operating Revenues | $188,230 | $169,764 | 11% |
Operating Expenses | $157,646 | $130,342 | 21% |
Operating Income | $30,584 | $39,422 | (22%) |
Operating revenues increased $18 million for the quarter primarily as a result of higher market prices of $37 million for natural gas purchased that were passed on to customers. To offset this increase, operating revenues decreased $7 million due to lower deliveries because of warmer winter weather in 2004 and $10 million for lower wholesale sales.
Operating expenses for the quarter increased $27 million compared to the prior year quarter, primarily due to an increase in natural gas purchased as a result of higher market prices of $39 million, partially offset by lower purchases of $14 million due to lower wholesale and lower retail deliveries because of warmer weather in 2004.
Item 1. Financial Statements
Thenotes on pages 38 through 45 are an integral part of the financial statements.
Rochester Gas and Electric Corporation | ||
March 31, 2004 | Dec. 31, | |
(Thousands) | ||
Liabilities | ||
Current Liabilities | ||
Current portion of preferred stock subject to mandatory |
|
|
Accounts payable and accrued liabilities | 56,101 | 70,560 |
Affiliate payable | 7,743 | 6,916 |
Interest accrued | 13,626 | 11,540 |
Taxes accrued | 43,283 | 24,130 |
Other | 28,453 | 29,642 |
Total Current Liabilities | 150,456 | 144,038 |
Regulatory and Other Liabilities | ||
Regulatory liabilities | ||
Accrued removal obligation | 187,881 | 185,472 |
Deferred income taxes | 175,776 | 186,571 |
Other | 37,069 | 46,173 |
Total regulatory liabilities | 400,726 | 418,216 |
Other liabilities | ||
Deferred income taxes | 79,263 | 72,568 |
Nuclear waste disposal | 104,389 | 104,095 |
Other postretirement benefits | 73,623 | 71,956 |
Environmental remediation costs | 22,356 | 22,356 |
Asset retirement obligation | 441,917 | 436,096 |
Other | 45,029 | 39,831 |
Total other liabilities | 766,577 | 746,902 |
Total Regulatory and Other Liabilities | 1,167,303 | 1,165,118 |
Preferred stock subject to mandatory redemption requirements | 22,500 | 23,750 |
Other long-term debt | 826,537 | 826,511 |
Total long-term debt | 849,037 | 850,261 |
Total Liabilities | 2,166,796 | 2,159,417 |
Commitments | - | - |
Preferred Stock | ||
Redeemable solely at the option of RG&E | 47,000 | 47,000 |
Common Stock Equity | ||
Common stock | 194,429 | 194,429 |
Capital in excess of par value | 556,251 | 556,190 |
Retained earnings | 146,459 | 121,032 |
Treasury stock, at cost | (117,238) | (117,238) |
Total Common Stock Equity | 779,901 | 754,413 |
Total Liabilities and Stockholder's Equity | $2,993,697 | $2,960,830 |
Thenotes on pages 38 through 45 are an integral part of the financial statements.
Thenotes on pages 38 through 45 are an integral part of the financial statements.
Thenotes on pages 38 through 45 are an integral part of the financial statements.
Thenotes on pages 38 through 45 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 nuclear plant, one coal-fired plant, three gas turbines and several smaller hydroelectric stations.
Joint Proposals in RG&E 2003 Electric and Gas Rate Proceeding: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.
RG&E 2002 Electric and Gas Rate Proceeding: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.
RG&E Cost Deferral Petitions: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.
Sale of Ginna Station and Relicensing: 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.
Joint Proposals in RG&E 2003 Electric and Gas Rate Proceeding
: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.RG&E 2002 Electric and Gas Rate Proceeding: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.
Management's discussion and analysis of financial condition and results of operations
Rochester Gas and Electric Corporation
NYPSC Collaborative on End State of Energy Competition: See Energy East's Item 2(a), Electric Delivery Business, for this discussion.
Investing and Financing Activities
Investing Activities: Capital spending for the first three months of 2004 was $16 million, including nuclear fuel. Capital spending is projected to be $123 million for 2004, including nuclear fuel, and is expected to be paid for 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.
Three months ended March 31 | 2004 | 2003 | Change |
(Thousands) | |||
Operating Revenues | $313,346 | $326,694 | (4%) |
Operating Income | $59,852 | $31,081 | 93% |
Earnings Available for Common Stock | $25,427 | $565 | * |
* Change is not meaningful.
Earnings increased $25 million for the quarter primarily due to the recognition of the terms and conditions of the NYPSC rate order for RG&E, which became effective January 15, 2003, and reduced earnings $30 million in the first quarter of 2003. (See RG&E 2002 Electric and Gas Rate Proceeding.) The rate order included $26 million for excess electric earnings and related interest.
Operating Results for the Electric Delivery Business
Three months ended March 31 | 2004 | 2003 | Change |
(Thousands) | |||
Retail Deliveries - Megawatt-hours | 1,740 | 1,781 | (2%) |
Operating Revenues | $164,184 | $176,294 | (7%) |
Operating Expenses | $129,742 | $173,151 | (25%) |
Operating Income | $34,442 | $3,143 | * |
* Change is not meaningful.
The $12 million decrease in operating revenues for the quarter is primarily due to an $8 million net reduction as a result of a change in market structure that allows ESCOs to provide electricity, which reduced retail revenues by $36 million and increased wholesale revenues by $28 million. An additional $3 million decrease in revenues resulted from lower retail deliveries because of warmer winter weather in 2004.
Management's discussion and analysis of financial condition and results of operations
Rochester Gas and Electric Corporation
Operating expenses decreased $43 million for the quarter primarily due to the recognition of terms and conditions of the NYSPC rate order, which became effective January 15, 2003, and increased operating expenses $30 million in 2003. (See RG&E 2002 Electric and Gas Rate Proceeding.) In addition, purchased power costs decreased $16 million as a result of the change in market structure and a $9 million adjustment to amounts owed to the New York Independent System Operator.
Operating Results for the Natural Gas Delivery Business
Three months ended March 31 | 2004 | 2003 | Change |
(Thousands) | |||
Retail Deliveries - Dekatherms | 24,148 | 25,034 | (4%) |
Operating Revenues | $149,162 | $150,400 | (1%) |
Operating Expenses | $123,752 | $122,462 | 1% |
Operating Income | $25,410 | $27,938 | (9%) |
The $1 million decrease in operating revenues for the quarter is primarily due to lower deliveries because of warmer winter weather in 2004, partially offset by higher market prices that were passed on to customers.
Operating expenses increased $1 million for the quarter primarily due to higher market prices for natural gas purchased.
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 |
CMP | 1, 2, 3, 6, 7, 8, 9, 10 |
NYSEG | 1, 2, 3, 6, 7, 8, 9, 10 |
RG&E | 1, 2, 3, 7, 8, 9, 10 |
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 for 2003 have been reclassified in the company's unaudited financial statements to reflect discontinued operations.
Note 2. 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 substantially paid off as of April 15, 2004.
Note 3. Other (Income) and Other Deductions
Three months ended March 31 | 2004 | 2003 |
(Thousands) | ||
Energy East | ||
Interest income | $(406) | $(1,312) |
Noncash returns | - | (255) |
Allowance for funds used during construction | - | (544) |
Gains from the sale of nonutility property | (77) | (147) |
Earnings from equity investments | (1,674) | (1,658) |
Miscellaneous | (3,482) | (646) |
Total other (income) | $(5,639) | $(4,562) |
Miscellaneous | $3,145 | $1,878 |
Total other deductions | $3,145 | $1,878 |
CMP | ||
Interest income | $(37) | $(256) |
Noncash returns | - | (202) |
Earnings from equity investments | (387) | (538) |
Miscellaneous | (535) | 9 |
Total other (income) | $(959) | $(987) |
Miscellaneous | $43 | $379 |
Total other deductions | $43 | $379 |
NYSEG | ||
Interest income | $(61) | $(378) |
Noncash returns | - | (214) |
Miscellaneous | 105 | (1,332) |
Total other (income) | $44 | $(1,924) |
Miscellaneous | $(282) | $256 |
Total other deductions | $(282) | $256 |
RG&E | ||
Interest income | $189 | $(1,710) |
Noncash returns | - | - |
Miscellaneous | (842) | (408) |
Total other (income) | $(653) | $(2,118) |
Miscellaneous | $363 | $148 |
Total other deductions | $363 | $148 |
Note 4. 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 ended March 31 | 2004 | 2003 |
(Thousands) | ||
Basic average common shares outstanding | 146,085 | 145,096 |
Restricted stock awards | 343 | 119 |
Potentially dilutive common shares | 256 | 269 |
Options issued with SARs | (256) | (269) |
Dilutive average common shares | 146,428 | 145,215 |
In February 2004 the company awarded 240,138 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 of $23.89 per share of common stock on the date of the award.
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 March 31 were: 1.8 million in 2004 and 2.6 million in 2003.
Note 5. Discontinued Operations
In keeping with its focus on regulated electric and natural gas delivery businesses, during the past few years the company has been systematically exiting certain noncore businesses. In 2003 Berkshire Propane, Inc., a subsidiary of Berkshire Energy Resources, sold its assets and Energetix sold its Griffith Oil Co., Inc. Both businesses were reported in the company's Other business segment. Certain financial information concerning the two businesses for the first quarter of 2003 is shown in the table below.
Griffith Oil | Berkshire | |
(Thousands) | ||
Revenues | $127,621 | $3,430 |
Income from businesses sold | $7,418 | $534 |
Income taxes | 2,777 | 220 |
Income from discontinued operations | $4,641 | $314 |
Note 6. 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 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 of those NUGs. The company evaluated each of CMP's and NYSEG's power purchase contracts with NUGs in accordance with FIN 46R. Most of the purchase contracts were determined not to be variable interests due to one of the following three reasons: the contract is based on a fixed price or a market price and there is no other involvement with the NUG, the length of the contract is short-term or the contract is for a minor portion of the NUG's capacity. NYSEG determined that it is not required to apply FIN 46R to certain NUGs because the NUG is either a governmental organization or an individual. The companies are not able t o apply FIN 46R to the remaining NUGs because they are unable to obtain the information necessary to determine if the NUG is a variable interest entity, to determine if CMP or NYSEG is the NUG's primary beneficiary or to perform the accounting required to consolidate the NUG. The companies will continue to make efforts to obtain that necessary information. CMP and NYSEG are not consolidating any NUGs as of March 31, 2004.
Note 7. Accounts Receivable
Accounts receivable for the companies include unbilled revenues as follows: Energy East - consolidated unbilled revenues of $176 million at March 31, 2004, and $219 million at December 31, 2003; CMP - consolidated unbilled revenues of $17 million at March 31, 2004, and $25 million at December 31, 2003; NYSEG - unbilled revenues of $62 million at March 31, 2004, and $72 million at December 31, 2003; RG&E - unbilled revenues of $39 million at March 31, 2004, and $50 million at December 31, 2003.
Note 8. Retirement Benefits
Components of net periodic benefit cost
Pension Benefits | Postretirement Benefits | |||
Three months ended March 31 | 2004 | 2003 | 2004 | 2003 |
(Thousands) | ||||
Energy East | ||||
Service cost | $8,248 | $8,002 | $1,843 | $1,842 |
Interest cost | 32,561 | 33,237 | 9,383 | 8,910 |
Expected return on plan assets | (51,318) | (50,778) | (664) | (614) |
Amortization of prior service cost | 1,164 | 1,247 | (1,711) | (1,717) |
Recognized net actuarial (gain) loss | (325) | (2,497) | 2,211 | 1,111 |
Amortization of transition (asset) |
|
|
|
|
Net periodic benefit cost | $(9,978) | $(12,599) | $13,079 | $11,549 |
CMP | ||||
Service cost | $1,101 | $1,099 | $486 | $508 |
Interest cost | 3,462 | 3,358 | 2,043 | 1,981 |
Expected return on plan assets | (3,592) | (3,365) | (255) | (203) |
Amortization of prior service cost | 49 | 48 | (157) | (157) |
Recognized net actuarial loss | 1,143 | 897 | 576 | 508 |
Net periodic benefit cost | $2,163 | $2,037 | $2,693 | $2,637 |
NYSEG | ||||
Service cost | $4,583 | $4,381 | $952 | $839 |
Interest cost | 17,014 | 16,856 | 4,907 | 4,401 |
Expected return on plan assets | (30,940) | (30,102) | - | - |
Amortization of prior service cost | 1,083 | 1,163 | (1,533) | (1,539) |
Recognized net actuarial (gain) loss | (3,386) | (4,284) | 1,419 | 454 |
Amortization of transition (asset) |
|
|
|
|
Net periodic benefit cost | $(11,954) | $(13,796) | $7,762 | $6,172 |
RG&E | ||||
Service cost | $1,506 | $1,571 | $272 | $292 |
Interest cost | 7,467 | 8,086 | 1,525 | 1,562 |
Expected return on plan assets | (12,456) | (12,823) | - | - |
Amortization of prior service cost | 325 | 366 | 294 | 335 |
Recognized net actuarial loss | (1,665) | (2,062) | (22) | (69) |
Amortization of transition (asset) |
|
|
|
|
Net periodic benefit cost | $(4,823) | $(4,862) | $2,614 | $2,741 |
In April of 2004 Energy East contributed $19 million to its retirement benefit plans, including $11 million for CMP.
Note 9. 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.
The carrying amounts of goodwill, by operating segment, were the same at March 31, 2004, and December 31, 2003, and are shown in the table below.
Electric | Natural Gas |
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(Thousands) | ||||
Energy East | $844,531 | $677,119 | $11,473 | $1,533,123 |
The company's unamortized intangible assets had a carrying amount of $10 million at March 31, 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 March 31, 2004, and December 31, 2003, and primarily consisted of investments in pipelines. Accumulated amortization was $13 million at March 31, 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 March 31, 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 March 31, 2004, and December 31, 2003, and primarily consisted of technology rights. Estimated amortization expense for intangible assets is $9 thousand for each of the next five years, 2004 through 2008.
NYSEG's unamortized intangible assets had a carrying amount of $1.4 million at March 31, 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 $1.6 million at March 31, 2004, and $1.5 million at December 31, 2003, and accumulated amortization of $1 million at March 31, 2004, and December 31, 2003, and consisted of hydroelectric licenses. Estimated amortization expense for intangible assets for the next five years is $40 thousand for the year 2004 and 2005, $24 thousand for 2006 and $21 thousand for year 2007 and 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 March 31, 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 10. 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. Other consists of CMP's corporate assets.
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 | Natural Gas |
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(Thousands) | ||||
Three Months Ended | ||||
March 31, 2004 | ||||
Operating Revenues |
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Net Income (Loss) |
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March 31, 2003 | ||||
Operating Revenues |
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Net Income (Loss) |
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Electric | Natural Gas |
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March 31, 2004 |
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December 31, 2003 |
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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. and RGS Energy Group, Inc.; 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 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 April 15, 2004, NYSEG's load was 95% hedged for on-peak periods and 87% hedged for off-peak pe riods in 2004. A fluctuation of $1.00 per megawatt-hour in the price of electricity would change earnings by $0.7 million for May 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.
RG&E currently faces commodity price risk that relates to market fluctuations in the price of electricity. Owned electric generation and long-term supply contracts significantly reduce RG&E's exposure to market fluctuations for procurement of its electric supply. As of April 15, 2004, RG&E's load was fully hedged for both on-peak and off-peak periods for May through December 2004. A fluctuation of $1.00 per megawatt-hour in the price of electricity would change earnings by $0.6 million for May through December 2004. The percentage of RG&E's hedged load is based on RG&E'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 Joint Proposal, if approved, RG&E would be allowed to recover its actual fuel expenses effective May 1, 2004, and earnings risks related to changes in market value of electricity discussed above would be eliminated. Beginning January 1, 2005, in accordance with the Electric Joint Proposal RG&E would offer its 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. RG&E's exposure to fluctuations in the market price of electricity would be 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.
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.
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, except that 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 functio ns for Energy 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
Energy East Corporation | ||||
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| (c) | (d) |
Month #1 |
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Month #2 |
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Month #3 |
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Total | 260,244 | $24.24 | - | - |
The 260,244 shares were purchased in open-market transactions and were purchases of the company's common stock (Par Value $.01).
(1) These 6,212 shares were purchased on behalf of the company's Employees' Stock Purchase Plan.
(2) Includes 4,032 shares purchased on behalf of the company's Employees' Stock Purchase Plan. Substantially all of the remaining 250,000 shares purchased were awarded to employees through the company's Restricted Stock Plan and the balance of the shares were reissued through the company's Investor Services Program. (See the company's Part I, Item 2(a), Investing and Financing Activities - Financing Activities.)
Rochester Gas and Electric Corporation | ||||
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| (c) | (d) |
Month #1 |
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Month #2 |
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Month #3 |
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Total | 12,500 | $100.00 | - | - |
(1) These share purchases were a partial redemption of RG&E's 6.60% Series V preferred stock, Par Value $100, as required by a mandatory sinking fund provision. (See RG&E's Part I, Item 2(a), Investing and Financing Activities - Financing Activities.)
CMP and NYSEG had no issuer purchases of equity securities during the quarter ended March 31, 2004.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits - SeeExhibit Index.
(b) The following reports on Form 8-K were filed or furnished during the quarter:
Energy East filed two reports on Form 8-K, one dated January 20, 2004, and one dated March 9, 2004, were filed to report certain information under Item 5, "Other Events." Another report, dated January 30, 2004, was furnished to report certain information under Item 9, "Regulation FD Disclosure," and Item 12, "Disclosure of Results of Operations and Financial Condition."
RG&E filed two reports on Form 8-K, one dated January 20, 2004, and one dated March 9, 2004, were filed to report certain information under Item 5, "Other Events." Another report, dated January 30, 2004, was furnished to report certain information under Item 9, "Regulation FD Disclosure," and Item 12, "Disclosure of Results of Operations and Financial Condition."
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.
| ENERGY EAST CORPORATION |
| CENTRAL MAINE POWER COMPANY |
| NEW YORK STATE ELECTRIC & GAS CORPORATION |
| ROCHESTER GAS AND ELECTRIC CORPORATION |
The following exhibits are delivered with this report:
Registrant | Exhibit No. | Description of Exhibit |
Energy East Corporation | 3-4 | By-Laws of the Company as amended April 8, 2004. |
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. |
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 | (A)10-33 | Amendment No. 5 to Supplemental Executive Retirement Plan, amended and restated August 1, 2001. |
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. | |
Rochester Gas and | (A)10-25 | Supplemental Executive Retirement Program Amendment No. 4, effective as of May 1, 2004. |
(A)10-26 | Supplemental Retirement Benefit Program Amendment No. 4, effective as of May 1, 2004. | |
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. |
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(A) Management contract or compensatory plan or arrangement.