UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year 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 File Number | Registrant, State of Incorporation, Address and Telephone Number | I.R.S. Employer Identification Number |
| 2-26651 | New England Power Company | 04-1663070 |
(a Massachusetts corporation) 25 Research Drive Westborough, MA 01582 508-389-2000 |
Securities registered pursuant to Section 12(b) or Section 12(g) of the Act: None
Indicate by check mark whether the 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K [ X ]
Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). YES [ ] NO [ X ]
State the aggregate market value of the common equity held by nonaffiliates of the registrant: N/A
Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). YES [ ] NO [ X ]
State the aggregate market value of the common equity held by nonaffiliates of the registrant: N/A
Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.
Registrant | Title | Shares Outstanding at June 24, 2004 |
New England Power Company | Common Stock, $20.00 par value | 3,619,896 |
(all held by National Grid USA) |
| PAGE | ||
TABLE OF CONTENTS | ||
PART I | ||
Item 1. | Business | |
Item 2. | Properties | |
Item 3. | Legal Proceedings | |
Item 4. | Submission of Matters to a Vote of Security Holders | |
PART II | ||
Item 5. | Market for the Registrant's Common Equity and Related Stockholders Matters | |
Item 6. | Selected Financial Data | |
Item 7. | Management's Discussion and Analysis of Financial Condition and Results of Operations | |
Item 7A. | Quantitative and Qualitative Disclosures About Market Risk | |
Item 8. | Financial Statements and Supplementary Data | |
Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | |
Item 9A. | Controls and Procedures | |
PART III | ||
Item 10. | Directors and Executive Officers of the Registrant | |
Item 11. | Executive Compensation | |
Item 12. | Security Ownership of Certain Beneficial Owners and Management | |
Item 13. | Certain Relationships and Related Transactions | |
Item 14. | Principal Accountant Fees and Services | |
PART IV | ||
Item 15. | Exhibits and Reports on Form 8-K | |
Signatures | ||
Forward-Looking information: This report contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Throughout this report, forward-looking statements can be identified by the words or phrases “will likely result”, “are expected to”, “will continue”, “is anticipated”, “estimated”, “projected”, “believe”, “hopes”, or similar expressions. Although the Company believes that, in making any such statements, its expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to:
(a) | the impact of industry restructuring; |
(b) | federal and state regulatory developments and changes in law which may have a substantial adverse impact on revenues or on the value of NEP’s assets; |
(c) | federal regulatory developments concerning regional transmission organizations; |
(d) | changes in accounting rules and interpretations which may have an adverse impact on NEP’s statements of financial position and reported earnings; |
(e) | failure to recover costs currently deferred under the provisions Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation”, as amended; and |
(f) | acts of terrorism. |
PART I
ITEM 1. BUSINESS
New England Power Company (the Company or NEP) is a subsidiary of National Grid USA (formerly New England Electric System (NEES)). NEP is a Massachusetts corporation qualified to do business in Massachusetts, New Hampshire, Rhode Island, Connecticut, Maine, and Vermont. Nap’s transmission facilities are part of National Grid USA’s transmission operations, which are represented under the name National Grid Transmission USA.
NEP’s business is primarily the transmission of electricity in wholesale quantities to other electric utilities, principally its New England electricity distribution affiliates: Massachusetts Electric Company, The Narragansett Electric Company, Granite State Electric Company, and Nantucket Electric Company. The Company’s customers and assets are concentrated in the northeast region of the United States. For more information, see Note A “Accounting Policies”, in Item 8. Financial Statements and Supplementary Data. The facilities of NEP, together with those of these affiliates, constitute an electricity transmission and distribution system that is directly interconnected with the facilities of its New York affiliate, Niagara Mohawk Power Corporation and other utilities in New England and New York State, and indirectly interconnected with those of utilities in Canada.
Capital stock: Holders of NEP’s common stock and 6% Cumulative Preferred Stock have general voting rights. National Grid USA owns all of the common stock of NEP, or 99.64% of the voting stock. Non-affiliates own NEP’s 6% Cumulative Preferred Stock, or 0.36% of the voting stock.
Investees: The Company holds minority interests in three nuclear generating companies (the Yankees) which own generating facilities that are permanently retired and are conducting decommissioning operations. The Company also owns minority interests in two companies that transmit hydro electricity from Canada. The Company owns voting stock of the following companies in the amounts indicated:
New England Power Company (the Company or NEP) is a subsidiary of National Grid USA (formerly New England Electric System (NEES)). NEP is a Massachusetts corporation qualified to do business in Massachusetts, New Hampshire, Rhode Island, Connecticut, Maine, and Vermont. Nap’s transmission facilities are part of National Grid USA’s transmission operations, which are represented under the name National Grid Transmission USA.
NEP’s business is primarily the transmission of electricity in wholesale quantities to other electric utilities, principally its New England electricity distribution affiliates: Massachusetts Electric Company, The Narragansett Electric Company, Granite State Electric Company, and Nantucket Electric Company. The Company’s customers and assets are concentrated in the northeast region of the United States. For more information, see Note A “Accounting Policies”, in Item 8. Financial Statements and Supplementary Data. The facilities of NEP, together with those of these affiliates, constitute an electricity transmission and distribution system that is directly interconnected with the facilities of its New York affiliate, Niagara Mohawk Power Corporation and other utilities in New England and New York State, and indirectly interconnected with those of utilities in Canada.
Capital stock: Holders of NEP’s common stock and 6% Cumulative Preferred Stock have general voting rights. National Grid USA owns all of the common stock of NEP, or 99.64% of the voting stock. Non-affiliates own NEP’s 6% Cumulative Preferred Stock, or 0.36% of the voting stock.
Investees: The Company holds minority interests in three nuclear generating companies (the Yankees) which own generating facilities that are permanently retired and are conducting decommissioning operations. The Company also owns minority interests in two companies that transmit hydro electricity from Canada. The Company owns voting stock of the following companies in the amounts indicated:
Name of Company | State of Organization | Type of Business | % Voting Securities Owned by NEP |
Connecticut Yankee Atomic Power Company (a) | CT | Ownership of Permanently Shutdown Nuclear Unit | 19.5% |
Maine Yankee Atomic Power Company (a) | ME | Ownership of Permanently Shutdown Nuclear Unit | 24.0% |
Yankee Atomic Electric Company (a) | MA | Ownership of Permanently Shutdown Nuclear Unit | 34.5% |
New England Hydro Transmission | NH | Electricity Transmission | 3.4% |
New England Hydro-Transmission Electric Co., Inc. | MA | Electricity Transmission | 3.4% |
(a) For information on the Company’s ownership interests in the Yankees, see Note C, Item. 8 Financial Statements and Supplementary Data.
Regulation: Numerous activities of the Company are subject to regulation by various federal agencies. Under the Public Utility Holding Company Act of 1935 (the 1935 Act), many transactions of the Company are subject to the jurisdiction of the Securities and Exchange Commission (SEC). Under the Federal Power Act, the Company is subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) with respect to rates and accounting. In addition, the Nuclear Regulatory Commission (NRC) has broad jurisdiction over nuclear units and federal environmental agencies have broad jurisdiction over environmental matters. NEP is also subject, for certain purposes, to the jurisdiction of the utility commissions of Massachusetts, New Hampshire, Rhode Island, Maine, and Vermont. For more information on regulation by the FERC, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note A, “Accounting Policies” in Item 8. Financial Statements and Supplementary Data.
Environmental Requirements: The Company is subject to federal, state, and local environmental regulation of, among other things, wetlands and flood plains; air and water quality; storage, transportation, and disposal of hazardous wastes and substances; underground storage tanks; and land use. For more information, see Note D “Commitments and Contingencies”, in Item 8. Financial Statements and Supplementary Data.
Purchased Power Transfer Agreement: As part of the sale of the Company’s nonnuclear generating business to USGen New England, Inc. (USGen), a wholly owned subsidiary of PG&E, in 1997, NEP signed a purchased power transfer agreement through which USGen purchased the Company’s entitlement to approximately 1,100 MW of power procured under long-term contracts. In the ensuing period, contract terminations, assignments and expirations have reduced this entitlement to approximately 580 MW. For more information, see Note B “Rate and Regulatory”, in Item 8. Financial Statements and Supplementary Data.
Segments: The Company's reportable segments are electricity transmission and stranded/other. The Company is engaged principally in the business of electricity transmission. For more information, see Note J “Segments”, in Item 8. Financial Statements and Supplementary Data.
Employee Relations: NEP receives substantial support for its activities from the employees of National Grid USA Service Company, Inc. (Service Company), an affiliated company that provides administrative support to all National Grid USA companies in accordance with the 1935 Act. NEP reimburses Service Company for the costs associated with those services. (For a more detailed discussion of Service Company support for the Company, see Note A “Accounting Policies”, in Item 8. Financial Statements and Supplementary Data.) In addition, at March 31, 2004, NEP had seven employees, six of whom are members of a labor organization, the International Brotherhood of Electrical Workers.
ITEM 2. PROPERTIES
The Company’s integrated system consists of approximately 2,848 circuit miles of transmission lines, and approximately 122 substations. The properties of the Company also include the ownership interests of New England Electric Transmission Corporation (NEET), New England Hydro-Transmission Electric Company, Inc. (Mass. Hydro), and New England Hydro-Transmission Corporation (N.H. Hydro) in the Hydro-Quebec Interconnection, and an integrated system of transmission lines, substations, and distribution facilities. NEP also holds a nine percent joint ownership interest in the Wyman 4 fossil fuel plant located in Yarmouth, Maine
The Company is a participant in the New England Power Pool (NEPOOL). The NEPOOL Agreement provides for coordination of the operation of the generation and transmission facilities of its members. The NEPOOL Agreement further provides for New England-wide central dispatch of generation by the Independent System Operator New England (ISO-NE).
ISO-NE was activated on July 1, 1997 and has been operating the control area since that time. It operates under contract with NEPOOL and is governed by an independent board of directors. NEPOOL’s Open Access Transmission Tariff, which covers service across pool transmission facilities, is administered by ISO-NE.
In May 1999, NEPOOL and ISO-NE began implementing the NEPOOL competitive market system. The market system establishes markets for several tradable energy and reserve products. Implementation of the markets also has resulted in the imposition of certain costs including congestion related costs. By Order issued June 28, 2000, FERC conditionally approved a congestion management system and multi-settlement system (CMS/MSS). The CMS/MSS includes a Financial Transmission Rights scheme, a transmission planning process, and locational marginal pricing. The New England Standard Market Design (SMD), which was implemented on March 1, 2003, is based on the market system presently in place in the PJM (Pennsylvania, New Jersey, Maryland) interconnection and in New York, and is intended to bring greater consistency to power markets in the Northeast.
Hydro-Quebec Interconnection: Three affiliates of the Company were created to construct and operate transmission facilities to transmit power from Hydro-Quebec to New England. Under the financial and organizational agreements (the Support Agreements) entered into at the time these facilities were constructed, the Company agreed to guarantee a portion of the project debt. At March 31, 2004, the Company had guaranteed approximately $15 million of project debt, with terms through 2015. The Company entered into a Transmission Line Agreement with the purchaser of its nonnuclear generation, USGen, under which USGen assumed the Company’s rights to use the Hydro-Quebec line and also agreed to reimburse the Company for its payment obligations under the Support Agreements. The Transmission Line Agreement was terminated on April 1, 2004 and the Company has resumed performance and payment obligations under the Support Agreements. Costs associated with these Support Agreements are recoverable from the Company’s customers through CTCs.
ITEM 3. LEGAL PROCEEDINGS
Millstone 3 Prudence Challenge: In November 1999, New England Power Company entered into an agreement with Northeast Utilities (NU) to settle certain claims. As part of the agreement, NU agreed to include NEP’s 16.2 percent ownership interest in Millstone Unit 3 in an auction of NU’s share of the unit. Upon the closing of the sale, NEP was to receive a fixed amount, regardless of the actual sale price. In March 2001, the Millstone units were sold, including NEP’s interest, for $1.3 billion. In accordance with the settlement agreement, NEP was paid approximately $27.9 million, from which NEP paid approximately $5.8 million to increase the decommissioning trust fund.
Regulatory authorities from Rhode Island, New Hampshire and Massachusetts have expressed intent to challenge the reasonableness of the settlement agreement, taking the position that NEP would have received approximately $140 million of sale proceeds if there had been no agreement with NU. In the event that one or more of the states proceed with such a challenge, the dispute will be resolved by the FERC. Management believes that the Company acted prudently, because the amount it received under the settlement agreement was the highest sale price for a nuclear unit at the time the agreement was reached.
Town of Norwood Litigation: NEP continues to be engaged in litigation in judicial and administrative forums with the Town of Norwood, Massachusetts, for which NEP was a wholesale power supplier from 1983 to 1998. In April 1998, Norwood began taking power from another supplier, although its contract term with NEP ran to 2008. Pursuant to a tariff amendment approved by the FERC in May 1998, NEP has been assessing Norwood a CTC. Through March 31, 2004, the charges assessed Norwood amount to approximately $77 million, all of which remain unpaid. The litigation with Norwood is as follows:
1. State Collection Action. NEP filed a collection action in Massachusetts Superior Court (Worcester County) to collect the CTC, which Norwood has refused to pay. In March 2001, the Superior Court ruled that Norwood has breached the agreement by not paying the CTC charge, and ordered Norwood to make regular and substantial payments to an escrow account. Norwood unsuccessfully appealed the order to the Massachusetts Appeals Court, and the Massachusetts Supreme Judicial Court denied Norwood’s petition for further appellate review. On June 1, 2004, the Supreme Court denied Norwood’s petition for certiorari.
On December 17, 2003, the Superior Court entered judgment for NEP for approximately $40.6 million, which included interest to that date, and which the Company subsequently moved to increase by approximately $2.7 million, to adjust for computational errors. Norwood then moved to void the judgment, or stay its enforcement pending completion of the FERC proceeding described below, or both. On June 9, 2004, the Massachusetts Superior Court granted NEP’s motion to increase the judgment and denied Norwood’s motion to void the judgment or stay it pending Norwood’s Section 206 Proceeding at FERC.
2. FERC 206 Proceeding. In December 2002, Norwood filed a challenge to the CTC rate with the FERC under Section 206 of the Federal Power Act. Under this Section, the FERC has the power to grant prospective relief only. In an order dated July 2, 2003, the FERC set down for hearing Norwood’s challenge to the factors used to calculate the CTC rate for Norwood and set a refund effective date of February 21, 2003, which empowers the FERC to direct NEP to adjust Norwood’s liability for unpaid charges billed after that date in the event that Norwood’s challenge is successful. On June 9, 2004, the FERC administrative law judge issued an initial decision recommending that FERC revise the CTC formula to reduce the CTC amount that was previously calculated under the formula and that the FERC accepted and approved in 1998. NEP will request that FERC not modify the tariff as recommended by the initial decision.
3. Federal Court Antitrust Claim. In 1997, Norwood filed a lawsuit in the U.S. District Court for the District of Massachusetts challenging NEP’s proposed divestiture of its generating facilities. Following the District Court’s dismissal of all of Norwood’s claims, the U.S. Court of Appeals for the First Circuit reinstated Norwood’s claim that the sale to USGen violated Section 7 of the Clayton Act on the ground that USGen had acquired market power. The First Circuit characterized the claim as weak because FERC had found no anticompetitive consequences from the sale, and invited the District Court to address whether the FERC’s decision precluded further litigation. This issue was argued to the District Court in 2001, but no decision has been rendered, in part because the original judge who heard argument subsequently recused herself. USGen’s bankruptcy filing on July 2, 2003 resulted in an automatic stay of this case.
In addition to the legal proceedings described above, the Company has been named as a potentially responsible party (PRP) by either the United States Environmental Protection Agency or the Massachusetts Department of Environmental Protection for several sites at which hazardous waste is alleged to have been disposed. There are significant uncertainties as to the portion, if any, of the investigation and remediation costs of any particular hazardous waste site that may ultimately be borne by the Company. Management believes that hazardous waste liabilities for all sites of which it is aware are not material to the Company's financial position. For more detail, see Note D "Commitments and Contingencies" in Item 8. Financial Statements and Supplementary Data.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the last quarter of the fiscal year ended March 31, 2004. The Annual Meeting of Stockholders was held on April 21, 2004. By a vote of 3,619,906 shares out of 3,632,630 total shares voted, the following actions were taken:
Regulation: Numerous activities of the Company are subject to regulation by various federal agencies. Under the Public Utility Holding Company Act of 1935 (the 1935 Act), many transactions of the Company are subject to the jurisdiction of the Securities and Exchange Commission (SEC). Under the Federal Power Act, the Company is subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) with respect to rates and accounting. In addition, the Nuclear Regulatory Commission (NRC) has broad jurisdiction over nuclear units and federal environmental agencies have broad jurisdiction over environmental matters. NEP is also subject, for certain purposes, to the jurisdiction of the utility commissions of Massachusetts, New Hampshire, Rhode Island, Maine, and Vermont. For more information on regulation by the FERC, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note A, “Accounting Policies” in Item 8. Financial Statements and Supplementary Data.
Environmental Requirements: The Company is subject to federal, state, and local environmental regulation of, among other things, wetlands and flood plains; air and water quality; storage, transportation, and disposal of hazardous wastes and substances; underground storage tanks; and land use. For more information, see Note D “Commitments and Contingencies”, in Item 8. Financial Statements and Supplementary Data.
Purchased Power Transfer Agreement: As part of the sale of the Company’s nonnuclear generating business to USGen New England, Inc. (USGen), a wholly owned subsidiary of PG&E, in 1997, NEP signed a purchased power transfer agreement through which USGen purchased the Company’s entitlement to approximately 1,100 MW of power procured under long-term contracts. In the ensuing period, contract terminations, assignments and expirations have reduced this entitlement to approximately 580 MW. For more information, see Note B “Rate and Regulatory”, in Item 8. Financial Statements and Supplementary Data.
Segments: The Company's reportable segments are electricity transmission and stranded/other. The Company is engaged principally in the business of electricity transmission. For more information, see Note J “Segments”, in Item 8. Financial Statements and Supplementary Data.
Employee Relations: NEP receives substantial support for its activities from the employees of National Grid USA Service Company, Inc. (Service Company), an affiliated company that provides administrative support to all National Grid USA companies in accordance with the 1935 Act. NEP reimburses Service Company for the costs associated with those services. (For a more detailed discussion of Service Company support for the Company, see Note A “Accounting Policies”, in Item 8. Financial Statements and Supplementary Data.) In addition, at March 31, 2004, NEP had seven employees, six of whom are members of a labor organization, the International Brotherhood of Electrical Workers.
ITEM 2. PROPERTIES
The Company’s integrated system consists of approximately 2,848 circuit miles of transmission lines, and approximately 122 substations. The properties of the Company also include the ownership interests of New England Electric Transmission Corporation (NEET), New England Hydro-Transmission Electric Company, Inc. (Mass. Hydro), and New England Hydro-Transmission Corporation (N.H. Hydro) in the Hydro-Quebec Interconnection, and an integrated system of transmission lines, substations, and distribution facilities. NEP also holds a nine percent joint ownership interest in the Wyman 4 fossil fuel plant located in Yarmouth, Maine
The Company is a participant in the New England Power Pool (NEPOOL). The NEPOOL Agreement provides for coordination of the operation of the generation and transmission facilities of its members. The NEPOOL Agreement further provides for New England-wide central dispatch of generation by the Independent System Operator New England (ISO-NE).
ISO-NE was activated on July 1, 1997 and has been operating the control area since that time. It operates under contract with NEPOOL and is governed by an independent board of directors. NEPOOL’s Open Access Transmission Tariff, which covers service across pool transmission facilities, is administered by ISO-NE.
In May 1999, NEPOOL and ISO-NE began implementing the NEPOOL competitive market system. The market system establishes markets for several tradable energy and reserve products. Implementation of the markets also has resulted in the imposition of certain costs including congestion related costs. By Order issued June 28, 2000, FERC conditionally approved a congestion management system and multi-settlement system (CMS/MSS). The CMS/MSS includes a Financial Transmission Rights scheme, a transmission planning process, and locational marginal pricing. The New England Standard Market Design (SMD), which was implemented on March 1, 2003, is based on the market system presently in place in the PJM (Pennsylvania, New Jersey, Maryland) interconnection and in New York, and is intended to bring greater consistency to power markets in the Northeast.
Hydro-Quebec Interconnection: Three affiliates of the Company were created to construct and operate transmission facilities to transmit power from Hydro-Quebec to New England. Under the financial and organizational agreements (the Support Agreements) entered into at the time these facilities were constructed, the Company agreed to guarantee a portion of the project debt. At March 31, 2004, the Company had guaranteed approximately $15 million of project debt, with terms through 2015. The Company entered into a Transmission Line Agreement with the purchaser of its nonnuclear generation, USGen, under which USGen assumed the Company’s rights to use the Hydro-Quebec line and also agreed to reimburse the Company for its payment obligations under the Support Agreements. The Transmission Line Agreement was terminated on April 1, 2004 and the Company has resumed performance and payment obligations under the Support Agreements. Costs associated with these Support Agreements are recoverable from the Company’s customers through CTCs.
ITEM 3. LEGAL PROCEEDINGS
Millstone 3 Prudence Challenge: In November 1999, New England Power Company entered into an agreement with Northeast Utilities (NU) to settle certain claims. As part of the agreement, NU agreed to include NEP’s 16.2 percent ownership interest in Millstone Unit 3 in an auction of NU’s share of the unit. Upon the closing of the sale, NEP was to receive a fixed amount, regardless of the actual sale price. In March 2001, the Millstone units were sold, including NEP’s interest, for $1.3 billion. In accordance with the settlement agreement, NEP was paid approximately $27.9 million, from which NEP paid approximately $5.8 million to increase the decommissioning trust fund.
Regulatory authorities from Rhode Island, New Hampshire and Massachusetts have expressed intent to challenge the reasonableness of the settlement agreement, taking the position that NEP would have received approximately $140 million of sale proceeds if there had been no agreement with NU. In the event that one or more of the states proceed with such a challenge, the dispute will be resolved by the FERC. Management believes that the Company acted prudently, because the amount it received under the settlement agreement was the highest sale price for a nuclear unit at the time the agreement was reached.
Town of Norwood Litigation: NEP continues to be engaged in litigation in judicial and administrative forums with the Town of Norwood, Massachusetts, for which NEP was a wholesale power supplier from 1983 to 1998. In April 1998, Norwood began taking power from another supplier, although its contract term with NEP ran to 2008. Pursuant to a tariff amendment approved by the FERC in May 1998, NEP has been assessing Norwood a CTC. Through March 31, 2004, the charges assessed Norwood amount to approximately $77 million, all of which remain unpaid. The litigation with Norwood is as follows:
1. State Collection Action. NEP filed a collection action in Massachusetts Superior Court (Worcester County) to collect the CTC, which Norwood has refused to pay. In March 2001, the Superior Court ruled that Norwood has breached the agreement by not paying the CTC charge, and ordered Norwood to make regular and substantial payments to an escrow account. Norwood unsuccessfully appealed the order to the Massachusetts Appeals Court, and the Massachusetts Supreme Judicial Court denied Norwood’s petition for further appellate review. On June 1, 2004, the Supreme Court denied Norwood’s petition for certiorari.
On December 17, 2003, the Superior Court entered judgment for NEP for approximately $40.6 million, which included interest to that date, and which the Company subsequently moved to increase by approximately $2.7 million, to adjust for computational errors. Norwood then moved to void the judgment, or stay its enforcement pending completion of the FERC proceeding described below, or both. On June 9, 2004, the Massachusetts Superior Court granted NEP’s motion to increase the judgment and denied Norwood’s motion to void the judgment or stay it pending Norwood’s Section 206 Proceeding at FERC.
2. FERC 206 Proceeding. In December 2002, Norwood filed a challenge to the CTC rate with the FERC under Section 206 of the Federal Power Act. Under this Section, the FERC has the power to grant prospective relief only. In an order dated July 2, 2003, the FERC set down for hearing Norwood’s challenge to the factors used to calculate the CTC rate for Norwood and set a refund effective date of February 21, 2003, which empowers the FERC to direct NEP to adjust Norwood’s liability for unpaid charges billed after that date in the event that Norwood’s challenge is successful. On June 9, 2004, the FERC administrative law judge issued an initial decision recommending that FERC revise the CTC formula to reduce the CTC amount that was previously calculated under the formula and that the FERC accepted and approved in 1998. NEP will request that FERC not modify the tariff as recommended by the initial decision.
3. Federal Court Antitrust Claim. In 1997, Norwood filed a lawsuit in the U.S. District Court for the District of Massachusetts challenging NEP’s proposed divestiture of its generating facilities. Following the District Court’s dismissal of all of Norwood’s claims, the U.S. Court of Appeals for the First Circuit reinstated Norwood’s claim that the sale to USGen violated Section 7 of the Clayton Act on the ground that USGen had acquired market power. The First Circuit characterized the claim as weak because FERC had found no anticompetitive consequences from the sale, and invited the District Court to address whether the FERC’s decision precluded further litigation. This issue was argued to the District Court in 2001, but no decision has been rendered, in part because the original judge who heard argument subsequently recused herself. USGen’s bankruptcy filing on July 2, 2003 resulted in an automatic stay of this case.
In addition to the legal proceedings described above, the Company has been named as a potentially responsible party (PRP) by either the United States Environmental Protection Agency or the Massachusetts Department of Environmental Protection for several sites at which hazardous waste is alleged to have been disposed. There are significant uncertainties as to the portion, if any, of the investigation and remediation costs of any particular hazardous waste site that may ultimately be borne by the Company. Management believes that hazardous waste liabilities for all sites of which it is aware are not material to the Company's financial position. For more detail, see Note D "Commitments and Contingencies" in Item 8. Financial Statements and Supplementary Data.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the last quarter of the fiscal year ended March 31, 2004. The Annual Meeting of Stockholders was held on April 21, 2004. By a vote of 3,619,906 shares out of 3,632,630 total shares voted, the following actions were taken:
- The number of directors was fixed at five.
- The following persons were elected as directors: John G. Cochrane, Michael E. Jesanis, Stephen P. Lewis, Lawrence J. Reilly, and Jeffrey A. Scott.
- James S. Robinson was elected Treasurer and Gregory A. Hale was elected Clerk.
- PricewaterhouseCoopers LLP, an independent registered public accounting firm, was appointed the Company’s auditor for the fiscal year ending March 31, 2005.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SECURITY HOLDER MATTERS
The common stock of NEP is held solely by National Grid USA, and therefore indirectly by National Grid Transco plc. There is no public trading market for the Company’s common stock, and the Company sold no equity securities during the period covered by this Annual Report. For information about the Company's payment of dividends and restrictions on those payments, see Item 6, Selected Financial Data, and Item 8. Financial Statements and Supplementary Data, Note I.
ITEM 6. SELECTED FINANCIAL DATA
The following tables set forth selected financial information for NEP for the fiscal years ended March 31, 2004, 2003, 2002, and 2001 respectively, for the three months ended March 31, 2000, and for the year ended December 31, 1999. These have been derived from the financial statements of NEP and should be read together with them.
On March 22, 2000, the Company’s former parent New England Electric System merged with a subsidiary of National Grid Transco plc (NGT) (formerly National Grid Group plc) in a purchase business combination recorded under the “push-down” method of accounting, resulting in a new basis of accounting for the “successor” period beginning March 22, 2000. Information relating to all “predecessor” periods prior to the acquisition is presented using the Company’s historical basis of accounting. The following selected audited financial data for the Company may not be indicative of the Company’s future financial condition, results of operations or cash flows.
The common stock of NEP is held solely by National Grid USA, and therefore indirectly by National Grid Transco plc. There is no public trading market for the Company’s common stock, and the Company sold no equity securities during the period covered by this Annual Report. For information about the Company's payment of dividends and restrictions on those payments, see Item 6, Selected Financial Data, and Item 8. Financial Statements and Supplementary Data, Note I.
ITEM 6. SELECTED FINANCIAL DATA
The following tables set forth selected financial information for NEP for the fiscal years ended March 31, 2004, 2003, 2002, and 2001 respectively, for the three months ended March 31, 2000, and for the year ended December 31, 1999. These have been derived from the financial statements of NEP and should be read together with them.
On March 22, 2000, the Company’s former parent New England Electric System merged with a subsidiary of National Grid Transco plc (NGT) (formerly National Grid Group plc) in a purchase business combination recorded under the “push-down” method of accounting, resulting in a new basis of accounting for the “successor” period beginning March 22, 2000. Information relating to all “predecessor” periods prior to the acquisition is presented using the Company’s historical basis of accounting. The following selected audited financial data for the Company may not be indicative of the Company’s future financial condition, results of operations or cash flows.
Year Ended March 31, (Successor) | Three Months Ended March 31, (Predecessor) | Year Ended December 31, (Predecessor) | ||||
(In millions) | 2004 | 2003 | 2002 | 2001 | 2000 | 1999 |
Operating Revenue | $ 458 | $ 514 | $ 560 | $ 656 | $ 135 | $ 596 |
Net Income | $ 72 | $ 77 | $ 77 | $ 58 | $ 14 | $ 71 |
Income from continuing operations per average common share | ** | ** | ** | ** | ** | ** |
Total assets | $2,762 | $2,984 | $2,740 | $2,889 | $2,630 | $2,303 |
Long-term debt | $ 410 | $ 410 | $ 410 | $ 410 | $ 372 | $ 372 |
Cumulative preferred stock | $ 1 | $ 1 | $ 2 | $ 1 | $ 1 | $ 2 |
Dividends per common share | ** | ** | ** | ** | ** | ** |
** All of NEP’s shares of common stock are owned by its parent company. Therefore management considers dividend information and per share data not relevant.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
FERC Proceedings: The FERC has issued several orders and is contemplating some additional changes to the regulatory structure that governs the Company’s transmission business.
Regional Transmission Organizations (RTO): Transmission owners, including NEP, and ISO-NE, filed with FERC for approval of a New England RTO that complies with FERC’s Order 2000 minimum characteristics, including independence from the market, and functions. The filing included an RTO transmission tariff which would govern the recovery of NEP’s transmission revenues. The proposed tariff continues to provide for a formula rate for the recovery of NEP’s transmission expenses. FERC issued an order on March 24, 2004 granting RTO status subject to the fulfillment of certain conditions. RTO status is contingent upon the filing parties agreeing to a number of changes in their proposal. Some of the changes would make it easier for FERC to modify the terms of the underlying RTO documents in the future. Others would strengthen the authority of the RTO on matters such as determining facility ratings and rescheduling transmission outages. National Grid and the other New England transmission owners have petitioned FERC for rehearing on some of these changes. Other parties have also petitioned for rehearing on several issues.
Rate Filing: Transmission owners in New England, including NEP, filed with FERC to increase their allowed return on equity in transmission rates. The filing had three components. First, transmission owners sought an increased return on equity of 12.8%. Second, transmission owners sought an additional 0.5% return on equity for joining the RTO which they have separately proposed to FERC (see above). Third, transmission owners sought an additional 1% equity return on new transmission investment that is constructed pursuant to an approved RTO plan.
FERC’s March 24, 2004 RTO order approved for regional network service rates (RNS) the 0.5% return on equity adder for joining the proposed RTO effective as of the date that the RTO commences operation. NEP would earn this additional return on equity provided it joins the RTO. Approximately seventy percent of the company’s transmission costs are recovered through RNS rates. FERC rejected for local network service (LNS) rates both the 0.5% adder and the 1% adder. FERC also suspended the proposed increase in the base ROE for both RNS and LNS rates and the 1% adder for RNS rates subject to refund effective as of the RTO operations date, and it encouraged the parties to participate in settlement discussions on these issues with a FERC administrative law judge. The settlement judge procedure ended on May 13 without an agreement, and the issues concerning the base ROE for both RNS rates and LNS rates and the 1% adder for RNS rates have been set for an evidentiary hearing in December 2004.
The transmission owners on April 15, 2004 filed a motion for clarification with FERC on three issues. The filing states that clarification on these issues is necessary before transmission owners can make a final determination on whether to transfer operational control of their transmission assets to the RTO. Each of these issues concerns the amount of revenues that transmission owners would receive once the RTO commences. The transmission owners have asked FERC for expedited consideration of this motion.
Standards of Conduct: FERC issued new regulations on November 25, 2003 revising the standards of conduct for transmission providers including National Grid. FERC’s regulations provide generally that transmission employees must function independently from marketing employees and from Energy Affiliates. The definition of Energy Affiliate exempts holding and parent companies that do not engage in markets or transmission transactions in the US. However, language in the regulatory preamble implied that holding companies such as NGT would be “engaging in transmission transactions in the US” and, hence a non-exempt Energy Affiliate of the Company’s subsidiaries that are transmission providers. The Company filed a motion with FERC seeking to clarify the language so that it is clear that NGT is not an Energy Affiliate of the Company’s transmission subsidiaries. On April 16, 2004, FERC revised its regulations. The preamble to the revised regulations clarifies that a holding and parent company such as NGT qualifies for an exemption to the definition of Energy Affiliate.
FERC Proceedings: The FERC has issued several orders and is contemplating some additional changes to the regulatory structure that governs the Company’s transmission business.
Regional Transmission Organizations (RTO): Transmission owners, including NEP, and ISO-NE, filed with FERC for approval of a New England RTO that complies with FERC’s Order 2000 minimum characteristics, including independence from the market, and functions. The filing included an RTO transmission tariff which would govern the recovery of NEP’s transmission revenues. The proposed tariff continues to provide for a formula rate for the recovery of NEP’s transmission expenses. FERC issued an order on March 24, 2004 granting RTO status subject to the fulfillment of certain conditions. RTO status is contingent upon the filing parties agreeing to a number of changes in their proposal. Some of the changes would make it easier for FERC to modify the terms of the underlying RTO documents in the future. Others would strengthen the authority of the RTO on matters such as determining facility ratings and rescheduling transmission outages. National Grid and the other New England transmission owners have petitioned FERC for rehearing on some of these changes. Other parties have also petitioned for rehearing on several issues.
Rate Filing: Transmission owners in New England, including NEP, filed with FERC to increase their allowed return on equity in transmission rates. The filing had three components. First, transmission owners sought an increased return on equity of 12.8%. Second, transmission owners sought an additional 0.5% return on equity for joining the RTO which they have separately proposed to FERC (see above). Third, transmission owners sought an additional 1% equity return on new transmission investment that is constructed pursuant to an approved RTO plan.
FERC’s March 24, 2004 RTO order approved for regional network service rates (RNS) the 0.5% return on equity adder for joining the proposed RTO effective as of the date that the RTO commences operation. NEP would earn this additional return on equity provided it joins the RTO. Approximately seventy percent of the company’s transmission costs are recovered through RNS rates. FERC rejected for local network service (LNS) rates both the 0.5% adder and the 1% adder. FERC also suspended the proposed increase in the base ROE for both RNS and LNS rates and the 1% adder for RNS rates subject to refund effective as of the RTO operations date, and it encouraged the parties to participate in settlement discussions on these issues with a FERC administrative law judge. The settlement judge procedure ended on May 13 without an agreement, and the issues concerning the base ROE for both RNS rates and LNS rates and the 1% adder for RNS rates have been set for an evidentiary hearing in December 2004.
The transmission owners on April 15, 2004 filed a motion for clarification with FERC on three issues. The filing states that clarification on these issues is necessary before transmission owners can make a final determination on whether to transfer operational control of their transmission assets to the RTO. Each of these issues concerns the amount of revenues that transmission owners would receive once the RTO commences. The transmission owners have asked FERC for expedited consideration of this motion.
Standards of Conduct: FERC issued new regulations on November 25, 2003 revising the standards of conduct for transmission providers including National Grid. FERC’s regulations provide generally that transmission employees must function independently from marketing employees and from Energy Affiliates. The definition of Energy Affiliate exempts holding and parent companies that do not engage in markets or transmission transactions in the US. However, language in the regulatory preamble implied that holding companies such as NGT would be “engaging in transmission transactions in the US” and, hence a non-exempt Energy Affiliate of the Company’s subsidiaries that are transmission providers. The Company filed a motion with FERC seeking to clarify the language so that it is clear that NGT is not an Energy Affiliate of the Company’s transmission subsidiaries. On April 16, 2004, FERC revised its regulations. The preamble to the revised regulations clarifies that a holding and parent company such as NGT qualifies for an exemption to the definition of Energy Affiliate.
CRITICAL ACCOUNTING POLICIES
The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to apply policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial statements. Because of the inherent uncertainty in the nature of the matters where estimates are used, actual amounts could differ from estimated amounts. The following accounting policies represent those that management believes are particularly important to the financial statements and require the use of judgment in estimating matters that are inherently uncertain.
Regulatory Assets and Liabilities: Regulatory assets represent costs that have been deferred to future periods when it is probable that the regulator (being the FERC or other regulatory body having jurisdiction) will allow future recovery of those costs through rates. The Company bases its assessment of recovery by either specific recovery measures or historical precedents established by the regulatory body. Regulatory liabilities represent previous collections from customers to fund future expected costs or amounts received in rates that are expected to be refunded to customers in future periods. These costs typically include deferral of energy costs, the normalization of income taxes, and the deferral of losses incurred on debt retirements. The accounting for these regulatory assets and liabilities is in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation”.
The Company continually assesses whether the regulatory assets continue to meet the criteria for probability of future recovery. This assessment considers factors such as changes in the regulatory environment, recent rate orders to other regulated entities under the same jurisdiction, and the status of any pending or potential deregulation legislation. If future recovery of costs becomes no longer probable, the assets and liabilities would be recognized as current-period revenue or expense.
Amortization of regulatory assets is provided over the recovery period as allowed in the related regulatory agreement. Amortization of stranded cost regulatory assets are included in the depreciation and amortization captions on the income statement. Amortization of the above market cost of purchased power contracts and nuclear decommissioning costs are included in the contract termination and nuclear unit shutdown charges caption on the income statement.
Benefit Plans: The Company maintains qualified and nonqualified pension plans. The Company also provides health care and life insurance benefits for its retired employees. The Company's qualified pension plans are funded through outside trusts. See “Employee Relations” in Item 1. Business, for a discussion of the Company’s employees
In addition to the market returns, various other assumptions also affect the pension and other post-retirement benefit expense and measurement of their respective obligations. The following is a description of some of those assumptions:
- Assumed return on assets. The estimated rate of return for various passive asset classes is based both on analysis of historical rates of return and forward looking analysis of risk premiums and yields. Current market conditions, such as inflation and interest rates, are evaluated in connection with the setting of our long-term assumption. A small premium is added for active management of both equity and fixed income. The rates of return for each asset class are then weighted in accordance with our target asset allocation, and the resulting long-term return on asset rate is then applied to the market-related value of assets. For fiscal 2004, the Company used an 8.5% and 8.15% assumed return on assets for its pension and other post-retirement benefits plans, respectively.
- Discount rate. In determining the discount rate, the Company considers Moody’s Aa rates for corporate bonds and public utility bonds. In addition, the Company considers other measures of interest rates for high quality fixed income investments which match the duration of the liabilities. A rate is chosen within the range set by these measures, rounded to the nearest 25 basis points.
- Medical trend assumptions. The health care cost trend rate is the assumed rate of increase in per-capita health care charges. For 2004, the health trend was set at 10% with the ultimate trend of 5% reached in 2008.
Goodwill: The company applies the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets” (FAS 142). In accordance with FAS 142, goodwill must be reviewed for impairment at least annually and when events or circumstances indicate that the asset may be impaired. The Company utilized a discounted cash flow approach incorporating its most recent business plan forecasts in the performance of the annual goodwill impairment test. The result of the annual analysis determined that no adjustment to the goodwill carrying value was required.
Tax Provision: The Company’s tax provisions, including both current and deferred components, are based on estimates, assumptions, calculations, and interpretation of tax statutes for the current and future years in accordance with SFAS No. 109, “Accounting for Income Taxes”. Federal income tax returns have been examined and all appeals and issues have been agreed upon by the Internal Revenue Service and the Company through 1996.
Management regularly makes assessments of tax return outcomes relative to financial statement tax provisions and adjusts the tax provisions in the period when facts become final.
RESULTS OF OPERATIONS
EARNINGS
Net income for year ended March 31, 2004, decreased approximately $5 million compared with the prior year. The reduction was due primarily to decreased mitigation incentives and reduced return on CTCs compared with the prior year. Also contributing to the decrease was reduced equity income from nuclear generation due to the sale of Vermont Yankee in July 2002. These decreases were partially offset by increased transmission earnings during the year ended March 31, 2004 as compared to the same periods in 2003.
Net income for year ended March 31, 2003, was not significantly different from the prior year. Affecting net income during the fiscal year were improved transmission earnings and lower interest expense on variable rate long-term debt as compared to the prior year. These increases were partially offset by decreased mitigation incentives and reduced return on CTC cost recovery as compared with the prior year.
Net income for year ended March 31, 2003, was not significantly different from the prior year. Affecting net income during the fiscal year were improved transmission earnings and lower interest expense on variable rate long-term debt as compared to the prior year. These increases were partially offset by decreased mitigation incentives and reduced return on CTC cost recovery as compared with the prior year.
REVENUES
The Company has two primary sources of revenue: transmission and stranded investment recovery. Transmission revenues are based on a formula rate that recovers the Company’s actual costs plus a return on investment. Stranded investment recovery revenues are in the form of a CTC to former all-requirements customers of the Company in connection with the Company’s divestiture of its electricity generation investments. During the prior fiscal year, the Company also had revenues associated with its ownership interests in the Vermont Yankee Nuclear Generating Station (Vermont Yankee) and the Seabrook Nuclear Generating Station (Seabrook). Vermont Yankee and Seabrook were sold in July and November 2002, respectively.
Operating revenue for fiscal year ended March 31, 2004, decreased approximately $56 million compared to the prior year. The primary reason for the decrease was reduced sales of power received from Vermont Yankee and Seabrook during the fiscal year. The decrease is also related to reduced CTC revenue due to fully reconciling true-up mechanisms that allow the Company to adjust revenues proportionately with correlating expenses. In addition, reduced mitigation incentives under the CTC contributed to the reduction in operating revenue.
Operating revenue for the fiscal year ended March 31, 2003, decreased approximately $46 million compared to the prior year. In fiscal 2003, the Company was no longer receiving revenue related to its obligation to provide electricity supply to serve certain customers of The Narragansett Electric Company, an affiliate. In addition, revenue decreased as a result of reduced sales of power purchased from Vermont Yankee which was sold in July 2002. The decrease in revenues for the fiscal year ended March 31, 2003 in comparison to the prior year was partially offset by an increase in nuclear revenues, due to the recovery of a portion of increased nuclear operating expenses and increased transmission revenue.
OPERATING EXPENSES
Fuel for generation expense for the fiscal year ended March 31, 2004 was comparable to the prior year. Fuel for generation expense for the fiscal year ended March 31, 2003 increased approximately $3 million, compared with the prior year due to increased fuel expense at the Wyman 4 plant.
Purchased power expense for the fiscal year ended March 31, 2004 decreased approximately $33 million compared with the same period in 2003. The decrease was caused by reduced ongoing payments for purchased power due primarily to the buyout of a purchased power contract during in November 2002. Also contributing to the decrease was reduced purchased power expense for the fiscal year ended March 31, 2004 as compared with the prior year due to the sale of Vermont Yankee in July 2002. Partially offsetting the decreases was an increase in purchased power expenses due to the resumption of decommissioning billings by Yankee Atomic in June 2003.
Purchased power expense for the fiscal year ended March 31, 2003, decreased approximately $51 million compared with the prior year. The decrease was primarily caused by the termination of the company’s obligation to provide power to the Narragansett Electric Company as described in Operating Revenue above. In addition, purchased power expense decreased in connection with the sale of Vermont Yankee in July 2002. Also contributing to the decrease was reduced ongoing payments resulting from the November 2002 buyout of a purchased power contract.
Operation and maintenance expense for the fiscal year ended March 31, 2004, decreased approximately $2 million compared with the prior year. The reduction was due primarily to the inclusion of expenses from Seabrook during the fiscal year ended March 31, 2003. Seabrook was sold in November 2002. Partially offsetting the decreased expense for the fiscal year ended March 31, 2004 were increased costs due to a voluntary early retirement program provided to employees which is discussed in Note H, “Employee Benefits” in Item 8 Financial Statements and Supplemental Data.
Operation and maintenance expense decreased approximately $1 million for the fiscal year ended March 31, 2003, compared with the prior year. The decreased cost is primarily the result of the sale of Seabrook in November 2002. The decrease was partially offset by increased costs from a refueling outage at Seabrook prior to the sale and increased transmission maintenance costs.
Purchased power contract buyout and nuclear fuel amortization expense for the fiscal year ended March 31, 2004 increased approximately $5 million compared with the prior year. The increase was due primarily to the amortization of scheduled purchased power contract buyout cost increases based upon rate agreements. The increases were partially offset by decreased nuclear fuel amortization cost for the fiscal year ended March 31, 2004, as compared with the prior year due to the sale of Seabrook in November 2002.
Purchased power contract buyout and nuclear fuel amortization expense for the fiscal year ended March 31, 2003 increased approximately $2 million as compared with the prior year. The increase was due primarily to the amortization of scheduled purchased power contract buyout cost increases based upon rate agreements. The increase was partially offset by decreased nuclear fuel amortization due to the sale of the Seabrook plant in November 2002.
Other depreciation and amortization expense for the fiscal year ended March 31, 2004, decreased approximately $14 million compared with the prior year. The decrease was due primarily to reduced decommissioning expenses as a result of the sale of Seabrook in November 2002.
Other depreciation and amortization expense for the fiscal year ended March 31, 2003, increased by approximately $7 million compared with the prior year. The increase is due to the Company’s payment in November 2002 of approximately $5 million to the Seabrook decommissioning trust fund for its share of the balance needed to raise the fund to the level required in the Seabrook sales agreement.
Equity in income of nuclear power companies decreased approximately $3 million during the fiscal year ended March 31, 2004 compared to the same period in the prior year due to the redemption of the Company’s interest in the Vermont Yankee Nuclear Power Corporation.
Other income net increased approximately $2 million during the fiscal year ended March 31, 2004 as compared with the prior year due to increased interest income and the sale of non-utility property.
Interest expense for the fiscal years ended March 31, 2004 and 2003, decreased approximately $2 million and $6 million, respectively, compared with fiscal 2003 and 2002, respectively, primarily due to decreased interest rates on the Company’s variable rate long-term debt.
Operating revenue for the fiscal year ended March 31, 2003, decreased approximately $46 million compared to the prior year. In fiscal 2003, the Company was no longer receiving revenue related to its obligation to provide electricity supply to serve certain customers of The Narragansett Electric Company, an affiliate. In addition, revenue decreased as a result of reduced sales of power purchased from Vermont Yankee which was sold in July 2002. The decrease in revenues for the fiscal year ended March 31, 2003 in comparison to the prior year was partially offset by an increase in nuclear revenues, due to the recovery of a portion of increased nuclear operating expenses and increased transmission revenue.
OPERATING EXPENSES
Fuel for generation expense for the fiscal year ended March 31, 2004 was comparable to the prior year. Fuel for generation expense for the fiscal year ended March 31, 2003 increased approximately $3 million, compared with the prior year due to increased fuel expense at the Wyman 4 plant.
Purchased power expense for the fiscal year ended March 31, 2004 decreased approximately $33 million compared with the same period in 2003. The decrease was caused by reduced ongoing payments for purchased power due primarily to the buyout of a purchased power contract during in November 2002. Also contributing to the decrease was reduced purchased power expense for the fiscal year ended March 31, 2004 as compared with the prior year due to the sale of Vermont Yankee in July 2002. Partially offsetting the decreases was an increase in purchased power expenses due to the resumption of decommissioning billings by Yankee Atomic in June 2003.
Purchased power expense for the fiscal year ended March 31, 2003, decreased approximately $51 million compared with the prior year. The decrease was primarily caused by the termination of the company’s obligation to provide power to the Narragansett Electric Company as described in Operating Revenue above. In addition, purchased power expense decreased in connection with the sale of Vermont Yankee in July 2002. Also contributing to the decrease was reduced ongoing payments resulting from the November 2002 buyout of a purchased power contract.
Operation and maintenance expense for the fiscal year ended March 31, 2004, decreased approximately $2 million compared with the prior year. The reduction was due primarily to the inclusion of expenses from Seabrook during the fiscal year ended March 31, 2003. Seabrook was sold in November 2002. Partially offsetting the decreased expense for the fiscal year ended March 31, 2004 were increased costs due to a voluntary early retirement program provided to employees which is discussed in Note H, “Employee Benefits” in Item 8 Financial Statements and Supplemental Data.
Operation and maintenance expense decreased approximately $1 million for the fiscal year ended March 31, 2003, compared with the prior year. The decreased cost is primarily the result of the sale of Seabrook in November 2002. The decrease was partially offset by increased costs from a refueling outage at Seabrook prior to the sale and increased transmission maintenance costs.
Purchased power contract buyout and nuclear fuel amortization expense for the fiscal year ended March 31, 2004 increased approximately $5 million compared with the prior year. The increase was due primarily to the amortization of scheduled purchased power contract buyout cost increases based upon rate agreements. The increases were partially offset by decreased nuclear fuel amortization cost for the fiscal year ended March 31, 2004, as compared with the prior year due to the sale of Seabrook in November 2002.
Purchased power contract buyout and nuclear fuel amortization expense for the fiscal year ended March 31, 2003 increased approximately $2 million as compared with the prior year. The increase was due primarily to the amortization of scheduled purchased power contract buyout cost increases based upon rate agreements. The increase was partially offset by decreased nuclear fuel amortization due to the sale of the Seabrook plant in November 2002.
Other depreciation and amortization expense for the fiscal year ended March 31, 2004, decreased approximately $14 million compared with the prior year. The decrease was due primarily to reduced decommissioning expenses as a result of the sale of Seabrook in November 2002.
Other depreciation and amortization expense for the fiscal year ended March 31, 2003, increased by approximately $7 million compared with the prior year. The increase is due to the Company’s payment in November 2002 of approximately $5 million to the Seabrook decommissioning trust fund for its share of the balance needed to raise the fund to the level required in the Seabrook sales agreement.
Equity in income of nuclear power companies decreased approximately $3 million during the fiscal year ended March 31, 2004 compared to the same period in the prior year due to the redemption of the Company’s interest in the Vermont Yankee Nuclear Power Corporation.
Other income net increased approximately $2 million during the fiscal year ended March 31, 2004 as compared with the prior year due to increased interest income and the sale of non-utility property.
Interest expense for the fiscal years ended March 31, 2004 and 2003, decreased approximately $2 million and $6 million, respectively, compared with fiscal 2003 and 2002, respectively, primarily due to decreased interest rates on the Company’s variable rate long-term debt.
LIQUIDITY AND CAPITAL RESOURCES
At March 31, 2004 the Company’s principal sources of liquidity included cash and cash equivalents of approximately $230 million and accounts receivable of approximately $155 million. The Company has a working capital balance of approximately $304 million.
Net cash flows provided by operating activities for the fiscal year ended March 31, 2004, was approximately $84 million.
Net cash flows used in investing activities for the fiscal year ended March 31, 2004 was approximately $25 million. Cash expenditures for the period were due primarily to transmission utility plant expenditures offset by the one time receipt of proceeds from the redemption of the Company’s investment in the Vermont Yankee Nuclear Power Corporation in November 2004.
Net cash flows used in financing activities for the fiscal year ended March 31, 2004 was approximately $77 million. Cash expenditures for the period were due primarily to dividends paid on common and preferred stock.
At March 31, 2004 the Company had no short-term debt outstanding. The Company has regulatory approval to issue up to $375 million of short-term debt. National Grid USA and certain subsidiaries, including the Company, with regulatory approval, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowing companies pay interest at a rate designed to approximate the cost of outside short-term borrowings. Companies that invest in the pool share the interest earned on a basis proportionate to their average monthly investment in the money pool. Funds may be withdrawn from or repaid to the pool at any time without prior notice.
At March 31, 2004 the Company had lines of credit and standby bond purchase facilities with banks totaling $439 million which is available to provide liquidity support for $410 million of the Company’s long-term bonds in tax-exempt commercial paper mode, and for other corporate purposes. The Company's line of credit expires and is renewed each December. The Company's standby bond purchase facility expires and is renewed each September. There were no borrowings under these lines of credit at March 31, 2004. Fees are paid on the lines and facilities in lieu of compensating balances.
Contractual Obligations: The Company’s capital obligations consist of amounts for purchased power from Vermont Yankee, long-term debt maturities, construction expenditures and operating leases. Payments by fiscal year are as follows:
Net cash flows provided by operating activities for the fiscal year ended March 31, 2004, was approximately $84 million.
Net cash flows used in investing activities for the fiscal year ended March 31, 2004 was approximately $25 million. Cash expenditures for the period were due primarily to transmission utility plant expenditures offset by the one time receipt of proceeds from the redemption of the Company’s investment in the Vermont Yankee Nuclear Power Corporation in November 2004.
Net cash flows used in financing activities for the fiscal year ended March 31, 2004 was approximately $77 million. Cash expenditures for the period were due primarily to dividends paid on common and preferred stock.
At March 31, 2004 the Company had no short-term debt outstanding. The Company has regulatory approval to issue up to $375 million of short-term debt. National Grid USA and certain subsidiaries, including the Company, with regulatory approval, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowing companies pay interest at a rate designed to approximate the cost of outside short-term borrowings. Companies that invest in the pool share the interest earned on a basis proportionate to their average monthly investment in the money pool. Funds may be withdrawn from or repaid to the pool at any time without prior notice.
At March 31, 2004 the Company had lines of credit and standby bond purchase facilities with banks totaling $439 million which is available to provide liquidity support for $410 million of the Company’s long-term bonds in tax-exempt commercial paper mode, and for other corporate purposes. The Company's line of credit expires and is renewed each December. The Company's standby bond purchase facility expires and is renewed each September. There were no borrowings under these lines of credit at March 31, 2004. Fees are paid on the lines and facilities in lieu of compensating balances.
Contractual Obligations: The Company’s capital obligations consist of amounts for purchased power from Vermont Yankee, long-term debt maturities, construction expenditures and operating leases. Payments by fiscal year are as follows:
| Contractual Obligations due in: | ||||||
(In millions) | Total | Less than 1 year | 1-3 years | 3-5 years | More than 5 years | |
Long term debt maturities | $410 | $ - | $ - | $ - | $ 410 | |
Vermont Yankee purchased power commitments | 377 | 44 | 88 | 88 | 157 | |
Construction expenditures* | 66 | 66 | * | * | * | |
Operating leases | 1 | - | 1 | - | ||
| Total | $854 | $110 | $89 | $88 | $567 | |
* Budgeted amount in which substantial commitments have been made. Amounts beyond 1 year are budgetary in nature and not considered contractual obligations and are therefore not included. |
Expected contributions to the Company’s pension and post-retirement benefit plans trusts (as disclosed in Item 8. Financial Statements and Supplementary Data - Note H. “Employee Benefits”) are not included on the above table.
In connection with the sale of Vermont Yankee the Company has entered into a power contract to buy 22.5 percent of the entitlement of the Vermont Yankee generation until 2012. At the same time the Company has entered into a contract with a third party to sell the entire 22.5 percent of the Vermont Yankee entitlement and recover 100 percent of its purchased power contract costs. The Company sells the power to the third party at its cost and thus does not recognize any financial impact from the agreement on its financial statements. The Company matches the cost of the power contract with the revenue from the sale of the power to the third party on its income statement.
Utility Plant Expenditures: Cash expenditures for the Company for utility plant totaled approximately $41 million for the fiscal year ended March 31, 2004 and were primarily transmission-related. The funds necessary for utility plant expenditures during the period were primarily provided by internal funds. All of the Company’s construction expenditures during the fiscal years ended March 2005 through March 2007 are expected to be financed by internally generated funds.
Cost of Removal: The Company estimates it has collected over time approximately $19 million and $18 million for cost of removal through March 31, 2004 and 2003, respectively. For more information about the cost of removal see the discussion of “New Accounting Standards” below.
New Accounting Standards: In June 2001, the Financial Accounting Standards Board (FASB) issued Statement on Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations” (FAS 143). FAS 143 provides the accounting requirements for retirement obligations associated with tangible long-lived assets. FAS 143 is effective for fiscal years beginning after June 15, 2002. The Company adopted FAS 143 during the fiscal year ended March 31, 2004. For a further discussion of the cost of removal see Note L “Cost of Removal”.
The Company does not have any material asset retirement obligations arising from legal obligations as defined under FAS 143. However, under Company’s current and prior rate plans it has collected through rates an implied cost of removal for its plant assets. This cost of removal collected from customers differs from the FAS 143 definition of an asset retirement obligation in that these collections are for costs to remove an asset when it is no longer deemed usable (i.e. broken or obsolete) and not necessarily from a legal obligation.
The cost of removal collected from customers has historically been embedded within accumulated depreciation (as these costs have charged over time through depreciation expense). With the adoption of FAS 143 the Company has reclassified the cost of removal collections to a regulatory liability account to more properly reflect the future usage of these collections. The Company estimates it has collected over time approximately $19 million and $18 million for cost of removal through March 31, 2004 and 2003, respectively.
In December 2003 the FASB revised SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (FAS 132-R). FAS 132-R retains the disclosure requirements contained in the original statement and adds new disclosures about the assets, obligations, cash flows, and net periodic benefit cost of defined benefit pension and other defined benefit postretirement plans. FAS 132-R is effective for fiscal years ending after December 15, 2003 and for interim periods beginning thereafter. The Company adopted FAS 132-R during the fiscal year ended march 31, 2004. This standard does not change the measurement or recognition of the aforementioned plans and, as such, the adoption of this statement has not had any effect on the Company’s financial position, results of operations, or cash flows.
In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities, an interpretation of ARB 51” (FIN 46). FIN 46 requires the consolidation of entities in which an enterprise absorbs a majority of the entity’s expected losses, receives a majority of the entity’s expected residual returns, or both, as a result of ownership, contractual or other financial interest in the entity. Historically, entities have generally been consolidated by an enterprise when it has a controlling financial interest through ownership of a majority voting interest in the entity. The objectives of FIN 46 are to provide guidance on the identification of variable interest entities (VIEs) for which control is achieved through means other than a controlling financial interest, and how to determine which business enterprise, as the primary beneficiary, should consolidate the VIE. This new model for consolidation applies to an entity in which either (1) the entity lacks sufficient equity to absorb expected losses without additional subordinated financial support or (2) its at-risk equity holders as a group are not able to make decisions that have a significant impact on the success or failure of the entity’s ongoing activities.
In December 2003, the FASB modified FIN 46 with FIN 46-R to make certain technical corrections to the standard and to address certain implementation issues. FIN 46, as originally issued, was effective immediately for VIEs created or acquired after January 31, 2003. FIN 46-R delayed the effective date of the interpretation to no later than March 31, 2004 (for calendar-year enterprises), except for special purpose entities for which the effective date was December 31, 2003. The adoption of FIN 46-R has not had a material impact on the Company's financial position, results of operations, or cash flows.
In January 2004, the FASB issued Staff Position No. 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act)” (FSP 106-1). FSP 106-1 is effective for annual fiscal periods ending after December 7, 2003. FSP 106-1 permits employers that sponsor postretirement benefit plans (plan sponsors) that provide prescription drug benefits to retirees to make a one-time election to defer accounting for any effects of the Act. FSP 106-1 requires all plan sponsors to provide certain disclosures, regardless of whether they choose to account or defer accounting. If deferral is elected, the deferral must remain in effect until the earlier of (1) the issuance of guidance by the FASB on how to account for the federal subsidy to be provided to plan sponsors under the Act or (2) the remeasurement of plan assets and obligations subsequent to January 31, 2004. The Company has decided not to make an election until further accounting guidance is issued by the FASB. The measurement of the accumulated postretirement benefit obligation and net postretirement benefit cost in the financial statements and accompanying notes do not reflect the effect of the Act on the Company's postretirement benefit plans.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk: The Company's major financial market risk exposure is changing interest rates. Changing interest rates will affect interest paid on variable rate debt. At March 31, 2004 and 2003, respectively, the Company's tax exempt variable rate long-term debt had a carrying value of approximately $410 million. While the ultimate maturity dates of the underlying loan agreements range from 2015 through 2022, this debt is issued in tax exempt commercial paper mode. The various components that comprise this debt are issued for periods ranging from one day to 270 days, and are remarketed through remarketing agents at the conclusion of each period. The weighted average variable interest rate for the fiscal year ended March 31, 2004 was approximately 1.18 percent.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
A. FINANCIAL STATEMENTS
- Report of Independent Registered Public Accounting Firm
- Statements of Income, Statements of Retained Earnings and Statements of Comprehensive Income for the fiscal years ended March 31, 2004, 2003 and 2002
- Balance Sheets at March 31, 2004 and 2003
- Statements of Cash Flows for the fiscal years ended March 31, 2004, 2003 and 2002
- Notes to Financial Statements
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors of
In our opinion, the accompanying balance sheets and the related statements of income, of comprehensive income, of retained earnings and of cash flows present fairly, in all material respects, the financial position of New England Power Company at March 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended March 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Boston, Massachusetts
May 6, 2004, except for the Town of Norwood Dispute
section of Note D, as to which the date is June 9, 2004
New England Power Company
Statements of Income
Statements of Income
Year Ended March 31, | |||
(In thousands) | 2004 | 2003 | 2002 |
Operating revenue, principally from affiliates (Note A) | $457,811 | $514,006 | $560,418 |
Operating expenses: | |||
Fuel for generation | 4,503 | 5,209 | 1,991 |
Purchased electricity : | |||
Contract termination and nuclear unit shutdown charges | 145,517 | 161,583 | 174,810 |
Other | 14,387 | 31,389 | 68,675 |
Other operation | 55,814 | 49,986 | 56,769 |
Maintenance | 14,498 | 22,666 | 17,266 |
Depreciation and amortization: (Note A) | |||
Purchased power contract buyout and nuclear fuel | 65,462 | 60,158 | 58,176 |
Other | 23,259 | 37,497 | 30,601 |
Taxes, other than income taxes: (Note K) | 16,957 | 18,868 | 18,183 |
Income taxes (Note G) | 42,610 | 45,429 | 47,593 |
Total operating expenses | 383,007 | 432,785 | 474,064 |
Operating income | 74,804 | 81,221 | 86,354 |
Other income(expense): | |||
Allowance for equity funds used during construction | 680 | 467 | 1,077 |
Equity in income of nuclear power companies | 1,675 | 4,554 | 3,332 |
Other income, net | 2,533 | 76 | 791 |
Operating and other income | 79,692 | 86,318 | 91,554 |
Interest: | |||
Interest on long-term debt | 5,875 | 7,694 | 11,434 |
Other interest | 1,363 | 1,231 | 3,509 |
Allowance for borrowed funds used during construction | (36) | (34) | (163) |
Total interest | 7,202 | 8,891 | 14,780 |
Net income | $72,490 | $ 77,427 | $ 76,774 |
The accompanying notes are an integral part of these financial statements.
New England Power Company
Statements of Comprehensive Income
New England Power Company
Statements of Comprehensive Income
Year Ended March 31, | |||
(In thousands) | 2004 | 2003 | 2002 |
Net income | $ 72,490 | $ 77,427 | $ 76,774 |
Unrealized gain (loss) on securities, net of tax | 317 | (120) | 35 |
Comprehensive income (Note A) | $ 72,807 | $ 77,307 | $ 76,809 |
New England Power Company
Statements of Retained Earnings
Statements of Retained Earnings
Year Ended March 31, | |||
(In thousands) | 2004 | 2003 | 2002 |
Retained earnings at beginning of period | $ 214,154 | $ 136,798 | $ 60,110 |
Net income | 72,490 | 77,427 | 76,774 |
Dividends declared on cumulative preferred stock | (75) | (82) | (86) |
Dividends declared on common stock | (77,250) | ||
Gain on redemption of preferred stock | - | 11 | - |
Retained earnings at end of period | $ 209,319 | $ 214,154 | $136,798 |
The accompanying notes are an integral part of these financial statements.
New England Power Company
Balance Sheets
New England Power Company
Balance Sheets
At March 31 (In thousands) | 2004 | 2003 |
Assets | ||
Utility plant, at original cost | $ 878,824 | $ 842,823 |
Less accumulated provisions for depreciation and amortization | 240,203 | 228,274 |
638,621 | 614,549 | |
Construction work in progress | 12,852 | 12,639 |
Net utility plant | 651,473 | 627,188 |
Goodwill | 338,188 | 338,188 |
Investments: | ||
Equity investments in nuclear power companies (Note C) | 18,305 | 36,749 |
Nonutility property and other investments | 11,290 | 10,922 |
Total investments | 29,595 | 47,671 |
Current assets: | ||
Cash and cash equivalents (including $229,400 and $224,150 with affiliates) | 229,716 | 247,678 |
Accounts receivable: | ||
Affiliated companies | 51,131 | 53,112 |
Others (less reserves of $153 and $153) | 104,338 | 83,657 |
Fuel, materials, and supplies, at average cost | 2,054 | 1,796 |
Prepaid and other current assets | 1,370 | 141 |
Regulatory assets – purchased power obligations | 102,490 | 107,707 |
Total current assets | 491,099 | 494,091 |
Regulatory assets (Note B) | 1,136,903 | 1,324,546 |
Additional minimum pension liability regulatory asset (Note B) | 62,454 | 92,070 |
Prepaid pension asset | 47,245 | 45,225 |
Deferred charges and other assets | 5,374 | 14,697 |
Total assets | $2,762,331 | $2,983,676 |
The accompanying notes are an integral part of these financial statements.
New England Power Company
Balance Sheets
New England Power Company
Balance Sheets
At March 31 (In thousands) | 2004 | 2003 |
Capitalization and Liabilities | ||
Capitalization: | ||
Common stock, par value $20 per share, Authorized - 6,449,896 shares Outstanding – 3,619,896 shares | $ 72,398 | $ 72,398 |
Other paid-in capital | 731,974 | 731,974 |
Retained earnings | 209,319 | 214,154 |
Accumulated other comprehensive income(loss) (Note A) | 87 | (230) |
Total common equity | 1,013,778 | 1,018,296 |
Cumulative preferred stock, par value $100 per share (Note I) | 1,274 | 1,295 |
Long-term debt (Note E) | 410,297 | 410,291 |
Total capitalization | 1,425,349 | 1,429,882 |
Current liabilities: | ||
Accounts payable (including $34,814 and $22,798 to affiliates) | 59,620 | 71,402 |
Accrued liabilities: | ||
Taxes | 18,337 | 65,311 |
Interest | 532 | 357 |
Purchased power obligations | 102,490 | 107,707 |
Other accrued expenses | 5,737 | 4,506 |
Dividends payable | 19 | 19 |
Total current liabilities | 186,735 | 249,302 |
Deferred federal and state income taxes | 233,852 | 258,492 |
Unamortized investment tax credits | 7,885 | 8,326 |
Accrued Yankee nuclear plant costs (Note D) | 269,997 | 252,392 |
Purchased power obligations | 293,296 | 399,699 |
Additional minimum pension liability | 39,952 | 65,441 |
Other reserves and deferred credits | 305,265 | 320,142 |
Commitments and contingencies (Note D) | ||
Total capitalization and liabilities | $2,762,331 | $2,983,676 |
The accompanying notes are an integral part of these financial statements.
New England Power Company
Statements of Cash Flows
New England Power Company
Statements of Cash Flows
Year Ended March 31, | |||
(In thousands) | 2004 | 2003 | 2002 |
Operating activities: | |||
Net income | $ 72,490 | $ 77,427 | $ 76,774 |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Purchased power contract buyout and nuclear fuel amortization | 65,462 | 60,158 | 58,176 |
Other depreciation and amortization | 23,259 | 37,497 | 30,601 |
Deferred income taxes and investment tax credits, net | (23,065) | 2,386 | (16,072) |
Allowance for funds used during construction | (716) | (501) | (1,240) |
Changes in assets and liabilities: | |||
Decrease (increase) in accounts receivable, net | (18,700) | (27,901) | 16,806 |
Decrease in regulatory assets | 177,228 | 82,827 | 157,257 |
Decrease (increase) in prepaid and other current assets | (1,514) | 5,680 | 723 |
Decrease in accounts payable | (6,936) | (4,912) | (18,659) |
Decrease in purchased power contract obligations | (111,620) | (151,533) | (127,069) |
Increase (decrease) in other current liabilities | (45,568) | 51,940 | (30,327) |
Decrease in other non-current liabilities | (55,578) | (30,538) | (45,479) |
Other, net | 9,776 | (639) | (1,981) |
Net cash provided by operating activities | $ 84,518 | $ 101,891 | $ 99,510 |
Investing activities: | |||
Proceeds from sale of generating assets, net | - | $ 84,300 | $ 25,000 |
Return of capital from equity investment | 11,977 | - | - |
Plant expenditures, excluding allowance for funds used during construction | (41,318) | (41,980) | (46,927) |
Other investing activities | 4,207 | 226 | 3,610 |
Net cash provided by (used in) investing activities | $(25,134) | $ 42,546 | $(18,317) |
The accompanying notes are an integral part of these financial statements.
New England Power Company
Statements of Cash Flows – (continued)
Year Ended March 31, | |||
(In thousands) | 2004 | 2003 | 2002 |
Financing activities: | |||
Dividends paid on common stock | $(77,250) | $ - | $ - |
Dividends paid on preferred stock | (75) | (85) | (86) |
Preferred stock – retirements | (21) | (141) | - |
Net cash used in financing activities | $(77,346) | $ (226) | $ (86) |
Net increase (decrease) in cash and cash equivalents | $(17,962) | $ 144,211 | $ 81,107 |
Cash and cash equivalents at beginning of period | $247,678 | $ 103,467 | $ 22,360 |
Cash and cash equivalents at end of period | $229,716 | $ 247,678 | $103,467 |
Supplementary Information: | |||
Interest paid, less amounts capitalized | $ 5,975 | $ 7,535 | $ 10,734 |
Federal and state income taxes paid (refunded) | $ 114,915 | $ (4,467) | $ 90,810 |
Dividends received from investments at equity | $ 5,169 | $ 5,984 | $ 3,812 |
Non-cash Supplementary Information: | |||
Increases in Yankee decommissioning costs | $ 57,306 | $ 104,365 | $ 11,308 |
Additional minimum pension costs | $ 30,335 | $ 94,397 | $ - |
Cost of removal | $ 1,000 | $ 17,633 | $ - |
The accompanying notes are an integral part of these financial statements.
New England Power
Notes to Financial Statements
Notes to Financial Statements
NOTE A - ACCOUNTING POLICIES
Basis of Presentation: New England Power Company (the Company or NEP), a wholly owned subsidiary of National Grid USA, is a Massachusetts corporation qualified to do business in Massachusetts, New Hampshire, Connecticut, Rhode Island, Maine, and Vermont. The Company is subject, for certain purposes, to the jurisdiction of the regulatory commissions of these states (except Connecticut), the Securities and Exchange Commission (SEC), under the Public Utility Holding Company Act of 1935 (1935 Act), the Federal Energy Regulatory Commission (FERC), and the Nuclear Regulatory Commission (NRC). The Company’s accounting policies conform to generally accepted accounting principles (GAAP) in the United States of America, including the accounting principles for rate-regulated entities, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities.
Nature of Operations: The Company's business is primarily the transmission of electricity in wholesale quantities to other electric utilities, principally its distribution affiliates Granite State Electric Company, Massachusetts Electric Company, Nantucket Electric Company, and The Narragansett Electric Company. The Company’s transmission facilities are part of National Grid USA’s transmission operations, which are represented under the name National Grid Transmission USA. In addition, the Company holds a minority joint ownership interest in one fossil fuel generating unit. The Company also owns minority equity interests in three nuclear generating companies (the Yankees), which own generating facilities that are permanently retired and are conducting decommissioning operations. Additionally the Company sold a minority interest in a jointly owned nuclear generating unit in November 2002 and redeemed its minority ownership interest in another nuclear generating company in November 2003.
Goodwill: The Company’s goodwill is primarily the result of two mergers that were accounted for by the purchase accounting method: the merger of New England Electric System and a subsidiary of National Grid Transco plc (formerly National Grid Group plc) on March 22, 2000 and the acquisition of Eastern Utilities Associates by National Grid USA (a wholly owned subsidiary of National Grid Transco plc) on April 19, 2000. The approximately $2.1 billion of goodwill that resulted from the transactions was pushed down and reflected on the financial statements of the National Grid USA subsidiaries, including $338 million allocated to the Company.
The Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets” (FAS 142) effective April 1, 2001. In accordance with FAS 142, goodwill can no longer be amortized and must be reviewed for impairment at least annually and when events or circumstances indicates that the asset may be impaired. The Company utilized a discounted cash flow approach incorporating its most recent business plan forecasts in the performance of the annual goodwill impairment test. The result of the annual analysis determined that no impairment adjustment to the goodwill carrying value was required.
Use of Estimates: The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities
and disclosure of contingent liabilities at the date of the Financial Statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Utility Plant: The cost of additions to utility plant and replacements of retirement units of property are capitalized. Costs include direct material, labor, overhead and Allowance for Funds Used During Construction. Replacement of minor items of utility plant and the cost of current repairs and maintenance are charged to expense. Whenever utility plant is retired, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation.
Allowance for Funds Used During Construction (AFUDC): The Company capitalizes AFUDC as part of construction costs. AFUDC represents an allowance for the cost of funds used to finance construction. AFUDC is capitalized in "Utility plant" with offsetting noncash credits to "Other income" and "Interest”. This method is in accordance with an established rate-making practice under which a utility is permitted a return on, and the recovery of, prudently incurred capital costs through their ultimate inclusion in rate base and in the provision for depreciation. The composite AFUDC rates were 7.8 percent, 7.7 percent and 8.1 percent for the years ended March 31, 2004, 2003, and 2002, respectively.
Depreciation and Amortization: The depreciation and amortization expense included in the statements of income is composed of the following:
Year Ended March 31, | |||
(In thousands) | 2004 | 2003 | 2002 |
Purchased Power contract buyout and nuclear fuel amortization: | |||
Purchased power contract buyout | $65,462 | $58,490 | $54,739 |
Nuclear fuel | - | 1,668 | 3,437 |
Total purchased power contract buyout and nuclear fuel amortization | $65,462 | $60,158 | $58,176 |
Other depreciation and amortization: | |||
Depreciation - transmission related | $17,863 | $17,079 | $16,238 |
Depreciation - all other | 148 | 1,011 | 1,093 |
Nuclear decommissioning costs | - | 7,171 | 2,394 |
Amortization: | |||
Regulatory assets covered by contract termination charges (Note B) | 5,248 | 12,236 | 10,876 |
Total other depreciation and amortization expense | $23,259 | $37,497 | $ 30,601 |
Depreciation is provided annually on a straight-line basis. The provision for depreciation as a percentage of weighted average depreciable transmission property was 2.3 percent for all periods presented. Amortization of purchase power contracts and regulatory assets covered by contract termination charges (CTCs) are provided over the recovery period as allowed in the applicable regulatory agreement.
Revenues: The Company has three primary sources of revenue: transmission, stranded investment recovery, and nuclear. Transmission revenues are based on a formula rate that recovers the Company's actual costs plus a return on actual investment. Stranded investment recovery revenues are in the form of a CTC to former all-requirements customers of the Company in connection with the Company's divestiture of its electricity generation investments. Nuclear revenues include sales of electricity and recovery of a portion of net operating profit/ (loss) from the Company's operating nuclear units prior to their sale during fiscal 2003.
Federal and State Income Taxes: Income taxes have been computed utilizing the asset and liability approach that requires the recognition of deferred tax assets and liabilities for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities (see Note G).
Service Company Charges: National Grid USA Service Company, Inc., an affiliated service company operating pursuant to the provisions of Section 13 of the 1935 Act, furnished services to the Company at the cost of such services. These costs amounted to approximately $64 million, $46 million and $43 million including capitalized construction costs of $15 million, $10 million and $15 million for the years ended March 31, 2004, 2003 and 2002, respectively.
Cash and Cash Equivalents: The Company classifies short-term investments with a maturity at purchase date of 90 days or less as cash equivalents.
Comprehensive Income: Comprehensive income consists of net income and other gains and losses affecting common equity that, under generally accepted accounting principles are excluded from net income. For the Company, the components of accumulated other comprehensive income consist of unrealized gains and losses on marketable equity investments. For the fiscal years ended March 31, 2004, 2003, and 2002 tax expense/(benefit) related to comprehensive income were approximately $205,000, ($78,000) and $22,000, respectively.
New Accounting Standards: In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations” (FAS 143). FAS 143 provides the accounting requirements for retirement obligations associated with tangible long-lived assets. FAS 143 is effective for fiscal years beginning after June 15, 2002. The Company adopted FAS 143 during the fiscal year ended March 31, 2004. The adoption of this statement did not have a material impact on the Company’s financial position, results of operations, or cash flows. For a further discussion of the cost of removal see Note L “Cost of Removal”.
In December 2003 the FASB revised SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (FAS 132-R). FAS 132-R retains the disclosure requirements contained in the original statement and adds new disclosures about the assets, obligations, cash flows, and net periodic benefit cost of defined benefit pension and other defined benefit postretirement plans. FAS 132-R is effective for fiscal years ending after December 15, 2003 and for interim periods beginning thereafter. The Company adopted FAS 132-R during the fiscal year ended March 31, 2004. This standard does not change the measurement or recognition of the aforementioned plans and, as such, the adoption of this statement has not had any effect on the Company’s financial position, results of operations, or cash flows.
In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities, an interpretation of ARB 51” (FIN 46). FIN 46 requires the consolidation of entities in which an enterprise absorbs a majority of the entity’s expected losses, receives a majority of the entity’s expected residual returns, or both, as a result of ownership, contractual or other financial interest in the entity. Historically, entities have generally been consolidated by an enterprise when it has a controlling financial interest through ownership of a majority voting interest in the entity. The objectives of FIN 46 are to provide guidance on the identification of variable interest entities (VIEs) for which control is achieved through means other than a controlling financial interest, and how to determine which business enterprise, as the primary beneficiary, should consolidate the VIE. This new model for consolidation applies to an entity in which either (1) the entity lacks sufficient equity to absorb expected losses without additional subordinated financial support or (2) its at-risk equity holders as a group are not able to make decisions that have a significant impact on the success or failure of the entity’s ongoing activities.
In December 2003, the FASB modified FIN 46 with FIN 46-R to make certain technical corrections to the standard and to address certain implementation issues. FIN 46, as originally issued, was effective immediately for VIEs created or acquired after January 31, 2003. FIN 46-R delayed the effective date of the interpretation to no later than March 31, 2004 (for calendar-year enterprises), except for special purpose entities for which the effective date was December 31, 2003. The adoption of FIN 46-R has not had a material impact on the Company's financial position, results of operations, or cash flows.
In January 2004, the FASB issued Staff Position No. 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act)” (FSP 106-1). FSP 106-1 is effective for annual fiscal periods ending after December 7, 2003. FSP 106-1 permits employers that sponsor postretirement benefit plans (plan sponsors) that provide prescription drug benefits to retirees to make a one-time election to defer accounting for any effects of the Act. FSP 106-1 requires all plan sponsors to provide certain disclosures, regardless of whether they choose to account or defer accounting. If deferral is elected, the deferral must remain in effect until the earlier of (1) the issuance of guidance by the FASB on how to account for the federal subsidy to be provided to plan sponsors under the Act or (2) the remeasurement of plan assets and obligations subsequent to January 31, 2004. The Company has decided not to make an election until further accounting guidance is issued by the FASB. The measurement of the accumulated postretirement benefit obligation and net postretirement benefit cost in the financial statements and accompanying notes do not reflect the effect of the Act on the Company's postretirement benefit plans.
Reclassifications: Certain amounts from prior years have been reclassified in the accompanying financial statements to conform to the 2004 presentation. In particular, offsetting non-cash changes in balance sheet captions were reclassified within the operating activities section of the fiscal 2003 and 2002 Statements of Cash Flows. These items have been reclassified into the “Other net”, cash flows line of the operating activities section of the Statements of Cash Flows. These reclassifications had no impact on “Net cash provided by operating activities”.
NOTE B – RATE AND REGULATORY
Because electricity rates have historically been based on a utility's costs, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. The Company applies the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (FAS 71), which requires regulated entities, in appropriate circumstances, to establish regulatory assets or liabilities, and thereby defer the income statement impact of certain charges or revenues because they are expected to be collected or refunded through future customer billings.
The Company has received authorization from the FERC to recover through CTCs substantially all of the costs associated with its former generating business not recovered through the divestiture. Additionally, FERC enables transmission companies to recover their specific costs of providing transmission service. Therefore, substantially all of the Company’s business, including the recovery of its stranded costs, remains under cost-based rate regulation.
Under settlement agreements, the Company is permitted to recover costs associated with its former generating investments (nuclear and nonnuclear) and related contractual commitments that were not recovered through the sale of those investments (stranded costs). Stranded costs are recovered from the Company’s wholesale customers with whom it has settlement agreements through a CTC which the affiliated former wholesale customers recover through delivery charges to distribution customers. The Company earns a return on equity (ROE) of approximately 9.7 percent on stranded cost recovery. Most stranded costs will be fully recovered through CTCs by the end of 2010. The Company’s stranded cost obligation related to the above-market cost of purchased power contracts and nuclear decommissioning costs are recovered through the CTC as such costs are actually incurred. The Company, under certain settlement agreements, earns incentives based on successful mitigation of its stranded costs and these incentives supplement the Company’s ROE.
As a result of applying FAS 71, the Company has recorded a regulatory asset for the costs that are recoverable from customers through CTCs and regulatory liabilities for amounts owed to customers. The following table details regulatory assets and liabilities summarized in the Company’s financial statements:
March 31, | ||
(In thousands) | 2004 | 2003 |
Regulatory assets – current | ||
Purchased power obligations | $ 102,490 | $ 107,707 |
Total current regulatory assets | $ 102,490 | $ 107,707 |
Regulatory assets – non-current | ||
Purchased power payment obligations | $ 293,296 | $ 399,699 |
Purchased power contracts bought-out | 255,724 | 307,974 |
Accrued Yankee nuclear decommissioning costs | 269,997 | 252,392 |
Additional minimum pension liability (Note H) | 62,454 | 92,070 |
Other regulatory assets | 317,886 | 364,481 |
Total regulatory assets non-current | $ 1,199,357 | $ 1,416,616 |
Total regulatory assets | $ 1,301,847 | $ 1,524,323 |
Regulatory liabilities included in other reserves and deferred credits: | ||
CTC related liabilities | $ (167,299) | $ (196,178) |
Revaluation – Pensions and other post-retirement employee benefits | (47,682) | (51,433) |
Total regulatory liabilities | $ (214,981) | $ (247,611) |
Net regulatory assets | $ 1,086,866 | $ 1,276,712 |
In conjunction with the divestiture of its generating business, the Company transferred its entitlement to power procured under several long-term contracts (the Contracts) to US Gen New England Inc. (USGen), Constellation Power Source, Inc. and Transcanada Power Marketing Ltd. (the Buyers). The Buyers agreed to fulfill the Company’s performance and payment obligations under the Contracts. At the same time the Company agreed to pay the Buyers a fixed amount monthly for the above-market cost of the Contracts. Annually these fixed payments by the Company average approximately $106 million through December 2007 decreasing to approximately $12 million for 2008 then decreasing to approximately $3 million annually from 2009 to 2014. The net present value of these fixed monthly payments is recorded as a liability with an equal balance recorded in regulatory assets representing the future collection of the liability from ratepayers. At March 31, 2004 and 2003, the net present value of the liability for the fixed monthly payment is approximately $398 million and $507 million, respectively.
On July 8, 2003, PG&E National Energy Group (USGen’s parent company) and USGen separately filed for bankruptcy protection. In the event that the bankruptcy court relieved USGen from meeting its obligations under the purchased power transfer agreement (the Transfer Agreement), the Company would resume the performance and payment obligations under the Contracts. At that point the Company would remove the liability and a corresponding regulatory asset for the above market cost of the Contracts from its balance sheet. At March 31, 2004, the Company’s capitalized cost of the above market portion of the USGen Contracts is approximately $332 million. To date USGen continues to perform under the Transfer Agreement. Resumption of the performance payment obligations in the case of a default by USGen would not materially affect the results of operations, as the Company would continue to pass the above-market cost of the Contracts to customers through a CTC.
Separate from the Transfer Agreement, USGen asked the bankruptcy court to relieve it of obligations under Hydro Quebec transmission line agreements (HQ Contracts) under which it was obligated to reimburse the Company for monthly costs of approximately $1 million. USGen and the Company entered into a stipulation under which USGen continued to reimburse the Company through April 1, 2004. As of April 2, 2004, the Company resumed performance and payment under the HQ Contracts. The Company has a claim against USGen in bankruptcy for its damages. The Company’s resumption of performance and payment obligations will not affect the results of operations, as the Company will be able to recover any remaining costs through CTC’s from its customers.
Pension: The Company has recognized an additional minimum pension liability for the years ended March 31, 2004 and 2003 of approximately $40 million and $65 million, respectively, on its balance sheet in other reserves and deferred credits to reflect its under funded pension obligation. Due to the nature of its rate plan the Company has recorded a regulatory asset representing the future collection of the liability from rate payers.
The Company has also recognized an allocated share of the additional minimum pension liability of its affiliated service company of approximately $24 million and $29 million at March 31, 2004 and 2003, respectively, which is recorded in accounts payable on the balance sheet with an offsetting charge to regulatory assets.
NOTE C – NUCLEAR INVESTMENTS
Yankee Nuclear Power Companies: At March 31, 2004, the Company has minority interests in the Yankees, that own nuclear generating units that have been permanently retired and are conducting decommissioning operations. These ownership interests are accounted for on the equity method. The Company also had a minority interest in a fourth company, Vermont Yankee Nuclear Power Corporation (Vermont Yankee) which sold its nuclear generating unit in July 2002. The Company has power contracts with each of the Yankees that require the Company to pay an amount equal to its share of total fixed and operating costs of the plant plus a return on equity. The Company’s share of the expenses of the Yankees is accounted for in “Purchased electricity” on the income statement.
The following table summarizes financial information furnished by the Yankees and Vermont Yankee:
Year Ended March 31, | |||
(In thousands) | 2004 | 2003 | 2002 |
Operating revenue | $ 270,392 | $ 283,609 | $ 284,663 |
Net income | $ 8,174 | $ 20,828 | $ 14,711 |
Company’s equity in net income | $ 1,674 | $ 4,554 | $ 3,332 |
Net plant | $ 2,099 | $ 2,132 | $ 143,182 |
Other assets | $ 1,470,306 | $ 1,608,191 | $ 1,812,032 |
Liabilities and debt | $(1,387,527) | $(1,447,168) | $(1,775,130) |
Net assets | $ 84,878 | $ 163,155 | $ 180,084 |
Company’s equity in net assets | $ 18,473 | $ 36,749 | $ 40,339 |
Company's purchased electricity: | |||
Yankees and Vermont Yankee | $ 37,507 | $ 61,582 | $ 57,451 |
At March 31, 2004 and 2003, approximately $6 million of undistributed earnings of the Yankees were included in the Company’s retained earnings.
NOTE D – COMMITMENTS AND CONTINGENCIES
Decommissioning Nuclear Units: The Yankees have been permanently retired and are conducting decommissioning operations. These three units are as follows:
| The Company’s Investment as of March, 31 2004 | Future Estimated Billings to the Company | ||||
Unit | % | $(millions) | Date Retired | $(millions) | |
Yankee Atomic | 34.5 | 0.3 | Feb 1992 | 58 | |
Connecticut Yankee | 19.5 | 8.5 | Dec 1996 | 128 | |
Maine Yankee | 24.0 | 9.5 | Aug 1997 | 85 | |
With respect to each of these units, NEP has recorded a liability and a regulatory asset reflecting the estimated future decommissioning billings from the companies. In a 1993 decision, the FERC allowed Yankee Atomic to recover its undepreciated investment in the plant, including a return on that investment, as well as unfunded nuclear decommissioning costs and other costs. Maine Yankee and Connecticut Yankee recover their prudently incurred costs, including a return, in accordance with settlement agreements approved by the FERC in May 1999 and July 2000, respectively. The Company’s share of the decommissioning costs is accounted for in "Purchased electricity" on the income statement.
Future estimated billings from the Yankees are based upon decommissioning cost estimates which are recovered in rates regulated by the FERC. These estimates include the projected costs of decontaminating the units as required by the NRC, dismantling the units, spent fuel storage, security, and liability and property insurance, as well as other costs. The decommissioning costs that are actually incurred by the Yankees may exceed the estimated amounts, perhaps substantially. Beginning in the third quarter of fiscal 2003 and continuing through fiscal 2004, the Yankees increased their aggregate decommissioning estimates to reflect projected future security, insurance cost increases and other expenses. Based on the Yankees’ estimates, NEP’s share of the additional cost is approximately $162 million. Under settlement agreements, NEP is permitted to recover prudently incurred decommissioning costs through CTCs.
Decommissioning Collections: Each of the Yankees has established a trust fund, or escrow fund to meet the projected costs of decommissioning. In order to collect the costs of decommissioning, from their purchasers (including NEP), the Yankees are required to file rate cases periodically with FERC. The rate filings present the Yankees’ estimates of future decommissioning costs for FERC approval. Yankee Atomic ceased decommissioning collections in June 2000. Subsequently, it filed for a rate increase, and received final approval from the FERC on October 2, 2003. Maine Yankee filed a rate case on October 20, 2003, and Connecticut Yankee plans to file a case shortly.
Connecticut Yankee will seek a rate increase of approximately $76 million per year through 2010, of which NEP’s share would be approximately $15 million per year. This amount is included in the $162 million estimate for all of the Yankees mentioned above. On June 10, 2004, the Connecticut Department of Public Utilities and the Connecticut Office of Consumer Counsel filed a petition with the FERC asking the FERC to determine that if it should find that any of Connecticut Yankee’s decommissioning costs were not prudently incurred, the purchasers may not recover these costs in rates that are ultimately charged to distribution customers. Connecticut Yankee will oppose the petition, as will NEP and the other purchasers. NEP intends to contest the petition vigorously but cannot predict the outcome of this proceeding.
DOE Dispute: The Nuclear Waste Policy Act of 1982 establishes that the federal government, through the Department of Energy (DOE), is responsible for the disposal of spent nuclear fuel. In a lawsuit brought against the DOE by numerous utilities and state regulatory commissions, the U.S. Court of Appeals for the District of Columbia Circuit ruled in 1997 that the DOE was obligated to begin disposing of utilities’ spent nuclear fuel by January 1998. The DOE failed to meet this deadline. Many owners of nuclear power plants, including the Yankees, filed claims for money damages in the U.S. Court of Federal Claims for the costs associated with the DOE’s failure to begin to take fuel in 1998. In October 1998 the court held that the DOE is liable for such failure. The Yankees have filed a further action against the DOE to determine the level of damages. The court has scheduled trial for July 12, 2004. As an interim measure until the DOE meets its contractual obligations to dispose of the spent fuel, the Yankees have constructed independent spent fuel storage installations located at the plant sites.
Bechtel Dispute: On June 13, 2003, Connecticut Yankee terminated its firm fixed price contract with Bechtel Power Corporation, its decommissioning operations contractor, alleging various defaults of Betchel’s obligations. Bechtel then filed a proceeding in Connecticut Superior Court against Connecticut Yankee alleging breach of contract and other claims, seeking compensatory and punitive damages. Connecticut Yankee has filed a counterclaim against Bechtel and has stated that it intends to defend against Bechtel’s claims vigorously and to pursue its rights under the $36 million performance bond supplied by Bechtel’s surety, if necessary. Following the contract termination, Connecticut Yankee commenced self-performance of the decommissioning work. As part of its transition into self-performance, Connecticut Yankee has updated its 2003 cost estimate. This update includes the impact of Bechtel’s termination and reflects a substantial increase in cost and delay in the estimated completion date.
Divested Nuclear Units:
Seabrook: NEP previously held a 10 percent non-operating ownership interest in the Seabrook Nuclear Generating Station (Seabrook). As part of a group of joint owners, NEP sold its interest in Seabrook to FPL Energy Seabrook LLC (FPL) on November 1, 2002. Pursuant to the transaction, FPL assumed the decommissioning liability and trust fund for the plant including NEP’s share of both. Net of closing adjustments, NEP’s share of the proceeds from the sale of Seabrook was approximately $84 million following its $5 million top-off payment to the decommissioning trust fund. Ninety-eight percent of the proceeds from the sale in excess of related expenses and NEP’s post-1995 investment are being credited to the Company’s customers over a four year period through CTCs. NEP’s share of expenses for Seabrook prior to November 1, 2002 is accounted for in "Other operation" and "Maintenance" expenses on the income statement.
Millstone Unit 3: In November 1999, NEP entered into an agreement with Northeast Utilities (NU) to settle certain claims. As part of the agreement, NU agreed to include NEP’s 16.2 percent ownership interest in Millstone Unit 3 in an auction of NU’s share of the unit. Upon the closing of the sale, NEP was to receive a fixed amount, regardless of the actual sale price. In March 2001, the Millstone units were sold, including NEP’s interest, for $1.3 billion. In accordance with the settlement agreement, NEP was paid approximately $27.9 million, from which NEP paid approximately $5.8 million to increase the decommissioning trust fund.
Regulatory authorities from Rhode Island, New Hampshire and Massachusetts have expressed intent to challenge the reasonableness of the settlement agreement, taking the position that NEP would have received approximately $140 million of sale proceeds if there had been no agreement with NU. In the event that one or more of the states proceed with such a challenge, the dispute will be resolved by the FERC. Management believes that the Company acted prudently, because the amount it received under the settlement agreement was the highest sale price for a nuclear unit at the time the agreement was reached.
Vermont Yankee Nuclear Power Corporation: NEP redeemed its 23.9 percent equity investment in Vermont Yankee on November 7, 2003. Vermont Yankee formerly owned the Vermont Yankee Nuclear Generating Station (the Station). It sold the Station to Entergy Vermont Yankee LLC (ENVY) in July 2002 for approximately $180 million. NEP’s portion of the sale price was approximately $43 million before settlement of Vermont Yankees’ outstanding liabilities. As part of the transaction, ENVY assumed the decommissioning liability for the Station. Following regulatory approvals and prior to the redemption of its stock on October 27, 2003, Vermont Yankee distributed to its owners including NEP a majority of the proceeds from the sale after payment of outstanding debt and other obligations. NEP received approximately $13 million in this distribution.
Vermont Yankee Missing Fuel Rod Segments: In April 2004, in response to an NRC inspection, which was conducted during the Station’s regularly scheduled refueling outage, ENVY determined that two spent nuclear fuel rod segments were not in their documented location in the spent fuel pool. According to station documentation, in 1979, the rods were placed in a special stainless steel container in the spent fuel pool. ENVY is continuing to investigate the matter, including reviewing the storage records and performing an inspection of the spent fuel pool to determine the location of the rod segments.
On May 5, 2004, ENVY informed Vermont Yankee that it believes that Vermont Yankee is responsible under their Purchase and Sale Agreement for all costs arising in connection with ENVY's inspection. Vermont Yankee has informed NEP that it is reviewing ENVY's communication and studying its options. The Company cannot predict the outcome of this matter at this time.
Plant Expenditures: The Company’s utility plant expenditures are estimated to be approximately $66 million for 2005. At March 31, 2004, substantial commitments had been made relative to normal operating future planned expenditures.
Hydro-Quebec Interconnection: Three affiliates of the Company were created to construct and operate transmission facilities to transmit power from Hydro-Quebec to New England. Under the financial and organizational agreements (the Support Agreements) entered into at the time these facilities were constructed, the Company agreed to guarantee a portion of the project debt. At March 31, 2004, the Company had guaranteed approximately $15 million of project debt with terms through 2015. The Company entered into a Transmission Line Agreement with the purchaser of its nonnuclear generation, USGen under which USGen assumed the Company’s rights to use the Hydro-Quebec line and also agreed to reimburse the Company for its payment obligations under the Support Agreements. The Transmission Line Agreement was terminated on April 1, 2004 and the Company has resumed performance and payment obligations under this agreement. The Company remains an obligor under the support agreements for the portion of the rights it transferred until 2020. Costs associated with these Support Agreements are recoverable from the Company’s customers through CTCs.
Hazardous Waste: The Federal Comprehensive Environmental Response, Compensation and Liability Act, more commonly known as the "Superfund" law, imposes strict, joint and several liability, regardless of fault, for remediation of property contaminated with hazardous substances. A number of states, including Massachusetts, have enacted similar laws.
The electric utility industry typically utilizes and/or generates in its operations a range of potentially hazardous products and by-products. The Company currently has in place an internal environmental audit program and an external waste disposal vendor audit and qualification program intended to enhance compliance with existing federal, state, and local requirements regarding the handling of potentially hazardous products and by-products.
The Company has been named as a potentially responsible party (PRP) by either the United States Environmental Protection Agency or the Massachusetts Department of Environmental Protection for several sites at which hazardous waste is alleged to have been disposed. Private parties have also contacted or initiated legal proceedings against the Company regarding hazardous waste cleanup. The Company is currently aware of other possible hazardous waste sites, and may in the future become aware of additional sites, that it may be held responsible for remediating. Some of these sites relate to the disposal of ash from fossil fuel generating plants formerly owned by the Company.
Predicting the potential costs to investigate and remediate hazardous waste sites continues to be difficult. There are also significant uncertainties as to the portion, if any, of the investigation and remediation costs of any particular hazardous waste site that may ultimately be borne by the Company. The Company has recovered amounts from certain insurers, and, where appropriate, intends to seek recovery from other insurers and from other PRPs, but it is uncertain whether, and to what extent, such efforts will be successful. The Company is currently recovering certain environmental cleanup costs in rates. The Company believes that hazardous waste liabilities for all sites of which it is aware are not material to its financial position.
Town of Norwood Dispute: NEP continues to be engaged in litigation in judicial and administrative forums with the Town of Norwood, Massachusetts. From 1983 until 1998, NEP was the wholesale power supplier for Norwood. In April 1998, Norwood began taking power from another supplier, although its contract term with NEP ran to 2008. Pursuant to a tariff amendment approved by the FERC in May 1998, NEP has been assessing Norwood a CTC. Through March 31, 2004, the charges assessed Norwood amount to approximately $77 million, all of which remain unpaid. The litigation with Norwood is as follows.
State Collection Action: NEP filed a collection action in Massachusetts Superior Court (Worcester County) to collect the CTC, which Norwood has refused to pay. In March 2001, the Superior Court ruled that Norwood has breached the agreement by not paying the CTC charge, and ordered Norwood to make regular and substantial payments to an escrow account. Norwood unsuccessfully appealed the order to the Massachusetts Appeals Court, and the Massachusetts Supreme Judicial Court denied Norwood’s petition for further appellate review. On June 1, 2004, the Supreme Court denied Norwood’s petition for certiorari.
On December 17, 2003, the Superior Court entered judgment for NEP for approximately $40.6 million, which included interest to that date, and which the Company subsequently moved to increase by approximately $2.7 million, to adjust for computational errors. Norwood then moved to void the judgment, or stay its enforcement pending completion of the FERC proceeding described below, or both. On June 9, 2004, the Massachusetts Superior Court granted NEP’s motion to increase the judgment and denied Norwood’s motion to void the judgment or stay it pending Norwood’s Section 206 Proceeding at FERC.
FERC 206 Proceeding: In December 2002, Norwood filed a challenge to the CTC rate with the FERC under Section 206 of the Federal Power Act. Under this Section, the FERC has the power to grant prospective relief only. In an order dated July 2, 2003, the FERC set down for hearing Norwood’s challenge to the factors used to calculate the CTC rate for Norwood, and set a refund effective date of February 21, 2003, which empowers the FERC to direct NEP to adjust Norwood’s liability for unpaid charges billed after that date in the event that Norwood’s challenge is successful. On June 9, 2004, the FERC administrative law judge issued an initial decision recommending that FERC revise the CTC formula to reduce the CTC amount that was previously calculated under the formula and that the FERC accepted and approved in 1998. NEP will request that FERC not modify the tariff as recommended by the initial decision.
Federal Court Antitrust Claim: In 1997, Norwood filed a lawsuit in the U.S. District Court for the District of Massachusetts challenging NEP’s proposed divestiture of its generating facilities. Following the District Court’s dismissal of all of Norwood’s claims, the U.S. Court of Appeals for the First Circuit reinstated Norwood’s claim that the sale to US Gen New England, Inc. (USGen) violated Section 7 of the Clayton Act on the ground that USGen had acquired market power. The First Circuit characterized the claim as weak because FERC had found no anticompetitive consequences from the sale, and invited the District Court to address whether the FERC’s decision precluded further litigation. This issue was argued to the District Court in 2001, but no decision has been rendered, in part because the original judge who heard argument subsequently recused herself. USGen’s bankruptcy filing on July 2, 2003 resulted in an automatic stay of this case.
Contracts for the Purchase of Electricity from ENVY: In connection with the sale of the Station, the Company entered into a power contract with ENVY to buy 22.5 percent of the entitlement of the Vermont Yankee generation until 2012. At the same time the Company entered into a contract with a third party to sell the entire 22.5 percent of the Vermont Yankee entitlement and recover 100 percent of its purchased power contract costs. The Company sells the power to the third party at its cost and thus does not recognize any financial impact from the agreement on its financial statements. The Company matches the cost of the power contract with the revenue from the sale of the power to the third party on its income statement. The Company’s commitments for future fiscal periods, under this purchased power contract as of March 31, 2004, are as follows: 2005, $44 million; 2006, $43 million; 2007, $45 million; 2008, $43 million; 2009, $45 million and 2010 and thereafter $157 million.
NOTE E – LONG-TERM DEBT
A summary of long-term debt is as follows:
At March 31 (In thousands) | ||||||
Series | Rate % | Maturity | 2004 | 2003 | ||
Pollution Control Revenue Bonds: | ||||||
CDA (a) | Variable | October 15, 2015 | $ 38,500 | $ 38,500 | ||
MIFA 1 (b) | Variable | March 1, 2018 | 79,250 | 79,250 | ||
BFA 1 (c) | Variable | November 1, 2020 | 135,850 | 135,850 | ||
BFA 2 (c) | Variable | November 1, 2020 | 50,600 | 50,600 | ||
MIFA 2 (b) | Variable | October 1, 2022 | 106,150 | 106,150 | ||
Unamortized discounts | (53) | (59) | ||||
Total long-term debt | $ 410,297 | $ 410,291 | ||||
(a) CDA = Connecticut Development Authority
(b) MIFA = Massachusetts Industrial Finance Authority
(c) BFA = Business Finance Authority of the State of New Hampshire
At March 31, 2004, interest rates on the Company's variable rate long-term bonds ranged from 0.85 percent to 1.45 percent. There are no payments or sinking fund requirements due in 2004 through 2007.
At March 31, 2004, the Company's long-term debt had a carrying value and fair value of approximately $410 million. The fair value of debt that re-prices frequently at market rates approximates carrying value.
NOTE F - SHORT-TERM BORROWINGS
At March 31, 2004 and 2003, the Company had no short-term debt outstanding. The Company has regulatory approval to issue up to $375 million of short-term debt. National Grid USA and certain subsidiaries, including the Company, with regulatory approval, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowing companies pay interest at a rate designed to approximate the cost of outside short-term borrowings. Companies that invest in the pool share the interest earned on a basis proportionate to their average monthly investment in the money pool. Funds may be withdrawn from or repaid to the pool at any time without prior notice.
At March 31, 2004 and 2003, the Company had lines of credit and standby bond purchase facilities with banks totaling $439 million, which is available to provide liquidity support for $410 million of the Company’s long-term bonds in tax-exempt commercial paper mode, and for other corporate purposes. The Company's line of credit expires and is renewed each December. The Company's standby bond purchase facility expires and is renewed each September. There were no borrowings under these lines of credit at March 31, 2004. Fees are paid on the lines and facilities in lieu of compensating balances.
NOTE G – TAXES
NGUSA and its subsidiaries (including the Company) participate with National Grid General Partnership, a wholly owned subsidiary of NGT, in filing consolidated federal income tax returns. The Company's income tax provision is calculated on a separate return basis. Federal income tax returns have been examined and all appeals and issues have been agreed upon by the Internal Revenue Service and the Company through 1996.
Total income taxes in the statements of income are as follows:
(c) BFA = Business Finance Authority of the State of New Hampshire
At March 31, 2004, interest rates on the Company's variable rate long-term bonds ranged from 0.85 percent to 1.45 percent. There are no payments or sinking fund requirements due in 2004 through 2007.
At March 31, 2004, the Company's long-term debt had a carrying value and fair value of approximately $410 million. The fair value of debt that re-prices frequently at market rates approximates carrying value.
NOTE F - SHORT-TERM BORROWINGS
At March 31, 2004 and 2003, the Company had no short-term debt outstanding. The Company has regulatory approval to issue up to $375 million of short-term debt. National Grid USA and certain subsidiaries, including the Company, with regulatory approval, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowing companies pay interest at a rate designed to approximate the cost of outside short-term borrowings. Companies that invest in the pool share the interest earned on a basis proportionate to their average monthly investment in the money pool. Funds may be withdrawn from or repaid to the pool at any time without prior notice.
At March 31, 2004 and 2003, the Company had lines of credit and standby bond purchase facilities with banks totaling $439 million, which is available to provide liquidity support for $410 million of the Company’s long-term bonds in tax-exempt commercial paper mode, and for other corporate purposes. The Company's line of credit expires and is renewed each December. The Company's standby bond purchase facility expires and is renewed each September. There were no borrowings under these lines of credit at March 31, 2004. Fees are paid on the lines and facilities in lieu of compensating balances.
NOTE G – TAXES
NGUSA and its subsidiaries (including the Company) participate with National Grid General Partnership, a wholly owned subsidiary of NGT, in filing consolidated federal income tax returns. The Company's income tax provision is calculated on a separate return basis. Federal income tax returns have been examined and all appeals and issues have been agreed upon by the Internal Revenue Service and the Company through 1996.
Total income taxes in the statements of income are as follows:
Year Ended March 31, | |||
(In thousands) | 2004 | 2003 | 2002 |
Income taxes charged to operations | $42,610 | $45,429 | $47,593 |
Income taxes charged (credited) to "Other income" | 2,727 | 1,443 | 1,694 |
Total income taxes | $45,337 | $46,872 | $49,287 |
Total income taxes, as shown above, consist of the following components:
Year Ended March 31, | |||
(In thousands) | 2004 | 2003 | 2002 |
Current income taxes | $ 68,401 | $44,486 | $ 65,359 |
Deferred income taxes | (22,623) | 2,855 | (15,555) |
Investment tax credits, net | (441) | (469) | (517) |
Total Income Taxes | $45,337 | $46,872 | $49,287 |
Since 1998, the Company has been amortizing previously deferred investment tax credits (ITC) related to generation investments over the CTC recovery period. Unamortized ITC related to generating units divested in 1998 and 2001 was credited to other income pursuant to federal tax law. Previously recognized ITC related to transmission facilities is amortized over the estimated productive lives.
Total income taxes, as shown above, consist of federal and state components as follows:
Year Ended March 31, | |||
(In thousands) | 2004 | 2003 | 2002 |
Federal income taxes | $40,625 | $41,039 | $41,018 |
State income taxes | 4,712 | 5,833 | 8,269 |
Total Income Taxes | $45,337 | $46,872 | $49,287 |
With regulatory approval from the FERC, the Company has adopted comprehensive interperiod tax allocation (normalization) for temporary book/tax differences.
Total income taxes differ from the amounts computed by applying the federal statutory tax rates to income before taxes. The reasons for the differences are as follows:
Year Ended March 31, | |||
(In thousands) | 2004 | 2003 | 2002 |
Computed tax at statutory rate | $41,239 | $43,505 | $44,121 |
Increases (reductions) in tax resulting from: | |||
Amortization of investment tax credits | (286) | (305) | (336) |
State income taxes, net of federal income tax benefit | 3,063 | 3,791 | 5,375 |
Rate recovery of deficiency in deferred tax reserves | 1,769 | 1,103 | 1,007 |
All other differences | (448) | (1,222) | (880) |
Total income taxes | $45,337 | $46,872 | $49,287 |
The Company adopted SFAS No. 109, “Accounting for Income Taxes”, which requires recognition of deferred income taxes for temporary differences that are reported in different years for financial reporting and tax purposes using the liability method. Under the liability method, deferred tax liabilities or assets are computed using the tax rates that will be in effect when temporary differences reverse. Generally, for regulated companies, the change in tax rates may not be immediately recognized in operating results because of rate-making treatment and provisions in the Tax Reform Act of 1986.
The following table identifies the major components of total deferred income taxes:
At March 31 (In millions) | 2004 | 2003 | 2002 |
Deferred tax asset: | |||
Plant related | $ 66 | $ 66 | $ 67 |
Investment tax credits | 3 | 3 | 3 |
All other | 42 | 42 | 37 |
111 | 111 | 107 | |
Deferred tax liability: | |||
Plant related | 20 | 32 | (211) |
All other, principally regulatory assets | (364) | (401) | (153) |
(344) | (369) | (364) | |
Net deferred tax liability | $ (233) | $ (258) | $ (257) |
There were no valuation allowances for deferred tax assets at March 31, 2004 or 2003.
NOTE H – EMPLOYEE BENEFITS
Summary
The Company has a non-contributory defined benefit pension plan and a post-retirement benefit plan (the Plans) covering substantially all employees. The pension is a noncontributory, tax-qualified defined benefit plan which provides all employees of National Grid USA and its subsidiaries with a minimum retirement benefit. Under the pension plan a participant’s retirement benefit is computed using formulas based on percentages of highest average compensation computed over five consecutive years. The compensation covered by the pension plan includes salary, bonus and incentive share awards. Non-union employees hired after July 15, 2002 participate under a noncontributory defined benefit cash balance design.
Supplemental nonqualified, non-contributory executive retirement programs provide additional defined pension benefits for certain executives.
The post-retirement benefit plan provides health care and life insurance coverage to eligible retired employees. Eligibility is based on certain age and length of service requirements and in some cases retirees must contribute to the cost of their coverage.
Funding Policy
Absent unusual circumstances, the Company’s funding policy is to contribute to the plans each year the maximum tax-deductible amount for that year. However, the contribution for any year will not be less than the minimum contribution required by federal law or greater than the maximum tax-deductible amount.
Investment Strategy
The Company manages the Plans’ investments to minimize the long-term cost of operating the Plans, with a reasonable level of risk. Risk tolerance is determined as a result of a periodic asset/liability study which analyzes the plans’ liabilities, and funded status and results in the determination of the allocation of assets across equity and fixed income. Equity investments are broadly diversified across U.S. and non-U.S. stocks, as well as across growth, value, and small and large capitalization stocks. Likewise, the fixed income portfolio is broadly diversified across the various fixed income market segments. Small investments are also held in private equity, real estate and timber, with the objective of enhancing long-term returns while improving portfolio diversification. Investment risk and return is reviewed by an investment committee on a quarterly basis.
The target asset allocation for the pension plan is:
2004 | 2003 | |
U.S. Equities | 42% | 50% |
Global Equities (including U.S.) | 7% | - |
Non-U.S. Equities | 11% | 15% |
Fixed Income | 35% | 35% |
Private Equity and Property | 5% | - |
100% | 100% |
The target asset allocation for the post-retirement benefit plan is:
2004 | 2003 | |
U.S. Equities | 45% | 45% |
Non-U.S. Equities | 15% | 15% |
Fixed Income | 40% | 40% |
100% | 100% |
Expected Rate of Return on Assets
The estimated rate of return for various passive asset classes is based both on analysis of historical rates of return and forward looking analysis of risk premiums and yields. Current market conditions, such as inflation and interest rates, are evaluated in connection with the setting of our long-term assumption. A small premium is added for active management of both equity and fixed income. The rates of return for each asset class are then weighted in accordance with our target asset allocation, and the resulting long-term return on asset rate is then applied to the market-related value of assets.
The Plans’ costs used the following assumptions:
Pension Benefits |
Year Ended | Year Ended | Year Ended | ||||
March 31, | March 31, | March 31, | ||||
2004 | 2003 | 2002 | ||||
Weighted average assumptions used to determine net periodic cost: |
Discount rate | 6.25% | 7.50% | 7.50% | |
Rate of compensation increase | ||||
Union | 4.00% | 4.00% | 4.00% | |
Nonunion | 5.25% | 5.25% | 5.25% | |
Expected return on plan assets | 8.50% | 8.75% | 8.75% |
Other Post-retirement benefits | |||||||
Year Ended | Year Ended | Year Ended | ||||
March 31, | March 31, | March 31, | ||||
2004 | 2003 | 2002 | ||||
Weighted average assumptions used to determine net periodic cost: |
Discount rate | 6.25% | 7.50% | 7.50% | ||
Expected return on plan assets | |||||
Union | 8.75% | 9.00% | 9.00% | ||
Nonunion | 7.25% | 7.50% | 7.50% | ||
Medical trend | |||||
Initial | 10.00% | 10.00% | 10.00% | ||
Ultimate | 5.00% | 5.00% | 5.00% | ||
| Year ultimate rate reached | 2008 | 2007 | 2006 |
The Company’s net pension cost for the years ended March 31, 2004, 2003 and 2002 included the following components:
Year Ended March 31, | |||
(In thousands) | 2004 | 2003 | 2002 |
Service cost-benefits earned during the period | $ 148 | $ 729 | $ 809 |
Plus (less): | |||
Interest cost on projected benefit obligation | 7,688 | 8,954 | 8,729 |
Return on plan assets at expected long-term rate | (9,320) | (12,500) | (12,789) |
Amortization of net loss | 2,710 | - | - |
Amortization of prior service cost | 184 | 209 | 195 |
Curtailment loss | 10 | - | - |
Benefit (income)/cost | $ 1,420 | $(2,608) | $(3,056) |
Special termination benefits not included above | $ 963 | $ - | $ 1,339 |
The funded status of the pension plan cannot be presented separately for the Company as the Company participates in the plan with certain other National Grid USA subsidiaries.
The following table provides a reconciliation of the changes in the National Grid companies’ pension plan’s fair value of assets for the fiscal years ended March 31, 2004 and 2003, and percentage distribution of the fair market value of the types of assets held in the pension plan’s trust. The expected contribution to the National Grid companies’ pension plan for fiscal 2005 is approximately $50 million and was made to the plan’s trust in April 2004.
(In millions) | 2004 | 2003 |
Reconciliation of change in plan assets: | ||
Fair value of plan assets at beginning of period | $ 869 | $ 1,053 |
Actual return on plan assets during year | 256 | (110) |
Company contributions | 75 | 8 |
Benefits paid from plan assets | (98) | (82) |
Fair value of plan assets at end of period | $ 1,102 | $ 869 |
2004 | 2003 | |
Distribution of plan assets: | ||
Debt securities | 34% | 39% |
Equity securities | 63% | 58% |
Property/real estate | 1% | 1% |
Other | 2% | 2% |
100% | 100% |
The following table provides the changes in the National Grid companies’ pension plan’s benefit obligations, the accumulated benefit obligation and the assumptions used in developing those obligations for the National Grid USA companies’ pension plan at March 31:
(In millions) | 2004 | 2003 |
Accumulated benefit obligation | $ 1,249 | $ 1,125 |
Change in benefit obligation: | ||
Benefit obligation at beginning of period | $ 1,258 | $ 1,074 |
Service cost | 20 | 15 |
Interest cost | 78 | 78 |
Actuarial (gain)/loss | 93 | 173 |
Benefits paid | (98) | (82) |
Curtailments | (4) | - |
Special termination benefits | 78 | - |
Benefit obligation at end of period | $ 1,425 | $ 1,258 |
Reconciliation of prepaid cost | ||
Fair value of plan assets at end of period | $1,102 | $869 |
Funded status | (323) | (389) |
Unrecognized actuarial loss | 543 | 646 |
Unrecognized prior service cost | 14 | 17 |
Net amount prepaid | $ 234 | $ 274 |
Amounts recognized on the balance sheet consist of: | ||
Accrued benefit liability | (148) | (255) |
Intangible asset | 16 | 18 |
Regulatory assets | 62 | 92 |
Accumulated other comprehensive income | 304 | 419 |
Net amount recognized on the balance sheet | $ 234 | $ 274 |
March 31, | ||
2004 | 2003 | |
Weighted average assumptions to determine pension benefit obligation: | ||
Discount rate | 5.75% | 6.25% |
Average rate of increase in future compensation level | ||
Union | 4.00% | 4.00% |
Non-Union | 5.25% | 5.25% |
Expected long-term rate of return on assets | 8.50% | 8.50% |
Additional Minimum Liability (AML): Statement of Financial Accounting Standards 87 “Employers’ Accounting for Pensions” states that if a pension plan’s accumulated benefit obligation (ABO) exceeds the fair value of plan assets, the employer shall recognize in the statement of financial position a liability that is at least equal to the unfunded ABO with an offsetting charge to other comprehensive income. Due to the severe downturn in the capital markets the Company's ABO at March 31, 2004 and 2003 is greater than the fair value of plan assets. As such, at March 31, 2004 and 2003, the Company has recognized an additional minimum pension liability of $40 million and $65 million, respectively, on its balance sheet reflecting the under funded pension obligation. However, due to the nature of its rate plan the Company has not charged other comprehensive income but has instead recorded a regulatory asset. If in the future, capital markets recover such that the fair value of plan assets is once again greater than the ABO, the additional minimum pension liability will be removed from the Company's balance sheets.
The Company has also recognized an allocated share of the additional minimum pension liability of its affiliated service company of approximately $24 million and $29 million at March 31, 2004 and 2003, respectively, which is recorded in accounts payable on the balance sheet with an offsetting charge to regulatory assets.
Postretirement Benefit Plans Other than Pensions (PBOPs): The Company provides health care and life insurance coverage to eligible retired employees. Eligibility is based on certain age and length of service requirements and in some cases retirees must contribute to the cost of their coverage.
The Company's total cost of PBOPs for the years ended March 31, 2004, 2003 and 2002 included the following components:
Year Ended March 31, | |||
(In thousands) | 2004 | 2003 | 2002 |
Service cost - benefits earned during the period | $ 67 | $ 221 | $ 225 |
Plus (less): | |||
Interest cost on projected benefit obligation | 3,608 | 3,994 | 3,434 |
Return on plan assets at expected long-term rate | (3,414) | (3,841) | (3,721) |
Amortization of prior service cost | (19) | (12) | - |
Amortization of net loss | 516 | 395 | 120 |
Curtailment (gain)/loss | 215 | - | - |
Benefit cost | $ 973 | $ 757 | $ 58 |
Special termination benefits not included above | $ 196 | $ - | $ 61 |
The following table provides a reconciliation of the changes in the Company’s portion of the National Grid companies’ post-retirement plan’s fair value of assets for the fiscal years ended March 31, 2004 and 2003, as well as the investment allocation of the fair market value of the securities held in the post-retirement plan’s trust. The Company’s expected contribution to the post-retirement plan during fiscal 2005 is approximately $3 million.
(In millions) | 2004 | 2003 |
Reconciliation of change in plan assets: | ||
Fair value of plan assets at beginning of period | $ 36 | $ 41 |
Actual return on plan assets during year | 8 | (4) |
Company contributions | 2 | 3 |
Benefits paid from plan assets | (4) | (4) |
Fair value of plan assets at end of period | $ 42 | $ 36 |
2004 | 2003 | |
Distribution of plan assets: | ||
Debt securities | 38% | 55% |
Equity securities | 61% | 44% |
Other | 1% | 1% |
100% | 100% |
The following provides a reconciliation of the Company’s portion of the National Grid companies’ post-retirement obligations at March 31:
(In millions) | 2004 | 2003 |
Change in benefit obligation: | ||
Benefit obligation at beginning of period | $ 67 | $ 53 |
Interest cost | 4 | 4 |
Actuarial loss | - | 14 |
Benefits paid | (4) | (4) |
Benefit obligation at end of period | $ 67 | $ 67 |
Reconciliation of prepaid cost | ||
Fair value of plan assets at end of period | $42 | $36 |
Funded status | (25) | (31) |
Unrecognized actuarial loss | 32 | 37 |
Net amount prepaid | $ 7 | $ 6 |
March 31, | ||
(In thousands) | 2004 | 2003 |
Weighted average assumptions used to determine post-retirement benefit obligation: | ||
Discount rate | 5.75% | 6.25% |
Expected long-term rate of return on assets | ||
Union | 9.00% | 8.75% |
Nonuion | 5.75% | 7.25% |
Health care cost trend | ||
Initial | 10.00% | 10.00% |
Ultimate | 5.00% | 5.00% |
Year ultimate rate reached | 2009 | 2008 |
The assumptions used in the health care cost trends have a significant effect on the amounts reported. A one percentage point change in the assumed rates would increase the accumulated postretirement benefit obligation (APBO) as of March 31, 2004 by approximately $9 million or decrease the APBO by approximately $8 million, and increase or decrease the net post-retirement cost for 2004 by approximately $500,000.
Voluntary Early Retirement Offers: At December 31, 2003, enrollment periods ended with respect to two voluntary early retirement offers (VEROs) made by National Grid USA. The VEROs will not affect the Company’s results of operations, as the Company will recover the related expenses through cost recovery mechanisms.
The first VERO was made to eligible non-union employees in New York and New England in areas including transmission, retail operations (in New England), and corporate administrative functions such as finance, human resources, legal, and information technology. The majority of enrollees will retire by November 1, 2004, with the remainder retiring by November 1, 2007. For the fiscal year ended March 31, 2004 the cost of this VERO to the Company was approximately $5 million.
The second VERO was made to eligible union employees in New England, with the enrollees retiring in two groups. The first group retired on or before February 1, 2004. The second group will be released over a four-year period from February 1, 2004 to January 1, 2008. For the fiscal year ended March 31, 2004 the cost of this VERO to the Company was approximately $2 million.
NOTE I - PREFERRED STOCK
A summary of cumulative preferred stock at March 31, 2004 and 2003, respectively, is as follows (in thousands of dollars except for share data):
| Shares Outstanding | Amount | Dividends Declared | ||||
2004 | 2003 | 2004 | 2003 | 2004 | 2003 | |
$100 par value 6.00% Series (a) | 12,730 | 12,950 | $1,273 | $1,295 | $75 | $82 |
(a) Noncallable.
The annual dividend requirement for cumulative preferred stock was approximately $75,000 and $82,000 for 2004 and 2003, respectively.
There are no mandatory redemption provisions on the Company’s cumulative preferred stock.
NOTE J - SEGMENTS
The Company's reportable segments are electricity transmission and stranded/other. The Company is engaged principally in the business of electricity transmission. Certain information regarding the Company's segments is set forth in the following table. General corporate expenses, property common to both segments and depreciation on such common property have been allocated to the segments based on labor or plant using a percentage derived from total labor or plant dollars charged directly to certain operating expense accounts or certain plant accounts. General corporate expenses include the cost of the services furnished by National Grid USA Service Company, Inc., an affiliated service company operating pursuant to the provisions of Section 13 of the 1935 Act. Assets allocated to the electricity transmission and stranded/other segments include net utility plant, materials and supplies, and certain regulatory and other assets. Corporate assets consist primarily of other property and investments, cash, restricted cash, and unamortized debt expense.
(In millions) | Electricity Transmission | Stranded / Other | Total |
Year Ended March 31, 2004 | |||
Operating revenue | $180 | $278 | $458 |
Operating income before income taxes | 76 | 41 | 117 |
Depreciation and amortization | 18 | 66 | 84 |
Amortization of stranded costs | - | 5 | 5 |
Year Ended March 31, 2003 | |||
Operating revenue | $164 | $350 | $514 |
Operating income before income taxes | 73 | 54 | 127 |
Depreciation and amortization | 18 | 68 | 86 |
Amortization of stranded costs | - | 12 | 12 |
Year Ended March 31, 2002 | |||
Operating revenue | $159 | $401 | $560 |
Operating income before income taxes | 68 | 66 | 134 |
Depreciation and amortization | 16 | 62 | 78 |
Amortization of stranded costs | - | 11 | 11 |
| Total Assets | ||
At March 31, (In millions) | 2004 | 2003 |
Electricity transmission | $1,111 | $1,076 |
Stranded/other | 1,394 | 1,614 |
Corporate assets | 257 | 294 |
Total | $2,762 | $2,984 |
NOTE K - SUPPLEMENTARY INCOME STATEMENT
Advertising expenses, expenditures for research and development, and rents were not material and there were no royalties paid in the years ended March 31, 2004, 2003 and 2002. Taxes, other than income taxes, charged to operating expenses are set forth by class as follows:
Year Ended March 31, | |||
(In thousands) | 2004 | 2003 | 2002 |
Municipal property taxes | $15,364 | $16,800 | $16,045 |
Federal and state payroll and other taxes | 1,593 | 2,068 | 2,138 |
Total taxes other than income taxes | $16,957 | $18,868 | $18,183 |
Transactions between the Company and other affiliated companies for sales of electric energy and other sales amounted to approximately $340 million, $324 million and $354 million for the years ended March 31, 2004, 2003 and 2002, respectively.
NOTE L – COST OF REMOVAL
In June 2001, the Financial Accounting Standards Board (FASB) issued Statement on Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations” (FAS 143). FAS 143 provides the accounting requirements for retirement obligations associated with tangible long-lived assets. FAS 143 is effective for fiscal years beginning after June 15, 2002. The Company adopted FAS 143 during the fiscal year ended March 31, 2004.
The Company does not have any material asset retirement obligations arising from legal obligations as defined under FAS 143. However, under Company’s current and prior rate plans it has collected through rates an implied cost of removal for its plant assets. This cost of removal collected from customers differs from the FAS 143 definition of an asset retirement obligation in that these collections are for costs to remove an asset when it is no longer deemed usable (i.e. broken or obsolete) and not necessarily from a legal obligation.
The cost of removal collected from customers has historically been embedded within accumulated depreciation (as these costs have charged over time through depreciation expense). With the adoption of FAS 143 the Company has reclassified the cost of removal collections to a regulatory liability account to more properly reflect the future usage of these collections. The Company estimates it has collected over time approximately $19 million and $18 million for cost of removal through March 31, 2004 and 2003, respectively.
NOTE M - QUARTERLY INFORMATION (UNAUDITED)
(In thousands) | Quarter Ended June 30, 2003 | Quarter Ended Sept. 30, 2003 | Quarter Ended Dec. 31, 2003 | Quarter Ended March 31, 2004 |
Operating revenue | $110,629(a) | $114,235(a) | $117,208 | $115,739 |
Operating income | $ 18,935 | $ 17,986 | $ 20,269 | $ 17,614 |
Net income | $ 18,709 | $ 18,059 | $ 18,551 | $ 17,171 |
(In thousands) | Quarter Ended June 30, 2002 | Quarter Ended Sept. 30, 2002 | Quarter Ended Dec. 31, 2002 | Quarter Ended March 31, 2003 |
Operating revenue | $143,488 | $127,267 | $126,227 | $117,024 |
Operating income | $ 21,891 | $ 20,553 | $ 23,105 | $ 15,672 |
Net income | $ 20,398 | $ 20,837 | $ 21,798 | $ 14,394 |
(a) Operating revenues for the quarters ended June 30, 2003 and September 30, 2003 have been reduced by approximately $4 million, respectively, from amounts previously reported in the related SEC Form 10-Q for reclassifications between operating revenue and other operating expense. These reclassifications had no impact on operating income or net income for the respective periods.
Management considers per share data not relevant because the Company's common stock is wholly owned by National Grid USA, a wholly owned subsidiary of NGT.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
The Company has nothing to report for this item.
ITEM 9A. CONTROLS AND PROCEDURES
The Company has carried out an evaluation under the supervision and with the participation of its management, including the Chief Financial Officer and President, of the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based on and as of that evaluation, it was determined that these disclosure controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports that the Company files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required. During the most recent fiscal quarter, there were no changes in internal control over financial reporting that could materially affect internal control over financial reporting.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The following table lists the Company’s executive officers and directors:
The Company has nothing to report for this item.
ITEM 9A. CONTROLS AND PROCEDURES
The Company has carried out an evaluation under the supervision and with the participation of its management, including the Chief Financial Officer and President, of the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based on and as of that evaluation, it was determined that these disclosure controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports that the Company files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required. During the most recent fiscal quarter, there were no changes in internal control over financial reporting that could materially affect internal control over financial reporting.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The following table lists the Company’s executive officers and directors:
Name | Age | Position |
Stephen P. Lewis | 47 | President and Director |
John G. Cochrane | 46 | Chief Financial Officer, Vice President and Director |
Michael Calviou | 35 | Vice President |
Edward A. Capomacchio | 58 | Controller |
Marc F. Mahoney | 50 | Vice President |
Michael E. Jesanis | 47 | Vice President and Director |
Lawrence J. Reilly | 48 | Vice President and Director |
James S. Robinson | 51 | Vice President and Treasurer |
Herb Schrayshuen | 50 | Vice President |
Jeffrey A. Scott | 49 | Senior Vice President of National Grid USA, Transmission, and Director |
Each member of the board of directors is elected at the annual meeting of stockholders and holds office until the next annual meeting or a special meeting in lieu thereof, and until his or successor is elected and qualified. There are no family relationships between any of the directors and the executive officers listed in the table.
Mr. Lewis was elected President and director effective April 16, 2003; he was Vice President from February 26, 2003 until April 16, 2003. He has been a Vice President of National Grid USA since November 2002. He was elected President of National Grid Transmission Services Corporation in December 2002 and elected Vice President of Niagara Mohawk Power Corporation and National Grid USA Service Company, Inc. in November 2002. From 2001 to 2002, he was Manager of UK Electricity Services for National Grid. From 1997 to 2001, he was a Network Manager for Services for National Grid.
Mr. Cochrane was elected Chief Financial Officer effective August 1, 2002 and Vice President effective January 2002 and has served on the Company’s Board since 2002. He was the Company’s Treasurer from 1998 to January 31, 2002. He has served as National Grid USA’s Chief Financial Officer since January 2001, Senior Vice President since May 2002, and Treasurer since April 2003. He was Treasurer of National Grid USA (and its predecessor, New England Electric System) and of National Grid USA Service Company from 1998 to 2002. Mr. Cochrane was also Treasurer of Massachusetts Electric Company from 1998 to 2000 and of The Narragansett Electric Company from 1993 to 2000.
Mr. Calviou was elected Vice President effective May 1, 2004. He previously was Commercial Frameworks Manager for National Grid UK Transmission. He previously worked in National Grid Transco’s UK Transmission business, most recently as Commercial Frameworks Manager from February 2003 to April 2004, and prior to that as Strategy and Development Manager from December 2001 to February 2003, and as Strategy and Portfolio Manager from March 2000 to December 2001.
Mr. Capomacchio has served as Controller of the Company and its affiliates Massachusetts Electric Company, The Narragansett Electric Company, Nantucket Electric Company and Granite State Electric Company since May 2001. Since January 2002, he has served as Vice President and Controller of National Grid USA Service Company and as Controller of Niagara Mohawk Power Corporation. Mr. Capomacchio was Assistant Controller of National Grid USA Service Company from 1998 to 2002.
Mr. Mahoney joined the Company as Vice President in May 2000 at the merger of Montaup Electric Company with the Company. Prior to that he was Vice President, Field Operations, of Eastern Utilities Associates from 1997 to 2000.
Mr. Jesanis has been Vice President since March 17, 1998 and was elected director in 2000. He became President of National Grid USA in November 2003 having been its Chief Operating Officer and responsible for the day-to-day operations since January 2001. He served as Senior Vice President and Chief Financial Officer of National Grid USA’s predecessor, New England Electric System, from 1998 to 2000. Mr. Jesanis is also a director of National Grid USA and of Niagara Mohawk Power Corporation and will be appointed a director of National Grid Transco in July 2004.
Mr. Reilly joined the Company’s Board of Directors in 2001 and has been a Vice President of the Company and Secretary and General Counsel of National Grid USA since January 2001. Since 2000 he has been National Grid USA Senior Vice President, and he served as President of Massachusetts Electric Company, The Narragansett Electric Company, Nantucket Electric Company and Granite State Electric Company from 1996 to 2000.
Mr. Robinson has been the Company’s Treasurer since January 31, 2002 and has served as Vice President since 1998. He was the Company’s Director of Nuclear Investments from 1997 to 1998.
Mr. Schrayshuen has been Vice President since January 31, 2002. He was Director of Electric Assets from 1999 to 2002 and Director of Energy Transactions from 1998 to 1999.
Mr. Scott was elected director July 1, 2003. He has been a Senior Vice President and director of National Grid USA since August 1, 2003. He joined The National Grid Company in 1990, becoming Commercial Director of UK Transmission in February 2003. Currently, he is responsible for all operations associated with National Grid’s Transco’s US Transmission businesses.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires the Company’s executive officers and directors, and persons who own more than 10 percent of a registered class of the Company’s equity securities, to file reports with the Securities and Exchange Commission disclosing their ownership of stock in the Company and changes in such ownership. To the Company’s knowledge, based solely on written representations from reporting persons, no such reports were required to be filed during the fiscal year ended March 31, 2004.
Senior Financial Officer Code of Ethics
The Company has adopted a code of ethics that applies to its principal executive officer, principal financial officer and principal accounting officer. This code is available on the National Grid Transco website, at www.ngtgroup.com/about/mn_corp_govern.html, where any amendments or waivers will also be posted.
Senior Financial Officer Code of Ethics
The Company has adopted a code of ethics that applies to its principal executive officer, principal financial officer and principal accounting officer. This code is available on the National Grid Transco website, at www.ngtgroup.com/about/mn_corp_govern.html, where any amendments or waivers will also be posted.
ITEM 11. EXECUTIVE COMPENSATION
Summary Compensation Table
The following table sets forth the compensation paid or accrued for services rendered to NEP in fiscal years 2004, 2003 and 2002 by the president and the three most highly paid persons who were serving as executive officers on March 31, 2004 (the Named Executive Officers).
The following table sets forth the compensation paid or accrued for services rendered to NEP in fiscal years 2004, 2003 and 2002 by the president and the three most highly paid persons who were serving as executive officers on March 31, 2004 (the Named Executive Officers).
Name and Principal Position (a) | Year | Annual Compensation (b) | Long-Term Compensation Awards Securities Underlying Options (#) | All Other Compen- sation($)(e) | ||
|---|---|---|---|---|---|---|
| Salary($) | Bonus($)(c) | Other Annual Compen-sation($)(d) | ||||
Stephen P. Lewis President (f) | 2004 2003 2002 | 47,183 --- --- | 10,282 --- --- | 23,245 --- --- | 0 --- --- | 118,476 --- --- |
Marc F. Mahoney Vice President | 2004 2003 2002 | 68,520 74,778 106,485 | 33,246 39,664 64,675 | 3,489 9,443 12,637 | 0 8,408 9,702 | 125 122 165 |
James S. Robinson Vice President | 2004 2003 2002 | 73,718 50,022 139,663 | 28,136 20,754 66,344 | 3,757 6,227 18,221 | 0 7,029 12,060 | 153 88 221 |
Masheed H. Rosenqvist Vice President | 2004 2003 2002 | 79,844 158,280 152,196 | 45,925 70,900 70,479 | 3,993 19,179 18,154 | 0 17,789 14,711 | 245 484 464 |
(a) | Certain officers of NEP also perform services for affiliate companies. Compensation that is allocable to NEP is set forth in the table. |
(b) | Includes deferred compensation in category and year earned. |
(c) | The bonus figure represents cash bonuses and the fair market value of unrestricted securities of National Grid Transco awarded under an incentive compensation plan and cash bonuses awarded under the all-employees goals program. |
(d) | Includes amounts reimbursed for the payment of taxes on certain non-cash benefits and contributions to the incentive thrift plan that are not bonus contributions, including related deferred compensation plan match. |
(e) | Includes Company contributions to life insurance. For Mr. Lewis, includes expenses associated with his overseas assignment. |
(f) | Mr .Lewis is on assignment to the US from the UK, and he is paid in pounds sterling. A conversion rate of $1.68/£1.00 was used to translate his compensation, which is the weighted average exchange rate for the National Grid companies’ results for the fiscal year ended March 31, 2004. |
Long-Term Incentive Plans – Awards in Last Fiscal Year
The following table sets forth awards made under the National Grid Transco Performance Share Plan (the PSP) to the Named Executive Officers during fiscal 2004.
Name | Number of Shares (#) | Performance Period | Estimated Future Payouts | |
| Threshold (#) | Maximum (#) | |||
Stephen P. Lewis | 6,040 | July 1, 2003 through June 30, 2006 | 1,812 | 6,040 |
Marc F. Mahoney | 12,142 | July 1, 2003 through June 30, 2006 | 3,643 | 12,142 |
James S. Robinson | 7,009 | July 1, 2003 through June 30, 2006 | 2,103 | 7,009 |
Masheed H. Rosenqvist | 9,392 | July 1, 2003 through June 30, 2006 | 2,818 | 9,392 |
Under the PSP, the Named Executive Officers and certain members of management are awarded notional allocations of shares. Shares vest after three years, subject to the satisfaction of the relevant performance criterion, which is set at the date of grant. Shares must then be held for a further year, after which they are released. For the grants set forth above, the relevant criterion is total shareholder return (TSR) performance over a three-year period, relative to the TSR performances of a group of comparator companies. This comparator group includes companies in the energy distribution sector, against which National Grid Transco benchmarks its performance for business purposes, and other utilities based in the UK, Europe and the US. The proportion of the original award of shares that will transfer to participants will depend on National Grid Transco’s performance when compared to the comparator group. National Grid Transco must achieve median ranking in order for participants to realize the threshold payout of 30% of the original award. It must rank in the upper quartile relative to the comparator group to achieve the maximum payout of 100% of the original award.
Option Exercises in Fiscal Year 2004 and Fiscal Year-End Option Values
The following table sets forth, for the Named Executive Officers, the number of shares for which stock options were exercised in fiscal year 2004, the realized value or spread (the difference between the exercise price and market value on the date of exercise) and the number and unrealized spread of the unexercised options held by each at fiscal year-end.
Name | Options Exercised (#) | Value Realized ($) | Number of Shares Underlying Unexercised Options on March 31, 2004 (a) | Value of Unexercised Options on March 31, 2004 (b) | ||
Vested | Unvested | Vested | Unvested | |||
Stephen P. Lewis | 0 | 0 | 0 | 15,848 | 0 | 0 |
Marc F. Mahoney | 0 | 0 | 0 | 68,364 | 0 | 0 |
James S. Robinson | 0 | 0 | 0 | 48,741 | 0 | 0 |
Masheed H. Rosenqvist | 0 | 0 | 0 | 48,523 | 0 | 0 |
(a) | Options granted in 2000 and 2001 were to have vested in March 2003 and March 2004, respectively, but as of March 31, 2004 they had not vested, as the Company’s total shareholder return did not meet specific performance conditions. |
(b) | At March 31, 2004, the price per Ordinary Share on the London Stock Exchange was lower than the exercise price for any of the named executive officers’ stock options. |
Pension Plans
National Grid Group Electricity Supply Pension Scheme
As a UK-based employee, Mr. Lewis participates in the National Grid Group Electricity Supply Pension Scheme. The Electricity Supply Pension Scheme is a contributory, defined benefit which provides a minimum retirement benefit to UK-based employees of National Grid Transco who were formerly employees of National Grid Company. Pension benefits are related to pensionable compensation for each year of service, subject to the maximum annual limits noted in the pension table below, plus a tax-free lump-sum payment equal to three times the annual pension benefit. Under the Electricity Supply Pension Scheme, a participant’s retirement benefit is computed using the highest of: (i) the last 12 months of salary, (ii) or any one year’s salary in the last five years, adjusted for inflation, or (iii) the annual average of any three consecutive years’ qualified salary in the last 10 years, adjusted for inflation. Normal retirement age under this plan is age 63. The pensionable compensation covered by the pension scheme includes base salary only. It does not include any bonuses or incentive share awards.
The following table shows the retirement benefits payable under the National Grid Group Electricity Supply Pension Scheme. The benefit calculations are made as of March 31, 2004 and assume the officer has selected a straight life annuity commencing at age 63. Dollar amounts are translated from pounds sterling at the rate of $1.68 per £1.00.
| Final Pensionable Salary | Years of Service | ||||
| 15 | 20 | 25 | 30 | 35 | |
| $126,000 | $23,625 | $31,500 | $39,375 | $47,250 | $55,125 |
| $168,000 | $31,500 | $42,000 | $52,500 | $63,000 | $73,500 |
| $210,000 | $39,375 | $52,500 | $65,625 | $78,750 | $91,875 |
| $252,000 | $47,250 | $63,000 | $78,750 | $94,500 | $110,250 |
| $294,000 | $55,125 | $73,500 | $91,875 | $110,250 | $128,625 |
| $336,000 | $63,000 | $84,000 | $105,000 | $126,000 | $147,000 |
| $378,000 | $70,875 | $94,500 | $118,125 | $141,750 | $165,375 |
| $420,000 | $78,750 | $105,000 | $131,250 | $157,500 | $183,750 |
| $504,000 | $94,500 | $126,000 | $157,500 | $189,000 | $220,500 |
In addition to the annual pension benefit, upon retirement a plan participant receives a tax-free lump-sum payment equal to three times the applicable annual pension benefit shown above. Mr. Lewis has 31 years of service.
National Grid USA Companies Final Average Pay Pension Plan (FAPP)
and Executive Supplemental Retirement Plan (ESRP)
As employees of National Grid USA companies, Mr. Mahoney, Mr. Robinson and Ms. Rosenqvist participate in the National Grid USA Companies Final Average Pay Pension Plan (FAPP). FAPP is a noncontributory, tax-qualified defined benefit plan which provides all employees of National Grid USA and its subsidiaries with a minimum retirement benefit. Pension benefits are related to compensation, subject to the maximum annual limits noted in the pension table below. Under FAPP, a participant’s retirement benefit is computed using formulas based on percentages of highest average compensation computed over five consecutive years. The compensation covered by the pension plan includes salary, bonus and incentive share awards.
The Executive Supplemental Retirement Plan (ESRP) is a noncontributory, nonqualified defined benefit plan that provides additional retirement benefits to Mr. Mahoney, Mr. Robinson and Ms. Rosenqvist and to certain members of management who are eligible to receive a FAPP benefit and whose compensation exceeds legal limits under the applicable plan or who are otherwise selected for participation. Depending on the participant, the ESRP may provide for unreduced benefits payable as early as age 55, may enhance the qualified plan formula, may give credit for more years of service or may award benefits not otherwise payable due to limits on benefits that can be provided under the qualified plan.
The following table shows the maximum retirement benefit (adjusted for Social Security, if applicable) an executive officer can earn in aggregate under FAPP together with the ESRP. The benefit calculations are made as of March 31, 2004 and assume the officer has selected a straight life annuity commencing at age 65. Annual compensation limits of $205,000 under a tax-qualified plan will reduce the portion payable for some highly compensated officers. The benefits listed are shown without any joint and survivor benefits. If at age 65 a participant elected a 100 percent joint and survivor benefit with a spouse of the same age, the benefit shown in the table would be reduced by approximately 16 percent.
| Five-Year Average Compensation | Years of Service | |||||
| 10 | 15 | 20 | 25 | 30 | 35 | |
| $100,000 | $18,921 | $27,381 | $35,841 | $44,051 | $52,262 | $57,222 |
| $150,000 | $29,921 | $43,381 | $56,841 | $69,926 | $83,012 | $91,222 |
| $200,000 | $40,921 | $59,381 | $77,841 | $95,801 | $113,762 | $125,222 |
| $250,000 | $51,921 | $75,381 | $98,841 | $121,676 | $144,512 | $159,222 |
| $300,000 | $62,921 | $91,381 | $119,841 | $147,551 | $175,262 | $193,222 |
| $350,000 | $73,921 | $107,381 | $140,841 | $173,426 | $206,012 | $227,222 |
| $400,000 | $84,921 | $123,381 | $161,841 | $199,301 | $236,762 | $261,222 |
| $450,000 | $95,921 | $139,381 | $182,841 | $225,176 | $267,512 | $295,222 |
| $500,000 | $106,921 | $155,381 | $203,841 | $251,051 | $298,262 | $329,222 |
The following Named Executive Officers have approximately the following credited years of benefit service as of March 31, 2004:Mr. Mahoney, 27 years; Mr. Robinson, 16 years; and Ms. Rosenquivst, 22 years. At retirement, Mr. Mahoney, Mr. Robinson and Ms. Rosenqvist may become eligible for post-retirement health and life insurance benefits determined based on their age and service. The executive may be required to contribute to the cost of benefits, depending on date of hire and total years of service.
Payments on a Change in Control or Termination of Employment
Payments on a Change in Control or Termination of Employment
At retirement, the Named Executive Officers (except for Mr. Lewis) and certain members of management may become eligible for post-retirement health and life insurance benefits determined based on their age and service. The executive may be required to contribute to the cost of benefits, depending on date of hire and total years of service.
Under the National Grid USA companies’ bonus plans, in the event of a change in control, each Named Executive Officer (except for Mr. Lewis) would receive a cash payment in an amount equal to the average annual bonus percentage for the incentive compensation plan level for the three prior years multiplied by that officer’s annualized base compensation. These payments would be made in lieu of the bonuses under these plans for the year in which the change in control occurs. In addition, provisions in the Retirees Health and Life Insurance Plan prevent changes in benefits adverse to the participants for three years following a change in control. Upon a change in control of National Grid USA, a participant in the deferred compensation plan may elect to receive a full distribution from the participant’s accounts plus the actuarial value of future benefits in relation to the insurance-related benefits under a prior plan, all less 10 percent.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table indicates the number of ordinary shares of National Grid Transco beneficially owned as of June 1, 2004 by: (a) each of the Named Executive Officers; (b) each director of the Company; and (c) all directors and executive officers of the Company as a group. Except as indicated, each such person has sole investment and voting power with respect to the shares shown as being beneficially owned by such person, based on information provided to the Company. Each person listed in this table owns less than one percent of the outstanding equity securities of National Grid Transco. National Grid USA owns all of the common stock of the Company.
Name | Number of Shares Beneficially Owned* |
Stephen P. Lewis | 19,565 |
Marc F. Mahoney | 17,345 |
James S. Robinson | 25,078 |
Masheed H. Rosenqvist | 26,163 |
John G. Cochrane | 74,712 |
Michael E. Jesanis | 113,931 |
Lawrence J. Reilly (a) | 108,751 |
Jeffrey A. Scott | 146,197 |
All directors and executive officers as a group (11 persons) (a) | 566,480 |
* | This number is expressed in terms of ordinary shares. It includes American Depositary Receipts listed on the New York Stock Exchange, each of which represents five ordinary shares |
(a) | Includes shares held by Mr. Reilly’s spouse. |
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
PricewaterhouseCoopers LLP, an independent registered public accounting firm, served as auditors of the Company for the fiscal year ended March 31, 2004.
Audit Fees
The aggregate fees billed by PricewaterhouseCoopers LLP for the audit of the Company’s financial statements and regulatory filings for the fiscal year ended March 31, 2004, and the reviews of quarterly reports on Form 10-Q filed during the fiscal year ended March 31, 2004 were $91,187. Fees billed by PricewaterhouseCoopers LLP for the audit of the Company’s financial statements and regulatory filings for the fiscal year ended March 31, 2003, and the reviews of quarterly reports on Form 10-Q filed during the fiscal year ended March 31, 2003 were $218,992.
Audit-Related Fees, Tax Fees and All Other Fees
The Company did not pay any other type of fee and did not receive any other services from PricewaterhouseCoopers LLP during the fiscal years ended March 31, 2004 and March 31, 2003.
The Company’s stockholders appoint the Company’s independent auditors, with the approval of the Audit Committee of the Company’s indirect parent company, National Grid Transco plc. Subject to National Grid Transco’s Articles of Association, the Audit Committee is solely and directly responsible for the approval of the appointment, re-appointment, compensation and oversight of the Company’s independent auditors. The Audit Committee must approve in advance all non-audit work to be performed by the independent auditors.
During the fiscal year ended March 31, 2004, all of the services provided by PricewaterhouseCoopers LLP to the Company were pre-approved by the Audit Committee.
ITEM 15. EXHIBITS AND REPORTS ON FORM 8-K
Reports on Form 8-K
The Company did not file any current reports on Form 8-K during the last quarter of fiscal year ended March 31, 2004.
Exhibits
The exhibit index is incorporated herein by reference.
SIGNATURES
Pursuant to the Requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company.
NEW ENGLAND POWER COMPANY | |||
Date: June 29, 2004 | By: | /s/ Stephen P. Lewis | |
Stephen P. Lewis | |||
President |
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, this report has been signed below on June 29, 2004 by the following persons on behalf of the registrant and in the capacities indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company.
Signature | Title | |
/s/ Stephen P. Lewis | ||
Stephen P. Lewis | President and Director (Principal Executive Officer) | |
/s/ John G. Cochrane | ||
John G. Cochrane | Vice President and Chief Financial Officer and Director (Principal Financial Officer) | |
/s/ Edward A. Capomacchio | ||
Edward A. Capomacchio | Controller (Principal Accounting Officer) | |
/s/ Michael E. Jesanis | ||
Michael E. Jesanis | Director | |
/s/ Lawrence J. Reilly | ||
Lawrence J. Reilly | Director | |
/s/ Jeffrey A. Scott | ||
Jeffrey A. Scott | Director |
EXHIBIT INDEX
Exhibit No. | Description |
| 3.1* | Articles of Organization as amended through June 25, 1987 (Exhibit 3(a) to 1988 Form 10-K, File No. 0-1229); Articles of Amendment dated January 27, 1998 (Exhibit B.18.a to National Grid USA 1999 Form U-5-S, File No. 30-33); Articles of Amendment dated February 25, 2000 (Exhibit 3(a) to 2000 Form 10-K, File No. 1-6564); Articles of Merger dated May 1, 2000 (Exhibit 3(a) to 2001 Form 10-K, File No. 1-6564) |
| 3.2* | By-laws of the Company as amended February 20, 2003 (Exhibit 3.2 to Form 10-K for fiscal year ended March 31, 2003, File No. 2-26651) |
| 10.1* | Boston Edison Company et al. and the Company: Amended REMVEC Agreement dated August 12, 1977 (Exhibit 5-4(d), File No. 2-61881) |
| 10.2* | Boston Edison Company et al. and the Company: REMVEC II Agreement dated on or about July 1, 1994 (Exhibit 10(a)(I) to NEES 1997 Form 10- K, File No. 1-3446) |
| 10.3* | Boston Edison Company et al. and the Company: Security Analysis Services Agreement dated on or about July 1, 1994 (Exhibit 10(a)(ii) to NEES 1997 Form 10-K, File No. 1-3446) |
| 10.4* | Connecticut Yankee Atomic Power Company et al. and the Company: Stockholders Agreement dated July 1, 1964 (Exhibit 13-9-A, File No. 2-2006); Power Purchase Contract dated July 1, 1964 (Exhibit 13-9-B, File No. 2-23006); Additional Power Contract dated as of April 30, 1984 and 1996; Amendatory Agreement dated as of December 4, 1996 (Exhibit 10(c) to 1996 Form 10-K, File No. 1-3446); Supplementary Power Contract dated as of April 1, 1987 (Exhibit 10(c) to 1987 Form 10-K, File No. 0-1229); Capital Funds Agreement dated September 1, 1964 (Exhibit 13-9-C, File No. 2-23006); Transmission Agreement dated October 1, 1964 (Exhibit 13-9-D, File No. 2-23006); Agreement revising Transmission Agreement dated July 1, 1979 (Exhibit to NEES 1979 Form 10-K, File No. 1-3446); Amendment revising Transmission Agreement dated as of January 19, 1994 (Exhibit 10(c) to NEES 1995 Form 10-K, File No. 1-3446); Five Year Capital Contribution Agreement dated November 1, 1980 (Exhibit 10(e) to NEES 1980 Form 10-K, File No. 1-3446) |
| 10.5* | Maine Yankee Atomic Power Company et al. and the Company: Capital Funds Agreement dated May 20, 1968 and Power Purchase Contract dated May 20, 1968 (Exhibit 4-5, File No. 2-29145); Amendments dated as of January 1, 1984, March 1, 1984 (Exhibit 10(d) to NEES 1983 Form 10-K, File No. 1-3446); October 1, 1984, and August 1, 1985 (Exhibit 10(d) to NEES 1985 Form 10-K, File No. 1-3446); Stockholders Agreement dated May 20, 1968 (Exhibit 10-20; File No. 2-34267); Additional Power Contract dated as of February 1, 1984 (Exhibit 10(d) to NEES 1985 Form 10-K, File No. 1-3446); 1997 Amendatory Agreement dated as of August 6, 1997 (Exhibit 10(d) to NEES 1997 Form 10-K, File No. 1-3446) |
| 10.6* | New England Electric Transmission Corporation et al. and the Company: Phase I Terminal Facility Support Agreement dated as of December 1, 1981 (Exhibit 10(g) to NEES 1981 Form 10-K, File No. 1-3446); Amendments dated as of June 1, 1982 and November 1, 1982 (Exhibit 10(f) to NEES 1982 Form 10-K, File No. 1-3446); Agreement with respect to Use of the Quebec Interconnection dated as of December 1, 1981 (Exhibit 10(g) to NEES 1981 Form 10-K, File No. 1-3446); Amendments dated as of May 1, 1982 and November 1, 1982 (Exhibit 10(f) to NEES 1982 Form 10-K, File No. 1-3446); Amendment dated as of January 1, 1986 (Exhibit 10(f) to NEES 1986 Form 10-K, File No. 1-3446); Agreement for Reinforcement and Improvement of the Company's Transmission System dated as of April 1, 1983 (Exhibit 10(f) to NEES 1983 Form 10-K, File No. 1-3446); Lease dated as of May 16, 1983 (Exhibit 10(f) to NEES 1983 Form 10-K, File No. 1-3446); Upper Development-Lower Development Transmission Line Support Agreement dated as of May 16, 1983 (Exhibit 10(f) to NEES 1983 Form 10-K, File No. 1-3446); Agreement with Respect to Second Amendment and Restatement of Agreement with Respect to Use of Quebec Interconnection dated November 19, 1997 (Exhibit 10(d) to 2002 Form 10-K, File No. 1-6564) |
| 10.7* | Vermont Electric Transmission Company, Inc. et al. and the Company: Phase I Vermont Transmission Line Support Agreement dated as of December 1, 1981; Amendments dated as of June 1, 1982 and November 1, 1982 (Exhibit 10(g) to NEES 1982 Form 10-K, File No. 1-3446); Amendment dated as of January 1, 1986 (Exhibit 10(h) to NEES 1986 Form 10-K, File No. 1-3446) |
| 10.8* | New England Power Pool Agreement: Restated New England Power Pool Agreement as amended through the Seventy-Sixth Agreement amending New England Power Pool Agreement and Amendments dated as of July 13, 2001, September 24, 2001, October 12, 2001, December 7, 2001, and January 18, 2002 (Exhibit 10(f) to 2002 Form 10-K, File No. 1-6564) |
| 10.9* | Vermont Yankee Nuclear Power Corporation et al. and the Company: Capital Funds Agreement dated February 1, 1968, Amendment dated March 12, 1968 and Power Purchase Contract dated February 1, 1968 (Exhibit 4-6, File No. 2-29145); Amendments dated as of June 1, 1972, April 15, 1983 (Exhibit 10(k) to NEES 1983 Form 10-K, File No. 0-1229) and April 24, 1985 (Exhibit 10(n) to NEES 1985 Form 10-K, File No. 1-3446); Amendment dated as of June 1, 1985 (Exhibit 10(n) to 1988 Form 10-K, File No. 0-1229); Amendments dated May 6, 1988 (Exhibit 10(n) to 1988 Form 10-K, File No.0-1229); Amendment dated as of June 15, 1989 (Exhibit 10(k) to 1989 NEES Form 10-K, File No. 1-3446); Additional Power Contract dated as of February 1, 1984 (Exhibit 10(k) to NEES 1983 Form 10-K, File No. 1-3446); Guarantee Agreement dated as of November 5, 1981 (Exhibit 10(j) to NEES 1981 Form 10-K, File No. 1-3446) |
| 10.9(a) | 2001 Amendatory Agreement dated as of September 21, 2001 between Vermont Yankee Nuclear Power Corporation and New England Power Company |
| 10.10* | Yankee Atomic Electric Company et al. and the Company: Amended and Restated Power Contract dated April 1, 1985 (Exhibit 10(l) to NEES 1985 Form 10-K, File No. 1-3446); Amendment dated May 6, 1988 (Exhibit 10(l) to NEES 1988 Form 10-K, File No. 1-3446); Amendments dated as of June 26, 1989 and July 1, 1989 (Exhibit 10(l) to 1989 NEES Form 10-K, File No. 1-3446); Amendment dated as of February 1, 1992 (Exhibit 10(l) to 1992 NEES Form 10-K, File No. 1-3446) |
| 10.11* | New England Hydro-Transmission Electric Company, Inc. et al. and the Company: Phase II Massachusetts Transmission Facilities Support Agreement dated as of June 1, 1985 (Exhibit 10(t) to NEES 1986 Form 10-K, File No. 1-3446); Amendment dated as of May 1, 1986 (Exhibit 10(t) to NEES 1986 Form 10-K, File No. 1-3446); Amendments dated as of February 1, 1987, June 1, 1987, September 1, 1987, and October 1, 1987 (Exhibit 10(u) to NEES 1987 Form 10-K, File No. 1-3446); Amendment dated as of August 1, 1988 (Exhibit 10(u) to NEES 1988 Form 10-K, File No.1-3446); Amendment dated January 1, 1989 (Exhibit 10(u) to NEES 1990 Form 10-K, File No. 1-3446) |
| 10.12* | New England Hydro-Transmission Corporation et al. and the Company: Phase II New Hampshire Transmission Facilities Support Agreement dated as of June 1, 1985 (Exhibit 10(u) to NEES 1986 Form 10-K, File No. 1-3446); Amendment dated as of May 1, 1986 (Exhibit 10(u) to NEES 1986 Form 10-K, File No. 1-3446); Amendments dated as of February 1, 1987, June 1, 1987, September 1, 1987, and October 1, 1987 (Exhibit 10(v) to NEES 1987 Form 10-K, File No. 1-3446).Amendment dated as of August 1, 1988 (Exhibit 10(v) to NEES 1988 Form 10-K, File No. 1-3446); Amendments dated January 1, 1989 and January 1, 1990 (Exhibit 10(v) to NEES 1990 Form 10-K, File No. 1-3446) |
| 10.13* | Vermont Electric Power Company et al. and the Company: Phase II New England Power AC Facilities Support Agreement dated as of June 1, 1985 (Exhibit 10(v) to NEES 1986 Form 10-K, File No. 1-3446); Amendment dated as of May 1, 1986 (Exhibit 10(v) to NEES 1986 Form 10-K, File No. 1-3446). Amendments dated as of February 1, 1987, June 1, 1987, and September 1, 1987 (Exhibit 10(w) to NEES 1987 Form 10-K, File No. 1-3446); Amendment dated as of August 1, 1988 (Exhibit 10(w) to NEES 1988 Form 10-K, File No. 1-3446) |
| 10.14* | Amended and Restated PPA Transfer Agreement between the Company and USGen New England, Inc. dated as of October 29, 1997 (Exhibit 10(aa) (iii) to 2001 Form 10-K, File No. 1-6564); First Amendment to Amended and Restated PPA Transfer Agreement dated as of October 10, 2001 (Exhibit 10(aa)(iii) to 2002 Form 10-K, File No. 1-6564) |
| 10.17* | Form of PSA Performance Support Agreement between the Company, USGen New England, Inc., and each of the following; Unitil Power Corp. (Ocean State), Braintree Electric Light Department, Littleton Electric Light Department, Massachusetts Government Land Bank, Shrewsbury Electric Light Plant, and Taunton Municipal Light Plant, dated as of August 5, 1997 (Exhibit 10(gg)(iv) to 1997 Form 10-K, File No. 1-6564) |
| 31.1 | Certifications of Principal Executive Officer |
| 31.2 | Certifications of Principal Financial Officer |
| 32 | Certifications Pursuant to 18 U.S.C. 1350 |