Item 1. Description of the Business
Corporate Overview
KeySpan Corporation ("KeySpan"), a New York corporation, is a member of the Standard and Poor's 500 Index and a registered holding company under the Public Utility Holding Company Act of 1935, as amended ("PUHCA"). KeySpan was formed in May 1998, as a result of the business combination of KeySpan Energy Corporation, the parent of The Brooklyn Union Gas Company, and certain businesses of the Long Island Lighting Company ("LILCO"). On November 8, 2000, we acquired Eastern Enterprises ("Eastern"), now known as KeySpan New England, LLC ("KNE"), a Massachusetts limited liability company[1], which primarily owns Boston Gas Company ("Boston Gas"), Colonial Gas Company ("Colonial Gas") and Essex Gas Company ("Essex Gas"), gas utilities operating in Massachusetts, as well as EnergyNorth Natural Gas, Inc. ("EnergyNorth"), a gas utility operating principally in central New Hampshire. As used herein, "KeySpan," "we," "us" and "our" refers to KeySpan, its six principal gas distribution subsidiaries, and its other regulated and unregulated subsidiaries, individually and in the aggregate.
Under our holding company structure, we have no independent operations and conduct substantially all of our operations through our subsidiaries. Our subsidiaries operate in the following four businesses: Gas Distribution, Electric Services, Energy Services and Energy Investments.
The Gas Distribution segment consists of our six regulated gas distribution subsidiaries, which operate in New York, Massachusetts and New Hampshire and serve approximately 2.5 million customers.
The Electric Services segment consists of subsidiaries that manage the electric transmission and distribution ("T&D") system owned by the Long Island Power Authority ("LIPA"); provide energy conversion services for LIPA from our generating facilities located on Long Island; and manage fuel supplies for LIPA to fuel our approximate 4,200 megawatts of Long Island generating facilities. The electric services segment also includes subsidiaries that own, lease and operate the 2,200 megawatt Ravenswood electric generation facility (the "Ravenswood facility"), located in Queens County in New York City.
The Energy Services segment provides energy-related services to customers primarily located within New York, New Jersey, Massachusetts, New Hampshire, Rhode Island and Pennsylvania through various subsidiaries that operate under the following principal three lines of business: (i) home energy services; (ii) business solutions; and (iii) fiber optic services.
The Energy Investments segment includes: (i) gas exploration and production activities; (ii) domestic pipelines and gas storage facilities; (iii) midstream natural gas processing activities in Canada; and (iv) natural gas distribution and pipeline activities in the United Kingdom.
KeySpan's vision is to be the premier energy company in the Northeastern United States. Following the acquisition of Eastern and EnergyNorth in November 2000, KeySpan became the largest gas distribution company in the Northeast and the fifth largest in the United States. KeySpan's increased size and scope is enabling us to provide enhanced cost-effective customer service; to offer our existing customers other services and products by building upon our existing customer relationships; and to capitalize on the above-average growth opportunities for natural gas expansion in the Northeast by expanding our infrastructure, primarily on Long Island and in New England. The key element of our business strategy is the continued focus and growth of our Gas Distribution, Electric Services and Energy Services businesses. We also continue to explore the monetization of some or all of our non-core assets in the Energy Investments segment.
- -------- 1 Pursuant to an application on Form U-1 filed with the Securities and Exchange Commission on May 28, 2002, Eastern Enterprises, a Massachusetts business trust, was reorganized as KNE. The transaction involved the formation of KNE as well as another new subsidiary named KSNE, LLC ("KSNE"), a Delaware limited liability company, that is a wholly-owned subsidiary of KeySpan. KNE is 99% owned by KeySpan and 1% owned by KSNE.
Certain statements contained in this Annual Report on Form 10-K concerning expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are other than statements of historical facts, are "forward-looking statements" within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Without limiting the foregoing, all statements under the captions "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings, pursuit of potential future acquisition opportunities and sources of funding, are forward-looking statements. Such forward-looking statements reflect numerous assumptions and involve a number of risks and uncertainties and actual results may differ materially from those discussed in such statements.
Among the factors that could cause actual results to differ materially are:
- volatility of energy prices of fuel used to generate electricity;
- fluctuations in weather and in gas and electric prices;
- general economic conditions, especially in the Northeast United States;
- our ability to successfully reduce our cost structure and operate efficiently;
- our ability to successfully contract for natural gas supplies required to meet the needs of our firm customers;
- implementation of new accounting standards;
- inflationary trends and interest rates;
- the ability of KeySpan to identify and make complementary acquisitions, as well as the successful integration of recent and future acquisitions;
- available sources and cost of fuel;
- creditworthiness of counter-parties to derivative instruments and commodity contracts;
- retention of key personnel;
- federal and state regulatory initiatives that increase competition, threaten cost and investment recovery, and place limits on the type and manner in which we invest in new businesses;
- the impact of federal and state utility regulatory policies and orders on our regulated and unregulated businesses;
- potential write-down of our investment in natural gas properties when natural gas prices are depressed or if we have significant downward revisions in our estimated proved gas reserves;
- competition in general facing our unregulated Energy Services businesses, including but not limited to competition from other mechanical, plumbing, heating, ventilation and air conditioning, and engineering companies, as well as, other utilities and utility holding companies that are permitted to engage in such activities;
- the degree to which we develop unregulated business ventures, as well as federal and state regulatory policies affecting our ability to retain and operate such business ventures profitably; and
- other risks detailed from time to time in other reports and other documents filed by KeySpan with the Securities and Exchange Commission ("SEC").
For any of these statements, KeySpan claims the protection of the safe harbor for forward-looking information contained in the Private Securities Litigation Reform Act of 1995, as amended. For additional discussion on these risks, uncertainties and assumptions, see "Item 1. Description of Business," "Item 2.
Item 2. Properties
Information with respect to KeySpan's material properties used in the conduct of its business is set forth in, or incorporated by reference in, Item 1 hereof. Except where otherwise specified, all such properties are owned or, in the case of certain rights of way used in the conduct of its gas distribution business, held pursuant to municipal consents, easements or long-term leases, and in the case of gas and oil properties, held under long-term mineral leases. In addition to the information set forth therein with respect to properties utilized by each business segment, KeySpan leases the executive headquarters located in Brooklyn, New York. In addition, we lease other office and building space, office equipment, vehicles and power operated equipment. Our properties are adequate and suitable to meet our current and expected business requirements. Moreover, their productive capacity and utilization meet our needs for the foreseeable future. KeySpan continually examines its real property and other property for its contribution and relevance to our businesses and when such properties are no longer productive or suitable, they are disposed of as promptly as possible. In the case of leased office space, we anticipate no significant difficulty in leasing alternative space at reasonable rates in the event of the expiration, cancellation or termination of a lease.
Item 3.
Item 3. Legal Proceedings
See Note 7 to the Consolidated Financial Statements, "Contractual Obligations and Contingencies - Legal Matters."
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of the security holders during the last quarter of the 12 months ended December 31, 2002.
PART II
Item 5.
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
KeySpan's common stock is listed and traded on the New York Stock Exchange and the Pacific Stock Exchange under the symbol "KSE." As of March 1, 2003, there were approximately 70,213 registered record holders of KeySpan's common stock. The following table sets forth, for the quarters indicated, the high and low sales prices and dividends declared per share for the periods indicated:
2002 High Low Dividends Per Share First Quarter $36.72 $30.01 $0.445 Second Quarter $37.45 $34.35 $0.445 Third Quarter $38.19 $27.41 $0.445 Fourth Quarter $37.15 $30.75 $0.445
2001 High Low Dividends Per Share First Quarter $41.94 $34.20 $0.445 Second Quarter $41.10 $35.75 $0.445 Third Quarter $37.20 $29.10 $0.445 Fourth Quarter $35.35 $31.53 $0.445
The following table sets forth securities authorized for issuance under equity compensation plans for the year ended December 31, 2002:
(1) Includes grants of options and restricted stock pursuant to KeySpan's Long-Term Performance Incentive Compensation Plan, as amended, and options granted pursuant to the Brooklyn Union Long-Term Performance Incentive Compensation Plan and options granted pursuant to Eastern Enterprises Long-Term Performance Incentive Compensation Plans, as well as 328,000 shares of Common Stock issued pursuant to the Stock Plan. (2) Represents Deferred Stock Units issued pursuant to the Officers' Deferred Stock Unit Plan. (3) There is no set limit on the number of Deferred Stock Units issuable pursuant to the Officers' Deferred Stock Unit Plan or the KeySpan Services Inc. Officers' Deferred Stock Unit Plan.
Directors' Deferred Compensation Plan
The Directors' Deferred Compensation Plan provides all non-employee directors with the opportunity to defer any portion of their cash compensation received as directors, up to 100%, in exchange for Common Stock equivalents or cash equivalents. Common Stock equivalents are valued by utilizing the average of the high and low price per share of KeySpan common stock on the first trading day of the month following the month in which contributions are received. Dividends are paid on Common Stock equivalents in the same proportion as dividends paid on Common Stock. Compensation not deferred and exchanged for Common Stock equivalents, may be deferred into a cash account bearing interest at the prime rate. Upon retirement, death or termination of service as a director, all amounts in a director's Common Stock equivalent account and/or cash account shall, at the director's election, (i) be paid in a lump sum in cash; (ii) be deferred for up to five years; and/or (iii) be paid in the number of annual installments, up to ten, specified by the director. The non-employee directors are not entitled to benefits under any KeySpan retirement plan.
Officers' Deferred Stock Unit Plan
The Officers' Deferred Stock Unit Plan allows certain executives of the Company and its wholly owned subsidiaries to elect to defer between 10% to 50% of their annual cash bonus award and purchase deferred stock units ("DSUs"), which track the performance of the Company's Common Stock but do not possess voting rights. Executives also receive a 20% match by the Company on the amount deferred in each year. The DSUs must be deferred until retirement or resignation and are payable in Common Stock. The match on the deferral is also payable in Common Stock upon retirement or in the event of an executive's disability, death or upon change of control. The match is forfeited in the event of the executive's resignation prior to retirement.
KeySpan Services Inc. Officers' Deferred Stock Unit Plan
The KeySpan Services Inc. Officers' Deferred Stock Unit Plan allows certain officers of KeySpan Services Inc.and its wholly owned subsiadiries, to elect to defer between 10% to 50% of their annual cash bonus award and purchase DSUs which track the performance of the Company's Common Stock but do not possess voting rights. Executives also receive a 20% match by the Company on the amount deferred in each year. The DSUs must be deferred until retirement or resignation and are payable in Common Stock. The match on the deferral is also payable in Common Stock upon retirement or in the event of an executive's disability, death or upon change of control. The match is forfeited in the event of the executive's resignation prior to retirement.
Item 6.
Item 6. Selected Financial Data
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
KeySpan Corporation (referred to herein as "KeySpan", "we", "us" and "our") is a registered holding company under the Public Utility Holding Company Act of 1935, as amended ("PUHCA"). KeySpan operates six regulated utilities that distribute natural gas to approximately 2.5 million customers in New York City, Long Island, Massachusetts and New Hampshire, making us the fifth largest gas distribution company in the United States and the largest in the Northeast. We also own and operate electric generating plants in Nassau and Suffolk Counties on Long Island and in Queens County in New York City and are the largest investor owned generator in New York State. Under contractual arrangements, we provide power, electric transmission and distribution services, billing and other customer services for approximately one million electric customers of the Long Island Power Authority ("LIPA"). KeySpan's other subsidiaries are involved in gas and oil exploration and production; gas storage; wholesale and retail gas and electric marketing; appliance service; plumbing, heating, ventilation, air conditioning and other mechanical contracting services; large energy-system ownership, installation and management; engineering and consulting services; and fiber optic services. We also invest and participate in the development of natural gas pipelines, natural gas processing plants, electric generation, and other energy-related projects, domestically and internationally. (See Note 2 "Business Segments" for additional information on each operating segment.)
Consolidated Summary of Results
Consolidated earnings before interest and taxes ("EBIT") by segment, as well as consolidated earnings available for common stock is set forth in the following table for the periods indicated.
As indicated in the above table, earnings from continuing operations less preferred stock dividends for the year ended December 31, 2002 increased by $153.8 million, or $1.05 per share compared to the same period in 2001. The increase in earnings from continuing operations reflects the following significant events which are discussed in more detail below: (i) the discontinuance of goodwill amortization in 2002; (ii) the recording of special items in 2001 which resulted in the recognition of certain gains and losses; and (iii) a significant decrease in interest expense in 2002. These benefits to comparative earnings were offset, in part, by a decrease in natural gas prices, particularly during the first quarter, which reduced 2002 earnings associated with gas exploration and production operations, as well as the impact of extremely warm weather during the first quarter which adversely affected natural gas consumption by gas distribution customers.
In January 2002, we adopted Statement of Financial Accounting Standard ("SFAS") 142 "Goodwill and Other Intangible Assets". The key requirements of this Statement include the discontinuance of goodwill amortization, a revised framework for testing goodwill impairment and new criteria for the identification of intangible assets. Consolidated goodwill amortization for 2001 was $49.6 million, or $0.36 per share, and $19.7 million, or $0.15 per share for 2000.
During 2001, we recorded the effects of a number of events that impacted results of operations for that year. These events are as follows: (1) we incurred losses attributed to the former Roy Kay companies of $95.0 million after-tax, or $0.69 per share, primarily reflecting costs related to the discontinuance of the general contracting activities of these companies, costs to complete work on certain loss construction projects, and operating losses incurred. (See Note 10 to the Consolidated Financial Statements, "Roy Kay Operations" and Note 7 "Contractual Obligations, Financial Guarantees and Contingencies" - Legal Matters, for a further discussion of these issues); (2) our gas exploration and production subsidiaries recorded a non-cash impairment charge to recognize the effect of lower wellhead prices on their valuation of proved gas reserves. Our share of this charge was $26.2 million after-tax, or $0.19 per share. (See Note 1 to the Consolidated Financial Statements "Summary of Significant Accounting Policies", Item F for further details); and (3) following a favorable appellate court ruling, we reversed a previously recorded loss provision regarding certain pending rate refund issues relating to the 1989 RICO class action settlement of $20.1 million after-tax, or $0.15 per share. This adjustment has been reflected as a $22.0 million reduction to Operations and Maintenance expense and a reduction of $11.5 million to Interest Charges on the Consolidated Statement of Income for the year ended December 31, 2001. (See Note 11 to the Consolidated Financial Statements "Class Action Settlement" for a further discussion of this issue.)
Interest expense decreased by $52.0 million ($33.8 million after-tax), or $0.24 per share in 2002 compared to 2001. The weighted average interest rate on outstanding commercial paper for 2002 was approximately 2.0% compared to approximately 4.5% for last year. Further, KeySpan had a number of interest rate swap agreements which effectively converted fixed rate debt to floating rate debt. The use of these derivative instruments reduced interest expense by $35.6 million in 2002. (See Note 8 to the Consolidated Financial Statements "Hedging, Derivative Financial Instruments, and Fair Values" for a description of these instruments.) Interest expense in 2001 also reflects the reversal of $11.5 million in accrued interest expense resulting from the RICO class action settlement.
Net income from gas exploration and production operations decreased by $13.4 million, or $0.11 per share, in 2002 compared to 2001. These operations were adversely impacted by significantly lower realized gas prices in 2002, particularly in the first quarter. As previously mentioned, these operations recorded a non-cash impairment charge in 2001; excluding this charge, the comparative decrease in earnings was $39.6 million, or $0.30 per share.
Income tax expense generally reflects the level of pre-tax income for all periods reported. Further, during the year we finalized the valuation study related to the assets transferred to KeySpan resulting from the KeySpan/Long Island Lighting Company ("LILCO") business combination completed in May 1998. As a result, an adjustment to deferred taxes of $177.7 million was recorded to reflect a decrease in the tax basis of the assets acquired. Concurrent with this adjustment, KeySpan reduced current income taxes payable by $183.2 million, resulting in a $5.5 million income tax benefit. Income tax expense also reflects additional tax benefits of approximately $15 million resulting from the finalization of amended tax returns and the reversal of certain tax reserves.
Average common shares outstanding in 2002 increased by 2% compared to 2001 reflecting the re-issuance of shares held in treasury pursuant to dividend reinvestment and employee benefit plans. This increase in average common shares outstanding reduced earnings per share in 2002 by $0.06 compared to 2001. In January 2003, we received net proceeds of approximately $473 million from the issuance of 13.9 million shares of common stock. See the discussion under the caption "Capital Expenditures and Financing" for further information on this equity offering.
Earnings before interest and taxes ("EBIT") increased by $116.4 million in 2002 compared to last year. Comparative EBIT results were impacted by the items mentioned above, namely; (i) the discontinuation of goodwill amortization in 2002 of $49.6 million; (ii) EBIT losses of $137.8 million incurred by the Roy Kay companies in 2001 compared to losses of $10.8 million incurred in 2002; (iii) the recording of a non-cash pre-tax impairment charge of $42.0 million in 2001 to recognize the effect of lower wellhead prices; and (iv) the reversal, in 2001, of a previously recorded loss provision relating to the RICO class action settlement of $22.0 million. Offsetting these benefits to comparative EBIT results was a decrease in EBIT in 2002 from gas exploration and production operations resulting from a significant decline in average realized gas prices. (See "Review of Operating Segments" and Note 2 to the Consolidated Financial Statements "Business Segments" for a detailed discussion of EBIT results for each of our lines of business.)
Earnings from continuing operations less preferred stock dividends for the year ended December 31, 2001 decreased by $46.9 million, or $0.40 per share, compared to the same period in 2000. These comparative results were primarily driven by the items recorded in 2001 that were previously discussed.
Further, on November 8, 2000 we acquired all of the common stock of Eastern Enterprises ("Eastern") and EnergyNorth Inc. ("ENI") in a transaction accounted for as a purchase. As a result, comparisons in consolidated earnings, revenues and expenses between fiscal years 2001 and 2000 have been significantly affected by the addition of these operations. (See Note 1 to the Consolidated Financial Statements "Summary of Significant Accounting Policies".) As part of this transaction, in 2000 we recorded a $65.2 million pre-tax charge associated with early retirement and severance programs that were implemented upon the completion of the acquisitions. The after-tax effect of this charge on consolidated results was $41.1 million, or $0.31 per share.
Interest expense increased by $152.2 million, or 75% in 2001 compared to 2000, reflecting higher levels of debt outstanding, primarily related to: (i) $1.65 billion of long-term debt and $308.6 million of commercial paper issued to finance the acquisition of Eastern and ENI; (ii) debt assumed in the Eastern and ENI acquisition; (iii) $625 million of notes issued during the year, primarily used to repay short-term debt; (iv) debt incurred by KeySpan Canada, one of our Canadian subsidiaries; as well as (v) higher commercial paper borrowings during the year to satisfy seasonal working capital needs. As mentioned, we reversed $11.5 million of previously recorded interest expense relating to the RICO class action settlement during 2001, of which $9 million was recorded in 2000.
Income tax expense in 2001 generally reflects the lower level of pre-tax income compared to 2000. (See Note 3 to the Consolidated Financial Statements, "Income Taxes" for more information.) The decrease in preferred stock dividends in 2001 compared to 2000 resulted from the redemption, at maturity, of 14.5 million shares of preferred stock in the second quarter of 2000.
Average common shares outstanding in 2001 increased by 3% compared to 2000 reflecting the re-issuance of shares held in treasury pursuant to dividend reinvestment and employee benefit plans. This increase in average common shares outstanding reduced earnings per share in 2001 by $0.05 compared to 2000.
EBIT from continuing operations in 2001, after adjusting for the matters noted above, were substantially higher than such earnings for 2000. Our gas distribution operations benefited from the addition of the New England gas utilities for the entire year in 2001 compared to only two months in 2000, as well as from an increase in net margins due to continued gas sales growth, and cost saving synergies. Further, our gas exploration and production activities benefited from the combined effect of higher realized gas prices, primarily during the first quarter of 2001, and improved production volumes throughout the year. These benefits to EBIT from continuing operations were almost entirely offset by higher interest expense. In addition, during 2000 certain charges were incurred by our corporate and administrative areas that were not incurred in 2001, which resulted in a significant increase to comparative earnings. (See the discussion under the heading "Review of Operating Segments" for an analysis of comparative EBIT for each of our operating segments.)
On January 24, 2002, we announced that we had entered into an agreement to sell Midland Enterprises, LLC ("Midland"), KeySpan's inland marine barge business acquired in connection with the Eastern acquisition. In anticipation of this divestiture, which was completed on July 2, 2002, Midland's operations have been reported as discontinued for all periods. (See Note 9 to the Consolidated Financial Statements "Discontinued Operations" for further disclosure on the sale of Midland.) In the fourth quarter of 2001, an estimated loss on the sale of Midland, as well as an estimate for Midland's results of operations for the first six months of 2002 was recorded.
As a result of a change in the tax structure of this transaction, an additional after-tax loss of $19.7 million was recorded in 2002, primarily reflecting a provision for certain city and state taxes.
Financial Outlook for 2003
Consistent with our prior earnings guidance, and as reaffirmed in February 2003 following the announcement regarding the sale of a portion of our ownership in The Houston Exploration Company ("Houston Exploration"), our gas exploration and production subsidiary (as further discussed below), KeySpan's earnings for 2003 are forecasted to be approximately $2.45 to $2.60 per share, after giving effect to the sale of 13.9 million shares of common stock previously noted. Earnings from continuing core operations (defined for this purpose as all continuing operations other than gas exploration and production, less preferred stock dividends) are forecasted to be approximately $2.15 to $2.20 per share, while earnings from gas exploration and production operations are forecasted to be approximately $0.30 to $0.40 per share. The earnings forecast may vary significantly during the year due to, among other things, changing energy market and weather conditions. It should be noted that, starting in 2003, KeySpan will expense stock options granted to its employees in order to reflect all prospective compensation costs in earnings.
Consolidated earnings are seasonal in nature due to the significant contribution to earnings of our gas distribution operations. As a result, we expect to earn most of our annual earnings in the first and fourth quarters of our fiscal year and breakeven or marginally profitable earnings are anticipated to be achieved in the second and third quarters of our fiscal year.
Review of Operating Segments - ----------------------------
The following discussion of financial results achieved by our operating segments is presented on an EBIT basis. We use EBIT measures in our financial and business planning process to provide a reasonable assurance that our financial forecasts will provide, among other things, (i) shareholders with a competitive return on their investment, (ii) adequate earnings and cash flow to service debt; and (iii) adequate interest coverage to maintain or improve our credit ratings. Information concerning EBIT is presented as a measure of those financial results. EBIT should not be construed as an alternative to net income or cash flow from operating activities as determined by Generally Accepted Accounting Principles.
Gas Distribution
KeySpan Energy Delivery New York ("KEDNY") provides gas distribution service to customers in the New York City Boroughs of Brooklyn, Staten Island and a portion of Queens. KeySpan Energy Delivery Long Island ("KEDLI") provides gas distribution service to customers in the Long Island Counties of Nassau and Suffolk and the Rockaway Peninsula of Queens County. Four natural gas distribution companies - Boston Gas Company, Essex Gas Company, Colonial Gas Company and EnergyNorth Natural Gas, Inc., each doing business under the name KeySpan Energy Delivery New England ("KEDNE"), provide gas distribution service to customers in Massachusetts and New Hampshire.
The table below highlights certain significant financial data and operating statistics for the Gas Distribution segment for the periods indicated.
A MDTH is 10,000 therms and reflects the heating content of approximately one million cubic feet of gas. A therm reflects the heating content of approximately 100 cubic feet of gas. One billion cubic feet (BCF) of gas equals approximately 1,000 MDTH.
Net Revenues
Combined net gas revenues (revenues less the cost of gas sold and associated revenue taxes) from our gas distribution operations increased by $19.6 million, or 1.3%. Both the New York and New England based gas distribution operations were adversely impacted by the significantly warmer than normal weather experienced throughout the Northeastern United States during 2002, particularly during the first quarter. Based on heating degree days, weather for the twelve months ended December 31, 2002 was approximately 4%-7% warmer than normal and approximately 1%-3% colder than last year in the New York and New England service territories. However, weather during the heating season, January-March, was approximately 16%-19% warmer than normal, across our service territories. Our gas distribution operations historically earn approximately 60% of yearly EBIT during the January-March period.
During 2002, KEDNY and KEDLI, together, added approximately $40 million in gross gas load additions. The increased gas sales were generated from oil-to-gas space heating conversions, as well as from new construction. These load additions, however, were offset by declining usage per customer due to the extremely warm first quarter weather and the use of more efficient gas heating equipment. Additionally, the down-turn in the economy throughout the Northeastern United States had an adverse impact on gas consumption in 2002. As a result of these factors, net revenues from firm gas customers (residential, commercial and industrial customers) in our New York service territory decreased by $1.5 million in 2002 compared to last year. Included in net revenues are regulatory incentives that contributed a favorable $6.7 million to comparative net revenues.
Net revenues from firm gas customers in the New England service territory increased by $20.5 million in 2002 compared to last year, primarily as a result of approximately $24 million in gross gas load additions. Also included in net revenues are base rate adjustments totaling $10.0 million associated with Boston Gas Company's Performance Based Rate Plan ("PBR"). The largest component of this adjustment reflects the beneficial effect of a favorable ruling of the Massachusetts Supreme Judicial Court relating to the "accumulated inefficiencies" component of the productivity factor in the PBR. This ruling resulted in a benefit to comparative net margins of $6.3 million. (See "Regulation and Rate Matters" for a further discussion of this matter.) Offsetting, to some extent, these benefits to revenues are the adverse effects of declining usage per customer due to the extremely warm first quarter weather and the use of more efficient gas heating equipment. Additionally, the down-turn in the economy throughout the Northeastern United States had an adverse impact on gas consumption in 2002.
KEDNY and KEDLI each operate under utility tariffs that contain a weather normalization adjustment that significantly offsets variations in firm net revenues due to fluctuations in weather. These weather normalization adjustments resulted in an increase to net gas revenues of $22.3 million in 2002, but this did not fully mitigate the impact of the loss in revenues due to the extremely warm weather experienced during the first quarter. The New England-based gas distribution subsidiaries do not have weather normalization adjustments. To lessen, to some extent, the effect of fluctuations in normal weather patterns on KEDNE's results of operations and cash flows, weather derivatives are in place for the 2002/2003 winter heating season. Since weather during the fourth quarter of 2002 was 7% colder than normal in the New England service territory, we recorded a $3.3 million reduction to revenues to reflect the loss on these derivative transactions. (See Note 8 to the Consolidated Financial Statements "Hedging, Derivative Financial Instruments, and Fair Values" for further information).
Firm gas distribution rates in 2002, excluding gas cost recoveries, have remained substantially unchanged from last year in all of our service territories.
Total net gas revenues increased by $342.2 million or 30% in 2001 compared to 2000. The gas distribution operations of KEDNE added $296.8 million to this increase, while our New York based gas distribution operations accounted for the remaining $45.4 million increase. Net revenues from our firm gas customers increased by $343.1 million in 2001 compared to 2000. This increase was largely driven by the addition of KEDNE's gas distribution operations which accounted for $296.8 million of the increase. Our New York based gas distribution operations added $9.2 million to firm net revenues in 2001 through the addition of new gas customers and through our continuing efforts to convert residential and commercial customers from oil-to-gas for space heating purposes, primarily on Long Island. In addition, the comparative increase in firm net revenues in 2001 was favorably affected by the recovery of previously deferred property taxes, as well as regulatory incentives that added $13.3 million and $23.7 million, respectively, to the increase in firm net gas revenues in 2001. The related property tax expense is being amortized through operating taxes and therefore does not benefit EBIT.
In our large-volume heating and other interruptible (non-firm) markets, which include large apartment houses, government buildings and schools, gas service is provided under rates that are established to compete with prices of alternative fuel, including No. 2 and No. 6 grade heating oil. Net margins realized from these customers in 2002 are comparable to such margins realized last year. Net revenues in these markets in 2001 were slightly lower than sales to this market for 2000. The majority of these margins earned by KEDNE and KEDLI are returned to firm customers as an offset to gas costs.
We are committed to our expansion strategies initiated during the past few years. We believe that significant growth opportunities exist on Long Island and in the New England service territories. We estimate that on Long Island approximately 35% of the residential and multi-family markets, and approximately 55% of the commercial market currently use natural gas for space heating purposes. Further, we estimate that in the New England service territories approximately 50% of the residential and multi-family markets, and approximately 45% of the commercial market currently use natural gas for space heating purposes. We will continue to seek growth in all of our market segments through the expansion of the gas distribution system, as well as through the conversion of residential homes from oil-to-gas for space heating purposes and the pursuit of opportunities to grow multi-family, industrial and commercial markets.
Firm Sales, Transportation and Other Quantities
Total actual firm gas sales and transportation quantities remained consistent with last year. In the New York service territory, actual and weather normalized firm gas sales and transportation quantities decreased slightly in 2002 compared to 2001. In the New England services territories, firm gas sales and transportation quantities increased 4%, despite the warm first quarter weather, due to load additions.
Firm gas sales and transportation quantities increased by 27% during 2001, compared to 2000. The gas distribution operations of KEDNE, accounted for 73.9 MDTH, or 100% of the increase. Firm gas sales and transportation quantities from our New York based gas distribution operations decreased by 7% compared to 2000 as a result of warmer than normal weather. Weather was approximately 10% warmer than normal in 2001 and approximately 11% warmer than the prior year.
Weather normalized sales quantities in 2001 in our New York service territories were flat compared to 2000 due primarily to the adverse effect on consumption of extraordinarily high gas prices during the first quarter of 2001.
Net revenues are not affected by customers choosing to purchase their gas supply from other sources, since delivery rates charged to transportation customers generally are the same as the delivery component of rates charged to full sales service customers. Transportation quantities related to electric generation reflect the transportation of gas to KeySpan's electric generating facilities located on Long Island. Net revenues from these services are not material.
Other sales quantities include on-system interruptible quantities, off-system sales quantities (sales made to customers outside of our service territories) and related transportation. We have an agreement with Coral Resources, L.P. ("Coral"), a subsidiary of Shell Oil Company, under which Coral assists in the origination, structuring, valuation and execution of energy-related transactions on behalf of KEDNY and KEDLI. We also had a portfolio management contract with El Paso Energy Marketing, Inc. ("El Paso"), under which El Paso provided all of the city gate supply requirements at market prices and managed certain upstream capacity, underground storage and term supply contracts for KEDNE. Our agreement with El Paso expired on October 31, 2002 and our agreement with Coral expires on March 31, 2003. We have negotiated a new agreement with Entergy-Koch to replace the expired El Paso agreement. The new agreement with Entergy-Koch began on November 1, 2002 and extends through March 31, 2003. In anticipation of the expiration of the existing agreements, a request for proposal was sent to various portfolio managers. Upon evaluation of the bids, KeySpan will negotiate agreements for all of its gas distribution subsidiaries. It is anticipated that such agreements will become effective April 1, 2003.
Purchased Gas for Resale
The decrease in gas costs in 2002 compared to 2001 of $448.5 million, or 22%, reflects a decrease of 26% in the price per dekatherm of gas purchased, and a 1.0% increase in the quantity of gas purchased. The increase in gas costs in 2001 compared to 2000 of $714.3 million, or 55% primarily reflects the addition of KEDNE's operations for an entire year. KEDNE's operations accounted for $666.1 million of the increase. Fluctuations in utility gas costs associated with firm gas customers have no impact on operating results. The current gas rate structure of each of our gas distribution utilities includes a gas adjustment clause, pursuant to which variations between actual gas costs incurred and gas costs billed are deferred and refunded to or collected from customers in a subsequent period.
Operating Expenses
Operating expenses decreased by $11.2 million in 2002 compared to last year. Comparative operating expenses were significantly impacted by the discontinuation of goodwill amortization. As previously mentioned, in January 2002, we adopted Statement of Financial Accounting Standards ("SFAS") 142 "Goodwill and Other Intangible Assets," which required, among other things, the discontinuation of goodwill amortization. Goodwill amortization in the gas distribution segment for the twelve months ended December 31, 2001 was $35.6 million. Excluding the effects of this amortization, operating expenses increased by $24.4 million, or 3%, in 2002 compared to last year.
The increase in operating expense in 2002 is attributable, in part, to higher pension and other postretirement benefits which increased by approximately $25 million, net of amounts deferred and subject to regulatory true-ups, over the level incurred in 2001. The cost of these benefits has risen primarily as a result of lower actual returns on plan assets, as well as an increase in health care costs. Further, depreciation and amortization expense, excluding the 2001 goodwill amortization, has also increased as a result of the continued expansion of the gas distribution system.
Offsetting, to some extent, the increases in expenses noted above is a favorable $7.4 million adjustment to operating taxes recorded in 2002 related to the reversal of certain operating tax reserves established for the KeySpan/LILCO transaction and subsequent re-organization in May 1998. Further, we are realizing cost saving synergies as a result of early retirement and severance programs implemented in the fourth quarter of 2000. The early retirement portion of the program was completed in 2000, but the severance feature continued through 2002.
Operating expenses increased by $222.3 million, or 29%, in 2001 compared to 2000, due to the addition of the New England gas distribution operations, which added $289.1 million to operating expenses in 2001. This amount includes operations and maintenance costs of $170.6 million, depreciation and amortization charges of $91.0 million and general taxes of $27.5 million. Operating expenses related to our New York based gas distribution operations decreased in 2001 compared to 2000, as a result of cost savings synergies realized in 2001 and lower general and administrative costs being allocated to our New York operations as a result of a change in 2001 of the allocation methodology for these costs pursuant to the Securities and Exchange Commission's ("SEC") requirements under PUHCA. Further, in 2000 we recorded a charge of $41.8 million associated with early retirement and severance programs implemented upon the acquisition of Eastern and ENI.
Depreciation and amortization expense in 2001 reflects $35.6 million for the amortization of goodwill as previously noted, as well as continued property additions, and the amortization of certain costs that were previously deferred and were recovered through gas rates in 2001.
Other Matters
As previously mentioned, there remain significant growth opportunities in our Long Island and New England gas distribution service areas. The Northeast region represents a significant portion of the country's population and energy consumption. Gas sales growth and customer additions are critical to our earnings in the future. However, the beneficial effect of our growth initiatives may not be fully realized in the short-term since we will continue to make incremental investments in our gas distribution network and expand our promotional campaigns to optimize the long-term growth opportunities in our service territories.
To take advantage of the anticipated gas sales growth opportunities in our New York service territory, in 2000 we formed the Islander East Pipeline, LLC ("Islander East"), a limited liability company in which a KeySpan subsidiary and a subsidiary of Duke Energy Corporation each own a 50% equity interest. During 2002, Islander East received a certificate of public convenience and necessity from the Federal Energy Regulatory Commission ("FERC") to construct, own and operate a natural gas pipeline facility consisting of approximately 50 miles of interstate natural gas pipeline extending from Algonquin Gas Transmission Company's facilities in Connecticut, across the Long Island Sound and connecting with KEDLI's facilities on Long Island. Islander East has obtained all required permits in New York State for the construction of the facility. However, the State of Connecticut has issued a moratorium on the issuance of the permits relating to the construction of energy projects until June 2003. Islander East has therefore been unable to obtain the necessary permits from the State of Connecticut at this time. Islander East has also appealed a denial by the State of Connecticut of the coastal zone management permit to the U.S. Department of
Commerce and such appeal is currently pending. Assuming the timely receipt of approvals from the State of Connecticut, the Islander East pipeline is expected to begin operating by year-end 2004 and will transport 260,000 DTH daily to the Long Island and New York City energy markets, enough fuel to heat 600,000 homes, as well as allow us to further diversify the geographic sources of our gas supply. We are currently evaluating various options for the financing of this pipeline. (See the discussion under "Capital Expenditures and Financing" for more information on our financing plans for 2003.)
On December 12, 2002, we acquired Algonquin LNG, LP, the owner and operator of a 600,000 barrel FERC-regulated liquefied natural gas ("LNG") storage and receiving facility in Providence, Rhode Island, from Duke Energy for approximately $28 million. Algonquin LNG was renamed KeySpan LNG, L.P. and its largest customer is Boston Gas Company, which contracts for more than half of the facility's storage capacity.
Electric Services
The Electric Services segment primarily consists of subsidiaries that own and operate oil and gas fired electric generating plants in the borough of Queens (the "Ravenswood facility") and the counties of Nassau and Suffolk on Long Island. In addition, through long-term contracts of varying lengths, we manage the electric transmission and distribution ("T&D") system, the fuel and electric purchases, and the off-system electric sales for LIPA.
Selected financial data for the Electric Services segment is set forth in the table below for the periods indicated.
*Reflects the operations of the Ravenswood facility only.
Net Revenues
Total electric net revenues increased by $19.3 million for the twelve months ended December 31, 2002, compared to the same period in 2001. Net revenues in 2002 reflect net revenues of $17.3 million from our new Glenwood Landing and Port Jefferson electric "peaking" facilities located on Long Island. The Glenwood facility was placed in service on June 1, 2002, while the Port Jefferson facility was placed in service on July 1, 2002. These facilities add a combined 160 megawatts of generating capacity to KeySpan's electric generation portfolio. The capacity of and energy produced by these facilities are dedicated to LIPA under 25 year contracts.
Net revenues from the LIPA Agreements increased by $47.2 million or 6% in 2002, compared to last year. Included in revenues for 2002, are billings to LIPA for certain third party costs that were significantly higher than such billings last year. These revenues have minimal impact on earnings since we record a similar amount of costs in operating expense and we share any cost under-runs with LIPA. Excluding these third party billings, revenues for 2002 associated with the LIPA Agreements were comparable to such revenues last year. In addition, in 2002 we earned $16.0 million associated with non-cost performance incentives provided for under these agreements, compared to $16.2 million earned last year. (For a description of the LIPA Agreements, see "LIPA Agreements".)
Net revenues from the Ravenswood facility were $45.2 million, or 13%, lower in 2002, compared to 2001. Net revenues from capacity sales decreased 19% compared to last year, while margins associated with the sale of electric energy were basically flat. Comparative energy sales benefited from a 2% increase in the megawatt hours sold as a result of the hot summer weather offset, in part, by a reduction in "spark-spread" (the selling price of electricity less cost of fuel). Measured in cooling degree days, weather during the 2002 cooling season was approximately 7% warmer than last year.
The decrease in net revenues from capacity sales in 2002, was due, in part, to more competitive pricing by the electric generators that bid into the New York Independent System Operator ("NYISO") energy market which lowered capacity clearing prices by approximately 8% compared to last year. Further, the NYISO revised its methodology employed to determine the available supply of and demand for installed capacity that also had an adverse impact on the capacity market by reducing the capacity required to be purchased by load serving entities such as electric utilities. However, in September 2002, the NYISO recognized a flaw in its revised methodology. Since this flaw resulted in insufficient capacity being procured by the market, it was identified as a reliability concern. The NYISO corrected its methodology prior to the recent 2002/2003 winter auction to ensure sufficient capacity is procured. Elimination of the flaw ensures compliance with New York State Reliability Rules. The Ravenswood facility and the NYISO energy market should benefit from this correction since, as a result, load serving entities should procure sufficient capacity to maintain reliability for customers.
The rules and regulations for capacity, energy sales and the sale of certain ancillary services to the NYISO energy markets continue to evolve and the FERC has adopted several price mitigation measures that have adversely impacted earnings from the Ravenswood facility. Certain of these mitigation measures are still subject to rehearing and possible judicial review.
The final resolution of these issues and their effect on our financial position, results of operations and cash flows cannot be fully determined at this time. (See discussion under Market and Credit Risk Management Activities for a further discussion of these matters.)
Total electric net revenues increased slightly in 2001 compared to 2000. Net revenues from the Ravenswood facility decreased by $12.6 million, or 3%, reflecting lower realized energy prices and lower ancillary service revenues offset, in part, by effective hedging strategies. (Ancillary services include primarily spinning reserves and non-spinning reserves available to replace energy that is unable to be delivered due to the unexpected loss of a major energy source.) Further, capacity and energy sales quantities, as well as realized energy prices were adversely impacted by an increase in available capacity in New York City during 2001.
Revenues from the service agreements with LIPA increased by $22.7 million, or 3% in 2001 compared to 2000. Included in revenues in 2001 were billings to LIPA for certain third party capital costs that were significantly higher than such billings in 2000 primarily due to the construction of an underground transmission line to reinforce the electric system capacity on the South Fork of Long Island. As noted previously, these revenues had a minimal impact on net income. Excluding the third party billings, revenues in 2001 associated with the LIPA Agreements were comparable to such revenues earned during the prior year. In addition, in 2001 we earned $16.2 million associated with non-cost performance incentives provided for under these agreements, compared to $15.4 million earned in 2000.
Operating Expenses
Operating expenses in 2002 were consistent with the prior year. However, included in comparative operating expenses is an increase in third party capital costs that are fully recoverable from LIPA, as noted previously. Excluding the increase in these costs, operating expenses have decreased by approximately $48 million in 2002 compared to 2001. In addition to third party capital costs, LIPA reimburses KeySpan for costs directly incurred by KeySpan in providing service to LIPA, subject to the sharing provisions in the LIPA Agreements. These reimbursements are based on predetermined estimates of operating costs. Variations between certain actual operating costs incurred (i.e. postretirement costs and property taxes) and the predetermined estimates are deferred and refunded to or collected from LIPA in subsequent periods. As a result of an adjustment related to this "true-up", certain pension and other postretirement costs were approximately $23 million lower in 2002 compared to 2001. Further, during 2002, we settled certain outstanding issues with LIPA and the Consolidated Edison Company of New York, Inc. ("Consolidated Edison") that resulted in a $20.3 million decrease to comparative operating expenses. The increase in depreciation and amortization expense, as indicated in the above table, primarily reflects depreciation associated with the two new electric peaking facilities.
Operating expenses increased by $44.5 million, or 5% in 2001, compared to 2000, primarily as a result of the increase in third party costs previously noted and higher allocated charges for corporate and administrative costs due to changes in our allocation methodology as prescribed under PUHCA.
Other Income and Deductions
The increases in Other Income in 2002 and 2001 are due primarily to inter-company interest income earned by subsidiaries within the Electric Services segment. For the most part, the various subsidiaries of KeySpan do not maintain separate cash balances. Rather, liquid assets are maintained in a money pool, from and to which subsidiaries can either borrow or lend. Inter-company interest expense is charged to "borrowers", while inter-company interest income is earned by "lenders". In all years presented in the above table, the subsidiaries within the Electric Services segment have been net "lenders" to the money pool and, accordingly, have earned inter-company interest income. Interest rates associated with money pool borrowings are generally the same as KeySpan's short-term borrowing rate. All inter-company interest income and expense is eliminated for consolidated financial reporting purposes.
Other Matters
As previously mentioned, both the Glenwood Landing and Port Jefferson electric generating peaking facilities are fully operational. Short-term financing was used for the construction of these facilities, but various financing options to permanently finance these facilities are being explored. (See the discussion under "Capital Expenditures and Financing" for more information on our financing plans for 2003.) Further, construction has begun on a new 250 MW combined cycle generating facility at the Ravenswood facility site. The new facility is expected to commence operations in late 2003. The capacity and energy produced from this plant are anticipated to be sold into the NYISO energy markets. We are also progressing through the siting process before the New York State Board on Electric Generation Siting and the Environment with a proposal to build a similar 250 MW combined cycle electric generating facility on Long Island. On February 4, 2003, an Examiners' Recommended Decision was issued recommending the granting of a certificate of environmental capability and public need for this proposed facility. In addition, as part of our growth strategy, we continually evaluate the possible acquisition of additional generating facilities in the Northeast. However, we are unable to predict when or if any such facilities will be acquired and the effect any such acquired facilities will have on our financial condition, results of operations or cash flows.
Under the Generation Purchase Right Agreement ("GPRA"), LIPA had the right for a one-year period, beginning on May 28, 2001, to acquire all of our Long Island based generating assets formerly owned by LILCO at fair market value at the time of the exercise of such right. By agreement dated March 29, 2002, LIPA and KeySpan amended the GPRA to provide for a new six-month option period ending on May 28, 2005. The other terms of the option reflected in the GPRA remain unchanged. See the discussion under the heading "Electric Services - Revenue Mechanisms, Generation Purchase Right Agreement" for further details.
In late 2002, LIPA announced, and we acknowledged, that during 2001 and 2002 we had made errors in reporting LIPA's electric system requirements, resulting in an overestimation of LIPA's unbilled revenue. LIPA and KeySpan have continued to review and audit the reporting of electric system requirements for 2002 and earlier periods, and have determined that, in addition to the 2002 and 2001 overestimation, unbilled revenues for prior periods back to May 1998 were slightly underestimated. Based upon the review, the total overestimation in unbilled revenues amounted to approximately $65 million.
The LIPA revenue estimation error did not have an impact on LIPA's electric rates charged to its customers nor to its cash balances. We do not believe that the LIPA revenue estimation error will have any material adverse impact on the various agreements with LIPA or on our financial or operating performance.
Energy Services
The Energy Services segment primarily includes companies that provide services through three lines of business to clients located within the New York City metropolitan area, including New Jersey and Connecticut, as well as in Rhode Island, Pennsylvania, Massachusetts and New Hampshire. The lines of business are: Home Energy Services; Business Solutions; and Fiber Optic Services.
The table below highlights selected financial information for the Energy Services segment.
Comparative EBIT results for 2002 compared to 2001 were significantly impacted by losses incurred by one of our subsidiaries. In 2001, we discontinued the general contracting activities related to the former Roy Kay companies, with the exception of completion of work on then existing contracts, based upon our view that the general contracting business is not a core competency of these companies. (See Note 10 to the Consolidated Financial Statements "Roy Kay Operations" for a more detailed discussion.) For the year-ended December 31, 2001, we incurred an EBIT loss of $137.8 million associated with the operations of the former Roy Kay companies. The Roy Kay EBIT results reflect costs related to the discontinuation of the general contracting activities of these companies, costs to complete work on certain loss construction projects, and operating losses. We are completing the contracts entered into by the former Roy Kay companies and, for the twelve months ended December 31, 2002, we incurred EBIT losses of $10.8 million reflecting increases in the estimates of and costs to complete these contracts, and general and administrative expenses.
Excluding the results of the former Roy Kay companies, the Energy Services segment reflected an increase in EBIT of $6.1 million in 2002 compared to last year. Revenues, excluding the Roy Kay companies, decreased by $180.4 million in 2002, while the cost of fuel decreased by $201.0 million. These declines, which for the most part offset each other, reflect the operations of our gas and electric marketing subsidiary. In 2002, this subsidiary began to focus its marketing efforts on higher net margin customers and as a result has substantially decreased its customer base.
EBIT results for the Business Solutions group of companies, which provide mechanical contracting, plumbing, engineering and consulting services to commercial, institutional, and industrial customers, improved by $22.3 million in 2002 compared to 2001. This increase reflects additional work being performed on the backlog of projects existing at year-end last year and the absence of $6 million in losses incurred on four major projects in 2001. A backlog of approximately $514 million presently exists, which is 20% below the December 31, 2001 level.
Offsetting the positive contribution to EBIT by the Business Solutions group of companies, was a decrease of $15.4 million associated with the Home Energy Services group of companies. These companies provide residential and small commercial customers with service and maintenance of appliances, as well as the retail marketing of natural gas and electricity. Contributing to the decrease in EBIT from Home Energy Services were the following factors: (i) the continued adverse impact of the down-turn in the economy; (ii) the non-renewal of appliance service contracts due to the warm first quarter weather; (iii) costs associated with the closing of a service center; and (iv) an increase in the reserve for bad debts. Comparative EBIT results in 2002 benefited from the elimination of goodwill amortization, which for 2001 amounted to $8.2 million.
We continue to re-align and/or combine a number of our service centers in this segment in order to reduce operating and general and administrative costs, realize synergy savings and improve profitability.
Excluding the operations of the Roy Kay companies, EBIT for this segment was $19.0 million lower in 2001 compared to 2000, reflecting costs incurred to complete certain loss construction contracts and higher corporate allocated costs as a result of PUHCA requirements (See "Securities and Exchange Commission Regulation" for further discussion.)
Energy Investments
The Energy Investment segment consists of our gas exploration and production operations, certain other domestic and international energy-related investments, as well as certain technology related investments. Our gas exploration and production subsidiaries are engaged in gas and oil exploration and production, and the development and acquisition of domestic natural gas and oil properties. At December 31, 2002, these investments consisted of our 66% ownership interest in Houston Exploration, as well as our wholly-owned subsidiary, KeySpan Exploration and Production, LLC. In line with our strategy of exploring the monetization or divesture of certain non-core assets, in October 2002 we monetized a portion of our assets in the joint venture drilling program with Houston Exploration that was initiated in 1999. We received $26.5 million in cash from Houston Exploration for 18.6 BCFe of estimated proved and probable reserves. The proceeds were used to pay down short-term debt; there was no earnings impact from this transaction. Further, in February 2003, we reduced our ownership interest in Houston Exploration to approximately 56% through the repurchase, by Houston Exploration, of 3 million shares of common stock owned by KeySpan. The net proceeds of approximately $79 million received in connection with this repurchase were used to pay down short-term debt.
This segment also consists of KeySpan Canada; our 20% interest in the Iroquois Gas Transmission System LP ("Iroquois"); and our 50% interest in Premier Transmission Limited and 24.5% interest in Phoenix Natural Gas Limited, both located in Northern Ireland.
Selected financial data and operating statistics for our gas exploration and production activities is set forth in the following table for the periods indicated.
*Operating income above represents 100% of our gas exploration and production subsidiaries' results for the periods indicated. Earnings before interest and taxes, however, is adjusted to reflect minority interest.
Earnings Before Interest and Taxes
The decrease in EBIT of $24.4 million in 2002 compared to last year, reflects a 24% reduction in average realized gas prices (average wellhead price received for production including hedging gains and losses), which lowered comparative revenues, as well as an increase in operating expenses associated with higher levels of production and a higher depletion rate. The adverse effect on revenues resulting from the decline in average realized gas prices was partially offset by an increase of 13% in production volumes.
The average realized gas price for 2002 was 105% of the average unhedged natural gas price, resulting in revenues that were $16.4 million higher than revenues that would have been achieved if derivative financial instruments had not been in place during 2002. Houston Exploration hedged approximately 64% of its 2002 production, principally through the use of costless collars. The average realized gas price for 2001 was 104% of the average unhedged natural gas price, resulting in revenues that were $12.9 million higher than revenues that would have been achieved if derivative financial instruments had not been employed during 2001. These derivative instruments are designed to provide Houston Exploration with a more predictable cash flow, as well as to reduce its exposure to fluctuations in natural gas prices. At December 31, 2002 Houston Exploration
had derivative positions in place to hedge approximately 67% of its estimated 2003 production and approximately 20% of its estimated 2004 production, again principally through the use of costless collars. Depending upon market conditions, Houston Exploration may enter into additional derivative positions during 2003 to hedge a larger portion of its estimated 2004 production. (See Note 8 to the Consolidated Financial Statements, "Hedging, Derivative Financial Instruments, and Fair Value" for further information.)
The depreciation, depletion and amortization rate was $1.68 per Mcf for the twelve months ended December 31, 2002, compared to $1.49 per Mcf for the same period in 2001, reflecting higher finding and development costs together with the addition of fewer new reserves.
In 2001, our gas exploration and production subsidiaries recorded a non-cash impairment charge of $42.0 million to recognize the effect of lower wellhead prices on their valuation of proved gas reserves. Our share of this charge, which includes our joint venture ownership interest and minority interest, was $26.2 million after-tax. Excluding this charge, the comparative decrease in EBIT for 2002 compared to 2001 would have been greater. (See Note 1 to the Consolidated Financial Statements "Summary of Significant Accounting Policies", Item F for more information on this charge.)
The increase in EBIT for 2001 compared to 2000 reflects a significant increase in gas exploration and production revenues, partially offset by an increase in operating expenses associated with higher production volumes. Revenues for 2001 benefited from the combined effect of a 17% increase in production volumes and a 25% increase in average realized gas prices. As noted above, 2001 EBIT results also reflect the recording of a non-cash impairment charge to recognize the effect of lower wellhead prices on the valuation of proved gas reserves.
As previously mentioned, the average realized gas price in 2001 was 104% of the average unhedged natural gas price, resulting in revenues that were $12.9 million higher than revenues that would have been achieved if derivative financial instruments had not been employed during 2001. The average realized gas price in 2000 was 85% of the average unhedged natural gas price, resulting in revenues that were $46.3 million lower than revenues that would have been achieved if derivative financial instruments had not been in place during 2000.
Natural gas prices continue to be volatile and the risk that we may be required to record an impairment charge on our full cost pool again in the future increases when natural gas prices are depressed or if we have significant downward revisions in our estimated proved reserves.
The table below indicates the net proved reserves of our gas exploration and production subsidiaries for the periods indicated.
Selected financial data for our other energy-related investments is set forth in the following table for the periods indicated.
The increase in EBIT in 2002 compared to last year primarily reflects lower comparative losses associated with certain technology-related investments. Further, higher EBIT from our Northern Ireland investments were, for the most part, offset by lower EBIT realized by KeySpan Canada. KeySpan Canada experienced lower per unit sales prices, as well as lower quantities of sales of natural gas liquids in 2002, as a result of generally lower oil prices. The pricing of natural gas liquids is directly related to oil prices.
Overall, EBIT from these operations and investments in 2001 remained relatively constant compared to 2000. EBIT growth from our investments in KeySpan Canada, Northern Ireland and certain operations purchased as part of our acquisition of Eastern were offset, in part, by losses incurred from certain technology-related investments. Further, in the fourth quarter of 2000, we acquired the remaining 50% interest in KeySpan Canada, making us the sole owner. Results of operations associated with KeySpan Canada have been fully consolidated since the additional investment, whereas prior to this transaction, KeySpan Canada's results were reported as equity income in Other Income and (Deductions).
We do not consider certain businesses contained in the Energy Investments segment to be part of our core asset group. We have stated in the past that we may sell or otherwise dispose of all or a portion of our non-core assets. Based on current market conditions, we cannot predict when, or if, any such sale or disposition may take place, or the effect that any such sale or disposition may have on our financial position, results of operations or cash flows.
Allocated Costs
As previously mentioned, we are subject to the jurisdiction of the SEC under PUHCA. As part of the regulatory provisions of PUHCA, the SEC regulates various transactions among affiliates within a holding company system. In accordance with the regulations of PUHCA and the New York State Public Service Commission requirements, we have service companies that provide: (i) traditional corporate and administrative services; (ii) gas and electric transmission and distribution systems planning, marketing, and gas supply planning and procurement; and (iii) engineering and surveying services to subsidiaries. Revised allocation methodologies, approved by the SEC, have been in use since 2001 to allocate certain service company costs to affiliates.
These non-operating subsidiaries incurred certain costs in 2002 primarily related to general corporate expenses that were not allocated to the various operating subsidiaries. These expenses combined with inter-company money pool eliminations (that were higher in 2002 compared to 2001) resulted in an EBIT loss of $27.6 million in 2002. In 2001, these non-operating subsidiaries realized EBIT of $34.0 million, primarily related to the $22.0 million benefit associated with the favorable appellate court decision regarding the RICO class action settlement, previously mentioned.
During 2000, certain costs were incurred by our corporate and administrative subsidiaries that were not allocated to other operating segments, and were not incurred in 2001. These unallocated costs had a significant effect on comparative EBIT results between the two years and are as follows: (i) a charge of $10.0 million for a contribution to the KeySpan Foundation (a not-for-profit philanthropic foundation that makes donations to local charitable community organizations); (ii) an impairment charge of $23.2 million associated with our equity investment in certain technology-related activities; (iii) branding expenses and other costs related to the integration of the Eastern and ENI companies of $24.6 million; and (iv) early retirement and severance charges of $23.1 million. Item (i) is reflected in "Other Income and Deductions" and all other items are reflected in "Operations and Maintenance expense" in the Consolidated Statement of Income for 2000. Further, during 2001 we: (i) recorded the benefit associated with the favorable appellate court decision regarding the RICO class action settlement at our corporate holding company level, as mentioned previously, which increased EBIT by $22.0 million; and (ii) settled certain outstanding issues associated with LIPA and reallocated certain administrative costs which combined added $15.8 million to EBIT. The net result of the preceding items contributed to the increase in EBIT of $137.0 million in 2001 associated with our non-operating subsidiaries.
Liquidity
Cash flow from operations decreased by $81.1 million, or 9%, in 2002 compared to 2001. Operating cash flow from gas exploration and production activities was adversely impacted by significantly lower realized gas prices in 2002. Further, cash flow from operations in 2002 reflects the funding of the minimum pension obligation related to our New England subsidiaries of $80 million. These adverse effects on cash flow were partially offset by the termination of two interest rate swap agreements that resulted in a favorable operating cash flow benefit of approximately $23.4 million, as well as lower income tax payments. State and federal tax payments were lower in 2002, compared to last year, as KeySpan is currently in a refund position with regard to such taxes. (See Note 8 to the Consolidated Financial Statements, "Hedging, Derivative Financial Instruments, and Fair Value" for an explanation of the interest rate hedges.)
Cash flow from operations for 2001 reflects strong results from gas distribution and electric operations, as well as significant contributions from gas exploration and production activities. Further, the decrease in natural gas prices in the second half of 2001 also had a positive impact on cash flow from operations. As a result of the seasonal nature of gas distribution operations, we incur significant cash expenditures during the summer and early fall to purchase and inject gas into our storage facilities. We recover these costs in subsequent periods as the gas is removed from storage and delivered to our customers, primarily during the winter, for space heating purposes. Significant cash flows are generated during the first two quarters of the subsequent fiscal year as we receive payment from customers for such heating season use. Due to the significant increase in gas prices during the summer and early fall of 2000, gas cost recoveries for the first two quarters of 2001 were greater than such recoveries for the same period in 2000. Further, gas prices during the third and fourth quarters of 2001 were lower than the prior year, resulting in lower cash expenditures required to maintain natural gas inventory in storage. Also, as stated earlier, gas exploration and production activities benefited from higher gas prices during the first two quarters of 2001 compared to 2000. These enhancements to cash flow were partially offset by an increase in interest payments due to higher levels of outstanding debt.
A substantial portion of consolidated revenues are derived from the operations of businesses within the Electric Services segment, that are largely dependent upon two large customers - LIPA and the NYISO. Accordingly, our cash flows are dependent upon the timely payment of amounts owed to us by these customers.
In 2002, KeySpan renewed its existing 364-day revolving credit agreement with a commercial bank syndicate of 16 banks totaling $1.3 billion, a reduction from the previous $1.4 billion facility. The credit facility is used to back up the $1.3 billion commercial paper program. The fees for the facility are subject to a ratings-based grid, with an annual fee of .075% on the total amount of the revolving facility. The credit agreement allows for KeySpan to borrow using several different types of loans; specifically, Eurodollar loans, Adjustable Bank Rate ("ABR") loans, or competitively bid loans. Eurodollar loans are based on the Eurodollar rate plus a margin of 42.5 basis points for loans up to 33% of the facility, and an additional 12.5 basis points for loans over 33% of the total facility. ABR loans are based on the greater of the Prime Rate, the base CD rate plus 1%, or the Federal Funds Effective Rate plus 0.5%. Competitive bid loans are based on bid results requested by KeySpan from the lenders. We do not anticipate borrowing against this facility; however, if the credit rating on our commercial paper program were to be downgraded, it may be necessary to do so.
The credit facility contains certain affirmative and negative operating covenants, including restrictions on KeySpan's ability to mortgage, pledge, encumber or otherwise subject its property to any lien, as well as certain financial covenants that require us to, among other things, maintain a consolidated indebtedness to consolidated capitalization ratio of no more than 66%, a decrease from the 68% ratio required under the previous credit facility.
Under the terms of the credit facility, KeySpan's debt-to-total capitalization ratio reflects 80% equity treatment for the MEDS Equity Units issued in May 2002. In addition, the $425 million Ravenswood Master Lease is treated as debt. At December 31, 2002, consolidated indebtedness, as calculated under the terms
of the credit facility, was 64.6% of consolidated capitalization. This ratio was reduced to 59.8% by the sale of 13.9 million shares of common stock in January 2003 as discussed below. Violation of this covenant could result in the termination of the credit facility and the required repayment of amounts borrowed thereunder, as well as possible cross defaults under other debt agreements. (See discussion under "Capital Expenditures and Financing" for an explanation of the MEDS Equity Units and the Ravenswood Master Lease.)
The credit facility also requires that net cash proceeds from the sale of significant subsidiaries be applied to reduce consolidated indebtedness. Further, an acceleration of indebtedness of KeySpan or one of its subsidiaries for borrowed money in excess of $25 million in the aggregate, if not annulled within 30 days after written notice, would create an event of default under the Indenture dated November 1, 2000, between KeySpan Corporation and the JPMorganChase Bank as Trustee. At December 31, 2002, KeySpan was in compliance with all covenants.
At December 31, 2002, we had cash and temporary cash investments of $170.6 million. During 2002, we repaid $132.8 million of commercial paper and, at December 31, 2002, $915.7 million of commercial paper was outstanding at a weighted average annualized interest rate of 1.52%. We had the ability to borrow up to an additional $384.3 million at December 31, 2002 under the commercial paper program.
During 2002, Houston Exploration entered into a new revolving credit facility with a commercial banking syndicate that replaced the previous $250 million revolving credit facility. The new facility provides Houston Exploration with an initial commitment of $300 million, which can be increased at its option to a maximum of $350 million with prior approval from the banking syndicate. The new credit facility is subject to borrowing base limitations, initially set at $300 million and will be re-determined semi-annually. Up to $25 million of the borrowing base is available for the issuance of letters of credit. The new credit facility matures on July 15, 2005, is unsecured and ranks senior to all existing debt of Houston Exploration.
Under the Houston Exploration credit facility, interest on base rate loans is payable at a fluctuating rate, or base rate, equal to the sum of (a) the greater of the federal funds rate plus 0.50% or the bank's prime rate plus (b) a variable margin between 0% and 0.50%, depending on the amount of borrowings outstanding under the credit facility. Interest on fixed loans is payable at a fixed rate equal to the sum of (a) a quoted reserve adjusted LIBOR rate, plus (b) a variable margin between 1.25% and 2.00%, depending on the amount of borrowings outstanding under the credit facility.
Financial covenants require Houston Exploration to, among other things, (i) maintain an interest coverage ratio of at least 3.00 to 1.00 of earnings before interest, taxes and depreciation ("EBITDA") to cash interest; (ii) maintain a total debt to EBITDA ratio of not more than 3.50 to 1.00; and (iii) hedge no more than 70% of natural gas production during any 12-month period. At December 31, 2002, Houston Exploration was in compliance with all financial covenants.
During 2002, Houston Exploration borrowed $79 million under its credit facility and repaid $71 million. At December 31, 2002, $152 million of borrowings remained outstanding at a weighted average annualized interest rate of 3.42%.
Also, $0.4 million was committed under outstanding letters of credit obligations. At December 31, 2002, $147.6 million of borrowing capacity was available. KeySpan Canada has two revolving credit facilities with financial institutions in Canada. Repayments under these agreements totaled approximately US $26.1 million during 2002. At December 31, 2002, approximately US $150.9 million was outstanding at a weighted average annualized interest rate of 3.23%. KeySpan Canada currently has available borrowings of approximately US $55.8 million. These revolving credit agreements have been extended through January 2004. An event of default would exist under these credit facilities if KeySpan, as guarantor on the facilities, falls below investment grade rating or falls below A3 or A- at a time when its consolidated indebtedness, as measured using the same criteria employed under KeySpan's credit facility, is greater than 66% of consolidated capitalization or its cash flow to interest expense is less than 2.25 to 1.00. At December 31, 2002, KeySpan and KeySpan Canada were in compliance with all covenants.
On January 17, 2003, KeySpan sold 13.9 million shares of common stock to the open market and realized net proceeds of approximately $473 million. All shares were offered by KeySpan pursuant to the effective shelf registration statement filed with the SEC. Net proceeds from the equity sale were used initially to pay down commercial paper and reduced our debt to capitalization ratio by approximately 480 basis points. Consolidated indebtedness at December 31, 2002, as calculated under the terms of KeySpan's credit facility and, adjusted for this equity offering was 59.8% of consolidated capitalization. In addition, as previously noted, we used the net proceeds of approximately $79 million received in February 2003 in connection with the partial monetization of Houston Exploration to repay short-term debt. The anticipated impact of additional common shares outstanding due to the equity offering offset by the expected interest savings from the repayments of commercial paper is anticipated to result in dilution of approximately 7% per share in 2003.
In connection with the KeySpan/LILCO transaction, KeySpan and certain of its subsidiaries issued promissory notes to LIPA to support certain debt obligations assumed by LIPA. At December 31, 2002 the remaining principal amount of promissory notes issued to LIPA was approximately $600 million. In an effort to mitigate the dilutive effect of the equity issuance, in February 2003, KeySpan notified LIPA of its intention to redeem approximately $447 million aggregate principal amount of such promissory notes at the applicable redemption prices plus accrued and unpaid interest through the dates of redemption. It is anticipated that such redemption will take place before the end of the first quarter of 2003. Under these promissory notes, KeySpan is required to obtain letters of credit to secure its payment obligations if its long-term debt is not rated at least in the "A" range by at least two nationally recognized statistical rating agencies.
The ratings on our long-term debt have remained unchanged since December 31, 2001. The following table represents the ratings of our long-term debt at December 31, 2002. Currently, these ratings are all on stable outlook with the exception of Standard & Poor's rating on KeySpan which is on negative outlook.
We satisfy our seasonal working capital requirements primarily through internally generated funds and the issuance of commercial paper. We believe that these sources of funds are sufficient to meet our seasonal working capital needs. In addition, we currently use treasury stock to satisfy the requirements of our dividend reinvestment and employee benefit plans.
Capital Expenditures and Financing
Construction Expenditures
The table below sets forth our construction expenditures by operating segment for the periods indicated:
Construction expenditures related to the Gas Distribution segment are primarily for the renewal and replacement of mains and services and for the expansion of the gas distribution system. Construction expenditures for the Electric Services segment reflect costs to: (i) maintain our generating facilities; (ii) expand the Ravenswood facility; and (iii) construct the new Long Island generating facilities as previously noted. Construction expenditures related to the Energy Investments segment primarily reflect costs associated with gas exploration and production activities. These costs are related to the exploration and development of properties primarily in Southern Louisiana and in the Gulf of Mexico. Expenditures also include development costs associated with the joint venture with Houston Exploration, as well as costs related to KeySpan Canada's gas processing facilities.
At December 31, 2002, total expenditures associated with the siting, permitting and construction of the Ravenswood expansion project, the siting, permitting and procurement of equipment for the Long Island 250MW combined cycle generation plant, and the siting and permitting of the Islander East pipeline project were $234.6 million.
Construction expenditures for 2003 are estimated to be $1.1 billion, including estimated expenditures for the construction of the new electric generating facilities. The amount of future construction expenditures is reviewed on an ongoing basis and can be affected by timing, scope and changes in investment opportunities.
Financing
At December 31, 2001, KeySpan had authorization under PUHCA to issue up to $1 billion of securities and had an existing $1 billion shelf registration statement on file with the SEC, with $500 million available for issuance. In February 2002, we filed a new shelf registration statement for the issuance of an additional $1.2 billion of securities, thereby giving us the ability to issue up to $1.7 billion of debt, equity or various forms of preferred stock.
In May 2002, we issued $460 million of MEDS Equity Units at 8.75% consisting of a three-year forward purchase contract for our common stock and a six-year note. The purchase contract commits us three years from the date of issuance of the MEDS Equity Units to issue and the investors to purchase a number of shares of our common stock based on a formula tied to the market price of our common stock at that time. The 8.75% coupon is composed of interest payments on the six-year note of 4.9% and premium payments on the three-year equity forward contract of 3.85%. These instruments have been recorded as long-term debt on our Consolidated Balance Sheet, but rating agencies, as well as our credit facility, consider between 80% to 100% of the instruments as equity for purposes of calculating debt-to-total capitalization ratios. (See Note 6 to the Consolidated Financial Statements "Long-Term Debt" for further details on the MEDS Equity Units.)
The issuance of the MEDS equity units utilized $920 million of our financing authority under both the shelf registration and the PUHCA financing authority. Both the $460 million six-year note and the $460 million forward equity contract are considered current issuances for these purposes. On December 6, 2002 the SEC issued an order increasing the available financing authority under PUHCA to an aggregate $780 million. Following the recent common stock offering previously mentioned and shares expected to be issued for employee benefit and dividend reinvestment plans, we have approximately $40 million available for the issuance of new securities under our current PUHCA authorization. However, the issuance of securities in connection with the redemption of existing securities (including the promissory notes discussed previously) is permitted under our PUHCA authorization notwithstanding the foregoing limit. We intend to seek authorization to issue additional securities in the near term.
In May 2002, Colonial Gas Company repaid $15 million of its 6.81% Series A First Mortgage Medium -Term Notes. These Notes would have matured on May 19, 2027, but the holder of the Notes elected to exercise a put option to redeem the Notes early.
As previously noted, we issued commercial paper to finance the construction of our two Long Island peaking-power plants, and we will continue to finance the construction of the new 250MW combined cycle generating facility at the Ravenswood facility site, as well as the Islander East Pipeline, through the issuance of commercial paper.
During 2003, we intend to issue approximately $150 million of either taxable or tax-exempt long-term debt securities, the proceeds of which, it is anticipated, will be used to re-pay the outstanding commercial paper related to the construction of our two Long Island peaking-power plants. We also may issue an additional $200 to $300 million of medium-term or long-term debt in 2003 to refinance existing indebtedness. We will continue to evaluate our capital structure and financing strategy for 2003 and beyond. We believe that our current sources of funding (i.e., internally generated funds, the issuance of additional securities as noted above, and the availability of commercial paper), together with the cash proceeds from the recent equity offering, are sufficient to meet our anticipated working capital needs for the foreseeable future.
Off-Balance Sheet Arrangements
Guarantees
KeySpan has fully and unconditionally guaranteed $525 million of medium- term notes issued by KEDLI under KEDLI's current shelf registration, as well as a US $130 million revolving credit agreement associated with KeySpan Canada. Both the medium-term notes and outstanding borrowings under the credit agreement are reflected on the Consolidated Balance Sheet.
Further, at December 31, 2002 KeySpan has guaranteed: (i) $153.9 million of surety bonds associated with certain construction projects currently being performed by subsidiaries within the Energy Services segment; (ii) certain supply contracts, margin accounts and purchase orders for certain subsidiaries in the aggregate amount of $65.7 million; (iii) the obligations of KeySpan Ravenswood LLC, the lessee under the $425 million Master Lease Agreement associated with the Ravenswood facility; and (iv) $64.4 million of subsidiary letters of credit. KeySpan has also guaranteed $25 million associated with a non-affiliated company's line of credit. These guarantees are not recorded on the Consolidated Balance Sheet. The guarantee of the KEDLI medium-term notes expires in 2010, while the other guarantees have terms that do not extend beyond 2005; however the Master Lease Agreement can be extended to 2009. At this time, we have no reason to believe that our subsidiaries will default on their current obligations. However, we cannot predict when or if any defaults may take place or the impact such defaults may have on our consolidated results of operations, financial condition or cash flows. (See Note 7 to the Consolidated Financial Statements, "Contractual Obligations, Financial Guarantees and Contingencies" for a description of the leasing arrangement associated with the Ravenswood Master Lease Agreement and additional information regarding KeySpan's guarantees.)
Variable Interest Entity
We have an arrangement with a variable interest entity through which we lease a portion of the Ravenswood facility. We acquired the Ravenswood facility, in part, through the variable interest entity from Consolidated Edison on June 18, 1999 for approximately $597 million. In order to reduce the initial cash requirements, we entered into a lease agreement (the "Master Lease") with a variable interest, unaffiliated financing entity that acquired a portion of the facility, or three steam generating units, directly from Consolidated Edison and leased it to a KeySpan subsidiary. The variable interest unaffiliated financing
entity acquired the property for $425 million, financed with debt of $412.3 million (97% of capitalization) and equity of $12.7 million (3% of capitalization). Monthly lease payments equal the monthly interest expense on the debt securities. The Master Lease currently qualifies as an operating lease for financial reporting purposes while preserving our ownership of the facility for federal and state income tax purposes.
The initial term of the Master Lease expires on June 20, 2004 and may be extended until June 20, 2009. In June 2004, we have the right to either purchase the facility at the original acquisition cost of $425 million plus the present value of the lease payments that would otherwise have been paid through June 20, 2009, or terminate the Master Lease and dispose of the facility. If the Master Lease is terminated, KeySpan has guaranteed an amount equal to 83% of the original acquisition cost plus the present value of the lease payments that would have otherwise been paid through June 20, 2009. In June 2009, when the Master Lease terminates, we may purchase the facility in an amount equal to the original acquisition cost, subject to adjustments, or surrender the facility to the lessor. If we elect not to purchase the facility, the lessor will sell the property; we have guaranteed the lessor 84% of the original acquisition cost.
In January 2003, The Financial Accounting Standards Board (the "Board") issued Interpretation No. 46 ("FIN 46"), "Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51". This Interpretation would require us to, among other things, consolidate this variable interest entity for the first interim period ending after June 15, 2003, so long as the current variable interest structure remains intact. This Interpretation will require us to classify the Master Lease as debt on the Consolidated Balance Sheet at an amount generally equal to fair market value. As previously mentioned, under the terms of our credit facility the Master Lease is considered debt in the ratio of debt-to-total capitalization and therefore, implementation of FIN 46 will have no impact on our credit facility. Further, we will be required to record an asset on the Consolidated Balance Sheet for an amount equal to the fair market value of the leased assets. However, such amount cannot exceed the amount of debt to be recorded for the variable interest entity. At this time, we believe that the fair market value of the leased assets is in excess of the original acquisition cost. The Interpretation contains certain other provisions that we will be required to implement in 2003 and such provisions may impact future earnings. (See Note 7 to the Consolidated Financial Statements "Contractual Obligations, Financial Guarantees and Contingencies" for additional information on the Master Lease and Interpretation No. 46 implementation issues.)
Contractual Obligations
KeySpan has certain contractual obligations related to its outstanding long-term debt, outstanding credit facility borrowings, outstanding commercial paper borrowings, operating and capital leases, and demand charges associated with certain commodity purchases. KeySpan's outstanding short-term and long-term debt issuances are explained in more detail in Note 6 to the Consolidated Financial Statements "Long-Term Debt". KeySpan's operating and capital leases, as well as its demand charges are more fully detailed in Note 7 to the Consolidated Financial Statements "Contractual Obligations, Financial Guarantees and Contingencies". The table below reflects maturity schedules for KeySpan's contractual obligations at December 31, 2002:
Discussion of Critical Accounting Policies and Assumptions
In preparing our financial statements, the application of certain accounting policies requires difficult, subjective and/or complex judgments. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the impact of matters that are inherently uncertain. Actual effects on our financial position and results of operations may vary significantly from expected results if the judgments and assumptions underlying the estimates prove to be inaccurate. The critical accounting policies requiring such subjectivity are discussed below.
Percentage-of-Completion
Percentage-of-completion accounting is the prescribed method of accounting for long-term construction type contracts in accordance with Generally Accepted Accounting Principles and, accordingly, the method used for revenue recognition by the Energy Services segment. Percentage-of-completion is measured principally by comparing the percentage of costs incurred to date for each contract to the estimated total costs for each contract at completion. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Application of percentage-of-completion accounting results in the recognition of costs and estimated earnings in excess of billings on uncompleted contracts (recorded within the Consolidated Balance Sheet) which arise when revenues have been recognized but the amounts cannot be billed under the terms of the contracts. Such amounts are recoverable from customers based on various measures of performance, including achievement of certain milestones, completion of specified units or completion of the contract. Due to uncertainties inherent within estimates employed to apply percentage-of-completion accounting, it is possible that estimates will be revised as project work progresses. Changes in estimates resulting in additional future costs to complete projects can result in reduced margins or loss contracts. Application of percentage-of-completion accounting requires that the impact of those revised estimates be reported in the consolidated financial statements prospectively.
Valuation of Goodwill
KeySpan records goodwill on purchase transactions, representing the excess of acquisition cost over the fair value of net assets acquired. In testing for goodwill impairment under SFAS 142, significant reliance is placed upon estimated future cash flows requiring broad assumptions and significant judgment by management. Cash flow estimates are determined based upon future commodity prices, customer rates, customer demand, operating costs, rate relief from regulators, customer growth and other items. A change in the fair value of our investments could cause a significant change in the carrying value of goodwill. While we believe that our assumptions are reasonable, actual results may differ from our projections. The assumptions used to measure the fair value of our investments are the same as those used by us to prepare yearly operating segment and consolidated earnings and cash flow forecasts. In addition, these assumptions are used to set yearly budgetary guidelines.
Under SFAS 142, goodwill is deemed impaired if the fair value of the reporting unit's assets is less than the carrying value of those assets including goodwill. It was determined that KeySpan's financial reporting segments are virtually the same as the reporting unit levels as defined in SFAS 142.
For those segments with goodwill, the following amounts were evaluated using the standards set forth by SFAS 142 through December 31, 2002.
- ------------------------------------------------------------------- (In Thousands of Dollars) - ------------------------------------------------------------------- Reporting Unit Gas Distribution $ 1,592,510 Energy Services 142,121 Energy Investments and other 55,120 - ------------------------------------------------------------------- Total Goodwill $ 1,789,751 - -------------------------------------------------------------------
The majority of the goodwill associated with the Gas Distribution unit resulted from the November 2000 acquisition of Eastern and ENI. For purposes of determining goodwill impairment, the fair value of the entire Gas Distribution segment is evaluated against the carrying value of the entire unit. Some of the major factors that were considered in determining the fair value of the Gas Distribution unit included assumptions regarding the growth in revenues, earnings before interest, taxes, depreciation and amortization, and the weighted average cost of capital.
For the initial implementation of SFAS 142, the fair value of each of the reporting units exceeded the carrying value and no impairment charge was necessary. The fair value for the reporting units was evaluated based on the present value of anticipated cash flows.
As permitted under SFAS 142, we can rely on our previous valuations for the annual impairment testing provided that the following criteria for each reporting unit are met: (a) the assets and liabilities that make up the reporting unit have not changed significantly since the most recent fair value determination; and (b) the most recent fair value determination resulted in an amount that exceeded the carrying amount of the reporting unit by a substantial margin.
In the case of the Gas Distribution and the Energy Investments segment, the above criteria have been met and no further evaluation was required. In regard to the Energy Services segment, criteria (b) was not met since the initial fair value valuation did not exceed the carrying value by an amount deemed by us to be substantial. However, our annual test was performed in the fourth quarter of 2002 which verified that no impairment charge was deemed necessary. KeySpan will continue to monitor the goodwill associated with this reporting unit.
Accounting for the Effects of Rate Regulation on Gas Distribution Operations
The financial statements of the Gas Distribution segment reflect the ratemaking policies and orders of the NYPSC, the New Hampshire Public Utilities Commission ("NHPUC"), and the Massachusetts Department of Telecommunications and Energy ("DTE").
Four of our six regulated gas utilities (KEDNY, KEDLI, Boston Gas Company and EnergyNorth Natural Gas, Inc.) are subject to the provisions of SFAS 71, "Accounting for the Effects of Certain Types of Regulation." This statement recognizes the actions of regulators, through the ratemaking process, to create future economic benefits and obligations affecting rate-regulated companies.
In separate merger-related orders issued by the DTE, the base rates charged by Colonial Gas Company and Essex Gas Company have been frozen at their current levels for a ten-year period ending 2009. Due to the length of these base rate freezes, the Colonial and Essex Gas Companies had previously discontinued the application of SFAS 71.
SFAS 71 allows for the deferral of expenses and income on the consolidated balance sheet as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the rate setting process in a period different from the period in which they would have been reflected in the consolidated statements of income of an unregulated company. These deferred regulatory assets and liabilities are then recognized in the consolidated statement of income in the period in which the amounts are reflected in rates.
Rate regulation is undergoing significant change as regulators and customers seek lower prices for utility service and greater competition among energy service providers. In the event that regulation significantly changes the opportunity for us to recover costs in the future, all or a portion of our regulated operations may no longer meet the criteria for the application of SFAS 71. In that event, a write-down of our existing regulatory assets and liabilities could result. If we were unable to continue to apply the provisions of SFAS 71 for any of our rate regulated subsidiaries, we would apply the provisions of SFAS 101 "Regulated Enterprises - Accounting for the Discontinuation of Application of FASB Statement No. 71." We estimate that the write-off of all our net regulatory assets at December 31, 2002 could result in a charge to net income of $230.1 million or $1.63 per share, which would be classified as an extraordinary item. In management's opinion, our regulated subsidiaries that currently are subject to the provisions of SFAS 71 will continue to be subject to SFAS 71 for the foreseeable future.
As is further discussed under the caption "Regulation and Rate Matters", the rate plans previously in effect for KEDNY, KEDLI and Boston Gas Company have all expired. The continued application of SFAS 71 to record the activities of these subsidiaries is contingent upon the actions of regulators with regard to future rate plans. We anticipate filing a base rate case and a performance based rate plan for Boston Gas Company in the second quarter of 2003. Further, we are currently evaluating various options that may be available to us including, but not limited to, proposing new plans for KEDNY and KEDLI. The ultimate resolution of any future rate plans could have a significant impact on the application of SFAS 71 to these entities and, accordingly, on our financial position, results of operations and cash flows. However, management believes that currently available facts support the continued application of SFAS 71 and that all regulatory assets and liabilities are recoverable or refundable through the regulatory environment.
Pension and Other Postretirement Benefits
As discussed in Note 4 of the Consolidated Financial Statements, "Postretirement Benefits", KeySpan participates in both non-contributory defined benefit pension plans, as well as other post-retirement benefit ("OPEB") plans (collectively "postretirement plans"). KeySpan's reported costs of providing pension and OPEB benefits are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. Pension and OPEB costs (collectively "postretirement costs") are impacted by actual employee demographics, the level of contributions made to the plans, earnings on plan assets, and health care cost trends. Changes made to the provisions of these plans may also impact current and future postretirement costs. Postretirement costs may also be significantly affected by changes in key actuarial assumptions, including, anticipated rates of return on plan assets and the discount rates used in determining the postretirement costs and benefit obligations.
The discount rate used for our postretirement benefits at December 31, 2002 was 6.75%. Our discount rate assumption is based upon the current investment yield associated with rating agency indices that have high quality long-term corporate bonds.
For 2002, the assumed long-term return on our postretirement plans' assets was 8.5%. In selecting an assumed rate of return, we consider past performance and economic forecasts for the types of investments held by the plans. The actual 10-year compound rate of return, net of all expenses, for the KeySpan postretirement plans are greater than 8.5%. In addition, in eight of the last 10 years, actual returns have been greater than 8.5%. Our postretirement plans' assets presently consist of approximately 65% equity, 33% fixed income/bonds and 2% cash. In an effort to maximize plan performance, actual asset allocation will fluctuate from year to year depending on the then current economic environment. Based upon the historical performance of equity investments over time, our asset allocation, and our investment strategy, the assumed long-term rate of return appears reasonable.
Our health care cost trend assumptions are developed based on historical cost data, the near-term outlook and an assessment of likely long-term trends. The salary growth assumptions reflect our long-term actual experience and future and near-term outlook.
Actual results that differ from our assumptions are accumulated and amortized over ten years.
Certain gas distribution subsidiaries are subject to SFAS 71, and, as a result, changes in postretirement expenses are deferred for future recovery from or refund to gas sales customers. Further, changes in postretirement expenses associated with subsidiaries that service the LIPA Agreements are also deferred for future recovery from or refund to LIPA. As a result of these deferrals, we estimate that the actual impact of postretirement expense to KeySpan's Consolidated Statement of Income is approximately 50% of the otherwise actuarially determined expense.
The year-end December 31, 2002 assumed discount rate used to determine postretirement obligations was 6.75%. A 25 basis point increase or decrease in the assumed year-end discount rate would have had no impact on 2002 expense. However, a 25 basis point decrease in the assumed year-end discount rate would result in the recording of an additional minimum pension liability. Therefore, a year-end discount rate of 6.50% would have required an additional $76.4 million debit to Other Comprehensive Income ("OCI"), net of tax and deferrals noted previously. A year-end discount rate of 7.00% would have reduced the charge to OCI by a net $8.8 million.
At January 1, 2002, the assumed discount rate used to determine postretirement obligations was 7.0%. A 25 basis point increase or decrease in the assumed discount rate at the beginning of the year would have impacted 2002 expense by approximately $4.2 million, net of tax and deferrals.
In 2002, the expected rate of return on plan assets was 8.50%. A 25 basis point increase or decrease in the return on plan assets would have impacted 2002 expense by approximately $2.0 million, net of tax and deferrals.
Historically, we have funded our pension plans in excess of the amount required to satisfy minimum ERISA funding requirements. At December 31, 2002, we had a funding balance in excess of the ERISA minimum funding requirements and as a result KeySpan will not be required to make any contribution to its pension plans in 2003. However, although we have presently exceeded ERISA funding requirements, our pension plans, on an actuarial basis, are currently underfunded. Future funding requirements are heavily dependent on actual return on plan assets. Therefore, if the actual return on plan assets continues to be significantly below the expected returns, we may elect to fund the pension plans in 2003.
Full Cost Accounting
Our gas exploration and production subsidiaries use the full cost method to account for their natural gas and oil properties. Under full cost accounting, all costs incurred in the acquisition, exploration, and development of natural gas and oil reserves are capitalized into a "full cost pool". Capitalized costs include costs of all unproved properties, internal costs directly related to natural gas and oil activities, and capitalized interest.
Under full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of future net revenues, discounted at 10%, plus the lower of cost or fair value of unproved properties less income tax effects (the "ceiling limitation"). A quarterly ceiling test is performed to
evaluate whether the net book value of the full cost pool exceeds the ceiling limitation. If capitalized costs (net of accumulated depreciation, depletion and amortization) less deferred taxes are greater than the discounted future net revenues or ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders' equity in the period of occurrence and typically results in lower depreciation, depletion and amortization expense in future periods. Once incurred, a write-down is not reversible at a later date.
The ceiling test is calculated using natural gas and oil prices in effect as of the balance sheet date, held constant over the life of the reserves. Our gas exploration and production subsidiaries use derivative financial instruments that qualify for hedge accounting under SFAS 133 to hedge against the volatility of natural gas prices. In accordance with current SEC guidelines, these derivatives are included in the estimated future cash flows in the ceiling test calculation. In calculating the ceiling test at December 31, 2002, our subsidiaries estimated that a full cost ceiling "cushion" existed, whereby the carrying value of the full cost pool was less that the ceiling limitation. No writedown is required when a cushion exists. Natural gas prices continue to be volatile and the risk that a write down to the full cost pool will be required increases when natural gas prices are depressed or if there are significant downward revisions in estimated proved reserves.
Natural gas and oil reserve quantities represent estimates only. Under full cost accounting, reserve estimates are used to determine the full cost ceiling limitation as well as the depletion rate. Houston Exploration estimates its proved reserves and future net revenues using sales prices estimated to be in effect as of the date it makes the reserve estimates. Natural gas prices, which have fluctuated widely in recent years, affect estimated quantities of proved reserves and future net revenues. Any estimates of natural gas and oil reserves and their values are inherently uncertain, including many factors beyond our control. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based upon actual production, results of future development and exploration activities, prevailing natural gas and oil prices, operating costs and other factors, which revision may be material. Reserve estimates are highly dependent upon the accuracy of the underlying assumptions. Actual future production may be materially different from estimated reserve quantities and the differences could materially affect future amortization of natural gas and oil properties.
Valuation of Derivative Instruments
We employ derivative instruments to hedge a portion of our exposure to commodity price risk and interest rate risk, to partially hedge the cash flow variability associated with our electric energy and capacity sales from the Ravenswood facility, as well as to economically hedge certain other commodity exposures. In addition, KeySpan Canada has used swap instruments to lock-in the purchase price on the purchase of electricity needed to operate its gas processing plants.
All of our derivative instruments, except for certain weather derivatives, meet the SFAS 133 definition of a derivative. For those derivative instruments designated as cash flow hedges, changes in the market value of substantially all of our derivatives are recorded in Other Comprehensive Income, (in line with effectiveness measurements) and are not recorded through earnings until the derivative positions are settled. Further, none of KeySpan's derivative instruments qualify as "energy trading contracts" as defined by current accounting literature.
When available, quoted market prices are used to record a contract's fair value. However, market values for certain derivative contracts may not be readily available or determinable. A number of our commodity related derivative instruments are exchange traded and, accordingly, fair value measurements are generally based on standard New York Mercantile Exchange ("NYMEX") quotes. We use industry-published indices, NYISO location zone indices, as well as other local published indices to value contracts for commodities that are not exchange traded, such as No. 6 grade fuel oil and electricity. The fair value of our electric capacity hedges is based on published NYISO capacity bidding prices. Further, if no active market exists for a commodity, fair values may be based on pricing models.
For collar transactions relating to natural gas sales associated with our gas exploration and production subsidiaries, we use standard NYMEX quotes, and published volatility with Black- Scholes valuations to calculate the fair value of these instruments.
All fair value measurements, whether calculated using standard NYMEX quotes or other valuation techniques, are subjective and subject to fluctuations in commodity prices, interest rates and overall economic market conditions and, as a result, our fair value measurements may not be precise and can fluctuate significantly from period to period.
The table below summarizes the sources of fair value for cash-flow derivative instruments that qualify for hedge accounting treatment at December 31, 2002.
During 2002, we also had interest rate swap agreements in which approximately $1.3 billion of fixed rate debt was effectively converted to floating rate debt. The fair values of these derivative instruments were provided to us by our counter-parties and represent the present value of estimated future cash-flows based on a forward interest rate curve for the life of the derivative instrument.
Additionally, we use derivative financial instruments to reduce cash flow variability associated with the purchase price for a portion of future natural gas purchases for our regulated gas distribution activities. Since these derivative instruments are employed to reduce variability of the purchase price of natural gas to be sold to regulated firm gas sales customers, the accounting for these derivative instruments is subject to SFAS 71. At December 31, 2002, these instruments had a fair value of $4.8 million and were valued using, primarily, standard NYMEX quotes. These derivative instruments will be settled in 2003. Further, certain contracts for the physical purchase of natural gas for our regulated firm gas sales customers can no longer be exempted as normal purchases from the requirements of SFAS 133. At December 31, 2002, these contracts had a fair value of $1.2 million. The fair value for these contracts was determined using matrix-pricing models based on contracts with similar terms and risks.
KeySpan also has a small number of derivative financial instruments that meet the SFAS 133 definition of a derivative but do not qualify for hedge accounting treatment. Further, these instruments do not qualify as "energy trading contracts" as defined by current accounting literature. We use NYMEX futures to economically hedge the cash flow variability associated with the purchase of fuel for a portion of our fleet vehicles. KeySpan Canada has a portfolio of financially-settled natural gas collars and natural gas liquid swap transactions. Finally, our retail gas and electric marketing subsidiary has bought options to economically hedge the cash flow variability associated with a portion of expected future natural gas purchases. At December 31, 2002, these instruments, all of which expire in 2003, had an unfavorable net mark-to-market value of $0.4 million, which was recorded to earnings. We use standard NYMEX quotes, local published commodity indices, and prices provided by external sources to value these instruments.
See Note 8 to the Consolidated Financial Statements "Hedging, Derivative Financial Instruments and Fair Values" for a further description of all our derivative instruments.
Dividends
We are currently paying a dividend at an annual rate of $1.78 per common share. Our dividend policy is reviewed annually by the Board of Directors. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors. Based on currently foreseeable market conditions, we intend to maintain the dividend at the $1.78 level.
Pursuant to NYPSC orders, the ability of KEDNY and KEDLI to pay dividends to KeySpan is conditioned upon maintenance of a utility capital structure with debt not exceeding 55% and 58%, respectively, of total utility capitalization. In addition, the level of dividends paid by both utilities may not be increased from current levels if a 40 basis point penalty is incurred under the customer service performance program. At the end of KEDNY's and KEDLI's rate years (September 30, 2002 and November 30, 2002, respectively), the ratio of debt to total utility capitalization was 42% and 52%, respectively. Additionally, we have met the requisite customer service performance standards. Our corporate and financial activities and those of each of our subsidiaries (including their ability to pay dividends to us) are also subject to regulation by the SEC. (For additional information, see the discussion under the heading "Securities and Exchange Commission Regulation").
Regulation and Rate Matters
Gas Distribution
By orders dated February 5, 1998 and April 14, 1998, the NYPSC approved the KeySpan/LILCO business combination and established gas rates for both KEDNY and KEDLI. Pursuant to the orders, $1 billion of efficiency savings, excluding gas costs, attributable to operating synergies that are expected to be realized over the ten-year period following the combination, were allocated to customers, net of transaction costs.
Effective May 29, 1998, KEDNY's base rates to core customers were reduced by $23.9 million annually. In addition, KEDNY is subject to an earnings sharing provision pursuant to which it was required to credit core customers with 60% of any utility earnings up to 100 basis points above certain threshold return on equity levels over the term of the rate plan (other than any earnings associated with discrete incentives) and 50% of any utility earnings in excess of 100 basis points above such threshold levels. The threshold level for the rate year ended September 30, 2002 was 13.25%. KEDNY slightly exceeded the threshold return on equity for the rate year ended September 30, 2002. On September 30, 2002, KEDNY's rate agreement with the NYPSC expired. Under the terms of the agreement, the then current gas distribution rates and all other provisions, including the earnings sharing provision (at the 13.25% threshold level), remain in effect until changed by the NYPSC. At this time, we are currently evaluating various options that may be available to us regarding KEDNY's rates, including but not limited to, proposing a new rate plan.
The 1998 orders also required KEDLI to reduce base rates to its customers by $12.2 million annually effective February 5, 1998 and by an additional $6.3 million annually effective May 29, 1998. KEDLI is subject to an earnings sharing provision pursuant to which it is required to credit to firm customers 60% of any utility earnings in any rate year up to 100 basis points above a return on equity of 11.10% and 50% of any utility earnings in excess of a return on equity of 12.10%. KEDLI did not earn above its threshold return level in its rate year ended November 30, 2002. On November 30, 2000, KEDLI's rate agreement with the NYPSC expired. Under the terms of the agreement, the gas distribution rates and all other provisions, including the earnings sharing provision, will remain in effect until changed by the NYPSC. At this time, we are currently evaluating various options that may be available to us regarding KEDLI's rate plan, including but not limited to, proposing a new rate plan.
We expect current gas distribution rates for KEDNY and KEDLI to remain in effect through 2003.
Boston Gas Company, Colonial Gas Company and Essex Gas Company operations are subject to Massachusetts's statutes applicable to gas utilities. Rates for gas sales and transportation service, distribution safety practices, issuance of securities and affiliate transactions are regulated by the DTE.
Boston Gas Company's gas rates for local distribution service are governed by a five-year performance-based rate plan approved by the DTE in 1996 (the "Plan"). Under the Plan, Boston Gas Company's rates for local distribution were recalculated annually to reflect inflation for the previous 12 months, and reduced by a productivity factor of 1%. The productivity factor has been the subject of a remand proceeding at the DTE. With respect to this appeal, on March 7, 2002, the Massachusetts Supreme Judicial Court ruled in favor of Boston Gas Company and reduced the productivity factor from 1.0% to .5%. Further, the plan contains a margin sharing mechanism, whereby 25% of earnings in excess of a 15% return on equity are passed back to customers. Similarly, ratepayers absorb 25% of any shortfall below a 7% return on equity. The Plan expired on October 31, 2002.
On March 27, 2002, we filed notice, as required, with the DTE that we may file a base rate case and a performance based rate plan for the Boston Gas Company to replace the plan that expired on October 31, 2002. On May 21, 2002, we filed with the DTE a request to extend the existing performance based rate plan for an additional term of one year. This request was denied by the DTE in early September 2002. As a result, we anticipate filing a base rate case and a performance based rate plan for the Boston Gas Company in the second quarter of 2003, to be effective in the fourth quarter of 2003.
In connection with the Eastern acquisition of Colonial Gas Company in 1999, the DTE approved a merger and rate plan that resulted in a ten year freeze of base rates to Colonial Gas Company's firm customers. The base rate freeze is subject only to certain exogenous factors, such as changes in tax laws, accounting changes, or regulatory, judicial, or legislative changes. The Office of the Attorney General appealed the DTE's order to the Supreme Judicial Court, which appeal is still pending. Due to the length of the base rate freeze, Colonial Gas Company discontinued its application of SFAS 71 "Accounting for the Effects of Certain Types of Regulation". Essex Gas Company is also under a ten-year base rate freeze and has also discontinued its application of SFAS 71.
EnergyNorth Natural Gas, Inc.'s base rates continue as set by the NHPUC in 1993.
Securities and Exchange Commission Regulation
KeySpan and its subsidiaries are subject to the jurisdiction of the SEC under PUHCA. The rules and regulations under PUHCA generally limit the operations of a registered holding company to a single integrated public utility system, plus additional energy-related businesses. In addition, the principal regulatory provisions of PUHCA: (i) regulate certain transactions among affiliates within a holding company system including the payment of dividends by such subsidiaries to a holding company; (ii) govern the issuance, acquisition and disposition of securities and assets by a holding company and its subsidiaries; (iii) limit the entry by registered holding companies and their subsidiaries into businesses other than electric and/or gas utility businesses; and (iv) require SEC approval for certain utility mergers and acquisitions.
The SEC's order issued on November 8, 2000, in connection with our acquisition of Eastern and ENI as amended on December 6, 2002 and February 14, 2003, provides us with, among other things, authorization to do the following through December 31, 2003 (the "Authorization Period"): (a) subject to an aggregate amount of $5.8 billion, (i) maintain existing financing agreements, (ii) issue
and sell up to $2.2 billion of additional securities in compliance with certain defined parameters, (iii) issue additional guarantees and other forms of credit support in an aggregate amount of $2.0 billion at any time in addition to any such securities, guarantees and credit support outstanding or existing as of November 8, 2000, and (iv) amend, renew, extend, supplement or replace any of the foregoing; (b) issue shares of common stock or reissue shares of common stock held in treasury under dividend reinvestment and stock-based management incentive and employee benefit plans; (c) maintain existing and enter into additional hedging transactions with respect to outstanding indebtedness in order to manage and minimize interest rate costs; (d) invest up to $2.2 billion in exempt wholesale generators; and (e) pay dividends out of capital and unearned surplus as well as paid-in-capital with respect to certain subsidiaries, subject to certain limitations.
In addition, we have committed that during the Authorization Period, our common equity will be at least 30% of our consolidated capitalization and each of our utility subsidiaries' common equity will be at least 30% of such entity's capitalization. At December 31, 2002 our consolidated common equity was 33% of our consolidated capitalization, including commercial paper, and each of our utility subsidiaries common equity was at least 35% of its respective capitalization.
Electric Services - Revenue Mechanisms
LIPA Agreements
KeySpan, through certain of its subsidiaries, provides services to LIPA under the following agreements:
Management Services Agreement ("MSA")
A KeySpan subsidiary manages the day-to-day operations, maintenance and capital improvements of the T&D system. LIPA exercises control over the performance of the T&D system through specific standards for performance and incentives. In exchange for providing the services, we earn a $10 million annual management fee and are operating under a contract, which provides certain incentives and imposes certain penalties based upon performance. We have reached an agreement with LIPA to extend the MSA for 31 months through 2008, as discussed under the heading "Generation Purchase Right Agreement" below. Annual service incentives or penalties exist under the MSA if certain targets are achieved or not achieved. In addition, we can earn certain incentives for budget underruns associated with the day-to-day operations, maintenance and capital improvements of LIPA's T&D system. These incentives provide for us to (i) retain 100% on the first $5 million in annual budget underruns, and (ii) retain 50% of additional annual underruns up to 15% of the total cost budget, thereafter all savings accrue to LIPA. With respect to cost overruns, we will absorb the first $15 million of overruns, with a sharing of overruns above $15 million. There are certain limitations on the amount of cost sharing of overruns. To date, we have performed our obligations under the MSA within the agreed upon budget guidelines and we are committed to providing on-going services to LIPA within the established cost structure. However, no assurances can be given as to future operating results under this agreement.
Power Supply Agreement ("PSA")
A KeySpan subsidiary sells to LIPA all of the capacity and, to the extent requested, energy conversion services from our existing Long Island based oil and gas-fired generating plants. Sales of capacity and energy conversion services are made under rates approved by the FERC. Under the terms of the PSA, rates will be reestablished for the contract year commencing January 1, 2004 by recalculating the revenue requirement underlying those rates. We anticipate submitting to the FERC a rate filing reflecting the recalculated revenue requirement in the Fall of 2003. We are unable to predict the outcome of that proceeding at this time. Rates charged to LIPA include a fixed and variable component. The variable component is billed to LIPA on a monthly basis and is dependent on the number of megawatt hours dispatched. LIPA has no obligation to purchase energy conversion services from us and is able to purchase energy conversion services on a least-cost basis from all available sources consistent with existing interconnection limitations of the T&D system. The PSA provides incentives and penalties that can total $4 million annually for the maintenance of the output capability and the efficiency of the generating facilities. The PSA runs for a term of fifteen years, with LIPA having the option to renew the PSA for an additional fifteen year term.
Energy Management Agreement ("EMA")
The EMA provides for a KeySpan subsidiary to procure and manage fuel supplies on behalf of LIPA to fuel the generating facilities under contract to it and perform off-system capacity and energy purchases on a least-cost basis to meet LIPA's needs. In exchange for these services we earn an annual fee of $1.5 million. In addition, we arrange for off-system sales on behalf of LIPA of excess output from the generating facilities and other power supplies either owned or under contract to LIPA. LIPA is entitled to two-thirds of the profit from any off-system energy sales. In addition, the EMA provides incentives and penalties that can total $7 million annually for performance related to fuel purchases and off-system power purchases. The EMA covers a period of fifteen years to 2013 for the procurement of fuel supplies and eight years to 2006 for off-system management services.
Under these agreements, we are required to obtain a letter of credit in the aggregate amount of $60 million supporting our obligations to provide the various services if our long-term debt is not rated in the "A" range by a nationally recognized rating agency.
Generation Purchase Right Agreement ("GPRA")
Under the GPRA, LIPA had the right for a one-year period beginning on May 28, 2001, to acquire all of our Long Island based generating assets formerly owned by LILCO at fair market value at the time of the exercise of such right.
By agreement dated March 29, 2002, LIPA and KeySpan amended the GPRA to provide for a new six month option period ending on May 28, 2005. The other terms of the option reflected in the GPRA remained unchanged. In return for providing LIPA an extension of the GPRA, KeySpan has been provided with a corresponding extension of 31 months for the MSA to the end of 2008.
The extension is the result of a new initiative established by LIPA to work with KeySpan and others to review Long Island's long-term energy needs. LIPA and KeySpan will jointly analyze new energy supply options including re-powering existing plants, renewable energy technologies, distributed generation, conservation initiatives and retail competition. The extension allows both LIPA and KeySpan to explore alternatives to the GPRA including re-powering existing facilities, the sale of some or all of KeySpan's plants to LIPA, or the sale of some or all of these plants to other investor-owned entities.
KeySpan Glenwood and Port Jefferson Energy Centers
KeySpan Glenwood Energy Center LLC and KeySpan Port Jefferson Energy Center LLC have entered into 25 year Power Purchase Agreements with LIPA (the "PPAs"). Under the terms of the PPAs, these subsidiaries sell capacity, energy conversion services and ancillary services to LIPA. Both plants are designed to produce 79.9 megawatts. Under the PPAs, LIPA pays a monthly capacity fee, which guarantees full recovery of each plant's construction costs, as well as an appropriate rate of return on investment. The PPAs also obligate LIPA to pay for each plant's costs of operation and maintenance. These costs are billed on a monthly estimated basis and are subject to true-up for actual costs incurred.
Ravenswood Facility
We currently sell capacity, energy and ancillary services associated with the Ravenswood facility through a bidding process into the NYISO energy markets on both a day ahead and a real time basis. We also have the ability to enter into bilateral transactions to sell all or a portion of the energy produced by the Ravenswood facility to Load Serving Entities, i.e. entities that sell to end-users or to brokers and marketers.
Environmental Matters
KeySpan is subject to various federal, state and local laws and regulatory programs related to the environment. Ongoing environmental compliance activities, which have not been material, are charged to operation and maintenance activities. We estimate that the remaining cost of our manufactured gas plant ("MGP") related environmental cleanup activities, including costs associated with the Ravenswood facility, will be approximately $192.9 million and we have recorded a related liability for such amount. We have also recorded an additional $39.2 million liability, representing the estimated environmental cleanup costs related to a former coal tar processing facility. As of December 31, 2002, we have expended a total of $70.5 million on environmental investigation and remediation activities. (See Note 7 to the Consolidated Financial Statements, "Contractual Obligations, Guarantees and Contingencies" for a further explanation of these matters.)
Market and Credit Risk Management Activities
Market Risk: We are exposed to market risk arising from potential changes in one or more market variables, such as energy commodity price risk, interest rate risk, foreign currency exchange rate risk, volumetric risk due to weather or other variables. Such risk includes any or all changes in value whether caused by commodity positions, asset ownership, business or contractual obligations, debt covenants, exposure concentration, currency, weather, and other factors regardless of accounting method. We manage our exposure to changes in market prices using various risk management techniques for non-trading purposes, including hedging through the use of derivative instruments, both exchange-traded and over-the-counter contracts, purchase of insurance and execution of other contractual arrangements. (See Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The market risks discussed below relate to our derivative financial instruments. We have derivative financial instruments and derivative commodity contracts that are exposed to potential losses due to adverse changes in interest rates, commodity prices and weather. Interest rate risk generally is related to our outstanding debt and financing activities. The majority of our commodity price risk and volumetric risk due to weather relate to our Ravenswood merchant electric operations, exploration and production operations and our gas distribution operations. We use derivative contracts to manage price risk and volumetric risk exposure from these activities.
Financially-Settled Commodity Derivative Instruments: From time to time KeySpan has utilized derivative financial instruments, such as futures, options and swaps, for the purpose of hedging exposure to commodity price risk and to hedge the cash flow variability associated with a portion of peak electric energy sales.
Houston Exploration has utilized collars, as well as over-the-counter ("OTC") swaps to hedge the cash flow variability associated with forecasted sales of a portion of its natural gas production. As of December 31, 2002, Houston Exploration has hedged approximately 67% and 20% of its estimated 2003 and 2004 production, respectively. Further, Houston Exploration may enter into additional derivative positions for 2003 and 2004. Houston Exploration used standard New York Mercantile Exchange ("NYMEX") futures prices and published volatility in its Black-Scholes calculation to value its outstanding derivatives. The maximum length of time over which Houston Exploration has hedged such cash flow variability is through December 2004.
The estimated amount of losses associated with such derivative instruments that are reported in Other Comprehensive Income and that are expected to be reclassified into earnings over the next twelve months is $34.9 million, or $22.7 million after-tax.
With respect to price exposure associated with fuel purchases for the Ravenswood facility, KeySpan employs standard NYMEX natural gas futures contracts and over-the-counter financially settled natural gas basis swaps to hedge the cash flow variability of a portion of forecasted purchases of natural gas. KeySpan also employs the use of financially-settled oil swap contracts to hedge the cash flow variability of a portion of forecasted purchases of fuel oil that will be consumed at the Ravenswood facility. The maximum length of time over which we have hedged cash flow variability associated with: (i) forecasted purchases of natural gas is through December 2003; and (ii) forecasted purchases of fuel oil is through April 2004. We used standard NYMEX futures prices to value the gas futures contracts and industry published oil indices for number 6 grade fuel oil to value the oil swap contracts. The estimated amount of gains associated with all such derivative instruments that are reported in Other Comprehensive Income and that are expected to be reclassified into earnings over the next twelve months is $4.5 million, or $2.9 million after-tax.
Our retail gas and electric marketing subsidiary, our domestic gas distribution operations and KeySpan Canada employed NYMEX natural gas futures contracts and natural gas swaps to lock-in a price for expected future natural gas purchases. As applicable, we used standard NYMEX futures prices and relevant natural gas indices to value the outstanding contracts. The maximum length of time over which we have hedged such cash flow variability is through December 2003. The estimated amount of gains associated with such derivative instruments that are reported in Other Comprehensive Income and that are expected to be reclassified into earnings over the next twelve months is $4.9 million, or $3.2 million after-tax.
We have also engaged in the use of cash-settled swap instruments to hedge the cash flow variability associated with (i) a portion of forecasted peak electric energy sales from the Ravenswood facility and (ii) forecasted sales of Unforced Capacity ("UCAP") to the NYISO. The maximum length of time over which we have hedged cash flow variability is through March 2004. We used NYISO-location zone published indices as well as published NYISO bidding prices to value these outstanding derivatives. The estimated amount of losses associated with such derivative instruments that are reported in Other Comprehensive Income and that are expected to be reclassified into earnings over the next twelve months is $1.1 million, or $0.7 million after-tax.
KeySpan Canada also has employed electricity swap contracts to lock-in the purchase price of electricity needed to operate its gas processing plants. These contracts are not exchange-traded and local published indices were used to value these outstanding swap agreements. The maximum length of time over which we have hedged such cash flow variability is through December 2003. The estimated amount of losses associated with such derivative instruments that are reported in Other Comprehensive Income and that are expected to be reclassified into earnings over the next twelve months is $1.5 million, or $1.0 million after-tax.
The following tables set forth selected financial data associated with these derivative financial instruments noted above that were outstanding at December 31, 2002.
- ------------------------------------------------------------------------------ Change in Fair Value of Derivative Instruments 2002 ($000) - ------------------------------------------------------------------------------ Fair value of contracts at January 1, $ 55,097 (Gain) on contracts realized (26,204) Fair value of new contracts when entered into during period - (Decrease) in fair value of all open contracts (61,521) - ------------------------------------------------------------------------------ Fair value of contracts outstanding at December 31, $ (32,628) - ------------------------------------------------------------------------------
NYMEX futures are also used to economically hedge the cash flow variability associated with the purchase of fuel for a portion of our fleet vehicles. Further, KeySpan Canada has a portfolio of financially-settled natural gas collars and natural gas liquid swap transactions. Such contracts are executed by KeySpan Canada to: (i) synthetically fix the price that is paid or received by KeySpan Canada for certain physical transactions involving natural gas and natural gas liquids and (ii) transfer the price exposure of such instruments to other trading partners. In addition, our retail gas and electric marketing subsidiary has bought options to economically hedge the cash flow variability associated with a portion of expected future natural gas purchases. These derivative financial instruments do not qualify for hedge accounting under SFAS 133. At December 31, 2002, these instruments had a net fair market value of ($0.4) million, that was recorded on the Consolidated Balance Sheet. Based on the non-hedge designation of these instruments, the loss was recognized in the Consolidated Statement of Income.
Firm Gas Sales Derivative Instruments - Regulated Utilities: We also use derivative financial instruments to reduce the cash flow variability associated with the purchase price for a portion of future natural gas purchases. Our strategy is to minimize fluctuations in firm gas sales prices to our regulated firm gas sales customers in our New York and New Hampshire service territories. Since these derivative instruments are employed to reduce the variability of the purchase price of natural gas to be sold to regulated firm gas sales customers, the accounting for these derivative instruments is subject to SFAS 71. Therefore, changes in the market value of these derivatives have been recorded as a Regulatory Asset or Regulatory Liability on the Consolidated Balance Sheet. Gains or losses on the settlement of these contracts are initially deferred and then refunded to or collected from our firm gas sales customers during the appropriate winter heating season consistent with regulatory requirements.
The following table sets forth selected financial data associated with these derivative financial instruments that were outstanding at December 31, 2002.
Physically-Settled Commodity Derivative Instruments: On April 1, 2002 we implemented Derivative Implementation Group ("DIG") Issue C15 and C16 of SFAS 133, "Accounting for Derivative Instruments and Hedging Activities", as amended and interpreted, incorporating SFAS 137 and SFAS 138 and certain implementation issues (collectively "SFAS 133"). Issue C15 establishes new criteria that must be satisfied in order for option-type and forward contracts in electricity to be exempted as normal purchases and sales, while Issue C16 relates to the exemption (as normal purchases and normal sales) of contracts that combine a forward contract and a purchased option contract. Based upon a review of our physical commodity contracts, we determined that certain contracts for the physical purchase of natural gas can no longer be exempted as normal purchases from the requirements of SFAS 133. At December 31, 2002, the fair value of these contracts was $1.2 million. Since these contracts are for the purchase of natural gas sold to regulated firm gas sales customers, the accounting for these contracts is subject to SFAS 71. Therefore, changes in the market value of these contracts have been recorded as a Regulatory Asset or Regulatory Liability on the Consolidated Balance Sheet.
Interest Rate Derivative Instruments: During most of 2002, we had interest rate swap agreements in which approximately $1.3 billion of fixed rate debt had been synthetically modified to floating rate debt. Under the terms of the agreements, we received the fixed coupon rate associated with these bonds and paid the counter-parties a variable interest rate that was reset on a quarterly basis. These swaps were designated as fair-value hedges and qualified for "short-cut" hedge accounting treatment under SFAS 133. Through the utilization of these agreements, we reduced recorded interest expense by $35.6 million for the twelve months ended December 31, 2002. In early November 2002, we terminated two interest rate swap agreements with an aggregate notional amount of $1.0 billion and received $80.9 million from our swap counter-parties, of which $23.4 million represented accrued swap interest. The difference between the termination settlement amount and the amount of accrued swap interest, $57.4 million, will be amortized to earnings (as an adjustment to interest expense) on a level yield basis over the remaining lives of the originally hedged debt obligations. The remaining swap, which had a notional amount of $270.0 million, and a fair market value of $15.6 million at December 31, 2002, was terminated on February 25, 2003. We received $18.4 million from our swap counter-parties, of which $8.1 million represents accrued swap interest. The difference between the termination settlement amount and the amount of accrued interest, $10.3 million, will be recorded to earnings in the first quarter of 2003. This swap was used to hedge a portion of our outstanding promissory notes to LIPA. As discussed in Note 6 to the Consolidated Financial Statements "Long-Term Debt", we intend to redeem a portion of these promissory notes before the end of the first quarter of 2003.
Additionally, we also have an interest rate swap agreement that hedges the cash flow variability associated with the forecasted issuance of a series of commercial paper offerings. The maximum length of time over which we have hedged such cash flow variability is through March 2003. The estimated amount of loss associated with such derivative instruments that are reported in Other Comprehensive Income and that are expected to be reclassified into earnings over the next twelve months is $0.6 million, or $0.4 million after-tax.
Weather Derivatives: The utility tariffs associated with KEDNE's operations do not contain weather normalization adjustments. As a result, fluctuations from normal weather may have a significant positive or negative effect on the results of these operations. To mitigate a substanial portion of the effect of fluctuations from normal weather on our financial position and cash flows, we sold heating degree-day call options and purchased heating degree-day put options for the November 2002 - March 2003 winter season. With respect to sold call options, KeySpan is required to make a payment of $40,000 per heating degree day to its counter-parties when actual weather experienced during the November 2002 - March 2003 time frame is above 4,470 heating degree days, which equates to approximately 1% colder than normal weather. With respect to purchased put options, KeySpan will receive a $20,000 per heating degree day payment from its counter-parties when actual weather is below 4,150 heating degree days, or is approximately 7% warmer than normal. Based on the terms of such contracts, as discussed in Note 1 to the Consolidated Financial Statements "Summary of Significant Accounting Policies", we account for such instruments pursuant to the requirements of EITF 99-2, "Accounting for Weather Derivatives." In this regard, we account for such instruments using the "intrinsic value method" as set forth in such guidance. During the fourth quarter of 2002, weather was 7% colder than normal and, as a result, $3.3 million has been recorded as a reduction to revenues.
Derivative contracts are primarily used to manage exposure to market risk arising from changes in commodity prices and interest rates. In the event of nonperformance by a counter-party to a derivative contract, the desired impact may not be achieved. The risk of a counter-party nonperformance is generally considered credit risk and is actively managed by assessing each counter-party credit profile and negotiating appropriate levels of collateral and credit support.
Foreign Currency Fluctuations
We follow the principles of SFAS 52, "Foreign Currency Translation" for recording our investments in foreign affiliates. Due to our continued activities in Canada and Northern Ireland, our investment in foreign affiliates has been growing. At December 31, 2002, the net assets of these affiliates was approximately $374 million and at December 31, 2002, the accumulated after-tax foreign currency translation included in Other Comprehensive Income was a debit of $2.2 million. (See Note 1 to the Consolidated Financial Statements "Summary of Significant Accounting Policies.")
Item 8.
Item 8. Financial Statements and Supplementary Data
CONSOLIDATED BALANCE SHEET
See accompanying Notes to the Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEET
See accompanying Notes to the Consolidated Financial Statements.
CONSOLIDATED STATEMENT OF INCOME
See accompanying Notes to the Consolidated Financial Statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
See accompanying Notes to the Consolidated Financial Statements.
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
See accompanying Notes to the Consolidated Financial Statements.
CONSOLIDATED STATEMENT OF CAPITALIZATION
See accompanying Notes to the Consolidated Financial Statements.
Notes to the Consolidated Financial Statements
Note 1. Summary of Significant Accounting Policies
A. Organization of the Company
KeySpan Corporation, a New York corporation, was formed in May 1998, as a result of the business combination of KeySpan Energy Corporation, the parent of The Brooklyn Union Gas Company, and certain businesses of the Long Island Lighting Company ("LILCO"). On November 8, 2000, KeySpan acquired Eastern Enterprises ("Eastern"), a Massachusetts business trust, and the parent of several gas utilities operating in Massachusetts. Also on November 8, 2000, Eastern acquired EnergyNorth, Inc. ("ENI"), the parent of a gas utility operating in central New Hampshire. KeySpan Corporation will be referred to in these notes to the Consolidated Financial Statements as "KeySpan", "we", "us" and "our."
Our core business is gas distribution, conducted by our six regulated gas utility subsidiaries: The Brooklyn Union Gas Company d/b/a KeySpan Energy Delivery New York ("KEDNY") and KeySpan Gas East Corporation d/b/a KeySpan Energy Delivery Long Island ("KEDLI") distribute gas to customers in the boroughs of Brooklyn, Staten Island and a portion of the borough of Queens in New York City, and the counties of Nassau and Suffolk on Long Island and the Rockaway Peninsula in Queens, respectively; Boston Gas Company, Colonial Gas Company and Essex Gas Company, each doing business as KeySpan Energy Delivery New England ("KEDNE"), distribute gas to customers in southern, eastern and central Massachusetts; and EnergyNorth Natural Gas, Inc., d/b/a KeySpan Energy Delivery New England distributes gas to customers in central New Hampshire. Together, these companies distribute gas to approximately 2.5 million customers throughout the Northeast.
We also own, lease and operate electric generating plants on Long Island and in New York City. Under contractual arrangements, we provide power, electric transmission and distribution services, billing and other customer services for approximately 1.1 million electric customers of the Long Island Power Authority ("LIPA").
Our other subsidiaries are involved in gas and oil exploration and production; gas storage; wholesale and retail gas and electric marketing; appliance service; heating, ventilation and air conditioning installation and services; large energy-system ownership, installation and management; and fiber optic services. We also invest in, and participate in the development of, pipelines and other energy-related projects, domestically and internationally. (See Note 2, "Business Segments" for additional information on each operating segment.)
We are a registered holding company under the Public Utility Holding Company Act of 1935 ("PUHCA"), as amended. Therefore, our corporate and financial activities and those of our subsidiaries, including their ability to pay dividends to us, are subject to regulation by the Securities and Exchange Commission ("SEC"). Under our holding company structure, we have no independent operations or source of income of our own and conduct all of our operations through our subsidiaries and, as a result, we depend on the earnings and cash flow of, and dividends or
distributions from, our subsidiaries to provide the funds necessary to meet our debt and contractual obligations. Furthermore, a substantial portion of our consolidated assets, earnings and cash flow is derived from the operations of our regulated utility subsidiaries, whose legal authority to pay dividends or make other distributions to us is subject to regulation by state regulatory authorities.
B. Basis of Presentation
The Consolidated Financial Statements presented herein reflect the accounts of KeySpan and its subsidiaries. Most of our subsidiaries are fully consolidated in the financial information presented, except for certain subsidiary investments in the Energy Investments segment which are accounted for on the equity method as we do not have a controlling voting interest or otherwise have control over the management of such companies. All significant intercompany transactions have been eliminated.
As noted, on November 8, 2000, we completed the acquisitions of Eastern and ENI. The transactions have been accounted for using the purchase method of accounting for business combinations and accordingly the accompanying consolidated financial statements include the results of Eastern and ENI since the acquisition date.
The preparation of financial statements in conformity with Generally Accepted Accounting Principles ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
C. Accounting for the Effects of Rate Regulation
The accounting records for our six regulated gas utilities are maintained in accordance with the Uniform System of Accounts prescribed by the Public Service Commission of the State of New York ("NYPSC"), the New Hampshire Public Utility Commission ("NHPUC"), and the Massachusetts Department of Telecommunications and Energy ("DTE"). Our electric generation subsidiaries are not subject to state rate regulation, but they are subject to Federal Energy Regulatory Commission ("FERC") regulation. Our financial statements reflect the ratemaking policies and actions of these regulators in conformity with GAAP for rate-regulated enterprises.
Four of our six regulated gas utilities (KEDNY, KEDLI, Boston Gas Company and EnergyNorth Natural Gas, Inc.) and our Long Island based electric generation subsidiaries are subject to the provisions of Statement of Financial Accounting Standards ("SFAS") 71, "Accounting for the Effects of Certain Types of Regulation." This statement recognizes the ability of regulators, through the ratemaking process, to create future economic benefits and obligations affecting rate-regulated companies. Accordingly, we record these future economic benefits and obligations as Regulatory Assets and Regulatory Liabilities on the Consolidated Balance Sheet, respectively.
In separate merger related orders issued by the DTE, the base rates charged by Colonial Gas Company and Essex Gas Company have been frozen at their current levels for a ten-year period. Due to the length of these base rate freezes, the Colonial and Essex Gas Companies had previously discontinued the application of SFAS 71.
The following table presents our net regulatory assets at December 31, 2002 and December 31, 2001.
The regulatory assets above are not included in rate base. However, we record carrying charges on the property tax and costs associated with the KeySpan/LILCO transaction cost deferrals. We also record carrying charges on our regulatory liabilities. The remaining regulatory assets represent, primarily, costs for which expenditures have not yet been made, and therefore, carrying charges are not recorded. We anticipate recovering these costs in our gas rates concurrently with future cash expenditures. If recovery is not concurrent with the cash expenditures, we will record the appropriate level of carrying charges. Deferred gas costs of $61.8 million and $5.6 million at December 31, 2002 and December 31, 2001, respectively are reflected in Accounts Receivable on the Consolidated Balance Sheet. Deferred gas costs are subject to current recovery from customers.
We estimate that full recovery of our regulatory assets will not exceed 15 years, except for the regulatory tax asset, which will be recovered over the estimated lives of certain utility property.
Rate regulation is undergoing significant change as regulators and customers seek lower prices for utility service and greater competition among energy service providers. In the event that regulation significantly changes the opportunity to recover costs in the future, all or a portion of our regulated operations may no longer meet the criteria for the application of SFAS 71. In that event, a write-down of all or a portion of our existing regulatory assets and liabilities could result. If we were unable to continue to apply the provisions of SFAS 71 for any of our rate regulated subsidiaries, we would apply the provisions of SFAS 101, "Regulated Enterprises - Accounting for the Discontinuation of Application of FASB Statement 71." We estimate that the write-off of all regulatory assets at December 31, 2002 could result in a charge to net income of $230.1 million or $1.63 per share, which would be classified as an extraordinary item. In management's opinion, our regulated subsidiaries that are currently subject to the provisions of SFAS 71 will continue to be subject to SFAS 71 for the foreseeable future.
D. Revenues
Gas Distribution: Utility gas customers are billed monthly or bi-monthly on a cycle basis. Revenues include unbilled amounts related to the estimated gas usage that occurred from the most recent meter reading to the end of each month.
The cost of gas used is recovered when billed to firm customers through the operation of gas adjustment clauses ("GAC") included in utility tariffs. The GAC provision requires periodic reconciliation of recoverable gas costs and GAC revenues. Any difference is deferred pending recovery from or refund to firm customers. Further, net revenues from tariff gas balancing services, off-system sales and certain on-system interruptible sales are refunded, for the most part, to firm customers subject to certain sharing provisions.
The New York and Long Island gas utility tariffs contain weather normalization adjustments that largely offset shortfalls or excesses of firm net revenues (revenues less gas costs and revenue taxes) during a heating season due to variations from normal weather. Revenues are adjusted each month the clause is in effect and are generally included in rates in the following month. The New England gas utility rate structures contain no weather normalization feature, therefore their net revenues are subject to weather related demand fluctuations.
Electric Services: Electric revenues are derived from billings to LIPA for management of LIPA's transmission and distribution ("T&D") system, electric generation, and procurement of fuel. The agreements with LIPA include provisions for us to earn, in the aggregate, approximately $11.5 million per year (plus up to an additional $5 million per year if certain cost savings are achieved) in annual management service fees from LIPA for the management of the T&D system and the management of all aspects of fuel and power supply. Under a Management Service Agreement ("MSA") costs in excess of budgeted levels are assumed by us up to $15 million, while cost reductions in excess of $5 million from budgeted levels are shared with LIPA. These agreements also contain certain non-cost incentive and penalty provisions which could impact earnings. Rates billed to LIPA on a monthly basis include fixed and variable components. Billings related to transmission, distribution and delivery services are based, in part, on negotiated estimated levels.
KeySpan Glenwood Energy Center LLC and KeySpan Port Jefferson Energy Center LLC have entered into 25 year Power Purchase Agreements with LIPA (the "PPAs"). Under the terms of the PPAs, these subsidiaries sell capacity, energy conversion services and ancillary services to LIPA. Both plants are designed to produce 79.9 megawatts ("MW"). Under the PPAs, LIPA pays a monthly capacity fee, which guarantees full recovery of each plant's construction costs, as well as an appropriate rate of return on investment. The PPAs also obligate LIPA to pay for each plant's costs of operation and maintenance. These costs are billed on a monthly estimated basis and are subject to true up for actual costs incurred.
In addition, electric revenues are derived from our investment in the 2,200 megawatt Ravenswood electric generation facility ("Ravenswood facility"), which we acquired in June 1999. (See Note 7 "Contractual Obligations, Financial Guarantees and Contingencies" for a description of the Ravenswood transaction.)
We realize revenues from our investment in the Ravenswood facility through the sale, at wholesale, of energy, capacity, and ancillary services to the New York Independent System Operator ("NYISO"). Energy and ancillary services are sold through a bidding process into the NYISO energy markets on a day ahead or real time basis.
Energy Services: Revenues earned by our Energy Services segment for mechanical and other contracting services are generally recognized by the percentage-of-completion method. This method measures the percentage of costs incurred and accrued to date for each contract to the estimated total costs for each contract at completion. Provisions for estimated losses on uncompleted contracts are made in the period such losses are determined. Changes in job performance, job conditions and estimated profitability may result in revisions to cost and income, which are recognized in the period in which the revisions are determined. The percentage of completion method of accounting may result in situations where billings to customers are in excess of costs incurred to date. These excess billings are not recognized in income until the related costs have been incurred and the earnings process is complete. At December 31, 2002 and December 31, 2001 we had billings in excess of costs of $27.2 million and $53.6 million, respectively. These balances are included in Accounts Payable and Other Liabilities on the Consolidated Balance Sheet and are expected to be included in income within one year.
Energy service and maintenance revenues are recognized as earned or over the life of the service contract, as appropriate. Energy sales made by our electric and gas marketing subsidiary are recorded upon delivery of the related commodity. Fiber optic service revenue is recognized upon delivery of service access. We have unearned revenue recorded in Deferred Credits and Other Liabilities - Other on the Consolidated Balance Sheet totaling $19.2 million and $18.0 million for the years ended December 31, 2002 and December 31, 2001, respectively. These balances represent unearned revenues for service contracts and leases on our fiber optic cables. The unearned revenues from the service contracts are generally amortized to income within one year, while the lease related unearned revenues are amortized over periods ranging from seven to 30 years.
Gas Exploration and Production: Natural gas and oil revenues earned by our gas exploration and production activities is recognized using the entitlements method of accounting. Under this method of accounting, income is recorded based on the net revenue interest in production or nominated deliveries. Production gas volume imbalances are incurred in the ordinary course of business. Net deliveries in excess of entitled amounts are recorded as liabilities, while net under deliveries are recorded as assets. Imbalances are reduced either by subsequent recoupment of over and under deliveries or by cash settlement, as required by applicable contracts. Production imbalances are marked-to-market at the end of each month using the market price at the end of each period.
E. Utility and Other Property - Depreciation and Maintenance
Property, principally utility gas property is stated at original cost of construction, which includes allocations of overheads, including taxes, and an allowance for funds used during construction. The rates at which KeySpan subsidiaries capitalized interest for years ended December 31, 2000 through 2002 ranged from 3.44% to 10.67%. Capitalized interest for 2002, 2001 and 2000 was $19.7 million, $8.5 million and $2.7 million respectively.
Depreciation is provided on a straight-line basis in amounts equivalent to composite rates on average depreciable property. The cost of property retired, plus the cost of removal less salvage, is charged to accumulated depreciation. The cost of repair and minor replacement and renewal of property is charged to maintenance expense. The composite rates on average depreciable property were as follows:
- ---------------------------------------------------------------------------- Year Ended December 31, 2002 2001 2000 - ---------------------------------------------------------------------------- Electric 3.88% 3.78% 3.68% Gas 3.44% 3.40% 3.51% - ----------------------------------------------------------------------------
We also had $394.4 million of other property at December 31, 2002, which is not recovered under rate orders. This property consists of assets held primarily by our Corporate Service subsidiary of $312.6 million and $81.8 million in Energy Services assets. The Corporate Service assets consist largely of land, buildings, office equipment and furniture, vehicles, computer and telecommunications equipment and systems. These assets have depreciable lives ranging from three to 40 years. Energy Service assets consist largely of construction equipment and fiber optic cable and related electronics and have service lives ranging from seven to 40 years.
KeySpan's repair and maintenance costs, including planned major maintenance in the Electric Services segment for turbine and generator overhauls, are expensed as incurred. Planned major maintenance cycles primarily range from seven to eight years. Smaller periodic overhauls are performed approximately every 18 months.
F. Gas Exploration and Production Property - Depletion
At December 31, 2002, we had exploration and production property in the amount of $2.4 billion related to our investments in natural gas and oil properties. These assets are accounted for under the full cost method of accounting. Under the full cost method, costs of acquisition, exploration and development of natural gas and oil reserves are capitalized into a "full cost pool" as incurred. Unproved properties and related costs are excluded from the amortization base until a determination as to the existence of proved reserves. Properties are depleted and charged to operations using the unit of production method using proved reserve quantities.
These investments consist of our ownership interest in The Houston Exploration Company ("Houston Exploration"), an independent natural gas and oil exploration company, as well as KeySpan Exploration and Production, LLC, our wholly-owned subsidiary engaged in a joint venture with Houston Exploration. On February 26, 2003, we reduced our ownership interest in Houston Exploration from 66% to
approximately 56% following the repurchase, by Houston Exploration, of 3 million shares of stock owned by KeySpan. To the extent that such capitalized costs (net of accumulated depletion) less deferred taxes exceed the present value (using a 10% discount rate) of estimated future net cash flows from proved natural gas and oil reserves and the lower of cost or fair value of unproved properties, less deferred taxes, such excess costs are charged to operations. If an impairment is required, it would result in a charge to earnings but would not have an impact on cash flows. Once incurred, such impairment of gas properties is not reversible at a later date even if gas prices increase.
The ceiling test is calculated using natural gas and oil prices in effect as of the balance sheet date, held flat over the life of the reserves. We use derivative financial instruments that qualify for hedge accounting under SFAS 133 "Accounting for Derivative Instruments and Hedging Activities", to hedge the volatility of natural gas prices. In accordance with current SEC guidelines, we have included estimated future cash flows from our hedging program in the ceiling test calculation. As of December 31, 2002, we estimated, using a wellhead price of $4.99 per mcf, that our capitalized costs did not exceed the ceiling test limitation.
In calculating the ceiling test at December 31, 2001, we estimated, using a wellhead price of $2.38 per mcf, that our capitalized costs exceeded the ceiling limitation. As a result, in the fourth quarter of 2001, we recorded a $42.0 million impairment charge to write down our gas exploration and production assets, and recorded this charge in Depreciation, Depletion and Amortization on the Consolidated Statement of Income. Our share of the impairment charge was $26.2 million after-tax, or $0.19 per share.
Natural gas prices continue to be volatile and the risk that we will be required to write down our full cost pool increases when, among other things, natural gas prices are depressed, we have significant downward revisions in our estimated proved reserves or we have unsuccessful drilling results.
Houston Exploration capitalizes interest related to its unevaluated natural gas and oil properties, as well as some properties under development which are not currently being amoritized. For years ended December 31, 2002, 2001 and 2000, capitalized interest was $8.0 million, $12.0 million and $13.7 million, respectively.
G. Goodwill
At December 31, 2002 and 2001, the balance of goodwill was $1.8 billion, representing the excess of acquisition cost over the fair value of net assets acquired. Our recorded goodwill, net of accumulated amortization, consists of $1.5 billion related to the Eastern and ENI acquisitions, $156 million related to the KeySpan/LILCO transaction, and $176 million related to the acquisitions of energy-related service companies and to certain ownership interests of 50% or less in energy-related investments in Northern Ireland which are accounted for under the equity method.
On January 1, 2002, KeySpan adopted SFAS 142 "Goodwill and Other Intangible Assets". Under SFAS 142, among other things, goodwill is no longer required to be amortized and is to be tested for impairment at least annually. The initial impairment test was to be performed within six months of adopting SFAS 142 using a discounted cash flow method, compared to a undiscounted cash flow method allowed under a previous standard. Any amounts impaired using data as of January
1, 2002, was to be recorded as a "Cumulative Effect of an Accounting Change". Any amounts impaired using data after the initial adoption date will be recorded as an operating expense. During the second quarter of 2002, we completed our initial impairment analysis for all the reporting units and determined that no consolidated impairment existed. Also, in the fourth quarter of 2002, KeySpan updated its review of the carrying value of goodwill compared to the fair value of the assets by reporting unit and determined that no impairment existed.
As required by SFAS 142, below is a reconciliation of reported earnings available for common stockholders for the years ended December 31, 2002, 2001 and 2000 and pro-forma net income, for the same periods, adjusted for the discontinuance of goodwill amortization.
* Excludes the write-off of $12.4 million of goodwill in 2001 associated with the Roy Kay Operations.
For the twelve months ended December 31, 2001 and 2000, respectively goodwill amortization was recorded in each segment as follows: Gas Distribution $35.6 and $5.9 million; Energy Services $8.2 and $7.6 million; and Energy Investments and other $5.8 and $6.2 million. The increase in amortization expense in 2001 versus 2000 primarily reflects the acquisition of Eastern and ENI in November 2000.
Prior to implementation of SFAS 142, goodwill was reviewed for impairment under SFAS 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of". Under SFAS 121, the carrying value of goodwill is reviewed if the facts and circumstances, such as significant declines in sales, earnings or cash flows, or material adverse changes in the business climate, suggest it might be impaired. If this review indicates that goodwill is not recoverable, as determined based upon the estimated undiscounted cash flows of the entity acquired, impairment would be measured by comparing the carrying value of the investment in such entity to its fair value. Fair value would be determined based on quoted market values, appraisals, or discounted cash flows. For the year ended December 31, 2001, we reviewed the facts and circumstances for the entities carrying goodwill and as a result of the above procedures, wrote off $12.4 million associated with the Roy Kay Companies upon determination that the asset was not recoverable. (See Note 10, "Roy Kay Operations" for additional information.)
H. Hedging and Derivative Financial Instruments
From time to time, we employ derivative instruments to hedge a portion of our exposure to commodity price risk and interest rate risk, as well as to hedge cash flow variability associated with a portion of our peak electric energy sales. Whenever hedge positions are in effect, we are exposed to credit risk in the event of nonperformance by counter-parties to derivative contracts, as well as nonperformance by the counter-parties of the transactions against which they are hedged. We believe that the credit risk related to the futures, options and swap instruments is no greater than that associated with the primary commodity contracts which they hedge. Our derivative instruments do not qualify as energy trading contracts as defined by current accounting literature.
Financially-Settled Commodity Derivative Instruments: We employ derivative financial instruments, such as futures, options and swaps, for the purpose of hedging the cash flow variability associated with forecasted purchases and sales of various energy-forecasted commodities. All such derivative instruments are accounted for pursuant to the requirements of SFAS 133 "Accounting for Derivative Instruments and Hedging Activities", as amended by SFAS 138, "Accounting for Certain Derivative Instruments and Hedging Activities" (collectively, "SFAS 133"). With respect to those commodity derivative instruments that are designated and accounted for as cash flow hedges, the effective portion of periodic changes in the fair market value of cash flow hedges is recorded as Other Comprehensive Income on the Consolidated Balance Sheet, while the ineffective portion of such changes in fair value is recognized in earnings. Gains and losses (on such cash flow hedges) that are recorded as Other Comprehensive Income are subsequently reclassified into earnings concurrent with when hedged transactions impact earnings. With respect to those commodity derivative instruments that are not designated as hedging instruments, such derivatives are accounted for on the Consolidated Balance Sheet at fair value, with all changes in fair value reported in earnings.
Firm Gas Sales Derivatives Instruments - Regulated Utilities: We utilize derivative financial instruments to reduce cash flow variability associated with the purchase price for a portion of our future natural gas purchases. Our strategy is to minimize fluctuations in firm gas sales prices to our regulated firm gas sales customers in our New York and New Hampshire service territories. Since these derivative instruments are being employed to support our gas sales prices to regulated firm gas sales customers, the accounting for these derivative instruments is subject to SFAS 71. Therefore, changes in the market value of these derivatives are recorded as a Regulatory Asset or Regulatory Liability on our Consolidated Balance Sheet. Gains or losses on the settlement of these contracts are initially deferred and then refunded to or collected from our firm gas sales customers during the appropriate winter heating season consistent with regulatory requirements.
Physically-Settled Commodity Derivative Instruments: Upon our implementation of Derivative Implementation Group ("DIG") Issue C16 on April 1, 2002, certain of our contracts for the physical purchase of natural gas were assessed as no longer being exempt from the requirements of SFAS 133 as normal purchases. As such, these contracts are recorded on the Consolidated Balance Sheet at fair
market value. However, since such contracts were executed for the purchases of natural gas that is sold to regulated firm gas sales customers, and pursuant to the requirements of SFAS 71, changes in the fair market value of these contracts are recorded as a Regulatory Asset or Regulatory Liability on the Consolidated Balance Sheet.
Weather Derivatives: The utility tariffs associated with our New England gas distribution operations do not contain a weather normalization adjustment. As a result, fluctuations from normal weather may have a significant positive or negative effect on the results of these operations. To mitigate the effect of fluctuations from normal weather on our financial position and cash flows, we may enter into derivative instruments from time to time. Based on the terms of the contracts, we account for these instruments pursuant to the requirements of EITF 99-2 "Accounting for Weather Derivatives." In this regard, we account for weather derivatives using the "intrinsic value method" as set forth in such guidance.
Interest Rate Derivative Instruments: We continually assess the cost relationship between fixed and variable rate debt. Consistent with our objective to minimize capital costs, we periodically enter into hedging transactions that effectively convert the terms of underlying debt obligations from fixed to variable or variable to fixed. Payments made or received on these derivative contracts are recognized as an adjustment to interest expense as incurred. Hedging transactions that effectively convert the terms of underlying debt obligations from fixed to variable are designated and accounted for as fair-value hedges pursuant to the requirements of SFAS 133. Hedging transactions that effectively convert the terms of underlying debt obligations from variable to fixed are considered cash flow hedges.
I. Equity Investments
Certain subsidiaries own as their principal assets, investments (including goodwill) representing ownership interests of 50% or less in energy-related businesses that are accounted for under the equity method. None of these investments are publicly traded.
J. Income and Excise Tax
In accordance with SFAS 109, "Accounting for Income Taxes" and applicable rate regulation, certain of our regulated subsidiaries record a regulatory asset for the net cumulative effect of providing deferred income taxes on all differences between the financial statement carrying amounts of existing assets and liabilities, and their respective tax basis. Investment tax credits, which were available prior to the Tax Reform Act of 1986, were deferred and generally amortized as a reduction of income tax over the estimated lives of the related property.
We report our collections and payments of excise taxes on a gross basis. Gas distribution revenues include the collection of excise taxes, while operating taxes include the related expense. For the years ended December 31, 2002, 2001 and 2000, excise taxes collected and paid were $98.2 million, $119.1 million and $117.8 million, respectively.
K. Subsidiary Common Stock Issuances to Third Parties
We follow an accounting policy of income statement recognition for parent company gains or losses from issuances of common stock by subsidiaries to unaffiliated third parties.
L. Foreign Currency Translation
We follow the principles of SFAS 52, "Foreign Currency Translation," for recording our investments in foreign affiliates. Under this statement, all elements of the financial statements are translated by using a current exchange rate. Translation adjustments result from changes in exchange rates from one reporting period to another. At December 31, 2002, the foreign currency translation adjustment was included in Other Comprehensive Income on the Consolidated Balance Sheet. The functional currency for our foreign affiliates is their local currency.
M. Earnings Per Share
Basic earnings per share ("EPS") is calculated by dividing earnings for common stock by the weighted average number of shares of common stock outstanding during the period. No dilution for any potentially dilutive securities is included. Diluted EPS assumes the conversion of all potentially dilutive securities and is calculated by dividing earnings for common stock, as adjusted, by the sum of the weighted average number of shares of common stock outstanding plus all potentially dilutive securities.
At December 31, 2002 we have approximately 2.1 million options outstanding to purchase KeySpan common stock that were not used in the calculation of diluted EPS since the exercise price associated with these options was greater than the average per share market price of KeySpan's common stock. Further, we have 88,486 shares of convertible preferred stock outstanding that can be converted into 228,406 shares of common stock. These shares were not included in the calculation of diluted EPS for the years ending December 31, 2001 and 2000, since to do so would have been anti-dilutive.
Under the requirements of SFAS 128, "Earnings Per Share" our basic and diluted EPS are as follows:
N. Stock Options
We issue stock options to all KeySpan officers and certain other management employees as approved by the Board of Directors. These options generally vest over a three-to-five year period and have a ten-year exercise period. Up to approximately 19.3 million shares have been authorized for the issuance of options and approximately 6.7 million of these shares were remaining at December 31, 2002. Moreover, under a separate plan, Houston Exploration has issued approximately 2.4 million stock options to key Houston Exploration employees. During 2002, we announced our intention to record stock options as a compensation expense beginning with those options granted in 2003. KeySpan and Houston Exploration have adopted the prospective method of transition in accordance with SFAS 148 "Accounting for Stock-Based Compensation - Transition and Disclosure". Accordingly, compensation expense will be recognized by employing the fair value recognition provisions of SFAS 123 "Accounting for Stock-Based Compensation" for grants awarded after January 1, 2003.
KeySpan and Houston Exploration will continue to apply APB Opinion 25, "Accounting for Stock Issued to Employees," and related Interpretations in accounting for grants awarded prior to January 1, 2003. Accordingly, no compensation cost has been recognized for these fixed stock option plans in the Consolidated Financial Statements since the exercise prices and market values were equal on the grant dates. Had compensation cost for these plans been determined based on the fair value at the grant dates for awards under the plans consistent with SFAS 123, our net income and earnings per share would have decreased to the pro-forma amounts indicated below:
All grants are estimated on the date of the grant using the Black-Scholes option-pricing model. The following table presents the weighted average fair value, exercise price and assumptions used for the periods indicated:
A summary of the status of our fixed stock option plans and changes is presented below for the periods indicated:
In early March 2003, KeySpan's Board of Directors approved a modification to the Long-Term Incentive Compensation Plan and its application to officers of KeySpan. During 2003, long-term incentive compensation for officers will consist of 50% stock options and 50% performance shares. Performance shares will be awarded based upon the attainment of overall corporate performance goals and will better align incentive compensation with overall corporate performance. During 2002, and in prior years, the majority of long-term incentive compensation awards were stock option grants with a limited amount of restricted stock award grants.
O. Recent Accounting Pronouncements
On January 1, 2002, we adopted SFAS 141, "Business Combinations", and SFAS 142 "Goodwill and Other Intangible Assets". The key concepts from the two interrelated Statements include mandatory use of the purchase method when accounting for business combinations, discontinuance of goodwill amortization, a revised framework for testing goodwill impairment at a "reporting unit" level and new criteria for the identification and potential amortization of other intangible assets. Other changes to existing accounting standards involve the amount of goodwill to be used in determining the gain or loss on the disposal of assets and a requirement to test goodwill for impairment at least annually. See Item G "Goodwill" for a discussion of goodwill impairment testing.
In July 2001, the Financial Accounting Standards Board ("FASB") issued SFAS 143, "Accounting for Asset Retirement Obligations." SFAS 143 requires an entity to record a liability and corresponding asset representing the present value of legal obligations associated with the retirement of tangible, long-lived assets. SFAS 143 was effective for fiscal years beginning after June 2002.
KeySpan has completed its assessment of SFAS 143. At December 31, 2002, we estimate that the present value of our future Asset Retirement Obligation ("ARO") is approximately $57 million, primarily related to our investment in Houston Exploration. We estimate that the cumulative effect of SFAS 143 and the change in accounting principle will be a benefit to net income of $49.5 million, or $32.2 million, after-tax. KeySpan's largest asset base is its gas
transmission and distribution system. A legal obligation may be construed to exist due to certain safety requirements at final abandonment. In addition, a legal obligation may be construed to exist with respect to KeySpan's liquefied natural gas ("LNG") storage tanks due to clean up responsibilities upon cessation of use. However, mass assets such as storage, transmission and distribution assets are believed to operate in perpetuity and, therefore, have indeterminate cash flow estimates. Since that exposure is in perpetuity and cannot be measured, no liability will be recorded. KeySpan's ARO will be re-evaluated in future periods until sufficient information exists to determine a reasonable estimate of fair value.
SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", was effective January 1, 2002, and addresses accounting and reporting for the impairment or disposal of long-lived assets. SFAS 144 supersedes SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" and APB Opinion No. 30, "Reporting the Results of Operations-Reporting the Effects of Disposal of a Segment of a Business". SFAS 144 retains the fundamental provisions of SFAS 121 and expands the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. For 2002, implementation of this Statement did not have a significant effect on our results of operations and financial position.
In June of 2002, the FASB issued SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities". This Statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies EITF 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity". This Statement is effective for exit or disposal activities initiated after December 31, 2002, with early application encouraged.
In December of 2002, the FASB issued SFAS 148, "Accounting for Stock-Based Compensation-Transition and Disclosure", which amends SFAS 123, "Accounting for Stock-Based Compensation". This Statement provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require more prominent and more frequent disclosures in financial statements about the effects of stock-based compensation. See Item N "Stock Options" for these disclosures. The transition guidance and annual disclosure provisions of SFAS 148 are effective for fiscal years ending after December 15, 2002, with earlier application permitted in certain circumstances. The interim disclosure provisions are effective for financial reports containing financial statements for interim periods beginning after December 15, 2002.
The recognition provisions of this Statement allow for three alternative methods of recognizing stock-based employee compensation expense. KeySpan has elected to follow the prospective method of recognizing an expense for all employee awards granted or modified after January 1, 2003. The expense associated with implementation of this method is not expected to be material in 2003.
In November 2002, the FASB issued FASB Interpretation No. 45 ("FIN 45"), "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." FIN 45 requires the guarantor to recognize a liability for the non-contingent component of a guarantee; that is, the obligation to stand ready to perform in the event that specified triggering events or conditions occur. The initial measurement of this liability is the fair value of the guarantee at inception. The recognition of the liability is required even if it is not probable that payments will be required under the guarantee or if the guarantee was issued with a premium payment or as part of a transaction with multiple elements. FIN 45 also requires additional disclosures related to guarantees (See Note 7 "Contractual Obligations, Financial Guarantees and Contingencies" for a description of KeySpan's outstanding guarantees). The disclosure requirements are effective for interim and annual financial statements for periods ending after December 15, 2002. The recognition and measurement provisions of FIN 45 are effective for all guarantees entered into or modified after December 31, 2002. We currently do not anticipate that implementation of this Statement will have a significant effect on our results of operations and financial condition.
In January 2003, the FASB issued FASB Interpretation No. 46 ("FIN 46"), "Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51." FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective for all new variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003. We currently have an arrangement with a variable interest entity through which we lease a portion of the Ravenswood facility (See Note 7 "Contractual Obligations, Financial Guarantees and Contingencies" for a description of the Ravenswood transaction).
Note 2. Business Segments
We have four reportable segments: Gas Distribution, Electric Services, Energy Services and Energy Investments.
The Gas Distribution segment consists of our six gas distribution subsidiaries. KEDNY provides gas distribution services to customers in the New York City boroughs of Brooklyn, Staten Island and a portion of the borough of Queens. KEDLI provides gas distribution services to customers in the Long Island counties of Nassau and Suffolk and the Rockaway Peninsula of Queens County. The remaining gas distribution subsidiaries, collectively doing business as KEDNE, provide gas distribution service to customers in Massachusetts and New Hampshire.
The Electric Services segment consists of subsidiaries that: operate the electric transmission and distribution system owned by LIPA; own and provide capacity to and produce energy for LIPA from our generating facilities located on Long Island; and manage fuel supplies for LIPA to fuel our Long Island generating facilities. These services are provided in accordance with long-term service contracts having remaining terms that range from four to twelve years. The Electric Services segment also includes subsidiaries that own, lease and operate the 2,200 megawatt Ravenswood electric generation facility located in Queens, New York. All of the energy, capacity and ancillary services related to the Ravenswood facility is sold to the NYISO energy markets. Further, two 79.9 megawatt generating facilities located on Long Island were placed into service in June and July 2002. The capacity of and energy from these facilities are dedicated to LIPA under 25 year contracts.
The Energy Services segment includes companies that provide energy-related services to customers primarily located within the New York City metropolitan area including New Jersey and Connecticut, as well as Rhode Island, Pennsylvania, Massachusetts and New Hampshire, through the following three lines of business: (i) Home Energy Services, which provides residential customers with service and maintenance of energy systems and appliances, as well as the retail marketing of natural gas and electricity to residential and small commercial customers; (ii) Business Solutions, which provides plumbing, heating, ventilation, air conditioning and mechanical contracting services, as well as operation and maintenance, design, engineering and consulting services to commercial, institutional and industrial customers; and (iii) Fiber Optic Services, which provides various services to carriers of voice and data transmission on Long Island and in New York City.
The Energy Investments segment consists of our gas exploration and production investments, as well as certain other domestic and international energy-related investments. Our gas exploration and production subsidiaries are engaged in gas and oil exploration and production, and the development and acquisition of domestic natural gas and oil properties. These investments consist of our ownership interest in Houston Exploration, an independent natural gas and oil exploration company, as well as KeySpan Exploration and Production, LLC, our wholly-owned subsidiary engaged in a joint venture with Houston Exploration. As previously mentioned, on February 26, 2003, we reduced our ownership interest in Houston Exploration from 66% to approximately 56% following the repurchase, by Houston Exploration, of 3 million shares of stock owned by KeySpan. We realized
$79 million in connection with this repurchase. Additionally, there is an over-allotment option for 300,000 shares, which if exercised, would further reduce our ownership in Houston Exploration to 55%. Subsidiaries in this segment also hold a 20% equity interest in the Iroquois Gas Transmission System LP, a pipeline that transports Canadian gas supply to markets in the Northeastern United States; a 50% interest in the Premier Transmission Pipeline and a 24.5% interest in Phoenix Natural Gas, both in Northern Ireland; and investments in certain midstream natural gas assets in Western Canada through KeySpan Canada. With the exception of our gas exploration and production subsidiaries and KeySpan Canada, which are consolidated in our financial statements, these subsidiaries are accounted for under the equity method. Accordingly, equity income from these investments is reflected in Other Income and (Deductions) in the Consolidated Statement of Income.
The accounting policies of the segments are the same as those used for the preparation of the Consolidated Financial Statements. Our segments are strategic business units that are managed separately because of their different operating and regulatory environments. Operating results of our segments are evaluated by management on an earnings before interest and taxes ("EBIT") basis. To reflect a complete picture of the electric operations, we reclassified, for all periods presented, KeySpan Energy Supply from the Energy Services segment to the Electric Services segment. This subsidiary provides commodity management and procurement services for fuel supply and management of energy sales, primarily for and from the Ravenswood facility. Due to the July 2002 sale of Midland Enterprises LLC, an inland marine barge business, this subsidiary is reported as discontinued operations for all periods presented. (See Note 9 "Discontinued Operations" for more information on the sale of Midland).
The reportable segment information below is shown excluding the operations of Midland:
Eliminating items include intercompany interest income and expense, the elimination of certain intercompany accounts, as well as activities of our corporate and administrative subsidiaries.
Electric Services revenues from LIPA and the NYISO of $1.4 billion for the year ended December 31, 2002, represents approximately 24% of our consolidated revenues during that period.
Eliminating items include intercompany interest income and expense and the elimination of certain intercompany accounts as well as activities of our corporate and administrative subsidiaries.
Electric Services revenues from LIPA and the NYISO of $1.4 billion for the year ended December 31, 2001 represents approximately 21% of our consolidated revenues during that period.
Eliminating items include intercompany interest income and expense and the elimination of certain intercompany accounts as well as activities of our corporate and administrative subsidiaries.
Electric Services revenues from LIPA, Consolidated Edison and the NYISO of $1.4 billion for the year ended December 31, 2000 represents approximately 28% of our consolidated revenues during that period.
Note 3. Income Tax
We file a consolidated federal income tax return. A tax sharing agreement between our holding company and its subsidiaries provides for the allocation of a realized tax liability or benefit based upon separate return contributions of each subsidiary to the consolidated taxable income or loss in the consolidated income tax returns. The subsidiaries record income tax payable or receivable from KeySpan resulting from the inclusion of their taxable income or loss in the consolidated return.
Income tax expense is reflected as follows in the Consolidated Statement of Income:
The components of deferred tax assets and (liabilities) reflected in the Consolidated Balance Sheet are as follows:
During the year ended December 31, 2002, an adjustment to deferred income taxes of $177.7 million was recorded to reflect a decrease in the tax basis of the assets acquired at the time of the KeySpan/LILCO combination. This adjustment resulted from a revised valuation study and the preparation of amended tax returns. Concurrent with this deferred tax adjustment, KeySpan reduced current income taxes payable by $183.2 million, resulting in a net $5.5 million income tax benefit. Currently, the Internal Revenue Service is auditing KeySpan's tax returns pertaining to the KeySpan/LILCO combination, as well as other return years. At this time, we cannot predict the outcome of the ongoing audit.
The following is a reconciliation between the effective tax rate and the federal income tax rate of 35%:
(1) Reflects both federal as well as state income taxes.
Note 4. Postretirement Benefits
Pension Plans: The following information represents the consolidated results for our noncontributory defined benefit pension plans which cover substantially all employees. Benefits are based on years of service and compensation. Funding for pensions is in accordance with requirements of federal law and regulations. KEDLI is subject to certain deferral accounting requirements mandated by the NYPSC for pension costs and other postretirement benefit costs.
Boston Gas Company is also subject to deferral accounting requirements, as previously ordered by the DTE, for other postretirement benefit costs. In addition, by DTE approval dated January 28, 2003, Boston Gas Company will defer for the year 2003, and record as either a regulatory asset or regulatory liability, the difference between the level of pension expense that is included in rates charged to gas customers and the actuarial determined amounts.
Information pertaining to discontinued operations has been excluded from this presentation.
The calculation of net periodic pension cost is as follows:
(1) See discussion of early retirement program at end of note. (2) See discussion of pension plan settlement.
Pension cost includes expense and income for KEDNE since November 8, 2000.
The following table sets forth the pension plans' funded status at December 31, 2002 and December 31, 2001. Plan assets are principally common stock and fixed income securities.
Pension Plan Settlement: In 2000, we settled certain participating contracts covering retiree pension plans with MetLife. As required under SFAS 88 "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits", a gain of $20.2 million was recognized as part of our pension cost for the year ended December 31, 2000.
Unfunded Pension Obligation: At December 31, 2001, accumulated benefit obligations were in excess of pension assets. As prescribed by SFAS 87 "Employers' Accounting for Pensions", we were required to record an additional $68.9 million minimum liability for this unfunded pension obligation. At December 31, 2002, the accumulated benefit obligations were re-measured which
resulted in a revised minimum liability of $286.3 million. As permitted under current accounting guidelines, this accrual can be offset by a corresponding debit to a long-term asset up to the amount of accumulated unrecognized prior service costs. Any remaining amount is to be recorded in Other Comprehensive Income.
Therefore, at year-end, we have recorded a long-term asset in Deferred Charges Other of $61.5 million. We also recorded a $118.6 million contractual receivable in Deferred Charges Other, representing the amount that would be recovered from LIPA in accordance with our service agreements if the underlying assumptions giving rise to this minimum liability were realized and recorded as pension expense. The remaining charge to equity of $106.2 million, or $69.0 million after-tax, has been recorded as a debit to Other Comprehensive Income. At December 31, 2002 the projected benefit obligation, accumulated benefit obligation and value of assets for plans with accumulated benefit obligations in excess of plan assets were $1.1 billion, $948.0 million and $621.0 million, respectively. At the end of each year, we will re-measure the accumulated benefit obligations and pension assets, and adjust the accrual and deferrals as appropriate.
Other Postretirement Benefits: The following information represents the consolidated results for our noncontributory defined benefit plans covering certain health care and life insurance benefits for retired employees. We have been funding a portion of future benefits over employees' active service lives through Voluntary Employee Beneficiary Association ("VEBA") trusts. Contributions to VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code.
Net periodic other postretirement benefit cost included the following components:
(1) See discussion of early retirement program at end of note. Other postretirement benefit costs include expense and income for KEDNE since November 8, 2000.
The following table sets forth the plans' funded status at December 31, 2002 and December 31, 2001. Plan assets are principally common stock and fixed income securities.
The measurement of plan liabilities also assumes a health care cost trend rate of 9% grading down to 5% in 2009 and thereafter. A 1% increase in the health care cost trend rate would have the effect of increasing the accumulated postretirement benefit obligation as of December 31, 2002 by $118.4 million and the net periodic health care expense by $11.0 million. A 1% decrease in the health care cost trend rate would have the effect of decreasing the accumulated postretirement benefit obligation as of December 31, 2002 by $104.6 million and the net periodic health care expense by $9.4 million.
At December 31, 2002, KeySpan had a contractual receivable from LIPA of $238 million representing the postretirement benefits associated with the electric business unit employees recorded in Deferred Charges Other in the Consolidated Balance Sheet. LIPA has been reimbursing us for costs related to the postretirement benefits of the electric business unit employees in accordance with the LIPA Agreements.
Early Retirement Program: In December 2000, we completed an early retirement program for certain management and union employees. Included in the pension and other postretirement benefits expense for the year ended December 31, 2000 are charges of $45.8 million and $5.6 million, respectively related to the early retirement program.
Defined Contribution Plan: KeySpan also offers both its union and management employees a defined contribution plan. Both the KeySpan Energy 401(k) Plan for Management Employees and the KeySpan Energy 401(k) Plan for Union Employees are available to all eligible employees. These Plans are defined contribution plans subject to Title I of the Employee Retirement Income Security Act of 1974 ("ERISA"). All eligible employees contributing to the Plan receive a certain employer matching contribution based on a percentage of the employee contribution, as well as a 10% discount on the KeySpan Common Stock Fund anywhere from three to twelve months after their date of hire depending upon the Plan. The matching contributions are in KeySpan's common stock. The match and discount amounts may be transferred out of common stock immediately. For the years ended December 31, 2002, 2001 and 2000, we recorded an expense equal to $11.2 million, $11.0 million and $6.7 million respectively.
Note 5. Capital Stock
Common Stock: Currently we have 450,000,000 shares of authorized common stock. In 1998, we initiated a program to repurchase a portion of our outstanding common stock on the open market. At December 31, 2002, we had 16.4 million shares, or approximately $475 million of Treasury Stock outstanding. We completed this repurchase plan in 1999 and now utilize Treasury Stock to satisfy our common stock plans. During 2002, we issued 3 million shares out of treasury for the dividend reinvestment feature of our Investor Program, the Employee Stock Discount Purchase Plan and the 401(k) Plan.
On January 17, 2003, KeySpan sold 13.9 million shares of common stock in a public offering that generated net proceeds of approximately $473 million. All shares were offered by KeySpan pursuant to the effective shelf registration statement filed with the SEC. Net proceeds from the equity sale were used initially to pay down commercial paper.
Preferred Stock: We have the authority to issue 100,000,000 shares of preferred stock with the following classifications: 16,000,000 shares of preferred stock, par value $25 per share; 1,000,000 shares of preferred stock, par value $100 per share; and 83,000,000 shares of preferred stock, par value $.01 per share.
At December 31, 2002 we had 553,000 shares outstanding of 7.07% Preferred Stock Series B par value $100; 197,000 shares outstanding of 7.17% Preferred Stock Series C par value $100; and 88,486 shares outstanding of 6% Preferred Stock Series A par value $100, in the aggregate totaling $83.8 million.
Boston Gas Company has 562,700 shares of 6.421% non-voting preferred stock par value $25 per share outstanding at December 31, 2002. This issue of preferred stock has a 5% annual sinking fund requirement and $1.5 million was paid on September 1, 2002 to satisfy this requirement. We have the option of increasing the sinking fund payment up to 10% per year. This issue is callable beginning in 2003 and is reflected in Minority Interest on the Consolidated Balance Sheet.
Note 6. Long-Term Debt
Gas Facilities Revenue Bonds: KEDNY can issue tax-exempt bonds through the New York State Energy Research and Development Authority. Whenever bonds are issued for new gas facilities projects, proceeds are deposited in trust and subsequently withdrawn to finance qualified expenditures. There are no sinking fund requirements on any of our Gas Facilities Revenue Bonds. At December 31, 2002, KEDNY had $648.5 million of Gas Facilities Revenue Bonds outstanding. The interest rate on the variable rate series due December 1, 2020 is reset weekly and ranged from 1.00% to 1.68% through December 31, 2002, at which time the rate was 1.28%.
Authority Financing Notes: One of our electric generation subsidiaries can issue tax-exempt bonds through the New York State Energy Research and Development Authority. At December 31, 2002, $41.1 million of Authority Financing Notes 1999 Series A Pollution Control Revenue Bonds due October 1, 2028 were outstanding. The interest rate on these notes is reset based on an auction procedure. The interest rate during the year ranged from 1.00% to 1.68%, through December 31, 2002, at which time the rate was 1.20%.
We also have outstanding $24.9 million variable rate 1997 Series A Electric Facilities Revenue Bonds due December 1, 2027. The interest rate on these bonds is reset weekly and ranged from .95% to 1.90% through December 31, 2002 at which time the rate was 1.60%.
Promissory Notes: In connection with the KeySpan/LILCO transaction, KeySpan and certain of its subsidiaries issued promissory notes to LIPA to support certain debt obligations assumed by LIPA. The remaining principal amount of promissory notes issued to LIPA was approximately $600 million at December 31, 2002. In February 2003, KeySpan notified LIPA of its intention to redeem approximately $447 million aggregate principal amount of such promissory notes at the applicable redemption prices plus accrued and unpaid interest through the dates of redemption. It is anticipated that such redemption will take place before the end of the first quarter of 2003. Under these promissory notes, KeySpan is required to obtain letters of credit to secure its payment obligations if its long-term debt is not rated at least in the "A" range by at least two nationally recognized statistical rating agencies.
Notes Payable: KEDLI had $125 million of Medium-Term Notes at 6.90% due January 15, 2008, and $400 million of 7.875% Medium-Term Notes due February 1, 2010, outstanding at December 31, 2002 each of which is guaranteed by KeySpan.
Further, KeySpan had $2.36 billion of Medium-Term Notes outstanding at December 31, 2002 of which $1.65 billion of these notes are associated with the acquisition of Eastern and ENI. These notes were issued in three series as follows: $700 million, 7.25% Notes due 2005; $700 million, 7.625% Notes due 2010 and $250 million, 8.00% Notes due 2030. The remaining Medium-Term Notes of $710 million have interest rates ranging from 6.15% to 9.75% and mature in 2005-2025.
In May 2002, we issued $460 million of MEDS Equity Units at 8.75% consisting of a three-year forward purchase contract for our common stock and a six-year note. The purchase contract commits us, three years from the date of issuance of the MEDS Equity Units, to issue and the investors to purchase, a number of shares of our common stock based on a formula tied to the market price of our common stock at that time. The 8.75% coupon is composed of interest payments on the six-year note of 4.9% and premium payments on the three-year equity forward contract of 3.85%. These instruments have been recorded as long-term debt on the Consolidated Balance Sheet. Further, upon issuance of the MEDS Equity Units, we recorded a direct charge to Retained Earnings of $49.1 million, which represents the present value of the forward contract's premium payments.
These securities are currently not considered convertible instruments for purposes of applying SFAS 128 "Earnings Per Share" calculations, unless or until such time as the market value of our common stock reaches a threshold appreciation price ($42.36 per share) that is higher than the current per share market value. Interest payments do, however, reduce net income and earnings per share.
The Emerging Issues Task Force of the FASB is considering proposals related to accounting for certain securities and financial instruments, including securities such as the Equity Units. The current proposals being considered include the method of accounting discussed above. Alternatively, other proposals being considered could result in the common shares issuable pursuant to the purchase contract to be deemed outstanding and included in the calculation of diluted earnings per share, and could result in periodic "mark to market" of the purchase contracts, causing periodic charges or credits to income. If this latter approach were adopted, our basic and diluted earnings per share could increase and decrease from quarter to quarter to reflect the lesser and greater number of shares issuable upon satisfaction of the contract, as well as charges or credits to income.
At December 31, 2001, KeySpan had authorization under PUHCA to issue up to $1 billion of securities and had an effective $1 billion shelf registration statement on file with the SEC, with $500 million available for issuance. In February 2002, we updated the shelf registration for the issuance of an additional $1.2 billion of securities, thereby giving KeySpan the ability to
issue up to $1.7 billion of debt, equity or various forms of preferred stock. The issuance of the MEDS Equity Units utilized $920 million of KeySpan's financing authority under both the shelf registration and the PUHCA financing authority. Both the $460 million six-year note and the $460 million forward equity contract are considered current issuances under these arrangements. On December 6, 2002, the SEC issued an order increasing the available authorization amount of financing under PUHCA to an aggregate of $780 million. Following the recent common stock offering mentioned in Note 5 "Capital Stock" and shares expected to be issued for employee benefit and dividend reinvestment plans, we have approximately $40 million available for the issuance of new securities under our current PUHCA authorization. However, the issuance of securities in connection with the redemption of existing securities (including the promissory notes discussed previously) is permitted under our PUHCA authorization notwithstanding the foregoing limit. We intend to seek authorization to issue additional securities in the near term.
At December 31, 2002, Houston Exploration had outstanding $100 million of 8.625% Senior Subordinated Notes due 2008. These notes were issued in a private placement in March 1998 and are subordinate to borrowings under Houston Exploration's line of credit. These notes are redeemable at the option of Houston Exploration after January 1, 2003.
First Mortgage Bonds: Colonial Gas Company, Essex Gas Company, ENI and their respective subsidiaries, have issued and outstanding approximately $163.6 million of first mortgage bonds. These bonds are secured by KEDNE gas utility property. The first mortgage bond indentures include, among other provisions, limitations on: (i) the issuance of long-term debt; (ii) engaging in additional lease obligations; and (iii) the payment of dividends from retained earnings.
In May 2002, Colonial Gas Company repaid $15 million of its 6.81% Series A First Mortgage Medium-Term Notes. These Notes would have matured on May 19, 2027, but the holder of the Notes elected to exercise a put option to redeem the Notes early.
Commercial Paper and Revolving Credit Agreements: In 2002, KeySpan renewed its existing 364-day revolving credit agreement with a commercial bank syndicate of 16 banks totaling $1.3 billion, a reduction from the previous $1.4 billion facility. The credit facility is used to back up the $1.3 billion commercial paper program. The fees for the facility are subject to a ratings-based grid, with an annual fee of .075% on the total amount of the revolving facility. The credit agreement allows for KeySpan to borrow using several different types of loans; specifically, Eurodollar loans, Adjustable Bank Rate ("ABR") loans, or competitively bid loans. Eurodollar loans are based on the Eurodollar rate plus a margin of 42.5 basis points for loans up to 33% of the facility, and an additional 12.5 basis points for loans over 33% of the total facility. ABR loans are based on the greater of the Prime Rate, the base CD rate plus 1%, or the Federal Funds Effective Rate plus 0.5%. Competitive bid loans are based on bid results requested by KeySpan from the lenders. We do not anticipate borrowing against this facility; however, if the credit rating on our commercial paper program were to be downgraded, it may be necessary to borrow on the credit facility.
The credit facility contains certain affirmative and negative operating covenants, including restrictions on KeySpan's ability to mortgage, pledge, encumber or otherwise subject its property to any lien and certain financial covenants that require us to, among other things, maintain a consolidated indebtedness to consolidated capitalization ratio of no more than 66%, a decrease from the 68% ratio required under the previous credit facility.
Under the terms of the credit facility, the calculation of KeySpan's debt-to-total capitalization ratio reflects 80% equity treatment for the MEDS Equity Units issued in May 2002. Further the $425 million Ravenswood master lease ("Master Lease") is treated as debt. (See Note 7 "Contractual Obligations, Financial Guarantees and Contingencies" for a discussion of the Ravenswood Master Lease.) At December 31, 2002, consolidated indebtedness, as calculated under the terms of the credit facility, was 64.6% of consolidated capitalization. As a result of the common stock offering previously mentioned, this ratio has been reduced to 59.8%. Violation of this covenant could result in the termination of the credit facility and the required repayment of amounts borrowed thereunder, as well as possible cross defaults under other debt agreements.
The credit facility also requires that net cash proceeds from the sale of subsidiaries be applied to reduce consolidated indebtedness. Further, an acceleration of indebtedness of KeySpan or one of its subsidiaries for borrowed money in excess of $25 million in the aggregate, if not annulled within 30 days after written notice, would create an event of default under the Indenture, dated as of November 1, 2000, between KeySpan Corporation and the Chase Manhattan Bank, as Trustee. At December 31, 2002, KeySpan was in compliance with all covenants.
At December 31, 2002, we had cash and temporary cash investments of $170.6 million. During, 2002, we repaid $132.8 million of commercial paper and, at December 31, 2002, $915.7 million of commercial paper was outstanding at a weighted average annualized interest rate of 1.52%. We had the ability to borrow up to an additional $384.3 million at December 31, 2002 under the commercial paper program.
During 2002, Houston Exploration entered into a new revolving credit facility with a commercial banking syndicate that replaced the existing $250 million revolving credit facility. The new facility provides Houston Exploration with an initial commitment of $300 million, which can be increased, at its option to a maximum of $350 million with prior approval from the banking syndicate. The new credit facility is subject to borrowing base limitations, initially set at $300 million and will be re-determined semi-annually. Up to $25 million of the borrowing base is available for the issuance of letters of credit. The new credit facility matures July 15, 2005, is unsecured and ranks senior to all existing debt.
Under the Houston Exploration credit facility, interest on base rate loans is payable at a fluctuating rate, or base rate, equal to the sum of (a) the greater of the federal funds rate plus 0.50% or the bank's prime rate plus (b) a variable margin between 0% and 0.50%, depending on the amount of borrowings outstanding under the credit facility. Interest on fixed loans is payable at a fixed rate equal to the sum of (a) a quoted reserve adjusted LIBOR rate plus (b) a variable margin between 1.25% and 2.00%, depending on the amount of borrowings outstanding under the credit facility.
Financial covenants require Houston Exploration to, among other things, (i) maintain an interest coverage ratio of at least 3.00 to 1.00 of earnings before interest, taxes and depreciation ("EBITDA") to cash interest; (ii) maintain a total debt to EBITDA ratio of not more than 3.50 to 1.00; and (iii) hedge no more than 70% of natural gas production during any 12-month period. At December 31, 2002, Houston Exploration was in compliance with all financial covenants.
During 2002, Houston Exploration borrowed $79.0 million under its credit facility and repaid $71.0 million. At December 31, 2002, $152 million of borrowings remained outstanding at a weighted average annualized interest rate of 3.42%. Also, $0.4 million was committed under outstanding letters of credit obligations. At December 31, 2002, $147.6 million of borrowing capacity was available.
KeySpan Canada has two revolving credit facilities with financial institutions in Canada. Repayments under these agreements totaled approximately US $26.1 million during 2002. At December 31, 2002, approximately US $150.9 million was outstanding at a weighted average annualized interest rate of 3.23%. KeySpan Canada currently has available borrowings of approximately US $55.8 million. These revolving credit agreements have been extended through January 2004. An event of default would exist under these credit facilities if KeySpan, as guarantor on the facilities, falls below investment grade rating or falls below A3 or A- at a time when its consolidated indebtedness is greater than 66% of consolidated capitalization or its cash flow to interest expense is less than 2.25 to 1.00. At December 31, 2002, KeySpan and KeySpan Canada were in compliance with all covenants.
Capital Leases: Our subsidiaries lease certain facilities and equipment under long-term leases, which expire on various dates through 2022. The weighted average interest rate on these obligations was 6.25%.
Debt Maturity: The following table reflects the maturity schedule for our debt repayment requirements, including capitalized leases and related maturities, at December 31, 2002:
- --------------------------------------------------------------------------- Long-Term Capital (In Thousands of Dollars) Debt Leases Total - --------------------------------------------------------------------------- Repayments: Year 1 $ 10,333 $ 1,080 $ 11,413 Year 2 333 1,033 1,366 Year 3 1,327,333 1,044 1,328,377 Year 4 512,333 1,003 513,336 Year 5 333 1,061 1,394 Thereafter 3,379,190 8,663 3,387,853 - --------------------------------------------------------------------------- $ 5,229,855 $ 13,884 $ 5,243,739 - ---------------------------------------------------------------------------
Note 7. Contractual Obligations, Financial Guarantees and Contingencies
Lease Obligations: Lease costs included in operation expense were $71.1 million in 2002 reflecting, primarily, the Master Lease and the lease of our Brooklyn headquarters of $29.1 million and $14.3 million, respectively. Lease costs also include leases for other buildings, office equipment, vehicles and power operated equipment. Lease costs for the year ended December 31, 2001 and 2000 were $75.8 million and $69.3 million, respectively. The future minimum lease payments under various leases, all of which are operating leases, are $80.8 million per year over the next five years and $200.9 million, in the aggregate, for all years thereafter, including future minimum lease payments for the Master Lease of $30.8 million per year over the next five years and $61.7 million for all years thereafter (See discussion below for further information regarding the Master Lease.)
Variable Interest Entity: KeySpan has an arrangement with a variable interest entity through which we lease a portion of the Ravenswood facility. We acquired the Ravenswood facility, in part, through the variable interest entity from Consolidated Edison on June 18, 1999 for approximately $597 million. In order to reduce the initial cash requirements, we entered into the Master Lease with a variable interest, unaffiliated financing entity that acquired a portion of the facility, or three steam generating units, directly from Consolidated Edison and leased it to our subsidiary. The variable interest unaffiliated financing entity acquired the property for $425 million, financed with debt of $412.3 million (97% of capitalization) and equity of $12.7 million (3% of capitalization). KeySpan has no ownership interests in the units or the variable interest entity.
KeySpan has guaranteed all payment and performance obligations of our subsidiary under the Master Lease. The Master Lease represents approximately $425 million of the acquisition cost of the facility, which is the amount of debt that would have been recorded on our Consolidated Balance Sheet had the variable interest entity not been utilized and conventional debt financing been employed. Further, we would have recorded an asset in the same amount. Monthly lease payments equal the monthly interest expense on such debt securities. The Master Lease currently qualifies as an operating lease for financial reporting purposes.
The initial term of the Master Lease expires on June 20, 2004 and may be extended until June 20, 2009. In June 2004, we have the right to: (i) either purchase the facility for the original acquisition cost of $425 million, plus the present value of the lease payments that would otherwise have been paid through June 2009; (ii) terminate the Master Lease and dispose of the facility; or (iii) otherwise extend the Master Lease to 2009. If the Master Lease is terminated in 2004, KeySpan has guaranteed an amount generally equal to 83% of the residual value of the original cost of the property, plus the present value of the lease payments that would have otherwise been paid through June 20, 2009. In June 2009, when the Master Lease terminates, we may purchase the facility in an amount equal to the original acquisition cost, subject to adjustment, or surrender the facility to the lessor. If we elect not to purchase the property, the Ravenswood facility will be sold by the lessor. We have guaranteed to the lessor 84% of the residual value of the original cost of the property.
In January 2003, the FASB issued FIN 46, "Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51." FIN 46 requires KeySpan, based upon its current status as the primary beneficiary, to consolidate this variable interest entity for the first interim period ending after June 15, 2003. It also requires that assets, liabilities and non-controlling interests of the variable interest entity be consolidated at fair value, except to the extent that to do so would result in a gain to KeySpan. KeySpan believes that the fair market value of the Ravenswood facility exceeds the fair market value of the lease obligation.
Prospectively, KeySpan will have a $425 million asset that will be amortized over the economic life of the leased property. However, upon implementation, there will be a cumulative catch-up adjustment for a change in accounting policy as if the asset had been owned from inception, or June 20, 1999. Therefore, at July 1, 2003, assuming a 35 year economic life, KeySpan will be deemed to have owned the asset for approximately 4 years and it is anticipated that we will record a $31.6 million after-tax charge, or $0.20 per share, change in accounting principle on the Consolidated Statement of Income. Upon implementation of FIN 46, therefore, we anticipate recording an asset of approximately $376 million and debt of $425 million.
Based upon expected average outstanding shares, we anticipate the incremental impact of the additional depreciation expense for the remaining six months of 2003 to be approximately $0.02 per share. In addition, KeySpan is also conducting a study to determine the fair value of the Ravenswood facility. Although considered unlikely, to the extent the fair value of the Ravenswood facility was less than the value of the lease obligation, then a loss would be recognized upon consolidation.
If our subsidiary that leases the Ravenswood facility was not able to fulfill its payment obligations with respect to the Master Lease payments, then the maximum amount KeySpan would be exposed to under its current guarantees would be $425 million plus the present value of the remaining lease payments through June 20, 2009.
KeySpan is currently exploring various options associated with the Master Lease, including but not limited to, restructuring the current leasing arrangement. At this time, we cannot predict the future structure of the leasing arrangement nor the impact on our financial position, results of operations or cash flows.
Financial Guarantees: KeySpan has issued financial guarantees in the normal course of business, primarily on behalf of its subsidiaries, to various third party creditors. At December 31, 2002, the following amounts would have to be paid by KeySpan in the event of non-payment by the primary obligor at the time payment is due:
The following is a description of KeySpan's outstanding subsidiary guarantees:
(i) KeySpan has fully and unconditionally guaranteed $525 million to holders of Medium-Term Notes issued by KEDLI. These notes are due to be repaid on January 15, 2008 and February 1, 2010. KEDLI is required to comply with certain financial covenants under the debt agreements. Currently, KEDLI is in compliance with all covenants and management does not anticipate that KEDLI will have any difficulty maintaining such compliance. The face value of these notes are included in Long-Term Debt on the Consolidated Balance Sheet.
(ii) KeySpan has guaranteed all payment and performance obligations of KeySpan Ravenswood, LLC, the lessee under the $425 million Master Lease associated with the lease of the Ravenswood facility. The initial term of the lease expires on June 20, 2004 and may be extended until June 20, 2009. For further information, see Variable Interest Entity above.
(iii)KeySpan has fully and unconditionally guaranteed a US $130 million revolving credit agreement associated with KeySpan Canada. The term of the agreement expires July 1, 2004.
(iv) KeySpan has purchased various surety and performance bonds associated with certain construction projects currently being performed by subsidiaries within the Energy Services segment. In the event that the operating companies in the Energy Services segment fail to perform their obligation under contract, the injured party may demand that the surety make payments or provide services under the bond. KeySpan would then be obligated to reimburse the surety for any expenses or cash outlays it incurs.
(v) KeySpan has guaranteed commodity-related payments for subsidiaries within the Energy Services segment, as well as KeySpan Ravenswood, LLC. These guarantees are provided to third parties to facilitate physical and financial transactions involved in the purchase of natural gas, oil and other petroleum products for electric production and marketing activities. The guarantees cover actual purchases by these subsidiaries that are still outstanding as of December 31, 2002.
(vi) KeySpan has issued stand-by letters of credit in the amount of $64.4 million to third parties that have extended credit to certain subsidiaries. Certain vendors require us to post letters of credit to guarantee subsidiary performance under our contracts and to ensure payment to our subsidiary subcontractors and vendors under those contracts. Certain of our vendors also require letters of credit to ensure reimbursement for amounts they are disbursing on behalf of our subsidiaries, such as to beneficiaries under our self-funded insurance programs. Such letters of credit are generally issued by a bank or similar financial institution. The letters of credit commit the issuer to pay specified amounts to the holder of the letter of credit if the holder demonstrates that we have failed to perform specified actions. If this were to occur, KeySpan would be required to reimburse the issuer of the letter of credit.
To date, KeySpan has not had a claim made against it for any of the above guarantees and we have no reason to believe that our subsidiaries will default on their current obligations. However, we cannot predict when or if any defaults may take place or the impact such details may have on our consolidated results of operations, financial condition or cash flows.
The following is a description of KeySpan's outstanding guarantees to non-affiliates:
(vii)KeySpan has agreed to support a line of credit up to $25 million on behalf of Hawkeye Construction ("Hawkeye"), a non-affiliated company. It also assisted Hawkeye in obtaining performance bonds. The guarantees related to their line of credit extend through 2004. To the extent Hawkeye does not meet its obligations, KeySpan could be liable for the amount of the outstanding guarantees. At December 31, 2002, the amount guaranteed was $25 million.
If Hawkeye fails to perform under a contract or to pay subcontractors and vendors, the counter-party that requested the performance bond may demand that the surety make payments or provide services under the bond. KeySpan would then have to reimburse the surety for any expenses or outlays the surety incurs. To date, we have not had a claim made against either the guarantee associated with the line of credit or the performance bonds. KeySpan is presently engaged in a legal action with Hawkeye as discussed further in "Legal Matters" below.
Fixed Charges Under Firm Contracts: Our utility subsidiaries and the Ravenswood facility have entered into various contracts for gas delivery, storage and supply services. The contracts have remaining terms that cover from one to thirteen years. Certain of these contracts require payment of annual demand charges in the aggregate amount of approximately $462.3 million. We are liable for these payments regardless of the level of service we require from third parties. Such charges are currently recovered from utility customers through the gas adjustment clause.
Legal Matters: From time to time we are subject to various legal proceedings arising out of the ordinary course of our business. Except as described below, we do not consider any of such proceedings to be material to our business or likely to result in a material adverse effect on our results of operations, financial condition or cash flows.
KeySpan has been cooperating in preliminary inquiries regarding trading in KeySpan Corporation stock by individual officers of KeySpan prior to the July 17, 2001 announcement that KeySpan was taking a special charge in its Energy Services business and otherwise reducing its 2001 earnings forecast. These inquiries are being conducted by the U.S. Attorney's Office, Southern District of New York and the SEC.
As previously reported, as part of its continuing inquiry, on March 5, 2002, the SEC issued a formal order of investigation, pursuant to which it will review the trading activity of certain company insiders from May 1, 2001 to the present, as well as KeySpan's compliance with its reporting rules and regulations, generally during the period following the acquisition of the Roy Kay companies through the July 17th announcement.
Furthermore, KeySpan and certain of its officers and directors are defendants in a number of class action lawsuits filed in the United States District Court for the Eastern District of New York after the July 17th announcement. These lawsuits allege, among other things, violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended ("Exchange Act"), in connection with disclosures relating to or following the acquisition of the Roy Kay companies by KeySpan Services, Inc., a KeySpan subsidiary and the announcement of the agreement to acquire Eastern and ENI. Finally, in October 2001, a shareholder's derivative action was commenced in the same court against certain officers and directors of KeySpan, alleging, among other things, breaches of fiduciary duty, violations of the New York Business Corporation Law and violations of Section 20(a) of the Exchange Act. In addition, a second derivative action has been commenced asserting similar allegations. Each of the proceedings seek monetary damages in an unspecified amount. We have filed a motion to dismiss the class action lawsuits which is currently pending. We are unable to determine the outcome of these proceedings and what effect, if any, such outcome will have on our financial condition, results of operations or cash flows.
In June 2002, Hawkeye Electric, LLC et al. ("Hawkeye") commenced an action in New York State Supreme Court, Suffolk County against KeySpan and certain of its subsidiaries alleging, among other things, that KeySpan and its subsidiaries breached certain contractual obligations to Hawkeye with respect to the provision of certain gas, electric and telecommunications construction services offered by Hawkeye. Hawkeye is seeking damages in excess of $90 million and KeySpan has alleged a number of counterclaims seeking damages in excess of $4 million. At this time, we are unable to determine the outcome of this proceeding and what effect, if any, such outcome will have on our financial position, results of operations or cash flows.
KeySpan subsidiaries, along with several other parties, have been named as defendants in numerous proceedings filed by plaintiffs claiming various degrees of injury from asbestos exposure. Most of these proceedings have been commenced in the New York State Supreme Court for New York County by alleged present or former employees of various contractors, allegedly as a result of exposure to
asbestos in connection with the construction and maintenance of our electric generating facilities. Certain subsidiaries have also been named as defendants in proceedings involving facilities not owned by KeySpan. At the present time, KeySpan is unable to determine the outcome of these proceedings, but does not believe that such outcome, if adverse, will have a material effect on its financial condition, results of operations or cash flows.
KeySpan, through its subsidiary, formerly known as Roy Kay, Inc., has terminated the employment of the former owners of the Roy Kay companies and commenced a proceeding in the Chancery Division of the Superior Court, Monmouth County, New Jersey (Docket No. Mon. C. 95-01) as a result of the alleged fraudulent acts of the former owners, both before and after the acquisition of the Roy Kay companies in January 2000. KeySpan believes the former owners misstated the financial statements of the Roy Kay companies and certain underlying work-in-progress schedules. KeySpan is seeking damages in excess of $76 million, as well as a judicial determination that KeySpan is not required to pay the former owners any further amounts under the terms of the stock purchase agreement entered into in connection with the acquisition of the Roy Kay companies. The causes of action include breach of contract and fiduciary duty, fraud, and violation of the New Jersey Securities Laws. The former owners have filed counterclaims against KeySpan and certain of its subsidiaries, as well as certain of their respective officers, to recover damages they claim to have incurred as a result of, among other things, their alleged improper termination and the alleged fraud on the part of KeySpan in failing to disclose the limitations imposed upon the Roy Kay companies, with respect to the performance of certain services under PUHCA. The fraud claims asserted by the former owners include claims under the New Jersey Uniform Securities Law and RICO statutes. We are unable to predict the outcome of these proceedings or what effect, if any, such outcome will have on our financial condition, results of operations or cash flows.
Environmental Matters
Air: With respect to NOx emissions reduction requirements for our existing power plants, we are required to be in compliance with the Phase III reduction requirements of the Ozone Transportation Commission memorandum by May 1, 2003, and we fully expect to achieve such emission reductions on time and in a cost-effective manner. Our expenditures to address emission reduction requirements through the year 2003 are expected to be between $10 million and $15 million.
Water: Additional capital expenditures associated with the renewal of the surface water discharge permits for our power plants may be required by the Department of Environmental Conservation ("DEC"). Until our monitoring obligations are completed and changes to the Environmental Protection Agency regulations under Section 316 of the Clean Water Act are promulgated, the need for and the cost of equipment upgrades cannot be determined.
Land: Manufactured Gas Plants and Related Facilities
New York Sites: Within the State of New York we have identified 28 manufactured gas plant ("MGP") sites and related facilities, which were historically owned or operated by KeySpan subsidiaries or such companies' predecessors. These former sites, some of which are no longer owned by us, have been identified to both the DEC for inclusion on appropriate site inventories and listing with the NYPSC.
We have identified 18 sites associated with the historic operations of KEDNY. Administrative Orders on Consent ("ACO") or Voluntary Cleanup Agreements have been executed with the DEC to address the investigation and remediation activities associated with three of these sites. In 2001, KEDNY filed a complaint for the recovery of its remediation costs in the New York State Supreme Court against the various insurance companies that issued general comprehensive liability policies to KEDNY. The outcome of this proceeding cannot yet be determined. We presently estimate the remaining environmental cleanup activities of these sites will be $81.1 million, which amount has been accrued by us. Expenditures incurred to date by us with respect to MGP-related activities total $26.8 million.
We have identified nine sites associated with the historic operations of KEDLI, six of which are the subject of two separate ACOs, which we executed with the DEC in 1999. Field investigations and, in some cases, interim remedial measures, are underway or scheduled to occur at each of these sites under the supervision of the DEC and the New York State Department of Health. Pursuant to a separate ACO also entered into in 1999, we have performed preliminary site assessments at five other sites, which were formerly owned by KEDLI. For one of these sites, the DEC has advised us that no further action is required. At another site, the DEC has indicated that a remedial investigation will be required. For the remaining three sites, KeySpan awaits the DEC's comments.
In January 1998, KEDLI filed a complaint for the recovery of its remediation costs in the New York State Supreme Court against the various insurance companies that issued general comprehensive liability policies to KEDLI. The outcome of this proceeding cannot yet be determined. We presently estimate the remaining environmental cleanup activities of these sites will be $61.1 million, which amount has been accrued by us. Expenditures incurred to date by us with respect to KEDLI MGP-related activities total $22.3 million.
We presently estimate the remaining cost of our New York/Long Island MGP-related environmental cleanup activities will be $142.2 million, which amount has been accrued by us as a reasonable estimate of probable cost for known sites. Expenditures incurred to date by us with respect to these MGP-related activities total $49.1 million.
With respect to remediation costs, the KEDNY rate plan provides, among other things, that if the total cost of investigation and remediation varies from that which is specifically estimated for a site under investigation and/or remediation, then KEDNY will retain or absorb up to 10% of the variation. The KEDLI rate plan also provides for the recovery of investigation and remediation costs but with no consideration of the difference between estimated and actual costs. Under prior rate orders, KEDNY has offset certain amounts due to ratepayers against its estimated environmental cleanup costs for MGP sites. At December 31, 2002, we have reflected a regulatory asset of $123.7 million for our New York/Long Island MGP sites.
We are also responsible for environmental obligations associated with the Ravenswood facility, purchased from Consolidated Edison in 1999, including remediation activities associated with its historic operations and those of the MGP facilities that formerly operated at the site. We are not responsible for liabilities arising from disposal of waste at off-site locations prior to the acquisition closing and any monetary fines arising from Consolidated Edison's pre-closing conduct. We presently estimate the remaining environmental clean up activities for this site will be $3.6 million, which amount has been accrued by us. Expenditures incurred to date total $1.4 million.
New England Sites: Within the Commonwealth of Massachusetts and the State of New Hampshire, we are aware of 76 former MGP sites and related facilities within the existing or former service territories of KEDNE.
Boston Gas Company, Colonial Gas Company and Essex Gas Company may have or share responsibility under applicable environmental laws for the remediation of 66 MGP sites and related facilities. A subsidiary of National Grid USA ("National Grid"), formerly New England Electric System, has assumed responsibility for remediating 11 of these sites, subject to a limited contribution from Boston Gas Company, and has provided full indemnification to Boston Gas Company with respect to eight other sites. At this time, there is substantial uncertainty as to whether Boston Gas Company, Colonial Gas Company or Essex Gas Company have or share responsibility for remediating any of these other sites. No notice of responsibility has been issued to us for any of these sites from any governmental environmental authority.
In March 1999, Boston Gas Company and a subsidiary of National Grid filed a complaint for the recovery of remediation costs in the Massachusetts Superior Court against various insurance companies that issued comprehensive general liability policies to National Grid and its predecessors with respect to, among other things, the 11 sites for which Boston Gas Company has agreed to make a limited contribution. The outcome of this proceeding cannot be determined at this time.
We presently estimate the remaining cost of these Massachusetts KEDNE MGP-related environmental cleanup activities will be $32.4 million, which amount has been accrued by us as a reasonable estimate of probable cost for known sites. Expenditures incurred since November 8, 2000 with respect to these MGP-related activities total $10.7 million.
We may have or share responsibility under applicable environmental laws for the remediation of 10 MGP sites and related facilities associated with the historical operations of EnergyNorth. EnergyNorth has received notice of its potential responsibility for contamination at two former MGP sites and, together with other potentially responsible parties, has received notice of potential responsibility for contamination associated with four other sites.
With respect to the Laconia and Nashua sites, EnergyNorth has entered into separate cost sharing agreements with Public Service of New Hampshire ("PSNH"). Under the agreements PSNH is obligated to indemnify EnergyNorth for future remediation costs, with limited exceptions, at the Laconia site and PSNH will pay EnergyNorth up to $4.8 million toward the costs of the investigation and remediation at the Nashua site. EnergyNorth also has entered into an agreement with the United States Environmental Protection Agency ("EPA") for the contamination from the Nashua site that was allegedly commingled with asbestos at the so-called Nashua River Asbestos Site, adjacent to the Nashua MGP site.
EnergyNorth has filed suit in both the New Hampshire Superior Court and the United States District Court for the District of New Hampshire for recovery of its remediation costs against the various insurance companies that issued comprehensive general liability and excess liability insurance policies to EnergyNorth and its predecessors. Settlements have been reached with some of the carriers and one carrier was dismissed from a Superior Court action on summary judgment. The outcome of the remaining proceedings cannot yet be determined. EnergyNorth has also filed a contribution action in the United States District Court for the District of New Hampshire against an entity it alleges shares liability for the Manchester MGP study and remediation costs.
We presently estimate the remaining cost of EnergyNorth MGP-related environmental cleanup activities will be $14.7 million, which amount has been accrued by us as a reasonable estimate of probable cost for known sites. Expenditures incurred since November 8, 2000, with respect to these MGP-related activities total $5.3 million.
By rate orders, the DTE and the NHPUC provide for the recovery of site investigation and remediation costs and, accordingly, at December 31, 2002, we have reflected a regulatory asset of $58.7 million for the KEDNE MGP sites. As previously mentioned, Colonial Gas Company and Essex Gas Company are not subject to the provisions of SFAS 71 and therefore have recorded no regulatory asset. However, rate plans currently in effect for these subsidiaries provide for the recovery of investigation and remediation costs.
KeySpan New England LLC Sites: We are aware of three non-utility sites associated with the historic operations of KeySpan New England, LLC, a successor company to Eastern Enterprises for which we may have or share environmental remediation responsibility or ongoing maintenance: the former Philadelphia Coke site located in Pennsylvania; the former Connecticut Coke site located in New Haven, Connecticut; and the former Everett Coal Tar Processing Facility (the "Everett Facility") located in Massachusetts. Honeywell International, Inc. and Beazer East, Inc. (both former owners and operators of the Everett Facility) together with KeySpan, have entered into an ACO with the Massachusetts Department of Environmental Protection for the investigation and development of a remedial response plan for the site.
KeySpan, Honeywell and Beazer East have entered into a cost-sharing agreement under which each company has agreed to pay one-third of the costs of compliance with the consent order, while preserving any claims it may have against the other companies. The companies have completed preliminary remedial measures, including abatement of seepage of materials into the adjacent tidal river. In 2002, Beazer East commenced an action with the U.S. District Court for the Southern District of New York which seeks a judicial determination on the allocation of liability for the Everett Facility. The outcome of this proceeding cannot yet be determined.
KeySpan also is recovering certain legal defense costs and may be entitled to recover remediation costs from its insurers. We presently estimate the remaining cost of our environmental cleanup activities for the three non-utility sites will be approximately $39.2 million, which amount has been accrued by us as a reasonable estimate of probable costs for known sites. Expenditures incurred since November 8, 2000, with respect to these sites total $4.0 million.
We believe that in the aggregate, the accrued liability for investigation and remediation of sites and related facilities identified above are reasonable estimates of likely cost within a range of reasonable, foreseeable costs. We may be required to investigate and, if necessary, remediate each of these, or other currently unknown former sites and related facility sites, the cost of which is not presently determinable but may be material to our financial position, results of operations or cash flows. Remediation costs for each site may be materially higher than noted, depending upon remediation experience, selected end use for each site, and actual environmental conditions encountered.
Note 8. Hedging, Derivative Financial Instruments and Fair Values
Financially-Settled Commodity Derivative Instruments: From time to time KeySpan has utilized derivative financial instruments, such as futures, options and swaps, for the purpose of hedging exposure to commodity price risk and to hedge the cash flow variability associated with a portion of peak electric energy sales.
Houston Exploration has utilized collars, as well as over-the-counter ("OTC") swaps to hedge the cash flow variability associated with forecasted sales of a portion of its natural gas production. As of December 31, 2002, Houston Exploration has hedged approximately 67% and 20% of its estimated 2003 and 2004 production, respectively. Further, Houston Exploration may enter into additional derivative positions for 2003 and 2004. Houston Exploration used standard New York Mercantile Exchange ("NYMEX") futures prices and published volatility in its Black-Scholes calculation to value its outstanding derivatives. The maximum length of time over which Houston Exploration has hedged such cash flow variability is through December 2004. The estimated amount of losses associated with such derivative instruments that are reported in Other Comprehensive Income and that are expected to be reclassified into earnings over the next twelve months is $34.9 million, or $22.7 million after-tax.
With respect to price exposure associated with fuel purchases for the Ravenswood facility, KeySpan employs standard NYMEX natural gas futures contracts and over-the-counter financially settled natural gas basis swaps to hedge the cash flow variability of a portion of forecasted purchases of natural gas. KeySpan also employs the use of financially-settled oil swap contracts to hedge the cash flow variability of a portion of forecasted purchases of fuel oil that will be
consumed at the Ravenswood facility. The maximum length of time over which we have hedged cash flow variability associated with: (i) forecasted purchases of natural gas is through December 2003; and (ii) forecasted purchases of fuel oil is through April 2004. We used standard NYMEX futures prices to value the gas futures contracts and industry published oil indices for number 6 grade fuel oil to value the oil swap contracts. The estimated amount of gains associated with all such derivative instruments that are reported in Other Comprehensive Income and that are expected to be reclassified into earnings over the next twelve months is $4.5 million, or $2.9 million after-tax.
Our retail gas and electric marketing subsidiary, our domestic gas distribution operations and KeySpan Canada employed NYMEX natural gas futures contracts and natural gas swaps to lock-in a price for expected future natural gas purchases. As applicable, we used standard NYMEX futures prices and relevant natural gas indices to value the outstanding contracts. The maximum length of time over which we have hedged such cash flow variability is through December 2003. The estimated amount of gains associated with such derivative instruments that are reported in Other Comprehensive Income and that are expected to be reclassified into earnings over the next twelve months is $4.9 million, or $3.2 million after-tax.
We have also engaged in the use of cash-settled swap instruments to hedge the cash flow variability associated with (i) a portion of forecasted peak electric energy sales from the Ravenswood facility and (ii) forecasted sales of Unforced Capacity ("UCAP") to the NYISO. The maximum length of time over which we have hedged cash flow variability is through March 2004. We used NYISO-location zone published indices as well as published NYISO bidding prices to value these outstanding derivatives. The estimated amount of losses associated with such derivative instruments that are reported in Other Comprehensive Income and that are expected to be reclassified into earnings over the next twelve months is $1.1 million, or $0.7 million after-tax.
KeySpan Canada also has employed electricity swap contracts to lock-in the purchase price of electricity needed to operate its gas processing plants. These contracts are not exchange-traded and local published indices were used to value these outstanding swap agreements. The maximum length of time over which we have hedged such cash flow variability is through December 2003. The estimated amount of losses associated with such derivative instruments that are reported in Other Comprehensive Income and that are expected to be reclassified into earnings over the next twelve months is $1.5 million, or $1.0 million after-tax.
The following tables set forth selected financial data associated with these derivative financial instruments noted above that were outstanding at December 31, 2002.
- ------------------------------------------------------------------------------ Change in Fair Value of Derivative Instruments 2002 ($000) - ------------------------------------------------------------------------------ Fair value of contracts at January 1, $ 55,097 (Gain) on contracts realized (26,204) Fair value of new contracts when entered into during period - (Decrease) in fair value of all open contracts (61,521) - ------------------------------------------------------------------------------ Fair value of contracts outstanding at December 31, $ (32,628) - ------------------------------------------------------------------------------
NYMEX futures are also used to economically hedge the cash flow variability associated with the purchase of fuel for a portion of our fleet vehicles. Further, KeySpan Canada has a portfolio of financially-settled natural gas collars and natural gas liquid swap transactions. Such contracts are executed by KeySpan Canada to: (i) synthetically fix the price that is paid or received by KeySpan Canada for certain physical transactions involving natural gas and natural gas liquids and (ii) transfer the price exposure of such instruments to other trading partners. In addition, our retail gas and electric marketing subsidiary has bought options to economically hedge the cash flow variability associated with a portion of expected future natural gas purchases. These derivative financial instruments do not qualify for hedge accounting under SFAS 133. At December 31, 2002, these instruments had a net fair market value of ($0.4) million, that was recorded on the Consolidated Balance Sheet. Based on the non-hedge designation of these instruments, the loss was recognized in the Consolidated Statement of Income.
Firm Gas Sales Derivative Instruments - Regulated Utilities: We also use derivative financial instruments to reduce the cash flow variability associated with the purchase price for a portion of future natural gas purchases. Our strategy is to minimize fluctuations in firm gas sales prices to our regulated firm gas sales customers in our New York and New Hampshire service territories. Since these derivative instruments are employed to reduce the variability of the purchase price of natural gas to be sold to regulated firm gas sales customers, the accounting for these derivative instruments is subject to SFAS 71. Therefore, changes in the market value of these derivatives have been recorded as a Regulatory Asset or Regulatory Liability on the Consolidated Balance Sheet. Gains or losses on the settlement of these contracts are initially deferred and then refunded to or collected from our firm gas sales customers during the appropriate winter heating season consistent with regulatory requirements.
The following table sets forth selected financial data associated with these derivative financial instruments that were outstanding at December 31, 2002.
Physically-Settled Commodity Derivative Instruments: On April 1, 2002 we implemented Derivative Implementation Group ("DIG") Issue C15 and C16 of Statement of Financial Accounting Standard 133, "Accounting for Derivative Instruments and Hedging Activities", as amended and interpreted, incorporating SFAS 137 and SFAS 138 and certain implementation issues (collectively "SFAS 133"). Issue C15 establishes new criteria that must be satisfied in order for option-type and forward contracts in electricity to be exempted as normal purchases and sales, while Issue C16 relates to the exemption (as normal purchases and normal sales) of contracts that combine a forward contract and a purchased option contract. Based upon a review of our physical commodity contracts, we determined that certain contracts for the physical purchase of natural gas can no longer be exempted as normal purchases from the requirements of SFAS 133. At December 31, 2002, the fair value of these contracts was $1.2 million. Since these contracts are for the purchase of natural gas sold to regulated firm gas sales customers, the accounting for these contracts is subject to SFAS 71. Therefore, changes in the market value of these contracts have been recorded as a Regulatory Asset or Regulatory Liability on the Consolidated Balance Sheet.
Interest Rate Derivative Instruments: During most of 2002, we had interest rate swap agreements in which approximately $1.3 billion of fixed rate debt had been synthetically modified to floating rate debt. Under the terms of the agreements, we received the fixed coupon rate associated with these bonds and paid the counter-parties a variable interest rate that was reset on a quarterly basis. These swaps were designated as fair-value hedges and qualified for "short-cut" hedge accounting treatment under SFAS 133. Through the utilization of these agreements, we reduced recorded interest expense by $35.6 million for the twelve months ended December 31, 2002.
In early November 2002, we terminated two interest rate swap agreements with an aggregate notional amount of $1.0 billion and received $80.9 million from our swap counter-parties, of which $23.4 million represented accrued swap interest. The difference between the termination settlement amount and the amount of accrued swap interest, $57.4 million, will be amortized to earnings (as an adjustment to interest expense) on a level yield basis over the remaining lives of the originally hedged debt obligations. The remaining swap, which had a notional amount of $270.0 million, and a fair market value of $15.6 million at December 31, 2002, was terminated on February 25, 2003. We received $18.4 million from our swap counter-parties, of which $8.1 million represents accrued swap interest. The difference between the termination settlement amount and the amount of accrued interest, $10.3 million, will be recorded to earnings in the first quarter of 2003. This swap was used to hedge a portion of our outstanding promissory notes to LIPA. As discussed in Note 6 "Long-Term Debt", we intend to redeem a portion of these promissory notes before the end of the first quarter of 2003.
Additionally, we also have an interest rate swap agreement that hedges the cash flow variability associated with the forecasted issuance of a series of commercial paper offerings. The maximum length of time over which we have hedged such cash flow variability is through March 2003. The estimated amount of loss associated with such derivative instruments that are reported in Other Comprehensive Income and that are expected to be reclassified into earnings over the next twelve months is $0.6 million, or $0.4 million after-tax.
Weather Derivatives: The utility tariffs associated with the KEDNE's operations do not contain weather normalization adjustments. As a result, fluctuations from normal weather may have a significant positive or negative effect on the results of these operations. To mitigate a substantial portion of the effect of fluctuations from normal weather on our financial position and cash flows, we sold heating degree-day call options and purchased heating degree-day put options for the November 2002 - March 2003 winter season. With respect to sold call options, KeySpan is required to make a payment of $40,000 per heating degree-day to its counter-parties when actual weather experienced during the November 2002 - March 2003 time frame is above 4,470 heating degree days, which equates to approximately 1% colder than normal weather. With respect to purchased put options, KeySpan will receive a $20,000 per heating degree day payment from its counter-parties when actual weather is below 4,150 heating degree days, or is approximately 7% warmer than normal. Based on the terms of
such contracts, as discussed in Note 1 "Summary of Significant Accounting Policies", we account for such instruments pursuant to the requirements of EITF 99-2, "Accounting for Weather Derivatives." In this regard, we account for such instruments using the "intrinsic value method" as set forth in such guidance. During the fourth quarter of 2002, weather was 7% colder than normal and, as a result, $3.3 million has been recorded as a reduction to revenues.
Derivative contracts are primarily used to manage exposure to market risk arising from changes in commodity prices and interest rates. In the event of nonperformance by a counter-party to a derivative contract, the desired impact may not be achieved. The risk of a counter-party nonperformance is generally considered credit risk and is actively managed by assessing each counter-party credit profile and negotiating appropriate levels of collateral and credit support.
Fair Values of Long-Term Debt
- --------------------------------------------------------------------------- December 31, (In Thousands of Dollars) 2002 2001 - --------------------------------------------------------------------------- First Mortgage Bonds $ 180,666 $ 182,666 Notes 3,441,619 3,076,455 Gas Facilities Revenue Bonds 674,828 630,845 Authority Financing Notes 66,005 66,005 Promissory Notes 616,240 617,933 MEDS Equity Units 525,918 - - --------------------------------------------------------------------------- $ 5,505,276 $ 4,573,904 - ---------------------------------------------------------------------------
Carrying Values of Long-Term Debt
- ----------------------------------------------------------------------------- December 31, (In Thousands of Dollars) 2002 2001 - ----------------------------------------------------------------------------- First Mortgage Bonds $ 163,625 $ 179,122 Notes 2,985,000 2,985,000 Gas Facilities Revenue Bonds 648,500 648,500 Authority Financing Notes 66,005 66,005 Promissory Notes 602,427 602,427 MEDS Equity Units 460,000 - - ----------------------------------------------------------------------------- $ 4,925,557 $ 4,481,054 - -----------------------------------------------------------------------------
Our subsidiary debt is carried at an amount approximating fair value because interest rates are based on current market rates. All other financial instruments included in the Consolidated Balance Sheet such as cash, commercial paper, accounts receivable and accounts payable, are also stated at amounts that approximate fair value.
Note 9. Discontinued Operations
On November 8, 2000, KeySpan acquired Midland Enterprises LLC ("Midland"), an inland marine transportation subsidiary, as part of the Eastern acquisition. In its order approving the acquisition, the SEC required KeySpan to sell this subsidiary by November 8, 2003 because Midland's operations were not functionally related to KeySpan's core utility operations. On July 2, 2002, the sale of Midland to Ingram Industries Inc. was completed and net proceeds of $175.1 million were received from the sale.
Discontinued operations for the year ended December 31, 2001 included an anticipated after-tax loss on disposal of $30.4 million. As a result of a change in the tax structuring strategy related to the sale of Midland, in the second quarter of 2002 we recorded an additional provision for city and state taxes and made adjustments to the estimates used in the December 31, 2001 loss provision. These changes resulted in an additional after tax loss on disposal of $19.7 million.
The following is selected financial information for Midland for the period January 1, 2002 through July 2, 2002 and the year ended December 31, 2001 and for the period November 8, 2000 through December 31, 2000:
Assets and liabilities of the discontinued operations are as follows:
- ------------------------------------------------------------------------ (In Thousands of Dollars) 2001 - ------------------------------------------------------------------------ Current assets $ 139,522 Property, plant and equipment, net 316,626 Long-term assets 35,233 Current liabilities (58,835) Long-term liabilitites (241,491) - ------------------------------------------------------------------------ Assets held for disposal $ 191,055 - ------------------------------------------------------------------------
Note 10. Roy Kay Operations
During 2001, we undertook a complete evaluation of the strategy, operating controls and organizational structure of the Roy Kay companies - plumbing, mechanical, electrical and general contracting companies acquired by us in January 2000. We decided to discontinue the general contracting business conducted by these companies based upon our view that the general contracting business is not a core competency of these companies. Certain remaining activities engaged in by the Roy Kay companies have been integrated with those of other KeySpan energy-related businesses. During 2002, substantially all of the remaining field work on outstanding construction projects was completed. We are now engaged in the finalization of claims and collections and, as a result, their operations will continue to be consolidated in our Consolidated Financial Statements until such time as this process is complete.
For the year ended December 31, 2001, the Roy Kay companies incurred an after-tax loss of $95.0 million ($137.8 million pre-tax) reflecting: (i) unanticipated costs to complete work on certain construction projects; (ii) the impact of inaccuracies in the books of these companies relating to their overall financial and operational performance; (iii) discontinuance costs of the general contracting activities of those companies, including the write-off of goodwill, and certain account and retainage receivables; and (iv) operating losses. For the years ended December 31, 2002, 2001 and 2000 the Roy Kay companies recorded EBIT losses of $10.8 million, $137.8 million and EBIT earnings of $1.3 million, respectively. KeySpan and the former Roy Kay companies are currently engaged in litigation relating to the termination of the former owners, as well as other matters relating to the acquisition of the Roy Kay companies. (See Note 7 "Contractual Obligations and Contingencies" - Legal Matters.)
Note 11. Class Action Settlement
During 2001, we reversed a previously recorded loss provision regarding certain pending rate refund issues relating to the 1989 RICO class action settlement. This adjustment resulted from a favorable United States Court of Appeals ruling received on September 28, 2001, overturning a lower court decision, and resulted in a positive pre-tax adjustment to earnings of $33.5 million, or $20.1 million after-tax. This adjustment has been reflected as a $22.0 million reduction to Operations and Maintenance expense and a reduction of $11.5 million to Interest Expense on the Consolidated Statement of Income.
Note 12. KeySpan Gas East Corporation Summary Financial Data
KEDLI is a wholly owned subsidiary of KeySpan. KEDLI was formed on May 7, 1998 and on May 28, 1998 acquired substantially all of the assets related to the gas distribution business of LILCO. KEDLI provides gas distribution services to customers in the Long Island counties of Nassau and Suffolk and the Rockaway peninsula of Queens county. KEDLI established a program for the issuance, from time to time, of up to $600 million aggregate principal amount of Medium-Term Notes, which will be fully and unconditionally guaranteed by the parent, KeySpan Corporation. On February 1, 2000, KEDLI issued $400 million of 7.875% Medium-Term Notes due 2010. In January 2001, KEDLI issued an additional $125 million of Medium-Term Notes at 6.9% due January, 2008. The following condensed financial statements are required to be disclosed by SEC regulations and set forth those of KEDLI, KeySpan Corporation as guarantor of the Medium- Term Notes and our other subsidiaries on a combined basis. The December 31, 2001 and 2000 disclosures have been revised to separately present our other subsidiaries.
Note 13. Eastern/EnergyNorth Acquisition
On November 8, 2000, we purchased all of the outstanding stock of Eastern for $64.56 per share in cash and all of the outstanding common stock of ENI for $61.46 per share in cash. Itemization of the purchase price is as follows:
- -------------------------------------------------------------- (In Thousands of Dollars) - -------------------------------------------------------------- Eastern Enterprises Common Stock $ 1,754,400 EnergyNorth Common Stock 204,200 Transaction costs 10,200 Other 2,000 - -------------------------------------------------------------- Total Consideration $ 1,970,800 - --------------------------------------------------------------
The transactions have been accounted for using the purchase method of accounting for business combinations. Accordingly, the accompanying Consolidated Statement of Income includes Eastern and ENI results commencing November 8, 2000. The purchase price was allocated to the net assets acquired based upon their fair value. The historical cost basis of Eastern's and ENI's assets and liabilities, with minor exceptions, was determined to represent the fair value due to the existence of regulatory-approved rate plans based upon the recovery of historical costs and a fair return thereon. The allocation of the purchase price to the assets and liabilities acquired from Eastern and ENI was as follows:
* Certain non-regulated long-term assets of Eastern were increased by approximately $25 million to reflect the fair value of such assets at the date of acquisition. Further, no intangible assets were acquired as part of this transaction.
The following is the comparative unaudited proforma condensed financial information for the year ended December 31, 2000. The proforma disclosures reflect the results of the operations of Eastern and ENI as if our acquisitions were consummated on January 1, 2000.
- -------------------------------------------------------------------------------- Year Ended (In Thousands of Dollars, Except Per Share Amounts) December 31, 2000 - -------------------------------------------------------------------------------- Revenues $ 6,130,158 Operating Income $ 671,081 Net Income $ 114,393 Earnings Per Share $ 0.71 - --------------------------------------------------------------------------------
Included in the 2000 pro-forma earnings are merger related costs of $76.0 million, after-tax, recorded by Eastern and ENI in connection with our acquisition of these companies. Excluding these costs, pro-forma earnings were $1.27 per share for the year ended December 31, 2000. These pro-forma results may not be indicative of future results. Further, the consolidated pro-forma results for 2000 do not take into account: (i) continued gas sales growth throughout our service territories, especially on Long Island and in New England; (ii) earnings enhancement from our gas exploration and production operations; and (iii) the continued successful integration of acquired companies providing energy-related services within our Energy Services segment.
Note 14. Workforce Reduction Programs
As a result of the Eastern and ENI acquisitions, we implemented early retirement and severance programs in an effort to reduce our workforce. The early retirement program was completed in December 2000, at which time KeySpan recorded a charge of $51.4 million to reflect termination benefits related to employees who voluntarily elected early retirement. In addition, KeySpan recorded a $13.8 million liability associated with severance programs; Eastern and ENI had previously recorded an additional liability of $8.9 million. The combined liability, therefore, was $22.7 million. During the year ended December 31, 2001, we reduced this liability by $4.1 million as a result of lower than anticipated costs per employee and recorded a corresponding reduction to goodwill. During 2002, we paid $3.5 million for the program and, in total, $13.6 million was distributed to employees during the past two years. The remaining liability of $5.0 million was reversed and recorded to earnings in 2002.
Note 15. Shareholder Rights Plan
On March 30, 1999, our Board of Directors adopted a Shareholder Rights Plan (the "Plan") designed to protect shareholders in the event of a proposed takeover. The Plan creates a mechanism that would dilute the ownership interest of a potential unauthorized acquirer. The Plan establishes one preferred stock purchase "right" for each outstanding share of common stock to shareholders of record on April 14, 1999. Each right, when exercisable, entitles the holder to purchase 1/100th of a share of Series D Preferred Stock, at a price of $95.00. The rights generally become exercisable following the acquisition of more than 20 percent of our common stock without the consent of the Board of Directors. Prior to becoming exercisable, the rights are redeemable by the Board of Directors for $0.01 per right. If not so redeemed, the rights will expire on March 30, 2009.
Note 16. Subsequent Events
Subsequent to December 31, 2002, the following events ocurred:
On January 17, 2003, KeySpan sold 13.9 million shares of common stock in a public offering. The offering generated net proceeds of approximately $473 million. All shares were offered by KeySpan pursuant to the effective shelf registration statement filed with the SEC. Net proceeds from the sale were used initially to pay down commercial paper.
On February 25, 2003 we terminated an interest rate swap agreement that had a notional amount of $270 million and received $18.4 million from our swap counter-parties of which $8.1 million represents accrued swap interest. The difference between the termination settlement amount and the amount of accrued swap interest, $10.3 million, will be recorded through earnings in the first quarter of 2003. This swap was used to hedge a portion of our outstanding promissory notes to LIPA. As discussed in Note 6 "Long-Term Debt", we intend to redeem a portion of these promissory notes before the end of the first quarter of 2003.
On February 26, 2003, we reduced our ownership interest in Houston Exploration from 66% to approximately 56% following the repurchase, by Houston Exploration, of 3 million shares of stock owned by KeySpan. The net proceeds of approximately $79 million received in connection with this repurchase were used to pay down commercial paper. Additionally there is an over-allotment option for 300,000 shares, which if exercised would further reduce our ownership in Houston Exploration to 55%.
In connection with the class action lawsuit discussed in Note 7, regarding among other things, alleged violations of Sections 10(b) and 20(a) of the Exchange Act, on March 18, 2003 the court granted our motion to dismiss the complaint. The court's order dismissed certain class allegations with prejudice but provided the plaintiffs a final opportunity to file an amended complaint concerning the remaining allegations. (Unaudited)
Note 17. Supplemental Gas and Oil Disclosures (Unaudited)
This information includes amounts attributable to 100% of Houston Exploration and KeySpan Exploration and Production, LLC at December 31, 2002. Shareholders other than KeySpan had a minority interest of approximately 34% in Houston Exploration at December 31, 2002, 33% in 2001 and 30% in 2000. Gas and oil operations, and reserves, were located in the United States in all years.
* (Excluding corporate overhead and interest costs)
The gas and oil reserves information is based on estimates of proved reserves attributable to the interest of Houston Exploration and KeySpan Exploration and Production, LLC as of December 31 for each of the years presented. These estimates principally were prepared by independent petroleum consultants. Proved reserves are estimated quantities of natural gas and crude oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
(1) Includes minority interest of 208,516, 188,077, and 167,730 in 2002, 2001, and 2000, respectively.
(2) Includes minority interest of 148,811, 148,593 and 133,271in 2002, 2001, and 2000, respectively.
(1) Includes minority interest of 2,256, 2,186 and 1,695 in 2002, 2001, and 2000, respectively. (2) Includes minority interest of 824, 821 and 573 in 2002, 2001, and 2000, respectively.
The standardized measure of discounted future net cash flows was prepared by applying year-end prices of gas and oil to the proved reserves. The standardized measure does not purport, nor should it be interpreted, to present the fair value of gas and oil reserves of Houston Exploration or KeySpan Exploration and Production LLC. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
(1) Includes minority interest of 361,435, 182,555 and 653,046 in 2002, 2001 and 2000, respectively
Costs included in future development costs related to proved undeveloped reserves for the years ending December 31, 2003, 2004 and 2005 are $155.6 million, $38.2 million and $7.0 million, respectively.
*Represents the cash price received which excludes the effect of any hedging transactions.
Acreage - ------------------------------------------------------------------------------- At December 31, 2002 Gross Net - ------------------------------------------------------------------------------- Producing 396,988 262,659 Undeveloped 267,666 228,428 - -------------------------------------------------------------------------------
Number of Producing Wells - ------------------------------------------------------------------------------ At December 31, 2002 Gross Net - ------------------------------------------------------------------------------ Gas wells 1,593.0 861.3 Oil wells 10.0 6.1 - ------------------------------------------------------------------------------
Wells in Process - -------------------------------------------------------------------------------- At December 31, 2002 Gross Net - -------------------------------------------------------------------------------- Exploratory 5.0 2.8 Developmental 7.0 6.2 - --------------------------------------------------------------------------------
Note 18. Summary of Quarterly Information (Unaudited)
The following is a table of financial data for each quarter of KeySpan's year ended December 31, 2002.
(a) Quarterly earnings per share are based on the average number of shares outstanding during each quarter. Because of the changing number of common shares outstanding in each quarter, the sum of quarterly earnings per share does not necessarily equal earnings per share for the year.
The following is a table of financial data for each quarter of KeySpan's year ended December 31, 2001.
(a) Reflects costs to complete work on certain construction projects, as well as operating losses of the Roy Kay Companies of $35.6 million after-tax.
(b) Reflects the reversal of a previously recorded loss provision regarding certain pending rate refund issues of $20.1 after-tax. Also includes losses incurred by the Roy Kay Companies of $56.6 million after-tax related to the discontinuance of the general contracting activities of these companies.
(c) Reflects an after-tax non-cash impairment charge of $26.2 million to recognize the effect of lower wellhead prices on the valuation of proved gas reserves, as well as after-tax operating losses of the Roy Kay Companies of $2.8 million.
(d) Quarterly earnings per share are based on the average number of shares outstanding during each quarter. Because of the changing number of common shares outstanding in each quarter, the sum of quarterly earnings per share does not necessarily equal earnings per share for the year.
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors of KeySpan Corporation:
We have audited the accompanying Consolidated Balance Sheet of KeySpan Corporation and subsidiaries (the Company) as of December 31, 2002, and the related Consolidated Statements of Income, Retained Earnings, Comprehensive Income, Capitalization, and Cash Flows for the year then ended. Our audit also included the consolidated financial statement schedule, for the year ended December 31, 2002, listed in the Index at Item 14 (a). These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and the consolidated financial schedule based on our audit. The consolidated financial statements of KeySpan Corporation for the years ended December 31, 2001 and 2000 were audited by other auditors who have ceased operations. Their report, dated February 4, 2002, expressed an unqualified opinion on those statements.
We conducted our audit in accordance with auditing standards generally accepted in the United States of America. 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the KeySpan Corporation and subsidiaries as of December 31, 2002, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, on January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142 "Goodwill and Other Intangible Assets," (SFAS No. 142) to change its method of accounting for goodwill and other intangible assets.
As discussed above, the consolidated financial statements of the Company as of December 31, 2001, and for the two years in the period then ended were audited by other auditors who have ceased operations. The notes related to these consolidated financial statements have been revised to include the transitional disclosures required by SFAS No. 142, which was adopted by the Company as of January 1, 2002. Our audit procedures with respect to the disclosures in Note 1 G for 2001 and 2000 included (i) agreeing the previously reported earnings for common stockholders to the previously issued consolidated financial statements and the adjustments to earnings for common stockholders representing amortization expense recognized in those periods related to goodwill to the Company's underlying records obtained from management, and (ii) testing the mathematical accuracy of the reconciliation of adjusted net income to reported earnings for common shareholders, and the related earnings-per-share amounts. In addition, Note 12 has also been revised. Our auditing procedures with respect to the disclosures in Note 12 for 2001 and 2000 included (i) agreeing the amounts in the guarantor and other subsidiaries columns to underlying consolidating records obtained from management, (ii) comparing the sum of these columns to the previously issued consolidated financial statements, and (iii) testing the mathematical accuracy of the schedule. In our opinion, the adjustments in Notes 1G and 12 are appropriate and have been properly applied. However, we were not engaged to audit, review, or apply any procedures to the 2001 and 2000 financial statements of the Company other than with respect to such adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2001 and 2000 financial statements taken as a whole.
DELOITTE & TOUCHE LLP February 10, 2003 (February 26, 2003, as to Note 16) New York, New York
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of KeySpan Corporation d/b/a/ KeySpan Energy:
We have audited the accompanying Consolidated Balance Sheet and Consolidated Statement of Capitalization of KeySpan Corporation (a New York corporation) and subsidiaries as of December 31, 2001 and December 31, 2000 and the related Consolidated Statements of Income, Retained Earnings, Comprehensive Income and Cash Flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the KeySpan Corporation's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position and capitalization of KeySpan Corporation and subsidiaries as of December 31, 2001 and December 31, 2000 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in Item 14 is the responsibility of the KeySpan Corporation's management and is presented for the purpose of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP February 4, 2002 New York, New York
Readers of these consolidated financial statements should be aware that this report is a copy of a previously issued Arthur Andersen LLP report and that this report has not been reissued by Arthur Andersen LLP. Furthermore, this report has not been updated since February 4, 2002 and Arthur Anersen LLP completed its last post-audit review of the December 31, 2001, consolidated financial information on April 29, 2002.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Arthur Andersen LLP ("Arthur Andersen") served as KeySpan's independent public accountants since May 1998. On March 29, 2002, KeySpan's Board of Directors, upon recommendation of the Audit Committee, determined not to renew the engagement of Arthur Andersen and appointed Deloitte & Touche LLP ("Deloitte & Touche") as independent public accountants. During the past two fiscal years through March 29, 2002, there was no report on the financial statements of the Company by either Deloitte & Touche or Arthur Andersen that contained an adverse opinion or a disclaimer of opinion, or was qualified or modified as to uncertainty, audit scope, or accounting principles. During the past two fiscal years through March 29, 2002, there were no disagreements with either Deloitte & Touche or Arthur Andersen on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure which, if not resolved to the satisfaction of either Deloitte & Touche or Arthur Andersen, would have caused the firm to make reference to the subject matter of such disagreements in connection with their respective reports.
Part III
Item 10.
Item 10. Directors and Executive Officers of the Registrant
A definitive proxy statement will be filed with the SEC on or about March 26, 2003 (the "Proxy Statement"). The information required by this item is set forth under the caption "Executive Officers of the Company" in Part I hereof and under the captions "Proposal 1. Election of Directors" and "Section 16(a) Beneficial Ownership Reporting Compliance" contained in the Proxy Statement, which information is incorporated herein by reference thereto.
Item 11.
Item 11. Executive Compensation
The information required by this item set forth under the captions "Director Compensation" and "Executive Compensation" in the Proxy Statement, which information is incorporated herein by reference thereto.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The information required by this item is set forth under the captions "Security Ownership of Management" and "Security Ownership of Certain Beneficial Owners" in the Proxy Statement, which information is incorporated herein by reference thereto.
Item 13.
Item 13. Certain Relationships and Related Transactions
The information required by this item is set forth under the caption "Agreements with Executives," "Transactions with Management and Others" and "Involvement in Certain Proceedings" in the Proxy Statement, which information is incorporated by reference thereto.
Item 14.
Item 14. Controls and Procedures
(a) Evaluation of Disclosure Controls and Procedures
Within the 90 days prior to the date of this report, KeySpan carried out an evaluation, under the supervision and with the participation of KeySpan's management, including KeySpan's Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of KeySpan's disclosure controls and procedures. KeySpan's disclosure controls and procedures are designed to ensure that information required to be disclosed by KeySpan in its periodic SEC filings is recorded, processed and reported within the time periods specified in the SEC's rules and forms. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that KeySpan's disclosure controls and procedures are effective in timely alerting them to material information relating to KeySpan (including its consolidated subsidiaries) required to be included in KeySpan's periodic SEC filings.
(b) Changes In Internal Controls
There were no significant changes in KeySpan's internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.
Item 15.
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)
1. Financial Statements
The following consolidated financial statements of KeySpan and its subsidiaries and report of independent accountants are included in Item 8 and are filed as part of this Report:
o Consolidated Statement of Income for the year ended December 31, 2002, the year ended December 31, 2001, and the year ended December 31, 2000 o Consolidated Statement of Retained Earnings for the year ended December 31, 2002, the year ended December 31, 2001, and the year ended December 31, o Consolidated Balance Sheet at December 31, 2002 and December 31, 2001 o Consolidated Statement of Capitalization at December 31, 2002 and December 31, 2001 o Consolidated Statement of Cash Flows for the year ended December 31, 2002, the year ended December 31, 2001, and the year ended December 31, 2000 o Consolidated Statement of Comprehensive Income for the Year ended December 31, 2002, the year ended December 31, 2001 and the year ended December 31, o Notes to Consolidated Financial Statements o Report of Independent Public Accountants
2. Financial Statement Schedules
Consolidated Schedule of Valuation and Qualifying Accounts for the year ended December 31, 2002, the year ended December 31, 2001, and the year ended December 31, 2000.
All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto.
SCHEDULE OF VALUATION AND QUALIFYING ACCOUNTS
(b) Reports on Form 8-K
In our report on Form 8-K dated October 24, 2002, we disclosed that we had issued a press release concerning, among other things, our earnings for the third quarter ended September 30, 2002.
In our report on Form 8-K dated December 12, 2002, we disclosed that we had issued a press release concerning, among other things, 2003 earnings guidance.
In our report on Form 8-K dated January 13, 2003, we disclosed that we had issued a press release announcing our proposed issuance of approximately 14,000,000 shares of common stock.
In our report on Form 8-K dated January 14, 2003, we disclosed that we had issued a press release discussing the anticipated net proceeds from the offering of common stock announced on January 13, 2003.
In our report on Form 8-K dated January 15, 2003, we disclosed that we had issued a press release announcing that our proposed issuance of approximately 14,000,000 shares of common stock announced on January 13, 2003, would be offered at variable prices.
In our report on Form 8-K dated January 28, 2003, we disclosed that we had issued a press release concerning, among other things, our consolidated earnings for the year ended December 31, 2002.
In our report on Form 8-K dated February 21, 2003, we disclosed that we had issued a press release concerning, among other things, a proposed sale of a portion of our ownership interest in The Houston Exploration Company.
(c) Exhibits
Exhibits listed below which have been filed with the SEC pursuant to the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, and which were filed as noted below, are hereby incorporated by reference and made a part of this report with the same effect as if filed herewith.
2 Purchase Agreement by and among Eastern Enterprises, Landgrove Corp. and KeySpan Corporation for the acquisition of Midland Enterprises dated as of January 23, 2002 (filed as Exhibit 2 to the Company's Form 10-K for the year ended December 31, 2001)
3.1 Certificate of Incorporation of the Company effective April 16, 1998, Amendment to Certificate of Incorporation of the Company effective May 26,1998, Amendment to Certificate of Incorporation of the Company effective June 1, 1998, Amendment to the Certificate of Incorporation of the Company effective April 7, 1999 and Amendment to the Certificate of Incorporation of the Company effective May 20, 1999 (filed as Exhibit 3.1 to the Company's Form 10-Q for the quarterly period ended June 30, 1999)
3.2 ByLaws of the Company in effect on April 25, 2002, as amended (filed as Exhibit 3.1 to the Company's Form 10-Q for the quarterly period ended March 31, 2002)
* Filed herewith ** Management Contract or Compensation Plan
4.1-a Indenture, dated as of November 1, 2000, between KeySpan Corporation and the Chase Manhattan Bank, as Trustee, with the respect to the issuance of Debt Securities (filed as Exhibit 4-a to Amendment No. 1 to Form S-3 Registration Statement No. 333-43768 and filed as Exhibit 4-a to the Company's Form 8-K on November 20, 2000)
4.1-b Form of Note issued in connection with the issuance of the 7.25% notes issued on November 20, 2000 (filed as Exhibit 4-b to the Company's Form 8-K on November 20, 2000)
4.1-c Form of Note issued in connection with the issuance of the 7.625% notes issued on November 20, 2000 (filed as Exhibit 4-c to the Company's Form 8-K on November 20, 2000)
4.1-d Form of Note issued in connection with the issuance of the 8.0% notes issued on November 20, 2000 (filed as Exhibit 4-d to the Company's Form 8-K on November 20, 2000)
4.1-e Form of Note issued in connection with the issuance of the 6.15% notes issued on May 24, 2001 (filed as Exhibit 4 to the Company's Form 8-K on May 24, 2001)
4.2-a Indenture, dated December 1, 1999, between KeySpan and KeySpan Gas East Corporation, the Registrants, and the Chase Manhattan Bank, as Trustee, with respect to the issuance of Medium-Term Notes, Series A, (filed as Exhibit 4-a to Amendment No. 1 to the Company's and KeySpan Gas East Corporation's Form S-3 Registration Statement No. 333-92003)
4.2-b Form of Medium-Term Note issued in connection with the issuance of KeySpan Gas East Corporation 7 7/8% notes issued on February 1, 2000 (filed as Exhibit 4 to the Company's Form 8-K on February 1, 2000)
4.2-c Form of Medium-Term Note issued in connection with the issuance of KeySpan Gas East Corporation 6.9% notes issued on January 19, 2001 (filed as Exhibit 4.3 to the Company's Form 10-K for the year ended December 31, 2000)
4.3-a Participation Agreements dated as of February 1, 1989, between NYSERDA and The Brooklyn Union Gas Company relating to the Adjustable Rate Gas Facilities Revenue Bonds ("GFRBs") Series 1989A and Series 1989B (filed as Exhibit 4 to The Brooklyn Union Gas Company's Form 10-K for the year ended September 30, 1989)
4.3-b Indenture of Trust, dated February 1, 1989, between NYSERDA and Manufacturers Hanover Trust Company, as Trustee, relating to the Adjustable Rate GFRBs Series 1989A and 1989B (filed as Exhibit 4 to the Brooklyn Union Gas Company's Form 10-K for the year ended September 30, 1989)
4.3-c First Supplemental Participation Agreement dated as of May 1, 1992 to Participation Agreement dated February 1, 1989 between NYSERDA and The Brooklyn Union Gas Company relating to Adjustable Rate GFRBs, Series 1989A & B (filed as Exhibit 4 to The Brooklyn Union Gas Company's Form 10-K for the year ended September 30, 1992)
4.3-d First Supplemental Trust Indenture dated as of May 1, 1992 to Trust Indenture dated February 1, 1989 between NYSERDA and Manufacturers Hanover Trust Company, as Trustee, relating to Adjustable Rate GFRBs, Series 1989A & B (filed as Exhibit 4 to The Brooklyn Union Gas Company's Form 10-K for the year ended September 30, 1992)
* Filed herewith ** Management Contract or Compensation Plan
4.4-a Participation Agreement, dated as of July 1, 1991, between NYSERDA and The Brooklyn Union Gas Company relating to the GFRBs Series 1991A and 1991B (filed as Exhibit 4 to The Brooklyn Union Gas Company's Form 10-K for the year ended September 30, 1991)
4.4-b Indenture of Trust, dated as of July 1, 1991, between NYSERDA and Manufacturers Hanover Trust Company, as Trustee, relating to the GFRBs Series 1991A and 1991B (filed as Exhibit 4 to The Brooklyn Union Gas Company's Form 10-K for the year ended September 30, 1991)
4.5-a Participation Agreement, dated as of July 1, 1992, between NYSERDA and The Brooklyn Union Gas Company relating to the GFRBs Series 1993A and 1993B (filed as Exhibit 4 to The Brooklyn Union Gas Company's Form 10-K for the year ended September 30, 1992)
4.5-b Indenture of Trust, dated as of July 1, 1992, between NYSERDA and Chemical Bank, as Trustee, relating to the GFRBs Series 1993A and 1993B (filed as Exhibit 4 to The Brooklyn Union Gas Company Form 10-K for the year ended September 30, 1992)
4.6-a First Supplemental Participation Agreement dated as of July 1, 1993 to Participation Agreement dated as of June 1, 1990, between NYSERDA and The Brooklyn Union Gas Company relating to GFRBs Series C (filed as Exhibit 4 to The Brooklyn Union Gas Company's Form 10-K for the year ended September 30, 1993)
4.6-b First Supplemental Trust Indenture dated as of July 1, 1993 to Trust Indenture dated as of June 1, 1990 between NYSERDA and Chemical Bank, as Trustee, relating to GFRBs Series C (filed as Exhibit 4 to The Brooklyn Union Gas Company's Form 10-K for the year ended September 30, 1993)
4.7-a Participation Agreement, dated July 15, 1993, between NYSERDA and Chemical Bank as Trustee, relating to the GFRBs Series D-1 1993 and Series D-2 1993 (filed as Exhibit 4 to The Brooklyn Union Gas Company's Form S-8 Registration Statement No. 33-66182)
4.7-b Indenture of Trust, dated July 15, 1993, between NYSERDA and Chemical Bank as Trustee, relating to the GFRBs Series D-1 1993 and D-2 1993 (filed as Exhibit 4 to The Brooklyn Union Gas Company's Form S-8 Registration Statement No. 33-66182)
4.8-a Participation Agreement, dated January 1, 1996, between NYSERDA and The Brooklyn Union Gas Company relating to GFRBs Series 1996 (filed as Exhibit 4 to The Brooklyn Union Gas Company's Form 10-K for the year ended September 30, 1996)
4.8-b Indenture of Trust, dated January 1, 1996, between NYSERDA and Chemical Bank, as Trustee, relating to GFRBs Series 1996 (filed as Exhibit 4 to The Brooklyn Union Gas Company's Form 10-K for the year ended September 30, 1996)
4.9-a Participation Agreement, dated as of January 1, 1997, between NYSERDA and The Brooklyn Union Gas Company relating to GFRBs 1997 Series A (filed as Exhibit 4 to The Brooklyn Union Gas Company's Form 10-K for the year ended September 30, 1997)
4.9-b Indenture of Trust, dated January 1, 1997, between NYSERDA and Chase Manhattan Bank, as Trustee, relating to GFRBs 1997 Series A (filed as Exhibit 4 to The Brooklyn Union Gas Company's Form 10-K for the year ended September 30, 1997)
* Filed herewith ** Management Contract or Compensation Plan
4.9-c Supplemental Trust Indenture, dated as of January 1, 2000, by and between New York State NYSERDA and The Chase Manhattan Bank, as Trustee, relating to the GFRBs 1997 Series A (filed as Exhibit 4.11 to the Company's Form 10-K for the year ended December 31, 1999)
4.10-a Participation Agreement dated as of December 1, 1997 by and between NYSERDA and Long Island Lighting Company relating to the 1997 EFRBs, Series A (filed as Exhibit 10(a) to the Company's Form 10-Q for the quarterly period ended September 30, 1998)
4.10-b Indenture of Trust dated as of December 1, 1997 by and between NYSERDA and The Chase Manhattan Bank, as Trustee, relating to the 1997 Electric Facilities Revenue Bonds (EFRBs), Series A (filed as Exhibit 10(a) to the Company's Form 10-Q for the quarterly period ended September 30, 1998)
4.11-a Participation Agreement, dated as of October 1, 1999, by and between NYSERDA and KeySpan Generation LLC relating to the 1999 Pollution Control Refunding Revenue Bonds, Series A (filed as Exhibit 4.10 to the Company's Form 10-K for the year ended December 31, 1999)
4.11-b Trust Indenture, dated as of October 1, 1999, by and between NYSERDA and The Chase Manhattan Bank, as Trustee, relating to the 1999 Pollution Control Refunding Revenue Bonds, Series A (filed as Exhibit 4.10 to the Company's Form 10-K for the year ended December 31, 1999)
4.12 Indenture dated as of December 1, 1989 between Boston Gas Company and The Bank of New York, Trustee (Filed as Exhibit 4.2 to Boston Gas Company's Form S-3 (File No. 33-31869).
4.13 Agreement of Registration, Appointment and Acceptance dated as of November 18, 1992 among Boston Gas Company, The Bank of New York as Resigning Trustee, and The First National Bank of Boston as Successor Trustee. (Filed as an exhibit to Boston Gas Company's S-3 Registration S (File No. 33-31869))
4.14. Second Amended and Restated First Mortgage Indenture for Colonial Gas Company dated as of June 1, 1992 (filed as Exhibit 4(b) to Colonial Gas Company's Form 10-Q for the quarter ended June 30, 1992)
4.15 First Supplemental Indenture for Colonial Gas Company dated as of June 15, 1992 (filed as Exhibit 4(c) to Colonial Gas Company's Form 10-Q for the quarter ended June 30, 1992)
4.16 Second Supplemental Indenture for Colonial Gas Company dated as of September 27, 1995 (filed as Exhibit 4(c) to Colonial Gas Company's Form 10-K for the fiscal year ended December 31, 1995)
4.17 Amendment to Second Supplemental Indenture for Colonial Gas Company dated as of October 12, 1995 (filed as Exhibit 4(d) to Colonial Gas Company's Form 10-K for the fiscal year ended December 31, 1995)
4.18 Third Supplemental Indenture for Colonial Gas Company dated as of December 15, 1995 (filed as Exhibit 4(f) to Colonial Gas Company's Form S-3 Registration Statement dated January 5, 1998)
4.19 Fourth Supplemental Indenture for Colonial Gas Company dated as of March 1, 1998 (filed as Exhibit 4(l) to Colonial Gas Company's Form 10-Q for the quarter ended March 31, 1998)
* Filed herewith ** Management Contract or Compensation Plan
4.20 Trust Agreement dated as of June 22, 1990 between Colonial Gas Company (as Trustor) and Shawmut Bank, N.A. (as Trustee) (filed as Exhibit 10(d) to Colonial Gas Company's Form 10-Q for the period ended June 30, 1990)
4.21 Gas Service, Inc. General and Refunding Mortgage Indenture, dated as of June 30, 1987, as amended and supplemented by a First Supplemental Indenture, dated as of October 1, 1988, and by a Second Supplemental Indenture, dated as of August 31, 1989 (filed as Exhibit 4.1 to EnergyNorth, Inc.'s Form 10-K for the fiscal year ended September 30, 1989 (File No. 0-11035)
4.22 Third Supplemental Indenture, dated as of September 1, 1990, to Gas Service, Inc. General and Refunding Mortgage Indenture, dated as of June 30, 1987 (filed as Exhibit 4.2 to EnergyNorth, Inc.'s Form 10-K for the fiscal year ended September 30, 1990 (File No. 0-11035)
4.23 Fourth Supplemental Indenture, dated as of January 10, 1992, to Gas Service, Inc. General and Refunding Mortgage Indenture, dated as of June 30, 1987 (filed as Exhibit 4.3 of EnergyNorth, Inc.'s Form 10-K for the fiscal year ended September 30, 1992 (File No. 0-11035)
4.24 Fifth Supplemental Indenture, dated as of February 1, 1995, to Gas Service, Inc. General and Refunding Mortgage Indenture, dated as of June 30, 1987 (filed as Exhibit 4.4 to EnergyNorth, Inc.'s Form 10-K for the fiscal year ended September 30, 1996 (File No. 1-11441)
4.25 Sixth Supplemental Indenture, dated as of September 15, 1997, to Gas Service, Inc. General and Refunding Mortgage Indenture, dated as of June 30, 1987 (filed as Exhibit 4.5 to EnergyNorth Natural Gas, Inc.'s Amendment No. 1 to Registration Statement on Form S-1, No. 333-32949, dated September 10, 1997)
4.26 Indenture dated as of June 1, 1986 between Essex Gas Company and Centerre Trust Company of St. Louis, Trustee. (Filed as an Exhibit to Essex Gas Company's Registration Statement on Form S-2, filed June 19, 1986, File No. 33-6597).
4.27 Twelfth Supplemental Indenture dated as of December 1, 1990, between Essex Gas Company and Centerre Trust Company of St. Louis, Trustee, providing for a 10.10 percent Series due 2020. (Filed as Exhibit 4-14 to Essex Gas Company's Form 10-Q for the quarter ended February 28, 1991).
4.28 Fifteenth Supplemental Indenture dated as of December 1, 1996, between Essex Gas Company and Centerre Trust Company of St. Louis, Trustee, providing for a 7.28 percent Series due 2017. (Filed as Exhibit 4.5 to the Essex Gas Company's Form 10-Q for the quarter ended February 28, 1997).
4.29 Bond Purchase Agreement dated December 1, 1990, between Allstate Life Insurance Company of New York, and Essex County Gas Company. (Filed as an Exhibit to Company's Form 10-Q for the quarter ended February 28, 1991).
4.30-a Letter of Credit and Reimbursement Agreement, dated as of December 1, 2000, by and between KeySpan Generation LLC and National Westminister Bank PLC relating to the Electric Facilities Revenue Bonds ("EFRBs") Series 1997A (filed as Exhibit 4.10 to the Company's Form 10-K for the year ended December 31, 2000).
4.30-b* Extension Agreement, dated as of November 20, 2002 by and between KeySpan Generation LLC and National Westmnister Bank PLC, relating to the Letter of Credit and Reimbursement Agreement, dated as of December 1, 2000
* Filed herewith ** Management Contract or Compensation Plan
4.31 Indenture, dated as of March 2, 1998, between The Houston Exploration Company and The Bank of New York, as Trustee, with respect to the 8 5/8% SENIOR Subordinated Notes Due 2008 (including form of 8 5/8% SENIOR Subordinated Note Due 2008) (filed as Exhibit 4.1 to The Houston Exploration Company's Registration Statement on Form S-4 (No. 333-50235))
10.1 Amendment, Assignment and Assumption Agreement dated as of September 29, 1997 by and among The Brooklyn Union Gas Company, Long Island Lighting Company and KeySpan Energy Corporation (filed as Exhibit 2.5 to Schedule 13D by Long Island Lighting Company on October 24, 1997)
10.2 Agreement and Plan of Merger dated as of June 26, 1997 by and among BL Holding Corp., Long Island Lighting Company, Long Island Power Authority and LIPA Acquisition Corp. (filed as Annex D to Registration Statement on Form S-4, No. 333-30353 on June 30, 1997)
10.3 Agreement of Lease between Forest City Jay Street Associates and The Brooklyn Union Gas Company dated September 15, 1988 (filed as an exhibit to The Brooklyn Union Gas Company's Form 10-K for the year ended September 30, 1996)
10.4-a Management Services Agreement between Long Island Power Authority and Long Island Lighting Company dated as of June 26, 1997 (filed as Annex D to Registration Statement on Form S-4, No. 333-30353, on June 30, 1997)
10.4-b* Amendment dated as of March 29, 2002 to Management Services Agreement between Long Island Lighting Company d/b/a LIPA and KeySpan Electric Services LLC dated as of June 26, 1997
10.5 Power Supply Agreement between Long Island Lighting Company and Long Island Power Authority dated as of June 26, 1997 (filed as Annex D to Registration Statement on Form S-4, No. 333-30353, on June 30, 1997)
10.6-a Energy Management Agreement between Long Island Lighting Company and Long Island Power Authority dated as of June 26, 1997 (filed as Annex D to Registration Statement on Form S-4, No. 333-30353, on June 30, 1997)
10.6-b* Amendment dated as of March 29, 2002 to Energy Management Agreement between Long Island Lighting Company d/b/a LIPA and KeySpan Energy Trading Services LLC dated as of June 26, 1997
10.7-a Generation Purchase Rights Agreement between Long Island Lighting Company and Long Island Power Authority dated as of June 26, 1997 (filed as Exhibit 10.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 2001)
10.7-b Amendment dated as of March 29, 2002 to Generation Purchase Right Agreement by and between KeySpan Corporation as Seller, and Long Island Lighting Company d/b/a LIPA as Buyer, dated as of June 26, 1997 (filed as Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2002)
10.8** Employment Agreement dated September 10, 1998, between KeySpan and Robert B. Catell (filed as Exhibit (10)(b) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1998)
10.9** First Amendment dated as of February 24, 2000, to the Employment Agreement dated September 10, 1998, between KeySpan and Robert B. Catell (filed as Exhibit 10.12-a to the Company's Annual Report on Form 10-K for the year ended December 31, 2000)
* Filed herewith ** Management Contract or Compensation Plan
10.10** Second Amendment dated as of June 26, 2002, to the Employment Agreement dated September 10, 1998, between KeySpan and Robert B. Catell (filed as Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2002)
10.11* Supplemental Retirement Agreement dated January 1, 2002 between KeySpan and Gerald Luterman
10.12* Supplemental Retirement Agreement dated January 1, 2002 between KeySpan and Steven L. Zelkowitz
10.13* Supplemental Retirement Agreement dated January 1, 2002 between KeySpan and David J. Manning
10.14* Supplemental Retirement Agreement dated January 1, 2002 between KeySpan and Neil Nichols
10.15* Supplemental Retirement Agreement dated January 1, 2002 between KeySpan and Elaine Weinstein
10.16** Amended Directors' Deferred Compensation Plan (filed as Exhibit 10.27 to the Company's Form 10-K for the year ended December 31, 2001)
10.17** * Officers' Deferred Stock Unit Plan of KeySpan Corporation
10.18** * Officers' Deferred Stock Unit Plan KeySpan Services, Inc.
10.19** Corporate Annual Incentive Compensation and Gainsharing Plan (filed as Exhibit 10.20 to the Company's Form 10-K for the year ended December 31, 2000)
10.20** Senior Executive Change of Control Severance Plan effective as of October 30, 1998 (filed as Exhibit 10.20 to the Company's Form 10-K for the year ended December 31, 1998)
10.21** KeySpan's Amended Long Term Performance Incentive Compensation Plan (filed as Exhibit A to the Company's 2001 Proxy Statement on March 23, 2001)
10.22 Rights Agreement dated March 30, 1999, between the KeySpan and the Rights Agent (filed as Exhibit 4 to the Company's Form 8-K, on March 30, 1999)
10.23 Generating Plant and Gas Turbine Asset Purchase and Sale Agreement for Ravenswood for Ravenswood Generating Plants and Gas Turbines dated January 28, 1999, between the KeySpan and Consolidated Edison Company of New York, Inc. (filed as Exhibit 10(a) to the Company's Form 10-Q for the quarterly period ended March 31, 1999)
10.24 Lease Agreement dated June 9, 1999, between KeySpan-Ravenswood, LLC and LIC Funding, Limited Partnership (filed as Exhibit 10.2 to the Company's Form 10-Q for the quarterly period ended June 30, 1999)
10.25* First Amendment to the Lease between KeySpan-Ravenswood, LLC and LIC Funding, Limited Partnership, dated as of June 27, 2002
10.26 Guaranty dated June 9, 1999, from KeySpan in favor of LIC Funding, Limited Partnership (filed as Exhibit 10.1 to the Company's Form 10-Q for the quarterly period ended June 30, 1999)
10.27* Purchase Agreement by and among Duke Energy Gas Transmission Corporation, Algonquin Energy, Inc., KeySpan LNG GP, LLC and KeySpan LNG LP, dated as of December 12, 2002
* Filed herewith ** Management Contract or Compensation Plan
10.28 Restated Exploration Agreement between The Houston Exploration Company and KeySpan Exploration and Production, L.L.C., dated June 30, 2000, (filed as Exhibit 10.1 to The Houston Exploration Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2000, File No. 001-11899)
10.29 Revolving Credit Facility between The Houston Exploration Company and Wachovia Bank, National Association, as issuing bank and administrative agent, Bank of Nova Scotia and Fleet National Bank as co-syndication agents and BNP Paribas as documentation agent dated July 15, 2002 (filed as Exhibit 10.1 to The Houston Exploration Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 001-11899)
10.30-a Credit Agreement among KeySpan Energy Development Co. several Lenders and the Royal Bank of Canada, as Agent, for $125,000,000 (Canadian) Credit Facility, dated as of October 13, 2000 (filed as Exhibit 10.10 to the Company's Annual Report on Form 10-K for the year ended December 31, 2001)
10.30-b Consent, Waiver and Amending Agreement among KeySpan Energy Development Co., several Lenders and the Royal Bank of Canada, as Agent, for the $125,000,000 (Canadian) Credit Facility, dated as of December 22, 2000 (filed as Exhibit 10.11 to the Company's Annual Report on Form 10-K for the year ended December 31, 2001)
10.30-c Second Amending Agreement among KeySpan Energy Development Co., several Lenders and the Royal Bank of Canada, as Agent, for the $125,000,000 (Canadian) Credit Facility, dated as of October 12, 2001 (filed as Exhibit 10.12 to the Company's Annual Report on Form 10-K for the year ended December 31, 2001)
10.30-d* Extendible Revolving Credit Facility Amended and Restated Credit Agreement among KeySpan Energy Development Co., National Bank Financial, ATB Financial and Certain Financial Institutions with National Bank of Canada, dated as of January 24, 2003
10.31-a Credit Agreement among KeySpan Energy Development Co., Borrower, the Several Lenders' and Royal Bank of Canada, Administrative Agent, dated July 29, 1999 (filed as Exhibit 10.37-a to the Company's Annual Report on Form 10-K for the year ended December 31, 2001)
10.31-b First Amending Agreement dated as of October 13, 2000 to the Credit Agreement among KeySpan Energy Development Co., Borrower, the Several Lenders' and Royal Bank of Canada, Administrative Agent dated July 29, 1999 (filed as Exhibit 10.37-b to the Company's Annual Report on Form 10-K for the year ended December 31, 2001)
10.31-c Second Amending Agreement dated as of December 15, 2000 to the Credit Agreement among KeySpan Energy Development Co., Borrower, the Several Lenders' and Royal Bank of Canada, Administrative Agent dated July 29, 1999 (filed as Exhibit 10.37-c to the Company's Annual Report on Form 10-K for the year ended December 31, 2001)
10.31-d* Third Amending Agreement dated as of December 20, 2002 to the Credit Agreement among KeySpan Energy Development Co., Borrower, the Several Lenders' and Royal Bank of Canada, Administrative Agent dated July 29,
10.32 Guarantee Agreement by KeySpan Corporation in favor of the Several Lenders to KeySpan Energy Development Co. dated as of July 29, 1999 (filed as Exhibit 10.38 to the Company's Annual Report on Form 10-K for the year ended December 31, 2001)
* Filed herewith ** Management Contract or Compensation Plan
10.33 Credit Agreement among KeySpan Corporation, the several Lenders, ABN AMRO Bank, N.V. and Citibank, N.A., as Co-Syndication Agents, The Bank of New York and The Royal Bank of Scotland PLC, as Co-Documentation Agents, and J.P. Morgan Chase Bank, as Administrative Agent for $1.3 billion, dated as of July 9, 2002 (filed as Exhibit 4.1 to the Company's Form 10-Q for the quarterly period ended June 30, 2002)
12* Computation in support of ratio of earnings to fixed charges and ratio of combined fixed charges and dividends
21* Subsidiaries of the Registrant
23.1* Consent of Deloitte & Touche LLP, Independent Auditors
23.2* Consent of Netherland, Sewell & Associates, Inc., Independent Petroleum Consultants
23.3* Consent of Miller and Lents, Ltd., Independent Petroleum Consultants
24.1* Power of Attorney executed by Robert B. Catell on March 6, 2003
24.2* Power of Attorney executed by Andrea S. Christensen on March 6, 2003
24.3* Power of Attorney executed by Donald H. Elliott on March 6, 2003
24.4* Power of Attorney executed by Alan H. Fishman on March 6, 2003
24.5* Power of Attorney executed by J. Atwood Ives on March 6, 2003
24.6* Power of Attorney executed by James R. Jones on March 6, 2003
24.7* Power of Attorney executed by James L. Larocca on March 6, 2003
24.8* Power of Attorney executed by Stephen W. McKessy on March 6, 2003
24.9* Power of Attorney executed by Edward D. Miller on March 6, 2003
24.10* Power of Attorney executed by Edward Travaglianti on March 6, 2003
24.11* Certified copy of the Resolution of the Board of Directors authorizing signatures pursuant to power of attorney
* Filed herewith ** Management Contract or Compensation Plan
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.
KEYSPAN CORPORATION
By:/s/ Robert B. Catell -------------------- Robert B. Catell Chairman of the Board of Directors and Chief Executive Officer
By:/s/ Gerald Luterman ------------------- Gerald Luterman Executive Vice President and Chief Financial Officer
CHIEF EXECUTIVE OFFICER'S CERTIFICATION
I, Robert B Catell, certify that:
1. I have reviewed this annual report on Form 10-K of KeySpan Corporation;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Securities Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 6, 2003 /s/ Robert B. Catell ------------------------------ Robert B. Catell Chairman of the Board of Directors and Chief Executive Officer
CHIEF FINANCIAL OFFICER'S CERTIFICATION
I, Gerald Luterman, certify that:
1. I have reviewed this annual report on Form 10-K of KeySpan Corporation;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Securities Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 6, 2003 /s/ Gerald Luterman ----------------------------- Gerald Luterman Executive Vice President and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated.
* - -------------------- Andrea S. Christensen Director
* - -------------------- Donald H. Elliott Director
* - -------------------- Alan H. Fishman Director
* - -------------------- J. Atwood Ives Director
* - -------------------- James R. Jones Director
* - -------------------- James L. Larocca Director
* - -------------------- Stephen W. McKessy Director
* - -------------------- Edward D. Miller Director
* - -------------------- Edward Travaglianti Director
By:/s/ Gerald Luterman Attorney-in-Fact
* Such signature has been affixed pursuant to a Power of Attorney filed as an exhibit hereto and incorporated herein by reference thereto.