UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2003
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition period from ____ to ____
Commission file number 1-14161
KEYSPAN CORPORATION
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(Exact name of Registrant as specified in its Charter)
New York 11-3431358
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(State or other jurisdiction of (IRS Employer Identification No.)
incorporation or organization)
One MetroTech Center, Brooklyn, New York 11201
175 East Old Country Road, Hicksville, New York 11801
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(Address of principal executive offices) (Zip Code)
(718) 403-1000 (Brooklyn)
(631) 755-6650 (Hicksville)
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(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.[X]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act).[X]
APPLICABLE ONLY TO CORPORATE ISSUERS:
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class of Common Stock Outstanding at July 31, 2003
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$.01 par value 158,492,590
KEYSPAN CORPORATION AND SUBSIDIARIES
INDEX
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Part I. FINANCIAL INFORMATION Page No.
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Item 1. Financial Statements
Consolidated Balance Sheet -
June 30, 2003 and December 31, 2002 3
Consolidated Statement of Income -
Three and Six Months Ended June 30, 2003 and 2002 5
Consolidated Statement of Cash Flows -
Six Months Ended June 30, 2003 and 2002 6
Notes to Consolidated Financial Statements 7
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 33
Item 3. Quantitative and Qualitative Disclosures
About Market Risk 62
Item 4. Controls and Procedures 67
Part II. OTHER INFORMATION
Item 1. Legal Proceedings 66
Item 4. Submission of Matters to a Vote of Security Holders 66
Item 6. Exhibits and Reports on Form 8-K 69
Signatures 71
2
CONSOLIDATED BALANCE SHEET
(Unaudited)
(In Thousands of Dollars) June 30, 2003 December 31, 2002
- --------------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash and temporary cash investments $ 195,668 $ 170,617
Accounts receivable 1,307,457 1,122,022
Unbilled revenue 252,292 473,060
Allowance for uncollectible accounts (81,933) (63,029)
Gas in storage, at average cost 281,850 297,060
Material and supplies, at average cost 110,498 113,519
Other 99,124 93,980
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2,164,956 2,207,229
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Investments and Other 280,581 265,977
Property
Gas 6,287,988 6,124,281
Electric 2,073,464 1,974,352
Other 396,014 394,374
Accumulated depreciation (2,869,820) (2,740,516)
Gas exploration and production, at cost 2,705,912 2,438,998
Accumulated depletion (1,060,124) (973,889)
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7,533,434 7,217,600
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Deferred Charges
Regulatory assets 434,147 438,516
Goodwill, net of amortization 1,790,033 1,789,751
Other 696,992 695,233
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2,921,172 2,923,500
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Total Assets $ 12,900,143 $ 12,614,306
==============================================
See accompanying Notes to the Consolidated Financial Statements.
3
CONSOLIDATED BALANCE SHEET
(Unaudited)
(In Thousands of Dollars) June 30, 2003 December 31, 2002
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LIABILITIES AND CAPITALIZATION
Current Liabilities
Current redemption of long-term debt $ 111,416 $ 11,413
Accounts payable and other liabilities 967,751 1,061,649
Commercial paper 431,000 915,697
Dividends payable 71,779 64,714
Taxes accrued 168,381 51,276
Customer deposits 39,047 38,387
Interest accrued 59,227 77,092
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1,848,601 2,220,228
---------------------------------------------
Deferred Credits and Other Liabilities
Regulatory liabilities 76,129 84,479
Deferred income tax 903,961 877,013
Postretirement benefits and other reserves 822,088 759,731
Other 201,080 189,912
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2,003,258 1,911,135
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Commitments and Contingencies (See Note 8) - -
Capitalization
Common stock 3,481,361 3,005,354
Retained earnings 616,740 522,835
Other comprehensive income (91,848) (108,423)
Treasury stock (417,733) (475,174)
---------------------------------------------
Total common shareholders' equity 3,588,520 2,944,592
Preferred stock 83,697 83,849
Long-term debt 4,905,609 5,224,081
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Total Capitalization 8,577,826 8,252,522
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Minority Interest in Subsidiary Companies 470,458 230,421
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Total Liabilities and Capitalization $ 12,900,143 $ 12,614,306
=============================================
See accompanying Notes to the Consolidated Financial Statements.
4
CONSOLIDATED STATEMENT OF INCOME
(Unaudited)
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Three Months Ended June 30, Six Months Ended June 30,
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(In Thousands of Dollars, Except Per Share Amounts) 2003 2002 2003 2002
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Revenues
Gas Distribution $ 732,036 $ 521,822 $ 2,564,737 $ 1,744,791
Electric Services 370,591 354,756 704,985 669,440
Energy Services 154,022 229,311 346,393 470,870
Gas Exploration and Production 122,875 90,563 250,722 167,489
Energy Investments 28,628 21,748 53,840 39,187
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Total Revenues 1,408,152 1,218,200 3,920,677 3,091,777
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Operating Expenses
Purchased gas for resale 424,300 249,942 1,620,465 899,299
Fuel and purchased power 102,476 93,292 199,998 177,664
Operations and maintenance 509,636 552,706 1,007,825 1,050,784
Depreciation, depletion and amortization 142,290 127,463 287,261 253,460
Operating taxes 95,251 84,062 219,964 197,966
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Total Operating Expenses 1,273,953 1,107,465 3,335,513 2,579,173
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Income from Equity Investments 4,030 3,240 9,759 7,409
Operating Income 138,229 113,975 594,923 520,013
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Other Income and (Deductions)
Interest charges (79,198) (70,054) (148,137) (142,661)
Loss on sale of subsidiary stock (30,345) - (11,325) -
Cost of debt redemption (5,900) - (24,094) -
Minority interest (13,000) (6,138) (30,358) (10,569)
Other (246) 7,761 14,455 18,704
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Total Other Income and (Deductions) (128,689) (68,431) (199,459) (134,526)
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Earnings Before Income Taxes 9,540 45,544 395,464 385,487
Income Taxes
Current 4,017 5,298 133,592 (62,453)
Deferred 11,461 11,072 24,719 204,135
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Total Income Taxes 15,478 16,370 158,311 141,682
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Earnings (Loss) from Continuing Operations (5,938) 29,174 237,153 243,805
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Discontinued Operations
Income from Operations, net of tax - - - -
Loss on Disposal , net of tax of $13,050 - (19,662) - (19,662)
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Loss from Discontinued Operations - (19,662) - (19,662)
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Cummulative Effect of Change in Accounting Principle - - 174 -
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Net Income (Loss) (5,938) 9,512 237,327 224,143
Preferred stock dividend requirements 1,461 1,476 2,922 2,952
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Earnings (Loss) for Common Stock $ (7,399) $ 8,036 $ 234,405 $ 221,191
============================================================================
Basic Earnings Per Share From:
Continuing Operations, less preferred dividends (0.05) 0.20 1.49 1.71
Discontinued Operations - (0.14) - (0.14)
Change in Accounting Principle - - - -
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Basic Earnings (Loss) Per Share $ (0.05) $ 0.06 $ 1.49 $ 1.57
============================================================================
Diluted Earnings Per Share From:
Continuing Operations, less preferred dividends (0.05) 0.20 1.48 1.70
Discontinued Operations - (0.14) - (0.14)
Change in Accounting Principle - - - -
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Diluted Earnings (Loss) Per Share $ (0.05) $ 0.06 $ 1.48 $ 1.56
============================================================================
Average Common Shares Outstanding (000) 157,943 141,063 157,414 140,551
Average Common Shares Outstanding - Diluted (000) 158,757 142,156 158,464 141,706
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See accompanying Notes to the Consolidated Financial Statements.
5
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
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Six Months Ended June 30,
(In Thousands of Dollars) 2003 2002
-----------------------------------
Operating Activities
Net income $ 237,327 $ 224,143
Adjustments to reconcile net income to net
cash provided by (used in) operating activities
Depreciation, depletion and amortization 287,261 253,460
Deferred income tax 24,719 20,978
Income from equity investments (9,759) (7,409)
Dividends from equity investments - 120
Amortization of interest rate swap (4,930) -
Loss on disposal of subsidiary investments 15,048 19,662
Changes in assets and liabilities
Accounts receivable 54,237 125,015
Materials and supplies, fuel oil and gas in storage 18,231 94,637
Accounts payable and other liabilities 7,292 (48,213)
Interest accrued (17,865) (8,793)
Other (46,184) (5,443)
-----------------------------------
Net Cash Provided by Operating Activities 565,377 668,157
-----------------------------------
Investing Activities
Construction expenditures (434,052) (579,903)
Proceeds from sale of subsidiary investments 198,553 -
-----------------------------------
Net Cash Used in Investing Activities (235,499) (579,903)
-----------------------------------
Financing Activities
Treasury stock issued 57,441 51,896
Equity issuance 473,573 -
Issuance of long-term debt 599,684 507,754
Payment of long-term debt (377,174) (54,590)
Payment of commercial paper (484,697) (477,795)
Redemption of promissory notes (447,005) -
Preferred stock dividends paid (2,922) (2,952)
Common stock dividends paid (133,435) (124,684)
Other 9,708 (9,536)
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Net Cash Used in Financing Activities (304,827) (109,907)
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Net Increase in Cash and Cash Equivalents $ 25,051 $ (21,653)
Cash and Cash Equivalents at Beginning of Period 170,617 159,252
-----------------------------------
Cash and Cash Equivalents at End of Period $ 195,668 $ 137,599
===================================
Cash equivalents are short-term marketable securities purchased with maturities
of three months or less that were carried at cost which approximates fair value.
See accompanying Notes to the Consolidated Financial Statements.
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
KeySpan Corporation (referred to in the Notes to the Financial Statements 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 KeySpan 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 electric generation
operator 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; liquefied natural gas storage;
wholesale and retail gas and electric marketing; appliance service; plumbing;
heating, ventilation and air conditioning and other mechanical 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, and other
energy-related projects, domestically and internationally. (See Note 2 "Business
Segments" for additional information on each operating segment.)
1. BASIS OF PRESENTATION
In our opinion, the accompanying unaudited Consolidated Financial Statements
contain all adjustments necessary to present fairly KeySpan's financial position
as of June 30, 2003, and the results of operations for the three and six months
ended June 30, 2003 and June 30, 2002, as well as cash flows for the six months
ended June 30, 2003 and June 30, 2002. The accompanying financial statements
should be read in conjunction with the consolidated financial statements and
notes included in KeySpan's Annual Report on Form 10-K for the year ended
December 31, 2002, as well as KeySpan's March 31, 2003 quarterly report on Form.
The December 31, 2002 financial statement information has been derived from the
2002 audited financial statements. Income from interim periods may not be
indicative of future results. Certain reclassifications were made to conform
prior period financial statements to current period financial statement
presentation.
Basic earnings per share ("EPS") is calculated by dividing earnings available
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 available for common
stock, as adjusted, by the sum of the weighted average number of shares of
common stock outstanding plus all potentially dilutive securities.
We have approximately 2 million common stock options outstanding at June 30,
2003, that were not included in the calculation of diluted EPS since the
exercise price associated with these options was greater than the average market
price of our 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
three months ended June 30, 2003 since to do so would have been anti-dilutive.
7
Under the requirements of Statement of Financial Accounting Standards ("SFAS")
No. 128, "Earnings Per Share" our basic and diluted EPS are as follows:
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Three Months Ended June 30, Six Months Ended June 30,
(In Thousands of Dollars, Except Per Share Amounts) 2003 2002 2003 2002
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Earnings (loss) for common stock $ (7,399) $ 8,036 $ 234,405 $ 221,191
Interest savings on convertible preferred stock - - 265 284
Houston Exploration dilution (57) (129) (144) (225)
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Earnings (loss) for common stock - adjusted $ (7,456) $ 7,907 $ 234,526 $ 221,250
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Weighted average shares outstanding (000) 157,943 141,063 157,414 140,551
Add dilutive securities:
Options 814 1,093 822 911
Convertible preferred stock - - 228 244
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Total weighted average shares outstanding - assuming dilution 158,757 142,156 158,464 141,706
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Basic earnings (loss )per share $ (0.05) $ 0.06 $ 1.49 $ 1.57
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Diluted earnings (loss) per share $ (0.05) $ 0.06 $ 1.48 $ 1.56
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2. BUSINESS SEGMENTS
We have four reportable segments: Gas Distribution, Electric Services, Energy
Services and Energy Investments.
The Gas Distribution segment consists of six gas distribution subsidiaries.
KeySpan Energy Delivery New York ("KEDNY") provides gas distribution services to
customers in the New York City Boroughs of Brooklyn, Queens and Staten Island.
KeySpan Energy Delivery Long Island ("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, Boston
Gas Company, Colonial Gas Company, Essex Gas Company and EnergyNorth Natural
Gas, Inc., collectively referred to as KeySpan Energy Delivery New England
("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.
Also, in the summer of 2002, we placed two 79.9 megawatt generating facilities
into service; the capacity of and energy from these facilities are dedicated to
LIPA under 25 year contracts. The Electric Services segment also includes
subsidiaries that own, lease and operate the 2,200 megawatt Ravenswood electric
generation facility ("Ravenswood facility"), located in Queens, New York. All of
the energy, capacity and ancillary services related to the Ravenswood facility
is sold to the New York Independent System Operator ("NYISO") energy markets.
8
The Energy Services segment includes companies that provide energy-related
services to customers primarily located in 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
electricity to residential and small commercial customers; (ii) Business
Solutions, which provides plumbing, heating, ventilation, air conditioning and
mechanical services, as well as operation and maintenance, design, engineering
and consulting services to commercial 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.
KeySpan Services, Inc. and its wholly-owned subsidiary Paulus, Sokolowski, and
Sartor, LLC., have entered into an agreement to acquire Bard, Rao + Athanas
Consulting Engineers, Inc. (BR+A), a Boston, Massachusetts company engaged in
the business of providing engineering services relating to heating, ventilation,
and air conditioning systems. The purchase price is expected to be approximately
$35 million, plus up to $14.7 million in contingent consideration depending on
the financial performance of BR+A over the five-year period after the closing of
the acquisition. We have received all necessary regulatory approvals and it is
anticipated that the closing of this transaction will occur in the third quarter
of 2003. On May 1, 2003, KeySpan's gas and electric marketing subsidiary,
KeySpan Energy Services Inc., assigned the majority of its retail natural gas
customers, consisting mostly of residential and small commercial customers, to
ECONnergy Energy Co., Inc. ("ECONnergy"). KeySpan Energy Services will continue
to provide retail natural gas marketing to a small number of customers in New
Jersey and will continue its electric marketing activities.
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 56%
equity 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 56% following the repurchase, by
Houston Exploration, of three million shares of common stock owned by KeySpan.
We realized net proceeds of $79 million in connection with this repurchase.
KeySpan follows an accounting policy of income statement recognition for Parent
company gains or losses from common stock transactions initiated by its
subsidiaries. As a result, KeySpan realized a gain of $19 million on this
transaction. Income taxes were not provided, since this transaction was
structured as a return of capital.
KeySpan subsidiaries 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. These subsidiaries are accounted for under the equity method.
9
We also have investments in certain midstream natural gas assets in Western
Canada through KeySpan Canada. These assets include 14 processing plants and
associated gathering systems that can process approximately 1.5 BCFe of natural
gas daily and provide associated natural gas liquids fractionation. On May 30,
2003, we sold a portion of our interest in KeySpan Canada through the
establishment of an open-ended income fund trust (the "Fund") organized under
the laws of Alberta, Canada. The Fund acquired a 39.09% ownership interest in
KeySpan Canada through an indirect subsidiary, and then issued 17 million trust
units to the public through an initial public offering. Each trust unit
represents a beneficial interest in the Fund and is registered on the Toronto
Stock Exchange under the symbol KEY.UN. Additionally, we sold our 20% interest
in Taylor NGL LP that owns and operates two extraction plants also in Canada to
AltaGas Services, Inc. Net proceeds of $119.4 million from the two sales, plus
proceeds of $45.7 million drawn under a new credit facility made available to
KeySpan Canada, were used to pay down existing KeySpan Canada credit facilities
of $160.4 million. A pre-tax loss of $30.3 million was recognized on the
transactions and is included in Other Income and (Deductions) in the
Consolidated Statement of Income. These transactions produced a tax expense of
$3.8 million as a result of certain United States partnership tax rules and we,
therefore, recorded an after-tax loss of $34.1 million. This investment is now
expected to provide an annual cash dividend of approximately $20 million.
The accounting policies of the segments are the same as those used for the
preparation of the Consolidated Financial Statements. The 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 operating income basis. At June 30, 2003, the total assets of
each reportable segment have not changed materially from those levels reported
at December 31, 2002. The reportable segment information is as follows:
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Energy Investments
-------------------------------
(InThousands of Dollars) Gas Electric Energy Gas Exploration Other
Distribution Services Services and Production Investments Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Three Months Ended June 30, 2003
Unaffiliated revenue 732,036 370,591 154,022 122,875 28,628 - 1,408,152
Intersegment revenue - 26 1,542 - 1,252 (2,820) -
Operating Income 31,616 51,480 (9,872) 50,148 9,074 5,783 138,229
Three Months Ended June 30, 2002
Unaffiliated revenue 521,822 354,756 229,311 90,563 21,748 - 1,218,200
Intersegment revenue - 25 - - 194 (219) -
Operating Income 30,096 59,501 (10,867) 29,455 (147) 5,937 113,975
- ------------------------------------------------------------------------------------------------------------------------------------
Eliminating items include intercompany interest income and expense, the
elimination of certain intercompany accounts, as well as activities of our
corporate and administrative areas.
Because of the nature of our Electric Services business, electric revenues are
derived from two large customers - the NYISO and LIPA. Electric Services
revenues from these customers for the three months ended June 30, 2003 and 2002
represent approximately 26% and 29% of our consolidated revenues, respectively.
10
- ------------------------------------------------------------------------------------------------------------------------------------
Energy Investments
------------------------------
(InThousands of Dollars) Gas Electric Energy Gas Exploration Other
Distribution Services Services and Production Investments Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Six Months Ended June 30, 2003
Unaffiliated revenue 2,564,737 704,985 346,393 250,722 53,840 - 3,920,677
Intersegment revenue - 51 2,968 - 2,504 (5,523) -
Operating Income 396,553 91,150 (19,020) 105,738 19,198 1,304 594,923
Six Months Ended June 30, 2002
Unaffiliated revenue 1,744,791 669,440 470,870 167,489 39,187 - 3,091,777
Intersegment revenue - 49 - - 388 (437) -
Operating Income 361,118 120,991 (20,224) 49,280 4,555 4,293 520,013
- ------------------------------------------------------------------------------------------------------------------------------------
Eliminating items include intercompany interest income and expense, the
elimination of certain intercompany accounts, as well as activities of our
corporate and administrative areas.
Because of the nature of our Electric Services business, electric revenues are
derived from two large customers - the NYISO and LIPA. Electric Services
revenues from these customers for the six months ended June 30, 2003 and 2002
represent approximately 18% and 22% of our consolidated revenues, respectively.
3. COMPREHENSIVE INCOME
The table below indicates the components of comprehensive income.
- ------------------------------------------------------------------------------------------------------------------------------------
Three Months Ended June 30, Six Months Ended June 30,
(In Thousands of Dollars) 2003 2002 2003 2002
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings (loss) for common stock $ (7,399) $ 8,036 $ 234,405 $ 221,191
- ----------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax
Reclassification adjustments for loss (gains) realized in
net income 8,817 (2,998) 11,171 (10,285)
Foreign currency translation adjustments 17,773 10,829 27,526 9,116
Unrealized gains (losses) on marketable securities 5,405 (3,195) 2,249 (4,236)
Accrued unfunded pension obligation - - - (1,132)
Premiums on derivative financial instruments (3,437) - (3,437) -
Unrealized losses on derivative financial instruments (6,184) (2,159) (20,933) (25,944)
- ----------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax 22,374 2,477 16,576 (32,481)
- ----------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 14,975 $ 10,513 $ 250,981 $ 188,710
- ----------------------------------------------------------------------------------------------------------------------------------
Related tax (benefit) expense
Reclassification adjustments for loss (gains) realized in net
income 4,748 $ (1,614) 6,015 $ (5,538)
Foreign currency translation adjustments 9,570 5,831 14,822 4,908
Unrealized gains (losses) on marketable securities 2,910 (1,721) 1,211 (2,281)
Accrued unfunded pension obligation - - - (610)
Premiums on derivative financial instruments (1,851) - (1,851)
Unrealized losses on derivative financial instruments (3,329) (1,163) (11,271) (13,970)
- ----------------------------------------------------------------------------------------------------------------------------------
Total Tax (Benefit) Expense $ 12,048 $ 1,333 $ 8,926 $ (17,491)
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11
4. CAPITAL STOCK
On January 17, 2003, we issued 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 an effective shelf registration statement
filed with the Securities and Exchange Commission ("SEC").
5. LONG-TERM DEBT AND COMMERCIAL PAPER
On June 27, 2003, KeySpan renewed its $1.3 billion revolving credit facility,
which was syndicated among sixteen banks. The credit facility supports KeySpan's
commercial paper program, and consists of two separate credit facilities with
different maturities but substantially similar terms and conditions: a $450
million facility that extends for 364 days, and a $850 million facility that is
committed for three years. The fees for the facilities are subject to a
ratings-based grid, with an annual fee of 0.10% on the 364-day facility and
0.125% on the three-year facility. Both credit agreements allow 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 0.625% for loans up to 33% of
the total facility, and an additional 0.125% for loans over 33% of the total
facility. ABR loans are based on the highest 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. In addition, the
364-day facility has a one-year term out option, which would cost an additional
0.25% if utilized. 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.
In June 2003, as part of the sale of a portion of KeySpan's ownership in KeySpan
Canada, two outstanding KeySpan Canada credit facilities were replaced with one
new facility with three tranches that combined allow KeySpan Canada to borrow up
to approximately $125 million. These facilities mature as follows: (i) $50
million matures in 180 days; (ii) $37.5 million matures in 364 days; and (iii)
$37.5 million matures in two years.
On June 10, 2003, Houston Exploration finalized a private placement issuance of
$175 million of 7.0%, senior subordinated notes due 2013. Interest payments will
begin on December 15, 2003, and will be paid semi-annually thereafter. The notes
will mature on June 15, 2013. Houston Exploration has the right to redeem the
notes as of June 15, 2008, at a price equal to the issue price plus a specified
redemption premium. Until June 15, 2006, Houston Exploration may also redeem up
to 35% of the notes at a redemption price of 107% with proceeds from an equity
offering. Houston Exploration incurred approximately $4.5 million of debt
issuance costs on this private placement.
Houston Exploration used a portion of the net proceeds from the issuance to
redeem all of its outstanding $100 million principal amount of 8.625% senior
subordinated notes due 2008 at a price of 104.313% of par plus interest accrued
to the redemption date. Debt redemption costs totaled approximately $5.9 million
and is reflected in Other Income and (Deductions) in the Consolidated Statement
of Income. The remaining net proceeds from the offering were used to reduce debt
12
amounts associated with Houston Exploration's revolving bank credit facility.
The actual cash payment associated with the redemption of the senior
subordinated notes did not occur until July 11, 2003. The Consolidated Balance
Sheet at June 30, 2003, therefore reflects $100 million in cash and a
corresponding current liability.
In April 2003, we issued $300 million of medium-term and long-term debt. The
debt was issued in the following two series: (i) $150 million 4.65% Notes due
2013; and (ii) $150 million 5.875% Notes due 2033. The proceeds of this issuance
were used to pay down outstanding commercial paper.
In connection with the KeySpan/Long Island Lighting Company ("LILCO") business
combination in 1998, 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. To mitigate the dilutive effect of the equity
issuance previously mentioned in Note 4, in March 2003, we called 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. Interest savings associated with this redemption are estimated to
be $15.6 million after-tax, or $0.09 per share, in 2003. We applied the
provisions of Statement of Financial Accounting Standards ("SFAS") 145
"Rescission of FASB Statement No. 4, 44 and 64, Amendment of FASB Statement No.
13, and Technical Corrections" and recorded an expense of $18.2 million,
reflecting redemption costs, as well as the write-off of previously deferred
debt issuance costs. This expense has been recorded in Other Income and
Deductions in the Consolidated Statement of Income.
KeySpan had authorization under PUHCA to issue up to $2.2 billion of securities
through December 31, 2003. Following the recent common stock offering previously
mentioned and shares of common stock expected to be issued for employee benefit
and dividend reinvestment plans, we generally exhausted our ability to issue 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 have filed an application
with the SEC requesting authorization to, among other things, issue up to an
additional $3 billion of securities through December 31, 2006. It is anticipated
that this authorization will be obtained before the end of the year. This
request is intended to provide us with maximum flexibility to finance our future
capital requirements over the next three years.
6. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS
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.
13
Houston Exploration has utilized collars and put options, 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 June 30,
2003, Houston Exploration has hedged approximately 67% of its estimated 2003 and
2004 gas production. To value its outstanding derivatives, Houston Exploration
used standard New York Mercantile Exchange ("NYMEX") futures prices, and, in
addition, used published volatility in its Black-Scholes calculation for
outstanding options. The maximum length of time over which Houston Exploration
has hedged such cash flow 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 $47.5 million, or $30.6 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 September 2004; and (ii) forecasted purchases of fuel oil
is through April 2005. 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 $1.5 million, or $1.0 million after-tax.
KeySpan Canada employs natural gas swaps to lock-in a price for expected future
natural gas purchases. As applicable, we used 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 October 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 negligible at June 30, 2003.
We have also engaged in the use of cash-settled swap instruments to hedge the
cash flow variability associated with a portion of forecasted peak electric
energy sales from the Ravenswood facility. The maximum length of time over which
we have hedged cash flow variability is through December 2004. We used
NYISO-location zone published indices to value these outstanding derivatives.
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 $3.3 million, or $2.2
million after-tax.
KeySpan Canada also employs 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 $0.7 million, or $0.5 million after-tax.
14
The following tables set forth selected financial data associated with these
derivative financial instruments noted above that were outstanding at June 30,
2003.
- ------------------------------------------------------------------------------------------------------------------------------------
Year of Volumes Floor Ceiling Fixed Price Current Price Fair Value
Type of Contract Maturity (mmcf) ($) ($) ($) ($) ($000)
- ------------------------------------------------------------------------------------------------------------------------------------
Gas
Collars 2003 27,600 3.48 - 3.49 4.91 - 4.95 - 5.29 - 5.82 (22,760)
2004 64,100 3.75 - 4.50 5.05 - 7.00 - 4.87 - 5.92 (16,920)
Put Options - Short Natural Gas 2004 9,100 5.00 - - 5.66 - 5.92 4,228
Swaps/Futures - Short Natural Gas 2003 7,483 - - 3.19 - 3.89 4.35 - 5.82 (17,161)
Swaps/Futures - Long Natural Gas 2003 410 - - 3.22 - 5.72 5.41 - 5.48 1,215
2004 50 - - 5.11 - 5.13 4.87 - 4.89 (10)
- ------------------------------------------------------------------------------------------------------------------------------------
108,743 (51,408)
- ------------------------------------------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------------------------
Year of Volumes Current Fair Value
Type of Contract Maturity (Barrels) Fixed Price ($) Price ($) ($000)
- ----------------------------------------------------------------------------------------------------------------------
Oil
Swaps - Short Fuel Oil 2003 30,000 29.70 28.50 - 30.52 (25)
Swaps - Long Fuel Oil 2003 66,195 20.60 - 30.88 29.15 - 31.99 253
2004 76,548 20.50 - 29.95 27.05 - 30.37 141
2005 9,000 24.65 - 26.28 26.60 - 26.85 17
- ----------------------------------------------------------------------------------------------------------------------
181,743 386
- ----------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------------------
Year of Fixed Margin/ Price Current Fair Value
Type of Contract Maturity MWh ($) Price ($) ($000)
- ---------------------------------------------------------------------------------------------------------------------------------
Electricity
Swaps - Energy 2003 584,928 22.40 - 67.53 14.67 - 46.59 2,477
2004 308,000 14.00 - 26.50 13.13 - 24.04 774
- ---------------------------------------------------------------------------------------------------------------------------------
892,928 3,251
- ---------------------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
2003
Change in Fair Value of Derivative Instruments ($000)
- --------------------------------------------------------------------------------
Fair value of contracts at January 1, $ (32,628)
Net losses on contracts realized 17,186
(Decrease) in fair value of all open contracts (32,329)
- --------------------------------------------------------------------------------
Fair value of contracts outstanding at June 30, $ (47,771)
- --------------------------------------------------------------------------------
15
- ---------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- ---------------------------------------------------------------------------------------------------------
Fair Value of Contracts
- ---------------------------------------------------------------------------------------------------------
Maturity Maturity Total
Sources of Fair Value In 12 Months 2004 - 2005 Fair Value
- ---------------------------------------------------------------------------------------------------------
Prices actively quoted $ (40,995) $ (2,292) $ (43,287)
Prices provided by external sources 427 2 429
Prices based on models and
other valuation methods (5,753) (2,765) (8,518)
Local published indicies 2,961 644 3,605
- ---------------------------------------------------------------------------------------------------------
$ (43,360) $ (4,411) $ (47,771)
- ---------------------------------------------------------------------------------------------------------
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 swap transactions for natural gas liquids. Such contracts are
executed by KeySpan Canada to: (i) 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 to counterparties.
These derivative financial instruments do not qualify for hedge accounting under
SFAS 133. At June 30, 2003, these instruments had a net fair market value of
$0.6 million, which was recorded on the Consolidated Balance Sheet. Based on the
non-hedge designation of these instruments, the gain was recognized in the
Consolidated Statement of Income.
Firm Gas Sales Derivative Instruments - Regulated Utilities: We use derivative
financial instruments to reduce the cash flow variability associated with the
purchase price for a portion of future natural gas purchases associated with our
Gas Distribution operations. 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 "Accounting for the Effects of Certain Types
of Regulation". 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 consistent with regulatory requirements.
The following table sets forth selected financial data associated with these
derivative financial instruments that were outstanding at June 30, 2003.
- ------------------------------------------------------------------------------------------------------------------------------------
Type of Contract Year of Volumes Fair Value
Maturity mmcf Floor $ Ceiling $ Fixed Price $ Current Price $ ($000)
- ------------------------------------------------------------------------------------------------------------------------------------
Options 2003 3,040 4.00 - 5.00 5.50 - 6.35 - - 72
2004 3,560 4.00 - 5.00 5.37 - 6.00 - - (87)
Swaps 2003 9,690 - - 5.09 - 6.23 5.36 - 5.90 46
2004 11,440 - - 4.42 - 6.23 4.52 - 5.83 99
- ------------------------------------------------------------------------------------------------------------------------------------
27,730 130
- ------------------------------------------------------------------------------------------------------------------------------------
16
Physically-Settled Commodity Derivative Instruments: 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, ("SFAS 133") establishes criteria that must be satisfied in
order for option-type and forward contracts in electricity to be exempted as
normal purchases and sales, and 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 continuing review of our physical commodity
contracts, we determined that certain contracts for the physical purchase of
natural gas are not exempt as normal purchases from the requirements of SFAS
133. At June 30, 2003, the fair value of these contracts was $1.5 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: In May 2003, we entered into an interest
rate swap agreement in which we swapped $250 million of 7.25 % fixed rate debt
to floating rate debt. Under the terms of the agreements, we will receive the
fixed coupon rate associated with these bonds and pay our swap counterparties a
variable interest rate based on LIBOR, that is reset on a semi-annual basis.
These swaps are designated as fair-value hedges and qualify for "short-cut"
hedge accounting treatment under SFAS 133. During the second quarter of 2003, we
paid our counterparty an interest rate of 6.43%, and as a result, we realized
interest savings of $0.3 million for the quarter. The fair market value of this
derivative was $1.9 million at June 30, 2003.
During 2002, we had interest rate swap agreements in which we swapped
approximately $1.3 billion of fixed rate debt to floating rate debt. Under the
terms of the agreements, we received the fixed coupon rate associated with these
bonds and paid the swap counterparties 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. In 2002, we
terminated two of these interest rate swap agreements with an aggregate notional
amount of $1.0 billion. The remaining swap, which had a notional amount of
$270.0 million, was terminated on February 25, 2003. We received $18.4 million
from our swap counterparties as a result of the latter termination, of which
$8.1 million represented accrued swap interest. The difference between the
termination settlement amount and the amount of accrued interest, $10.3 million,
was 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 5 "Long-Term Debt", we called a portion of these promissory notes during
the first quarter of 2003.
Additionally, we had an interest rate swap agreement that hedged the cash flow
variability associated with the forecasted issuance of a series of commercial
paper offerings. This hedge expired in March 2003.
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 substantial portion of the effect of
17
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 was required to make a payment of $40,000 per heating
degree day to its counterparties when actual weather experienced during the
November 2002 - March 2003 time frame was above 4,470 heating degree days, which
equates to approximately 1% colder than normal weather. With respect to
purchased put options, KeySpan would receive a $20,000 per heating degree day
payment from its counterparties when actual weather was below 4,150 heating
degree days, or approximately 7% warmer than normal. Based on the terms of such
contracts, we account for such instruments pursuant to the requirements of EITF
99-2, "Accounting for Weather Derivatives." In this regard, such instruments
were accounted for using the "intrinsic value method" as set forth in such
guidance. During the first quarter of 2003, weather was 10% colder than normal
and, as a result, $11.9 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
non-performance by a counterparty to a derivative contract, the desired impact
may not be achieved. The risk of counterparty non-performance is generally
considered credit risk and is actively managed by assessing each counterparty
credit profile and negotiating appropriate levels of collateral and credit
support.
7. RECENT ACCOUNTING PRONOUNCEMENTS
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.
At June 30, 2003, the present value of our future asset retirement obligation
("ARO") was approximately $62 million, primarily related to our investment in
Houston Exploration. The cumulative effect of SFAS 143 and the change in
accounting principle was a benefit to net income of $0.6 million, or $0.2
million, after-tax. KeySpan's largest asset base is its gas transmission and
distribution system. A legal obligation exists 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 pursuant to SFAS 143. KeySpan's ARO will be re-evaluated in future
periods until sufficient information exists to determine a reasonable estimate
of fair value.
KeySpan recovers certain asset retirement costs through rates charged to
customers as a portion of depreciation expense. When depreciable properties are
retired, the original cost plus cost of removal less salvage, is charged to
accumulated depreciation. As of June 30, 2003, KeySpan had costs recovered in
excess of costs incurred totaling $444.3 million.
18
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 and we will apply the provisions of FIN 46 beginning July 1,
2003. (See Note 9 "Variable Interest Entity" for a detailed description of this
leasing arrangement).
In April 2003, the FASB issued SFAS 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities". This Statement amends and
clarifies financial accounting and reporting for derivative instruments,
including certain instruments embedded in other contracts and for hedging
activities under Statement No. 133, "Accounting for Derivative Instruments and
Hedging Activities." This Statement: (i) clarifies under what circumstances a
contract with an initial net investment meets the characteristic of a
derivative; (ii) clarifies when a derivative contains a financing component;
(iii) amends the definition of an underlying; and (iv) amends certain other
existing pronouncements. While we are still evaluating the provisions of this
Statement, we belive that implementation of this Statement is not expected to
have a significant impact on our results of operations, financial condition or
cash flows since our derivative instruments that meet the definition of a
derivative and qualify for hedge accounting treatment will continue to do so.
In May 2003, the FASB issued SFAS 150, "Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and Equity." This Statement
establishes standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and equity. It
requires that an issuer classify certain financial instruments as a liability
(or an asset in some circumstances) when there is an obligation to redeem the
issuer's shares and either requires or may require satisfaction of the
obligation by transferring assets, or satisfy the obligation by issuing
additional equity shares subject to certain criteria. This Statement is
effective for financial instruments entered into or modified after May 31, 2003,
and otherwise is effective at the beginning of the first interim period
beginning after June 15, 2003. It is to be implemented by reporting the
cumulative effect of a change in an accounting principle for financial
instruments created before the issuance date of the Statement and still existing
at the beginning of the interim period of adoption. The implementation of this
Statement is not expected to have a significant impact on our results of
operations, financial condition or cash flows.
19
8. FINANCIAL GUARANTEES AND CONTINGENCIES
Environmental Matters
New York Sites. We have identified 28 manufactured gas plant ("MGP") sites and
related facilities in New York State that were historically owned or operated by
KeySpan subsidiaries or such companies' predecessors. Twenty seven of these
former sites, some of which are no longer owned by KeySpan, were associated with
the regulated gas businesses, and have been identified to both the Department of
Environmental Conservation ("DEC") for inclusion on appropriate site inventories
and listing with the New York Public Service Commission ("NYPSC"). The remaining
former MGP site was acquired when the Ravenswood facility was purchased from
Consolidated Edison Company of New York Inc. ("Consolidated Edison"). Fourteen
sites are currently the subjects of Administrative Orders on Consent ("ACOs") or
Voluntary Clean-Up Agreements ("VCAs") with the DEC.
We presently estimate the remaining environmental cleanup costs related to our
New York MGP sites will be $135.3 million, which amount has been accrued as a
reasonable estimate of probable cost for known sites. Expenditures incurred to
date with respect to these MGP-related sites total $56.5 million. The KEDNY and
KEDLI rate plans generally provide for the recovery of MGP related investigation
and remediation costs in rates charged to gas distribution customers. Under
prior rate orders, KEDNY has offset certain refunds due customers against its
estimated environmental cleanup costs for MGP sites. A regulatory asset of
$123.1 million for the New York/Long Island MGP sites is reflected at June 30,
2003.
KeySpan is also responsible for environmental obligations associated with the
Ravenswood electric generating facility. Our obligations do not include those
arising from disposal of waste at off-site locations prior to our acquisition of
the Ravenswood facility, or any from Consolidated Edison's post-closing conduct
associated with its transmission facilities at the site. Based on information
currently available, a liability of $3.6 million has been accrued. Expenditures
incurred to date with respect to these environmental obligations 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 KeySpan for any of the sites from any
governmental authority.
20
We presently estimate the remaining cost of New England MGP-related
environmental cleanup activities will be $45.3 million, which amount has been
accrued as a reasonable estimate of probable cost for known sites. Expenditures
incurred since our acquisition of Eastern Enterprises on November 8, 2000 with
respect to these MGP-related activities total $17.6 million.
The Massachusetts Department of Telecommunications and Energy ("DTE") and the
New Hampshire Public Utilities Commission ("NHPUC") have issued rate orders that
provide for the recovery of site investigation and remediation costs in rates
charged to gas distribution customers. Accordingly, a regulatory asset of $56.6
million for the KEDNE MGP sites is reflected at June 30, 2003. Colonial Gas
Company and Essex Gas Company are not subject to the provisions of SFAS 71
"Accounting for the Effects of Certain Types of Regulation" and therefore have
recorded no regulatory asset. However, rate plans 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 historical operations of KeySpan New England, LLC, the
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 Everett site, which includes the
former Coal Tar Processing Facility (the "Everett Coal Tar Facility"), Coke
Plant and a by-products facility located in Massachusetts. Honeywell
International, Inc. and Beazer East, Inc. (both former owners or operators of
the Everett Coal Tar 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 Everett Coal
Tar Facility.
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 as a reasonable estimate of probable costs for known
sites. Expenditures incurred since November 8, 2000, with respect to these sites
total $4.6 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 liquidity. 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.
See KeySpan's Annual Report on Form 10-K for the year ended December 31, 2002
Note 7 to those Consolidated Financial Statements "Contractual Obligations and
Contingencies" for further information on environmental matters.
21
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, or in KeySpan's
Annual Report on Form 10-K for the year ended December 31, 2002, 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.
On March 5, 2002 , the SEC, as part of its continuing inquiry, 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 by KeySpan Services, Inc., a KeySpan subsidiary, of
the Roy Kay companies through the July 17th announcement.
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
and the announcement of the agreement to acquire Eastern Enterprises and
EnergyNorth Inc. 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. On March 18, 2003, the court granted our motion to dismiss
the class action 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. In April 2003,
the plaintiff filed an amended complaint and in July the court denied our motion
to dismiss this amended complaint. KeySpan intends to vigorously defend each of
these proceedings. However, 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.
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 at generating facilities formerly owned by Long
Island Lighting Company and others. In March 2003, a jury rendered a verdict in
one such proceeding against our subsidiary, KeySpan Generation LLC ("KeySpan
Generation"), and other defendants in the amount of $47 million. KeySpan has
moved to set aside this verdict and, if necessary, will prosecute an appeal, on
the grounds that, among other things, the amount of the verdict is excessive and
unreasonable and the finding of liability against KeySpan Generation is not
supported by the evidence.
22
In connection with the May 1998 transaction with LIPA, costs incurred by KeySpan
for liabilities for asbestos exposure arising from the activities of the
generating facilities previously owned by LILCO, including the facility involved
in the case referred to above, are recoverable from LIPA through the Power
Supply Agreement between LIPA and KeySpan. KeySpan's cost recovery under the
Power Supply Agreement is reduced by any insurance recoveries received by
KeySpan Generation and by amounts received by KeySpan Generation from other
indemnification claims it is pursuing.
KeySpan is unable to determine the outcome of the appeals of the above
referenced action or the outcome of any of these other proceedings, but does not
believe, for the reasons set forth above, that such outcome, if adverse, will
have a material effect on its financial condition, results of operation or cash
flows. KeySpan believes that its cost recovery rights under the Power Supply
Agreement, its indemnification rights against third parties and its insurance
coverage (above applicable deductible limits) cover its exposure in this case
and for asbestos liabilities generally.
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 was seeking damages in excess of $90 million and
KeySpan alleged a number of counterclaims seeking damages in excess of $4
million. In June 2003, the parties entered into an agreement settling this
matter and a stipulation discontinuing the lawsuit, with prejudice, has been
filed with the court. The settlement will not have a material adverse effect on
the financial condition, results of operations or cash flows of KeySpan. Under
the terms of the settlement (i) certain obligations between the parties have
been modified and clarified, (ii) certain contracts were awarded to Hawkeye,
(iii) certain property will be sold to Hawkeye at fair market value, (iv)
certain credit and bonding support made available by KeySpan to Hawkeye will be
curtailed and ultimately terminated and (v) in addition to a short-term bridge
loan of $21 million due to be repaid in August 2003, KeySpan will subsequently
provide a fully secured, interest bearing loan of up to $50 million in the
aggregate, to finance a power plant currently being constructed by a Hawkeye
affiliate.
23
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
June 30, 2003, 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:
- ----------------------------------------------------------------------------------------------------------------
Amount of Expiration
Nature of Guarantee (In Thousands of Dollars) Exposure Dates
- ----------------------------------------------------------------------------------------------------------------
Guarantees for Subsidiaries
Medium-Term Notes - KEDLI (i) $ 525,000 2008-2010
Master Lease - Ravenswood (ii) 425,000 2004
Surety Bonds (iii) 250,068 Revolving
Commodity Guarantees and Other (iv) 71,494 2005
Letters of Credit (v) 64,822 2003
- ----------------------------------------------------------------------------------------------------------------
Guarantees for Non-Affiliates
Surety Bonds (vi) 11,540 Revolving
Third Party Line of Credit (vi) 25,000 2004
- ----------------------------------------------------------------------------------------------------------------
$ 1,372,924
- ----------------------------------------------------------------------------------------------------------------
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 is 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 Ravenswood master lease
(the "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 Note 9 "Variable Interest
Entity."
(iii)KeySpan has agreed to indemnify the issuers of 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 obligations under various contracts, 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.
24
(iv) 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 June 30, 2003.
(v) KeySpan has arranged for stand-by letters of credit to be issued 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 disbursed 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 defaults 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:
(vi) At June 30, 2003, KeySpan had agreed to support a line of credit up to $25
million on behalf of Hawkeye, a non-affiliated company. In addition,
KeySpan had also guaranteed certain performance bonds of Hawkeye. To date,
we have not had a claim made against either the guarantee associated with
the line of credit or the performance bonds. In June 2003, KeySpan and
Hawkeye settled an outstanding legal proceeding. In connection with the
settlement discussed previously, our obligation to guarantee the line of
credit is expected to be reduced to $13 million and will be eliminated by
the end of the first quarter of 2004. Further, we are no longer required to
provide support for Hawkeye's surety bonds. It is anticipated that any
currently outstanding support will be terminated by the end of August 2003.
(See Legal Matters above for a summary of the settlement.)
9. 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 in
June1999 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, 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 steam units or in the variable interest entity.
25
KeySpan has guaranteed all payment and performance obligations of our subsidiary
under the Master Lease. The Master Lease represents $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 approximately 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 and depreciated the asset from inception, or for approximately 4 years.
Therefore, it is anticipated that we will record a $29.1 million after-tax
charge, or $0.18 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.
If our subsidiary that leases the Ravenswood facility is not able to fulfill its
payment obligation with respect to the Master Lease, 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.
26
10. STOCK OPTIONS
Stock options have been issued to KeySpan officers, directors and certain other
management employees and consultants 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. Moreover, under a separate plan, Houston Exploration
has issued stock options to its directors and 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. In 2003,
KeySpan and Houston Exploration adopted the prospective method of transition in
accordance with SFAS 148 "Accounting for Stock-Based Compensation - Transition
and Disclosure." Accordingly, compensation expense has been 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 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:
- -----------------------------------------------------------------------------------------------------------------------------------
Three Months Ended June 30, Six Months Ended June 30,
(In Thousands of Dollars, Except Per Share Amounts) 2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------------
Earnings available for common stock: $ (7,399) $ 8,036 $ 234,405 $ 221,191
As reported
Add: recorded stock-based compensation expense, net of tax 1,132 66 1,990 66
Deduct: total stock-based compensation expense, net of tax (2,969) (1,887) (6,070) (3,774)
- -----------------------------------------------------------------------------------------------------------------------------------
Pro-forma earnings $ (9,236) $ 6,215 $ 230,325 $ 217,483
- -----------------------------------------------------------------------------------------------------------------------------------
Earnings per share:
Basic - as reported $ (0.05) $ 0.06 $ 1.49 $ 1.57
Basic - pro-forma $ (0.06) $ 0.04 $ 1.46 $ 1.55
Diluted - as reported $ (0.05) $ 0.06 $ 1.48 $ 1.56
Diluted - pro-forma $ (0.06) $ 0.04 $ 1.45 $ 1.53
- -----------------------------------------------------------------------------------------------------------------------------------
11. KEYSPAN GAS EAST CORPORATION SUMMARY FINANCIAL INFORMATION
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 established a program for the issuance,
from time to time, of up to $600 million aggregate principal amount of
Medium-Term Notes, which are fully and unconditionally guaranteed by 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 June 30, 2002 disclosures
have been revised to separately present our other subsidiaries.
27
- -----------------------------------------------------------------------------------------------------------------------------------
Statement of Income
- -----------------------------------------------------------------------------------------------------------------------------------
Three Months Ended June 30, 2003
(In Thousands of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- -----------------------------------------------------------------------------------------------------------------------------------
Revenues $ 34 $ 177,340 $ 1,230,812 $ (34) $ 1,408,152
Operating Expenses
Purchased gas - 90,611 333,689 - 424,300
Fuel and purchased power - - 102,476 - 102,476
Operations and maintenance (5,424) 32,760 482,300 - 509,636
Intercompany expense 31 735 (735) (31) -
Depreciation and amortization (20) 18,064 124,246 - 142,290
Operating taxes (1,824) 16,954 80,121 - 95,251
------------------------------------------------------------------------------------------
Total Operating Expenses (7,237) 159,124 1,122,097 (31) 1,273,953
Income from Equity Investments 36 - 3,994 - 4,030
------------------------------------------------------------------------------------------
Operating Income (Loss) 7,307 18,216 112,709 (3) 138,229
Interest charges (53,403) (16,104) (56,720) 47,029 (79,198)
Other income and (deductions) 34,630 (1,809) (46,030) (36,282) (49,491)
------------------------------------------------------------------------------------------
Total Other Income and (Deductions) (18,773) (17,913) (102,750) 10,747 (128,689)
Income (Loss) Before Income Taxes (11,466) 303 9,959 10,744 9,540
Income Taxes (Benefit) (5,528) 1,221 19,785 - 15,478
------------------------------------------------------------------------------------------
Net Income (Loss) $ (5,938) $ (918) $ (9,826) $ 10,744 $ (5,938)
=========================================================================================
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Income
- ------------------------------------------------------------------------------------------------------------------------------------
Three Months Ended June 30, 2002
(In Thousands of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Revenues $ 130 $ 137,937 $ 1,080,263 $ (130) $ 1,218,200
Operating Expenses
Purchased gas - 62,573 187,369 - 249,942
Fuel and purchased power - - 93,292 - 93,292
Operations and maintenance 1,522 13,066 538,118 - 552,706
Intercompany expense 83 20,033 (20,033) (83) -
Depreciation and amortization (3) 15,340 112,126 - 127,463
Operating taxes (569) 18,354 66,277 - 84,062
-------------------------------------------------------------------------------------
Total Operating Expenses 1,033 129,366 977,149 (83) 1,107,465
Income from Equity Investment 34 - 3,206 - 3,240
-------------------------------------------------------------------------------------
Operating Income (Loss) (869) 8,571 106,320 (47) 113,975
Interest charges (47,831) (15,900) (68,663) 62,340 (70,054)
Other income and (deductions) 52,613 2,193 14,610 (67,793) 1,623
-------------------------------------------------------------------------------------
Total Other Income and (Deductions) 4,782 (13,707) (54,053) (5,453) (68,431)
Income (Loss) Before Income Taxes 3,913 (5,136) 52,267 (5,500) 45,544
Income Taxes (Benefit) (5,599) (1,767) 23,736 - 16,370
-------------------------------------------------------------------------------------
Earnings from Continuing Operations $ 9,512 $ (3,369) $ 28,531 $ (5,500) $ 29,174
Discontinued Operations - - (19,662) - (19,662)
-------------------------------------------------------------------------------------
Net Income (Loss) $ 9,512 $ (3,369) $ 8,869 $ (5,500) $ 9,512
====================================================================================-
28
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Income
- -----------------------------------------------------------------------------------------------------------------------------------
Six Months Ended June 30, 2003
(In Thousands of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- -----------------------------------------------------------------------------------------------------------------------------------
Revenues $ 177 $ 655,685 $ 3,264,992 $ (177) $ 3,920,677
Operating Expenses
Purchased gas - 377,620 1,242,845 - 1,620,465
Fuel and purchased power - - 199,998 - 199,998
Operations and maintenance 1,835 70,980 935,010 - 1,007,825
Intercompany expense 65 1,917 (1,917) (65) -
Depreciation and amortization (40) 44,984 242,317 - 287,261
Operating taxes (1,824) 40,959 180,829 - 219,964
------------------------------------------------------------------------------------
Total Operating Expenses 36 536,460 2,799,082 (65) 3,335,513
Income from Equity Investment 108 - 9,651 - 9,759
------------------------------------------------------------------------------------
Operating Income (Loss) 249 119,225 475,561 (112) 594,923
Interest charges (99,880) (31,110) (109,019) 91,872 (148,137)
Other income and (deductions) 328,011 (9,026) (41,444) (328,863) (51,322)
------------------------------------------------------------------------------------
Total Other Income and (Deductions) 228,131 (40,136) (150,463) (236,991) (199,459)
Income (Loss) Before Income Taxes 228,380 79,089 325,098 (237,103) 395,464
Income Taxes (Benefit) (8,947) 29,533 137,725 - 158,311
------------------------------------------------------------------------------------
Earnings before Change in Accounting Principle 237,327 49,556 187,373 (237,103) 237,153
Cumulative Effect of Change in Accounting
Principle - - 174 - 174
------------------------------------------------------------------------------------
Net Income (Loss) $ 237,327 $ 49,556 $ 187,547 $ (237,103) $ 237,327
====================================================================================
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Income
- ------------------------------------------------------------------------------------------------------------------------------------
Six Months Ended June 30, 2002
(In Thousands of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Revenues $ 234 $ 456,884 $ 2,634,893 $ (234) $ 3,091,777
Operating Expenses
Purchased gas - 205,440 693,859 - 899,299
Fuel and purchased power - - 177,664 - 177,664
Operations and maintenance 3,028 25,067 1,022,689 - 1,050,784
Intercompany expense 139 38,242 (38,242) (139) -
Depreciation and amortization (3) 35,581 217,882 - 253,460
Operating taxes 1 41,660 156,305 - 197,966
-------------------------------------------------------------------------------------
Total Operating Expenses 3,165 345,990 2,230,157 (139) 2,579,173
Income from Equity Investments 34 - 7,375 - 7,409
-------------------------------------------------------------------------------------
Operating Income (Loss) (2,897) 110,894 412,111 (95) 520,013
Interest charges (94,760) (31,102) (136,430) 119,631 (142,661)
Other income and (deductions) 315,864 5,095 27,498 (340,322) 8,135
-------------------------------------------------------------------------------------
Total Other Income and (Deductions) 221,104 (26,007) (108,932) (220,691) (134,526)
Income (Loss) Before Income Taxes 218,207 84,887 303,179 (220,786) 385,487
Income Taxes (Benefit) (5,936) 37,394 110,224 - 141,682
-------------------------------------------------------------------------------------
Earnings from Continuing Operations 224,143 47,493 192,955 (220,786) 243,805
Discontinued Operations - - (19,662) (19,662)
-------------------------------------------------------------------------------------
Net Income (Loss) $ 224,143 $ 47,493 $ 173,293 $ (220,786) $ 224,143
=====================================================================================
29
- ----------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
- ----------------------------------------------------------------------------------------------------------------------------------
June 30, 2003
Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- ----------------------------------------------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash & temporary cash investments $ 15,436 $ 6,533 $ 173,699 $ - $ 195,668
Accounts receivable, net 30,604 214,197 1,233,015 - 1,477,816
Other current assets 5,158 69,783 416,531 - 491,472
--------------------------------------------------------------------------------------
51,198 290,513 1,823,245 - 2,164,956
--------------------------------------------------------------------------------------
Investments and Other 3,930,951 2,542 210,721 (3,863,633) 280,581
--------------------------------------------------------------------------------------
Property
Gas - 1,819,692 4,468,296 - 6,287,988
Other - - 5,175,390 - 5,175,390
Accumulated depreciation and depletion - (337,659) (3,592,285) - (3,929,944)
--------------------------------------------------------------------------------------
- 1,482,033 6,051,401 - 7,533,434
--------------------------------------------------------------------------------------
Intercompany Accounts Receivable 3,676,581 - 537,345 (4,213,926) -
Deferred Charges 325,727 187,973 2,407,472 - 2,921,172
--------------------------------------------------------------------------------------
Total Assets $ 7,984,457 $ 1,963,061 $ 11,030,184 $ (8,077,559) $ 12,900,143
======================================================================================
LIABILITIES AND CAPITALIZATION
Current Liabilities
Accounts payable $ 131,692 $ 84,050 $ 752,009 $ - $ 967,751
Commercial paper 431,000 - - - 431,000
Other current liabilities 301,777 99,105 48,968 - 449,850
--------------------------------------------------------------------------------------
864,469 183,155 800,977 - 1,848,601
--------------------------------------------------------------------------------------
Intercompany Accounts Payable - 140,009 1,942,533 (2,082,542) -
---------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax (43,229) 147,602 799,588 - 903,961
Other deferred credits and liabilities 416,927 94,746 587,624 - 1,099,297
--------------------------------------------------------------------------------------
373,698 242,348 1,387,212 - 2,003,258
--------------------------------------------------------------------------------------
Capitalization
Common shareholders' equity 3,613,651 696,645 3,141,857 (3,863,633) 3,588,520
Preferred stock 83,697 - - - 83,697
Long-term debt 3,048,942 700,904 3,287,147 (2,131,384) 4,905,609
--------------------------------------------------------------------------------------
Total Capitalization 6,746,290 1,397,549 6,429,004 (5,995,017) 8,577,826
--------------------------------------------------------------------------------------
Minority Interest in Subsidiary Companies - - 470,458 - 470,458
--------------------------------------------------------------------------------------
Total Liabilities & Capitalization $ 7,984,457 $ 1,963,061 $ 11,030,184 $ (8,077,559) $ 12,900,143
======================================================================================
30
- -----------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
- -----------------------------------------------------------------------------------------------------------------------------------
December 31, 2002
Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- -----------------------------------------------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash & temporary cash investments $ 88,308 $ 6,472 $ 75,837 $ - $ 170,617
Accounts receivable, net 23,982 208,512 1,299,559 - 1,532,053
Other current assets 1,757 79,206 423,596 - 504,559
----------------------------------------------------------------------------------------
114,047 294,190 1,798,992 - 2,207,229
----------------------------------------------------------------------------------------
Investments and Other 3,797,964 2,717 201,675 (3,736,379) 265,977
----------------------------------------------------------------------------------------
Property
Gas - 1,771,780 4,352,501 - 6,124,281
Other - - 4,807,724 - 4,807,724
Accumulated depreciation and depletion - (322,236) (3,392,169) - (3,714,405)
----------------------------------------------------------------------------------------
- 1,449,544 5,768,056 - 7,217,600
----------------------------------------------------------------------------------------
Intercompany Accounts Receivable 3,619,515 - 712,394 (4,331,909) -
Deferred Charges 339,443 192,652 2,391,405 - 2,923,500
----------------------------------------------------------------------------------------
Total Assets $ 7,870,969 $ 1,939,103 $ 10,872,522 $ (8,068,288) $ 12,614,306
========================================================================================
LIABILITIES AND CAPITALIZATION
Current Liabilities
Accounts payable $ 132,966 $ 68,772 $ 859,911 $ - $ 1,061,649
Commercial paper 915,697 - - - 915,697
Other current liabilities 107,605 104,975 30,302 - 242,882
----------------------------------------------------------------------------------------
1,156,268 173,747 890,213 - 2,220,228
----------------------------------------------------------------------------------------
Intercompany Accounts Payable - 178,843 2,071,682 (2,250,525) -
----------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax (43,110) 139,715 780,408 - 877,013
Other deferred credits and liabilities 481,964 98,805 453,353 - 1,034,122
----------------------------------------------------------------------------------------
438,854 238,520 1,233,761 - 1,911,135
----------------------------------------------------------------------------------------
Capitalization
Common shareholders' equity 2,983,214 647,089 3,050,668 (3,736,379) 2,944,592
Preferred stock 83,849 - - - 83,849
Long-term debt 3,208,784 700,904 3,395,777 (2,081,384) 5,224,081
----------------------------------------------------------------------------------------
Total Capitalization 6,275,847 1,347,993 6,446,445 (5,817,763) 8,252,522
----------------------------------------------------------------------------------------
Minority Interest in Subsidiary Companies - - 230,421 - 230,421
----------------------------------------------------------------------------------------
Total Liabilities & Capitalization $ 7,870,969 $ 1,939,103 $ 10,872,522 $ (8,068,288) $ 12,614,306
========================================================================================
31
- --------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
- --------------------------------------------------------------------------------------------------------------------------
Six Months Ended June 30, 2003
--------------------------------------------------------------------
Guarantor KEDLI Other Subsidiaries Consolidated
--------------------------------------------------------------------
Operating Activities
Net Cash Provided by Operating Activities $ 138,174 $ 88,770 $ 338,433 $ 565,377
--------------------------------------------------------------------
Investing Activities
Capital expenditures - (49,875) (384,177) (434,052)
Proceeds from the sale of subsidiary investments 79,200 - 119,353 198,553
--------------------------------------------------------------------
Net Cash Provided by (Used in) Investing Activities 79,200 (49,875) (264,824) (235,499)
--------------------------------------------------------------------
Financing Activities
Treasury stock issued 57,441 - - 57,441
Equity issuance 473,573 - - 473,573
Redemption of promissory notes (447,005) - - (447,005)
Payment of debt, net (184,697) - (77,490) (262,187)
Common and preferred stock dividends paid (136,357) - - (136,357)
Other 13,065 - (3,357) 9,708
Net intercompany accounts (66,266) (38,834) 105,100 -
--------------------------------------------------------------------
-
Net Cash Provided by (Used in) Financing Activities (290,246) (38,834) 24,253 (304,827)
--------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents $ (72,872) $ 61 $ 97,862 $ 25,051
Cash and Cash Equivalents at Beginning of Period 88,308 6,472 75,837 170,617
--------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 15,436 $ 6,533 $ 173,699 $ 195,668
====================================================================
- ----------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
- ----------------------------------------------------------------------------------------------------------------------------------
Six Months Ended June 30, 2002
-----------------------------------------------------------------------------
Operating Activities Guarantor KEDLI Other Subsidiaries Consolidated
-----------------------------------------------------------------------------
Net Cash Provided by (Used in) Operating Activities $ (170,043) $ 176,705 $ 661,495 $ 668,157
-----------------------------------------------------------------------------
Investing Activities
Capital expenditures - (60,672) (519,231) (579,903)
-----------------------------------------------------------------------------
Net Cash Used in Investing Activities - (60,672) (519,231) (579,903)
-----------------------------------------------------------------------------
Financing Activities
Treasury stock issued 51,896 - - 51,896
Payment of debt, net (17,795) - (6,836) (24,631)
Common and preferred stock dividends paid (127,636) - - (127,636)
Other (1,355) - (8,181) (9,536)
Net intercompany accounts 309,651 (116,033) (193,618) -
-----------------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities 214,761 (116,033) (208,635) (109,907)
-----------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents $ 44,718 $ - $ (66,371) $ (21,653)
Cash and Cash Equivalents at Beginning of Period - - 159,252 159,252
-----------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 44,718 $ - $ 92,881 $ 137,599
=============================================================================
32
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Consolidated Review of Results
- ------------------------------
The following is a summary of transactions affecting comparative earnings and a
discussion of material changes in revenues and expenses during the three and six
months ended June 30, 2003, compared to the three and six months ended June 30,
2002. Capitalized terms used in the following discussion, but not otherwise
defined, have the same meaning as when used in the Notes to the Consolidated
Financial Statements included under Item 1. References to "KeySpan", "we", "us",
and "our" mean KeySpan Corporation, together with its consolidated subsidiaries.
Operating income by segment, as well as consolidated earnings available for
common stock is set forth in the following table for the periods indicated.
- ----------------------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars, Except per Share)
- ----------------------------------------------------------------------------------------------------------------------------------
Three Months Ended June 30, Six Months Ended June 30,
2003 2002 2003 2002
- ----------------------------------------------------------------------------------------------------------------------------------
Gas Distribution $ 31,616 $ 30,096 $ 396,553 $ 361,118
Electric Services 51,480 59,501 91,150 120,991
Energy Services (9,872) (10,867) (19,020) (20,224)
Energy Investments 59,222 29,308 124,936 53,835
Eliminations and other 5,783 5,937 1,304 4,293
- ----------------------------------------------------------------------------------------------------------------------------------
Operating Income 138,229 113,975 594,923 520,013
Other Income and (Deductions) (128,689) (68,431) (199,459) (134,526)
Income taxes 15,478 16,370 158,311 141,682
- ----------------------------------------------------------------------------------------------------------------------------------
Income (Loss) from Continuing Operations (5,938) 29,174 237,153 243,805
Cumulative effect of a change
in accounting principle (See Note 7) - - 174 -
Discontinued operations - (19,662) - (19,662)
- ----------------------------------------------------------------------------------------------------------------------------------
Net Income (Loss) (5,938) 9,512 237,327 224,143
Preferred stock dividend requirements 1,461 1,476 2,922 2,952
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) for Common Stock $ (7,399) $ 8,036 $ 234,405 $ 221,191
- ----------------------------------------------------------------------------------------------------------------------------------
Basic Earnings per Share
Income (loss) from continuing operations $ (0.05) $ 0.20 $ 1.49 $ 1.71
Change in accounting principle - - - -
Discontinued operations - (0.14) - (0.14)
- ----------------------------------------------------------------------------------------------------------------------------------
$ (0.05) $ 0.06 $ 1.49 $ 1.57
- ----------------------------------------------------------------------------------------------------------------------------------
As indicated in the above table, operating income increased $24.3 million, or
21% and $74.9 million, or 14% for the three and six months ended June 30, 2003,
respectively, compared to the corresponding periods of the prior year. The
increase in operating income for both the quarter and six months reflects higher
earnings from the Energy Investments and Gas Distribution segments, somewhat
offset by a decrease in earnings from the Electric Services segment. The Energy
Investment segment benefited from higher earnings associated with gas
exploration and production activities as a result of significantly higher
realized gas prices. The Gas Distribution segment benefited from significantly
colder weather during the January through April 2003 heating season compared to
33
the same period last year, as well as from load growth. Lower results from the
Electric Services segment are attributable to higher operating costs as a result
of increases in plant maintenance expenses and pension and other postretirement
costs, as well as lower revenues from our merchant generating facility, due, in
part to cooler weather. (See the discussion under the caption "Review of
Operating Segments" for further details on each segment.)
Included in Other Income and (Deductions) are interest charges of $79.2 million
and $148.1 million for the three and six months ended June 30, 2003,
respectively, an increase of 13% and 4% compared to the same periods last year.
The increase in interest charges primarily reflects the termination of certain
interest-rate derivative swap instruments that were in effect in 2002. (See Note
6 to the Consolidated Financial Statements "Hedging and Derivative Financial
Instruments".) For the three and six months ended June 30, 2003, Other Income
and (Deductions) also reflects a pre-tax loss of $30.3 million ($34.1 million
after-tax) associated with the partial monetization of our Canadian investments.
In June 2003, we sold 39.09% of our interest in KeySpan Canada, a company with
natural gas processing plants and gathering facilities in Western Canada.
Additionally, we sold our 20% interest in Taylor NGL LP that owns and operates
two extraction plants also in Canada. (See Note 2 to the Consolidated Financial
Statements "Business Segments" for additional information regarding this
transaction.)
Also included in Other Income and (Deductions) for the six months ended June 30,
2003 is a gain of $19.0 million reflecting the monetization of a portion of our
ownership interest in The Houston Exploration Company ("Houston Exploration"), a
gas exploration and production subsidiary. In February 2003, we reduced our
ownership interest in Houston Exploration from 66% to approximately 56%
following the repurchase, by Houston Exploration, of three million shares of
common stock owned by KeySpan. Income taxes were not provided on this
transaction, since the transaction was structured as a return of capital.
Further, in June 2003, Houston Exploration incurred costs of $5.9 million to
retire $100 million 8.625% Notes due 2008, that were also included in Other
Income and (Deductions). Additionally, in July 2002, Houston Exploration
received an abatement of severance taxes for certain qualifying wells. As a
result of this abatement, during the three and six months ended June 30, 2003,
Houston Exploration recorded severance tax refunds of $2.3 million and $12.9
million for severance taxes paid in 2002 and earlier periods, which have also
been reflected in Other Income and (Deductions).
In March 2003, we called approximately $447 million of outstanding promissory
notes that were issued to the Long Island Power Authority ("LIPA") in connection
with the KeySpan/Long Island Lighting Company ("LILCO") business combination
completed in May 1998. We recorded debt redemption charges of $18.2 million
associated with this redemption which is also recorded in Other Income and
(Deductions).
Finally, Other Income and (Deductions) reflects adjustments for minority
interest, as well as carrying charges on certain regulatory assets.
34
Income tax expense for the three and six months ended June 30, 2003 and 2002,
reflects a number of items impacting comparative earnings. During the second
quarter of 2003, certain costs associated with employee deferred compensation
plans were deducted for federal income tax purposes. These costs, however, are
not expensed for "book" purposes resulting in a beneficial permanent book-to-tax
difference of $6.3 million. Further, the partial monetization of our Canadian
investments resulted in a tax expense of $3.8 million, reflecting certain United
States partnership tax rules. Income tax expense for the three and six months
ended June 30, 2002 reflects a tax benefit of $6.4 million as a result of the
favorable resolution of certain outstanding tax issues related to the
KeySpan/LILCO merger. Additionally, during the first quarter of 2002, we
recorded an adjustment to deferred income taxes of $177.7 million reflecting a
decrease in the tax basis of the assets acquired at the time of the merger. This
adjustment was a result of a revised valuation study and the filing of an
amended tax return. Concurrent with the deferred tax adjustment, we reduced
current income taxes payable by $183.2 million, resulting in a $5.5 million
income tax benefit. Further, it should be noted that pre-tax income in the
Consolidated Statement of Income reflects minority interest adjustments, whereas
income taxes reflects the full amount of subsidiary taxes. Excluding these
items, income taxes generally reflects the level of pre-tax earnings for all
periods.
On January 24, 2002, we announced that we had entered into an agreement to sell
Midland Enterprises LLC ("Midland"), our marine barge business. During the
fourth quarter of 2001, in anticipation of this divestiture that closed on July
2, 2002, we recorded 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.
During the three months ended June 30, 2002, we recorded an additional after-tax
loss of $19.7 million, primarily reflecting a provision for certain city and
state taxes that resulted from a change in our tax structuring strategy.
As a result of the above mentioned items, earnings available for common stock
for the three months ended June 30, 2003 decreased $15.4 million, or $0.11 per
share, compared to the same period last year. Earnings available for common
stock for the six months ended June 30, 2003 increased $13.2 million; earnings
per share, however, decreased by $0.08 per share, compared to the same period
last year. Average common shares outstanding for the six months ended June 30,
2003 increased 12%, primarily reflecting the issuance of 13.9 million shares of
common stock on January 17, 2003, as well as the re-issuance of shares held in
treasury pursuant to dividend reinvestment and employee benefit plans. The
increase in average common shares outstanding reduced six months 2003 earnings
per share by $0.18 compared to the corresponding period in 2002. To mitigate the
dilutive effect of the equity offering we redeemed a portion of outstanding
promissory notes that were issued to LIPA, as previously mentioned. Interest
savings associated with this redemption are estimated to be $15.6 million
after-tax, or $0.09 per share, in 2003.
Consistent with our prior earnings guidance, KeySpan's earnings for 2003 are
forecasted to be approximately $2.45 to $2.60 per share, excluding special
items. 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 forecasts may vary
significantly during the year due to, among other things, changing economic and
energy market conditions, commodity prices and weather, and may vary by
operating segment as well.
35
Consolidated earnings are seasonal in nature due to the significant contribution
to earnings of the 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.
Review of Operating Segments
- ----------------------------
In response to new disclosure regulations adopted by the Securities and Exchange
Commission ("SEC") as part of its implementation of the Sarbanes-Oxley Act of
2002 - specifically Regulation G which became effective March 2003 - we are
reporting all of KeySpan's segment results on an Operating Income basis for 2003
and 2002. Management believes that this Generally Accepted Accounting Principle
(GAAP) based measure provides a true indication of KeySpan's underlying
performance associated with its operations. The following is a discussion of
financial results achieved by KeySpan's operating segments presented on an
Operating Income basis.
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, and 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 gas distribution
companies - Boston Gas Company, Colonial Gas Company, Essex 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. Net
revenues for 2002 have been restated to reflect a reclassification of gross
receipt taxes from revenue taxes to state income taxes, which is not an
Operating Income measure.
- ----------------------------------------------------------------------------------------------------------------------------
Three Months Ended June 30, Six Months Ended June 30,
(In Thousands of Dollars) 2003 2002 2003 2002
- ----------------------------------------------------------------------------------------------------------------------------
Revenues $ 732,036 $ 521,822 $ 2,564,737 $ 1,744,791
Cost of gas 417,484 236,357 1,571,616 849,939
Revenue taxes 17,269 15,588 55,886 48,144
- ----------------------------------------------------------------------------------------------------------------------------
Net Revenues 297,283 269,877 937,235 846,708
- ----------------------------------------------------------------------------------------------------------------------------
Operating Expenses
Operations and maintenance 163,124 152,767 329,214 298,305
Depreciation and amortization 66,192 58,118 137,009 121,138
Operating taxes 36,351 28,896 74,459 66,147
- ----------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 265,667 239,781 540,682 485,590
- ----------------------------------------------------------------------------------------------------------------------------
Operating Income $ 31,616 $ 30,096 $ 396,553 $ 361,118
- ----------------------------------------------------------------------------------------------------------------------------
Firm gas sales and transportation (MDTH) 56,048 47,978 211,714 164,496
Transportation - Electric Generation (MDTH) 9,145 13,182 14,148 26,541
Other Sales (MDTH) 24,482 39,112 78,151 102,024
Warmer (Colder) than Normal - New York (30%) - (13%) 15%
Warmer (Colder) than Normal - New England (45%) 14% (17%) 10%
- ----------------------------------------------------------------------------------------------------------------------------
An MDTH is 10,000 therms (British Thermal Units) 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.
36
Net Revenues
Net gas revenues (revenues less the cost of gas and associated revenue taxes)
from our gas distribution operations increased by $90.5 million, or 11%, for the
six months ended June 30, 2003 compared to the same period last year. Both our
New York and New England based gas distribution operations benefited from the
significantly colder than normal weather experienced throughout the Northeastern
United States during this past winter heating season. Based on heating degree
days, weather for the six months ended June 30, 2003 was approximately 13%-17%
colder than normal and approximately 30% - 35% colder than last year in our New
York and New England service territories.
Net revenues from firm gas customers (residential, commercial and industrial
customers) in our New York service territory increased by $51.4 million for the
six months ended June 30, 2003, compared to the same period last year. Customer
additions and oil-to-gas conversions, net of attrition and conservation, added
approximately $10 million to net revenues during the six months. Higher customer
consumption due primarily to colder than normal weather added approximately $50
million to net revenues during the six months. However, KEDNY and KEDLI each
operate under a utility tariff that contains a weather normalization adjustment
that significantly offsets variations in firm net revenues due to fluctuations
in normal weather. These weather normalization adjustments resulted in a $26.3
million refund to firm gas customers during the past six months. Further,
included in net revenues are regulatory incentives and recovery of certain taxes
that added $4.0 million and $13.5 million, respectively to net revenues during
this time period. The recovery of taxes through revenues, however, does not
impact net income since the taxes they are designed to recover are expensed as
amortization charges and income taxes, as appropriate, on the Consolidated
Statement of Income.
37
Net revenues from firm gas customers in our New England service territory
increased by $26.0 million for the six months ended June 30, 2003 compared to
the same period last year. Customer additions and oil-to-gas conversions, net of
attrition and conservation, added approximately $9 million to net revenues
during the six months. Higher customer consumption due primarily to colder than
normal weather added approximately $33 million to net revenues during the past
six months. The gas distribution operations of our New England based
subsidiaries do not have a weather normalization adjustment. To mitigate the
effect of fluctuations in normal weather patterns on KEDNE's results of
operations and cash flows, weather derivatives were put in place for the
2002/2003 winter heating season. Since weather during the first quarter of 2003
was 10% colder than normal in the New England service territory, we recorded an
$11.9 million reduction to revenues to reflect the loss on these derivative
transactions. (See Note 6 to the Consolidated Financial Statements "Hedging and
Derivative Financial Instruments" for further information). Further, included in
net revenues for the period ended June 30, 2002, was a benefit of $3.9 million
as a result of a favorable ruling from the Massachusetts Supreme Judicial Court
relating to the appeal by Boston Gas Company of its Performance Based Rate Plan
("PBR").
Firm gas distribution rates during the first six months of 2003, other than for
the recovery of gas costs, have remained substantially unchanged from rates
charged last year in all of our service territories.
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 designed to compete with prices of alternative
fuel, including No. 2 and No. 6 grade heating oil. Net revenues from sales to
these markets increased by $13.1 million during the six months ended June 30,
2003 compared to same period last year. The majority of interruptible profits
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 our 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.
Further, we estimate that in our 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 our market segments, through the economical
expansion of our 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.
38
Firm Sales, Transportation and Other Quantities
Firm gas sales and transportation quantities increased by 29% during the six
months ended June 30, 2003, compared to the same period in 2002, due to higher
customer consumption as a result of the significantly colder weather during the
past winter heating season, as well as from customer additions and oil-to-gas
conversions to natural gas. Net revenues are not affected by customers opting to
purchase their gas supply from other sources, since delivery rates charged to
transportation customers generally are the same as delivery rates charged to
sales service customers. Transportation quantities related to electric
generation reflect the transportation of gas to our 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 have a portfolio management contract with
Entergy-Koch, under which Entergy-Koch provides all of the city gate supply
requirements at market prices and manages certain upstream capacity, underground
storage and term supply contracts for KEDNE. These agreements have been renewed
through March 31, 2006.
Purchased Gas for Resale
The increase in gas costs for the six months ended June 30, 2003 compared to the
same period in 2002 of $721.7 million, or 85%, reflects an increase of 51% in
the price per dekatherm of gas purchased, and a 17% increase in the quantity of
gas purchased. 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 during the second quarter of 2003 increased $25.9 million, or
11%, compared to the same quarter last year and $55.1 million, or 11% for the
six months ended June 30, 2003, compared to the same period last year. These
increases are primarily attributable to higher employee benefits, primarily
pension and other postretirement benefits, which have increased (net of amounts
deferred and subject to regulatory true-ups) $11.9 million and $21.1 million for
the three and six months ended June 30, 2003, respectively. The cost of these
benefits has risen primarily as a result of lower actual returns on plan assets,
as well as increased health care costs. Further, the colder weather experienced
during the first six months of 2003 resulted in increased repair and maintenance
work on our gas distribution infrastructure and higher comparative operating
expenses. Also, for the six months ended June 30, 2003, the provision for bad
debts has increased as a result of higher revenues due to the cold weather and
higher cost of gas purchased.
39
Higher depreciation and amortization expense reflects the continued expansion of
the gas distribution system. Further, included in depreciation and amortization
expense is the amortization of certain property taxes previously deferred and
currently being recovered through revenues. Comparative operating taxes reflect
a favorable $7.4 million adjustment recorded during the three months ended June
30, 2002 relating to the reversal of excess tax reserves established for the
KeySpan / LILCO merger and subsequent re-organization in May 1998.
Other Matters
In order to serve the anticipated market requirements in our New York service
territory, KeySpan and Duke Energy Corporation formed Islander East Pipeline
Company, LLC ("Islander East") in 2000. Islander East is owned 50% by KeySpan
and 50% by Duke Energy, and was created to pursue the authorization and
construction of an interstate pipeline from Connecticut, across Long Island
Sound, to a terminus near Northport, Long Island. Applications for all necessary
regulatory authorizations were filed in 2000 and 2001. To date, Islander East
has received a final certificate from the Federal Energy Regulatory Commission
("FERC") and all necessary permits from the State of New York. However, the
State of Connecticut has denied Islander East's application for a coastal zone
management permit. Islander East has reinstated its appeal of the State of
Connecticut's determination to the United States Department of Commerce. Once in
service, the pipeline will transport 260,000 DTH daily to the Long Island and
New York City energy markets, enough natural gas to heat 600,000 homes. The
pipeline will also allow KeySpan to diversify the geographic sources of its gas
supply. Various options for the financing of pipeline construction are currently
being evaluated.
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.
40
Selected financial data for the Electric Services segment is set forth in the
table below for the periods indicated.
- ----------------------------------------------------------------------------------------------------------------------------
Three Months Ended June 30, Six Months Ended June 30,
(In Thousands of Dollars) 2003 2002 2003 2002
- ----------------------------------------------------------------------------------------------------------------------------
Revenues $ 370,617 $ 354,781 $ 705,036 $ 669,489
Purchased fuel 90,490 61,146 169,758 115,139
- ----------------------------------------------------------------------------------------------------------------------------
Net Revenues 280,127 293,635 535,278 554,350
- ----------------------------------------------------------------------------------------------------------------------------
Operating Expenses
Operations and maintenance 177,427 183,936 338,731 332,056
Depreciation 16,106 13,928 32,644 27,661
Operating taxes 35,114 36,270 72,753 73,642
- ----------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 228,647 234,134 444,128 433,359
- ----------------------------------------------------------------------------------------------------------------------------
Operating Income 51,480 59,501 91,150 120,991
- ----------------------------------------------------------------------------------------------------------------------------
Electric sales (MWH)* 995,433 1,125,735 1,762,782 2,216,978
Capacity(MW)* 2,200 2,200 2,200 2,200
Cooling degree days 184 353 184 353
- ----------------------------------------------------------------------------------------------------------------------------
*Reflects the operations of the Ravenswood facility only.
Net Revenues
Total electric net revenues decreased by $13.5 million, or 5%, in the second
quarter of 2003, compared to the same quarter of 2002. For the six months ended
June 30, 2003, total electric revenues decreased $19.1 million, or 3 %, compared
to the same period of 2002.
Net revenues from the Ravenswood facility were $8.5 million, or 11% lower during
the second quarter of 2003, compared to the same quarter in 2002 and $21.3
million, or 14% lower for the six months ended June 30, 2003 compared to the
same period last year. Comparative quarterly net revenues for the second quarter
reflect a decrease in energy margins of $18.9 million, partially offset by $10.4
million of higher capacity revenues. Comparative net revenues for the six months
reflect a decrease in energy margins of $19.8 million and a slight decrease in
capacity revenues. Due to a major overhaul of our largest steam generator, as
well as cooler weather compared to last year, energy sales quantities for the
quarter and six months ended June 30, 2003 were lower compared to the same
periods last year. Further, energy margins reflect lower realized
"spark-spreads" (the selling price of electricity less cost of fuel, plus
hedging gains or losses). The increase in capacity revenues for the second
quarter of 2003 reflects both an increase in the level of capacity sold and an
increase in the selling price of capacity. In 2002, the New York Independent
System Operator ("NYISO") employed a revised methodology to assess the available
supply of and demand for installed capacity. This revised methodology resulted
in insufficient capacity being procured by the market, as well as a reliability
concern. For the three and six months ended June 30, 2002 this revised
methodology resulted in both lower capacity volume sold into the NYISO and lower
capacity pricing. In September 2002, the NYISO recognized a calculation flaw in
its revised methodology and prior to the 2002/2003 winter auction the NYISO
corrected the calculation methodology to ensure sufficient capacity is procured.
Elimination of the flaw ensured compliance with New York State Reliability Rules
and resulted in higher capacity revenue realized at the Ravenswood facility for
the three and six months ended June 30, 2003.
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
41
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 KeySpan's 2002
Annual Report on Form 10-K for the Year Ended December 31, 2002 Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations under the caption "Market and Credit Risk Management Activities" for
a further discussion of these matters.)
Net revenues from the service agreements with LIPA decreased by $10.3 million,
or 5% and $11.0 million, or 3% for the three and six months ended June 30, 2003,
respectively, compared to the same periods last year. Included in 2003 revenues,
are billings to LIPA for certain third party costs that were lower 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 2003
associated with these service agreements were comparable to such revenues last
year.
Net revenues from the Glenwood Landing and Port Jefferson electric "peaking"
facilities located on Long Island were $5.3 million and $13.2 million higher
during the three and six months ended June 30, 2003, compared to the
corresponding periods last year. The Glenwood facility was placed in service on
June 1, 2002, while the Port Jefferson facility was placed in service on July 1,
2002.
Operating Expenses
Operating expenses decreased by $5.5 million in the second quarter of 2003
compared to the same quarter of 2002. However, included in comparative operating
expenses is a decrease in third party capital costs that are fully recoverable
from LIPA, as noted previously. Excluding the decrease in these costs, operating
expenses increased approximately $5 million, or 2% during the second quarter of
2003 compared to the same quarter last year. Operating expenses for the six
months ended June 30, 2003 increased $10.8 million compared to the corresponding
period last year. Again, included in comparative operating expenses is a
decrease in third party capital costs that are fully recoverable from LIPA.
Excluding the decrease in these costs, operating expenses for the six months
ended June 30, 2003 increased approximately $21 million, or 5%, compared to the
same period last year. This increase resulted, in part, from higher pension and
other postretirement benefits. LIPA reimburses KeySpan for costs directly
incurred by KeySpan in providing service to LIPA, subject to certain sharing
provisions. Variations between pension and other postretirement costs and the
estimates used to bill LIPA are deferred and refunded to or collected from LIPA
in subsequent periods. As a result of an adjustment recorded in 2002 relating to
this "true-up", comparative pension and other postretirement costs were
approximately $8 million higher for the six months ended June 30, 2003 compared
to this time last year. Further, plant maintenance costs were $5.3 million
higher for the six months, due to the major overhaul of our largest steam
generator as previously mentioned. The increase in depreciation expense is
primarily due to the depreciation of the two "peaking" facilities.
42
Other Matters
During 2002, construction began 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. In addition, our
application to construct and operate a similar 250 MW combined cycle electric
generating facility on Long Island has been approved. On May 8th, the New York
State Board on Electric Generation Siting and the Environment issued an opinion
and order which granted a certificate of environmental capability and public
need for this proposed facility. KeySpan plans to respond to a Request for
Proposals ("RFP") issued by LIPA in May 2003, by offering the capacity and
services from this proposed 250 MW combined cycle electric generating plant.
LIPA is seeking proposals from developers to either build and operate a Long
Island generating facility, and/or a new cable that will link Long Island to
dedicated off-Long Island power of between 250 to 600 megawatts (MW) of
electricity by no later than the summer of 2007.
As part of our growth strategy, we continually evaluate the possible acquisition
and development 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.
Energy Services
The Energy Services segment primarily includes companies that provide services
through three lines of business to clients primarily 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.
- ------------------------------------------------------------------------------------------------------------------------------
Three Months Ended June 30, Six Months Ended June 30,
(In Thousands of Dollars) 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Revenues $ 155,564 $ 229,311 $ 349,361 $ 470,870
Less: cost of gas and fuel 18,688 45,731 78,841 111,885
- ------------------------------------------------------------------------------------------------------------------------------
Net Revenues 136,876 183,580 270,520 358,985
Other operating expenses 146,748 194,447 289,540 379,209
- ------------------------------------------------------------------------------------------------------------------------------
Operating Income $ (9,872) $ (10,867) $ (19,020) $ (20,224)
- ------------------------------------------------------------------------------------------------------------------------------
Revenues decreased approximately 32% and 26% for the three and six months ended
June 30, 2003, respectively, compared to the same periods last year, due, in
part, to lower revenues realized by the Business Solutions group of companies as
a result of the continued down turn in the economy, as well as from the
discontinuation of the general contracting business of one of our subsidiaries.
The Business Solutions group of companies provide mechanical, contracting,
plumbing, engineering, and consulting services to commercial, institutional, and
industrial customers. Further, on May 1, 2003, KeySpan's gas and electric
marketing subsidiary, KeySpan Energy Services, assigned the majority of its
retail natural gas customers, consisting mostly of residential and small
commercial customers, to ECONnergy Energy Co., Inc. ("ECONnergy). KeySpan Energy
Services will continue to provided retail natural gas marketing to a small
number of customers in New Jersey and will continue its electric marketing
activities. Comparative revenues, as well as gas and fuel costs were impacted by
this transaction.
43
Operating Income for the Business Solutions group of companies decreased by $8.8
million for the second quarter of 2003 and by $10.6 million for the six months
ended June 30, 2003, compared to the corresponding periods of last year. These
declines reflect the slow down in the economy, which has delayed the start-up of
certain engineering and construction projects. Further, the continued down turn
in the economy has lowered margins realized on construction projects currently
in progress. This is further reflected by a backlog of approximately $469
million at June 30, 2003, compared to $514 million at December 31, 2002 and $610
million at June 30, 2002.
Offsetting the results of the Business Solutions group of companies, were
comparative increases in earnings of $9.8 million and $11.8 million for the
three and six months ended June 30, 2003, respectively, associated with the Home
Energy Services group of companies. These companies provide residential and
small commercial customers with service and maintenance contracts, as well as
the retail marketing of natural gas and electricity. Comparative operating
income reflects losses incurred during the three and six months ended June 30,
2002, resulting from: (i) the adverse impact of the down-turn in the economy;
(ii) the non-renewal of appliance service contracts due to the warm first
quarter 2002 weather; and (iii) an increase in the provision for bad debts.
Other Matters
KeySpan Services, Inc., and its wholly- owned subsidiary, Paulus, Sokolowski and
Sartor, LLC., have entered into an agreement to acquire Bard, Rao + Athanas
Consulting Engineers, Inc. (BR+A), a company engaged in the business of
providing engineering services relating to mechanical, electrical and plumbing
systems. The purchase price is expected to be approximately $35 million, plus up
to $14.7 million in contingent consideration depending on the financial
performance of BR+A over the five-year period after the closing of the
acquisition. We have received all necessary regulatory approvals and it is
anticipated that the closing of this transaction will occur in the third quarter
of 2003.
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, Houston Exploration and KeySpan Exploration and
Production LLC ("KES E&P") are engaged in gas and oil exploration and
production, and the development and acquisition of domestic natural gas and oil
properties. In line with our strategy of monetizing or divesting 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
44
1999. Further, in February 2003, we reduced our ownership interest in Houston
Exploration to approximately 56% (from the previous level of 66%) through the
repurchase, by Houston Exploration, of three 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. We
realized a $19.0 million gain on this transaction that was recorded in Other
Income and Deductions in the Consolidated Statement of Income. Income taxes were
not provided on this transaction, since the transaction was structured as a
return of capital.
Selected financial data and operating statistics for our gas exploration and
production activities are set forth in the following table for the periods
indicated.
- --------------------------------------------------------------------------------------------------------------------------------
Three Months Ended June 30, Six Months Ended June 30,
(In Thousands of Dollars) 2003 2002 2003 2002
- --------------------------------------------------------------------------------------------------------------------------------
Revenues $ 122,875 $ 90,563 $ 250,722 $ 167,489
Depletion and amortization expense 49,475 44,440 96,918 85,885
Other operating expenses 23,252 16,668 48,066 32,324
- --------------------------------------------------------------------------------------------------------------------------------
Operating Income $ 50,148 $ 29,455 $ 105,738 $ 49,280
- --------------------------------------------------------------------------------------------------------------------------------
Natural gas and oil production (Mmcf) 27,119 27,057 53,205 52,727
Natural gas (per Mcf) realized $ 4.55 $ 3.29 $ 4.73 $ 3.13
Natural gas (per Mcf) unhedged $ 5.16 $ 3.28 $ 5.76 $ 2.79
- --------------------------------------------------------------------------------------------------------------------------------
*Operating income above represents 100% of our gas exploration and production
subsidiaries' results for the periods indicated. Gas reserves and production are
stated in BCFe and Mmcfe, which includes equivalent oil reserves.
The increase in operating income of $20.7 million and $56.5 million for the
three and six months ended June 30, 2003, compared to the corresponding periods
last year, reflects, in part, a significant increase in revenues offset, to some
extent, by an increase in operating expenses associated with higher production
volumes. Revenues for both the quarter and first six months of 2003 benefited
from the significant increase in comparative average realized gas prices
(average wellhead price received for production including hedging gains and
losses). Average realized gas prices increased 38% and 51% for the three and six
months ended June 30, 2003, compared with the corresponding periods last year.
Revenues also benefited from a slight increase in production volumes for the
three and six months ended June 30, 2003, respectively.
The average realized gas price for the second quarter of 2003 was 88% of the
average unhedged natural gas price, resulting in revenues that were $15.4
million lower than revenues that would have been achieved if derivative
financial instruments had not been in place during the second quarter of 2003.
The average realized gas price for the six months ended June 30, 2003 was 82% of
the average unhedged natural gas price, resulting in revenues that were $50.0
million lower than revenues that would have been realized if derivative
financial instruments had not been in place during the first six months of 2003.
Houston Exploration hedged approximately 70% of its 2003 second quarter and six
months production, principally through the use of costless collars.
45
The average realized gas price for the second quarter of 2002 was substantially
the same as the average unhedged natural gas price. The average realized gas
price for the six months ended June 30, 2002 was 112% of the average unhedged
natural gas price resulting in revenues that were $17.0 million higher than
revenues that would have been realized if derivative financial instruments had
not been employed during the first six months of 2002.
The 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 June 30, 2003 Houston Exploration had derivative
positions in place to hedge approximately 67% of its estimated 2003 and 2004
yearly production, principally through the use of collars. (See Note 6 to the
Consolidated Financial Statements, "Hedging and Derivative Financial
Instruments" for further information on these derivative positions.)
The depletion rate was $1.79 per Mcf for the six months ended June 30, 2003,
compared to $1.63 per Mcf for the same period in 2002. The depletion rate has
increased as Houston Exploration completed the evaluation of several properties
that were classified as unproved during the fourth quarter of 2002. As the
evaluation is completed, the costs associated with these properties were
reclassified into the amortization base without incremental reserve additions.
In addition, future development costs have increased from prior year estimates.
The table below indicates the net proved reserves of our gas exploration and
production subsidiaries at December 31, 2002.
- -------------------------------------------------------------------
BCFe %
- -------------------------------------------------------------------
Houston Exploration 650 96.7%
KSE E&P 22 3.3%
- -------------------------------------------------------------------
Total 672 100.0%
- -------------------------------------------------------------------
This segment also consists of KeySpan Canada; our 20% interest in Iroquois Gas
Transmission System LP ("Iroquois"); and our 50% interest in the Premier
Transmission Pipeline and 24.5% interest in Phoenix Natural Gas, both located in
Northern Ireland.
46
Selected financial data and operating statistics for our other energy-related
investments are set forth in the following table for the periods indicated.
- ---------------------------------------------------------------------------------------------------------------------------------
Three Months Ended June 30, Six Months Ended June30,
(In Thousands of Dollars) 2003 2002 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------
Revenues $ 29,880 $ 21,942 $ 56,344 $ 39,575
Operation and maintenance expense 19,390 19,768 36,034 33,826
Other operating expenses 5,410 5,545 10,763 8,572
Equity earnings 3,994 3,224 9,651 7,378
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Income $ 9,074 $ (147) $ 19,198 $ 4,555
- ---------------------------------------------------------------------------------------------------------------------------------
The increase in operating income for both the three and six months ended June
30, 2003 compared to the same periods last year primarily reflects lower
comparative losses associated with certain technology-related investments, as
well as higher operating income associated with our Canadian investments,
primarily KeySpan Canada. KeySpan Canada experienced higher unit sales, as well
as higher quantities of sales of natural gas liquids in 2003, as a result of
increasing oil prices. The pricing of natural gas liquids is directly related to
oil prices.
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. As
previously indicated, on May 30, 2003 we monetized 39.09% of our interest in
KeySpan Canada, a company with natural gas processing plants and gathering
facilities in Western Canada. These assets include 14 processing plants and
associated gathering systems that can process approximately 1.5 BCFe of natural
gas daily and provide associated natural gas liquids fractionation. We sold a
portion of our interest in KeySpan Canada through the establishment of an
open-ended income fund trust (the "Fund") organized under the laws of Alberta,
Canada. The Fund acquired the 39.09% ownership interest of KeySpan Canada
through an indirect subsidiary, and then issued 17 million trust units to the
public through an initial public offering. Each trust unit represents a
beneficial interest in the Fund and is registered on the Toronto Stock Exchange
(KEY.UN). Additionally, we sold our 20% interest in Taylor NGL LP that owns and
operates two extraction plants also in Canada to AltaGas Services, Inc. We
received cash proceeds of $119.4 million associated with these transactions and
recorded a pre-tax loss of $30.3 million ($34.1 million after-tax). This
investment is now expected to provide an annual cash dividend of approximately
$20 million.
Based on current market conditions, however, we cannot predict when, or if, any
other sales or dispositions of our non-core assets 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
We are subject to the jurisdiction of the SEC under the Public Utility Holding
Company Act ("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 SEC's regulations under PUHCA and the New York State
Public Service Commission ("NYPSC") 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.
47
Liquidity
Cash flow from operations for the six months ended June 30, 2003 decreased
$102.8 million, compared to the same period last year, primarily due to
fluctuating natural gas prices and the seasonal nature of our 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 higher gas storage injection costs during the summer and
early fall of 2001 compared to the same period in 2002, gas cost recoveries for
the six months ended June 30, 2002 were greater than such recoveries for the
same period this year. Further, the significantly higher gas prices during the
six months ended June 30, 2003, compared with this time last year, coupled with
the colder weather, resulted in significantly higher customer accounts
receivable balances, as well as higher cash expenditures required to maintain
natural gas inventory levels. The higher accounts receivable reflect, in part,
cash expenditures for the purchase of natural gas that was consumed by our
customers during the winter, but have not yet been recovered through revenues.
At June 30, 2003, we had cash and temporary cash investments of $195.7 million.
During the six months ended June 30, 2003, we repaid $484.7 million of
commercial paper and, at June 30, 2003, $431.0 million of commercial paper was
outstanding at a weighted average annualized interest rate of 1.28%. We had the
ability to borrow up to an additional $869 million at June 30, 2003, under the
terms of our credit facility.
On June 27, 2003, KeySpan renewed its $1.3 billion revolving credit facility,
which was syndicated among sixteen banks. The facility is used to support
KeySpan's commercial paper program, and consists of two separate credit
facilities with different maturities but substantially similar terms and
conditions: a $450 million facility that extends for 364 days, and a $850
million facility that is committed for three years. The fees for the facilities
are subject to a ratings-based grid, with an annual fee of 0.10% on the 364-day
facility and 0.125% on the three-year facility. Both credit agreements allow 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 0.625% for
loans up to 33% of the total facility, and an additional 0.125% for loans over
33% of the total facility. ABR loans are based on the highest 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. In addition, the 364-day facility has a one-year term out option, which
would cost an additional 0.25% if utilized. 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.
48
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
64%. 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.
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 June 30, 2003, consolidated indebtedness, as calculated under the terms of
the credit facility and reflecting the redemption of Houston Exploration's
senior subordinated notes, was 57.2% of consolidated capitalization. (See Note 5
to the Consolidated Financial Statements "Long-term Debt and Commercial Paper"
for an explanation of the redemption, and the discussion under "Off-Balance
Sheet Arrangements" for an explanation of 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 June 30, 2003, KeySpan was in compliance with
all covenants.
Houston Exploration has a revolving credit facility with a commercial banking
syndicate that provides Houston Exploration with a 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 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 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 rate 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 June 30,
2003, Houston Exploration was in compliance with all financial covenants.
49
During the six months ended June 30, 2003, Houston Exploration borrowed $53
million under its credit facility and repaid $185 million. At June 30, 2003, $20
million of borrowings remained outstanding at a weighted average annualized
interest rate of 3.49%. Also, $9.4 million was committed under outstanding
letters of credit obligations. At June 30, 2003, $270.6 million of borrowing
capacity was available.
In June 2003, KeySpan Canada replaced its two outstanding credit facilities with
one facility with three tranches that combined allow KeySpan Canada to borrow up
to approximately $125 million. These facilities mature as follows: (i) $50
million matures in 180 days; (ii) $37.5 million matures in 364 days; and (iii)
$37.5 million matures in two years. At the time of the partial sale of KeySpan
Canada, net proceeds from the sale of $119.4 million plus an additional $45.7
million drawn under the new credit facilities were used to pay down existing
outstanding debt of $160.4 million. For the six months ended June 30, 2003,
KeySpan Canada borrowed $71.4 million from its credit facilities and repaid
$191.0 million. At June 30, 2003 $50.5 million is outstanding under the new
credit facilities and $74.5 million remains available to be borrowed. KeySpan is
not a guarantor of this credit facility.
On January 17, 2003, KeySpan sold 13.9 million shares of common stock on 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 to call a
portion of outstanding promissory notes to LIPA as is further explained in
"Capital Expenditures and Financing" below. 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.
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.
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.
50
Capital Expenditures and Financing
Construction Expenditures
The table below sets forth our construction expenditures by operating segment
for the periods indicated:
- --------------------------------------------------------------------------
Six Months Ended June 30,
(In Thousands of Dollars) 2003 2002
- --------------------------------------------------------------------------
Gas Distribution $ 165,690 $ 183,588
Electric Services 113,880 225,051
Energy Investments 149,009 161,155
Energy Services and other 5,473 10,109
- --------------------------------------------------------------------------
$ 434,052 $ 579,903
- --------------------------------------------------------------------------
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 new Long Island generating
facilities as previously noted. The decrease in Electric Services construction
expenditures for the six months ended June 30, 2003 compared to the same period
last year reflects the fact that construction of the Glenwood and Port Jefferson
peaking facilities was substantially completed by June 30, 2002. 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 June 30, 2003, 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
$297 million.
Financing
On June 10, 2003, Houston Exploration closed on a private placement issue of
$175 million of 7.0%, senior subordinated notes due 2013. Interest payments will
begin on December 15, 2003, and will be paid semi- annually thereafter. The
notes will mature on June 15, 2013. Houston Exploration has the right to redeem
the notes as of June 15, 2008, at a price equal to the issue price plus a
specified redemption premium. Until June 15, 2006, Houston Exploration may also
redeem up to 35% of the notes at a redemption price of 107 percent with proceeds
from an equity offering. Houston Exploration incurred approximately $4.5 million
of debt issuance costs on this private placement. On July 11, 2003, Houston
Exploration used a portion of the net proceeds from the issuance to redeem all
of its outstanding $100 million principal amount of 8.625% senior subordinated
notes due 2008 at a price of 104.313 percent of par plus interest accrued to the
redemption date. Debt redemption costs totaled approximately $5.9 million. The
remaining net proceeds from the offering were used to reduce debt amounts
associated with Houston Exploration's revolving bank credit facility.
51
In April 2003, we issued $300 million of medium-term and long-term debt. The
debt was issued in the following two series: (i) $150 million 4.65% Notes due
2013; and (ii) $150 million 5.875% Notes due 2033. The proceeds of this issuance
were used to pay down outstanding commercial paper.
In connection with the KeySpan/LILCO business combination, 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. 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. In an effort
to mitigate the dilutive effect of the equity issuance previously mentioned, in
March 2003, we called 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. Interest savings associated
with this redemption are estimated to be $15.6 million after-tax, or $0.09 per
share, in 2003.
KeySpan had authorization under PUHCA to issue up to $2.2 billion of securities
through December 31, 2003. Following the recent common stock offering previously
mentioned and shares of common stock expected to be issued for employee benefit
and dividend reinvestment plans, we generally exhausted our ability to issue 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 have filed an application
with the SEC requesting authorization to, among other things, issue up to an
additional $3 billion of securities through December 31, 2006. It is anticipated
that this authorization will be obtained before the end of the year. This
request is intended to provide us with maximum flexibility to finance our future
capital requirements over the next three years.
During the remainder 2003, we intend to issue approximately $150 million of
either taxable or tax-exempt long-term debt securities in a manner that will be
exempt from PUHCA restrictions. We anticipate that the proceeds from the
issuance will be used to re-pay the outstanding commercial paper related to the
construction of the two Long Island peaking-power plants that became operational
in 2002. 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) are sufficient to meet
our anticipated working capital needs for the foreseeable future.
52
The following table represents the ratings of our long-term debt at June 30,
2003. Currently, these ratings are all on stable outlook with the exception of
Standard & Poor's rating on KeySpan Corporation, which is on negative outlook.
Moody's Investor Standard
Services & Poor's FitchRatings
- --------------------------------------------------------------------------------
KeySpan Corporation A3 A A-
KEDNY A2 A+ A+
KEDLI A2 A+ A-
Boston Gas A A2 N/A
Colonial Gas A A2 N/A
Electric Generation A3 A N/A
- --------------------------------------------------------------------------------
Off-Balance Sheet Arrangements
Guarantees
KeySpan has a number of financial guarantees for its subsidiaries that have
remained substantially unchanged since December 31, 2002. At June 30, 2003,
KeySpan has fully and unconditionally guaranteed certain medium-term notes
issued by KEDLI. The medium-term notes are reflected on the Consolidated Balance
Sheet. Further, KeySpan has guaranteed: (i) 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, as well as an unaffiliated company;
(iii) the obligations of KeySpan Ravenswood LLC, the lessee under the $425
million Master Lease Agreement associated with the Ravenswood facility; and (iv)
certain subsidiary letters of credit. KeySpan has also guaranteed a $25 million
line of credit for Hawkeye Electric, LLC, ("Hawkeye"), a non-affiliated company.
As part of a settlement agreement with Hawkeye, such line of credit will be
reduced to $13 million and will terminate in March 2004. These guarantees are
not recorded on the Consolidated Balance Sheet. At this time, we have no reason
to believe that our subsidiaries or the non-affiliated company 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 8 to the
Consolidated Financial Statements, "Financial Guarantees and Contingencies" and
Note 9 "Variable Interest Entity" for additional information regarding KeySpan's
guarantees and a description of the leasing arrangement associated with the
Ravenswood Master Lease Agreement.)
53
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 The Consolidated Edison Company
of New York ("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, 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.
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 requires 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. FIN 46 will require us to classify the Master Lease as
debt on the Consolidated Balance Sheet at an amount approximately 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.
The Interpretation contains certain other provisions that we will be required to
implement in 2003 and such provisions will impact future earnings. (See Note 9
to the Consolidated Financial Statements "Variable Interest Entity" for a more
detailed description of the Master Lease and FIN 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. These obligations have remained substantially
unchanged since December 31, 2002. (For additional details regarding these
obligations see KeySpan's Annual Report on Form 10-K for the Year Ended December
31, 2002, Item 7 Management's Discussion and Analysis of Financial Condition and
Results of Operations, Note 6 to those Consolidated Financial Statements
"Long-Term Debt", as well as Note 7 to those Consolidated Financial Statements
"Contractual Obligations, Financial Guarantees and Contingencies.")
Discussions 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
54
operations may vary significantly from expected results if the judgments and
assumptions underlying the estimates prove to be inaccurate. At June 30, 2003,
KeySpan's critical accounting policies and assumptions have remained
substantially unchanged since December 31, 2002. Below is a brief discussion of
those critical accounting policies requiring such subjectivity. For a more
detailed discussion of these policies and assumptions see KeySpan's Annual
Report on Form 10-K for the Year Ended December 31, 2002, Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations
"Discussion of Critical Accounting Policies and Assumptions."
Percentage of Completion Accounting
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. 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.
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 Statement of Financial Accounting Standards ("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.
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.
55
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 ten-year periods ending 2008 and 2009, respectively. Due to the
length of these base rate freezes, the Colonial and Essex Gas Companies had
previously discontinued the application of SFAS 71.
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. 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 filed a base rate case and a performance based rate plan for
Boston Gas Company on April 16, 2003. Further, we are currently evaluating
various options that may be available to us including, but not limited to,
proposing new rate 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
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.
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 presently exceed ERISA funding requirements,
our pension plans, on an actuarial basis, are currently underfunded. Future
funding requirements are heavily dependent on the actual return on plan assets.
Therefore, if the actual return on plan assets continues to be significantly
56
below the expected returns, we may elect to fund the pension plans in 2003. (In
addition to Item 7 Management's Discussion and Analysis of Financial Condition
and Results of Operations in KeySpan's Annual Report on Form 10-K for the Year
Ended December 31, 2002, see also Note 4 to those Consolidated Financial
Statements, "Postretirement Benefits.")
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.
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.
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. Further, none of our currently outstanding
derivatives 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
57
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. (See Note 6 to the Consolidated Financial Statements "Hedging
and Derivative Financial Instruments" for a further description of all our
derivative instruments.)
Regulation and Rate Matters
Gas Matters
As of June 30, 2003, the rate agreements for KEDNY, KEDLI and Boston Gas Company
have all expired. Under the terms of the KEDNY and KEDLI rate agreements, gas
distribution rates and all other provisions 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 the KEDNY and KEDLI rate plans, including but not
limited to, proposing new rate plans. Regarding the Boston Gas Company, we filed
a base rate case and performance based rate plan on April 16, 2003, to be
effective in the fourth quarter of 2003. The filing requests an annual revenue
increase of approximately $62 million, a 12.18% return on equity, and a
performance based rate plan with a term of five years. Proceedings with the DTE
are currently ongoing.
For an additional information regarding our current gas distribution rate
agreements, see KeySpan's Annual Report on Form 10-K for the Year Ended December
31, 2002, Item 7 Management's Discussion and Analysis of Financial Condition and
Results of Operations "Regulation and Rate Matters."
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 Enterprises and EnergyNorth Inc. 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
58
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 June 30, 2003, our consolidated common equity was 40.7% of
our consolidated capitalization, including commercial paper but excluding
Houston Exploration's debt that was redeemed on July 11, 2003, and each of our
utility subsidiaries common equity was at least 35% of its respective
capitalization. As previously mentioned, we have filed a new application
requesting authorization to, among other things, issue up to an additional $3
billion of securities through December 31, 2006. It is anticipated that this
authorization will be obtained before the end of the year.
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 $184.2 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. Further, as of
June 30, 2003, we have expended a total of $80.2 million on environmental
remediation. (See Note 8 to the Consolidated Financial Statements, "Financial
Guarantees and Contingencies".)
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 Note 6 to the Consolidated
Financial Statements "Hedging and Derivative Financial Instruments" for a
further explanation of derivative financial instruments.)
59
Credit Risk: We are exposed to credit risk arising from the potential that our
counterparties fail to perform on their contractual obligations. Our credit
exposures are created primarily through the sale of gas and transportation
services to residential, commercial, electric generation, and industrial
customers and the provision of retail access services to gas marketers, by our
regulated gas businesses; the sale of commodities and services to LIPA and the
NYISO; the sale of gas, power and services to our retail customers by our
unregulated energy service businesses; entering into financial and energy
derivative contracts with energy marketing companies and financial institutions;
and the sale of gas, natural gas liquids, oil and processing services to energy
marketing and oil and gas production companies.
We have regional concentration of credit risk due to receivables from
residential, commercial and industrial customers in New York, New Hampshire and
Massachusetts, although this credit risk is spread over a diversified base of
residential, commercial and industrial customers. Customers' payment records are
monitored and action is taken, when appropriate. Companies within the Energy
Services segment have a concentration of credit risk to large customers and to
the governmental and healthcare industries.
We also have concentrations of credit risk from LIPA, our largest customer, and
from other energy companies. Concentration of energy company counterparties may
impact overall exposure to credit risk in that our counterparties may be
similarly impacted by changes in economic, regulatory or other considerations.
We actively monitor the credit profile of our wholesale counterparties in
derivative and other contractual arrangements, and manage our level of exposure
accordingly. Over the past year, the credit quality of certain energy companies
has declined. In instances where counterparties' credit quality has declined, we
may limit our credit exposure by restricting new transactions with the
counterparty, requiring additional collateral or credit support and negotiating
the early termination of certain agreements.
Regulatory Issues and Competitive Environment: We are subject to various other
risk exposures and uncertainties associated with our gas and electric
operations. The most significant contingency involves the evolution of the gas
distribution and electric industries towards more competitive and deregulated
environments. These risks have not changed substantially since December 31,
2002. For additional information regarding these risks see KeySpan's Annual
Report on Form 10-K for the Year Ended December 31, 2002, Item 7 Management's
Discussion and Analysis of Financial Condition and Results of Operations "Market
and Credit Risk Management Activities".
Cautionary Statement Regarding Forward-Looking Statements
Certain statements contained in this Quarterly Report on Form 10-Q 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 2.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Item 3. Quantitative and Qualitative Disclosures About Market
60
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 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 counterparties 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;
- - changes in political conditions, acts of war or terrorism;
61
- - changes in rates of return on overall debt and equity markets could have an
adverse impact on the value of pension assets;
- - changes in accounting standards or GAAP which may require adjustment to
financial statements; and
- - other risks detailed from time to time in other reports and other documents
filed by KeySpan with the 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 2. Management's Discussion and Analysis
of Financial Condition and Results of Operations" and "Item 3. Quantitative and
Qualitative Disclosures About Market Risk" contained herein.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
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 and put options, 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 June 30,
2003, Houston Exploration has hedged approximately 67% of its estimated 2003 and
2004 gas production. To value its outstanding derivatives, Houston Exploration
used standard New York Mercantile Exchange ("NYMEX") futures prices, and, in
addition, used published volatility in its Black-Scholes calculation for
outstanding options. The maximum length of time over which Houston Exploration
has hedged such cash flow 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 $47.5 million, or $30.6 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 September 2004; and (ii) forecasted purchases of fuel oil
is through April 2005. 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 $1.5 million, or $1.0 million after-tax.
62
KeySpan Canada employs natural gas swaps to lock-in a price for expected future
natural gas purchases. As applicable, we used 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 October 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 negligible at June 30, 2003.
We have also engaged in the use of cash-settled swap instruments to hedge the
cash flow variability associated with a portion of forecasted peak electric
energy sales from the Ravenswood facility. The maximum length of time over which
we have hedged cash flow variability is through December 2004. We used
NYISO-location zone published indices to value these outstanding derivatives.
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 $3.3 million, or $2.2
million after-tax.
KeySpan Canada also employs 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 $0.7 million, or $0.5 million after-tax.
The following tables set forth selected financial data associated with these
derivative financial instruments noted above that were outstanding at June 30,
2003.
- ------------------------------------------------------------------------------------------------------------------------------------
Year of Volumes Floor Fixed Price Current Price Fair Value
Type of Contract Maturity (mmcf) ($) Ceiling ($) ($) ($) ($000)
- ------------------------------------------------------------------------------------------------------------------------------------
Gas
Collars 2003 27,600 3.48 - 3.49 4.91 - 4.95 - 5.29 - 5.82 (22,760)
2004 64,100 3.75 - 4.50 5.05 - 7.00 - 4.87 - 5.92 (16,920)
Put Options - Short Natural Gas 2004 9,100 5.00 - - 5.66 - 5.92 4,228
Swaps/Futures - Short Natural Gas 2003 7,483 - - 3.19 - 3.89 4.35 - 5.82 (17,161)
Swaps/Futures - Long Natural Gas 2003 410 - - 3.22 - 5.72 5.41 - 5.48 1,215
2004 50 - - 5.11 - 5.13 4.87 - 4.89 (10)
- ------------------------------------------------------------------------------------------------------------------------------------
108,743 (51,408)
- ------------------------------------------------------------------------------------------------------------------------------------
63
- ------------------------------------------------------------------------------------------------------------------------
Year of Volumes Fixed Price Current Fair Value
Type of Contract Maturity (Barrels) ($) Price ($) ($000)
- ------------------------------------------------------------------------------------------------------------------------
Oil
Swaps - Short Fuel Oil 2003 30,000 29.70 28.50 - 30.52 (25)
Swaps - Long Fuel Oil 2003 66,195 20.60 - 30.88 29.15 - 31.99 253
2004 76,548 20.50 - 29.95 27.05 - 30.37 141
2005 9,000 24.65 - 26.28 26.60 - 26.85 17
- ------------------------------------------------------------------------------------------------------------------------
181,743 386
- ------------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------------------
Year of Fixed Margin/ Price Current Fair Value
Type of Contract Maturity MWh ($) Price ($) ($000)
- -------------------------------------------------------------------------------------------------------------------------------
Electricity
Swaps - Energy 2003 584,928 22.40 - 67.53 14.67 - 46.59 2,477
2004 308,000 14.00 - 26.50 13.13 - 24.04 774
- -------------------------------------------------------------------------------------------------------------------------------
892,928 3,251
- -------------------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------
2003
Change in Fair Value of Derivative Instruments ($000)
- ---------------------------------------------------------------------------------------------------
Fair value of contracts at January 1, $ (32,628)
Net losses on contracts realized 17,186
(Decrease) in fair value of all open contracts (32,329)
- ---------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at June 30, $ (47,771)
- ---------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------
Fair Value of Contracts
- -------------------------------------------------------------------------------------------------------
Maturity Maturity Total
Sources of Fair Value In 12 Months 2004 - 2005 Fair Value
- -------------------------------------------------------------------------------------------------------
Prices actively quoted $ (40,995) $ (2,292) $ (43,287)
Prices provided by external sources 427 2 429
Prices based on models and
other valuation methods (5,753) (2,765) (8,518)
Local published indicies 2,961 644 3,605
- -------------------------------------------------------------------------------------------------------
$ (43,360) $ (4,411) $ (47,771)
- -------------------------------------------------------------------------------------------------------
64
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 swap transactions for natural gas liquids. Such contracts are
executed by KeySpan Canada to: (i) 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 to counterparties.
These derivative financial instruments do not qualify for hedge accounting under
SFAS 133. At June 30, 2003, these instruments had a net fair market value of
$0.6 million, which was recorded on the Consolidated Balance Sheet. Based on the
non-hedge designation of these instruments, the gain was recognized in the
Consolidated Statement of Income.
Firm Gas Sales Derivative Instruments - Regulated Utilities: We use derivative
financial instruments to reduce the cash flow variability associated with the
purchase price for a portion of future natural gas purchases associated with our
Gas Distribution operations. 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 "Accounting for the Effects of Certain Types
of Regulation". 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 consistent with regulatory requirements.
The following table sets forth selected financial data associated with these
derivative financial instruments that were outstanding at June 30, 2003.
- -----------------------------------------------------------------------------------------------------------------------------------
Year of Volumes Fair Value
Type of Contract Maturity mmcf Floor $ Ceiling $ Fixed Price $ Current Price $ ($000)
- -----------------------------------------------------------------------------------------------------------------------------------
Options 2003 3,040 4.00 - 5.00 5.50 - 6.35 - - 72
2004 3,560 4.00 - 5.00 5.37 - 6.00 - - (87)
Swaps 2003 9,690 - - 5.09 - 6.23 5.36 - 5.90 46
2004 11,440 - - 4.42 - 6.23 4.52 - 5.83 99
- -----------------------------------------------------------------------------------------------------------------------------------
27,730 130
- -----------------------------------------------------------------------------------------------------------------------------------
Physically-Settled Commodity Derivative Instruments: 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, (SFAS 133") establishes criteria that must be satisfied in
order for option-type and forward contracts in electricity to be exempted as
normal purchases and sales, and 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 continuing review of our physical commodity
contracts, we determined that certain contracts for the physical purchase of
natural gas are not exempt as normal purchases from the requirements of SFAS
133. At June 30, 2003, the fair value of these contracts was $1.5 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: In May 2003, we entered into an interest
rate swap agreement in which we swapped $250 million of 7.25 % fixed rate debt
to floating rate debt. Under the terms of the agreements, we will receive the
fixed coupon rate associated with these bonds and pay our swap counterparties a
variable interest rate based on LIBOR, that is reset on a semi-annual basis.
These swaps are designated as fair-value hedges and qualify for "short-cut"
hedge accounting treatment under SFAS 133. During the second quarter of 2003, we
paid our counterparty an interest rate of 6.43%, and as a result, we realized
interest savings of $0.3 million for the quarter. The fair market value of this
derivative was $1.9 million at June 30, 2003.
65
During 2002, we had interest rate swap agreements in which we swapped
approximately $1.3 billion of fixed rate debt to floating rate debt. Under the
terms of the agreements, we received the fixed coupon rate associated with these
bonds and paid the swap counterparties 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. In 2002, we
terminated two of these interest rate swap agreements with an aggregate notional
amount of $1.0 billion. The remaining swap, which had a notional amount of
$270.0 million, was terminated on February 25, 2003. We received $18.4 million
from our swap counterparties as a result of the latter termination, of which
$8.1 million represented accrued swap interest. The difference between the
termination settlement amount and the amount of accrued interest, $10.3 million,
was 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 5 "Long-Term Debt", we called a portion of these promissory notes during
the first quarter of 2003.
Additionally, we had an interest rate swap agreement that hedged the cash flow
variability associated with the forecasted issuance of a series of commercial
paper offerings. This hedge expired in March 2003.
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 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 was required to make a payment of $40,000 per heating
degree day to its counterparties when actual weather experienced during the
November 2002 - March 2003 time frame was above 4,470 heating degree days, which
equates to approximately 1% colder than normal weather. With respect to
purchased put options, KeySpan would receive a $20,000 per heating degree day
payment from its counterparties when actual weather was below 4,150 heating
degree days, or approximately 7% warmer than normal. Based on the terms of such
contracts, we account for such instruments pursuant to the requirements of EITF
99-2, "Accounting for Weather Derivatives." In this regard, such instruments
were accounted for using the "intrinsic value method" as set forth in such
guidance. During the first quarter of 2003, weather was 10% colder than normal
and, as a result, $11.9 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
non-performance by a counterparty to a derivative contract, the desired impact
may not be achieved. The risk of counterparty non-performance is generally
considered credit risk and is actively managed by assessing each counterparty
credit profile and negotiating appropriate levels of collateral and credit
support.
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Item 4. Controls and Procedures
KeySpan maintains "disclosure controls and procedures", as such term is defined
under Exchange Act Rule 13a-15(e), that are designed to ensure that information
required to be disclosed by KeySpan in the reports it files or submits under the
Securities Exchange Act of 1934, as amended (the "Exchange Act"), is recorded,
processed, summarized and reported within the time periods specified in the
Securities and Exchange Commission's rules and forms, and that such information
is accumulated and communicated to KeySpan's management, including its Chief
Executive Officer and Chief Financial Officer, as appropriate to allow timely
decisions regarding required disclosure.
An evaluation of the effectiveness of KeySpan's disclosure controls and
procedures as of June 30, 2003 was conducted under the supervision and with the
participation of KeySpan's Chief Executive Officer and Chief Financial Officer.
Based on that evaluation, KeySpan's Chief Executive Officer and Chief Financial
Officer have concluded that KeySpan's disclosure controls and procedures were
adequate and designed to ensure that material information relating to KeySpan
and its consolidated subsidiaries would be made known to the Chief Executive
Officer and Chief Financial Officer by others within those entities,
particularly during the periods when periodic reports under the Exchange Act are
being prepared. Furthermore, there has been no change in KeySpan's internal
control over financial reporting, identified in connection with the evaluation
of such control, that occurred during KeySpan's last fiscal quarter that has
materially affected, or is reasonably likely to materially affect, KeySpan's
internal control over financial reporting. Refer to the Certifications by
KeySpan's Chief Executive Officer and Chief Financial Officer filed as exhibits
31.1 and 31.2 to this report
PART II. OTHER INFORMATION
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Item 1. Legal Proceedings
See Note 8 to the Consolidated Financial Statements "Financial Guarantees and
Contingencies."
Item 4. Submission of Matters to a Vote of Security Holders
We held our annual meeting of shareholders on May 8, 2003, at 10:00 a.m. Eastern
Time, at KeySpan's Auditorium located at our corporate headquarters at One
MetroTech Center, Brooklyn, New York to consider and take action on the
following items:
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1. Election of nine directors
The names of the persons who received a plurality of the votes cast by the
holders of shares entitled to vote thereon, and who were accordingly elected
Directors of KeySpan for a one year term or until their successors are duly
elected or chosen and qualified are as follows:
VOTES VOTES TOTAL
DIRECTOR FOR WITHHELD VOTES
Robert B. Catell 126,352,675 4,017,053 130,369,728
Andrea S. Christensen 126,524,919 3,844,809 130,369,728
Alan H. Fishman 126,383,916 3,985,812 130,369,728
J. Atwood Ives 127,466,357 2,903,371 130,369,728
James R. Jones 127,478,203 2,891,525 130,369,728
James L. Larocca 126,489,274 3,880,454 130,369,728
Stephen W. McKessy 126,496,857 3,872,871 130,369,728
Edward D. Miller 127,449,023 2,920,705 130,369,728
Edward Travaglianti 126,539,358 3,830,370 130,369,728
2. Ratification of Deloitte & Touche LLP, as independent public accountants
for the Company for the year ending December 31, 2003
Deloitte & Touche LLP received a majority of the votes cast by the holders of
shares entitled to vote thereon, and was accordingly ratified Independent Public
Accountants of KeySpan for the fiscal year ending December 31, 2003.
DELOITTE & TOUCHE LLP VOTES CAST
FOR 125,225,051
AGAINST 3,731,132
ABSTAIN 1,413,545
TOTAL 130,369,728
3. Approval of amendments to the Employee Discount Stock Purchase Plan
The management proposal to amend the Employee Discount Stock Purchase Plan
received a majority of the votes cast by the holders of shares entitled to vote
thereon, and was accordingly approved.
EMPLOYEE DISCOUNT
STOCK PURCHASE PLAN VOTES CAST
FOR 123,314,234
AGAINST 4,966,173
ABSTAIN 2,089,321
TOTAL 130,369,728
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4. Consideration of a shareholder proposal on Shareholder Rights Plans
The shareholder proposal on Shareholder Rights received a majority of the votes
cast by the holders of shares entitled to vote thereon, and was accordingly
approved.
SHAREHOLDER
PROPOSAL VOTES CAST
FOR 52,650,885
AGAINST 47,400,706
NON-VOTES 26,648,178
ABSTAIN 3,669,959
TOTAL 130,369,728
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
3.1* Amended Bylaws dated as of June 25, 2003
4.1* Credit Agreement among KeySpan Corporation, the several Lenders, ABN AMRO
Bank, N.V., as Syndication Agent, Bank One, N. A. and Wachovia Bank, N.A,
as Co-Documentation Agents, and J.P. Morgan Chase Bank, as Administrative
Agent for $450 million, dated as of June 27, 2003.
4.2* Credit Agreement among KeySpan Corporation, the several Lenders, Citibank
N.A., as Syndication Agent, 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 $850 million, dated as of June 27, 2003.
31.1*Certification of the Chairman and Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*Certification of the Executive Vice President and Chief Financial Officer
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*Certification of the Chairman and Chief Executive Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*Certification of the Executive Vice President and Chief Financial Officer
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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(b) Reports on Form 8-K
In our report on Form 8-K dated April 4, 2003, we disclosed that we had issued
$150 million 4.650% Notes due 2013 and $150 million 5.875% Notes due 2033.
In our report on Form 8-K dated May 1, 2003, we reported that KeySpan had issued
a press release concerning, among other things, its financial results for the
quarter ended March 31, 2003 and that KeySpan was hosting an earnings conference
call at 2:30 p.m. EDT on May 1, 2003 to discuss the financial results for the
first quarter.
In our report on Form 8-K dated May 5, 2003, we reported that we were giving a
series of presentations on KeySpan at the American Gas Association ("AGA")
Financial Forum.
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*Filed Herewith
70
KEYSPAN CORPORATION AND SUBSIDIARIES
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on behalf of the undersigned
there unto duly authorized.
KEYSPAN CORPORATION
-------------------
(Registrant)
Date: August 6, 2003 /s/ Gerald Luterman
-----------------------------
Gerald Luterman
Executive Vice President and
Chief Financial Officer
Date: August 6, 2003 /s/ Joseph Bodanza
---------------------------
Joseph Bodanza
Senior Vice President
and Chief Accounting Officer
71