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 1,500,000 electric customers in the areas of eastern, central, northern and western New York and sells, distributes, and transports natural gas to approximately 571,000 gas customers in areas of central, northern and eastern New York.
Niagara Mohawk Holdings, Inc. (Holdings), the parent company of the Company, is a wholly owned subsidiary of National Grid USA (National Grid). National Grid is a wholly owned subsidiary of National Grid plc (formerly known as National Grid Transco plc).
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 PSC went into effect, superseding the prior rate plan. Since then, 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.
Merger Rate Plan (MRP): The Company’s delivery rates are governed by a ten-year rate plan that began on February 1, 2002. Under the plan, after reflecting the Company’s share of savings related to the acquisition, it may earn a threshold return on equity for the electricity distribution business of 10.6%, up to 11.75% without any sharing with customers (12.0% if certain customer outreach, education, competition-related and low income incentive targets are met). Half of any amounts in excess of 12%, up to 14%, 25% of any earnings in excess of that up to 16%, and 10% beyond that are retained by the Company. This effectively offers the Company the potential to achieve a return on equity in excess of the regulatory allowed return of 10.6%. The return on equity is calculated cumulatively from inception to December 31, 2005 and annually thereafter for the prior two calendar years. The earnings calculation used to determine the regulated returns excludes half of the synergy savings, net of the cost to achieve them, that were assumed in the rate plan based on the Company’s merger with National Grid. Under the plan, gas delivery rates were frozen until the end of the 2004 calendar year, after which the Company had the right to request an increase at any time, if needed. The Company may earn a threshold return on equity ranging from 10.6% to 12.6% depending on the achievement of certain customer migration levels and customer awareness and understanding of gas competitive opportunities. Above this threshold, the revenue equivalent of gas earnings must be shared equally between shareholders and customers. The Company collects the transmission business revenues under several Federal Energy Regulatory Commission (FERC) rate schedules and the state energy delivery rates discussed above. Total transmission business revenues are determined by the state-approved 10-year rate plan.
The Company resets its Competitive Transition Charges (CTC) in electricity rates every two years under its MRP. The CTC reset is intended to account for changes in forecasted electricity and natural gas commodity prices, and the effects those changes have on the Company’s above-market payments under legacy power contracts that otherwise would be stranded. In addition, the MRP allows the Company to recover amounts exceeding $100 million in its deferral accounts (as projected through the end of each two-year CTC reset period). In accordance with the MRP, deferral accounts were established to track changes in specified cost and revenue items that have occurred since the Plan was established. These changes include costs or revenues related to changes in tax, accounting, and regulatory requirements, changes from the levels of pension and post-retirement benefit expenses from the levels specified in the Plan, and various other items, including storms, environmental remediation costs, and various rate discounts. The deferrals are subject to regulatory review and approval. On July 29, 2005, the Company made its biannual deferral account recovery filing for balances in the deferral account as of June 30, 2005 plus projected deferrals. On December 27, 2005, the PSC approved recovery of deferral account amounts of $100 million in calendar year 2006 and $200 million in
calendar year 2007, and established a timeline for the Department of Public Service Staff (Staff) to perform its audit of the deferral account. For 2006, the deferral surcharge was included in rates beginning in April and the $100 million was collected over the last nine months of the 2006 calendar year. The Staff filed testimony on August 2, 2006, proposing in excess of $200 million of initial adjustments to the deferral balance and projected deferrals. After replies from the Staff and the Company, an evidentiary hearing was held on October 5, 2006. Upon the conclusion of the evidentiary hearings, the Company and the Staff agreed to enter into non-binding mediation discussions before an administrative law judge from the PSC in an attempt to resolve some or all of the amounts remaining in dispute.
Through the mediation process, the Company, the Staff, and Multiple Intervenors (Parties), reached a resolution of the disputed issues presented in the deferral account case as well as other cases pending before the Commission regarding pension costs, the costs of enhanced inspections of the transmission and distribution system, and the sale of the Nine Mile Point nuclear generating facilities. A Stipulation of the Parties (Stipulation) setting forth the resolution of these issues was executed and filed with the Commission on March 23, 2007. A hearing on the Stipulation of the Parties was held before the PSC’s administrative law judge on May 17, 2007.
Under the Stipulation, the Company has agreed to a net reduction of the deferral account balance of approximately $127 million. This includes reclassifications from the deferral account to other balance sheet accounts of approximately $64 million. It also includes a reduction to the deferral account balance as of February 28, 2007 and decrease to earnings before income taxes of approximately $63 million. These adjustments include impacts to related gas deferral balances. The significant issues resolved under the Stipulation include:
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The Company will cease seeking to recover most disputed station service lost revenues. This resulted in a reduction to the deferral account and pre-tax earnings as of February 28, 2007 of $68 million. The impact of the settlement on future revenues depends on the usage by generators and prospective adjustments to delivery rates that are dependent in part on commodity prices. We currently estimate a reduction in revenues of about $9 million to $12 million per year through December 31, 2011 which is the end of the MRP.
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The Parties agreed to the method of determining incremental major storm costs related primarily to the treatment of third party contractor costs and costs incurred by affiliates during storm restoration efforts. The definition of a major storm was also clarified under the Stipulation. Storm related adjustments resulted in a reduction of $10 million to the deferral account and pre-tax earnings.
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The Parties agreed to the method of determining deferrable incremental costs associated with the Company’s ongoing stray voltage inspection and testing program resulting in a reduction to the deferral account and pre-tax earnings of $4 million.
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The Parties agreed to the method for capitalizing fringe benefit overhead costs associated with the Company’s fixed asset construction activities. This resulted in a decrease to utility plant of $17 million, an increase to the deferral account of $11 million, and a reduction in pre-tax earnings of $6 million.
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The Company is allowed to recover 50% of pension settlement losses that it incurred in fiscal years 2007 and 2004. This resulted in an increase to the deferral account and pre-tax earnings of $23 million related to fiscal 2007 and 2004 pension settlement losses.
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Although it has no impact on past or future rates, the Company will exclude goodwill from any future earnings sharing filings and other filings made with the PSC.
Certain deferral account balances as of June 30, 2005 remain subject to audit by the Staff. The Stipulation also clarifies going forward procedures for recording, reporting and auditing of certain other deferrals authorized for recovery. The next biannual deferral account filing will be made by August 1, 2007 for deferral balances as of June 30, 2007 and projected deferrals through December 31, 2009. The Staff will audit future biannual deferral account filings made pursuant to the MRP, however the Parties have agreed that the amount of deferral recoveries in calendar year 2008 and 2009 will not exceed the $200 million level currently being collected in rates. Any deferrals in excess of this recovery level would be subject to recovery after 2009.
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. As such the Company will provide electricity to its customers who are unable or unwilling to obtain an alternative supplier which accounts for approximately 89% of the Company’s customers and 57% of its deliveries. 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, 2007, the Company had approximately 53,000 pole miles of transmission and distribution lines for electricity delivery. Evaluation of these facilities relative to the requirements of the New York State Reliability Council, Northeast Power Coordinating Council, North American Electric Reliability Council, 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. The gas distribution system is served by 3 interstate natural gas pipelines regulated by the 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).
Compliance with Environmental Requirements: 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 and water quality; wetlands and flood plains; storage, transportation and disposal of hazardous wastes and substances; storage tanks; and site remediation. The Company believes it is handling identified wastes and by-products in a manner consistent with applicable requirements. The environmental management systems for the Company’s distribution, transmission and investment recovery facilities are certified to the International Organization for Standardization (ISO) 14001 standard. Management believes it is probable that costs associated with environmental compliance will continue to be recovered through the ratemaking process. The Company’s compliance has no material effect on its capital expenditures, earnings or competitive position. For a discussion of the Company’s reserves for environmental liabilities and its 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.
The Company has implemented an environmental audit program to identify any potential areas of concern and aid in compliance with legal 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.
Employee Relations: The Company’s workforce at March 31, 2007 numbered approximately 3,950 employees, of whom approximately 81% were union members. The Company also receives substantial support for its activities from employees of National Grid USA Service Company, Inc., an affiliate that provides administrative services support to all National Grid companies. The Company reimburses the Service Company for the costs associated with those services.
The Company believes relations with employees are good.
Seasonality: There is seasonal variation in electric customer load, usually peaking in the winter and summer months. The seasonality is correlated with the colder or warmer temperature because 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 with colder temperatures when more gas is used for heating.
Also see Part II, Item 8. Financial Statements and Supplementary Data - Note O - Quarterly Financial Data (unaudited).
ITEM 1A.
ITEM 1A. RISK FACTORS
This Annual Report on Form 10-K contains certain statements that are neither reported financial results nor other historical information. These statements are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Because these forward-looking statements are subject to assumptions, risks and uncertainties, actual future results may differ materially from those expressed in or implied by such statements. We have identified the following risk factors that could have a material adverse effect on our business, financial condition, results of operations or future prospects, or your investment in our securities. Not all of these factors are within our control. In addition, other factors besides those listed below may have an adverse effect on the Company. Any forward-looking statements should be considered in light of these risk factors and the cautionary statement set out at the beginning of this report.
Regulatory and environmental risks
Changes in law or regulation could have an adverse effect on our results of operations.
Our business is heavily regulated, and changes in law or regulation could adversely affect us. Regulatory decisions concerning, for example, whether licenses or approvals to operate are renewed and the level of permitted revenues could have an adverse impact on our results of operations, cash flows and financial condition. Our rate plan provides for deferral and recovery of the effects of any externally imposed accounting changes, and changes in federal and state rates, laws, regulations and precedents governing taxes that increase or decrease our costs or revenues from electric operations by more than $2 million per year, or by an amount that exceeds 1% of annual gas earnings. However, these deferred amounts are subject to regulatory review and audit. This is discussed in more detail in Part II, Item 8. Financial Statements and Supplementary Data - Note B - Rate and Regulatory Issues of the Financial Statements.
Breaches of or changes in environmental or health and safety laws or regulations could expose us to claims for financial compensation and adverse regulatory consequences, as well as damaging our reputation.
Aspects of our activities are potentially dangerous, such as the operation and maintenance of electricity lines and the transmission and distribution of natural gas. Energy delivery companies also typically use and generate in their operations hazardous and potentially hazardous products and by-products. In addition, there may be other aspects of our operations that are not currently regarded or proved to have adverse effects but
could become so, for example, the effects of electric and magnetic fields. We are subject to laws and regulations relating to pollution, the protection of the environment and how we use and dispose of hazardous substances and waste materials. We are also subject to laws and regulations governing health and safety matters including air quality, water quality, waste management, natural resources and the health and safety of the public and our employees. Any breach of these obligations, or even incidents relating to the environment or health and safety that do not amount to a breach, could adversely affect the results of operations and our reputation.
Changes to the regulatory treatment of commodity costs may have an adverse effect on the results of operations.
Changes in commodity prices could potentially affect our energy delivery businesses. Our rate plan permits us to pass through virtually all of the increased costs related to commodity prices to consumers. However, if this ability were restricted, it could have an adverse effect on our operating results.
Operational risks
Network failure or the inability to carry out critical non-network operations may have significant adverse impacts on both our financial position and our reputation.
We may suffer a major network failure or may not be able to carry out critical non-network operations. Operational performance could be adversely affected by a failure to maintain the health of the system or network, inadequate forecasting of demand or inadequate record keeping. This could cause us to fail to meet agreed standards, and even incidents that do not amount to a breach could result in adverse regulatory action and financial consequences, as well as harming our reputation. In addition to these risks, we are subject to other risks that are largely outside of our control such as the impact of weather or unlawful acts of third parties. Weather conditions can affect financial performance and severe weather that causes outages or damages infrastructure will adversely affect operational and potentially, business performance. Terrorist attack, sabotage or other intentional acts may also physically damage our infrastructure or otherwise significantly affect our activities and, as a consequence, affect the results of operations.
Our reputation may be harmed if customers suffer a disruption to their energy supply even if this disruption is outside of our control.
We are responsible for transporting available electricity and gas and, for those customers that have not chosen another supplier; we are also responsible for acquiring and providing electricity and gas which we procure from commodity suppliers. However, where there is insufficient supply, no matter the cause, our role is to manage the system safely, which, in extreme circumstances, may require us to disconnect consumers.
Our results of operations depend on a number of factors including performance against regulatory targets and the delivery of anticipated cost and efficiency savings.
Earnings maintenance and growth will be affected by our ability to meet regulatory efficiency targets. To meet these targets, we must continue to improve managerial and operational performance. Under our rate plan, earnings will be affected by our ability to deliver integration and efficiency savings. Earnings also depend on meeting service quality standards. To meet these standards, we must improve service reliability and customer service. If we do not meet these targets and standards, both the results of operations and our reputation may be harmed.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
There is no unresolved SEC staff comments required to be reported under this Item 1B.
ITEM 2.
ITEM 2. PROPERTIES
Electric Transmission and Distribution: As of March 31, 2007, the Company’s electric transmission and distribution systems were composed of:
A portion 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 Distribution: The Company distributes gas that it purchases from suppliers and transports gas owned by others. As of March 31, 2007, the Company’s natural gas delivery system was comprised of approximately 8,100 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: The Company’s facilities are potentially affected by land claim litigation involving the Oneida, Mohawk and Onondaga Nations. Other than the Cayuga Nation’s and Seneca land claims, which have been dismissed by the courts, the land claim litigation has not been resolved. The Company continues to monitor the land claim litigation and, where necessary, defend its interests.
Mortgage Liens: Substantially all of the Company’s operating properties are subject to mortgage liens securing its mortgage debt.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
None.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The following actions during the previous quarters of fiscal year ended March 31, 2007 were taken by unanimous written consent of the sole common shareholder in lieu of a special meeting,
PART II
ITEM 5.
ITEM 5.
MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
The common stock of the Company is held solely by Niagara Mohawk Holdings, Inc., and therefore indirectly by National Grid and National Grid plc. There is no public trading market for the Company’s common stock. The Company did not purchase any of its equity securities during the fourth quarter of fiscal 2007. 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 table sets forth selected financial information for the Company for the years ended March 31, 2007, 2006, 2005, 2004, and 2003. These tables have been derived from the financial statements of the Company and should be read in connection therewith.
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.
*
As all of the Company’s shares of common stock are owned by its parent company, dividend information and per share data are not relevant.
ITEM 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Business: The Company’s primary business driver is the long-term rate plan with state regulators through which the Company can earn and retain certain amounts in excess of traditional regulatory allowed returns. The plan provides incentive returns and shared savings allowances which allow the Company an opportunity to benefit from efficiency gains identified within operations. Other main business drivers for the Company include the ability to streamline operations, enhance reliability and generate funds for investment in the Company’s infrastructure.
CRITICAL ACCOUNTING POLICIES
The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America (GAAP) requires management to apply policies and make estimates and assumptions that affect the 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 (namely, the FERC, PSC, or other regulatory body with 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 regulatory assets and liabilities typically include deferral of under recovered or over recovered energy costs, environmental restoration costs and post retirement benefit costs, as well as 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 if its 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 regulatory assets and liabilities would be recognized as current-period revenues or expenses.
Amortization of regulatory assets is provided over the recovery period as allowed in the related regulatory agreement. Under the MRP, a regulatory asset, called stranded costs, was established that included the costs of the Master Restructuring Agreement (MRA), the cost of any additional Independent Power Producer (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 February 1, 2002, the MRP 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. Amortization of the stranded cost regulatory asset is shown separately because 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.
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 (discussed below) delivered between the cycle billing date and the end of the accounting period.
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.
Several assumptions affect the pension and other post-retirement benefit expense and the measurement of these benefit obligations. The more significant assumptions include the return on assets, discount rate, and in the case of retiree healthcare benefits, medical trends. All ongoing costs of qualified pension and post-retirement healthcare benefits plans are recoverable from customers through reconciling provisions of the MRP. 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.
The major assumptions are:
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Expected return on assets. The assumed rate of return for various passive asset classes is based on both 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 long-term assumptions. 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 the target asset allocation, and the resulting long-term return on asset rate is then applied to the market value of assets. For fiscal 2007, the Company used an 8% assumed return on assets for its pension plan and a weighted average of 7.8% assumed return on assets for its other post-retirement benefits plans.
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Discount rate. The Company bases its discount rate on two measures of rates specific to the yield curve applicable to the liabilities of the plans. The actuary calculates the present value of the projected cash flows of the plans utilizing derived zero coupon interest rates specific to the timing of each respective cash flow and calculates the single weighted average interest rate that equates the total present value with the stream of future cash flows. This results in a weighted average interest rate of 5.92% based on the Citigroup Pension Discount Curve, which is based on AA-rated corporate bonds, and an interest rate of 6% based on a yield curve of top quartile yielding Aa corporate bonds. A discount rate of 6% was deemed appropriate for the plans.
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Medical trends. The health care cost trend rate is the assumed rate of increase in per-capita health care charges. In fiscal year 2006, the health care cost trend assumption was updated to include rates for the pre 65 and post 65 age groups. For 2007, the initial health trend was assumed to be 10% for the pre 65 age group and 11% for the post 65 age group. The ultimate trend of 5%, for both age groups, was assumed to be reached in 2011 for the pre 65 age group and 2012 for the post 65 age group.
Refer to the adoption of the new accounting standard SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” under the New Accounting Standards section below.
Goodwill: The Company applies the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets.” In accordance with SFAS No. 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.
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.” Income taxes have been computed utilizing the asset and liability approach that requires the recognition of deferred tax assets and liabilities for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. Deferred investment tax credits are amortized over the useful life of the underlying property.
The Company’s income 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. Determination of current year federal and state income tax will not be settled until final approval of returns by taxing authorities.
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,” and SFAS No. 149, “Amendment of SFAS No. 133 on Derivative Instruments and Hedging Activities,” as amended. 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 because the Company has received approval from the PSC to establish a regulatory asset or liability for derivative instruments that did not qualify for hedge accounting and were the result of regulatory rulings. 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 percent to 120 percent of the changes in fair value or cash flows of the hedged item.
RESULTS OF OPERATIONS
The following discussion and analysis highlights items that significantly affected the Company’s operations during the fiscal years ended March 31, 2007 and 2006.
EARNINGS
Net income for the fiscal year ended March 31, 2007 decreased by $127 million compared to the same period in the prior fiscal year. The decrease is due to the deferral account audit write off of $63 million, higher operation and maintenance expense, lower sales of electricity due to milder weather conditions in the current fiscal year as compared to the prior year, and a positive adjustments to electric revenues of $32 million recorded in the prior year with no comparable adjustments in the current year. These decreases were partially
offset by lower income tax expense and reduced interest expense. See the following discussions of revenues and operating expenses for more detailed explanations.
Net income for the fiscal year ended March 31, 2006 increased by approximately $54 million compared to the same period in the prior fiscal year. This increase is primarily due to higher electric and gas margin of $48 million which is mostly attributable to favorable electric volume in delivery-only sales, reduced interest costs of approximately $21 million and a positive adjustment to electric revenues of $32 million stemming from the recognition of a regulatory asset reflecting our ability to recover a previously fully reserved account receivable. They were offset by increased income tax expense of $19 million, increased depreciation expense of $3 million, increased operating and maintenance expense of $9 million and increased other deductions of $16 million. See the following discussions of revenues and operating expenses for more detailed explanations.
REVENUES
Electric
The Company’s electricity business encompasses the transmission and distribution of electricity including stranded cost recoveries. Rates are set based on historical or forecasted costs, and the Company earns a return on its assets, including a return on the “stranded costs” associated with the divestiture of the Company’s generating assets under deregulation. Since the start of electricity deregulation in the state of New York, retail electric customers have been migrating to competitive suppliers for their commodity requirements. Commodity costs are passed through directly to customers.
Electric revenue includes:
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Retail sales - delivery charges and recovery of purchased power costs from customers who purchase their electric supply from the Company.
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Delivery only sales - charges for only the delivery of energy for customers who purchase their power from competitive electricity suppliers.
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Sales for resale - sales of excess electricity to the NYISO at the market price of electricity. Any gains or losses on sales for resale are passed through directly to customers.
Gas
The Company is also a gas distribution company that services customers in cities and towns in central and eastern New York. The Company’s gas rate plan allows it to recover all commodity costs (i.e., the purchasing, interstate transportation and storage of gas for sale to customers) from customers (similar to the recovery of purchased electricity).
Gas revenue includes:
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Retail sales - distribution (transportation) of gas and the commodity to customers who purchase their gas supply from the Company.
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Transportation revenue - charges for the transportation of gas to customers who purchase their gas commodity from other suppliers.
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Off-System wholesale sales - sales of gas commodity off its distribution system for resale.
Electric revenues decreased $50 million during the fiscal year ended March 31, 2007 compared to the same period in the prior fiscal year. The decrease in electric revenue was primarily due to an $80 million adjustment related to settlement of the deferral audit, a decrease due to the migration of customers to competitive suppliers, a 2.3% decrease in kWh deliveries due to milder weather than experienced in the prior fiscal year, a reduction in the cost of electricity that was passed on to customers, and a positive adjustment was made to electric revenues of $32 million in fiscal year 2006 with no comparable adjustment in the current fiscal year. The deferral audit settlement adjustment was primarily due to the write off of deferred disputed station service revenues. The $32 million positive adjustment recorded in the prior year due to a one-time recognition of a regulatory asset related to the recovery of a previously fully reserved accounts receivable. These decreases were partially offset by an increase of $150 million of rate plan deferral revenues and increased energy
management assessment revenues. The deferral revenues do not impact net income since the Company recognizes an equal offsetting amount of amortization expense. For further information regarding the deferral audit stipulation, see Part II, Item 8. Financial Statements and Supplementary Data - Note B - Rate and Regulatory Issues.
Electric revenues increased $190 million during the year ended March 31, 2006 from the prior fiscal year. Retail sales revenues increased $52 million primarily as a result of higher costs of electricity purchased which were passed through to customers. Another contributing factor to the increase in revenue was a $32 million positive adjustment to electric revenues stemming from the recognition of a regulatory asset reflecting our ability to recover a previously fully reserved account receivable. Delivery only sales and miscellaneous revenues increased $185 million primarily due to the migration of retail electric customers to competitive suppliers for their commodity requirements. The migration of customers is also a contributing factor to the decrease in retail kilowatt-hour (kWh) sales in the fiscal years ended March 31, 2006. Warmer summer and colder autumn weather than experienced in the previous fiscal year also contributed to the increase in revenue for the fiscal year ended March 31, 2006. Offsetting these increases was a $47 million decrease of sales for resale. All electricity purchased under certain purchased power contracts is sold to the NYISO. The decreases in sales to the NYISO for the year ended March 31, 2006 was due to the expiration of some of these contracts.
Gas revenues decreased $162 million in the fiscal year ended March 31, 2007 compared to the same period in the prior fiscal year. This decrease is primarily due to both decreased prices of gas purchases which were passed through to customers and decreased volumes of gas sold to customers.
Gas revenues increased $229 million in the fiscal year ended March 31, 2006 from the prior fiscal year. This increase is primarily a result of higher prices of gas purchases which were passed through to customers.
The table below details components of the gas revenue fluctuation:
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 volumes for the fiscal year ended March 31, 2007, excluding transportation of customer-owned gas, decreased approximately 1.8 million Dekatherms (Dth), or a 3.1% decrease from the prior fiscal year. Gas sales for the fiscal year ended March 31, 2006, excluding transportation of customer-owned gas, decreased approximately 3.9 million Dth, or a 6.4% decrease from the fiscal year ended March 31, 2005. The decreased gas usage for the fiscal year ended March 31, 2007 compared with the fiscal year ended March 31, 2006 is primarily due to a decrease in weather-normalized use per customer. The decreased gas usage for the fiscal year ended March 31, 2006 compared with the fiscal year ended March 31, 2005 is partially due to the impacts of weather, and decreased use per customer, somewhat offset by the return of customers from alternate providers.
OPERATING EXPENSES
Purchased electricity decreased $75 million for the fiscal year ended March 31, 2007 from the prior fiscal year primarily as a result of a decrease in volume purchased. The volume of kWh purchased decreased 1.3 billion kWh or 5.6% compared to the same period in the prior fiscal year, reflecting migration of customers to competitive electricity suppliers and milder weather. This volume decrease was offset by a 1% increase in the price of electricity relative to the prior fiscal year.
Purchased electricity increased $100 million for the fiscal year ended March 31, 2006 from the prior fiscal year. The volume of kWh purchased decreased 3.2 billion kWh, or 12% compared with the prior fiscal year, reflecting migration of customers to competitive electricity suppliers and the expiration of certain sales for resale purchased power contracts. This volume decrease was offset by a 22% increase in the price of electricity relative to the prior fiscal year.
Purchased gas decreased $159 million for the fiscal year ended March 31, 2007 compared to the same period in the prior fiscal year. This decrease is primarily the result of decreased gas prices during the year and a decrease in the amount of gas sold off-system. The Company’s net cost per Dth, as charged to expense, including the effects of the gas cost deferral, decreased to $8.29 in the fiscal year ended March 31, 2007 from $9.92 in the prior fiscal year. The decrease in purchased gas expense was also affected by decreased purchases of gas on behalf of system customers.
Purchased gas expense increased $232 million for the fiscal year ended March 31, 2006 from the prior fiscal year. This increase is primarily the result of increased gas prices during the year and an increase in the amount of gas sold off-system. The Company’s net cost per Dth, as charged to expense, including the effects of the gas cost deferral, increased to $9.92 in the fiscal year ended March 31, 2006 from $7.12 in the prior fiscal year. The increase due to price was slightly offset by decreased purchases.
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:
An Energy Procurement Risk Management Committee (EPRMC) was established to monitor and control efforts to manage commodity risks. This committee issues and oversees the Financial Risk Management Policy (the Policy) which outlines the parameters within which corporate managers are to engage in, manage and report on various areas of commodity 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 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.
Commodity Price Risk: The Company is exposed to commodity market price fluctuations related to: (1) the cost of electricity and natural gas for resale to its customers, and (2) the impact that natural gas, electricity and oil prices have on the swap contracts and one large non-Master Restructuring Agreement (MRA) IPP contract. For both gas and electricity, the Company reconciles and recovers commodity costs currently in rates to its customers who purchase the commodity. Where possible, the Company takes positions to mitigate expected price volatility but only to the extent that the quantities involved are based on expectations of delivery. The Company attempts to mitigate exposure through a program that hedges risks as appropriate. The Company does not speculate on movements in the underlying commodity prices. Commodity purchases are based on analyses performed in relation to expected customer deliveries for electricity and natural gas. The volume of commodities covered by hedging contracts does not exceed amounts needed for customer consumption in the normal course of business or to offset price movements in the contracts being hedged.
Large customers that continue to purchase electricity from the Company receive power from the NYISO at prevailing market prices and, in effect, assume the associated commodity price risk. For the remaining customers the Company meets a significant portion of its commodity supply responsibility through various physical and financial contracts. Some of these contracts are indexed to fuel prices, primarily natural gas. Although the current rate agreement allows for a pass-through of the commodity cost of power, the Company considers it prudent to perform certain hedging activities as a means of controlling cost volatility caused by the operation of these indexing mechanisms.
As part of the MRA, the Company entered into restated indexed swap contracts with eight IPPs. See Item 8.
Item 8. Financial Statements and Supplementary Data - Note L - Derivatives and Hedging Activities, for a more detailed discussion of these swap contracts.
The fair value of the liability under the swap contracts is based on the difference between projected future market prices and projected contract prices applied to the notional quantities and discounted to the present value. This liability was approximately $268 million and $537 million at March 31, 2007 and 2006, respectively, and is recorded on the Company’s balance sheets under both current and noncurrent liabilities. The decrease is primarily due to the revaluation of the contracts at March 31, 2007 and to normal contract settlements. The discount rate is a market-based rate representing the yield curve through the life of the contracts. Based on the PSC’s approval of the restated contracts as part of the MRA, including the indexed swap contracts, and the opportunity to recover the estimated indexed swap liability from customers, the Company recorded a corresponding regulatory asset. The amounts of the recorded liability and regulatory asset are sensitive to changes in anticipated future market prices and changes in the indices upon which the indexed swap contract payments are based.
If the indexed contract price increased or decreased by 1 percent, there would be a respective $5 million increase or decrease in the present value of the projected over-market exposure associated with these contracts. If the market prices increased or fell by 1 percent, there would be a respective $3 million decrease or increase in the projected over-market exposure associated with these contracts. If the discount rate was 0.5 percent higher or lower, the respective net present value of the projected over-market exposure associated with these contracts would decrease or increase by approximately $0.1 million.
The area of exposure to cash flow is in the indexing of the contract prices for the IPP indexed swaps and a non-MRA IPP where payments are based on gas prices. The contract payments under the IPP swaps and non-MRA IPP swaps are indexed to the costs of fuel, primarily natural gas. As fuel costs rise, the payments the Company makes under those contracts increase. The current rate plan allows the pass-through of the commodity cost of power to customers; however, the Company still considers it prudent to use certain financial instruments to limit the impact of commodity fluctuations on these payments.
The Company has taken steps to mitigate the potential impact that fuel prices would have on the payments for the IPP swaps and a physical power contract with a non-MRA IPP. To limit this exposure, the Company purchased NYMEX gas futures contracts and entered into fixed-for-floating swaps on gas-basis costs. To
hedge the non-MRA IPP contract, the Company purchased NYMEX gas futures. See Item 8 - Financial Statements and Supplementary Data - Note L - Derivatives and Hedging Activities for a more detailed discussion of these contracts. As of March 31, 2007, gas futures have been purchased to hedge approximately 50% of the estimated amount needed to offset gas price changes in the period ended March 31, 2008. At March 31, 2006 and 2007, the open NYMEX futures the Company had in place to hedge the payments under these contracts had a fair value pre-tax loss of $27 million and $4.6 million, respectively.
Activity for the fair value of the NYMEX futures and gas basis swaps for the fiscal year ended March 31, 2007 is as follows:
Gas Supply Price Risk: The cost of natural gas sold to customers fluctuates during the year with prices historically most volatile in the winter months. The Company’s gas rate agreement includes a provision for the collection or pass-back of increases or decreases in purchased gas costs. The PSC has also mandated that the Company attempt to reduce the price volatility in the gas commodity portion of customers’ bills. In response to this mandate, the Company’s Board of Directors has authorized the use of futures, options, and swaps to hedge against gas price fluctuations. The hedging program is consistent with the Policy and is monitored by the EPRMC.
The Company attempts to hedge approximately 50% of its forecasted average demand for the October to April period through a program using in-ground storage and financial instruments. NYMEX gas futures are the financial instruments used by the Company. Each NYMEX futures contract represents 10,000 Dth of gas. At March 31, 2007 and 2006 the mark-to-market net open position of cash flow hedges for gas supply was a gain of $2.5 million and a loss of $5 million, respectively. There were 702 and 671 open futures contracts at March 31, 2007 and March 31, 2006, respectively.
The following table details the fair value activity for gas cash flow hedges for the fiscal year ended March 31, 2007:
The above activity coupled with the in-ground storage hedged approximately 50% of the Company’s average gas demand for the October to April period. The rest of the gas needs are met through market-based purchases that are subject to price fluctuations and which are mitigated by regulatory rate recovery for the cost of gas purchased.
The extent to which market price movement would affect the value of the hedges would be matched by an offsetting change in the anticipated gas purchased costs for the quantity of gas hedged. Therefore, for the quantities hedged, variations in market costs would not result in any significant impact on earnings.
Electricity Price Risk: The Company meets a substantial portion of its electricity requirements through a series of long-term physical and financial contracts. The remaining electricity requirements are purchased at market prices through the NYISO. If certain proscribed risk values are exceeded during a time when the Company forecasts a short power situation, the Company may use electricity swaps to lock in a price for electricity. In April 2003, the Company began utilizing NYMEX electricity swap contracts to hedge electricity purchases. The Company continues to evaluate the use of hedging instruments to manage the cost of electricity purchased. At March 31, 2007, the mark-to-market net open position of electricity swap contracts was a gain of $0.8 million.
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. Financial Statements and Supplementary Data - Note E - Long-Term Debt and Note F - Short-Term Debt. Total adjustable rate promissory notes are currently valued at $575 million. There was $395 million of short term borrowings at March 31, 2007 from the intercompany money pool maintained by National Grid.
There is no interest rate cap on the promissory notes. The interest rates on short-term money pool borrowings are tied to the published, 30 day commercial paper rate with the amount borrowed from the National Grid money pool adjusted daily.
The Company also maintains long-term debt at fixed interest rates. A controlling factor on the exposure to interest rate variations is the mix of fixed to variable rate instruments maintained by the Company. For March 31, 2007 and 2006, adjustable rate instruments comprise 39.7% and 33.3% of external long-term debt, and 21.7% and 19.7% of total long-term debt, respectively. In the aggregate at March 31, 2007 and 2006, variable rate instruments do not constitute a significant portion of total capitalization and debt, thereby limiting the Company’s exposure to interest rate fluctuations.
If interest rates averaged 1% more in the next fiscal year versus the fiscal year ended March 31, 2007, the Company’s interest expense would increase and income before taxes would decrease by approximately $10 million. This figure was derived by applying a hypothetical 1% variance to the variable rate debt of $575 million plus the short-term variable borrowings of $395 million at March 31, 2007. Changes in the actual cost of capital from levels assumed in rates would create either exposure or opportunity for the Company until these changes could be reflected in future prices.
Equity Price Risk: The Company currently has no equity price risk.
Foreign Currency Exchange Risk: The Company currently has no foreign currency exchange risk.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
A. 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 consolidated financial statements listed in the index appearing under Item 15 present fairly, in all material respects, the financial position of Niagara Mohawk Power Corporation and its subsidiaries at March 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended March 31, 2007 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule 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.
As described in Note H to the financial statements, the Company adopted a new principle of accounting for pension and postretirement benefit plans in accordance with Financial Accounting Standards Board Statement No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. In accordance with the provisions of FASB No. 158, the 2007 financial statements include the adjustment to initially apply this new accounting principle as of March 31, 2007.
Boston, Massachusetts
June 28, 2007
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Statements of Operations
(In thousands of dollars)
Consolidated Statements of Comprehensive Income
(In thousands of dollars)
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.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Statements of Retained Earnings
(In thousands of dollars)
The accompanying notes are an integral part of these financial statements.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
(In thousands of dollars)
The accompanying notes are an integral part of these financial statements.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
(In thousands of dollars)
The accompanying notes are an integral part of these financial statements.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Statements of Cash Flows
(In thousands of dollars)
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 and subsidiary companies (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 costs. 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.
Basis of Consolidation
The Company is a wholly-owned subsidiary of Niagara Mohawk Holdings, Inc. (Holdings), which is wholly-owned by National Grid USA (National Grid). National Grid is a wholly owned subsidiary of National Grid plc (formerly known as National Grid Transco plc). National Grid acquired and merged with Holdings in January 2002.
The accompanying Consolidated Financial Statements reflect the results of operations, comprehensive income, retained earnings, financial position and cash flows of the Company and its subsidiaries. Inter-company balances and transactions have been eliminated.
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. The Company recorded a $28 million adjustment to goodwill related to an immaterial correction of an error in a pre-merger tax contingency in fiscal year 2007.
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. AFUDC is capitalized in “Utility plant” with offsetting cash credits to “Other interest” and non-cash credits to “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, 2007 and 2006 were 5.23% and 3.49%, 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 March 31, 2007 and 2006 were approximately $152 million and $133 million, respectively.
The Company recognizes changes in accrued unbilled electric revenues in its results of operations. Pursuant to the Company’s 2000 multi-year gas settlement changes in accrued unbilled gas revenues are deferred. At March 31, 2007 and 2006, approximately $18 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 have remained in effect under the Merger Rate Plan (MRP) which became effective upon the closing of the merger on January 31, 2002.
The PSC approved a multi-year gas rate settlement agreement (as amended through the Company’s MRP and ended in December 2004 with the Company having the right to request a change in rates at any time, if needed) 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 has continued under the MRP. 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.” Income taxes have been computed utilizing the asset and liability approach that requires the recognition of deferred tax assets and liabilities for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. Deferred investment tax credits are amortized over the useful life of the underlying property.
Service Company Charges: National Grid USA Service Company, Inc., an affiliated service company, has furnished services to the Company at the cost of such services since the merger with National Grid. These costs including operating costs and capital expenditures approximated $149 million and $160 million for the years ended March 31, 2007 and 2006, 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 deposits. The $29 million decrease in restricted cash for the fiscal year ended March 31, 2007 was primarily due to increased equity in hedge accounts related to the change in underlying commodity prices.
Derivatives: The Company accounts for derivative financial instruments under SFAS No. 133, “Accounting for Derivatives and Hedging Activities,” and SFAS No. 149, “Amendment of SFAS No. 133 on Derivative Instruments and Hedging Activities,” as amended. Under the provisions of SFAS No. 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 as the Company has received approval from the PSC to establish a regulatory asset or liability for derivative instruments that did not qualify for hedge accounting and were the result of regulatory rulings. 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.
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 changes in additional minimum pension liability, the adoption of SFAS No. 158, 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 - Changes in Equity Accounts.
Power Purchase Agreements: The Company accounts for its power purchase agreements, which are not deemed to be derivatives or leases, 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 May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3.” Previously, APB No. 20, “Accounting Changes,” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements,” defined the requirements for the accounting for and the reporting of a change in accounting principle. SFAS No. 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. When it is impracticable to determine the period-specific effects of an accounting change on one or more individual prior periods presented, SFAS No. 154 requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings for that period rather than being reported in an income statement. SFAS No. 154 became effective for fiscal years ending after December 15, 2005. The Company adopted SFAS No. 154 as of its March 31, 2006 fiscal year with no impact.
In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” SFAS No. 123R addresses the accounting for transactions in which a company receives employee services in exchange for (a) equity instruments of the company or (b) liabilities that are based on the fair value of the company’s equity instruments or that may be settled by the issuance of such equity instruments. SFAS No. 123R also eliminates the ability to account for share-based compensation transactions using Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and requires that such transactions be accounted for using a fair-value-based method. SFAS No. 123R was originally effective for public companies for interim and annual periods beginning after June 15, 2005; however, in April 2005 the Securities and Exchange Commission (SEC) delayed the effective date of SFAS No. 123R to annual, rather than interim, periods that begin after June 15, 2005. The adoption of SFAS No. 123R on April 1, 2006 did not have a material impact on the Company’s results of operations or its financial position.
In July 2006, the FASB issued Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109.” FIN 48 clarifies the accounting and reporting for uncertainties in income tax law. FIN 48 prescribes a comprehensive model for the financial statement recognition, measurement, presentation and disclosure of uncertain tax positions taken or expected to be taken in income tax returns. The cumulative effect of applying the provision of this interpretation are required to be reported separately as an adjustment to the opening balance of retained earnings in the year of adoption. FIN 48 is effective for fiscal years beginning after December 15, 2006 and will be effective for the Company in the first quarter of its 2008 fiscal year. The Company is currently evaluating the impact the adoption of FIN 48 will have on its financial statements and is not yet in a position to determine such effects.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which provides enhanced guidance for using fair value measurements in financial reporting. While the standard does not expand the use of fair value in any new circumstance, it has applicability to several current accounting standards that require or permit entities to measure assets and liabilities at fair value. This standard
defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. The Company is currently evaluating SFAS No. 157 and at this time cannot determine the full impact that the potential requirements may have on its financial statements.
In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” This standard amends SFAS Nos. 87, 88, 106 and 132(R). SFAS No. 158 requires an employer with a defined benefit pension plan or other postretirement plan to recognize an asset or liability on its balance sheet for the overfunded or underfunded status of the plan as defined by SFAS No. 158. The Company adopted SFAS No. 158 on March 31, 2007. The pension asset or liability is the difference between the fair value of the pension plan’s assets and the projected benefit obligation as of the year end. For post-retirement benefit plans other than pensions (PBOPs), the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation as of year end. At March 31, 2007, the Company recorded a combined liability of $443 million in connection with the adoption of SFAS No. 158. The Company has specific recovery of pension and PBOP expense and has recognized an offsetting regulatory asset in lieu of recording a charge to Accumulated other comprehensive income (AOCI) for the adjustment relating to its qualified pension plan and its PBOPs. For the non-qualified pension plan, the adoption of SFAS No. 158 resulted in a net change to AOCI of $1.3 million.
In September 2006, the SEC issued Staff Accounting Bulletin (SAB) No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements.” SAB No. 108 requires companies to quantify the impact of correcting misstatements using both an income statement (rollover) approach and a balance sheet (iron curtain) approach. If the misstatement of prior year expense is material to the current year, after all of the relevant quantitative and qualitative factors are considered, the prior year financial statements should be corrected. Correcting prior year financial statements for immaterial errors would not require previously filed reports to be amended.
Reclassifications: Certain amounts from prior fiscal years have been reclassified on the accompanying consolidated financial statements to conform to the fiscal 2007 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. The Company applies the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” In accordance with SFAS No. 71, the Company records regulatory assets (expenses deferred for future recovery from customers) and regulatory liabilities (revenues collected for future payment of expenses or for return to customers) on the balance sheet. The Company’s regulatory assets were approximately $4.4 billion and $4.7 billion as of March 31, 2007 and 2006, respectively. These regulatory assets are probable of recovery under the Company’s Merger Rate Plan (MRP) and Gas Multi-Year Rate and Restructuring Agreement. The Company is earning a return on most of its regulatory assets under its MRP. The Company believes that the prices it will charge for electric service in the future, including the Competitive Transition Charges (CTCs), will be sufficient to recover and earn a return on the MRP’s stranded regulatory assets over their planned amortization periods, assuming no unforeseen reduction in load or bypass of the CTC charges. The Company’s ongoing electric business continues to be rate-regulated on a cost-of-service basis under the MRP and, accordingly, the Company continues to apply SFAS No. 71 to it. In addition, the Company’s Independent Power Producer (IPP) contracts, and the Purchase Power Agreements entered into when the Company exited the power generation business, 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 SFAS No. 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 SFAS No. 71, the resulting charge would be material to the Company’s reported financial condition and results of operations.
Deferral Audit: Under its MRP, the Company is authorized to recover actual amounts deferred under the plan for each two-year period, as well as deferrals projected to accrue over the subsequent two-year period that are in excess of a $100 million threshold. The deferrals are subject to regulatory review and approval. On July 29, 2005, the Company made its biannual deferral account recovery filing for balances in the deferral account as of June 30, 2005 plus projected deferrals. On December 27, 2005, the PSC approved recovery of deferral account amounts of $100 million in calendar year 2006 and $200 million in calendar year 2007, and established a timeline for the Department of Public Service Staff (Staff) to perform its audit of the deferral account. For 2006, the deferral surcharge was included in rates beginning in April and the $100 million was collected over the last nine months of the 2006 calendar year. The Staff filed testimony on August 2, 2006, proposing in excess of $200 million of initial adjustments to the deferral balance and projected deferrals. After replies from the Staff and the Company, an evidentiary hearing was held on October 5, 2006. Upon the conclusion of the evidentiary hearings, the Company and the Staff agreed to enter into non-binding mediation discussions before an administrative law judge from the PSC in an attempt to resolve some or all of the amounts remaining in dispute.
Through the mediation process, the Company, the Staff, and Multiple Intervenors (Parties), reached a resolution of the disputed issues presented in the deferral account case as well as other cases pending before the Commission regarding pension costs, the costs of enhanced inspections of the transmission and distribution system, and the sale of the Nine Mile Point nuclear generating facilities. A Stipulation of the Parties (Stipulation) setting forth the resolution of these issues was executed and filed with the Commission on March 23, 2007. A hearing on the Stipulation was held before the PSC’s administrative law judge on May 17, 2007.
Under the Stipulation, the Company has agreed to a net reduction of the deferral account balance of approximately $127 million. This includes reclassifications from the deferral account to other balance sheet accounts of approximately $64 million. It also includes a reduction to the deferral account balance as of February 28, 2007 and decrease to earnings before income taxes of approximately $63 million. These adjustments include impacts to related gas deferral balances. The significant issues resolved under the Stipulation include:
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The Company will cease seeking to recover most disputed station service lost revenues. This resulted in a reduction to the deferral account and pre-tax earnings as of February 28, 2007 of $68 million. The impact of the settlement on future revenues depends on the usage by generators and prospective adjustments to delivery rates that are dependent in part on commodity prices. We currently estimate a reduction in revenues of about $9 million to $12 million per year through December 31, 2011 which is the end of the MRP.
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The Parties agreed to the method of determining incremental major storm costs related primarily to the treatment of third party contractor costs and costs incurred by affiliates during storm restoration efforts. The definition of a major storm was also clarified under the Stipulation. Storm related adjustments resulted in a reduction of $10 million to the deferral account and pre-tax earnings.
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The Parties agreed to the method of determining deferrable incremental costs associated with the Company’s ongoing stray voltage inspection and testing program resulting in a reduction to the deferral account and pre-tax earnings of $4 million.
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The Parties agreed to the method for capitalizing fringe benefit overhead costs associated with the Company’s fixed asset construction activities. This resulted in a decrease to utility plant of $17
Certain deferral account balances as of June 30, 2005 remain subject to audit by the Staff. The Stipulation also clarifies going forward procedures for recording, reporting and auditing of certain other deferrals authorized for recovery. The next biannual deferral account filing will be made by August 1, 2007 for deferral balances as of June 30, 2007 and projected deferrals through December 31, 2009. The Staff will audit future biannual deferral account filings made pursuant to the MRP, however the Parties have agreed that the amount of deferral recoveries in calendar year 2008 and 2009 will not exceed the $200 million level currently being collected in rates. Any deferrals in excess of this recovery level would be subject to recovery after 2009.
Significant components of regulatory assets are as follows:
Merger Rate Plan Stranded Costs: Under the MRP, 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 February 1, 2002, the MRP 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 basis and the tax basis 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 hazardous waste sites with which it may be associated. The Company’s rate plans provide 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. This regulatory asset includes the deferral of the fair value adjustments to the pension and PBOPs as of January 30, 2002 acquisition of the Company by National Grid. This deferral totaled $440 million at acquisition and is being amortized on a straight-line basis over the 10 years of the MRP. This amortization is included in the pension and PBOP deferral calculation as part of the costs that are compared to the recovery of such costs in rates.
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 ratably as interest expense over the lives of the related issues in accordance with PSC directives.
Service Quality Penalties: In connection with its MRP, the Company is subject to maintaining certain service quality standards. Service quality measures focus on eleven categories including safety targets
related to gas operations, electric reliability measures related to outages, residential and business customer satisfaction, meter reads, customer call response times, and administration of the Low-Income Customer Assistance Program. If a prescribed standard is not satisfied, the Company may incur a penalty, with the penalty amount applied as a credit or refund to customers.
Service quality performance is measured on a calendar year basis, thus the entire calendar year is taken into account when determining whether a penalty has been incurred that would be credited or refunded to customers. Target service levels for the customer service measures and the electric reliability measures are based on performance under all operating conditions. However, exclusions do apply for major storms or abnormal operating conditions such as periods of catastrophe, natural disaster, strike or other unusual events not in the Company’s control. Based upon its calendar year measurements, the Company has recorded service quality penalty expenses of $11 million and $9 million for the fiscal years ended March 31, 2007 and 2006, respectively. The MRP includes provisions that allow penalties to be doubled under certain circumstances when penalties have been incurred in prior years. These circumstances are met for the penalties associated with the frequency of outages on the system. In these circumstances, the $4.4 million penalty for exceeding the standard for outage frequency is doubled to $8.8 million in the current year and prospectively unless the Company demonstrates to the Commission that it has taken appropriate action to improve service quality under the affected standard.
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 D, H and L for a discussion of regulatory asset accounts - Deferred environmental restoration costs, Pensions and post-retirement benefits plans and Derivatives, respectively.
NOTE C - CHANGES IN EQUITY ACCOUNTS
The following table details the components of accumulated other comprehensive income (loss) for the fiscal years ended March 31, 2007 and 2006:
The deferred tax benefit (expense) on other comprehensive income for the following periods was:
In addition to the change in AOCI, the Company recorded a $16 million decrease to additional paid in capital under its intercompany tax sharing arrangement.
NOTE D - COMMITMENTS AND CONTINGENCIES
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, 2007, are summarized in the table below. 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.
If the Company needs any additional energy to meet its load, it can purchase the electricity from other IPPs, utilities, energy merchants or through the NYISO at market prices. Substantially all of these contracts require power to be delivered before the Company is obligated to make payment.
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, 2007 for each of 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 to the minimum take provisions. Commodity prices are based on New York Mercantile Exchange quotes and reservation charges, when applicable. Storage and pipeline capacity commitment amounts are based upon volumes specified in the contracts and represent demand charges priced in currently filed tariffs. At March 31, 2007, the Company’s firm gas supply commitments have varying expiration dates, the latest of which is March 2008. The gas storage and transportation commitments have varying expiration dates with the latest being October 2012.
Environmental Contingencies: The normal ongoing operations and historic activities of the Company are subject to various federal, state and local environmental laws and regulations. Like many other industrial companies, the Company’s transmission and distribution businesses use or generate some
hazardous and potentially hazardous wastes and by-products. Under federal and state Superfund laws, potential liability for the historic contamination of property may be imposed on responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred.
The U.S. Environmental Protection Agency (EPA), New York Department of Environmental Conservation (DEC), as well as private entities have alleged that the Company is a potentially responsible party under state or federal law for the remediation of an aggregate of approximately 85 sites, including 47 which are Company-owned. The Company’s most significant liabilities relate to former manufactured gas plant (MGP) facilities formerly owned or operated by the Company’s previous owners. The Company is currently investigating and remediating, as necessary, those MGP sites and certain other properties under agreements with the EPA and DEC.
The Company believes that obligations imposed on the Company because of the environmental laws will not have a material result on operations or its financial condition. The Company’s MRP provides for the continued application of deferral accounting for variations in spending from amounts provided in rates related to these environmental obligations. As a result, the Company has recorded a regulatory asset representing the investigation, remediation and monitoring obligations it expects to recover from ratepayers.
The Company is pursuing claims against other potentially responsible parties to recover investigation and remediation costs it believes are the obligations of those parties. The Company cannot predict the success of such claims, however. As of March 31, 2007 and 2006, the Company had accrued liabilities related to its environmental obligations of $397 million and $400 million, respectively. The decrease in the accrued liabilities was primarily the result of the closure of some sites as well as normal spending on the sites. The high end of the range of potential liabilities at March 31, 2007 is estimated at $517 million.
Nuclear Contingencies: As of March 31, 2007 and 2006, the Company has a liability of $158 million and $151 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 Energy Group Inc., which 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:
Station Service Cases: A number of generators complained or withheld payments associated with the Company’s delivery of station service to their generation facilities, arguing that they were permitted to bypass its retail charges. The FERC issued two orders on complaints filed by the Company’s station service customers in December 2003, allowing two generators to net their station service electricity over a 30-day period and to avoid state-authorized charges for deliveries made over distribution facilities. Subsequent to December 2003, FERC issued a third order that involved affiliates of NRG Energy, Inc. These orders directly conflict with the Company’s state-approved tariffs and the orders of the PSC on station service rates. The effect of these orders is to permit these generators to bypass the Company’s state-jurisdictional station service charges for electricity, including those set forth in the filing that was approved by the PSC on November 25, 2003. Under those state-approved tariffs, the Company was owed in aggregate approximately $62 million as of December 31, 2006. The Company appealed the FERC orders to the U.S. Court of Appeals for the District of Columbia Circuit, and the matters were
consolidated for appeal. On June 23, 2006, the Court issued a decision upholding the FERC’s orders, and on October 23, 2006, the Court denied the Company’s request for rehearing. On January 22, 2007, the Company filed a joint petition for certiorari to the United States Supreme Court requesting the Court to review and reverse the decision of the Court of Appeals. On April 30, 2007, the Supreme Court denied certiorari and thus the FERC orders have become final.
Under those orders, FERC allows generators to bypass local distribution company charges (including stranded cost recovery charges) when receiving service through the New York Independent System Operator if the amount of power produced by a generator over a 30-day period exceeds the amount of power taken over the power grid. As discussed under the deferral audit section of Note B, the Company is not recovering the lost revenues associated with the FERC orders through its deferral account and recorded a charge to expense of $68 million in the fourth quarter related to this matter.
Acquisitions
In 2006, National Grid plc, the ultimate parent of the Company, announced the proposed acquisition of KeySpan Corporation (KeySpan) for $7.3 billion together with the assumption of approximately $4.5 billion of debt. This would significantly expand its operations in the northeastern US as KeySpan is the fifth largest distributor of natural gas in the US and the largest in the northeast US, serving 2.6 million customers in New York, Massachusetts and New Hampshire. KeySpan also operates an electricity transmission and distribution network serving 1.1 million customers in New York under a long-term contract with the Long Island Power Authority. KeySpan’s other interests include 6.6 GW of generation capacity, together with a small portfolio of non-regulated, energy-related services, and strategic investments in certain gas pipeline, storage and liquefied natural gas assets. The planned combination of its current US operations with those of KeySpan would result in National Grid plc becoming the third largest energy utility in the US.
National Grid plc has made significant progress towards completion and has achieved several important milestones. National Grid plc has obtained clearances from the Federal Trade Commission in respect of the Hart-Scott-Rodino Antitrust Improvements Act, from the Committee on Foreign Investment in the US and by the Federal Energy Regulatory Commission, and received approval from both National Grid plc and KeySpan shareholders. In March 2007, National Grid plc and KeySpan announced an agreement with the staff of the Long Island Power Authority in principle regarding amended contracts, which is subject to approval by the Authority and by the Comptroller and Attorney General of New York. In April 2007, the staff of the New Hampshire Public Utilities Commission announced that they would recommend approval. National Grid plc has also made filings with the New York Public Service Commission and has held extensive discussions with regulatory staff and other interested parties that have yielded significant progress toward resolution of issues important to the completion of the acquisition. National Grid plc anticipates achieving a final result that will benefit investors and consumers alike by this autumn.
NOTE E - LONG-TERM DEBT
Long-term debt consisted of the following at March 31, 2007 and 2006:
Substantially all of the Company’s operating properties are subject to mortgage liens securing its mortgage debt. Several series of First Mortgage Bonds 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 $575 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 averaged 3.41% for the year ended March 31, 2007, 3.20% for the year ended March 31, 2006 and 1.69% for the year ended March 31, 2005. The bonds are currently in the auction rate mode and are backed by bond insurance. 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.
The aggregate maturities of long-term debt for the five years subsequent to March 31, 2007, 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 $0.6 million at March 31, 2007 and 2006. The non-current portion of capital lease obligations is reflected in the “Other” line item on the Consolidated Balance Sheet and was approximately $3.4 million and $4 million at March 31, 2007 and 2006, respectively.
At March 31, 2007 and 2006, the Company’s long-term debt, excluding intercompany debt, had a fair value of approximately $1.5 billion and $1.8 billion, respectively. 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.
NOTE F - SHORT-TERM DEBT
The Company has regulatory approval from the FERC to issue up to $1 billion of short-term debt. The Company had short-term debt outstanding of $395 million and $579 million at March 31, 2007 and 2006, respectively, from affiliated companies. The Company participates with National Grid, and certain other National Grid affiliates, in a system money pool. The money pool is administered by the National Grid USA Service Company as the agent for the participants. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowings from the money pool bear interest at the higher of (i) the monthly average of the rate for high-grade, 30-day commercial paper sold through dealers by major corporations as published in The Wall Street Journal, or (ii) the monthly average of the rate then available to money pool depositors from an eligible investment in readily marketable money market funds or the existing short-term investment accounts maintained by money pool depositors or the National Grid USA Service Company during the period in question. In the event neither rate is one that is permissible for a transaction because of constraints imposed by the state regulatory commission having jurisdiction over a utility participating in the transaction, the rate is that which is permissible for the transaction as determined under the requirements of the state regulatory commission. Companies that invest in the money 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 money pool at any time without prior notice. The average interest rate for the money pool was 5.23%, 4.03% and 1.80% for fiscal years 2007, 2006 and 2005, respectively.
The Company had no short-term debt outstanding to third-parties at March 31, 2007 or 2006.
NOTE G - INCOME TAXES
The Company has joint and several liability for any potential assessments against the consolidated group.
Following is a summary of the components of federal and state income tax and 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:
The following table identifies the major components of total deferred income taxes:
The Company has been audited and reported on by the Internal Revenue Service (IRS) through March 31, 2002. There were no valuation allowances for deferred tax assets at March 31, 2007 or 2006.
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.
A supplemental nonqualified, non-contributory executive retirement program provides additional defined pension benefits for certain executives.
The Company provides post-retirement benefits other than pensions (PBOPs). PBOPs include health care and life insurance coverage to eligible retired employees. Eligibility is based on certain age and length of service requirements and in some cases retirees must contribute to the cost of their coverage.
The PSC’s Statement of Policy dictates the accounting policy for the plans and requires amortization of unrecognized prior service costs and unrecognized gains and losses over a 10-year period calculated on a vintage year basis.
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 amounts that are required under the Pension Protection Act of 2006.
Plan Assets
The target asset allocations for the benefit plans are:
The percentage of the fair value of total plan assets at March 31:
The Company manages benefit plan 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 securities. Equity investments are broadly diversified across U.S. and non-U.S. stocks, as well as across growth, value, and small and large capitalization stocks. Likewise, the fixed income portfolio is broadly diversified across the various fixed income market segments. Small investments are also held in private equity, with the objective of enhancing long-term returns while improving portfolio diversification. For the PBOP plan, since the earnings on a portion of the assets are taxable, those investments are managed to maximize after tax returns consistent with the broad asset class parameters established by the asset allocation study. Investment risk and return is reviewed by the investment committee on a quarterly basis.
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 the long-term assumption. A small premium is added for active management and rebalancing of both equity and fixed income. The rates of return for each asset class are then weighted in accordance with the target asset allocation, and the resulting long-term return on asset rate is then applied to the market-related value of assets.
Assumptions Used for Benefits Accounting
The following weighted average assumptions were used to determine the pension and PBOP benefit obligations and net periodic costs for the fiscal years ended March 31:
The expected contributions by the Company to the pension and PBOP plans during fiscal year 2008 are approximately $277 million and $0, respectively.
Adoption of SFAS No. 158
The Company adopted SFAS No. 158 on March 31, 2007. This standard amends SFAS Nos. 87, 88, 106 and 132(R). SFAS No. 158 requires an employer with a defined benefit pension plan or post-retirement benefit plan other than pensions (PBOPs) to recognize an asset or liability on its balance sheet for the overfunded or underfunded status of the plan as defined by SFAS No. 158. The pension asset or liability is the difference between the fair value of the pension plan’s assets and the projected benefit obligation as of the year end. For PBOPs, the asset or liability is the difference between the fair value of the plan’s assets and the accumulated post-retirement benefit obligation as of year end. The Company has specific recovery of qualified pension and PBOP expense and has recognized a regulatory asset in lieu of taking a charge to AOCI.
The following table illustrates the effect on individual financial statement line items of applying this standard, relating to the Company’s pension and PBOP plans. The Company participates in these plans with its affiliate, National Grid USA Service Company.
The Company recorded increases in its pension and PBOP liabilities of $102 million and $342 million, respectively, with the offsetting charge to regulatory assets and AOCI.
Pension Benefits
The Company’s net periodic benefit cost for the fiscal years ended March 31, 2007, 2006 and 2005 included the following components:
The benefit obligation, assets and funded status of the pension plans cannot be presented separately for the Company as the Company participates in the plan with National Grid USA Service Company, an affiliate. The following table provides the pension plans’ accumulated benefit obligation, funded status and the amounts recognized in the National Grid USA consolidated balance sheet at March 31:
The estimated net actuarial loss and prior service cost for the defined benefit pension plans that will be amortized from regulatory assets and AOCI into net periodic benefit cost during fiscal year 2008 is estimated to be $29 million and $3 million, respectively.
The following payments, which reflect expected future services, as appropriate, are expected to be paid from the pension plans:
Additional Minimum Liability (AML)
Under SFAS No. 158, the Company recognized AML, as prescribed under SFAS No. 87, “Employers’ Accounting for Pensions,” prior to recording the entries to recognize the funded status of the pension plans. The Company recognized an AML of $74 million which was subsequently eliminated under SFAS No. 158. The Company recorded an AML of approximately $114 million at March 31, 2006. While the offset to this entry would normally be an after-tax charge to other comprehensive income, due to the nature of its rate plan, the Company recorded a pre-tax regulatory asset.
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 were expensed for each of the fiscal years ended March 31, 2007, 2006 and 2005.
Settlement Loss
The Company’s pension plan has unrecognized losses as a result of changes in the value of the projected benefit obligation and the plan assets due to experience different from that assumed and from changes in actuarial assumptions. Under SFAS No. 88 “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” the Company recognized a settlement loss of approximately $25 million during the fiscal year ended March 31, 2007 due to plan payouts that exceeded the threshold as prescribed in SFAS No. 88. The Company and the PSC staff reached agreement that permits the Company to recover approximately 50% of the incurred pension settlement loss.
Postretirement Benefit Plans Other than Pensions: The Company’s total cost of PBOPs for the fiscal years ended March 31, 2007, 2006 and 2005 included the following components:
*The Company participates in the plans with its affiliate, National Grid USA Service Company. For fiscal years ended March 31, 2006 and 2005, PBOP costs have been adjusted to exclude the expense of this affiliate.
The benefit obligation, assets and funded status of the PBOP plan cannot be presented separately for the Company as the Company participates in the plan with its affiliate, National Grid USA Service Company. The following table provides the PBOP plans’ funded status and the amounts recognized in the National Grid USA consolidated balance sheet at March 31:
The estimated net actuarial loss and prior service cost for the PBOP plans that will be amortized from regulatory assets and AOCI into net periodic benefit cost during fiscal year 2008 is estimated to be $34 million and $15 million, respectively. A portion of this amount will be recorded as expense of National Grid USA Service Company.
As a result of the Medicare Act of 2003, the Company receives a federal subsidy for sponsoring a retiree healthcare plan that provides a benefit that is actuarially equivalent to Medicare Part D.
The following PBOP benefit payments expected to be paid out by the Company and subsidies expected to be received from the U.S. Federal Government, which reflect expected future services, as appropriate, are:
A one-percentage point change in assumed health care cost trend rates would have the following effects:
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.
NOTE J - SEGMENTS
Segmental information is presented in accordance with management responsibilities and the economic characteristics of the Company’s business activities. The Company is primarily engaged in the business of the purchase, transmission and distribution of electricity and the purchase, distribution, sale and transportation of natural gas in New York State. The Company’s reportable segments are electricity-transmission, electricity-distribution, and gas-distribution. Certain information regarding the Company’s segments is set forth in the following tables. Corporate assets consist primarily of other property and investments, cash, restricted cash, current deferred income taxes and unamortized debt expense. 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.
NOTE K - STOCK BASED COMPENSATION
Prior to the Company’s merger with National Grid, stock appreciation rights (SARs) tied to the price of Holdings’ share price were granted to officers, key employees and directors. The table below sets forth the activity under the SARs program for the periods March 31, 2005 through March 31, 2007. Since SARs are payable in cash, the accounting under APB No. 25 and SFAS No. 123R is the same.
The Company’s SARs program 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, the acquisition of Holdings’ by National Grid was completed and outstanding Holdings’ SARs were converted to National Grid Group plc 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 the ADS price of National Grid Group plc over the vesting period of the award.
Included in the Company’s results of operations for years ended March 31, 2007 and 2006, is approximately $1 million of expense for each year related to the SARs program.
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 No. 133, “Accounting for Derivative Instruments and Hedging Activities,” 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 electricity 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 electricity or gas expense 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 fiscal year 2009 (June 2008), which resulted from the MRA. 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, 2007 and 2006, the Company had recorded liabilities at net present value of $268 million and $537 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 they are adjusted as periodic reassessments are made of energy price forecasts.
At March 31, 2007, the Company projects that it will make the following payments in connection with its swap contracts for the fiscal years 2008 and 2009, 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 No. 133. Cash flow hedges that qualify under SFAS No. 133 are as follows: NYMEX gas futures for the purchases of natural gas and NYMEX electric swap contracts hedging the purchases of electricity.
The following table represents the open positions and the results on operations of these instruments for the year ended March 31, 2006 and 2007.
*
Differences between asset and regulatory or other comprehensive income deferral represent contracts settled for the following month.
**
Other Comprehensive Income (OCI)
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, 2007, the realized net loss of $37 million from hedging instruments, as shown in the table above, was recorded to gas purchases and was offset by a corresponding increase in the cost of a comparable amount of gas. For the twelve months ended March 31, 2006, a realized net gain of $36 million was recorded to gas purchases and was offset by a corresponding decrease 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 2008. There were no gains or losses recorded during the fiscal year ended March 31, 2007 from the discontinuance of gas futures or electric swap cash flow hedges.
The deferred gain on NYMEX electric swap contracts to hedge electricity purchases was $0.8 million and $0.3 million for the fiscal years ended March 31, 2007 and 2006, respectively.
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% 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 MRP and under FERC and SEC orders with respect to the amount of dividends it can make to Holdings. As long as the Company remains rated Investment Grade, it 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 MRP and other regulatory orders.
NOTE N - COST OF REMOVAL AND ASSET RETIREMENT OBLIGATION
In 2001, FASB issued SFAS No. 143. SFAS No. 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets. The Company was required to adopt SFAS No. 143 and FIN 47 as of April 1, 2003. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 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. In March 2005, the FASB issued FIN 47 that clarifies that the term “conditional asset retirement obligation” used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the Company. This statement is effective for the Company for its fiscal year ended March 31, 2006. The Company has an $11 million asset retirement obligation reserve as of March 31, 2007.
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 SFAS No. 143 and FIN 47 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. it is 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 been charged over time through depreciation expense). With the adoption of SFAS No. 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 $350 million and $338 million for cost of removal through March 31, 2007 and 2006, respectively.
NOTE O - QUARTERLY FINANCIAL DATA (UNAUDITED)
Operating revenues, operating income, and net income by quarter from April 1, 2005 through March 31, 2007 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. The Company’s consolidated financial statements for the fiscal year ended March 31, 2006 included out-of-period adjustments. The out-of-period adjustments had a positive impact of $7 million on reported net income for the fiscal year ended March 31, 2006 and an offsetting negative impact on several prior fiscal years. These adjustments were recorded in fiscal year 2006 because they did not meet the materiality threshold for prior period restatement.
In the third fiscal quarter of 2007, the Company recorded a pension settlement loss of $25 million (See Note H-Employee Benefits) and in the fourth quarter, deferral account audit write off of $63 million (See Note B-Rate and Regulatory Issues).
NOTE P - SUBSEQUENT EVENT
On April 26, 2007, the Board of Directors declared a cash dividend of $0.4 million payable to stockholders on June 30, 2007.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
There is no disagreement or reportable event required to be reported under this Item 9.
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. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can provide only reasonable assurance of achieving their control objectives. 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, as amended, is recorded, processed, summarized and reported as and when required and accumulated and communicated to the Company’s management, including the Chief Financial Officer and President, as appropriate, to allow timely decisions regarding disclosure.
During the most recent fiscal quarter, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The following table lists the Company’s executive officers and directors:
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. 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 or she was selected as an officer.
Mr. Edwards was elected President of the Company and appointed a director effective January 31, 2002. He also serves as an Executive Vice President of National Grid USA Service Company and is a director of the National Grid USA Service Company and of National Grid USA.
Mr. Ash was appointed Vice President, Regulatory Proceedings in April 2006, Prior to that he served as Vice President, Energy Supply, Pricing and Regulatory Proceedings from July 2003 to April 2006. He was Vice President, Gas Delivery, from December 1998 to July 2003.
Mr. Bailey was elected Controller of the Company effective January 2006. He also serves as Controller of National Grid USA Service Company, Inc. Mr. Bailey was Vice President of Finance and Administration of Harvard Bioscience, Inc. from October 2003 until September 2005, when he joined National Grid. From 1998 to 2002, Mr. Bailey worked for Thermo Electron Corporation as the Controller of its analytical instruments business, formerly known as Thermo Instrument Systems, Inc.
Mr. Buck was elected Senior Vice President and Chief Financial Officer of the Company effective January 2007 and also effective as of January 2007 became the Senior Vice President and Chief Financial Officer of National Grid, USA He also, effective January 2007 was elected Senior Vice President of the Company’s four New England electric distribution affiliates and Vice President and Chief Financial Officer of the Company’s transmission affiliate, New England Power Corporation.
Ms. Crossett has served as Vice President of the Company since July 2002. She was elected director of the Company, effective May 15, 2007.
Ms. Hassan was elected Senior Vice President and a director in April 2006. Since May 2000, she has served as Senior Vice President of the Company’s New England electricity distribution affiliates.
Ms. LaFleur was elected director of the Company in April 2006. She also became Executive Vice President and Chief Operating Officer of National Grid USA in April 2006, having been a Senior Vice President since March 2000. She serves as a director of National Grid USA and the Company’s four New England electric distribution affiliates and was President of the four distribution affiliates from January 2001 until April 2006. Ms. LaFleur was appointed President and acting Chief Executive Officer effective April 23, 2007.
Mr. Pini has served as a director and was elected Senior Vice President of the Company since January 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. Reilly has been Secretary and General Counsel of National Grid USA since January 2001 and is a Director, Executive Vice President and General Counsel of National Grid USA.
Ms. Saidi is Vice President of the Company and was elected director and Senior Vice President of National Grid USA in April 2007. She also serves as Senior Vice President of National Grid USA Service Company with responsibility for National Grid’s US transmission operations. From 1998 to 2004, Ms. Saidi was a Vice President of the Company’s transmission affiliate, New England Power Company, and from 2004 to 2005 she served as Senior Vice President and Chief Operating Officer of GridAmerica.
Mr. Tasker has served as Senior Vice President, Distribution Finance, and Treasurer of the Company since January 2002. He was Vice President and Controller from December 1998 to January 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 % 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, 2007.
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 plc website, at www.nationalgrid.com, where any amendments or waivers will also be posted. There were no amendments to, or waivers under, the Company’s Code of Ethics in the fiscal year ended March 31, 2007.
The inclusion of National Grid plc’s website address in this annual report does not, and is not intended to, incorporate the contents of its website into this report and such information does not constitute part of this annual report.
Corporate Governance
Because the Company only has preferred stock listed on the New York Stock Exchange (‘NYSE”), the NYSE’s corporate governance rules, which relate to matters such as the independence of directors and the establishment of independent board committees, do not apply to us. The rules of the SEC that apply to audit committees, however, can apply even when only preferred stock is listed, unless there is an applicable exemption. Under the SEC’s rules on audit committees, because our parent company National Grid, plc has common shares listed on the NYSE we are exempt from the requirement to maintain an independent audit committee. As a result, we do not have an audit committee, a compensation committee or a nominating committee. In addition, we do not have any procedure by which security holders can nominate directors because the holders of our preferred stock do not have the right to vote in the election of directors.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
COMPENSATION DISCUSSION AND ANALYSIS
Objectives of Executive Compensation Programs
The executive compensation programs applicable to the named executives are derived from a number of different sources, given the global reach of the National Grid companies. For 2006/07, one of the named officers (Mr. Jesanis) was an Executive Director of National Grid plc. The compensation policies and programs that apply to an Executive Director are reviewed and approved by the Remuneration Committee of the Board of Directors for National Grid plc (the “Remuneration Committee”). The compensation policies and programs that apply to the direct reports of an Executive Director (which for 2006/07 include Mr. Edwards, Mr. Cochrane, Mr. Buck and Ms. LaFleur) as well as those of the remaining named executives (Mr. Kelleher, Mr. Ash and Mr. Tasker), primarily stem from the Remuneration Committee reviewed and approved programs and policies, although their annual salary levels and the specifics of their annual bonus criteria are established through a process that ends with a review at the Executive Director level.
While the Remuneration Committee generally reviews and approves the compensation programs for executives, including the named executives, typical of other multi-national companies, components of compensation packages, and entire benefits packages, are based upon local (meaning by country) practices, in order to ensure competitive compensation/benefit packages are offered as necessary to attract and retain executives in the local market, and to take into account tax incentives and/or other applicable rules and regulations that may be unique to the particular country. Consequently, as will become evident in this disclosure, named executives who have roots in the U.S. based operations (Mr. Jesanis, Mr. Edwards, Mr. Cochrane, Ms. LaFleur, Mr. Kelleher, Mr. Ash and Mr. Tasker) participate in certain compensation (and all benefit) programs that are U.S. based, and Mr. Buck, who recently moved from the U.K. to join the U.S. operations, participates in certain particular U.K. unique compensation and benefit programs.
Also noteworthy is the fact that the National Grid plc companies are transitioning from operating predominantly on a local (by country) basis to an international lines of business operating model. This is significant in the area of executive compensation and benefits because this will result in a greater integration of U.K. and U.S. executive teams, increased centralization of compensation
and benefits decision-making, as well as more commonality in compensation and benefit programs.
The National Grid plc Board of Directors Remuneration Committee members are John Allan, Ken Harvey, Stephen Pettit and George Rose. Each is a Non-executive Director of National Grid plc, is regarded as independent, and has served throughout the reporting year. The Group Human Resources Director and Group Head of Compensation and Benefits provide the Remuneration Committee with advice on compensation policies and practices and are usually invited to attend meetings, along with the Chairman and the Chief Executive of National Grid plc. No Director or other attendee is present during any discussion regarding his or her own compensation. The Remuneration Committee is responsible for developing and/or monitoring National Grid policy regarding total compensation of the executive group.
In addition to conferring with the Group Human Resources Director and Group Head of Compensation and Benefits during fiscal year 2006/07, the Remuneration Committee retained and conferred with Mercer Human Resources Consulting Limited and Deloitte & Touche LLP, independent human resources and compensation advisors, respectively, on executive compensation and benefit matters. The process used in setting total compensation for the named executives is explained in more detail below.
Executive compensation programs are designed with the aim of attracting, motivating and retaining high caliber executives to deliver value for National Grid plc shareholders and high levels of customer service, safety and reliability in an efficient and responsible manner. Executive compensation policies and practices take into consideration the elements of compensation and benefits that are typically offered in the local (country) markets in which the National Grid companies operate. Executive compensation policy is framed around the following key principles:
•
total rewards should be set at levels that are competitive in the relevant market;
•
a significant proportion of executive’s total reward should be performance based. Performance based incentives should be earned through the achievement of demanding targets for short-term business and personal performance, and long-term National Grid plc shareholder value creation, consistent with the Framework for Responsible Business which can be found at www.nationalgrid.com/responsibility/managementandgovernance;
•
rewards for higher levels of performance should be substantial but not excessive;
•
incentive plans, performance measures and targets should be structured to operate soundly throughout the business cycle, and should be aligned as closely as possible with National Grid plc shareholders’ interests; and
•
base salary should be competitive based upon the relevant market and scope of responsibilities.
Compensation Program
The named executives perform services for both the Company and affiliated National Grid companies (including parent companies). This compensation discussion and analysis does not reflect allocations based upon time spent performing services for the various National Grid companies.
The executive compensation program reflects the compensation philosophy and principles as set forth above. To achieve those objectives, direct compensation includes three basic components: base salary, annual incentive compensation (including the Executive Director’s Deferred Share Plan, applicable to Mr. Jesanis, the U.K. Annual Bonus Plan, applicable to Mr. Buck, and the Incentive Compensation Plan, applicable to Mr. Edwards, Mr. Cochrane, Ms. LaFleur, Mr. Kelleher, Mr. Ash and Mr. Tasker), and long-term incentive compensation (the Performance Share Plan, applicable to all named executives).
The mix between salary and incentive pay is weighted more heavily toward incentive pay at the top executive levels to ensure that those with the greatest potential impact on National Grid performance have the largest stake in its success. In addition, the proportion of total compensation that is linked to National Grid plc share performance is greatest at the top executive levels. The annual bonus programs include a significant National Grid share element in order to increase the proportion of rewards linked to both short-term performance and longer-term total shareholder returns. This practice also ensures that the executives’ total compensation shares a significant level of personal risk with National Grid plc shareholders. The compensation mix in place for 2006/07 was first established following a review in 2005, where the Remuneration Committee, in consultation with its outside compensation expert at the time (Ernst & Young LLP), undertook a complete review of the mix between fixed and variable compensation, and the operation of annual and long term incentive pay. That review resulted in a number of adjustments from prior practice, including an increase in the amount of incentive pay that would be tied to National Grid shares (ordinary shares or ADSs, as applicable) through both the annual and long term incentive plans.
For fiscal year 2006/07, Mr. Jesanis, as an Executive Director, could achieve a maximum annual bonus equal to 100% of annual salary, one-half delivered in deferred National Grid plc American Depositary Shares (ADSs), plus a maximum award grant (in ADSs) equal to 125% of annual salary under the long term incentive plan. Mr. Edwards, Mr. Cochrane and Ms. LaFleur, as direct reports to an Executive Director, could achieve a maximum annual bonus equal to 67.5% of annual salary, one-third delivered in ADSs, plus a maximum award grant (in ADSs) equal to 60% of annual salary under the long term incentive plan. Mr. Buck could achieve a maximum annual bonus equal to 50% of annual salary, 40% delivered in deferred in National Grid plc ordinary shares, plus a maximum award grant in National Grid plc ordinary shares equal to 60% of annual salary under the long term incentive plan. Mr. Kelleher and Mr. Tasker could achieve a maximum annual bonus equal to 67.5% of annual salary (49.5% for Mr. Ash), one-third delivered in ADSs, plus a maximum award grant (in ADSs) equal to 60% (40% for Mr. Ash) of annual salary under the long term incentive plan.
Following a thorough review of the remuneration policy in light of the proposed KeySpan acquisition, which will result in a larger and more complex role for executives, the Remuneration Committee is in the process of modifying variable compensation (a portion of which is subject to National Grid plc shareholder approval). The changes would include increases in maximum potential bonus awards, including an increase in the maximum long term incentive compensation award (Performance Share Plan) to a maximum of up to 150% of base salary for Ms. LaFleur, 150% for Mr. Edwards, 80% for Mr. Buck, and 60% for Mr. Ash and Mr. Tasker. In conjunction with this change, the upper target of the Performance Share Plan will be subject to more challenging targets than historical stretch targets. It is believed that the increase in range of potential bonuses will motivate executives toward greater excellence. In addition, a new multi-national annual bonus plan has been introduced for fiscal year 2007/08 (Annual Bonus Plan 2007/08) that will apply to Mr. Edwards and Ms. LaFleur in lieu of the Incentive Compensation Plan. The Annual Bonus Plan 2007/08 will provide a maximum bonus of up to 110% of annual salary, 60% of which will be based upon financial targets and 40% of which will be based upon individual objectives. Further, two-thirds of awards will be paid in cash and one-third in ADSs that will vest after three years. The Annual Bonus Plan 2007/08 will also apply to Mr. Buck, whose maximum bonus will be 70% of annual salary under the plan. These changes were the results of a benchmarking process performed for The Remuneration Committee, taking into account advice from Deloitte & Touche, including benchmarking against comparative size companies of equivalent complexity in the energy services sector as well as the general industry performed by Towers Perrin.
Executives are provided with benefits and perquisites that are intended to be comparable to those provided to executives in applicable peer groups. These other programs include the following:
•
ability to allocate a portion of any annual base pay or bonuses into a deferred compensation plan (does not apply to Mr. Buck)
•
retirement plans
•
401(k) plan with employer match (available to all U.S. employees)
•
share purchase plans (only applies to Mr. Buck)
•
executive life insurance
•
severance and change in control termination protection
•
other reasonable and customary perquisites
In the design of compensation and benefit programs, the compensation amounts realized in prior years are generally not taken into consideration when establishing compensation targets or awards. There is also no policy that would automatically result in an adjustment to payments if the relevant performance measures upon which they are based are restated or otherwise adjusted in subsequent years in a manner that would reduce or increase the size of a previous payment. However, in an instance such as this, the Remuneration Committee would have discretion to consider an adjustment, if warranted.
Base Salary
Salaries are reviewed annually and targeted broadly at the median position in the local (country) marketplace taking into account the regulated nature of a majority of National Grid’s operating
activities along with the size, complexity and international scope of the National Grid businesses. Base salaries for executives are established based on the scope of their responsibilities, taking into account competitive market compensation levels for similar positions. This analysis is completed with references and data points supplied by Towers Perrin, who is retained by Human Resources (U.K. and U.S.). Business performance and the individual’s experience in the role are taken into account in setting individual salaries, as are the employment and salary practices prevailing for other executives with similar levels of responsibility and expertise.
Setting annual salaries for the named executives is based in part on an overall recommendation by the Remuneration Committee on salary increase parameters. Those parameters are established in consultation with an outside compensation expert (Deloitte & Touche for fiscal year 2006/07). With respect to Mr. Jesanis, Mr. Edwards, Mr. Cochrane, Mr. Buck and Ms. LaFleur, salary reviews for fiscal year 2006/07 were undertaken by their respective managers, taking into account market reference information obtained from Towers Perrin. Due to his status as an Executive Director, recommendations regarding Mr. Jesanis’s annual salary were then reviewed and approved by the Remuneration Committee in consultation with Deloitte & Touche. Relative to Mr. Edwards, Mr. Cochrane, Mr. Buck and Ms. LaFleur, the salary adjustment recommendations were ultimately reviewed and approved by the Executive Directors (acting as The Executive Committee). With respect to Mr. Kelleher, Mr. Ash and Mr. Tasker, for fiscal year 2006/07, reviews were initially performed by the U.S. Manager of Compensation, using market reference information obtained from Towers Perrin. Those recommendations were then presented to the Executive Director with responsibility for U.S. operations (Mr. Jesanis for fiscal year 2006/07), who exercised final decision-making authority.
Annual Bonus Plans
Annual bonuses for the named executives during fiscal year 2006/07 were delivered through one of three different plans, namely the Executive Director’s Deferred Share Plan (Mr. Jesanis), the U.K. Annual Bonus Plan (Mr. Buck), and the Incentive Compensation Plan (Mr. Edwards, Mr. Cochrane, Ms. LaFleur, Mr. Kelleher, Mr. Ash and Mr. Tasker). Bonus awards for fiscal year 2006/07 were based on achievement of a combination of demanding Group (meaning National Grid plc in total), individual, and, where applicable, divisional targets. The process for setting financial targets is derived from the business planning process conducted by the executive directors and the highest level financial executives at National Grid. They make recommendations to the Remuneration Committee based upon analysis of National Grid company operations, investor community expectations, and divisional contributions towards operational and financial success. Recommendations regarding annual bonus targets are then presented to the Remuneration Committee. The Remuneration Committee believes that the targets established for fiscal year 2006/07 were stretch targets but achievable in view of National Grid’s historical annual performance and its 2006/07 business plan. As noted earlier, maximum bonus opportunity levels are set to reward exceptional operational and financial performance. Over the past three years, bonus payouts for the named executives have ranged from 60% to 80% of target.
Executive Deferred Share Plan (Mr. Jesanis) - For fiscal year 2006/07, this plan included a maximum bonus potential of 100% of annual salary, with a targeted payout of 50%. Awards were based 70% on financial targets and 30% on individual targets, with half of each award delivered in National Grid plc American Depositary Shares (ADSs) that vest on the third anniversary of award. The Remuneration Committee may, at the time of release of ADSs, use its discretion to
pay a cash amount equivalent to the value of the dividends that would have accumulated on the deferred shares. The principal measures of financial performance were adjusted earnings per share (EPS) and cash flow; the main divisional measures were divisional operating profit and divisional cash flow. Individual targets, representing 30% of the bonus, were set in relation to key operating and strategic objectives and included overriding measures for safety and customer service performance. The Remuneration Committee set targets at the start of fiscal year 2006/07 and reviewed performance against those targets at fiscal year end. The Remuneration Committee may use its discretion to reduce payments to take into account any significant safety or service standard incidents, or to increase them in the event of exceptional value creation.
U.K. Annual Bonus Plan (Mr. Buck) - For fiscal year 2006/07, this plan included a maximum bonus potential of 50% of annual salary. Awards were based 60% on a financial element and 40% on individual objectives, with 60% paid in cash and 40% of each award delivered in National Grid plc ordinary shares that vest on the third anniversary of the award date. (The share component is delivered through the Executive Director’s Deferred Share Plan.) The shares are held in trust for three years before release. During this time they are not owned by the executive, and therefore no dividends are paid. The Remuneration Committee may, at the time of release of shares, use its discretion to pay a cash amount equivalent to the value of the dividends that would have accumulated on the deferred shares. The principal measures of the annual bonus plan for financial performance were group level earnings per share (EPS) and cash flow as well as business unit operating profit and cash flow, with achievement producing the following percentages of the financial performance component: 20% at threshold; 50% at target; and 100% at stretch target performance. Individual targets, representing 40% of the bonus, were set in relation to key individual projects and deliverables required during the year for that role. Targets are set at the start of each fiscal year and performance against those targets is reviewed at fiscal year end. Further, discretion is retained to reduce payments to take into account any significant safety or service standard incidents.
Incentive Compensation Plan (Mr. Edwards, Mr. Cochrane, Ms. LaFleur, Mr. Kelleher, Mr. Ash and Mr. Tasker) - For fiscal year 2006/07, the principal measure of organization financial performance was based upon U.S. operations’ contribution to EPS, with a target payout at 45% of base salary (33% for Mr. Ash), further adjusted for individual performance down to 0% for unsatisfactory individual performance and up to 150% of target (resulting in a maximum annual bonus equal to 67.5% - 49.5% for Mr. Ash) for exceptional individual performance, measured based upon pre-established goals related to operating and strategic objectives, including safety, budgets, leadership and corporate values. If the threshold level of earnings is not achieved, no bonus is payable. The level of bonus available is calibrated with earnings achievement. Two-thirds of the award is paid in cash and one-third in ADSs. Either component may be deferred under the terms of the National Grid USA Companies’ Deferred Compensation Plan.
The named executives (excluding Mr. Buck) also participated in the USA Goals program, a bonus plan covering substantially all of U.S. employees that can pay up to 5.7% of salary on the achievement of certain earnings and performance targets.
Long-Term Incentive Compensation
Since 2003, long-term incentive compensation has been delivered through the Performance Share Plan. Prior to that date, long-term incentive compensation was delivered through the Executive Share Option Plan, discussed below. (The Executive Share Option Plan is described
due to the fact that several of the named executives have either exercised rights under the plan during fiscal year 2006/07 or have outstanding rights under the plan.) The long-term incentive compensation programs have been offered to a large number of senior employees who have significant influence over National Grid plc’s ability to meet its strategic objectives. Eligible executives, including the named executives, receive awards that vest subject to the achievement of performance conditions set by the Remuneration Committee at the date of grant.
Performance Share Plan. The value of shares constituting an award (as a percentage of salary) may vary by grade and seniority subject to a maximum (125% of annual salary for Mr. Jesanis, 60% of annual salary for Mr. Edwards, Mr. Buck, Mr. Cochrane, Ms. LaFleur, Mr. Kelleher and Mr. Tasker, and 40% of annual salary for Mr. Ash.). Awards were made at maximum applicable percentages in the fiscal year 2006/07. Shares vest after three years, subject to the satisfaction of the relevant performance criteria. Vested shares must then be held for a further year (the retention period) after which they are released. During the retention period, the Remuneration Committee has discretion to pay an amount, equivalent in cash or shares, to the dividend which would have been paid on the vested shares.
Under the terms of the Performance Share Plan, the Remuneration Committee may allow shares to vest early to a departing named executive to the extent the performance condition has been met, in which event the number of shares that vest are pro-rated to reflect the proportion of the performance period that has elapsed at the executive’s date of departure.
Performance Share Plan awards made in June 2003 and June 2004 were based on National Grid plc’s Total Shareholder Return (TSR) performance over a three-year period relative to the TSR performance of the following group of comparative companies:
Ameren Corporation
Iberdrola SA
AWG plc
International Power plc
Centrica plc
Kelda Group plc
Consolidated Edison, Inc.
Pennon Group plc
Dominion Resources, Inc.
RWE AG
E.ON AG
Scottish Power plc
Electrabel SA
Scottish & Southern Energy plc
Endesa SA
Severn Trent plc
Enel SpA
The Southern Company, Inc.
Exelon Corporation
Suez SA
FirstEnergy Corporation
United Utilities plc
FPL Group, Inc.
Viridian Group plc
Gas Natural SDG SA
Following consultation with the major National Grid plc shareholders, the performance conditions for awards under the Performance Share Plan were amended beginning with the June 2005 award. The change provided that 50% of any award be based on National Grid plc’s TSR
performance when compared to the FTSE 100 (as of June 27 2005) and 50% be based on the annualized growth of the National Grid plc’s EPS.
These measures were chosen because the Remuneration Committee believes they offer an improved balance between meeting the needs of shareholders (by measuring TSR performance against other large UK companies) and providing a measure of performance (EPS growth) over which the participating executives have direct influence. The Remuneration Committee considers the new Performance Share Plan performance conditions to be at least as challenging as the previous single performance criterion.
In calculating TSR for the fiscal year 2006/07 award, it is assumed that all dividends are reinvested. No shares will be released under the TSR part of the award if the National Grid plc’s TSR over the three-year performance period, when ranked against that of the FTSE 100 comparator group, falls below the median. For TSR at the median, 30% of those shares will be released; 100% will be released if National Grid plc’s TSR performance is 7.5% above that of the median company in the FTSE 100 (upper target).
The EPS measure is calculated by reference to National Grid plc’s real EPS growth - where annualized growth in EPS (excluding exceptional items and including continuing operations only) over the three-year performance period exceeds the average annual increase in RPI (the general index of retail prices for all items in the U.K., over the same period by 3% (threshold performance), 30% of the shares under the EPS part of the award will be released; 100% of the shares will be released where EPS growth exceeds RPI growth by 6% (upper target). As part of the Remuneration Committee’s proposals for fiscal year 2007/08 awards, required performance will be increased for 100% vesting of the shares for EPS growth exceeding RPI growth by 8% (upper target), which the Remuneration Committee considers to be more challenging.
For performance (for each target) between the threshold and the upper target, the number of shares released is calculated on a straight-line basis.
No re-testing of performance is permitted for any of the PSP awards that do not vest after the three-year performance period and any such awards lapse.
The performance criterion for the 2003 award was not reached and this award has lapsed in full.
Executive Share Option Plan.
In 2000, 2001 and 2002 certain named executives were provided grants of options to purchase National Grid plc ordinary shares at fair market value option pricing, dependent upon certain financial measures (performance conditions). Options were generally subject to an exercise window of between three and ten years following grant (with exceptions for death, and good leavers). If the performance condition is not satisfied after the relevant testing period, it is retested.
Options become exercisable if the full total shareholder return (TSR), measure over the period of three years beginning with the financial year in which the option is granted, is at least median compared with a comparator group of companies. Grants in excess of 100% of salary vest on a sliding scale, becoming fully exercisable if National Grid plc’s TSR is in the top quartile of comparative companies.
Options granted in March 2000 are vested. Options granted in June 2000 remain unvested. The June 2000 grants will continue to be tested annually throughout the testing period (due to expire June 5, 2010) Because the performance condition applicable to the June 2001 option was not met in March 2006, those options have lapsed and are no longer exercisable. The June 2002 grants are vested.
The comparator group for the 2000 grants is un-audited and this information follows below. The Remuneration Committee at that time believed the group to be an appropriate mix of energy distribution sector companies, including UK and international utilities.
Allegheny Energy, Inc.
Energy East Corporation
NSTAR
Scottish Power plc
BG Group plc
FPL Group, Inc.
Powergen plc
The Southern Company, Inc.
British Energy plc
GPU, Inc.
Progress Energy, Inc.
TXU, Corp
Central & South West Corp.
Innogy Holdings plc
Public Service Enerprise
United Utilities plc
Consolidated Edison, Inc.
International Power plc
Group, Inc.
Xcel Energy, Inc.
Duke Energy Corporation
Niagara Mohawk
Scottish & Southern
Holdings, Inc.
Energy plc
The Executive Share Option Plan was replaced by the Performance Share Plan in 2003.
Stock Appreciation Rights.
This is a Company legacy plan that existed prior to the merger of the Company into National Grid USA in 2002. Stock appreciation rights (SARs) were granted under Company’s Long Term Incentive Plan prior to the merger. At the time of merger, outstanding grants of SARs were converted to SARs over National Grid ADSs using a specified exchange ratio. Named executive holders of SARs are all vested in the SARs. In addition to any increase in value of the SARs over time, a participant is entitled to dividend equivalents accumulated from the date of grant. SARs may be exercised during the exercise period, which is established upon each grant. SARs lapse on the earlier of fifteen years from the date of grant or the end of the exercise period, if earlier.
Other Compensation Programs
The compensation programs noted below are part of a comprehensive compensation and benefits program that is designed to attract and retain high quality executive talent with expertise in the relevant business operations of the National Grid companies, including the Company. National Grid, like many companies, has come together by a series of mergers and acquisitions. Some of the named executives participate in legacy arrangements that originated with the company for which they worked for at the time of the particular merger. Certain legacy programs are maintained in their original forms due to certain tax advantages (such as tax favorable life insurance arrangements) or due to the desire to retain continuity in programs with long term implications (such as qualified pension plan benefit designs). Where reasonably possible, arrangements are brought to a common platform over time.
Executive Life Insurance
The named executive officers, as well as all other executives and eligible management employees, receive employer paid individual life insurance. Some executives participate in the group term life insurance plan that is provided to all other employees, while other executives receive coverage through split dollar life insurance programs (the “Split Dollar Programs”). Under the Split Dollar Programs the employer pays life insurance policy premiums on policies owned by the executive, and the National Grid employer retains the right, through a collateral assignment agreement with the executive, to be reimbursed for premiums paid plus amounts available through the insurance policy(ies) in excess of the life insurance promise. Executives receive a reimbursement for imputed income attributable to annual life insurance coverage provided pursuant to the Split Dollar Programs.
Mr. Edwards receives death benefits of three times base salary both during employment and after termination from National Grid, which is payable to his named beneficiary grossed up for estimated taxes. Mr. Jesanis, Mr. Cochrane and Ms. LaFleur receive life insurance coverage of three times base salary both during employment and after termination from National Grid under Split Dollar Programs. Mr. Buck receives 4 times base salary life insurance coverage during employment, which is provided all or in part through the U.K. pension plan in which he participates in, Mr. Kelleher, Mr. Ash and Mr. Tasker all receive a life insurance benefit of two times base salary during employment through the all employee insured arrangement. The total cash surrender values of policies (amounts attributable to the executive and their employer) under applicable Split Dollar Programs as of March 31, 2007 for the applicable named executives are as follows: Mr. Jesanis - $169,252; Mr. Cochrane - $190,535; and Ms, LaFleur - $288,777.
Perquisites
In addition to providing perquisites to attract and retain executives, additional perquisites are provided in some cases to account for the difficulties an executive faces when asked to undertake an extraordinary assignment at personal sacrifice, such as a temporary overseas assignment.
Named executive officers are reimbursed for financial and estate planning up to certain limits. The reimbursements for financial and estate planning are grossed up for applicable income tax impacts.
All such perquisites (including applicable income tax gross-ups) are reflected in the All Other Compensation column of the Summary Compensation Table and the accompanying footnotes.
Post-Retirement and Post-Employment Plans
The following post-employment plans are available to executives:
•
qualified pension plans and supplemental retirement plans are discussed in detail in the narrative following the Pension Benefits table. A qualified pension plan is available to all employees in order to be competitive in the marketplace, to provide a tax effective method for us to fund retirement benefits, and to help attract and retain executives. In addition to the qualified plan participation, the named executive officers (excluding Mr. Buck) also participate in executive supplemental pension plans.
These unfunded plans are maintained to provide named executive officers and other eligible employees with a pension benefit that will make up for the lost pension benefits that result from the Internal Revenue Code limits on the qualified plans, as well as, under certain circumstances, an enhanced formula and/or enhanced early retirement reduction factors. The retirement excess plans are provided in order to attract and retain qualified executives, which plans are common among companies that operate in similar industries to those of the National Grid plc companies. Mr. Edward, Mr. Kelleher, Mr. Ash and Mr. Tasker participated under the terms of a Company supplemental retirement plan up through the date of the merger of the Company with National Grid in 2002. The benefits payable under that plan (including those already distributed to Mr. Edwards and Mr. Kelleher immediately prior to the merger) are offset against the National Grid executive supplemental retirement plan benefits. For a more detailed discussion, see the disclosures following the 2006 Pension Benefits table below.
The named executive officers (other than Mr. Buck) are entitled to retiree medical and life insurance coverage if they terminate employment after age 55 with age and service totaling 85 points at the time or if they terminated employment at age 60 or older with at least 10 years of service. Retiree medical coverage is available to all non-union employees of the Company and its U.S. based affiliates who meet either eligibility criteria. The level of benefit coverage depends upon several factors, including date of hire, age and service as of certain dates, and company of origin prior to the Company merger with National Grid. In addition, Mr. Jesanis, Mr. Cochrane and Ms. LaFleur qualify for executive retiree health care benefits supplemental to those they may become eligible to receive under the general non-union employee plan. The executive health care plan provides health care benefits commencing upon the earlier of termination of employment or the earliest date they are eligible to receive qualified pension plan benefits (generally age 55). The employer pays the full cost of coverage and reimburses the executive for taxes if, and to the extent, the benefits are delivered on a taxable basis. Mr. Edwards is entitled to post-employment health care and life insurance coverage through an agreement explained in more detail under the section “Employment, Severance and Change in Control Agreements.
•
The named executives (excluding Mr. Buck) may elect to defer certain portions of their salary and bonuses into a deferred compensation plan. Deferral elections are generally allowed for 10 years, until separation from service, or to a specified age. These are unsecured promises from the applicable named executive’s National Grid employer. The plan is provided to allow executives an opportunity to defer income and associated income taxes on their compensation. In addition, when recruiting senior executives, the opportunity to defer compensation is an attractive feature in the recruitment process. The Deferred Compensation Plan is discussed in some detail in a narrative following the Nonqualified Deferred Compensation table.
•
Change of control protection and severance benefits are provided in agreements with Mr. Edwards, Mr. Jesanis, Mr. Cochrane and Ms. LaFleur. Mr. Kelleher, Mr. Ash and Mr. Tasker are provided severance benefits under the terms of the National Grid USA Companies’ Executive Severance Plan (the “Executive Severance Plan”). Change of control severance benefits are discussed in detail in a narrative following the Nonqualified Deferred Compensation table. These individual agreement benefits and the Executive Severance Plan benefits are provided to ensure the continued employment of the executive leadership team during a period of time when there may be a great deal of uncertainty pending a major corporate event, including a change of control.
•
Mr. Buck participated in a share matching plan prior to the plan’s replacement by the Executive Director’s Deferred Share Plan in June of 2006. The share matching plan was intended to encourage executives in the U.K. to purchase and retain shares in National Grid plc by investing part of their annual bonus in National Grid plc ordinary shares (Qualifying Shares). The National Grid U.K. employer matched that commitment with a right to acquire further ordinary shares(matching shares) at a nominal price, subject to retention of the Qualifying Shares and continued employment with National Grid.
Policy with Respect to Section 162(m) Deduction Limit
Under Section 162(m) of the Internal Revenue Code of 1986, as amended, compensation in excess of $1,000,000 paid in any year to the Chief Executive Officer or any of the other named executive officers cannot be deducted. This Section 162(m) limit does not apply to the Company.
Executive Stock Ownership Policy
Executive Directors are encouraged to build up and retain a shareholding of National Grid plc securities at a level of at least 100% of annual salary. As a minimum, this is expected to be achieved by retaining 50% of the after-tax gain on any options exercised or shares received through the long-term incentive or all-employee share plans.
Fiscal 2006/07 Summary Compensation Table
(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 plc awarded under an incentive compensation plan and cash bonuses awarded under the all-employees goals program. For Mr. Edwards, it also includes a special cash bonus in the amount of $25,000, associated with the completion of certain corporate objectives. For Mr. Cochrane, it also includes special bonuses totalling $175,600 which mainly reflects payments for special UK-based projects, including to be in the U.K. for long periods and a special one time payment for managing the successful sale of the U.K. wireless business. For Mr. Buck, 60% of his award was paid in cash and the remaining 40% is payable in deferred National Grid plc shares under the Executive Director’s Deferred Share Plan. These shares remain in trust for a 3 year period.
(c)
Represents FAS 123R expense of equity awards under the various executive plans.
(f)
Mr. Jesanis served as CEO of National Grid in the US. His employment terminated effective January 1, 2007.
(g)
Mr. Cochrane resigned as CFO of National Grid in the US on December 31, 2006 to take on a global position at National Grid.
(h)
Mr. Colin Buck is on assignment from the UK and was appointed as Senior VP and Chief Financial Officer of National Grid USA as of January 1, 2007. When paid in pounds sterling, a conversion rate of $1.97/1.00£ was used, which is the balance sheet exchange rate for the fiscal year ending March 31, 2007 that the National Grid companies use in translating/reporting results.
(i)
Includes salary supplement of $75,000 for Acting President & CEO position.
(j)
Mr. Jesanis, Mr. Cochrane and Ms. LaFleur performed services for affiliate companies. The amounts shown on this table and the other compensation tables represent their total compensation for the 2006/07 fiscal year for all services to all National Grid companies.
Grants of Plan Based Awards in Fiscal 2006/07
(a)
The table reflects grants made under the Performance Share Plan, under which the named executives received notional allocations of National Grid plc American Depositary Shares (ADSs). Mr. Buck, however, received notional allocations of National Grid plc ordinary shares. See the “Long-Term Incentive Compensation” section under the Compensation Program description for details regarding this 2006/07 grant.
(b)
For all named executives, except Mr. Buck, represents the 1/3 portion of the 2006/2007 fiscal year bonus paid in unrestricted shares under the Incentive Compensation Plan.
For Mr. Buck, represents restricted shares that are deferred to the Executive Director’s Deferred Share Plan under which shares are held in trust for a 3 year period.
(c)
Exchange rate of $1.97/£1.00 used, which is the exchange rate for the National Grid companies’ balance sheet at March 31, 2007.
Stock Awards
There were no grants of stock options to the named executive officers during 2006/07. As noted earlier, the Executive Share Option Plan was replaced by the Performance Share Plan beginning with awards made in 2003. Outstanding options from previous grants are reflected in the Outstanding Equity Awards at Fiscal Year-End table.
Outstanding Equity Awards at Fiscal 2006/07 Year End
Options Exercised and Stock Vested
(a)
Option basis is National Grid ordinary shares traded on the London Stock Exchange
(b)
Stock Appreciation Right (SAR) grants were made under Niagara Mohawk’s Long Term Incentive Plan which was discontinued when its parent, Niagara Mohawk Holdings, Inc., merged with a subsidiary of National Grid USA. At that time, outstanding grants of SARs were converted to SARs over National Grid Group American Depositary Shares (ADSs) using a specified exchange ratio. Basis for SARs is National Grid ADSs traded on the NYSE.
(c)
Performance Share Plan awards granted in June 2004 will be tested on June 30, 2007.
2006 Pension Benefits
Assumptions
Discount Rate for 3/31/2007 PVAB : 6.00%*
Discount Rate for 3/31/2006 PVAB : 6.00% *
Benefit Commencement Date : At first point unreduced benefits are available
Mortality Table : RP2000CH*
* For the Niagara Mohawk Pension and SERP Plans, the present value was determined based on a lump sum payment form (for this purpose a 5.75% discount rate assumption was used for the qualified plan and a 4.00% discount rate assumption was used for the SERP)
Depending on their company origin prior to the merger of the Company with National Grid, the named executives 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 (Company Plan). Both FAPP and the Company Plan are noncontributory, tax-qualified defined benefit plans which, between them, provide a retirement benefit to substantially all employees of the National Grid USA companies. Pension benefits are related to compensation, subject to maximum annual limits under the Internal Revenue Code
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 (but excludes Performance Share Plan awards and options).
Under the Company 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. Mr. Edwards, Mr. Kelleher, Mr. Ash and Mr. Tasker will receive the retirement benefit resulting from the higher of the two formulas.
The named executive officers (other than Mr. Buck) also participate in the National Grid USA Companies’ Executive Supplemental Retirement Plan (ESRP). The ESRP is a noncontributory, nonqualified defined benefit plan. It provides additional retirement benefits to members of management who meet certain eligibility criteria. Depending on the participant, the ESRP may provide for unreduced benefits payable as early as age 55, enhance the qualified plan formula, give credit for more years of service, take into account certain deferred compensation, and/or award benefits not otherwise payable due to limits on benefits that can be provided under the qualified plan. Mr. Edwards, Mr. Kelleher, Mr. Ash and Mr. Tasker, as well as other ESRP participants who formerly participated in the Niagara Mohawk Supplemental Executive Retirement Plan (Company SERP), are entitled to the pension benefit paid under the Company Plan, plus the higher of the pension benefit paid under the ESRP or that paid under the Company SERP. Company SERP accruals were frozen at the time of the merger of the Company with National Grid. Mr. Edwards, Mr. Kelleher and Mr. Tasker received all or a portion of their Company SERP benefit just prior to the merger of the Company with National Grid, which amounts are included in the ESRP offset formula.
Mr. Buck participates in one of the broad-based pension plans available to U.K. employees of National Grid called the National Grid Electricity Group of the Electricity Supply Pension Scheme (Pension Scheme). The Pension Scheme provides final salary-based retirement income benefits on a funded basis. The final average pay is based upon base salary in the 12 months up to the date of leaving National Grid. It is funded with both employer and employee contributions (since March 2004, contribution percentages have been 13.1% employer and 6% employee). The Pension Scheme was closed to new entrants effective April 1, 2006.
2006 Nonqualified Deferred Compensation
(a) Earnings reported in Summary Compensation table for fiscal year 2006/2007 that were above market:
Deferred Compensation Plan
The named executives (other than Mr. Buck) may elect to defer 75% of base pay, up to 100% of the Incentive Compensation Plan cash bonus, all or none of the share portion of the Incentive Compensation Plan bonus, all or none of the Performance Share Plan bonus, and/or all or none of any Executive Director’s Deferred Share Plan award, into a deferred compensation plan (Deferred Compensation Plan). Deferral elections are generally allowed for 10 years, until separation from service, or to a specified age. Re-deferrals are generally allowed under the following parameters: the re-election must occur at least 12 months in advance of the originally elected/established payment date; the re-deferral election is not effective for 12 months; and the re-deferral must extend the originally elected/established payment date by at least 5 years. Deferrals made for periods after December 31, 2004 are operated subject to the parameters of section 409A of the Internal Revenue Code. Deferrals made prior to that date are operated under then existing rules and are grandfathered from section 409A rules. Deferred compensation for each participant is credited to an account on applicable National Grid company books (the “Deferred Account”). Notional earnings are credited on amounts in a Deferred Account and are revalued daily. Notional investment choices are comprised of: Prime Rate; State Street Institutional Trust S&P 500 Index Fund; and/or NGG ADSs.
Employment Agreements Including Change of Control - Post Termination
Employment, Severance and Change of Control Arrangements
Of the named executive officers, only Mr. Jesanis has a formal employment contract. As of December 31, 2006, Mr. Jesanis’ employment was terminated and he entered into a separation and release agreement which provides for an aggregate lump sum payment of $3,126,711. Mr. Jesanis’ outstanding awards under National Grid’s Executive Share Option Plan, Performance Share Plan, and Deferred Share Plan remain subject to the
applicable plan rules. The performance criteria was assessed as of December 31, 2006 resulting in the lapsing and vesting of certain awards granted under the Performance Share Plan and the Deferred Share Plan. The separation and release agreement requires Mr. Jesanis to protect National Grid’s confidential and proprietary information and prohibits him from providing any professional or consulting services to any regulatory body that regulates a member of the Group until the earlier of December 31, 2008 or the completion of the KeySpan acquisition by National Grid. The separation and release agreement also extended certain non-compete and non-solicitation covenants from the service agreement until June 30, 2007. On January 1, 2007, Mr. Jesanis entered into a consulting agreement under which he provides consulting services to National Grid for a monthly consulting fee of $216,568, which will be reduced dollar-for-dollar by any base salary he receives should he become employed in any commercial activity up through June 30, 2007. The consulting agreement expires on June 30, 2007, but may be terminated earlier by National Grid, for cause or through a lump-sum payment of the amount that would have been payable had Mr. Jesanis served the full period of the agreement.
Mr. Edwards, Mr. Cochrane and Ms. LaFleur have change of control agreements with National Grid USA providing for severance payments and benefits if their employment is terminated without cause and not by reason of death, disability or retirement, or if they terminate with good reason within 36 months after a change in control or other qualifying transaction. The agreements are operating under 36 month protection periods set to expire on June 30, 2009 due to the trigger of three year protection periods following the approval by National Grid plc shareholders of the KeySpan acquisition. In addition to any other compensation and benefits payable under executive plans, the executive will be entitled to a lump sum cash payment equal to three times the sum of (i) the higher of the executive’s annual base salary in effect at termination or in effect immediately prior to the change of control, plus (ii) the higher of the average bonus amount for the 3 years preceding the year of termination or the three years preceding the year of the change of control; a lump sum cash payment of the difference between the amount the executive would have accrued under each pension plan had he or she remained employed for an additional 36 months and what he had accrued at the time of termination; and reimbursement of legal fees and expenses, if any, that he or she incurs in disputing in good faith any issue relating to the agreement. Under these agreements, Mr. Edwards, Mr. Cochrane and Ms. LaFleur agree to waive any rights to benefits under the National Grid’s standard severance plan and National Grid USA Companies’ Executive Severance Plan to the extent that they do not exceed the benefits payable under the change of control agreement. In addition, Mr. Cochrane and Ms. LaFleur are entitled to receive life, health and disability benefits for three years following termination. Payments under the agreements are capped at a level necessary to avoid triggering Internal Revenue Code Section 280G tax implications.
In addition to the above benefits, Mr. Edwards is also entitled to life insurance at three times his base pay in effect at termination or immediately prior to the change of control, whichever is higher, for his lifetime. Mr. Edwards and his eligible dependents will be entitled to certain post-termination medical benefits for his lifetime as well. With respect to his recent appointment as Executive Vice President US Shared Services and anticipated change in base location following the KeySpan merger, Mr. Edwards and the Company are in the process of finalizing a definitive retention and relocation letter agreement whereby Mr. Edwards will receive relocation assistance which includes $6,000 per month for a maximum period of four years, a one time disturbance allowance equivalent to three months of current base pay, and reimbursement of other related moving costs. Mr. Edwards will also be eligible to receive a one-time retention award of $1,476,125 in the form of National Grid ADSs which will be granted in November/ December 2007 and will vest in equal tranches over three years, subject to continued
employment. In addition, certain changes will be made to Mr. Edwards’ change of control agreement. A new transaction will not trigger any further protections under the outstanding agreement, and in the event any severance payments become payable during the remaining term of the outstanding agreement they will be reduced by the value of the retention award that has been vested and received by Mr. Edwards at the time of the severance payment.
Mr. Tasker does not have an individual change of control agreement but is eligible for severance benefits under the National Grid USA Companies’ Executive Severance Plan. Under this severance plan, if he is terminated without cause and not offered an equivalent position, he would be entitled to a payment equal to two times his total compensation, which is defined as the sum of one year’s base pay, at its highest level in the past two years, and the product of the annualized base pay and the average bonus payout for the three completed years prior to termination. Mr. Tasker would also receive a lump sum payment to cover the employer’s contribution toward health insurance premiums for 18 months, grossed up to reflect applicable payroll withholding taxes; a pro-rated bonus to reflect the number of months worked during the year; and outplacement counseling for 18 months. Further, the employer would either maintain the life insurance policy in effect for 18 months or provide a lump sum payment in the amount of 18 months’ premiums, grossed up for taxes. As a condition of acceptance of the severance benefits, Mr. Tasker must sign an agreement and release, waiving any claims against the National Grid companies.
Mr. Ash is eligible for severance benefits under the National Grid USA Companies’ Executive Severance Plan as well. Under this severance plan, if Mr. Ash is terminated without cause and not offered an equivalent position, he would be entitled to a payment equal to his total compensation, which is defined as the sum of one year’s base pay, at its highest level in the past two years, and the product of his annualized base pay and his average bonus payout for the three completed years prior to termination. Mr. Ash would also receive a lump sum payment to cover the employer’s contribution toward health insurance premiums for 12 months, grossed up to reflect any state or federal income taxes; a pro-rated bonus to reflect the number of months worked during the year; and outplacement counseling for 12 months. The employer would maintain the life insurance policy in effect for 12 months or provide a lump sum payment in the amount of 12 months’ premiums, grossed up for taxes. As a condition of acceptance of the severance benefits, Mr. Ash must sign an agreement and release, waiving any claims against the National Grid companies.
Mr. Kelleher and the Company entered into a separation and release agreement dated May 1, 2007, under which he has agreed to terminate his employment with National Grid as of August 31, 2007. Under the agreement, Mr. Kelleher will receive his salary and benefits through August 31, 2007, but will not be involved in day to day operations, unless requested, and may not engage in other employment without the prior written consent of National Grid during this period. He will receive a lump sum cash payment, applicable taxes withheld, equal to two times his annual base salary in effect on April 30, 2004, plus two times the product of his base pay times the average bonus award percentage under the Incentive Compensation Plan for plan years 2005, 2006 and 2007, plus a prorated bonus award for fiscal 2008 equal to his base pay times forty five percent times five twelfths. In addition, Mr. Kelleher will also receive a lump sum payment, applicable taxes withheld, to cover the employer’s contribution
toward health insurance premiums for 18 months, grossed up to reflect applicable payroll withholding taxes. The agreement also provides that the employer may, in its sole discretion, maintain the life insurance policy in effect for an additional 18 months or provide a lump sum payment in the amount of eighteen months’ premiums, grossed up for taxes. Mr. Kelleher will also receive outplacement services for eighteen months. These payments would be in lieu of any other severance benefits to which Mr. Kelleher may otherwise be entitled. Under the separation and release agreement, Mr. Kelleher agrees to protect the employer’s and its affiliates’ confidential and proprietary information. In addition, he would remain eligible for outstanding Performance Share Plan awards under the status of a good leaver.
Estimated Change of Control/Severance Payments
The following table shows the amount of potential severance benefits for the named executive officers pursuant to the employment/severance arrangements, assuming the named executive was terminated under circumstances qualifying for the benefits and that termination occurred as of March 31, 2007. The table also shows the estimated present value of continuing coverage for the benefits in the case of Mr. Edwards, Mr. Cochrane and Ms. LaFleur.
Estimated Change of Control/Severance Payments
(a)
Cash severance benefit is a lump sum payment based on the annual base salary prior to termination plus the average annual bonus times the severance multiple. The severance multiple is 3 times for Ms. LaFleur, Mr. Cochrane and Mr. Edwards; 2 times for Mr. Kelleher and Tasker, and 1 times for Mr. Ash.
(b)
Welfare benefits for Mr. Jesanis include legal, financial and outplacement services. For Ms. LaFleur and Mr. Cochrane includes company continuation of benefits for a period of 36 months following termination. For Mr. Edwards includes lifetime benefit continuation. For Mr. Kelleher and Mr. Tasker benefits include a lump sum payment equal to the company cost of medical coverage, grossed up for taxes for a period of 18 months and for Mr. Ash for a period of 12 months. Total gross up amounts are shown in the column entitled “Estimated Gross-up Payments.”
(c)
Benefits as outline in the agreement between National Grid plc, and Michael Jesanis, dated January 17, 2007.
(d)
Benefits as outline in the agreements between National Grid USA Cheryl LaFleur dated March 1, 1998, as amended, John Cochrane dated March 1, 1998, as amended, and William Edwards dated March 15, 2005.
(e)
Benefits as outline in the agreement between National Grid USA Service Co, Inc and Michael Kelleher, dated May 1, 2007.
(f)
Benefits as outline under the National Grid USA Companies Executive Severance Plan
(g)
Mr. Buck does not have a change of control/severance arrangement
(h)
Includes the present value of the right of Mr. Jesanis, Ms. LaFleur and Mr. Cochrane to receive their National Grid U.S.A Companies’ Executive Supplemental Retirement Plan (ESRP) benefit accrued up through December 31, 2004, in a lump sum less a 10% “haircut”. This right stems from the merger of New England Electric System with National Grid plc in 2000. The present value lump sum amounts are based on the following assumptions: a 6.0 percent discount rate; present value reduction from age 55 to age at March 31, 2007; the G83GATT mortality table; and a 10 percent deduction due to the “haircuts” provision. For Ms. LaFleur and Mr. Cochrane, the value also includes a lump sum derived by adding 3 years of age and service to the calculation of their ESRP benefit as contemplated by the terms of their respective employment agreements. The portion attributable to the 3 years added to age and service for Ms. LaFleur represents $1,084,482 of the $2,598,588 total, and represents $753,305 of the $2,266,931 total for Mr. Cochrane. The assumptions used in the calculation of the 3 years of age and service components were a 6% discount rate and the RP2000CH mortality table.
The following table provides a summary of the value of unvested stock options and performance shares that vest upon a change of control.
Accelerated Vesting of Equity Awards Attributed to Change of Control
Performance Share Plan
Awards vest on the date of the change in control, to the extent the performance condition has been satisfied at that date. The number of shares that will be transferred to the participant will be reduced to take account of the proportion of the vesting period which has not elapsed. Alternatively, awards may be exchanged for equivalent awards over the acquiring company’s shares, subject to the Remuneration Committee’s discretion.
Deferred Share Plan
Awards vest in full on the date of the change in control. Alternatively, awards may be exchanged for equivalent awards over the acquiring company’s shares, subject to the Remuneration Committee’s discretion.
Executive Share Option Plan
Options become exercisable on the date of the change in control, to the extent that the performance condition has been satisfied at that date. Alternatively, options may be exchanged for equivalent options over the acquiring company’s shares, subject to the Remuneration Committee’s discretion.
Share Matching Plan
Awards vest on the date of the change in control. Alternatively, awards may be exchanged for equivalent awards over the acquiring company’s shares, subject to the Remuneration Committee’s discretion.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The following table indicates the number of ordinary shares of National Grid plc beneficially owned as of June 1, 2007 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 plc. 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)
The Company’s directors and executive officers are listed in Item 10.
(b)
Includes shares held by Mr. Reilly’s spouse and Ms. Zschokke’s spouse.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
PricewaterhouseCoopers LLP served as an independent registered public accounting firm of the Company for the fiscal year ended March 31, 2007.
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, 2007, and the reviews of quarterly reports on Form 10-Q filed during the fiscal year ended March 31, 2007 were $1 million. Fees billed by PricewaterhouseCoopers LLP for the audit of the Company’s financial statements and regulatory filings for the fiscal year ended March 31, 2006, and the reviews of quarterly reports on Form 10-Q filed during the fiscal year 2006 were $0.8 million.
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 2007.
Tax Fees
Fees billed by PricewaterhouseCoopers LLP to the Company for tax compliance, tax advice and tax planning were $4,743 in fiscal year 2007. Aggregate fees billed by PricewaterhouseCoopers LLP for these fees were $42,489 in fiscal year 2006.
All Other Fees
During the fiscal year ended March 31, 2007, the Company was billed fees by PricewaterhouseCoopers LLP totaling $911,400 for Sarbanes-Oxley Section 404 related services. The Company did not pay any other type of fee for any other services from PricewaterhouseCoopers LLP during the fiscal year ended March 31, 2007. Aggregate fees billed by PricewaterhouseCoopers LLP for these fees were $95,700 in fiscal year 2006.
The Company’s stockholders appoint the Company’s independent registered public accounting firm, with the approval of the Audit Committee of the Company’s indirect parent company, National Grid plc. Subject to any relevant legal requirements and National Grid plc’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 registered public accounting firm. The Audit Committee must approve in advance all non-audit work to be performed by the independent registered public accounting firm.
During the fiscal year ended March 31, 2007, all of the above-described services provided by PricewaterhouseCoopers LLP were pre-approved by the Audit Committee.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Financial Statements
Exhibits
The exhibit index is incorporated herein by reference.
Financial Statement Schedule
Schedule II - Valuation and Qualifying Accounts and Reserves
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
(In thousands of dollars)
(a)
Uncollectible accounts written off net of recoveries.
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 28, 2007 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/ Colin Buck
Colin Buck
Senior Vice President and Chief Financial Officer (Principal Financial Officer)
/s/ Paul J. Bailey
Paul J. Bailey
Controller (Principal Accounting Officer)
/s/ Barbara A. Hassan
Barbara A. Hassan
Director
/s/ Susan M. Crossett
Susan M. Crossett
Director
/s/ Cheryl A. LaFleur
Cheryl A. LaFleur
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 % of the total consolidated assets of the Company and its subsidiaries.