ITEM 1. BUSINESS
Niagara Mohawk Power Corporation (the Company) was organized in 1937 under the laws of New York State and is engaged principally in the regulated energy delivery business in New York State. The Company provides electric service to approximately 1,600,000 electric customers in the areas of eastern, central, northern and western New York and sells, distributes, and transports natural gas to approximately 562,000 gas customers in areas of central, northern and eastern New York.
On January 31, 2002, Niagara Mohawk Holdings, Inc. (Holdings), the parent company of Niagara Mohawk Power Corporation became a wholly owned subsidiary of National Grid USA (National Grid). National Grid is a wholly owned subsidiary of National Grid Transco plc (NGT).
REGULATION AND RATES
In conjunction with the closing of the merger with National Grid a new rate plan (the Merger Rate Plan) that had been approved by the New York Public Service Commission (PSC) went into effect, superseding the prior rate plan. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Regulatory Agreements and the Restructuring of the Regulated Electric Utility Business - Merger Rate Plan” for a detailed discussion of this rate plan.
Several critical initiatives have been undertaken by various regulatory bodies and the Company that have had, and are likely to continue to have, a significant impact on the Company and the utility industry. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Regulatory Agreements and the Restructuring of the Regulated Electric Utility Business” for a discussion of these initiatives.
ELECTRIC SUPPLY
Although the Company has exited the generation business, the Company must still arrange for electric supply through a transition period and as provider of last resort, in that the Company will provide electricity and gas to its customers who are unable or unwilling to obtain an alternative supplier (which accounts for approximately 93% of the Company’s customers). The Company purchases energy from various suppliers under long-term Purchase Power Agreements (PPAs) and purchases any additional power needs on the open market through the New York Independent System Operator (NYISO). The Company also enters into financial swaps in order to hedge the price of electricity. For a discussion of the results of the power contracts and several financial agreements to hedge the price of electricity, see Part II, Item 8. Financial Statements and Supplementary Data - Note D - Commitments and Contingencies, and Note L - Derivatives and Hedging Activities.
ELECTRIC DELIVERY
As of March 31, 2004, the Company had approximately 52,000 pole miles of transmission and distribution lines for electric delivery. Evaluation of these facilities relative to the requirements of the New York State Reliability Council, Northeast Power Coordinating Council, North American Electric Reliability Organization, NYISO, and PSC, their orders, operating and planning guides and criteria, security considerations, and anticipated Company internal and external electrical demands is an ongoing process intended to maintain the reliability of electric service. The Company continually reviews the adequacy of its electric delivery facilities and establishes capital requirements to support (within the above processes) its asset renewal, existing load and new load growth needs.
GAS SUPPLY
The majority of the Company’s gas sales are for residential and commercial space heating. The Company purchases its natural gas under firm supply agreements. The natural gas purchased may be either transported or stored for later transport on a firm basis through interstate storage facilities and pipelines to the Company's system.
GAS DELIVERY
The Company sells, distributes and transports natural gas to a geographic territory that generally extends from Syracuse to Albany. The northern reaches of the system extend to Watertown and Glens Falls. Not all of the Company’s distribution areas are physically interconnected with one another by its own facilities. Presently there are 12 separate distribution zones connected to 3 interstate natural gas pipelines regulated by the Federal Energy Regulatory Commission (FERC) and one intrastate pipeline regulated by the PSC. The Company has nineteen direct connections with Dominion Transmission, Inc., two with Iroquois Gas Transmission, one with Tennessee Gas Pipeline and one with Empire State Pipeline (intrastate).
ENVIRONMENTAL MATTERS
General. The Company’s operations and facilities are subject to numerous federal, state and local laws and regulations relating to the environment including, among other things, requirements concerning air emissions, water discharges, site remediation, hazardous materials handling, waste disposal and employee health and safety. While the Company devotes considerable resources to environmental compliance and promoting employee health and safety, the impact of future environmental health and safety laws and regulations on the Company cannot be predicted with certainty.
In compliance with environmental statutes and consistent with its strategic philosophy, the Company performs environmental investigations and analyses and installs, as required, pollution control equipment, including, among other things, effluent monitoring instrumentation and materials storage/handling facilities designed to prevent or minimize releases of potentially harmful substances.
The Company believes it is probable that costs associated with environmental compliance will continue to be recovered through the ratemaking process. For a discussion of the circumstances regarding the Company’s continued ability to recover these types of expenditures in rates, see Part II, Item 8. Financial Statements and Supplementary Data - Note B. Rate and Regulatory Issues.
Clean Air Act. See Item 3. Legal Proceedings, for a discussion of the potential liability for the past operations of Huntley and Dunkirk fossil generating stations.
ISO 14001. The Company’s Investment Recovery facility Environmental Management System (EMS) is certified to the International Organization for Standardization (ISO) 14001 standard. The Company’s distribution and transmission EMS are certified to the ISO 14001 standard. The NY Transmission System EMS has been integrated into the National Grid USA Transmission EMS.
Solid/Hazardous Waste. The public utility industry typically utilizes and/or generates in its operations a broad range of hazardous and potentially hazardous wastes and by-products. The Company believes it is handling identified wastes and by-products in a manner consistent with federal, state and local requirements and has implemented an environmental audit program to identify any potential areas of concern and aid in compliance with such requirements. The Company is also currently conducting a program to investigate and remediate, as necessary to meet current environmental standards, certain properties associated with former gas manufacturing and other properties which the Company has learned may be contaminated with industrial waste, as well as investigating identified industrial waste sites as to which it may be determined that the Company has contributed. The Company has also been advised that various federal, state or local agencies believe certain properties require investigation and has prioritized the sites based on available information in order to enhance the management of investigation and remediation, if necessary. See Part II, Item 8. Financial Statements and Supplementary Data - Note D. Commitments and Contingencies, “Environmental Contingencies,” for a more detailed discussion of the Company’s environmental liabilities.
EMPLOYEE RELATIONS
The Company’s New York work force at March 31, 2004 numbered approximately 5,500, of whom approximately 75 percent were union members. The Company, however, also receives substantial support for its activities from employees of National Grid USA Service Company, Inc. (Service Company), an affiliated company that provides administrative services support to all National Grid USA companies. The Company reimburses Service Company for the costs associated with those services.
SEASONALITY
There is seasonal variation in electric customer load, usually peaking in the winter and summer months. The seasonality is correlated to the colder or warmer temperature in that more electricity is used for heating or cooling during those months.
There is a seasonal variation in gas customer sales, with loads usually peaking in the winter months. The seasonality is correlated to the colder temperatures in that more gas is used for heating during those months.
Also see Part II, Item 8. Financial Statements and Supplementary Data - Note P. Quarterly Financial Data (unaudited).
SUBSIDIARIES
The Company has the following wholly-owned subsidiaries:
NM Uranium, Inc. - has an interest in a uranium mining operation in Live Oak County, Texas. The mining operation is complete and the site has been reclaimed and restored.
NM Properties, Inc. - engages in real estate development and divestiture of property formerly owned by the Company. NM Properties, Inc. owns several subsidiaries and has interests in several joint ventures in carrying out its activities.
ITEM 2.
ITEM 2. PROPERTIES
ELECTRIC
As of March 31, 2004, the Company’s electric transmission and distribution systems were composed of:
748 substations with a rated transformer capacity of approximately 22,800,000 kilo-volt-amperes
approximately 9,400 pole miles of overhead and underground transmission lines
approximately 36,000 conductor miles of overhead distribution lines
about 6,100 cable miles of underground distribution cables
Only a part of the Company’s transmission and distribution lines are located on property owned by the Company. With respect to the Company’s transmission and distribution lines that are located on property not owned by the Company, the Company’s practice is to obtain right of way agreements.
The electric system of the Company is directly interconnected with other electric utility systems in New York, Massachusetts, Vermont, Pennsylvania, and the Canadian provinces of Ontario and Quebec, and indirectly interconnected with most of the electric utility systems through the Eastern Interconnection of the United States and Canada.
GAS
The Company distributes gas that it purchases from suppliers, and transports gas owned by others. As of March 31, 2004, the Company’s natural gas delivery system was comprised of approximately 8,500 miles of pipelines. Only a small part of these natural gas pipelines and mains are located on property owned by the Company. With respect to natural gas pipelines and mains that are not located on property owned by the Company, the Company’s practice is to obtain right of way agreements.
NATIVE AMERICAN MATTERS
There are five Native American Nations with reservations located in the vicinity of the Company’s service territory and facilities. The Company has held discussions and has been involved in legal proceedings with Native American Nations involving the Company’s high voltage transmission facilities on Nation lands, provision of electric service to customers on Nation lands, and the Nations’ land claims.
In June 2000, the Company entered into a 40-year agreement with the Seneca Nation to settle issues related to approximately 50 miles of high voltage transmission and distribution facilities located on the Seneca Nation’s Cattaraugus and Allegheny Reservations. The Company has entered into federally approved Electric Service Agreements with the Onondaga, Tuscarora and Seneca-Tonawanda Nations governing the provision of electric service to customers on their lands. The Company intends to seek similar agreements with the Oneida and Mohawk Nations to supplement existing federally approved agreements. The Company’s facilities are potentially affected by land claim litigation involving the Cayuga, Oneida, Mohawk and Seneca Nations. A court has awarded damages to the Cayuga Nation that are payable by the State of New York. The land claim matters involving the Cayuga, Oneida, Mohawk and Seneca Nations have not been completely and finally resolved, although the St. Regis Mohawk Tribe recently entered into negotiations with New York State that could lead to resolution of the Mohawk’s land claims against parties including the Company. The Company continues to monitor the land claim litigation and, where necessary, defends its interests.
MORTGAGE LIENS
Substantially all of the Company’s operating properties are subject to a mortgage lien securing its mortgage debt.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
The Company currently has the following material proceedings pending.
Alliance for Municipal Power v. New York State Public Service Commission: On February 17, 2003, the Alliance for Municipal Power (AMP) filed with the New York State Supreme Court (Albany County) a petition for review of decisions by the PSC that maintain the PSC’s established policy of using average distribution rates when calculating the exit fees that may be charged to municipalities that seek to leave the Niagara Mohawk Power Corporation system and establish their own municipal light departments. Changes in the methodology for the calculation of the exit fee are not likely to have a material effect on Niagara Mohawk’s financial position, results of operations or cash flows. However, AMP’s petition for review also challenges the lawfulness of Niagara Mohawk’s collection of exit fees from departing municipalities, regardless of the methodology used to calculate those fees. On October 27, 2003, the court dismissed AMP’s petition. AMP made a timely filing to appeal the court’s decision but has not perfected its appeal.
New York State v. Niagara Mohawk Power Corp. et al.: On January 10, 2002, the New York State Attorney General filed a civil action against Niagara Mohawk, NRG Energy, Inc. and certain of its affiliates in U.S. District Court for the Western District of New York for alleged violations of the federal Clean Air Act, related state environmental statutes, and the common law, at the Huntley and Dunkirk power plants. The State alleged that between 1982 and 1999, Niagara Mohawk modified the two plants 55 times without obtaining proper preconstruction permits and implementing proper pollution equipment controls.
On March 27, 2003, the court issued an order granting in part Niagara Mohawk’s motion to dismiss, which had been filed in 2002. Based on applicable statutes of limitations, the court reduced the number of projects allegedly requiring preconstruction permits under the Clean Air Act from fifty-five to nine.
On December 31, 2003, the court granted the State’s motion to amend the complaint, allowing it to assert operating permit violations against Niagara Mohawk and NRG. In so ruling, the court stated that monetary penalties for actions outside the statute of limitations period would still be barred. Niagara Mohawk answered the amended complaint on March 2, 2004, and filed a counterclaim against the State of New York in response to its common law public nuisance claim, seeking contribution for the Company’s portion of any alleged harm caused by emissions from facilities that the State owns or to which it has given permits. The State has moved to dismiss the counterclaim. Trial is scheduled for March 2006.
Niagara Mohawk Power Corporation v. NRG Energy, Inc., Huntley Power L.L.C. and Dunkirk Power L.L.C.: With respect to the claims asserted in the Clean Air Act lawsuit discussed above, NRG and its Affiliates have taken the position that Niagara Mohawk is responsible at least in part for the costs of pollution control equipment and related fines and penalties, notwithstanding contrary language in the agreement governing the sale of the Plants to the NRG Affiliates. As a result, on July 13, 2001, Niagara Mohawk sued NRG and the NRG Affiliates in New York State Supreme Court (Onondaga County), seeking a declaratory ruling that under the agreement, NRG is responsible for the costs of any pollution control upgrades and mitigation, as well as post-sale fines and penalties, that may result from the Clean Air Act suit. In response, NRG filed a counterclaim and filed a motion for partial summary on its counterclaim. Hearing on NRG’s motion is scheduled for July 28, 2004.
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 New York Department of Environmental Conservation for numerous 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.
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. On May 4, 2004, by unanimous written consent of the sole common stockholder,
The following persons were elected as directors: William F. Edwards, Michael E. Jesanis, Clement E. Nadeau, Kwong O. Nuey, Jr. and Anthony C. Pini.
The firm of PricewaterhouseCoopers LLP, an independent registered public accounting firm, was appointed the Company’s auditor for the fiscal year ending March 31, 2005.
The actions taken by the directors and officers of the Company since the last vote were ratified.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDERS MATTERS
The common stock of the Company is held solely by Holdings, and therefore indirectly by National Grid and NGT. 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.
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
The following tables set forth selected financial information for the Company for the years ended March 31, 2004 and 2003, the sixty day period ended March 31, 2002, the thirty day period ended January 30, 2002, the three months ended March 31, 2001, and each of the three years during the period ended December 31, 2001. These tables have been derived from the financial statements of the Company, and should be read in connection therewith.
On January 31, 2002, the Company was acquired by National Grid 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 January 31, 2002. Information relating to all “predecessor” periods prior to the acquisition is presented using the Company’s historical basis of accounting. The following selected financial data for the Company may not be indicative of the Company’s future financial condition, results of operations or cash flows.
* All of the Company’s shares of common stock are owned by its parent company. Therefore, management considers dividend information and per share data are not relevant.
** Balance Sheet information as of the 30 day period ended January 30, 2002 is not provided.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
MERGER WITH NATIONAL GRID
On January 31, 2002, the acquisition of Holdings by National Grid was completed for a value of approximately $3.0 billion in cash and American Depositary Shares. The acquisition was accounted for by the purchase method, the application of which, including the recognition of goodwill, was recognized on the books of the Company, the most significant subsidiary of Holdings. The merger transaction resulted in approximately $1.2 billion of goodwill. The purchase accounting method required the Company to revalue its assets and liabilities at their fair value. This revaluation resulted in an increase to the Company’s pension and postretirement benefit liability in the amount of approximately $440 million, with a corresponding offsetting increase to a regulatory asset account. See “Merger Rate Plan”, below, for a discussion of the anticipated future results on the Company. See Item 8. Financial Statements and Supplementary Data, - Note H. Employee Benefits for a discussion of the Company’s pension and postretirement benefit plans.
VEROs
In fiscal 2004, National Grid made a voluntary early retirement offer (VERO) to eligible non-union employees in areas including transmission and corporate administrative functions such as finance, human resources, legal and information technology. A total of 53 employees of the Company accepted the VERO. The majority of them will retire by November 1, 2004, with the remainder retiring by November 1, 2007. The Company expensed approximately $19 million of VERO costs in the fiscal 2004. This amount included approximately $9 million allocated to the Company from Service Company, an affiliate.
In January 2002, the Company made a VERO to 302 eligible non-union employees in targeted areas where significant workforce reductions were necessary in the combined organization, primarily corporate administrative functions such as finance, human resources, legal and information technology. The number of eligible employees that accepted the VERO was 267 and most retired by June 30, 2002, with the last employees retiring by March 31, 2004. Under the Merger Rate Plan, the Company is allowed to record a regulatory asset for separation and early retirement costs. The amortization of such regulatory asset is occurring over ten years, with approximately 69 percent of the amortization of the regulatory asset occurring within the first three years. On January 31, 2002, the Company recorded a regulatory asset of $53 million related to the VERO. This regulatory asset had a balance of approximately $22 million and $30 million at March 31, 2004 and 2003, respectively.
REGULATORY AGREEMENTS AND THE RESTRUCTURING OF
THE REGULATED ELECTRIC UTILITY BUSINESS
Merger Rate Plan. On November 28, 2001, the PSC approved the Merger Rate Plan. This rate plan became effective on January 31, 2002, the closing of the merger. Key terms of the plan are as follows:
• Net customer savings of approximately $1 billion over the next ten years from the effective date of the plan, compared with rates projected without the merger.
• Price-stabilized commodity service for residential and commercial customers for several years.
• Agreement to forgo the collection of approximately $850 million in nuclear-related costs that otherwise would have been collected in rates.
• Permitted recovery of and a return on the Company’s regulatory assets, including stranded costs associated with the divestiture of generation assets under deregulation.
• Agreement to expand the Company’s annual upstate New York economic development efforts by $12.5 million.
• The extension by 16 months of the existing multi-year gas rate settlement agreement, resulting in a freeze in natural gas delivery rates through December 2004.
•Extension of the Low Income Customer Assistance Program and introduction of a special low-income rate.
• Establishment of a Service Quality Assurance Program that calls for up to $24 million in annual penalties or more under certain conditions, if defined customer service goals are not achieved.
The sharing with customers of 50 percent of any cumulative earnings in excess of an 11.75 percent return on common equity.
Although rates will be lower under the Merger Rate Plan, the Company believes cost savings from the merger should enable it to improve its operating results.
Retail Bypass: In approving Power Choice, the rate plan in effect prior to the Merger Rate Plan, the PSC authorized changes to the Company’s retail tariff providing for the recovery of an exit fee for customers that leave the Company’s system. The retail tariff governs the application and calculation of the exit fee. The exit fee also applies to municipalities seeking to serve customers in the Company’s service area.
On September 22, 2002, a different type of retail bypass issue was presented in a filing with FERC by the NYISO seeking to implement a new station service rate which also provided that generators could net their station service electricity over a 30-day period. On November 22, 2002, FERC issued an order accepting the NYISO’s new rate, over the Company’s protest (the FERC NYISO Order). The FERC NYISO Order has allowed generators to argue that they should be able to avoid paying state-approved charges for retail deliveries when they take service under the NYISO tariff. On July 10, 2003, the Company filed modifications to its standby service rates with the PSC, which the PSC approved on November 25, 2003. The tariff modifications unbundle the transmission service component provided under the NYISO’s new rate but continue the Company’s own retail distribution charges to these customers.
A number of generators have complained or withheld payments associated with the Company’s delivery of station service to their generation facilities, including NRG Energy, Inc. (For a description of the NRG station service matter, see Item 8. Financial Statements and Supplementary Data, Note D. Commitments and Contingencies.) On December 23, 2003, FERC issued two orders on complaints filed by AES Somerset, L.L.C. (AES) and Nine Mile Point Nuclear Station, L.L.C. (Nine Mile) (together, the AES and Nine Mile FERC Orders), both of which are station service customers of the Company. The two orders allow these generators to net their station service electricity over a 30-day period and to avoid state-authorized charges for deliveries made over distribution facilities. While it is not entirely clear from reading the AES and Nine Mile FERC Orders, it is possible to construe them to have retroactive effect back to the date the plant was sold to AES by a third party. The net effect of these FERC decisions is that the two generators will no longer have to pay the Company for station service charges for electricity. The AES and Nine Mile FERC Orders are in direct conflict with the state-approved tariffs and the orders of the PSC on station service rates. The FERC orders, if upheld, will permit these generators to completely bypass the Company’s state-jurisdictional retail charges, including those set forth in the filing that was approved by the PSC on November 25, 2003. On February 23, 2004, the Company received orders granting rehearing for further consideration from the FERC in both the AES and Nine Mile Point proceedings. No further action on the rehearing requests has occurred to date.
On May 10, 2004, FERC issued an order denying motions for clarification filed by the Company and other parties with respect to the FERC NYISO Order, and reaffirmed its reasoning of the AES and Nine Mile FERC Orders. In so ruling, FERC indicated that the NYISO station service would be limited to merchant generators self-supplying their own power, and should not be interpreted to apply to self-supplying retail industrial and commercial customers. The Company intends to appeal.
The AES and Nine Mile FERC Orders and FERC NYISO Orders have increased the risk that generators will be able to bypass local distribution company charges (including stranded cost recovery charges) when receiving service through the NYISO. To the extent that the Company experiences any lost revenue attributable to retail bypass, it is permitted to recover these lost revenues under its rate plans.
Generation Asset Sales. Under deregulation, the Company divested all of its generation plants and operates primarily in the transmission and distribution sectors. The last generation asset sold was the Company’s share of the Nine Mile Point Nuclear Station for $603 million to Constellation in November 2001. The Company also signed PPAs with Constellation to purchase energy at negotiated prices through 2011 and revenue sharing agreements for ten years thereafter. See Item 8. Financial Statements and Supplementary Data, Note B. Rate and Regulatory Issues, Note D. Commitments and Contingencies, and Note L. Derivatives and Hedging Activities, for a further discussion of the terms of these agreements.
Following write-offs agreed to by the Company, the PSC approved the sale of Nine Mile Point and provided for the deferral and future recovery of the remaining nuclear stranded costs. The Company began to amortize the regulatory asset related to the loss on the sale of the nuclear assets immediately subsequent to such sale. Prior to implementation of the Merger Rate Plan, the Company had a regulatory asset of $1,074.6 million for the net loss on the sale of its nuclear generation assets. Under the Merger Rate Plan, the Company agreed to forgo collection of approximately $850 million in nuclear-related costs that otherwise would have been collected in rates. The nuclear regulatory asset that remained after such a write-off is included in the Company’s balance sheet as part of “Merger rate plan stranded costs.”
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.
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 an Energy Affiliate. 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. The Company’s Granite State Electric subsidiary falls within the technical definition of an Energy Affiliate because it is a company not engaged in transmission that makes a wholesale power sale. We have asked FERC for a waiver of its rules with respect to Granite State, however, pointing out that Granite State has no financial interest in its wholesale power sale. The regulations do not create any significant new financial risks for us.
PSC Issues. In February 2004, the Company reached an agreement with PSC Staff that would provide rate recovery for approximately $15 million of the $30 million pension settlement loss incurred in fiscal 2003. This agreement is subject to approval by the full New York State Public Service Commission. In addition, the agreement covers the funding of the entire settlement loss to benefit plan trust funds. Under the agreement, the Company will fund the non-recoverable portion of this loss within 30 days of approval of the agreement. The Company plans to file a petition with the PSC seeking recovery of its fiscal year 2004 settlement losses as well. For further discussion of the settlement losses see Item 8. Financial Statements and Supplementary Data - Note H. Employee Benefits.
In August 2003, the PSC approved a settlement with the Company following an audit that identified reconciliation issues between the rate allowance and actual costs of the Company’s pension and other post-retirement benefits. The settlement resolved all issues associated with those obligations for the period prior to its acquisition by National Grid and, among other things, covered the funding of the Company’s pension and post-retirement benefit plans. As part of the settlement, the Company provided $100 million of tax-deductible funding during fiscal 2003 and an additional $209 million of tax-deductible funding by the end of fiscal 2004. Under the settlement, the Group will earn a rate of return of at least 6.60 percent (nominal) on the $209 million of funding through December 31, 2011 and is eligible to earn 80 percent of the amount by which the rate of return on the pension and post-retirement benefit funds exceeds 5.34 per cent (nominal) measured as of that date. This settlement resolves all PSC staff audit issues related to the pre-acquisition period with the exception of certain gas deferrals and a Staff review of a pending Company compliance filing related to the sale of the Nine Mile Nuclear Station.
As part of the Company's ongoing reconciliation of commodity costs and revenues, the Company has identified several adjustments and included them in filings with the PSC. Specifically, the Company has requested recovery of $36 million of commodity costs associated with the under-reconciliation of New York Power Authority (NYPA) hydropower revenues in its commodity adjustment clause, and is proposing to refund $24 million associated with other revenues that were not included in the commodity adjustment reconciliation. This filing is pending before the PSC, and the Company cannot predict the outcome of the filing.
On February 19, 2003, the PSC commenced a proceeding to create a renewable portfolio standard for New York State, establishing a working target that 25% of the energy retailed in New York would be generated from qualifying renewable resources. An administrative law judge issued a recommended decision on June 3, 2004 for review by the full Commission. The decision proposes that an incremental amount of 7.5% renewable resource energy (13.7 Million MWhs) be retailed in New York State by 2013 or later, depending on the results of a proposed Commission review in 2008. If the Commission adopts the recommendations, individual load-serving entities such as Niagara Mohawk would have to comply with annual program targets beginning in 2006. The decision contemplates that utilities would have an opportunity to recover program costs in rates, subject to prudence reviews. The Commission will receive public comments on the recommendations before rendering any decision.
During fiscal 2004, the PSC issued an order related to the potential sale of a Company building. The order addresses the sharing between customers and the Company of sales proceeds and future avoided costs that will result from disposal of the building, as well as the sharing of the transaction costs and remaining net book value of this facility. In its order, the PSC has directed the Company to share with customers 50% of the benefits and costs associated with the sale, including the undepreciated net book value of the building. As of March 31, 2004, the sale of this facility remains subject to future performance by the proposed purchaser, and as such, the Company has not recorded the potential effects of this transaction in its records. Upon completion of the sale of this building, the Company will record a net charge of approximately $3 million (pre-tax) to expense reflecting its net unrecovered cost of this facility. The order also directs the Company to follow the same accounting and ratemaking treatment for the sale of other buildings during the term of the Merger Rate Plan.
OTHER
Change of Fiscal Year. At the time of the merger with National Grid, the Company changed its fiscal year from a calendar year ending December 31 to a fiscal year ending March 31. The Company made this change in order to align its fiscal year with that of its new parent company, National Grid. The Company’s first new full fiscal year began on April 1, 2002 and ended on March 31, 2003.
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, PSC, 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 (such as current rate agreements with the PSC) 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 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 the Stranded cost regulatory asset is shown separately (as it is the largest component of Regulatory Assets). Amortization of other regulatory assets are included in depreciation and amortization, purchased electricity & gas, and other operation and maintenance expense captions on the income statement (depending on the origin of the regulatory asset).
Unbilled Revenues. Revenues from the sale of electricity and gas to customers are generally recorded when electricity and gas are delivered to those customers. The quantity of those sales is measured by customers' meters. Meters are read on a systematic basis throughout the month based on established meter-reading schedules. Consequently, at the end of any month, there exists a quantity of electricity and gas that has been delivered to customers but has not been captured by the meter readings. As a result, management must estimate revenue related to electricity and gas delivered to customers between their meter read dates and the end of the period.
Pension and Other Post-retirement 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 pensions are funded through an outside trust.
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 more significant assumptions included the assumed return on assets, discount rate, and in the case of retiree healthcare benefits, medical trend assumptions. All ongoing costs of qualified pension and post-retirement healthcare benefits plans are recoverable from customers through reconciling provisions of the Merger Rate Plan. Special termination benefits paid in connection with employee separation programs and settlement and curtailment losses of pension and post-retirement benefit plans when incurred are only recoverable upon approval by the PSC.
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 8.0% 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”. Determination of current year federal and state income tax will not be settled for years.
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.
Accounting for Derivative Instruments. The Company accounts for derivative financial instruments under SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (FAS 133), and SFAS No. 149, “Amendment of SFAS No. 133 on Derivative Instruments and Hedging Activities,” as amended. Under the provisions of FAS 133, all derivatives except those qualifying for the normal purchase normal sale exception are recognized on the balance sheet at their fair value. Fair value is determined using current quoted market prices. If a contract is designated as a cash flow hedge, the change in its market value is generally deferred as a component of other comprehensive income until the transaction it is hedging is completed. Conversely, the change in the market value of a derivative not designated as a cash flow hedge is deferred as a regulatory asset or liability. A cash flow hedge is a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. To qualify as a cash flow hedge, the fair value changes in the derivative must be expected to offset 80% to 120% of the changes in fair value or cash flows of the hedged item.
The Company has received approval from the PSC to establish a regulatory asset or liability derivative instruments that did not qualify for hedge accounting and were the result of regulatory rulings.
RESULTS OF OPERATIONS
The following discussion and analysis highlights items that significantly affected the Company’s operations during the years ended March 31, 2004 and 2003, the three months ended March 31, 2002 and 2001, and the year ended December 31, 2001. See “Merger Rate Plan” for a further discussion of how the closing of the merger with National Grid has or will impact the current and future results of the Company. Results of operations through January 30, 2002 reflect the Power Choice rate plan and the Company’s generation assets sales. Reported earnings under Power Choice were substantially depressed as a result of the regulatory treatment of the Stranded cost regulatory asset. Information relating to all “predecessor” periods prior to the acquisition is presented using the Company’s historical basis of accounting. It should also be read in conjunction with Item 8. Financial Statements and Supplementary Data, and other financial and statistical information appearing elsewhere in this report.
Beginning with the merger in January 2002, the Company now reports results on a fiscal year ending March 31. To assist in the comparability of the Company’s financial results and discussions, results of operations for the three months ended March 31, 2002 include results for the 30 day period of the predecessor and the 60 day period of the successor and are designated as “combined.” Management has based its discussion and analysis of results of operations for the year ended March 31, 2003 as compared to the year ended December 31, 2001. Management has also based its discussion and analysis of results of operations for the three month period ending March 31, 2002 as compared to the three month period ending March 31, 2001 on the combined results of operations for the three month period ending March 31, 2002.
EARNINGS
Net income for the year ended March 31, 2004 increased by approximately $14 million from the prior year. This increase is primarily due to the reduced interest costs from the redemption or refinancing of long-term debt using lower cost associated company debt or funds from the intercompany money pool. Partially offsetting these cost reductions were lower sales of both electricity and gas due to more normal weather conditions in the current year than in the prior year. See the following discussions of revenues and operating expenses for more detailed explanations.
Net income for the fiscal year ended March 31, 2003 increased approximately $107 million compared to the year ended December 31, 2001. This increase is primarily due to the implementation of the Merger Rate Plan and a $123 million write-off in 2001 in connection with the sale of the Company’s nuclear assets, which was completed in 2001. Under the Merger Rate Plan, the Company has lowered delivery rates leading to lower operating revenues. However, this has been offset by lower operating expenses as a result of merger savings, the sale of the generation business and lower interest expense due to refinancing and the continuing repayment of debt.
Net income for the three months ended March 31, 2002 was approximately $24 million lower than the three month period ended March 31, 2001. A decline in operating income due to the effect a warm winter had on the gas business and increased other operation and maintenance costs was partially offset by lower interest expense due to the repayment of debt during 2002.
REVENUES
Electric revenues decreased $27 million during the year ended March 31, 2004 from the prior year. Electric revenues decreased $82 million in the twelve months ended March 31, 2003 as compared to the twelve months ended December 31, 2001. The table below details components of this fluctuation.
The decrease in retail sales for year ended March 31, 2004 from the comparable period in prior year was primarily attributable to a decrease in electric kilowatt-hour (KWh) deliveries (see below). Volume growth, primarily in the residential sector partially offset these decreases. Regulatory asset revenue comparisons were also affected by anticipated reductions in the return on regulatory assets and lower purchase power costs (due to lower demand).
The decrease in sales for resale for the twelve-months ended March 31, 2003 as compared to the twelve month ended December 31, 2001 is primarily attributable to lower sales to the NYISO. Transmission delivery revenue was lower primarily due to lower NYISO Transmission Congestion Contracts (TCC) auction revenues. Retail sales revenues increased due to higher delivery only revenue by $88 million, but were almost entirely offset by lower electric rates under the Merger Rate Plan.
Electric revenues decreased $1 million in the three months ended March 31, 2002 as compared to the same period in the 2001.
Electric kilowatt-hour sales were approximately 38.3 billion and 38.8 billion for the year ended March 31, 2004 and 2003, 9.4 billion and 9.3 billion for the three months ended March 31, 2002 and the same period in 2001, respectively, and 39.9 billion in the calendar year 2001.
Electric deliveries decreased 0.5 billion KWh for the year ended March 31, 2004 from the prior year. The decrease is primarily due to a return of more normal weather in the current fiscal year, versus the more extreme weather last year, particularly in the summer months. Offsetting this decrease was strong residential Kwh sales growth of 4.6%. Electric deliveries for the twelve-months ended March 31, 2003 as compared to the twelve months ended December 31, 2001 decreased 1.1 billion KWh. The decrease is primarily due to a decrease in sales for resale of 2.1 billion KWh as a result of lower sales to the NYISO and lower sales to commercial and industrial customers of 2.1 billion KWh offset by increased residential sales of 0.6 billion KWh and an increase in delivery only of energy of 2.5 billion KWh.
Electric deliveries for the three months ended March 31, 2002 as compared to the same period in 2001 increased 0.1 billion KWh and increased 3.6 billion KWh in the calendar year 2001 as compared to the same period in 2000. The increase in the three months ended March 31, 2002 as compared to the same period in 2001 is primarily due to an increase in sales for resale of 0.7 billion KWh as a result of higher sales to the NYISO and an increase in distribution of energy of 0.2 billion KWh, partially offset by a decrease in sales to ultimate customers of 0.7 billion KWh primarily due to the milder weather.
Gas revenues increased $71 million in the fiscal year ended March 31, 2004 from the prior year. This increase is primarily a result of higher prices of gas purchases, which are being passed through to customers. Partially offsetting these increases was an $8.0 million adjustment related to state income tax revenue deferrals.
Gas revenues decreased $13 million for the twelve-months ended March 31, 2003 compared to the twelve-months ended December 31, 2001 primarily due to a decrease in the commodity cost of purchased gas offset somewhat by an increase in delivery revenue. The primary reason for the increase in delivery revenue is higher rates which reflect the inclusion of the state income tax in the rates charged to customers. The decrease in the cost of purchased gas is explained below under “gas purchased” expense.
The table below details components of the gas revenue fluctuation:
Gas revenues decreased $127 million in the three months ended March 31, 2002 from the comparable period in 2001 due to lower purchased gas prices and milder weather in 2002.
The change in the cost of purchased gas has no impact on the Company’s net income because the actual commodity costs are passed through to customers on a dollar-for-dollar basis.
Gas sales for the twelve months ended March 31, 2004, excluding transportation of customer-owned gas, decreased approximately 3.6 million Dekatherms (Dth), or a 2 percent decrease from the prior year, primarily due to reduced deliveries to electric generation customers. Gas sales for the twelve months ended March 31, 2003, excluding transportation of customer-owned gas and spot market sales, were 69 million Dth, a 5.8 percent increase from the twelve-months ended December 31, 2001. The increase was primarily due to the impacts of weather as offset by migration to delivery only service. Gas sales in the calendar year 2001, excluding transportation of customer-owned gas and spot market sales, were 64 million Dth. Gas sales in the three months ended March 31, 2002, excluding transportation of customer-owned gas and spot market sales, were 28 million Dth, a 19.6 percent decrease from the same period in 2001. The decrease was primarily due to milder weather in the three months ended March 31, 2002 as compared to the same period in 2001.
OPERATING EXPENSES
Purchased electricity decreased approximately $3 million for the year ended March 31, 2004 from the prior year. Corresponding to lower electric sales, the Company purchased less KWh of electricity versus last year. In addition, contractual obligations to certain higher cost suppliers expired in the fiscal 2004, which resulted in a reduction to purchased power expense of $16 million, as compared to the prior year. However, increases in the market price of electricity, substantially offset these decreases.
Purchased electricity increased $290 million for the year ended March 31, 2003 as compared to the year ended December 31, 2001, $52 million in the three months ended March 31, 2002 as compared to the same period in 2001, primarily as a result of the timing of the various sales of the Company’s generation assets. The Company now purchases all of its load requirement through the NYISO, or from other parties under long-term PPAs (for a discussion of the portion of the purchases that are hedged. Although the prices the Company must pay for electricity are higher than the fuel costs it incurred when the assets were owned, the Company avoids operating costs from running these plants, including labor, fuel, real estate taxes, and depreciation.
Significantly higher natural gas prices impacted the Company’s fuel and purchased power costs in early 2001, principally because restructured contracts with IPPs began indexing to natural gas prices in July 2000. Fuel and purchased power costs were also higher in early 2001 because of an indexed contract with the new owner of the Albany generating station and an indexed contract with an IPP not part of the Master Restructuring Agreement (MRA). The Albany station is fueled by oil or natural gas. With respect to its exposure to the restructured contracts with the IPPs and the Albany contract, the Company takes steps to hedge against further volatility in natural gas prices, largely by purchasing New York Mercantile Exchange (NYMEX) gas futures contracts. On September 1, 2001, the rate plan changes under the Power Choice rate agreement allowed for the pass-through of most commodity-related costs to customers. This pass-through of commodity costs to customers continues under the Merger Rate Plan.
IPP purchases decreased by $17 million in the three months ended March 31, 2002 as compared to the same period in 2001, since the Company entered into an agreement with one IPP that reduced the amount of energy it had to buy from them. In the three months ended March 31, 2001, the Company paid that IPP $18 million. The Company did not make any payments to that particular IPP in the same period in 2002.
The Company had no fuel for electric generation expense in either the twelve-months ended March 31, 2004 and 2003 or the three months ended March 31, 2002 because it had sold all of its generation assets in earlier periods.
Purchased gas expense increased approximately $85 million for the year ended March 31, 2004 from the prior year. This increase is primarily a result of increased gas prices during the year. The Company’s net cost per Dth, as charged to expense, including the effects of the gas cost deferral, increased to $6.61 in the year ended March 31, 2004 from $5.57 in the prior year. This increase in price was slightly offset by decreased purchases. Quantities purchased and withdrawn from storage were down 3.6 million Dth.
Purchased gas expense decreased approximately $26 million for the twelve-months ended March 31, 2003 as compared to the twelve-months ended December 31, 2001. The decrease is a result of lower gas prices in the twelve-months ended March 31, 2003 partially offset by increased sales attributable to the colder winter weather conditions than in the comparable prior period. The Company’s net cost per Dth, as charged to expense, including the effects of the gas cost deferral, decreased to $5.57 in the twelve-months ended March 31, 2003 from $6.45 for the twelve-months ended December 31, 2001. Quantities purchased and withdrawn from storage were up 5.7 million Dth.
Purchased gas expense decreased $120 million in the three months ended March 31, 2002 as compared to the same period in 2001 primarily as a result of lower natural gas prices. The Company’s net cost per Dth, as charged to expense, including the effects of the gas commodity cost adjustment clause, decreased to $3.97 in the three months ended March 31, 2002 from $7.53 the same period in 2001. Dth purchased and withdrawn from storage were down 0.4 million Dth.
For a discussion of hedging of gas purchases, see Item 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to certain market risks because of transactions conducted in the normal course of business. The financial instruments held or issued by the Company are used for investing, financing, hedging or cost control and not for trading.
Quantitative and qualitative disclosures are discussed by market risk exposure category:
Interest Rate Risk
Commodity Price Risk
Equity Price Risk
Foreign Currency Exchange Risk
An Energy Procurement Risk Management Committee (EPRMC) was established to monitor and control efforts to manage these risks. The EPRMC issues and oversees the Financial Risk Management Policy (the Policy) that outlines the parameters within which corporate managers are to engage in, manage, and report on various areas of risk exposure. At the core of the Policy is a condition that the Company will engage in activities at risk only to the extent that those activities fall within commodities and financial markets to which it has a an actual market exposure in terms and in volumes consistent with its core business. That core business is to deliver energy, in the form of electricity and natural gas, to customers within the Company’s service territory. The policies of the Company may be revised as its primary markets continue to change, principally as increased competition is introduced and the role of the Company in these markets evolves.
Interest Rate Risk. The Company is exposed to changes in interest rates through several series of adjustable rate promissory notes and short-term borrowings. See Item 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
A. FINANCIAL STATEMENTS
Reports of Independent Registered Public Accounting Firm
Consolidated Statements of Operations, Consolidated Statements of Comprehensive Income (Loss), and Consolidated Statements of Retained Earnings for each of the two years in the period ended March 31, 2004, the sixty day period ended March 31, 2002, the thirty day period ended January 30, 2002, the three months ended March 31, 2001 (unaudited) and the year ended December 31,
Consolidated Balance Sheets at March 31, 2004 and
Consolidated Statements of Cash Flows for each of the two years in the period ended March 31, 2004, the sixty day period ended March 31, 2002, the thirty day period ended January 30, 2002, the three months ended March 31, 2001 (unaudited) and the year ended December 31, 2001
Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of Directors of
Niagara Mohawk Power Corporation:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive income (loss), of retained earnings and of cash flows present fairly, in all material respects, the financial position of Niagara Mohawk Power Corporation and its subsidiaries at March 31, 2004 and 2003, and the results of their operations and their cash flows for each of the two years in the period ended March 31, 2004 and the sixty day period ended March 31, 2002 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 Notes
D and E, as to which the dates
are May 10, 2004 and May 27, 2004,
respectively
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of Directors of
Niagara Mohawk Power Corporation:
In our opinion, the accompanying consolidated statements of operations, of comprehensive income (loss), of retained earnings and of cash flows present fairly, in all material respects, the results of operations and cash flows of Niagara Mohawk Power Corporation and its subsidiaries for the thirty day period ended January 30, 2002 and for the year ended December 31, 2001 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 14, 2002
Per share data is not relevant because the Company’s common stock is wholly-owned by Niagara Mohawk Holdings, Inc.
The accompanying notes are an integral part of these financial statements.
The accompanying notes are an integral part of these financial statements.
The accompanying notes are an integral part of these financial statements.
The accompanying notes are an integral part of these financial statements.
The accompanying notes are an integral part of these financial statements.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation: Niagara Mohawk Power Corporation (the Company) is subject to regulation by the New York State Public Service Commission (PSC) and the Federal Energy Regulatory Commission (FERC) with respect to its rates for service under a methodology that establishes prices based on the Company’s cost. The Company’s accounting policies conform to Generally Accepted Accounting Principles in the United States of America (GAAP), including the accounting principles for rate-regulated entities with respect to the Company’s transmission, distribution and gas operations (regulated business), and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities.
The Company is a wholly-owned subsidiary of Niagara Mohawk Holdings, Inc. (Holdings), which in turn is wholly-owned by National Grid USA (National Grid).
The Company’s consolidated financial statements include its accounts as well as those of its wholly owned subsidiaries. Inter-company balances and transactions have been eliminated.
The closing of the merger with National Grid and the related push down and allocation of the purchase price has had a significant effect on the reported results of the Company. The sale of the Company’s generation assets at various times during 1999 through 2002 has also affected the comparability of the financial statements.
The consolidated statements of cash flows for the Company have been presented to reflect the closings of the sales of the generation assets, such that certain individual line items are net of the effects of the sales.
Acquisition by National Grid: On January 31, 2002, the acquisition of Holdings by National Grid was completed for a consideration of approximately $3 billion in cash and American Depositary Shares.
The application of the purchase accounting method and implementation of the Merger Rate Plan resulted in substantial changes to the Company’s balance sheet, principally in the recording of goodwill, the write-down of regulatory assets, and the increase in the Company’s capital structure.
The closing of the merger with National Grid and the related push down and allocation of the purchase price has had a significant effect on the reported results of the Company. For a further discussion of Company’s new rate agreement see Note B.
The purchase accounting method required the Company to revalue its assets and liabilities at their fair value. This revaluation resulted in an increase to Niagara Mohawk’s pension and postretirement benefit plan liabilities in the amount of approximately $440 million, with a corresponding offsetting increase to a regulatory asset account. See Note H.
Change of Fiscal Year: The Company changed its fiscal year from a calendar year ending December 31 to a fiscal year ending March 31. The Company made this change in order to align its fiscal year with that of National Grid. The Company’s first new full fiscal year began on April 1, 2002 and ended on March 31, 2003.
Goodwill: The acquisition of the Company was accounted for by the purchase method, the application of which, including the recognition of goodwill, was recognized on the books of the Company, the most significant subsidiary of Holdings. The merger transaction resulted in approximately $1.2 billion of goodwill. In accordance with Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets”, the Company reviews its goodwill annually for impairment 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.
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 consolidated 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 AFUDC (see below). 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 in amounts equivalent to the cost of funds devoted to plant under construction for its regulated business. AFUDC represents an allowance for the cost of funds used to finance construction. AFUDC is capitalized in "Utility plant" with offsetting non-cash credits to "Other interest" and “Other income (deductions)” on the Consolidated Statement of Operations. 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. AFUDC rates are determined in accordance with FERC and PSC regulations. The AFUDC rates in effect at March 31, 2004 and 2003 were 1.22 percent and 1.50 percent, respectively. AFUDC is segregated into its two components, borrowed funds and other funds, and is reflected in the “Other interest” and “Other income (deductions)” sections, respectively, in the Company’s Consolidated Statements of Operations. The amounts of AFUDC credits were recorded as follows:
Depreciation: For accounting and regulatory purposes, the Company’s depreciation is computed on the straight-line basis using the average service lives. The Company performs depreciation studies to determine service lives of classes of property and adjusts the depreciation rates when necessary.
The weighted average service life, in years, for each asset category is presented in the table below:
Revenues: The Company bills its customers on a monthly cycle basis at approved tariffs based on energy delivered and a minimum customer service charge. Revenues are determined based on these bills plus an estimate for unbilled energy delivered between the cycle billing date and the end of the accounting period. The unbilled revenues included in accounts receivable at both March 31, 2004 and 2003 was approximately $132 million.
The Company recognizes changes in accrued unbilled electric revenues in its results of operations. Pursuant to the Company’s 2000 multi-year gas settlement (ending December 2004), changes in accrued unbilled gas revenues are deferred. At March 31, 2004 and 2003, approximately $9 million and $6 million, respectively, of unbilled gas revenues remain unrecognized in results of operations. The Company cannot predict when unbilled gas revenues will be allowed to be recognized in results of operations.
In August 2001, the PSC approved certain rate plan changes. The changes allowed for certain commodity-related costs to be passed through to customers beginning September 2001. At the same time, a transmission revenue adjustment mechanism was implemented which reconciles actual and rate forecast transmission revenues for pass-back to or recovery from customers. The commodity adjustment clause and the transmission revenue adjustment mechanism continue to remain in effect under the Merger Rate Plan which became effective upon the closing of the merger on January 31, 2002.
The PSC approved a multi-year gas rate settlement agreement (amended through the Company’s merger rate plan and ending December 2004) in July 2000 that includes a provision for the continuation of a full gas cost collection mechanism, effective August 2000. This gas cost collection mechanism was originally reinstated in an interim agreement that became effective November 1999. Such gas cost collection mechanism continues under the Merger Rate Plan. The Company's gas cost collection mechanism provides for the collection or pass back of increases or decreases in purchased gas costs.
Federal and State Income Taxes: Regulated federal and state income taxes are recorded under the provisions of Financial Accounting Standards Board (FASB) SFAS No. 109 “Accounting for Income Taxes”. Tax returns for Holdings and its U.S. subsidiaries were filed within National Grid’s consolidated federal tax returns for the periods subsequent to the closing of the merger. Under the National Grid intercompany tax allocation agreement, Holdings and its subsidiaries are allocated a federal tax liability based on their separate company liabilities with adjustment for tax benefits associated with any National Grid holding company losses not attributable to acquisition indebtedness. Holdings and its New York State business subsidiaries will continue to file a combined New York State tax return. As directed by the PSC, the Company defers any amounts payable pursuant to the alternative minimum tax rules. Deferred investment tax credits are amortized over the useful life of the underlying property. Deferred investment tax credits related to the generation assets that were sold were taken into income in accordance with IRS rules.
Service Company Charges: National Grid USA Service Company, Inc., an affiliated service company operating pursuant to the provisions of Section 13 of the Public Utility Holding Company Act of 1935, has furnished services to the Company at the cost of such services since the merger with National Grid. These costs approximated $113 million, $62 million and $6 million for the years ended March 31, 2004 and 2003 and the 60 day period ended March 31, 2002, respectively.
Cash and Cash Equivalents: The Company considers all highly liquid investments, purchased with an original maturity of three months or less, to be cash and cash equivalents.
Restricted Cash: Restricted cash consists of margin accounts for hedging activity, health care claims deposits, New York State Department of Conservation securitization for certain site cleanup, and worker’s compensation premium deposit.
Derivatives: The Company accounts for derivative financial instruments under SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (FAS 133), and SFAS No. 149, “Amendment of SFAS No. 133 on Derivative Instruments and Hedging Activities,” as amended. Under the provisions of FAS 133, all derivatives except those qualifying for the normal purchase normal sale exception are recognized on the balance sheet at their fair value. Fair value is determined using current quoted market prices. If a contract is designated as a cash flow hedge, the change in its market value is generally deferred as a component of other comprehensive income until the transaction it is hedging is completed. Conversely, the change in the market value of a derivative not designated as a cash flow hedge is deferred as a regulatory asset or liability. A cash flow hedge is a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. To qualify as a cash flow hedge, the fair value changes in the derivative must be expected to offset 80% to 120% of the changes in fair value or cash flows of the hedged item.
The Company has received approval from the PSC to establish a regulatory asset or liability derivative instruments that did not qualify for hedge accounting and were the result of regulatory rulings.
Sale of Customer Receivables: The Company had established a single-purpose financing subsidiary, NM Receivables LLC (NMR), to purchase and resell a financial interest in a pool of the Company’s customer receivables. NMR was dissolved during fiscal 2004. See Note D. Commitments and Contingencies for a complete description of the operations of NMR and its dissolution during the current fiscal year. The Company adopted SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities - a replacement of SFAS No. 125” in 2001. The Company’s program for selling its accounts receivable meets the requirements outlined in SFAS No. 140 for recognition and accounting as a sale transaction.
Comprehensive Income (Loss): Comprehensive income (loss) is the change in the equity of a company, not including those changes that result from shareholder transactions. While the primary component of comprehensive income (loss) is reported net income or loss, the other components of comprehensive income (loss) relate to additional minimum pension liability recognition, deferred gains and losses associated with hedging activity, and unrealized gains and losses associated with certain investments held as available for sale. See Note C. Accumulated Other Comprehensive Income (Loss).
Additional minimum pension liability: Under current rate agreements with the PSC, the Company does not recognize its additional minimum pension liability (AML) for its qualified plan as a component of accumulated other comprehensive income but as a regulatory asset. The additional minimum pension liability for its non-qualified plan is recognized in accumulated other comprehensive income.
Disallowed Nuclear Investment Costs: In 2001, as part of the PSC order approving the sale of the Company’s nuclear assets, the Company wrote-off $123 million of its nuclear investment.
Power Purchase Agreements: The Company accounts for its power purchase agreements as executory contracts. The Company assesses several factors in determining how to account for its power purchase contracts. These factors include:
the term of the contract compared to the economic useful life of the facility generating the electricity;
the involvement, if any, that the Company has in operating the facility;
the amount of any fixed payments the Company must make, even if the facility does not generate electricity; and
the level of control the Company has over the amount of electricity generated by the facility, and who bears the risk in the event the facility is unable to generate.
New Accounting Standards:
In June 2001, the 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 (see Note O. Cost of Removal). The adoption of this statement did not have a material impact on the Company’s financial position, results of operations, or cash flows.
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 requires 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 has adopted FAS 132-R during the current fiscal year. 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 FASB Staff Position No. FAS 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 on the accompanying consolidated financial statements to conform to the fiscal 2004 presentation.
NOTE B - RATE AND REGULATORY ISSUES
The Company’s financial statements conform to GAAP, including the accounting principles for rate-regulated entities with respect to its regulated operations. Substantively, SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation” (FAS 71) permits a public utility, regulated on a cost-of-service basis, to defer certain costs, which would otherwise be charged to expense, when authorized to do so by the regulator. These deferred costs are known as regulatory assets, which in the case of the Company, are approximately $5.2 billion and $5.5 billion at March 31, 2004 and 2003, respectively. These regulatory assets are probable of recovery under the Company’s Merger Rate Plan and Gas Multi-Year Rate and Restructuring Agreement. The Company believes that the regulated cash flows to be derived from prices it will charge for electric service in the future, including the Competitive Transition Charges (CTCs), and assuming no unforeseen reduction in demand or bypass of the CTC or exit fees, will be sufficient to recover the Merger Rate Plan stranded regulatory assets over the planned amortization period with a return. Under the Merger Rate Plan, the Company’s remaining electric business (electricity transmission and distribution business) continues to be rate-regulated on a cost-of-service basis and, accordingly, the Company continues to apply FAS 71 to these businesses. Also, the Company’s Independent Power Producer (IPP) contracts, and the Purchase Power Agreements (PPAs) entered into in connection with the generation divestiture, continue to be the obligations of the regulated business.
In the event the Company determines, as a result of lower than expected revenues and/or higher than expected costs, that its net regulatory assets are not probable of recovery, it can no longer apply the principles of FAS 71 and would be required to record an after-tax, non-cash charge against income for any remaining unamortized regulatory assets and liabilities. If the Company could no longer apply FAS 71, the resulting charge would be material to the Company’s reported financial condition and results of operations.
Under the Merger Rate Plan, the Company is earning a return on most of its regulatory assets.
Stranded Costs: Under the Merger Rate Plan, a regulatory asset was established that included the costs of the Master Restructuring Agreement (MRA), the cost of any additional IPP contract buyouts and the deferred loss on the sale of the Company’s generation assets. The MRA represents the cost to terminate, restate or amend IPP contracts. The Company is also permitted to defer and amortize the cost of any additional IPP contract buyouts. Beginning January 31, 2002, the Merger Rate Plan stranded costs regulatory asset is being amortized unevenly over ten years with larger amounts being amortized in the latter years, consistent with projected recovery through rates.
Regulatory Tax Asset: The regulatory tax asset represents the expected future recovery from ratepayers of the tax consequences of temporary differences between the recorded book bases and the tax bases of assets and liabilities. This amount is primarily timing differences related to depreciation. These amounts are recovered and amortized as the related temporary differences reverse.
Deferred environmental restoration costs: This regulatory asset represents deferred costs associated with the Company’s share of the estimated costs to investigate and perform certain remediation activities at sites which it may be associated. The Company’s rate plans provided for specific rate allowances for these costs, with variances deferred for future recovery or pass-back to customers. The Company believes future costs, beyond the expiration of current rate plans, will continue to be recovered through rates.
Pension and post-retirement benefit plans: Excess costs of the Company’s pension and post-retirement benefits plans over amounts received in rates are deferred to a regulatory asset to be recovered in a future period.
Additional minimum pension liability: The offset to any additional minimum pension liability associated with the Company’s qualified pension plan is applied to this regulatory asset on a pre-tax basis instead of after-tax to other comprehensive income as determined by regulatory rulings.
Loss on Reacquired Debt: The loss on reacquired debt regulatory asset represents the costs to redeem certain long-term debt securities, which were retired prior to maturity. These amounts are amortized as interest expense ratably over the lives of the related issues in accordance with PSC directives.
Other: Included in the other regulatory asset is the accumulation of numerous miscellaneous regulatory deferrals, income earned on gas rate sharing mechanisms, the incentive earned on the sale of the fossil and hydro generation assets and certain New York Independent System Operator (NYISO) costs that were deferred for future recovery.
See Notes H, D, and L for a discussion of regulatory asset accounts "Pensions and postretirement benefits", “Deferred environmental restoration costs", and "Swap contracts regulatory asset", respectively.
NOTE C - ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Taxes on other comprehensive income for the following periods were (in thousands of $’s):
NOTE D - COMMITMENTS AND CONTINGENCIES
Commodity Reconciliations: As part of the Company's ongoing reconciliation of commodity costs and revenues, the Company has identified several adjustments and included them in filings with the PSC. Specifically, the Company has requested recovery of $36 million of commodity costs associated with the under-reconciliation of New York Power Authority (NYPA) hydropower revenues in its commodity adjustment clause, and is proposing to refund $24 million associated with other revenues that were not included in the commodity adjustment reconciliation. This filing is pending before the PSC, and the Company cannot predict the outcome of this filing.
Long-Term Contracts for the Purchase of Electric Power: The Company has several types of long-term contracts for the purchase of electric power. The Company’s commitments under these long-term contracts, as of March 31, 2004 are summarized in the table below. The Company did not enter into any new agreements in fiscal 2004 or 2003. For a detailed discussion of the financial swap agreements that the Company has entered into to hedge the costs of purchased electricity (which are not included in the table below), see Note L. Derivatives and Hedging Activities.
In addition to the contractual commitments described above, the Company entered into a four-year contract, which expired in June 2003, that gave it the option to buy additional power at market prices from the Huntley coal-fired generation plant. If the Company needs any additional energy to meet its load it can purchase the electricity from other IPPs, other utilities, other energy merchants or through the NYISO at market prices.
Gas Supply, Storage and Pipeline Commitments: In connection with its regulated gas business, the Company has long-term commitments with a variety of suppliers and pipelines to purchase gas commodity, provide gas storage capability and transport gas commodity on interstate gas pipelines.
The table below sets forth the Company’s estimated commitments at March 31, 2004, for the next five years, and thereafter.
With respect to firm gas supply commitments, the amounts are based upon volumes specified in the contracts giving consideration for the minimum take provisions. Commodity prices are based on New York Mercantile Exchange quotes and reservation charges, when applicable. Storage and pipeline capacity commitments’ amounts are based upon volumes specified in the contracts, and represent demand charges priced at current filed tariffs. At March 31, 2004, the Company’s firm gas supply commitments have varying expiration dates, the latest of which is October 2006. The gas storage and transportation commitments have varying expiration dates with the latest being October 2012.
Environmental Contingencies: The public utility industry typically utilizes and/or generates in its operations a broad range of hazardous and potentially hazardous wastes and by-products. The Company believes it is handling identified wastes and by-products in a manner consistent with federal, state, and local requirements and has implemented an environmental audit program to identify any potential areas of concern and aid in compliance with such requirements. The Company is also currently conducting a program to investigate and remediate, as necessary, to meet current environmental standards, certain properties associated with former gas manufacturing and other properties which the Company has learned may be contaminated with industrial waste, as well as investigating identified industrial waste sites as to which it may be determined that the Company has contributed. The Company has also been advised that various federal, state, or local agencies believe certain properties require investigation.
The Company is currently aware of 103 sites with which it may be associated, including 56 which are Company-owned. With respect to non-owned sites, the Company may be required to contribute some proportionate share of remedial costs. Although one party can, as a matter of law, be held liable for all of the remedial costs at a site, regardless of fault, in practice, costs are usually allocated among Potentially Responsible Parties (PRP). The Company has denied any responsibility at certain of these PRP sites and is contesting liability accordingly. At non-owned manufactured gas plant sites, the Company may bear full or partial responsibility for remedial costs.
Investigations at each of the Company-owned sites are designed to: (1) determine if environmental contamination problems exist; (2) if necessary, determine the appropriate remedial actions; and (3) where appropriate, identify other parties who should bear some or all of the cost of remediation. Legal action against such other parties will be initiated where appropriate. As site investigations are completed, the Company expects to determine site-specific remedial actions and to estimate the attendant costs for restoration. However, since investigations and regulatory reviews are ongoing for most sites, the estimated cost of remedial action is subject to change.
The Company determines site liabilities through feasibility studies or engineering estimates, the Company’s estimated share of a PRP allocation, or, where no better estimate is available, the low end of a range of possible outcomes is used. Estimates of the cost of remediation and post-remedial monitoring are based upon a variety of factors, including identified or potential contaminants, location, size and use of the site, proximity to sensitive resources, status of regulatory investigation, and knowledge of activities at similarly situated sites. Actual expenditures are dependent upon the total cost of investigation and remediation and the ultimate determination of the Company’s share of responsibility for such costs, as well as the financial viability of other identified responsible parties since clean-up obligations are joint and several. It is more difficult to estimate the costs to remediate certain non-owned sites, because they have not undergone site investigations.
As a consequence of site characterizations and assessments completed to date and negotiations with other PRPs or with the appropriate environmental regulatory agency, the Company has accrued a liability in the amounts of $309 million and $301 million which is reflected in the Company’s Consolidated Balance Sheets at March 31, 2004 and 2003, respectively. The potential high end of the range is presently estimated at approximately $532 million. The reserve has been increased by $8 million since March 31, 2003 primarily due to the accrual of an additional $26 million associated with its Harbor Point site and other accruals, offset by anticipated site related expenditures. The Company had previously filed an Article 78 petition to contest the New York Department of Environmental Conservation’s more costly remediation plan of the site. During fiscal 2004, the petition was denied by the court and the additional estimated costs to remediate Harbor Point were accrued. This additional accrual has been offset by reductions in expected values on sites resulting from regular spending as well as a decrease of $13 million as the expected value on the Company’s Hudson (Water Street) site was adjusted to reflect costs as based on an actual bid, including long-term monitoring.
The Merger Rate Plan provides for the continued application of deferral accounting for variations in spending from amounts provided in rates. The Company has recorded a regulatory asset representing the investigation, remediation, and monitoring obligations to be recovered from ratepayers. As a result, the Company does not believe that site investigation and remediation costs will have a material adverse effect on its results of operations, financial condition or cash flows.
Nuclear Contingencies: As of March 31, 2004 and 2003, the Company has a liability of $143 million and $142 million, respectively, in other non-current liabilities for the disposal of nuclear fuel irradiated prior to 1983. In January 1983, the Nuclear Waste Policy Act of 1982 (the Nuclear Waste Act) established a cost of $.001 per KWh of net generation for current disposal of nuclear fuel and provides for a determination of the Company’s liability to the U.S. Department of Energy (DOE) for the disposal of nuclear fuel irradiated prior to 1983. The Nuclear Waste Act also provides three payment options for liquidating such liability and the Company has elected to delay payment, with interest, until the year in which Constellation, who purchased the Company’s nuclear assets, initially plans to ship irradiated fuel to an approved DOE disposal facility. Progress in developing the DOE facility has been slow and it is anticipated that the DOE facility will not be ready to accept deliveries until at least 2010.
Legal Matters:
Alliance for Municipal Power v. New York State Public Service Commission: On February 17, 2003, the Alliance for Municipal Power (AMP) filed with the New York State Supreme Court (Albany County) a petition for review of decisions by the PSC that maintain the PSC’s established policy of using average distribution rates when calculating the exit fees that may be charged to municipalities that seek to leave the company’s system and establish their own municipal light departments. Changes in the methodology for the calculation of the exit fee are not likely to have a material effect on the Company’s financial position or results of operations. However, AMP’s petition for review also challenges the lawfulness of the Company’s collection of exit fees from departing municipalities, regardless of the methodology used to calculate those fees. On October 27, 2003, the court dismissed AMP’s petition. AMP made a timely filing to appeal the court’s decision but has not perfected its appeal.
Niagara Mohawk Power Corp. v. Huntley Power L.L.C., Dunkirk Power L.L.C. and Oswego Harbor, L.L.C. The Company previously owned three power plants (the Plants), which it sold to three affiliates of NRG Energy, Inc. in 1999: Huntley Power L.L.C., Dunkirk Power L.L.C. and Oswego Harbor, L.L.C. (collectively, the NRG Affiliates). The Company is in involved in three proceedings with the NRG affiliates to recover bills for station service rendered to the Plants; a collections action filed by the Company against the NRG affiliates in New York State Supreme Court in October 2000; a petition filed by the Company at the FERC in November 2002, and an Article 78 Petition filed by the NRG Affiliates in New York Supreme Court in March 2004, challenging the state retail standby distribution tariff . The main issue in all three proceedings is whether the NRG Affiliates will be permitted to bypass the Company’s state-jurisdictional retail charges for station service. The State Supreme Court lawsuit filed by the Company has been stayed by agreement, the parties are awaiting a decision from FERC on the Company’s petition, and the parties have agreed to stay the NRG Affiliates’ Article 78 petition pending appeal of a FERC decision on May 10, 2004 in another proceeding. The May 10, 2004 Order denied rehearing of objections to FERC’s approval of the NYISO wholesale station service tariff, on which the NRG Affiliates are relying in part to avoid payment of the state retail distribution tariff for station service. FERC’s May 10, 2004 Order is discussed below under Retail Bypass. As of March 31, 2004, the NRG Affiliates owed the Company approximately $39 million for station service. In the event it is determined that the Company may not bill the NRG Affiliates for station service under its state tariff, the Company would seek recovery under its rate plans.
New York State v. Niagara Mohawk Power Corp. et al.: On January 10, 2002, the New York State Attorney General filed a civil action against the Company, NRG Energy, Inc. and certain of its affiliates in U.S. District Court for the Western District of New York for alleged violations of the federal Clean Air Act, related state environmental statutes, and the common law, at the Huntley and Dunkirk power plants. The State alleged that between 1982 and 1999, the Company modified the two plants 55 times without obtaining proper preconstruction permits and implementing proper pollution equipment controls.
On March 27, 2003, the court issued an order granting in part the Company’s motion to dismiss, which had been filed in 2002. Based on applicable statutes of limitations, the court reduced the number of projects allegedly requiring preconstruction permits under the Clean Air Act from 55 to nine.
On December 31, 2003, the court granted the State’s motion to amend the complaint, allowing it to assert operating permit violations against the Company and NRG. In so ruling, the court stated that monetary penalties for actions outside the statute of limitations period would still be barred. the Company answered the amended complaint on March 2, 2004, and filed a counterclaim against the State of New York in response to its common law public nuisance claim, seeking contribution for the Company’s portion of any alleged harm caused by emissions from facilities that the State owns or to which it has given permits. The State has moved to dismiss the counterclaim. Trial is scheduled for March 2006.
Niagara Mohawk Power Corporation v. NRG Energy, Inc., Huntley Power L.L.C. and Dunkirk Power L.L.C. With respect to the claims asserted in the Clean Air Act lawsuit discussed above, NRG and its Affiliates have taken the position that the Company is responsible at least in part for the costs of pollution control equipment and related fines and penalties, notwithstanding contrary language in the agreement governing the sale of the Plants to the NRG Affiliates. As a result, on July 13, 2001, the Company sued NRG and the NRG Affiliates in New York State Supreme Court (Onondaga County), seeking a declaratory ruling that under the agreement, NRG is responsible for the costs of any pollution control upgrades and mitigation, as well as post-sale fines and penalties, that may result from the Clean Air Act suit. In response, NRG filed a counterclaim and filed a motion for partial summary on its counterclaim. Hearing on NRG’s motion is scheduled for July 28, 2004.
Retail Bypass: In approving Power Choice, the rate plan in effect prior to the Merger Rate Plan, the PSC authorized changes to the Company’s retail tariff providing for the recovery of an exit fee for customers that leave the Company’s system. The retail tariff governs the application and calculation of the exit fee. The exit fee also applies to municipalities seeking to serve customers in the Company’s service area.
On September 22, 2002, a different type of retail bypass issue was presented in a filing with FERC by the NYISO seeking to implement a new station service rate which also provided that generators could net their station service electricity over a 30-day period. On November 22, 2002, FERC issued an order accepting the NYISO’s new rate, over the Company’s protest (the FERC NYISO Order). The FERC NYISO Order has allowed generators to argue that they should be able to avoid paying state-approved charges for retail deliveries when they take service under the NYISO tariff. On July 10, 2003, the Company filed modifications to its standby service rates with the PSC, which the PSC approved on November 25, 2003. The tariff modifications unbundle the transmission service component provided under the NYISO’s new rate but continue the Company’s own retail distribution charges to these customers.
A number of generators have complained or withheld payments associated with the Company’s delivery of station service to their generation facilities, including NRG Energy, Inc. On December 23, 2003, FERC issued two orders on complaints filed by AES Somerset, L.L.C. (AES) and Nine Mile Point Nuclear Station, L.L.C. (Nine Mile) (together, the AES and Nine Mile FERC Orders), both of which are station service customers of the Company. The two orders allow these generators to net their station service electricity over a 30-day period and to avoid state-authorized charges for deliveries made over distribution facilities. While it is not entirely clear from reading the AES and Nine Mile FERC Orders, it is possible to construe them to have retroactive effect back to the date the plant was sold to AES by a third party. The net effect of these FERC decisions is that the two generators will no longer have to pay the Company for station service charges for electricity. The AES and Nine Mile FERC Orders are in direct conflict with the state-approved tariffs and the orders of the PSC on station service rates. The FERC orders, if upheld, will permit these generators to completely bypass the Company’s state-jurisdictional retail charges, including those set forth in the filing that was approved by the PSC on November 25, 2003. On February 23, 2004, the Company received orders granting rehearing for further consideration from the FERC in both the AES and Nine Mile Point proceedings. No further action on the rehearing requests has occurred to date.
On May 10, 2004, FERC issued an order denying motions for clarification filed by the Company and other parties with respect to the FERC NYISO Order, and reaffirmed its reasoning of the AES and Nine Mile FERC Orders. In so ruling, FERC indicated that the NYISO station service would be limited to merchant generators self-supplying their own power, and should not be interpreted to apply to self-supplying retail industrial and commercial customers. The Company intends to appeal.
The AES and Nine Mile FERC Orders and FERC NYISO Orders have increased the risk that generators will be able to bypass local distribution company charges (including stranded cost recovery charges) when receiving service through the NYISO. To the extent that the Company experiences any lost revenue attributable to retail bypass, it is permitted to recover these lost revenues under its rate plans.
NOTE E - LONG-TERM DEBT
Long-term debt consisted of the following:
(1) Refinanced to auction rate mode on December 11, 2003. Effective interest rate at March 31, 2004 was 1.18 percent.
(2) Refinanced to auction rate mode on May 27, 2004.
(3) Refinanced to auction rate mode on May 1, 2003. Effective interest rate at March 31, 2004 was 1.19 percent
*Tax-exempt pollution control related issues
Several series of First Mortgage Bonds and Promissory Notes were issued to secure a like amount of tax-exempt revenue bonds issued by the New York State Energy Research and Development Authority (NYSERDA). Approximately $414 million of such securities bear interest at short-term adjustable interest rates (with an option to convert to other rates, including a fixed interest rate which would require the Company to issue First Mortgage Bonds to secure the debt) which averaged 1.24 percent for the year ended March 31, 2004, 1.36 percent for the year ended March 31, 2003, 1.12 percent for the three months ended March 31, 2002, and 2.50 percent for 2001 and are supported by bank direct pay letters of credit. Pursuant to agreements between NYSERDA and the Company, proceeds from such issues were used for the purpose of financing the construction of certain pollution control facilities at the Company’s generation facilities (which the company subsequently sold) or to refund outstanding tax-exempt bonds and notes (see Note F).
On May 1, 2003, the Company completed the restructuring of $414 million of variable rate tax exempt bonds. The bonds are currently in the auction rate mode, which allowed the Company to terminate $424 million of letter of credit facilities that were in place to provide liquidity support for principal and interest while the bonds were in a variable rate mode.
The restructuring of the $414 million of tax exempt bonds and the exchange of the $500 million note payable to National Grid USA for a $500 million note payable to Holdings were accomplished through noncash transactions.
The aggregate maturities of long-term debt for the five years subsequent to March 31, 2004, excluding capital leases are approximately:
The current portion of capital lease obligations is reflected in the other current liabilities line item on the Consolidated Balance Sheet and was approximately $1.0 million at March 31, 2004 and 2003. The non-current portion of capital lease obligations is reflected in the “Other” line item on the Consolidated Balance Sheet and was approximately $5 million and $6 million at March 31, 2004 and 2003, respectively.
At March 31, 2004, the Company's long-term debt had a fair value of approximately $3.1 billion. The fair market value of the Company’s long-term debt was estimated based on the debts’ coupons and remaining lives along with the current interest rate conditions.
Early Extinguishment of Debt
During the years ended March 31, 2004 and 2003 and the three months ended March 31, 2002, the Company defeased or redeemed approximately $658 million, $122 million, and $119 million, respectively, in long-term debt prior to its scheduled maturity.
Losses resulting from the early redemption of debt are deferred and amortized as interest expense ratably over the lives of the related issues in accordance with PSC directives (see Note B).
NOTE F - SHORT-TERM DEBT
The Company had short-term debt outstanding of $464 million and $198 million at March 31, 2004 and 2003, respectively, from the inter-company money pool. The Company has regulatory approval from the Securities and Exchange Commission (SEC), under the Public Utility Holding Company Act of 1935, to issue up to $1 billion of short-term debt. National Grid and certain subsidiaries, including the Company, 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. The average interest rate for the money pool was 1.11% and 1.62% for fiscal 2004 and 2003, respectively.
The Company had no short-term debt outstanding to third-parties at March 31, 2004 or 2003.
NOTE G - FEDERAL AND STATE INCOME TAXES
Following is a summary of the components of federal and state income tax and a reconciliation between the amount of federal income tax expense reported in the Consolidated Statements of Operations and the computed amount at the statutory tax rate:
Reconciliation between federal income taxes and the tax computed at prevailing U.S. statutory rate on income before income taxes:
(a) Includes Carrying Charges (Interest Expense) imposed by the PSC.
(b) Deferred investment tax credits of $79.7 million related to the generation assets that have been sold have been taken into income in 2001 in accordance with IRS rules.
The deferred tax liabilities (assets) were comprised of the following:
The Company has been audited and reported on by the Internal Revenue Service (IRS) through December 31, 1998.
In December 1998, the Company received a ruling from the IRS which provided that the amount of cash and the value of common stock that was paid by the Company to the subject terminated IPP Parties was deductible in 1998 which resulted in the Company not paying any regular federal income taxes for 1998, and further generated a substantial net operating loss for federal income tax purposes. The Company carried back a portion of the unused net operating loss (NOL) to the years 1996 and 1997, and also for the years 1988 through 1990, which resulted in federal income tax refunds of $135 million that were received in January 1999. As a result of the merger with National Grid, the Company is now part of the consolidated tax return filing group of National Grid General Partnership (the parent company, through an intermediary entity, of National Grid). The Company anticipates that the consolidated tax filing group will be able to utilize the remaining NOL carryforward prior to its expiration in 2019. The amount of the NOL carryforward as of March 31, 2004 and 2003 was $909 million and $1.6 billion, respectively. National Grid’s ability to utilize the NOL carryforward generated as a result of the MRA and the utilization of alternative minimum tax credits is affected by the rules of Section 382 of the Internal Revenue Code.
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 covering substantially all employees. The pension plan is a cash balance pension plan design and under that design, pay-based credits are applied based on service time, and interest credits are applied based on an average annual 30-year Treasury bond yield. In addition, a large number of employees hired by the Company prior to July 1998 are cash balance design participants who receive a larger benefit if so yielded under pre-cash balance conversion final average pay formula provisions. Employees hired by the Company following the August 1998 cash balance design conversion participate under cash balance design provisions only.
Supplemental nonqualified, non-contributory executive retirement programs provide additional defined pension benefits for certain executives.
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.
Funding Policy
Funding policy is determined largely by the Company’s settlement agreements with the PSC and what is recovered in rates. 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 its pension 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 plan liabilities and plan 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. Investment risk and return is reviewed by the investment committee on a quarterly basis.
The target asset allocation for the benefit plans are:
The target asset allocation for the other post-retirement benefits plan is:
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 benefit plans’ costs used the following assumptions:
The benefit plans’ included the following components of expense:
The following table provides a reconciliation of the changes in the plans’ fair value of assets for the fiscal years 2004 and 2003, the expected contributions to the trust in the 2005 fiscal year, and the % distribution of the fair market value of the types of assets held in the benefit plans’ trusts.
* Not required for disclosure for the year ended March 31, 2003.
The following table provides a reconciliation of the changes in the plans’ fair value benefit obligation for the fiscal years 2004 and 2003, accumulated benefit obligation for the pension plans at March 31, and the assumption used in developing that obligation.
* Not required for disclosure.
** The dispositions noted in the tables above related to the spin-off of the assets and liabilities in conjunction with the sale of NM Energy.
A one-percentage point change in assumed health care cost trend rates would have the following effects:
PSC Audit
In August 2003, the New York State PSC approved a settlement with the Company following an audit that identified reconciliation issues between the rate allowance and actual costs of the Company’s pension and other post-retirement benefits. The settlement resolved all issues associated with those obligations for the period prior to its acquisition by National Grid and, among other things, covered the funding of the Company’s pension and post-retirement benefit plans. As part of the settlement, the Company provided $100 million of tax-deductible funding during fiscal 2003 and an additional $209 million of tax-deductible funding by the end of fiscal 2004. Under the settlement, the Group will earn a rate of return of at least 6.60 percent (nominal) on the $209 million of funding through December 31, 2011 and is eligible to earn 80 percent of the amount by which the rate of return on the pension and post-retirement benefit funds exceeds 5.34 per cent (nominal) measured as of that date.
Asset Revaluation
At the time of the merger with National Grid, the Company revalued its assets and liabilities to their fair value in accordance with purchase accounting. This revaluation resulted in an increase to the Company’s pension and postretirement benefit plan liabilities in the amount of approximately $440 million, with a corresponding offset to a regulatory asset account, which is being amortized ratably over the ten year period beginning January 31, 2002. The costs of the change-of-control payment under the non-qualified plan were charged to expense. The following table sets forth the components and disposition of payments made during the 60 day period ended March 31, 2002 and the 30 day period ended January 30, 2002 (combined):
Additional Minimum Pension Liability
The Company has recorded an additional minimum pension liability of approximately $168 million and $269 million at March 31, 2004 and 2003, respectively, for its qualified pension plans because the pension plans’ accumulated benefit obligation was in excess of the prepaid pension asset and accrued pension liability on the balance sheet. While the offset to this entry would normally be a charge after-tax to other comprehensive income, due to the nature of its rate plan the Company has instead recorded a pre-tax regulatory asset.
The Company has also recorded an additional minimum pension liability of approximately $1.5 million at March 31, 2004 for its nonqualified executive pension plan. The non-qualified executive pension plan has no plan assets due to the nature of the plan. The offset to this liability was recorded as a charge to other comprehensive income.
Voluntary Early Retirement Offer
In fiscal 2004, National Grid made a voluntary early retirement offer (VERO) to eligible non-union employees in areas including transmission and corporate administrative functions such as finance, human resources, legal and information technology. A total of 53 employees of the Company accepted the VERO. The majority of them will retire by November 1, 2004, with the remainder retiring by November 1, 2007. The Company expensed approximately $19 million of VERO costs in the fiscal 2004. This amount included approximately $9 million allocated to the Company from National Grid USA Service Company, an affiliate.
Voluntary Early Retirement Program
As part of the acquisition by National Grid, the Company made certain change-of-control payments under the supplemental non-qualified executive retirement program and offered a voluntary early retirement program (VERP) to selected employees in areas targeted for staffing reductions. These items appear in the pension net periodic benefit cost tables as Special Termination Benefits at the time of the merger.
Settlement Losses
As the result of the decline in the stock market since the close of the merger with Niagara Mohawk and a reduction in the discount rate applied to pension obligations, the Company has an unrecognized loss in its pension plans. Under SFAS No. 88 “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” (FAS 88), the Company must recognize a portion of this loss immediately when payouts from the plans exceed a certain amount. The Company recognized approximately $22 million in fiscal 2004 relating to the remeasurement of the benefit plans from VERO. The Company had a net settlement loss of approximately $30 million in fiscal 2003 relating to normal lump-sum distributions and the spin-off of the assets and liabilities related to the sale of NM Energy. For the 60 Day Period ended March 31, 2002, the Company had a net settlement gain of approximately $17 million related to the sale of its nuclear assets. In 2001, the Company experienced a net curtailment/settlement loss of $32 million due to the employee transfers associated with the sale of the nuclear assets and change of control payments under the supplemental executive retirement plan. Of the 2001 loss, approximately $11 million is recorded in the deferred loss on the sale of assets, approximately $6 million was due from co-tenants for their allocation of the plant ownership and approximately $15 million was charged to expense.
In February 2004, the Company reached an agreement with PSC Staff that would provide rate recovery for approximately $15 million of the $30 million pension settlement loss incurred in fiscal 2003. This agreement is subject to approval by the full New York State Public Service Commission. In addition, the agreement covers the funding of the entire settlement loss to benefit plan trust funds. Under the agreement, the Company will fund the non-recoverable portion of this loss within 30 days of approval of the agreement. The Company plans to file a petition with the PSC seeking recovery of its fiscal year 2004 settlement losses as well.
Regulatory treatment of pensions and postretirement benefit plans
In addition to the regulatory assets established in connection with purchase accounting and the additional minimum pension liability discussed above, the regulatory asset account “Pension and postretirement benefit plans” includes certain other components. First, the Company is required under the Merger Rate Plan to defer the difference between pension and postretirement benefit expense and the allowance in rates for these costs. Also, the regulatory asset account includes the $52 million cost of the VERP discussed above, a postretirement benefit phase-in deferral established in the mid-1990’s, and the offset to the additional minimum pension liability discussed above. The VERP is being amortized unevenly over the 10 years of the Merger Rate Plan with larger amounts being amortized in the earlier years. VERP amortization in fiscal 2004 and 2003 was approximately $8 million and $17 million, respectively. The phase-in deferral is being amortized at a rate of approximately $3 million per year.
Post-employment benefits
The Company recognizes as an expense the obligation to provide post-employment benefits if the obligation is attributable to employees’ past services, rights to those benefits are vested, payment is probable and the amount of the benefits can be reasonably estimated. At March 31, 2004 and 2003, the Company’s post-employment benefit obligation is approximately $36 million and $34 million, respectively.
Defined contribution plan
The Company also has a defined contribution pension plan (employee savings fund plan) that covers substantially all employees. Employer matching contributions of approximately $7 million, $8 million, $2 million and $10 million were expensed for the twelve months ended March 31, 2004 and 2003, the three months ended March 31, 2002, and the year ended December 31, 2001, respectively.
NOTE I - PREFERRED STOCK
The Company has certain issues of non-participating preferred stock, which provide for redemption at the option of the Company, as shown in the table below. From time to time the Company repurchases shares of its preferred stock when it is approached on behalf of its shareholders.
During fiscal 2004, 624,533 preferred stock shares were redeemed at a cumulative loss of $939,000 which was charged to additional paid-in capital.
NOTE J - SEGMENTS
The Company’s reportable segments for the years ended March 31, 2004 and 2003 are electricity-transmission, electricity-distribution, and gas. The Company is engaged principally in the business of purchase, transmission, and distribution of electricity and the purchase, distribution, sale, and transportation of natural gas in New York State. Certain information regarding the Company’s segments is set forth in the following table. General corporate expenses, property common to the various segments, and depreciation of such common property have been allocated to the segments based on labor or plant, using a percentage derived from total labor or plant amounts charged directly to certain operating expense accounts or certain plant accounts. Corporate assets consist primarily of other property and investments, cash, restricted cash, current deferred income taxes, and unamortized debt expense.
For periods prior to the year ended March 31, 2003, the segment data presented is limited to electricity (in total) and gas. Prior to the Company’s merger with National Grid, the electricity segment was managed as a single operating unit, with a single bundled rate structure. Beginning in fiscal 2003, new mechanisms were put in place to capture the separate financial information, including revenue, for electricity-transmission and electricity-distribution in the Company’s detailed accounting records to facilitate the new management approach. These mechanisms were not in place in prior periods. Additionally, prior to fiscal 2003 the Company was also engaged in the operation of electricity generation, further complicating the development of comparable segment information for the prior periods. As a result, presentation of pre-fiscal 2003 information on a basis fully comparable to the fiscal 2003 reportable segments is not possible, and any attempt to develop additional segment data would require undue time and effort in recalculating comparative amounts.
NOTE K - STOCK BASED COMPENSATION
Under Holdings’ stock compensation plans prior to the merger, stock units and stock appreciation rights (SARs) were granted to officers, key employees and directors. In addition, Holdings’ plans previously allowed for the grant of stock options to officers. The table below sets forth the activity under Holdings’ stock compensation plans for the periods January 1, 2000 through March 31, 2004. On January 31, 2002, the acquisition of Holdings by National Grid was completed.
The Company's SARs and stock units provided for the acceleration of vesting upon the occurrence of certain events relating to a change in control, merger, sale of assets or liquidation of the Company. On January 31, 2002 outstanding Holdings SARs were converted to National Grid Transco plc (NGT) American Depositary Share (ADS) SARs. The SARs are payable in cash based on the increase in the ADS price from a specified level. As such, for these awards, compensation expense is recognized based on the value of Holdings’ stock price or NGT’s ADS price over the vesting period of the award. Upon the closing of the merger, the units were paid, and each stock option outstanding was cancelled and entitled the holder to receive an amount in cash.
Included in the Company’s results of operations for years ended March 31, 2004 and 2003, the three months ended March 31, 2002, and the year ended December 31, 2001, is approximately $5 million, $3 million, $21 million, and $12 million, respectively, related to these plans.
Since stock units and SARs are payable in cash, the accounting under APB No. 25 and SFAS No. 123 is the same. Therefore, the pro forma disclosure of information regarding net income, as required by SFAS No. 123, related only to Holdings’ outstanding stock options. There were no outstanding stock options subsequent to the closing of the merger.
NOTE L - DERIVATIVES AND HEDGING ACTIVITIES
In the normal course of business, the Company is party to derivative financial instruments (derivatives) that are principally used to manage commodity prices associated with its natural gas and electric operations. These financial exposures are monitored and managed as an integral part of the Company’s overall financial risk-management policy. At the core of the policy is a condition that the Company will engage in activities at risk only to the extent that those activities fall within commodities and financial markets to which it has a physical market exposure in terms and volumes consistent with its core business. The Company does not issue or intend to hold derivative instruments for speculative trading purposes. Derivatives are accounted for in accordance with SFAS 133, which requires derivatives to be reported at fair value as assets or liabilities on the balance sheet. The change in fair value of instruments that qualify for hedge accounting are deferred in Accumulated Other Comprehensive Income and will be reclassified through purchased power or purchased gas expense within the next twelve months. Other instruments are deferred in regulatory assets or liabilities according to current rate agreements and are reclassified through purchased power or gas in the hedge months. The Company’s rate agreements allow for the pass-through of the commodity costs of electricity and natural gas, including the costs of the hedging programs.
The Company has eight indexed swap contracts, expiring in June 2008 that resulted from the master restructuring agreement. There were also three swap contracts from the sale of the Company’s Huntley, Dunkirk, and Albany electric generating stations. The Huntley and Dunkirk contracts expired in June 2003; the Albany contract expired in September 2003. These derivatives are not designated as hedging instruments and are covered by regulatory rulings that allow the gains and losses to be recorded as regulatory assets or regulatory liabilities. As of March 31, 2004 and 2003, the Company had recorded liabilities at net present value of $715.4 million and $793.0 million, respectively, for these swap contracts and had recorded a corresponding swap contracts regulatory asset. The asset and liability are amortized over the remaining term of the swaps as nominal energy quantities are settled and are adjusted as periodic reassessments are made of energy price forecasts.
At March 31, 2004, the Company projects that it will make the following payments in connection with its swap contracts for the fiscal years 2005 through 2008, subject to changes in market prices and indexing provisions:
The Company uses New York Mercantile Exchange (NYMEX) gas futures to hedge the gas commodity component of its indexed swap contracts. These instruments, as used, do not qualify for hedge accounting status under SFAS 133. Cash flow hedges that qualify under SFAS 133 are as follows: NYMEX gas futures and combination call/put options hedging the purchases of natural gas, NYMEX electric swap contracts hedging the purchases of electricity.
The following table represents the open positions at March 31, 2004 and the results on operations of these instruments for the year ended March 31, 2004.
At March 31, 2003, the Company recorded a deferred gain on the futures contracts hedging the IPP swaps and non-MRA IPP of $17.3 million, offset by the consolidated balance sheet item “Derivative Instruments” for $14.2 million, with the resulting $3.1 having settled through cash for the hedge month of April 2003. For the twelve months ended March 31, 2003, settlement of NYMEX futures contracts resulted in a decrease to purchased power expense of $29.3 million.
The gains and losses on the derivatives that are deferred and reported in accumulated other comprehensive income will be reclassified as purchased energy expense in the periods in which expense is impacted by the variability of the cash flows of the hedged item. For the twelve months ended March 31, 2004, the net increase of $4.2 million, shown in the table above, was recorded to gas purchases offset by a corresponding decrease in the cost of a comparable amount of gas. For the twelve months ended March 31, 2004, the realized net loss of $4.2 million from hedging instruments, as shown in the table above, was recorded to gas purchases offset by a corresponding decrease in the cost of a comparable amount of gas. For the twelve months ended March 31, 2003, a net gain of $10.0 million was recorded to gas purchases offset by a corresponding increase in the cost of a comparable amount of gas.
The actual amounts to be recorded in purchased energy expense are dependent on future changes in the contract values, the majority of these deferred amounts will be reclassified to expense within the next twelve months. A nominal amount of the hedging instruments extend into April 2005. There were no gains or losses recorded during the year from the discontinuance of gas futures or electric swap cash flow hedges.
There were no open electric swaps at March 31, 2004 or 2003. In April 2003, the Company used NYMEX electric swap contracts to hedge electricity purchases for the summer 2003. The Company continues to evaluate the use of hedging instruments to manage the cost of electricity purchased.
During fiscal 2004, the company allowed all of it gas collars (combination call and put options) to expire. These contracts were hedges of gas supply price risk.
NOTE M - RESTRICTION ON COMMON DIVIDENDS
The indenture securing the Company’s mortgage debt provides that retained earnings shall be reserved and held unavailable for the payment of dividends on common stock to the extent that expenditures for maintenance and repairs plus provisions for depreciation do not exceed 2.25 percent of depreciable property as defined therein. These provisions have never resulted in a restriction of the Company’s retained earnings.
The Company is limited by the Merger Rate Plan and under FERC and SEC orders with respect to the amount of dividends it can make to Holdings. The Company is allowed to make dividends in an amount up to the pre-merger retained earnings balance plus any earnings subsequent to the merger, together with other adjustments that are authorized under the Merger Rate Plan and other regulatory orders.
NOTE N - ADDITIONAL PAID-IN CAPITAL
The following table details the changes in the equity account, “Additional paid-in capital”
The contribution from Holding in fiscal 2004 was for the funding of the pension and post-retirement benefit trusts associated with a PSC settlement (See Note H).
NOTE O - COST OF REMOVAL
In 2001, FASB issued FAS 143. FAS 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets. The Company was required to adopt FAS 143 as of April 1, 2003. Retirement obligations associated with long-lived assets included within the scope of FAS 143 are those for which there is a legal obligation under existing or enacted law, statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel.
The Company does not have any material asset retirement obligations arising from legal obligations as defined under FAS 143. However, under the 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. For a vast majority of its electric and gas transmission and distribution assets the Company would use these funds to remove the asset so a new one could be installed in its place.
The cost of removal collections 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 these 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 $314 million and $307 million for cost of removal through March 31, 2004 and March 31, 2003, respectively.
NOTE P - QUARTERLY FINANCIAL DATA (UNAUDITED)
Operating revenues, operating income, and net income (loss) by quarter from April 1, 2002 through March 31, 2004 are shown in the following table. The Company believes it has included all adjustments necessary for a fair presentation of the results of operations for the quarters. Due to the seasonal nature of the regulated utility business, the annual amounts are not generated evenly by quarter during the year. The Company’s quarterly results of operations reflect the seasonal nature of its business, with peak electric loads in summer and winter periods. Gas sales peak in the winter.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
The Company has nothing to report for this item.
ITEM 9A.
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 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.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The following table lists the Company’s executive officers and directors:
Name
Age
Position
William F. Edwards
President and Director
John G. Cochrane
Chief Financial Officer
Joseph T. Ash, Jr.
Vice President, Energy Supply, Pricing and Regulatory Proceedings
Edward A. Capomacchio
Controller
Michael E. Jesanis
President and Chief Operating Officer of National Grid USA and Director
Michael J. Kelleher
Senior Vice President, Business Services
Clement E. Nadeau
Senior Vice President, Operations, and Director
Kwong O. Nuey, Jr.
Vice President and Director
Anthony C. Pini
Senior Vice President, Customer Service, and Director
Neil Proudman
Vice President, Gas Delivery
Lawrence J. Reilly
Senior Vice President and General Counsel of National Grid USA
Steven W. Tasker
Senior Vice President and Treasurer
Directors are elected at the annual meeting of stockholders and hold office until the next annual meeting or a special meeting in lieu thereof, and until their successors are elected and qualified. All of the directors were elected in 2003. There are no family relationships between any of the directors and executive officers listed in the table. There are no arrangements or understandings between any executive officer and any other person pursuant to which he was selected as an officer.
Mr. Edwards was elected President of the Company and Senior Vice President of National Grid USA effective January 31, 2002. Prior to that, he served as Senior Vice President and Chief Financial Officer of the Company from 1997 to 2002. He served as Senior Vice President and Chief Financial Officer of Niagara Mohawk Holdings, Inc. from 1999 to 2002. He also serves as a director of National Grid USA and Utilities Mutual Insurance Company.
Mr. Cochrane was elected Chief Financial Officer effective August 1, 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. Ash has served as Vice President, Energy Supply, Pricing and Regulatory Proceedings since June 2003. He was Vice President, Gas Delivery, from December 1998 to June 2003.
Mr. Capomacchio was appointed Controller of the Company and Vice President and Controller of National Grid USA Service Company in January 2002. He has served as Controller of Massachusetts Electric Company, The Narragansett Electric Company, Nantucket Electric Company and Granite State Electric Company since May 2001. Mr. Capomacchio was Assistant Controller of the Service Company from 1998 to 2002.
Mr. Jesanis was appointed director of the Company in January 2002. 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 will be appointed a director of National Grid Transco in July 2004.
Mr. Kelleher was elected Senior Vice President of the Company effective May 1, 2004. He served as Vice President of National Grid USA from January 2002 to March 2004 and as its Treasurer from April 2002 to April 2003. Prior to that, he served as Vice President Financial Planning of Niagara Mohawk Power Corporation from 1999 to 2001. He also served as Vice President Financial Planning of Niagara Mohawk Holdings, Inc. in 2000.
Mr. Nadeau was elected Senior Vice President of the Company effective January 31, 2002. Prior to that, he served as Vice President-Electric Delivery beginning in 1998.
Mr. Nuey was elected Vice President and Chief Information Officer of National Grid USA Service Company effective January 31, 2002. He was the Vice President and Controller of National Grid USA Service Company from 2000 to 2002 and the Vice President and Director of Retail Information Services of the Company from 1997-2000.
Mr. Pini was elected Senior Vice President of the Company effective January 31, 2002. Previously, he was President of NEES Communications, Inc. from 1997 to 2002 and Vice President of Retail Customer Service of National Grid USA subsidiaries from 1993 to 1997.
Mr. Proudman was elected Vice President of the Company in August 2003. From 2002 to 2003, he was Head of Operations, Wales and the West Network, for the Company’s UK gas distribution affiliate Transco plc. Prior to that he was an Operations Manager for BG Transco from 1998 to 2001.
Mr. Reilly has been 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. Tasker has served as Senior Vice President, Distribution Finance, and Treasurer since February 2002. He was Vice President and Controller from December 1998 to February 2002.
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 plc website, at www.ngtgroup.com/about/mn_corp_govern.html, where any amendments or waivers will also be posted.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Summary Compensation Table
The following table sets forth the compensation paid or accrued for services rendered to Niagara Mohawk in the fiscal years ended March 31, 2004 and March 31, 2003, the transition period from January 1, 2002 to March 31, 2002 and the calendar year 2001 by the president and the four most highly paid persons who were serving as executive officers on March 31, 2004 (the “Named Executive Officers”).
(a)
Includes deferred compensation in category and year earned.
(b)
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.
(c)
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. For Mr. Pini, includes amounts reimbursed for housing expenses.
(d)
Includes Company contributions to life insurance. Also includes financial services for Mssrs. Ash, Jesanis and Nadeau.
(e)
Information is for the transition period from January 1, 2002 to March 31, 2002.
(f)
Mr. Jesanis is President and Chief Operating Officer of National Grid USA. Compensation that is allocable to NMPC is set forth in the table.
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.
Under the National Grid Transco Performance Share Plan, executives receive 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 from the UK, Europe and USA. 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. The Company must achieve median ranking in order for participants to realize the threshold payout of 30% of the original award. The Company must rank in the upper quartile relative to the comparator group to achieve the maximum payout of 100% of the original award.
Option/SAR Exercises in Fiscal Year 2004 and Fiscal Year-End Option/SAR 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.
The following table sets forth, for the Named Executive Officers, exercises of SARs 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 and SARs held by each at fiscal year-end.
(a)
Calculated based on the closing price on March 31, 2004 of National Grid Transco American Depositary Receipts traded on the New York Stock Exchange ($40.23). SAR grants were made under Niagara Mohawk’s Long Term Incentive Plan which was terminated on the merger with National Grid. At that time, outstanding grants of SARs were converted to SARs over National Grid American Depositary Receipts using a specified exchange ratio.
Pension Plans
Depending on their company origin prior to the merger of Niagara Mohawk Holdings with National Grid USA, the Named Executive Officers participate in one of two qualified pension plans: the National Grid USA Companies Final Average Pay Pension Plan (FAPP) or the Niagara Mohawk Pension Plan (Nimo Plan). Both FAPP and the Nimo Plan are noncontributory, tax-qualified defined benefit plans which between them provide a minimum retirement benefit to all employees of the National Grid USA companies. Pension benefits are related to compensation, subject to the maximum annual limits noted in the two pension tables 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 FAPP includes salary, bonus and incentive share awards.
Under the Nimo Plan, a participant’s retirement benefit is based on one of two formulas depending on age and years of service on July 1, 1998: the cash balance formula, or the highest five-year average compensation. Under the cash balance formula a participant’s retirement benefit grows monthly, according to pay credits (from 4 percent to 8 percent times base salary) plus interest credits. A non-union (management) employee who was at least 45 years of age and had 10 years of service on July 1, 1998 will receive the retirement benefit resulting from the higher of the two formulas.
Pension Plan Tables
Executive Supplemental Retirement Plan
The Executive Supplemental Retirement Plan (ESRP) is a noncontributory, nonqualified defined benefit plan that provides additional retirement benefits to Messrs. Edwards, Jesanis, Nadeau and Pini and other members of management who are eligible to receive either a FAPP or Nimo Plan benefit and whose compensation exceeds legal limits under the applicable plan or who are otherwise selected for participation. Mr. Ash is not eligible under the ESRP. 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. Mr. Nadeau and other ESRP participants who formerly participated in the Niagara Mohawk Supplemental Executive Retirement Plan (Niagara Mohawk SERP) are entitled to the pension benefit paid under the NiMo Plan, plus the higher of the pension benefit paid under the ESRP or that paid under the Niagara Mohawk SERP. The benefit paid under the Niagara Mohawk SERP was frozen at the time of the merger of Niagara Mohawk Holdings with National Grid. For Mr. Nadeau, that amount is frozen at $45,770. Mr. Edwards received the Niagara Mohawk SERP benefit at the merger and is eligible to receive a pension benefit under the ESRP, to be offset by the SERP benefit already received.
The following table shows the maximum retirement benefit (adjusted for Social Security, if applicable) an executive officer can earn in aggregate under the applicable qualified plan (FAPP or the Nimo Plan) 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 under the qualified pension plan for some highly compensated officers. The benefits listed are shown without any joint and survivor benefits. If a participant elected a 100 percent joint and survivor benefit at age 65, with a spouse of the same age, the benefit shown in the table would be reduced by approximately 16 percent.
For purposes of the pension program, the following Named Executive Officers had approximately the following credited years of benefit service at March 31, 2004: William F. Edwards, 25 years; Michael E. Jesanis, 20 years; Clement E. Nadeau, 31 years; and Anthony C. Pini, 25 years.
NiMo Plan
The following table shows the maximum retirement an employee can earn in aggregate under the Nimo Plan, without the ESRP. The total retirement benefit for Mr. Ash or any executive who is eligible for the NiMo Plan but is not eligible for the ESRP is equal to the pension paid under the Nimo Plan plus the frozen annual SERP benefit, which for Mr. Ash is $42,335 annually. The SERP benefits are inclusive of tax-qualified SERP benefits. 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 under the qualified pension plan for some highly compensated officers. The benefits listed are shown without any joint and survivor benefits. If a participant elected a 100 percent joint and survivor benefit at age 65, with a spouse of the same age, the benefit shown in the table would be reduced by approximately 16 percent.
For purposes of the pension program, Mr. Ash had approximately 34 credited years of benefit service at March 31, 2004.
Payments on a Change in Control or Termination of Employment
Certain Named Executive Officers have agreements with National Grid USA that provide for payments on a change in control or termination of employment. Those provisions are summarized below. In addition, all of the Named Executive Officers are subject to benefit and compensation plans of more general application, some of which also certain change in control provisions, also summarized below.
Mr. Edwards. Mr. Edwards has an employment agreement with National Grid USA, which will remain in effect until January 31, 2005. If Mr. Edwards terminates his employment for good reason or National Grid USA terminates his employment without cause, Mr. Edwards will be entitled to a lump sum severance benefit equal to four times his base salary. He will also be entitled to employee benefit plan coverage for medical, prescription drug, dental and hospitalization benefits and payment of premiums for life insurance for the remainder of his life. His coverage under other employee benefit plans will continue for four years. In the event that the severance payments to Mr. Edwards subject him to excise tax on excess parachute payments under the Internal Revenue Code, he would be reimbursed for such excise tax (plus the income tax and excise tax payable on such reimbursement). In the event of a dispute over Mr. Edwards’s rights under the agreement, National Grid USA will pay Mr. Edwards’s reasonable legal fees with respect to the dispute unless Mr. Edwards’s claims are found to be frivolous.
As used in Mr. Edwards’s employment agreement, “good reason” generally means a materially adverse change in duties, reduction in salary or benefits or relocation by more than 50 miles, all as determined by Mr. Edwards in good faith. Termination for “cause” generally arises on willful failure to perform duties, commitment of a felony, gross neglect or willful misconduct resulting in material economic loss to National Grid USA or its subsidiaries, including the Company, or breach of certain confidentiality and non-compete provisions. “Cause” must be determined by a vote of three-fourths of National Grid USA’s Board of Directors after a meeting at which Mr. Edwards and his legal counsel are entitled to be heard.
Mr. Jesanis. Mr. Jesanis has a change of control agreement with National Grid USA dated March 1, 1998 and amended March 15, 2003, which remains in effect for 36 months beyond the month in which a (1) Change in Control of National Grid (as defined in the agreement) or (2) Major Transaction (as defined in the agreement) occurs. In accordance with this agreement, if Mr. Jesanis’s employment is terminated without cause by National Grid USA or for Good Reason (as defined in the agreement) by Mr. Jesanis within 36 months following the event described in clause (1) or (2), National Grid USA will provide him with the severance payments and benefits described below.
In the event Mr. Jesanis’s employment is terminated without cause by National Grid USA or for Good Reason by Mr. Jesanis within 36 months following the month in which the Major Transaction or Change in Control occurs, Mr. Jesanis will be entitled to receive (in addition to any compensation and benefits payable to him through his Date of Termination (as defined in the agreement) according to the terms of said plans and any normal post-term compensation and benefits as they become due): (1) in lieu of any other salary payments: a lump sum cash payment equal to three times the sum of (a) the higher of (i) the annual base salary in effect at the time of termination or (ii) the annual base compensation in effect immediately prior to the Change in Control or Major Transaction and (b) the higher of (i) the average of the annual bonuses awarded him under the National Grid USA Companies’ Incentive Plan for the three performance years preceding the year in which Mr. Jesanis’s Date of Termination occurs or (ii) the average of the annual bonuses awarded him pursuant to the Incentive Plan for the three performance years preceding the year in which the Change in Control or Major Transaction occurs; (2) in addition to the retirement benefits to which Mr. Jesanis is entitled, a lump sum cash payment equal to the excess of (a) the actuarial equivalent of the retirement pension which he would have accrued under the terms of each Pension Plan (as defined in the agreement) of National Grid USA (determined as if he (i) were fully vested thereunder and had accumulated 36 additional months of service credit thereunder and (ii) had been credited under each Pension Plan during such 36-month period with compensation at the higher of (A) compensation during the 12 months immediately preceding Mr. Jesanis’s Date of Termination or (B) compensation during the 12 months immediately preceding the Change in Control or Major Transaction) over (b) the actuarial equivalent of the retirement pension which Mr. Jesanis had actually accrued pursuant to the provisions of each pension plan as of the Date of Termination; (3) the continuation of life, disability, accident and health insurance benefits substantially similar to those which Mr. Jesanis had received prior to his Date of Termination for 36 months following the Date of Termination, reduced to the extent he receives such benefits or such benefits are made available to him from a subsequent employer, without cost to him; (4) if Mr. Jesanis would have otherwise been entitled to post-retirement health care or life insurance had his employment terminated at any time during the 36 months following the Date of Termination such post-retirement health care and life insurance commencing on the later of (a) the date that such coverage would have first become available to him and (b) the date that the benefits described in clause (3) above terminate; and (5) the reimbursement of legal fees and expenses, if any, incurred by Mr. Jesanis in disputing in good faith, any issue relating to the termination of his employment. Notwithstanding the above, the payments and benefits to be provided to Mr. Jesanis will be reduced to the extent necessary to avoid imposition of the Excise Tax (as defined in the change in control agreements) pursuant to Section 4999 of the Code; provided that such reduction would yield a greater result to Mr. Jesanis than actual payment by him of the Excise Tax.
Executive Officers generally. At retirement, the Named Executive Officers 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’ executive compensation plan, in the event of a change in control, each Named Executive Officer 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.
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. Niagara Mohawk Holdings, Inc. owns all of the common stock of the Company.
*
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.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
ITEM 14.
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 $1,481,687. 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 $1,177,587.
Audit-related fees
There were no fees billed by PricewaterhouseCoopers LLP for assurance and related services that were reasonably related to the performance of the audit or review of the Company's financial statements and are not disclosed under “Audit Fees” above in fiscal 2004. In fiscal 2003, PricewaterhouseCoopers LLP billed $83,124 for such audit-related services. Services comprising these fees included ERISA audits of National Grid USA’s various employee benefit plans and the actuarial calculation of pension and other post-retirement benefits plan expense and obligation under United Kingdom GAAP.
Tax Fees
Aggregate fees billed by PricewaterhouseCoopers LLP to the Company for tax compliance, tax advice and tax planning were $77,983 in fiscal 2004, primarily for the review of deductibility of certain parachute payments. Aggregate fees billed by PricewaterhouseCoopers LLP to the Company for tax compliance, tax advice and tax planning were $124,396 in fiscal 2003, primarily for state tax, New York realty tax and property disposition tax services.
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 audit, audit-related and tax services provided by PricewaterhouseCoopers LLP were pre-approved by the Audit Committee.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE, AND REPORTS ON FORM 8-K
Exhibits
The exhibit index is incorporated herein by reference.
Financial Statement Schedules
Schedule II - Valuation and Qualifying Accounts and Reserves
Reports on Form 8-K
The Company did not file any current reports on Form 8-K during the last quarter of the fiscal year ended March 31, 2004.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
ON FINANCIAL STATEMENT SCHEDULE
To the Stockholders and Board of Directors of
Niagara Mohawk Power Corporation:
Our audits of the consolidated financial statements of Niagara Mohawk Power Corporation referred to in our report dated May 6, 2004, except for Notes D and E, as to which the dates are May 10, 2004 and May 27, 2004, respectively, appearing in this Form 10-K also included an audit of the financial statement schedule for each of the two years in the period ended March 31, 2004 and the sixty day period ended March 31, 2002, listed in Item 15 of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Boston, Massachusetts
May 6, 2004, except for Notes
D and E, as to which the dates
are May 10, 2004 and May 27, 2004,
respectively
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
ON FINANCIAL STATEMENT SCHEDULE
To the Stockholders and Board of Directors of
Niagara Mohawk Power Corporation:
Our audits of the consolidated financial statements of Niagara Mohawk Power Corporation referred to in our report dated May 14, 2002, appearing in this Form 10-K also included an audit of the financial statement schedule for the thirty day period ended January 30, 2002 and for the year ended December 31, 2001, listed in Item 15 of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Boston, Massachusetts
May 14, 2002
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
(a) Uncollectible accounts written off net of recoveries.
(b) The reserve in 2001 and after relates to non-rate base properties.
(c) In 2001, Niagara Mohawk eliminated certain valuation reserves, including certain materials and supplies inventory reserve as a result of the sale of its nuclear assets in November 2001.
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.
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/ William F. Edwards
William F. Edwards
President and Director (Principal Executive Officer)
/s/ John G. Cochrane
John G. Cochrane
Chief Financial Officer (Principal Financial Officer)
/s/ Edward A. Capomacchio
Edward A. Capomacchio
Controller (Principal Accounting Officer)
/s/ Michael E. Jesanis
Michael E. Jesanis
Director
/s/ Clement E. Nadeau
Clement E. Nadeau
Director
/s/ Kwong O. Nuey
Kwong O. Nuey
Director
/s/ Anthony C. Pini
Anthony C. Pini
Director
NIAGARA MOHAWK POWER CORPORATION
EXHIBIT INDEX
Each document referred to in this Exhibit Index is incorporated by reference to the files of the Securities and Exchange Commission, unless designated with an asterisk. The cross-reference table below sets forth the registration statements and reports from which the exhibits are incorporated by reference.
In accordance with Paragraph 4(iii) of Item 601 (b) of Regulation S-K, the Company agrees to furnish to the Securities and Exchange Commission, upon request, a copy of the agreements comprising the $804 million senior bank financing that the Company completed with a bank group on June 1, 2000, and subsequently amended. The total amount of long-term debt authorized under such agreement does not exceed ten percent of the total consolidated assets of the Company and its subsidiaries.
INCORPORATION BY REFERENCE
EXHIBIT NO.
PREVIOUS FILING
PREVIOUS EXHIBIT DESIGNATION
DESCRIPTION
3(a)(1)
O
3(a)(1)
Certificate of Consolidation of New York Power and Light Corporation, Buffalo Niagara Electric Corporation and Central New York Power Corporation, filed in the office of the New York Secretary of State, January 5,
INCORPORATION BY REFERENCE
EXHIBIT NO.
PREVIOUS FILING
PREVIOUS EXHIBIT DESIGNATION
DESCRIPTION
INCORPORATION BY REFERENCE
EXHIBIT NO.
PREVIOUS FILING
PREVIOUS EXHIBIT DESIGNATION
DESCRIPTION
INCORPORATION BY REFERENCE
EXHIBIT NO.
PREVIOUS FILING
PREVIOUS EXHIBIT DESIGNATION
DESCRIPTION
INCORPORATION BY REFERENCE
EXHIBIT NO.
PREVIOUS FILING
PREVIOUS EXHIBIT DESIGNATION
DESCRIPTION
INCORPORATION BY REFERENCE
EXHIBIT NO.
PREVIOUS FILING
PREVIOUS EXHIBIT DESIGNATION
DESCRIPTION
INCORPORATION BY REFERENCE
EXHIBIT NO.
PREVIOUS FILING
PREVIOUS EXHIBIT DESIGNATION
DESCRIPTION
4(a)
O
4(b)
Agreement to furnish certain debt instruments
4(b)(1)
C
**
Mortgage Trust Indenture dated as of October 1, 1937 between Niagara Mohawk (formerly CNYP) and Marine Midland Bank, N.A. (formerly named The Marine Midland Trust Company of New York), as Trustee
** Filed October 15, 1937 after effective date of Registration Statement No. 2-3414.
INCORPORATION BY REFERENCE
EXHIBIT NO.
PREVIOUS FILING
PREVIOUS EXHIBIT DESIGNATION
DESCRIPTION
INCORPORATION BY REFERENCE
EXHIBIT NO.
PREVIOUS FILING
PREVIOUS EXHIBIT DESIGNATION
DESCRIPTION
4(d)(3)
CC
1.2
Form of Second Supplemental Indenture, between Niagara Mohawk Power Corporation and The Bank of New York, as Trustee
INCORPORATION BY REFERENCE
EXHIBIT NO.
PREVIOUS FILING
PREVIOUS EXHIBIT DESIGNATION
DESCRIPTION
* Filed herewith.