UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 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 October 15, 2003
--------------------- -------------------------------
$.01 par value 159,060,100
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 -
September 30, 2003 and December 31, 2002 3
Consolidated Statement of Income -
Three and Nine months Ended September 30, 2003 and 2002 5
Consolidated Statement of Cash Flows -
Nine months Ended September 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 35
Item 3. Quantitative and Qualitative Disclosures
About Market Risk 68
Item 4. Controls and Procedures 73
Part II. OTHER INFORMATION
Item 1. Legal Proceedings 73
Item 6. Exhibits and Reports on Form 8-K 73
Signatures 75
2
CONSOLIDATED BALANCE SHEET
(Unaudited)
- -----------------------------------------------------------------------------------------
(In Thousands of Dollars) September 30, 2003 December 31, 2002
- -----------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash and temporary cash investments $ 118,051 $ 170,617
Accounts receivable 1,000,534 1,122,022
Unbilled revenue 227,554 473,060
Allowance for uncollectible accounts (70,306) (63,029)
Gas in storage, at average cost 522,736 297,060
Material and supplies, at average cost 120,655 113,519
Other 88,370 93,980
---------------------------------------------
2,007,594 2,207,229
---------------------------------------------
Investments and Other 292,587 265,977
Property
Gas 6,397,706 6,124,281
Electric 2,155,736 1,974,352
Other 400,953 394,374
Accumulated depreciation (2,941,551) (2,740,516)
Gas exploration and production, at cost 2,788,884 2,438,998
Accumulated depletion (1,108,826) (973,889)
---------------------------------------------
7,692,902 7,217,600
---------------------------------------------
Deferred Charges
Regulatory assets 475,748 438,516
Goodwill, net of amortization 1,816,434 1,789,751
Other 714,783 695,233
---------------------------------------------
3,006,965 2,923,500
---------------------------------------------
Total Assets $ 13,000,048 $ 12,614,306
=============================================
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See accompanying Notes to the Consolidated Financial Statements.
3
CONSOLIDATED BALANCE SHEET
(Unaudited)
- --------------------------------------------------------------------------------------------
(In Thousands of Dollars) September 30, 2003 December 31, 2002
- --------------------------------------------------------------------------------------------
LIABILITIES AND CAPITALIZATION
Current Liabilities
Current redemption of long-term debt $ 11,417 $ 11,413
Accounts payable and other liabilities 893,045 1,061,649
Commercial paper 644,400 915,697
Dividends payable 72,162 64,714
Taxes accrued 139,749 51,276
Customer deposits 39,529 38,387
Interest accrued 99,254 77,092
--------------------------------------------
1,899,556 2,220,228
--------------------------------------------
Deferred Credits and Other Liabilities
Regulatory liabilities 102,582 84,479
Deferred income tax 976,358 877,013
Postretirement benefits and other reserves 795,437 759,731
Other 164,202 189,912
--------------------------------------------
2,038,579 1,911,135
--------------------------------------------
Commitments and Contingencies (See Note 8) - -
Capitalization
Common stock 3,482,456 3,005,354
Retained earnings 557,121 522,835
Other comprehensive income (68,101) (108,423)
Treasury stock (398,190) (475,174)
--------------------------------------------
Total common shareholders' equity 3,573,286 2,944,592
Preferred stock 83,697 83,849
Long-term debt 4,927,423 5,224,081
--------------------------------------------
Total Capitalization 8,584,406 8,252,522
--------------------------------------------
Minority Interest in Subsidiary Companies 477,507 230,421
--------------------------------------------
Total Liabilities and Capitalization $ 13,000,048 $ 12,614,306
============================================
- --------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
4
CONSOLIDATED STATEMENT OF INCOME
(Unaudited)
- ------------------------------------------------------------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
(In Thousands of Dollars, Except Per Share Amounts) 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Revenues
Gas Distribution $ 405,777 $ 334,031 $ 2,970,514 $ 2,078,823
Electric Services 427,662 414,868 1,132,647 1,084,309
Energy Services 148,876 217,104 495,269 687,975
Gas Exploration and Production 123,052 88,600 373,774 256,089
Energy Investments 26,447 23,599 80,287 62,784
---------------------------------------------------------------------
Total Revenues 1,131,814 1,078,202 5,052,491 4,169,980
---------------------------------------------------------------------
Operating Expenses
Purchased gas for resale 173,116 134,853 1,793,581 1,034,153
Fuel and purchased power 132,649 144,259 332,647 326,327
Operations and maintenance 507,381 487,293 1,515,206 1,538,073
Depreciation, depletion and amortization 135,656 127,301 422,917 380,758
Operating taxes 91,790 89,103 311,754 282,663
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Total Operating Expenses 1,040,592 982,809 4,376,105 3,561,974
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Income from Equity Investments 2,727 2,299 12,486 9,713
Operating Income 93,949 97,692 688,872 617,719
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Other Income and (Deductions)
Interest charges (78,366) (79,937) (226,503) (222,594)
Loss on sale of subsidiary stock - - (11,325) -
Cost of debt redemption - - (24,094) -
Minority interest (19,894) (5,353) (50,252) (15,920)
Other 24,299 (3,549) 38,754 15,143
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Total Other Income and (Deductions) (73,961) (88,839) (273,420) (223,371)
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Earnings Before Income Taxes 19,988 8,853 415,452 394,348
Income Taxes
Current (39,317) (34,508) 94,275 (97,430)
Deferred 46,720 38,397 71,439 243,011
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Total Income Taxes 7,403 3,889 165,714 145,581
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Earnings from Continuing Operations 12,585 4,964 249,738 248,767
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Discontinued Operations
Income from Operations, net of tax - - - -
Loss on Disposal , net of tax of $13,050 - - - (19,662)
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Loss from Discontinued Operations - - - (19,662)
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Cummulative Effect of Change in Accounting Principle - - 174 -
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Net Income 12,585 4,964 249,912 229,105
Preferred stock dividend requirements 1,461 1,335 4,383 4,287
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Earnings for Common Stock $ 11,124 $ 3,629 $ 245,529 $ 224,818
=====================================================================
Basic Earnings Per Share From:
Continuing Operations, less preferred dividends $ 0.07 $ 0.03 $ 1.56 $ 1.74
Discontinued Operations - - - (0.14)
Change in Accounting Principle - - - -
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Basic Earnings Per Share $ 0.07 $ 0.03 $ 1.56 $ 1.60
=====================================================================
Diluted Earnings Per Share From:
Continuing Operations, less preferred dividends $ 0.07 $ 0.02 $ 1.55 $ 1.72
Discontinued Operations - - - (0.14)
Change in Accounting Principle - - - -
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Diluted Earnings Per Share $ 0.07 $ 0.02 $ 1.55 $ 1.58
=====================================================================
Average Common Shares Outstanding (000) 158,783 141,686 157,871 140,929
Average Common Shares Outstanding - Diluted (000) 159,539 142,359 158,670 141,760
- ------------------------------------------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
5
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
- ------------------------------------------------------------------------------------------
Nine Months Ended September 30,
(In Thousands of Dollars) 2003 2002
- ------------------------------------------------------------------------------------------
Operating Activities
Net income $ 249,912 $ 229,105
Adjustments to reconcile net income to net
cash provided by (used in) operating activities
Depreciation, depletion and amortization 422,917 380,758
Deferred income tax 71,439 60,495
Income from equity investments (12,486) (9,713)
Dividends from equity investments 1,021 1,777
Amortization of interest rate swap (7,396) -
Loss on disposal of subsidiary investments 11,325 -
Gain on sale of property (13,974) -
Minority interest in income of subsidiaries 50,252 15,920
Changes in assets and liabilities
Accounts receivable 384,836 239,569
Materials and supplies, fuel oil and gas in storage (239,847) 18,297
Accounts payable and other liabilities (110,866) (170,526)
Interest accrued 22,161 20,573
Pension/OPEB funding (125,385) (40,294)
Other 33,154 9,360
-----------------------------------
Net Cash Provided by Operating Activities 737,063 755,321
-----------------------------------
Investing Activities
Construction expenditures (720,217) (815,155)
Other investment (50,500) -
Proceeds from sale of property 13,974 -
Proceeds from sale of subsidiary investments 198,553 173,935
-----------------------------------
Net Cash Used in Investing Activities (558,190) (641,220)
-----------------------------------
Financing Activities
Treasury stock issued 76,984 67,308
Equity issuance 473,573 -
Issuance of long-term debt 710,475 515,774
Payment of long-term debt (564,506) (91,152)
Payment of commercial paper (271,297) (519,222)
Redemption of promissory notes (447,005) -
Redemption of preferred stock (14,293) -
Preferred stock dividends paid (4,383) (4,287)
Common stock dividends paid (203,795) (187,857)
Other 12,808 9
-----------------------------------
Net Cash Used in Financing Activities (231,439) (219,427)
-----------------------------------
Net Increase in Cash and Cash Equivalents $ (52,566) $ (105,326)
Cash and Cash Equivalents at Beginning of Period 170,617 159,252
-----------------------------------
Cash and Cash Equivalents at End of Period $ 118,051 $ 53,926
===================================
- ------------------------------------------------------------------------------------------
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 September 30, 2003, and the results of operations for the three and nine
months ended September 30, 2003 and September 30, 2002, as well as cash flows
for the nine months ended September 30, 2003 and September 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
and June 30, 2003 Quarterly Reports on Form 10-Q. 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 September
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 and nine months ended September 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:
- ------------------------------------------------------------------------------------------------------------------------------
Three Months Ended September 30, Nine Months Ended September 30,
(In Thousands of Dollars, Except Per Share Amounts) 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Earnings for common stock $ 11,124 $ 3,629 $ 245,529 $ 224,818
Houston Exploration dilution (74) (96) (212) (321)
- ------------------------------------------------------------------------------------------------------------------------------
Earnings for common stock - adjusted $ 11,050 $ 3,533 $ 245,317 $ 224,497
- ------------------------------------------------------------------------------------------------------------------------------
Weighted average shares outstanding (000) 158,783 141,686 157,871 140,929
Add dilutive securities:
Options 756 673 799 831
- ------------------------------------------------------------------------------------------------------------------------------
Total weighted average shares outstanding - assuming dilution 159,539 142,359 158,670 141,760
- ------------------------------------------------------------------------------------------------------------------------------
Basic earnings per share $ 0.07 $ 0.03 $ 1.56 $ 1.60
- ------------------------------------------------------------------------------------------------------------------------------
Diluted earnings per share $ 0.07 $ 0.02 $ 1.55 $ 1.58
- ------------------------------------------------------------------------------------------------------------------------------
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 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.
During the third quarter of 2003, KeySpan Services, Inc. and its wholly-owned
subsidiary Paulus, Sokolowski, and Sartor, LLC. acquired Bard, Rao + Athanas
Consulting Engineers, LLC. ("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 was 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 following the closing of the
acquisition. We have recorded goodwill of $26 million and intangible assets of
$2 million associated with this transaction. The intangible assets, which relate
primarily to a portion of the backlog purchased, as well as to non-compete
agreements entered into with all of the former owners of BR+A, will be amortized
over two and three years, respectively. We are currently in the process of
evaluating the fair market value of the assets acquired and may adjust the
recorded goodwill and intangible assets in the fourth quarter of 2003. In May
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 plans to
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, which is reflected in Other Income and (Deductions) in the
Consolidated Statement of Income. Income taxes were not provided, since this
transaction was structured as a return of capital.
9
On October 15, 2003, Houston Exploration acquired the entire Gulf of Mexico
shallow-water asset base of Transworld Exploration and Production, Inc for $149
million. The properties, which are 75% natural gas, have proven reserves of 92
billion cubic feet of natural gas equivalent. Current production is from 11
fields and is producing approximately 35 million cubic feet of natural gas
equivalent per day. Houston Exploration funded the transaction from its bank
revolver and with cash on hand at the time of closing. Consistent with past
acquisitions, Houston Exploration has derivative hedge positions in place for a
portion of the 2004 production.
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.
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. In May 2003,
we sold a portion of our interest in KeySpan Canada through the establishment of
an open-ended income fund trust ("KeySpan Facilities Income Fund" or 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.
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. Except as noted above, at September 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:
10
- ----------------------------------------------------------------------------------------------------------------------------------
Energy Investments
-----------------------------
Gas Electric Energy Gas Exploration Other
(InThousands of Dollars) Distribution Services Services and Production Investments Eliminations Consolidated
- ----------------------------------------------------------------------------------------------------------------------------------
Three Months Ended Sept. 30, 2003
Unaffiliated revenue 405,777 427,662 148,876 123,052 26,447 - 1,131,814
Intersegment revenue - 25 1,926 - 1,252 (3,203) -
Operating Income (Loss) (39,108) 100,254 (13,627) 50,995 8,009 (12,574) 93,949
Three Months Ended Sept. 30, 2002
Unaffiliated revenue 334,031 414,868 217,104 88,600 23,599 - 1,078,202
Intersegment revenue - 25 - - 194 (219) -
Operating Income (Loss) (39,565) 106,611 (4,834) 26,354 10,526 (1,400) 97,692
- ----------------------------------------------------------------------------------------------------------------------------------
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 September 30, 2003 and
2002 represent approximately 38% of our consolidated revenues for both periods.
- -----------------------------------------------------------------------------------------------------------------------------------
Energy Investments
-------------------------------
Gas Electric Energy Gas Exploration Other
(InThousands of Dollars) Distribution Services Services and Production Investments Eliminations Consolidated
- -----------------------------------------------------------------------------------------------------------------------------------
Nine Months Ended Sept. 30, 2003
Unaffiliated revenue 2,970,514 1,132,647 495,269 373,774 80,287 - 5,052,491
Intersegment revenue - 76 4,894 - 3,756 (8,726) -
Operating Income (Loss) 357,445 191,404 (32,647) 156,733 27,207 (11,270) 688,872
Nine Months Ended Sept. 30, 2002
Unaffiliated revenue 2,078,823 1,084,309 687,975 256,089 62,784 - 4,169,980
Intersegment revenue - 75 - - 582 (657) -
Operating Income (Loss) 321,551 227,613 (25,056) 75,633 15,081 2,897 617,719
- -----------------------------------------------------------------------------------------------------------------------------------
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 nine months ended September 30, 2003 and
2002 represent approximately 22% and 26% of our consolidated revenues,
respectively.
11
3. COMPREHENSIVE INCOME
The table below indicates the components of comprehensive income.
- ------------------------------------------------------------------------------------------------------------------------------------
Three Months Ended Sept. 30, Nine Months Ended Sept. 30,
(In Thousands of Dollars) 2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------------
Earnings for common stock $ 11,124 $ 3,629 $ 245,529 $ 224,818
- -----------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax
Reclassification adjustments for loss (gains) realized in net income 8,431 (7,529) 19,602 (17,814)
Foreign currency translation adjustments 366 (2,313) 27,892 6,804
Unrealized gains (losses) on marketable securities 1,209 (4,027) 3,458 (8,263)
Accrued unfunded pension obligation - - - (1,132)
Premiums on derivative financial instruments - - (3,437) -
Unrealized gains (losses) on derivative financial instruments 13,740 (641) (7,193) (26,585)
- -----------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax 23,746 (14,510) 40,322 (46,990)
- -----------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income (Loss) $ 34,870 $ (10,881) $ 285,851 $ 177,828
- -----------------------------------------------------------------------------------------------------------------------------------
Related tax (benefit) expense
Reclassification adjustments for loss (gains) realized in net income $ 4,540 $ (4,054) $ 10,555 $ (9,592)
Foreign currency translation adjustments 197 (1,245) 15,019 3,663
Unrealized gains (losses) on marketable securities 652 (2,168) 1,863 (4,449)
Accrued unfunded pension obligation - - - (610)
Premiums on derivative financial instruments - - (1,851) -
Unrealized gains (losses) on derivative financial instruments 7,398 (346) (3,873) (14,316)
- -----------------------------------------------------------------------------------------------------------------------------------
Total Tax (Benefit) Expense $ 12,787 $ (7,813) $ 21,713 $ (25,304)
- -----------------------------------------------------------------------------------------------------------------------------------
4. CAPITAL AND PREFERRED STOCK
In September 2003, the Boston Gas Company redeemed all 562,700 shares of its
outstanding Variable Term Cumulative Preferred Stock, 6.42 % Series A at its par
value of $25 per share. The total payment was $14.3 million which included $0.2
million of accumulated dividends. This preferred stock series had been reflected
as Minority Interest on KeySpan's Consolidated Balance Sheet.
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
During the third quarter of 2003, KeySpan Canada, issued Cdn$125 million, or
approximately US$93 million, long-term secured notes in a private placement to
investors in Canada and the United States. The notes were issued in the
following three series: (i) Cdn$20 million 5.42% senior secured notes due 2008;
(ii) Cdn$52.5 million 5.79% senior secured notes due 2010; and (iii) Cdn$52.5
million 6.16% senior secured notes due 2013. The proceeds of the offering have
been used to re-pay KeySpan Canada's credit facility.
12
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 allowed KeySpan Canada to borrow
up to approximately $125 million. As a result of the above long-term debt
issuance, one tranch of the credit facility was discontinued. Therefore, at
September 30, 2003, KeySpan Canada's credit facility has the following two
tranches with the following maturities: (i) $37.5 million matures in 364 days;
and (ii) $37.5 million matures in two years.
In June 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 that ranges from eight to twenty five
basis points on the 364-day facility and ten to thirty basis points 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. 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%, plus a margin. Competitive bid loans are based on bid results requested by
KeySpan from the lenders. The margins on both facilities are ratings based and
range from zero basis points to 112.5 basis points. The margins are increased if
outstanding loans are in excess of 33% of the total facility. 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.
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
amounts associated with Houston Exploration's bank revolving credit facility.
13
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 has 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 have nearly 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.
Houston Exploration has utilized collars and purchased 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
September 30, 2003, Houston Exploration has hedged slightly less than 70% of its
estimated 2003 gas production and a similar amount of its 2004 gas production.
Houston Exploration used standard New York Mercantile Exchange ("NYMEX") futures
prices to value its swap positions, 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 $10.5
million, or $6.8 million after-tax.
14
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 for 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 for 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 forecasted purchases of
natural gas and fuel oil is through September 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 $0.2 million, or $0.1
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 2003. The estimated amount
of gains or 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 September 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, as well as forecasted sales of
Unforced Capacity ("UCAP") to the NYISO. The maximum length of time over which
we have hedged cash flow variability is through December 2004. We used NYMEX
day-ahead forward pricing, as well as published NYISO day-ahead award prices to
value these outstanding derivatives. The estimated amount of losses associated
with such derivative instruments that are reported in Other Comprehensive Income
and that are expected to be reclassified into earnings over the next twelve
months is $1.3 million, or $0.8 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 $0.4 million, or $0.3 million after-tax.
15
The following tables set forth selected financial data associated with these
derivative financial instruments noted above that were outstanding at September
30, 2003.
- -----------------------------------------------------------------------------------------------------------------------------------
Year of Volumes Floor Ceiling Fixed Price Current Price Fair Value
Type of Contract Maturity (mmcf) ($) ($) ($) ($) ($000)
- -----------------------------------------------------------------------------------------------------------------------------------
Gas
Collars 2003 13,800 3.48 4.91 - 4.43 - 5.08 (4,085)
2004 64,100 3.50 - 4.50 4.75 - 7.00 - 4.70 - 5.26 (7,757)
Put Options - Short Natural Gas 2004 9,100 5.00 - - 5.11 - 5.26 4,228
Swaps/Futures - Short Natural Gas 2003 3,711 - - 3.19 4.43 - 5.08 (5,842)
2004 14,640 - - 4.96 4.76 - 5.26 1,152
Swaps/Futures - Long Natural Gas 2004 50 - - 5.11 - 5.14 4.71 - 4.72 (25)
2005 10 - - 4.95 4.46 (5)
- -----------------------------------------------------------------------------------------------------------------------------------
105,411 (12,334)
- -----------------------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------
Year of Volumes Fixed Price Current Price Fair Value
Type of Contract Maturity (Barrels) ($) ($) ($000)
- -----------------------------------------------------------------------------------------------------------------
Oil
Swaps - Long Fuel Oil 2003 55,367 20.60 - 30.07 28.54 - 29.80 204
2004 100,548 20.55 - 29.60 25.88 - 28.61 37
2005 28,000 24.65 - 27.25 25.25 - 25.59 (31)
- -----------------------------------------------------------------------------------------------------------------
183,915 210
- -----------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------
Year of Fixed Price Current Price Fair Value
Type of Contract Maturity Capacity MWh ($) ($) ($000)
- ------------------------------------------------------------------------------------------------------------------------------
Electricity
Swaps - Energy 2003 222,464 15.00 - 67.44 15.90 - 42.98 (613)
2004 340,800 14.00 - 26.50 17.15 - 41.96 (953)
Swaps - Capacity 2003 100 - 7.00 6.98 2
2004 200 - 7.00 6.98 4
- ------------------------------------------------------------------------------------------------------------------------------
300 563,264 (1,560)
- ------------------------------------------------------------------------------------------------------------------------------
16
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, "Accounting for Derivative Instruments and Hedging Activities." At
September 30, 2003, these instruments had a net fair market value of $1.3
million, which was recorded on the Consolidated Balance Sheet. Based on the
non-hedge designation of these instruments, the gain was recognized in the
Consolidated Statement of Income.
Firm Gas Sales Derivative Instruments - Regulated Utilities: We use derivative
financial instruments to reduce the cash flow variability associated with the
purchase price for a portion of future natural gas purchases associated with our
Gas Distribution operations. Our strategy is to minimize fluctuations in firm
gas sales prices to our regulated firm gas sales customers in our New York and
New Hampshire service territories. Since these derivative instruments are
employed to reduce the variability of the purchase price of natural gas to be
sold to regulated firm gas sales customers, the accounting for these derivative
instruments is subject to SFAS 71 "Accounting for the Effects of Certain Types
of Regulation". Therefore, changes in the market value of these derivatives have
been recorded as a Regulatory Asset or Regulatory Liability on the Consolidated
Balance Sheet. Gains or losses on the settlement of these contracts are
initially deferred and then refunded to or collected from our firm gas sales
customers consistent with regulatory requirements.
The following table sets forth selected financial data associated with these
derivative financial instruments that were outstanding at September 30, 2003.
- ----------------------------------------------------------------------------------------------------------------------------------
Year of Volumes Floor Ceiling Fixed Price Current Price Fair Value
Type of Contract Maturity mmcf ($) ($) ($) ($) ($000)
- ----------------------------------------------------------------------------------------------------------------------------------
Options 2003 2,650 4.00 - 5.00 5.15 - 6.00 - 4.90 - 5.13 (712)
2004 7,420 4.00 - 5.00 5.15 - 6.00 - 4.83 - 5.25 (411)
Swaps 2003 10,710 - - 5.00 - 6.23 4.90 - 5.13 (5,304)
2004 20,530 - - 4.42 - 6.23 4.83 - 5.25 (6,848)
- ----------------------------------------------------------------------------------------------------------------------------------
41,310 (13,275)
- ----------------------------------------------------------------------------------------------------------------------------------
Physically-Settled Commodity Derivative Instruments: Derivative Implementation
Group ("DIG") Issue C15 and C16 of SFAS 133, 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
17
that combine a forward contract and a purchased option contract. Based upon a
continuing review of our physical gas and electric commodity contracts, we
determined that certain contracts for the physical purchase of natural gas
associated with our regulated gas utilities are not exempt as normal purchases
from the requirements of SFAS 133. At September 30, 2003, the fair value of
these contracts was $2.8 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 interest rate
swap agreements 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 period ended September 30,
2003, we paid our counterparty an interest rate of 6.42%, and as a result, we
realized interest savings of $0.4 million. The fair market value of this
derivative was $1.4 million at September 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
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
18
purchased put options, KeySpan would have received 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.
In October 2003, we entered into heating-degree day call and put options to
mitigate the effect of fluctuations from normal weather on KEDNE's financial
position and cash flows for the 2003/2004 winter heating season - November 2003
through March 2004. With respect to sold call options, KeySpan will be required
to make a payment of $27,500 per heating degree day to its counterparties when
actual weather experienced during this time frame is above 4,440 heating degree
days, which equates to approximately 2% colder than normal weather, based on the
most recent 20-year average for normal weather. The maximum amount KeySpan may
be required to pay on its sold call options is $5.5 million. With respect to
purchased put options, KeySpan will receive a $27,500 per heating degree day
payment from its counterparties when actual weather is below 4,266 heating
degree days, or approximately 2% warmer than normal. The maximum amount KeySpan
may receive on its purchased put options is $11 million. The total premium cost
for these options was $0.4 million. We will account for these derivatives
pursuant to the requirements of EITF 99-2.
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 a 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, 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 September 30, 2003, the present value of our future asset retirement
obligation ("ARO") was approximately $65 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 $0.2 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,
19
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 September 30, 2003, KeySpan had costs recovered
in excess of costs incurred totaling $458 million.
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 original provisions of FIN 46 were to be applied for the
first interim or annual period beginning after June 15, 2003. However, in
October 2003, the FASB delayed implementation of FIN 46 until the fourth quarter
of 2003. We currently have an arrangement with a variable interest entity
through which we lease a portion of the Ravenswood facility. (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. The implementation of this Statement will not 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
20
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 did not have an impact on our results of operations, financial
condition or cash flows.
In July 2003, the Financial Accounting Standards Board ("FASB") concluded its
discussions on Emerging Issues Task Force ("EITF") 03-11 "Reporting Realized
Gains and Losses on Derivative Instruments That Are Subject to FASB Statement
No. 133 Accounting for Derivative Instruments and Hedging Activities and Not
Held for Trading Purposes as Defined in EITF Issue No. 02-3 Issues Involved in
Accounting for Derivative Contracts held for Trading Purposes and Contracts
Involved in Energy Trading and Risk Management Activities." The Task Force
reached a consensus that determining whether realized gains or losses on
physically settled derivative contracts not "held for trading purposes" should
be reported in the income statement on a gross or net basis is a matter of
judgment that depends on the relevant facts and circumstances. KeySpan reports
realized gains or losses on its derivative instruments that hedge the cash flow
variability associated with the forecasted sales of natural gas and electricity
in its reported revenues at time of their settlement. Realized gains or losses
on derivative instruments that hedge the cash flow variability associated with
the forecasted purchase of natural gas or fuel oil are reported in operating
expense. While we will continue to evaluate the provisions of EITF 03-11, we
believe that this EITF will not have a significant impact on our results of
operations, financial condition or cash flows.
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 the Department of
Environmental Conservation ("DEC") for inclusion on appropriate site inventories
and for 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 $124.6 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 $67.2 million. The KEDNY and
KEDLI rate plans generally provide for the recovery of MGP related investigation
and remediation costs as costs are incurred. A regulatory asset of $142.6
21
million for the New York/Long Island MGP sites is reflected at September 30,
2003. In accordance with NYPSC policy, KeySpan records a reduction to regulatory
liabilities as costs are incurred for environmental clean-up activities. At
September 30, 2003, these previously deferred ratepayer benefits totaled $42.8
million. In October 2003, KEDNY and KEDLI filed a joint petition with the NYPSC
seeking rate treatment for additional environmental costs that may be incurred
in the future. 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 $3.5 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.
We may have or share responsibility under applicable environmental laws for the
remediation of 10 MGP sites and related facilities associated with the
historical operations of EnergyNorth Natural Gas, Inc. ("EnergyNorth").
EnergyNorth has received notice of its potential responsibility for
contamination at two former MGP sites and, together with other potentially
responsible parties, has received notice of potential responsibility for
contamination associated with four other sites.
We presently estimate the remaining cost of all the New England MGP-related
environmental cleanup activities will be $45.2 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 $18.8 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 $54.3
million for the KEDNE MGP sites is reflected at September 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.
22
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 $37.8 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 $5.1 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
continually evaluate our recorded liability for clean-up activities and as
circumstances arise we may revise our reserves accordingly. 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.
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, KeySpan's
Quarterly Reports on Form 10-Q for the periods ended March 31, 2003 and June 30,
2003 and KeySpan's Current Report on Form 8-K dated October 15, 2003, 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.
23
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. As previously disclosed, in March 2003, a
jury rendered a verdict against our subsidiary, KeySpan Generation LLC ("KeySpan
Generation"), and other defendants in the amount of $47 million in a proceeding
filed by a plaintiff claiming injury from asbestos exposure at generating
facilities formerly owned by the Long Island Lighting Company ("LILCO") and
others. In October 2003, KeySpan Generation agreed to pay $400,000 to resolve
this matter and a stipulation discontinuing this lawsuit has been filed with the
court.
24
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 is unable to determine the outcome of the other outstanding asbestos
proceedings, but does not believe that such outcomes, 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 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, which was modified in September 2003, (i) certain
obligations between the parties have been modified and clarified, (ii) certain
contracts were awarded to Hawkeye, (iii) certain credit and bonding support made
available by KeySpan to Hawkeye will be curtailed and ultimately terminated and
(iv) in addition to a short-term bridge loan of $21 million in June 2003,
KeySpan will provide a fully secured, interest bearing loan of up to $55 million
in the aggregate, to finance a power plant that has been constructed by a
Hawkeye affiliate. In October 2003, KeySpan and Hawkeye closed on the $55
million long-term loan and the $21 million short-term bridge loan was paid in
full.
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
September 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:
25
- ----------------------------------------------------------------------------------------------------------
Amount of Expiration
Nature of Guarantee (In Thousands of Dollars) Exposure Dates
- ----------------------------------------------------------------------------------------------------------
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) 73,842 2005
Letters of Credit (v) 64,822 2003
- ----------------------------------------------------------------------------------------------------------
Surety Bonds (vi) 11,540 Revolving
Third Party Line of Credit (vi) 25,000 2004
- ----------------------------------------------------------------------------------------------------------
$ 1,375,272
- ----------------------------------------------------------------------------------------------------------
The following is a description of KeySpan's outstanding guarantees of the
obligations of its subsidiaries:
(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.
(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 were still
outstanding as of September 30, 2003.
26
(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 of 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 of the
obligations of non-affiliates:
(vi) At September 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 has been terminated. Further, we are no longer required to provide
support for Hawkeye's surety bonds. (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 June
1999 for approximately $597 million. In order to reduce the initial cash
requirements, we entered into the Master Lease with a variable interest,
unaffiliated financing entity that acquired a portion of the facility, 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.
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.
27
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. 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. In accordance with a recent FASB announcement,
implementation of FIN 46 is now scheduled for the fourth quarter of 2003.
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. At December 31,
2003, KeySpan will be deemed to have owned and depreciated the asset from
inception, or for approximately 4.5 years. Therefore, assuming a 35-year
economic life, it is anticipated that an after-tax charge of $34 million, or
$0.22 per share, will be recorded as a change in accounting principle on the
Consolidated Statement of Income. Upon implementation of FIN 46, therefore, we
anticipate recording an asset of approximately $362 million and debt of $412.3
million.
If the 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.
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.
28
During 2002, KeySpan announced its 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 Nine Months Ended
September 30, September 30,
(In Thousands of Dollars, Except Per Share Amounts) 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------------
Earnings available for common stock: $ 11,124 $ 3,629 $ 245,529 $ 224,818
As reported
Add: recorded stock-based compensation expense, net of tax 868 78 3,132 144
Deduct: total stock-based compensation expense, net of tax (2,707) (1,887) (9,043) (5,661)
- ------------------------------------------------------------------------------------------------------------------------------------
Pro-forma earnings $ 9,285 $ 1,820 $ 239,618 $ 219,301
- ------------------------------------------------------------------------------------------------------------------------------------
Earnings per share:
Basic - as reported $ 0.07 $ 0.03 $ 1.56 $ 1.60
Basic - pro-forma $ 0.06 $ 0.01 $ 1.52 $ 1.56
Diluted - as reported $ 0.07 $ 0.02 $ 1.55 $ 1.58
Diluted - pro-forma $ 0.06 $ 0.01 $ 1.51 $ 1.55
- ------------------------------------------------------------------------------------------------------------------------------------
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 September 30, 2002
disclosures have been revised to separately present our other subsidiaries.
29
- ---------------------------------------------------------------------------------------------------------------------------------
Statement of Income
- ---------------------------------------------------------------------------------------------------------------------------------
Three Months Ended September 30, 2003
(In Thousands of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- ---------------------------------------------------------------------------------------------------------------------------------
Revenues $ 185 $ 99,170 $ 1,032,644 $ (185) $ 1,131,814
Operating Expenses
Purchased gas - 37,038 136,078 - 173,116
Fuel and purchased power - - 132,649 - 132,649
Operations and maintenance 6,742 33,457 467,182 - 507,381
Intercompany expense 5,142 310 (310) (5,142) -
Depreciation and amortization (13) 13,519 122,150 - 135,656
Operating taxes 1,824 16,557 73,409 - 91,790
-------------------------------------------------------------------------------------------
Total Operating Expenses 13,695 100,881 931,158 (5,142) 1,040,592
Income from Equity Investments - - 2,727 - 2,727
-------------------------------------------------------------------------------------------
Operating Income (Loss) (13,510) (1,711) 104,213 4,957 93,949
Interest charges (54,233) (15,661) (54,205) 45,733 (78,366)
Other income and (deductions) 67,923 16,812 (11,939) (68,391) 4,405
-------------------------------------------------------------------------------------------
Total Other Income and (Deductions) 13,690 1,151 (66,144) (22,658) (73,961)
Income (Loss) Before Income Taxes 180 (560) 38,069 (17,701) 19,988
Income Taxes (Benefit) (12,574) 1,223 18,754 - 7,403
-------------------------------------------------------------------------------------------
Net Income (Loss) $ 12,754 $ (1,783) $ 19,315 $ (17,701) $ 12,585
===========================================================================================
- ---------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Income
- ------------------------------------------------------------------------------------------------------------------------------------
Three Months Ended September 30, 2002
(In Thousands of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Revenues $ 129 $ 79,717 $ 998,485 $ (129) $ 1,078,202
Operating Expenses
Purchased gas - 35,949 98,904 - 134,853
Fuel and purchased power - - 144,259 - 144,259
Operations and maintenance (226) 12,447 475,072 - 487,293
Intercompany expense 1,343 19,008 (20,127) (224) -
Depreciation and amortization (20) 11,949 115,372 - 127,301
Operating taxes (1) 17,534 71,570 89,103
-----------------------------------------------------------------------------------------
Total Operating Expenses 1,096 96,887 885,050 (224) 982,809
Income from Equity Investment 18 - 2,281 - 2,299
-----------------------------------------------------------------------------------------
Operating Income (Loss) (949) (17,170) 115,716 95 97,692
Interest charges (54,116) (15,073) (80,057) 69,309 (79,937)
Other income and (deductions) 55,417 1,765 12,079 (78,163) (8,902)
-----------------------------------------------------------------------------------------
Total Other Income and (Deductions) 1,301 (13,308) (67,978) (8,854) (88,839)
Income (Loss) Before Income Taxes 352 (30,478) 47,738 (8,759) 8,853
Income Taxes (Benefit) (4,612) (11,577) 20,078 - 3,889
-----------------------------------------------------------------------------------------
Earnings from Continuing Operations $ 4,964 $ (18,901) $ 27,660 $ (8,759) $ 4,964
Discontinued Operations - - - -
-----------------------------------------------------------------------------------------
Net Income (Loss) $ 4,964 $ (18,901) $ 27,660 $ (8,759) $ 4,964
=========================================================================================
- ------------------------------------------------------------------------------------------------------------------------------------
30
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Income
- ------------------------------------------------------------------------------------------------------------------------------------
Nine Months Ended September 30, 2003
(In Thousands of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Revenues $ 362 $ 754,855 $ 4,297,636 $ (362) $ 5,052,491
Operating Expenses
Purchased gas - 414,658 1,378,923 - 1,793,581
Fuel and purchased power - - 332,647 - 332,647
Operations and maintenance 8,577 104,437 1,402,192 - 1,515,206
Intercompany expense 5,207 2,227 (2,227) (5,207) -
Depreciation and amortization (53) 58,503 364,467 - 422,917
Operating taxes - 57,516 254,238 - 311,754
------------------------------------------------------------------------------
Total Operating Expenses 13,731 637,341 3,730,240 (5,207) 4,376,105
Income from Equity Investment 108 - 12,378 - 12,486
------------------------------------------------------------------------------
Operating Income (Loss) (13,261) 117,514 579,774 4,845 688,872
Interest charges (154,113) (46,771) (163,224) 137,605 (226,503)
Other income and (deductions) 395,934 7,786 (53,383) (397,254) (46,917)
------------------------------------------------------------------------------
Total Other Income and (Deductions) 241,821 (38,985) (216,607) (259,649) (273,420)
Income (Loss) Before Income Taxes 228,560 78,529 363,167 (254,804) 415,452
Income Taxes (Benefit) (21,521) 30,756 156,479 - 165,714
------------------------------------------------------------------------------
Earnings before Change in Accounting Principle 250,081 47,773 206,688 (254,804) 249,738
Cumulative Effect of Change in Accounting Principle - - 174 - 174
------------------------------------------------------------------------------
Net Income (Loss) $ 250,081 $ 47,773 $ 206,862 $ (254,804) $ 249,912
==============================================================================
- ------------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Income
- ------------------------------------------------------------------------------------------------------------------------------------
Nine Months Ended September 30, 2002
(In Thousands of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- -----------------------------------------------------------------------------------------------------------------------------------
Revenues $ 363 $ 536,601 $ 3,633,379 $ (363) $ 4,169,980
Operating Expenses
Purchased gas - 241,389 792,764 - 1,034,153
Fuel and purchased power - - 326,327 - 326,327
Operations and maintenance 2,802 37,514 1,497,757 - 1,538,073
Intercompany expense 1,482 57,250 (58,369) (363) -
Depreciation and amortization (23) 47,530 333,251 - 380,758
Operating taxes - 62,228 220,435 - 282,663
--------------------------------------------------------------------------------------------
Total Operating Expenses 4,261 445,911 3,112,165 (363) 3,561,974
Income from Equity Investments 52 - 9,661 9,713
--------------------------------------------------------------------------------------------
Operating Income (Loss) (3,846) 90,690 530,875 - 617,719
Interest charges (148,878) (46,175) (216,481) 188,940 (222,594)
Other income and (deductions) 371,281 6,860 39,567 (418,485) (777)
--------------------------------------------------------------------------------------------
Total Other Income and (Deductions) 222,403 (39,315) (176,914) (229,545) (223,371)
Income (Loss) Before Income Taxes 218,557 51,375 353,961 (229,545) 394,348
Income Taxes (Benefit) (10,548) 22,783 133,346 - 145,581
--------------------------------------------------------------------------------------------
Earnings from Continuing Operations 229,105 28,592 220,615 (229,545) 248,767
Discontinued Operations - (19,662) (19,662)
--------------------------------------------------------------------------------------------
Net Income (Loss) $ 229,105 $ 28,592 $ 200,953 $ (229,545) $ 229,105
============================================================================================
- -----------------------------------------------------------------------------------------------------------------------------------
31
- ------------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
- ------------------------------------------------------------------------------------------------------------------------------------
September 30, 2003
Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
-------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash & temporary cash investments $ 21,548 $ 3,039 $ 93,464 $ - $ 118,051
Accounts receivable, net 34,300 141,246 982,236 - 1,157,782
Other current assets 3,880 138,104 589,777 - 731,761
-------------------------------------------------------------------------------------------
59,728 282,389 1,665,477 - 2,007,594
-------------------------------------------------------------------------------------------
Investments and Other 3,981,367 2,542 221,121 (3,912,443) 292,587
-------------------------------------------------------------------------------------------
Property
Gas - 1,852,102 4,545,604 6,397,706
Other - - 5,345,573 5,345,573
Accumulated depreciation and depletion - (346,869) (3,703,508) (4,050,377)
-------------------------------------------------------------------------------------------
- 1,505,233 6,187,669 - 7,692,902
-------------------------------------------------------------------------------------------
Intercompany Accounts Receivable 3,753,148 - (3,753,148) -
Deferred Charges 325,297 184,347 6,939,954 (4,442,633) 3,006,965
-------------------------------------------------------------------------------------------
Total Assets $ 8,119,540 $ 1,974,511 $ 11,261,073 $ (8,355,076) $ 13,000,048
===========================================================================================
LIABILITIES AND CAPITALIZATION
Current Liabilities
Accounts payable $ 67,610 $ 62,503 $ 762,932 $ 893,045
Commercial paper 644,400 - - 644,400
Other current liabilities 263,667 85,066 13,378 362,111
-------------------------------------------------------------------------------------------
975,677 147,569 776,310 - 1,899,556
-------------------------------------------------------------------------------------------
Intercompany Accounts Payable - 172,501 2,138,748 (2,311,249) -
-------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax (44,539) 177,952 842,945 976,358
Other deferred credits and liabilities 480,288 80,724 501,209 1,062,221
-------------------------------------------------------------------------------------------
435,749 258,676 1,344,154 - 2,038,579
-------------------------------------------------------------------------------------------
Capitalization
Common shareholders' equity 3,575,954 694,861 3,214,914 (3,912,443) 3,573,286
Preferred stock 83,697 - - - 83,697
Long-term debt 3,048,463 700,904 3,309,440 (2,131,384) 4,927,423
-------------------------------------------------------------------------------------------
Total Capitalization 6,708,114 1,395,765 6,524,354 (6,043,827) 8,584,406
-------------------------------------------------------------------------------------------
Minority Interest in Subsidiary Companies - - 477,507 - 477,507
-------------------------------------------------------------------------------------------
Total Liabilities & Capitalization $ 8,119,540 $ 1,974,511 $ 11,261,073 $ (8,355,076) $ 13,000,048
===========================================================================================
- ------------------------------------------------------------------------------------------------------------------------------------
32
- ------------------------------------------------------------------------------------------------------------------------------------
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
===========================================================================================
- ------------------------------------------------------------------------------------------------------------------------------------
33
- ---------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
- ---------------------------------------------------------------------------------------------------------------------------------
Nine Months Ended September 30, 2003
------------------------------------------------------------------
Guarantor KEDLI Other Subsidiaries Consolidated
------------------------------------------------------------------
Operating Activities
Net Cash Provided by Operating Activities $ 55,555 $ 85,143 $ 596,365 $ 737,063
------------------------------------------------------------------
Investing Activities
Capital expenditures - (82,233) (637,984) (720,217)
Other investments - - (50,500) (50,500)
Proceeds from the sale of investments and property 79,200 - 133,327 212,527
------------------------------------------------------------------
Net Cash Provided by (Used in) Investing Activities 79,200 (82,233) (555,157) (558,190)
------------------------------------------------------------------
Financing Activities
Treasury stock issued 76,984 - - 76,984
Equity issuance 473,573 - - 473,573
Redemption of promissory notes (447,005) - - (447,005)
Payment of debt and preferred stock, net 28,703 - (168,324) (139,621)
Common and preferred stock dividends paid (208,178) - - (208,178)
Other 17,240 - (4,432) 12,808
Net intercompany accounts (142,833) (6,342) 149,175 -
-
------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities (201,516) (6,342) (23,581) (231,439)
------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents $ (66,761) $ (3,432) $ 17,627 $ (52,566)
Cash and Cash Equivalents at Beginning of Period 88,308 6,472 75,837 170,617
------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 21,547 $ 3,040 $ 93,464 $ 118,051
==================================================================
- ---------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
- -----------------------------------------------------------------------------------------------------------------------------------
Nine Months Ended September 30, 2002
----------------------------------------------------------------------
Guarantor KEDLI Other Subsidiaries Consolidated
----------------------------------------------------------------------
Operating Activities
Net Cash Provided by (Used in) Operating Activities $ (294,829) $ 180,694 $ 869,456 $ 755,321
----------------------------------------------------------------------
Investing Activities
Capital expenditures - (101,844) (713,311) (815,155)
Proceeds from sale of investments - - 173,935 173,935
----------------------------------------------------------------------
Net Cash Used in Investing Activities - (101,844) (539,376) (641,220)
----------------------------------------------------------------------
Financing Activities
Treasury stock issued 67,308 - 67,308
Payment of debt, net (59,222) (35,378) (94,600)
Common and preferred stock dividends paid (192,144) - (192,144)
Other (244) 253 9
Net intercompany accounts 542,945 (78,850) (464,095) -
----------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities 358,643 (78,850) (499,220) (219,427)
----------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents $ 63,814 $ - $ (169,140) $ (105,326)
Cash and Cash Equivalents at Beginning of Period - - 159,252 159,252
----------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 63,814 $ - $ (9,888) $ 53,926
======================================================================
- -----------------------------------------------------------------------------------------------------------------------------------
34
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
nine months ended September 30, 2003, compared to the three and nine months
ended September 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 Nine Months Ended
September 30, September 30,
2003 2002 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------
Gas Distribution $ (39,108) $ (39,565) $ 357,445 $ 321,551
Electric Services 100,254 106,611 191,404 227,613
Energy Services (13,627) (4,834) (32,647) (25,056)
Energy Investments 59,004 36,880 183,940 90,714
Eliminations and other (12,574) (1,400) (11,270) 2,897
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Income 93,949 97,692 688,872 617,719
Other Income and (Deductions) (73,961) (88,839) (273,420) (223,371)
Income taxes 7,403 3,889 165,714 145,581
- ---------------------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations 12,585 4,964 249,738 248,767
Cumulative effect of a change
in accounting principle - - 174 -
Discontinued operations - - - (19,662)
- ---------------------------------------------------------------------------------------------------------------------------------
Net Income 12,585 4,964 249,912 229,105
Preferred stock dividend requirements 1,461 1,335 4,383 4,287
- ---------------------------------------------------------------------------------------------------------------------------------
Earnings for Common Stock $ 11,124 $ 3,629 $ 245,529 $ 224,818
- ---------------------------------------------------------------------------------------------------------------------------------
Basic Earnings per Share
Income from continuing operations $ 0.07 $ 0.03 $ 1.56 $ 1.74
Change in accounting principle - - - -
Discontinued operations - - - (0.14)
- ---------------------------------------------------------------------------------------------------------------------------------
$ 0.07 $ 0.03 $ 1.56 $ 1.60
- ---------------------------------------------------------------------------------------------------------------------------------
As indicated in the above table, operating income decreased $3.7 million, or 4%
for the three months ended September 30, 2003, compared to the same quarter of
last year. These results reflect lower operating income from the Energy Services
and Electric Services segments, as well as a higher level of overall corporate
overhead costs, offset, in part, by higher operating earnings from the Energy
Investment segment. The Energy Services group of companies, continue to be
adversely impacted by the softness in the construction industry in the
northeastern United States. The lower operating income associated with the
Electric Services segment reflects lower revenues from KeySpan's service
agreements with the Long Island Power Authority ("LIPA"), as well as higher
operating costs. The Energy Investment segment benefited from higher earnings
associated with gas exploration and production activities as a result of
significantly higher realized gas prices.
35
For the nine months ended September 30, 2003, operating income increased $71.2
million, or 12% compared to the corresponding period of the prior year. This
increase in operating income reflects higher earnings from the Energy
Investments and Gas Distribution segments, somewhat offset by decreases in
earnings from the Electric Services and Energy Services segments, as well as a
higher level of overall corporate overhead costs. 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 colder weather during the January through
April 2003 heating season compared to 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 summer 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 $78.4 million
and $226.5 million for the three and nine months ended September 30, 2003,
respectively. Comparative interest charges for the third quarter of 2003 are
virtually the same compared to the third quarter of 2002. The increase in
interest charges of 2% for the nine months ended September 30, 2003, compared to
the same period last year, 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 third quarter of 2003, Other Income and (Deductions) also
reflects a $14.0 million pre-tax gain ($8.4 million after-tax or $0.05 per
share) for the sale of 550 acres of real property located on Long Island. The
amount of the gain is subject to adjustment as we are currently in the process
of defining the tax basis of the assets sold. In addition, during the three
months ended September 30, 2003, The Houston Exploration Company ("Houston
Exploration"), our gas exploration and production subsidiary, recorded severance
tax refunds of $6.2 million, as a result of an abatement of severance taxes for
certain qualifying wells.
For the nine months ended September 30, 2003, Other Income and (Deductions) also
reflects the impact from the monetization of a portion of our Canadian
investments, as well as a portion of our ownership interest in Houston
Exploration. 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. We recorded a pre-tax loss of
$30.3 million ($34.1 million after-tax) associated with these sales. (See Note 2
to the Consolidated Financial Statements "Business Segments" for additional
information regarding this transaction.) Additionally, 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. We recorded a gain of $19.0 million on this
transaction. Income taxes were not provided on this transaction, since the
transaction was structured as a return of capital.
36
In March 2003, we called approximately $447 million of outstanding promissory
notes that were issued to 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). Further, in
June 2003, Houston Exploration incurred costs of $5.9 million to retire $100
million 8.625% Notes due 2008.
Additionally, for the nine months ended September 30, 2003, Other Income and
(Deductions) reflects severance tax refunds totaling $19.1 million recorded by
Houston Exploration for severance taxes paid in 2002 and earlier periods, as
well the sale of the non-utility property, as noted earlier. Finally, Other
Income and (Deductions) reflects adjustments for minority interest related to
Houston Exploration and KeySpan Canada, as well as carrying charges on certain
regulatory assets.
Income tax expense for the three and nine months ended September 30, 2003 and
2002, reflects a number of items impacting comparative earnings. During the
third quarter of 2003, we recorded a tax benefit of $9.0 million associated with
certain New York City general corporation tax issues. Further, during the nine
months ended September 30, 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. In addition, 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 nine months ended September 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.
Also, it should be noted that pre-tax income in the Consolidated Statement of
Income reflects minority interest adjustments, whereas income taxes reflect the
full amount of subsidiary taxes. Excluding all of the aforementioned items,
income taxes generally reflects the level of pre-tax earnings for all periods.
In January 2002, KeySpan announced that it had entered into an agreement to sell
Midland Enterprises LLC ("Midland"), its marine barge business. During the
fourth quarter of 2001, in anticipation of this divestiture that closed on July
2, 2002, an estimated loss on the sale of Midland was recorded, as well as an
estimate for Midland's results of operations for the first nine months of 2002.
In the second quarter of 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.
37
As a result of the above mentioned items, earnings available for common stock
for the three months ended September 30, 2003 increased $7.5 million, or $0.04
per share, compared to the same quarter of last year. Earnings available for
common stock for the nine months ended September 30, 2003 increased $20.7
million. Earnings per share, however, decreased by $0.04 per share, compared to
the same period last year, 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 nine months 2003 earnings
per share by $0.18 compared to the corresponding period in 2002. To mitigate the
dilutive effect of the equity offering, a portion of outstanding promissory
notes that were issued to LIPA were redeemed, 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 earnings for 2003 are
forecasted to be approximately $2.45 to $2.60 per share, including the effect of
the equity issuance in January 2003 and excluding special items. Earnings from
continuing core operations (defined for this purpose as all continuing
operations other than exploration and production, less preferred stock
dividends) are forecasted to be approximately $2.15 to 2.20 per share, while
earnings from 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.
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.
38
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 by $1.8 million and $10.1 million for the
three and nine months ended September 30, 2002, respectively 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 Nine Months Ended
September 30, September 30,
(In Thousands of Dollars) 2003 2002 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------
Revenues $ 405,777 $ 334,031 $ 2,970,514 $ 2,078,823
Cost of gas 173,116 126,944 1,744,732 976,884
Revenue taxes 10,191 8,830 66,077 56,974
- ---------------------------------------------------------------------------------------------------------------------------------
Net Revenues 222,470 198,257 1,159,705 1,044,965
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Expenses
Operations and maintenance 163,372 147,023 492,586 445,330
Depreciation and amortization 59,996 56,174 197,005 177,312
Operating taxes 38,210 34,625 112,669 100,772
- ---------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 261,578 237,822 802,260 723,414
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Income (Loss) $ (39,108) $ (39,565) $ 357,445 $ 321,551
- ---------------------------------------------------------------------------------------------------------------------------------
Firm gas sales and transportation (MDTH) 26,668 25,768 238,382 190,264
Transportation - Electric Generation (MDTH) 15,567 27,709 29,715 54,250
Other Sales (MDTH) 35,157 51,949 113,309 153,974
Warmer (Colder) than Normal - New York N/A N/A (13%) 15%
Warmer (Colder) than Normal - New England N/A N/A (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.
Net Revenues
Net gas revenues (revenues less the cost of gas and associated revenue taxes)
from our gas distribution operations increased by $114.7 million, or 11%, for
the nine months ended September 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 nine months ended September 30, 2003 was
approximately 12%-16% colder than normal and approximately 30% - 35% colder than
last year in our New York and New England service territories.
39
Net revenues from firm gas customers (residential, commercial and industrial
customers) in our New York service territory increased by $60.6 million for the
nine months ended September 30, 2003, compared to the same period last year.
Customer additions and oil-to-gas conversions, net of attrition and
conservation, added approximately $15 million to net revenues during the nine
months. Higher customer consumption due primarily to colder than normal weather
added approximately $50 million to net revenues during the nine 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 million refund to firm gas customers during the
past nine months. Further, included in net revenues are regulatory incentives
and recovery of certain taxes that added $6.5 million and $15.1 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.
Net revenues from firm gas customers in our New England service territory
increased by $26.8 million for the nine months ended September 30, 2003,
compared to the same period last year. Customer additions and oil-to-gas
conversions, net of attrition and conservation, added approximately $9.5 million
to net revenues during the nine months. Higher customer consumption due
primarily to colder than normal weather added approximately $33 million to net
revenues during the past nine 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 September 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 nine 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 $27.3 million during the nine months ended September
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.
40
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.
Firm Sales, Transportation and Other Quantities
Firm gas sales and transportation quantities increased by 25% during the nine
months ended September 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 nine months ended September 30, 2003 compared
to the same period in 2002 of $767.8 million, or 79%, reflects an increase of
48% in the price per dekatherm of gas purchased, and a 25% increase in the
quantity of gas purchased. Fluctuations in utility gas costs associated with
firm gas customers have no material 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 third quarter of 2003 increased $23.8 million, or
10%, compared to the same quarter last year and $78.9 million, or 11% for the
nine months ended September 30, 2003, compared to the same period last year.
These increases are primarily attributable to higher pension and other
postretirement benefits, which have increased (net of amounts deferred and
subject to regulatory true-ups) by $9.0 million and $30.1 million for the three
and nine months ended September 30, 2003, respectively. The cost of these
benefits has risen primarily as a result of lower actual returns on plan assets,
41
as well as increased health care costs. Further, the colder weather experienced
during the first nine months of 2003 resulted in increased repair and
maintenance work on our gas distribution infrastructure and higher comparative
operating expenses. Also, for the nine months ended September 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.
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 $2.5 million and $9.9 million adjustment recorded during the three
and nine months ended September 30, 2002, respectively, 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, under 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.
42
Selected financial data for the Electric Services segment is set forth in the
table below for the periods indicated.
- ---------------------------------------------------------------------------------------------------------------------------
Three Months Nine Months Ended
Ended September 30, September 30,
(In Thousands of Dollars) 2003 2002 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------
Revenues $ 427,687 $ 414,893 $ 1,132,723 $ 1,084,384
Purchased fuel 124,789 106,293 294,547 225,836
- ---------------------------------------------------------------------------------------------------------------------------
Net Revenues 302,898 308,600 838,176 858,548
- ---------------------------------------------------------------------------------------------------------------------------
Operating Expenses
Operations and maintenance 150,447 149,682 489,178 481,732
Depreciation 16,410 16,176 49,054 43,835
Operating taxes 35,787 36,131 108,540 105,368
- ---------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 202,644 201,989 646,772 630,935
- ---------------------------------------------------------------------------------------------------------------------------
Operating Income $ 100,254 $ 106,611 $ 191,404 $ 227,613
- ---------------------------------------------------------------------------------------------------------------------------
Electric sales (MWH)* 1,854,740 2,175,937 3,617,522 4,392,915
Capacity(MW)* 2,200 2,200 2,200 2,200
Cooling degree days 824 1,015 1,000 1,353
- ---------------------------------------------------------------------------------------------------------------------------
*Reflects the operations of the Ravenswood facility only.
Net Revenues
Total electric net revenues decreased by $5.7 million, or 2%, in the third
quarter of 2003, compared to the same quarter of 2002. For the nine months ended
September 30, 2003, total electric net revenues decreased $20.4 million, or 2%,
compared to the same period of 2002.
Net revenues from the Ravenswood facility were $7.6 million, or 7% higher during
the third quarter of 2003, compared to the same quarter in 2002. Comparative
quarterly net revenues reflect higher capacity revenues of $26.8 million,
partially offset by a decrease in energy margins of $19.2 million. However, for
the nine months ended September 30, 2003, net revenues from the Ravenswood
facility were $9.4 million, or 4% lower than the same period of 2002.
Comparative net revenues, for the nine months ended September 30, 2003, reflect
higher capacity revenues of $25.2 million, which were more than offset by a
decrease in energy margins of $34.6 million.
The increase in capacity revenues for both the quarter and period ended
September 30, 2003, reflects an increase in the level of capacity sold, as well
as an increase in the selling price of capacity. Such increases are the result
of two measures. First, 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, which caused a reliability concern.
43
Further, the revised methodology resulted in lower capacity volume sold into the
NYISO and depressed capacity pricing during the quarter and period ended
September 30, 2002. The NYISO, however, 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 comparative capacity revenue realized at the Ravenswood
facility for the three and nine months ended September 30, 2003.
Secondly, on May 20, 2003, FERC approved the NYISO's revised capacity market
procurement design with an effective date of May 21, 2003. This revised capacity
market procurement design is based on a demand curve rather than relying on
deficiency auctions to procure necessary capacity. The deficiency auction and
its associated fixed minimum capacity requirements was replaced with a spot
market auction that pays gradually declining prices as additional capacity is
offered and gradually increasing prices as capacity offers decrease. This new
market design recognizes the value of capacity in excess of the minimum
requirement and reduces price spikes during periods of shortage. Essentially,
the demand curve design eliminates the high and low cycles inherent in the
deficiency auction market design. This new market design also established
seasonal electric generator specific price caps. Price caps establish the
maximum price per megawatt hour ("MW") that capacity can be sold into the NYISO
by divested electric generators like Ravenswood. Prior to this design change,
one price cap was established for the entire year and was effective for all
electric generators. For the Ravenswood facility, its 2003 summer price cap was
higher than the yearly price cap effective during the 2002 summer. As a result
of these market design changes, the Ravenswood facility realized higher capacity
revenues during the three and nine months ended September 30, 2003, compared to
the same periods in 2002. It should be noted, however, that Ravenswood's
2003/2004 winter price cap will be lower than the yearly price cap effective
during the 2002/2003 winter.
The decrease in energy margins during both the quarter and period ended
September 30, 2003, primarily reflects significantly cooler weather during the
summer of 2003 compared to the summer of 2002. Measured in cooling degree days,
weather for the three and nine months ended September 30, 2003 was 19% and 26%
cooler than the corresponding periods last year. The cooler weather resulted in
lower realized "spark-spreads" (the selling price of electricity less cost of
fuel, plus hedging gains or losses), as well as a reduction in megawatt hours
sold into the NYISO. Further, more competitive pricing by electric generators
that bid into the NYISO, as well as certain price mitigation measures imposed by
the FERC (as discussed below) have resulted in lower comparative realized
"spark-spreads." As mentioned, comparative energy sales margins for the nine
months ended September 30, 2003, also reflect the use of derivative hedging
instruments as discussed in more detail below. Energy sales quantities were also
adversely impacted by the major overhaul of our largest steam generator.
We employ derivative financial hedging instruments to hedge the cash flow
variability for a portion of forecasted purchases of natural gas and fuel oil
that will be consumed at the Ravenswood facility. Further, we have engaged in
the use of derivative financial hedging instruments to hedge the cash flow
variability associated with a portion of forecasted peak electric energy sales
from the Ravenswood facility, as well as forecasted sales of Unforced Capacity
44
("UCAP") to the NYISO. These derivative instruments resulted in hedging gains,
which are reflected in net energy margins, of $7.9 million and $11.3 million for
the three and nine months ended September 30, 2003, respectively. For the three
and nine months ended September 30, 2002, these derivative instruments resulted
in hedging gains of $4.2 million and $15.2 million, respectively. (See Note 6 to
the Consolidated Financial Statements, "Hedging and Derivative Financial
Instruments for additional information.)
The rules and regulations for capacity, energy sales and the sale of certain
ancillary services to the NYISO energy markets continue to evolve and the FERC
has adopted several price mitigation measures that have adversely impacted
earnings from the Ravenswood facility. Certain of these mitigation measures are
still subject to rehearing and possible judicial review. The final resolution of
these issues and their effect on our financial position, results of operations
and cash flows cannot be fully determined at this time. (See 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 $11.5 million,
or 6% and $22.5 million, or 4% for the three and nine months ended September 30,
2003, respectively, compared to the same periods last year. Included in revenues
are billings to LIPA for certain third party costs that were lower than such
billings last year. These revenues have minimal or no 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 the
three and nine months ended September 30, 2003 associated with these service
agreements decreased approximately $3 million and $4 million, respectively,
compared to the same periods last year. These decreases are mainly due to
slightly lower incentives earned on the LIPA service agreements, as well as
lower sales of emission credits.
Net revenues from the Glenwood Landing and Port Jefferson electric "peaking"
facilities located on Long Island were $1.8 million lower during the third
quarter of 2003 compared to same period last year, reflecting a decrease in
certain interest charges "passed-through" to LIPA. These charges have no impact
on net income. Net revenues were $11.5 million higher during the nine months
ended September 30, 2003, compared to the corresponding period 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 increased $0.7 million and $15.8 million for the three and
nine months ended September 30, 2003, respectively, compared to the same periods
of 2002. Included in comparative operating expenses is a decrease in third party
capital costs that are fully recoverable from LIPA, as noted previously.
45
Excluding the decrease in these costs, operating expenses increased
approximately $10 million and $35 million for the three and nine months ended
September 30, 2003, respectively, compared to the same periods of 2002. These
increases 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 $1 million
and $9 million higher for the three and nine months ended September 30, 2003
compared to the same periods last year. Further, plant maintenance costs were
$5.3 million higher for the nine months ended September 30, 2003, due to the
major overhaul of our largest steam generator at the Ravenswood facility site as
previously mentioned. In addition, during the third quarter of 2002 we settled
certain outstanding issues with LIPA and Consolidated Edison that resulted in a
$13.0 million decrease to operating expenses in 2002. The increase in
depreciation expense is primarily due to the depreciation of the Glenwood and
Port Jefferson peaking facilities.
Other Matters
On August 14, 2003, at approximately 4:15 PM eastern standard time, the
northeastern United States experienced a major black-out. The Ravenswood
electric generating units were out of service for up to 23 hours. The NYISO, in
an attempt to mitigate the economic damage to electric generators and load
serving entities from the black-out, revised its day-ahead and real-time pricing
mechanisms. We estimate that the lost opportunity of not selling electric energy
into the NYSIO, while the various Ravenswood generating units were out of
service, to be between $1 million to $2 million on a net margin basis.
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 operational testing in late 2003. The capacity and energy produced from
this plant are anticipated to be sold into the NYISO energy markets by the end
of the first quarter of 2004. We anticipate replacing outstanding commercial
paper related to the construction of this facility with permanent financing by
the end of the second quarter of 2004.
Our application to construct and operate a 250 MW combined cycle electric
generating facility in Melville, Long Island has been approved. In May, 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, which is now final and non-appealable.
Also in May 2003, LIPA issued a Request for Proposals ("RFP") 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 MW of electricity by no later than the summer of 2007. In
September, KeySpan and American National Power Inc. ("ANP") filed a joint
proposal in response to LIPA's RFP. Under the proposal, KeySpan and ANP will
jointly own and operate two 250 MW electric generating facilities to be located
on Long Island, including the proposed Melville facility. The joint proposal
also recommends that between 80% to 100% of the capacity of these two facilities
be sold to LIPA under long-term power purchase agreements. It is anticipated
that LIPA will respond to the joint proposal in the fourth quarter of 2003.
46
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 Nine Months Ended
September 30, September 30,
(In Thousands of Dollars) 2003 2002 2003 2002
- --------------------------------------------------------------------------------------------------------------------------
Revenues $ 150,802 $ 217,104 $ 500,163 $ 687,975
Less: cost of gas and fuel 7,731 45,809 86,572 157,694
- --------------------------------------------------------------------------------------------------------------------------
Net Revenues 143,071 171,295 413,591 530,281
Other operating expenses 156,698 176,129 446,238 555,337
- --------------------------------------------------------------------------------------------------------------------------
Operating (Loss) Income $ (13,627) $ (4,834) $ (32,647) $ (25,056)
- --------------------------------------------------------------------------------------------------------------------------
Revenues decreased approximately 31% and 27% for the three and nine months ended
September 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 softness in the construction industry in the northeastern
United States, 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 continues to provide retail natural gas
marketing to a small number of customers in New Jersey and plans to continue its
electric marketing activities. Comparative revenues, as well as gas and fuel
costs were impacted by this transaction.
47
Operating Income for the Business Solutions group of companies decreased by
$11.6 million for the third quarter of 2003 and by $22.3 million for the nine
months ended September 30, 2003, compared to the corresponding periods last
year. These declines reflect the softness in the construction industry, which
has delayed the start-up of certain engineering and construction projects, and
has generally increased competition for remaining opportunities. As a result,
the Business Solution group of companies have realized lower margins on
construction projects currently in progress. This is further reflected by a
backlog of approximately $527 million at September 30, 2003 (which includes
backlog of $38 million purchased in a recent acquisition as discussed below),
compared to $514 million at December 31, 2002 and $578 million at September 30,
2002.
Offsetting, in part, the results of the Business Solutions group of companies,
were comparative increases in operating earnings of $2.8 million and $14.7
million for the three and nine months ended September 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 nine months
ended September 30, 2002, resulting from the non-renewal of appliance service
contracts due to the warm first quarter 2002 weather, as well as from an
increase in the provision for bad debts.
Other Matters
During the third quarter of 2003, KeySpan Services, Inc., and its wholly- owned
subsidiary, Paulus, Sokolowski and Sartor, LLC., acquired 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 was $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 recorded goodwill
of $26 million and intangible assets of $2 million associated with this
transaction. The intangible assets, which relate primarily to a portion of the
backlog purchased, as well as to non-compete agreements with all of the former
owners of BR+A, will be amortized over two and three years, respectively. We are
currently in the process of evaluating the fair market value of the assets
acquired and may adjust the recorded goodwill in the fourth 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
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
48
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.
On October 15, 2003, Houston Exploration acquired the entire Gulf of Mexico
shallow-water asset base of Transworld Exploration and Production, Inc. for $149
million. The properties, which are 75% natural gas, have proven reserves of
approximately 92 billion cubic feet of natural gas equivalent. Current
production is from 11 fields and is producing approximately 35 million cubic
feet of natural gas equivalent per day. Houston Exploration funded the
transaction from its bank revolver and from cash on hand at the time of closing.
Consistent with past acquisitions, Houston Exploration has derivative hedge
positions in place for a portion of the 2004 production.
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 Nine Months Ended
September 30, September 30,
(In Thousands of Dollars) 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------
Revenues $ 123,052 $ 88,600 $ 373,774 $ 256,089
Depletion and amortization expense 48,641 44,880 145,559 130,766
Other operating expenses 23,416 17,366 71,482 49,690
- ------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------
Operating Income $ 50,995 $ 26,354 $ 156,733 $ 75,633
- ------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------
Natural gas and oil production (Mmcf) 26,984 26,914 80,188 79,641
Natural gas (per Mcf) realized $ 4.45 $ 3.23 $ 4.64 $ 3.17
Natural gas (per Mcf) unhedged $ 4.84 $ 3.09 $ 5.45 $ 2.89
- ------------------------------------------------------------------------------------------------------------------------------
*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 $24.6 million and $81.1 million for the
three and nine months ended September 30, 2003, compared to the corresponding
periods last year, reflects a significant increase in revenues. The higher
revenues were offset, to some extent, by an increase in operating expenses
associated with a higher depletion rate, as well as greater lease operating
expenses, as discussed below. Revenues for both the third quarter and first nine
months of 2003 benefited from increases of 38% and 46% in comparative average
realized gas prices (average wellhead price received for production including
hedging gains and losses).
Derivative financial hedging instruments are employed by Houston Exploration to
provide more predictable cash flow, as well as to reduce its exposure to
fluctuations in natural gas prices. The average realized gas price for the third
quarter of 2003 was 92% of the average unhedged natural gas price, resulting in
revenues that were $9.7 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 nine months ended
September 30, 2003 was 85% of the average unhedged natural gas price, resulting
in revenues that were $59.7 million lower than revenues that would have been
realized if derivative financial instruments had not been in place during the
first nine months of 2003. Houston Exploration hedged slightly less than 70% of
its 2003 third quarter and nine months production, principally through the use
of costless collars, and a similar amount for its 2004 production.
49
The average realized gas price for the third quarter of 2002 was 105% of the
average unhedged natural gas price resulting in revenues that were $3.5 million
higher than revenues that would have been realized if derivative financial
instruments had not been employed during the third quarter 2002. The average
realized gas price for the nine months ended September 30, 2002 was 110% of the
average unhedged natural gas price resulting in revenues that were $20.5 million
higher than revenues that would have been realized if derivative financial
instruments had not been employed during the first nine months of 2002. (See
Note 6 to the Consolidated Financial Statements, "Hedging and Derivative
Financial Instruments" for further information on these derivative positions.)
The depletion rate for the nine months ended September 30, 2003 was $1.80 per
Mcf , compared to $1.64 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 are
reclassified into the amortization base without incremental reserve additions.
In addition, future development costs have increased from prior year estimates.
The increase in other operating expenses for both the three and nine months
ended September 30, 2003, compared to same periods last year was primarily due
to increased lease operating costs and severance taxes. Lease operating expenses
increased $1.5 million and $9.5 million for the three and nine months ended
September 30, 2003, respectively, as a result of the continued expansion of
operations both onshore and offshore. Severance tax, which is a function of
volume and revenues generated from onshore production, increased $0.7 million
and $3.7 million for the three and nine months ended September 30, 2003,
respectively, as a result of the increase in average wellhead prices for natural
gas. Overall operating expenses are increasing as new wells and facilities are
added and production from existing wells is maintained.
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.
50
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 Nine Months Ended
September 30, September 30,
(In Thousands of Dollars) 2003 2002 2003 2002
- --------------------------------------------------------------------------------------------------------------------------
Revenues $ 27,699 $ 23,793 $ 84,043 $ 63,366
Operation and maintenance expense 16,709 10,849 52,743 44,675
Other operating expenses 5,708 4,699 16,471 13,271
Equity earnings 2,727 2,281 12,378 9,661
- --------------------------------------------------------------------------------------------------------------------------
Operating Income $ 8,009 $ 10,526 $ 27,207 $ 15,081
- --------------------------------------------------------------------------------------------------------------------------
*Operating income above reflects 100% of KeySpan Canada's results.
The increase in operating income for the nine months ended September 30, 2003
compared to the same period last year reflects, in part, higher operating income
associated with our Canadian investments, primarily KeySpan Canada, as well as
higher earnings from our Northern Ireland investments. 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. Operating income for 2003
also reflects our investment in KeySpan LNG storage facility located in Rhode
Island, which we acquired in December 2002.
KeySpan has announced a joint initiative with BG LNG Services to upgrade the
storage and receiving terminal at the KeySpan's LNG facility located in
Providence, Rhode Island. Pending approvals, the facility could be ready to
accept marine deliveries by 2005. We anticipate making an investment of
approximately $50 million to upgrade the facility.
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, in May 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).
51
Based on current market conditions 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
KeySpan is 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. As required by the SEC, during the third quarter of
2003, we adjusted certain provisions in our allocation methodology. These
adjustments have resulted in a higher level of costs remaining at our corporate
holding company level than in the past.
Liquidity
Cash flow from operations for the nine months ended September 30, 2003 decreased
$18.3 million, or 2%, compared to the same period last year, due in part, to
higher pension and other postretirement funding requirements. Although KeySpan's
funding balance is currently in excess of ERISA minimum funding requirements,
our pension plans, on an actuarial basis, are currently underfunded. In order to
limit future funding requirements, we follow a multi-year funding strategy. As
such, we contributed approximately $90 million to KeySpan's pension plans during
the nine months ended September 30, 2003. In addition, we contributed $35
million in other postretirement funding. For the nine months ended September 30,
2002, pension and other post retirement funding amounted to approximately $40
million. (See Critical Accounting Policies and Assumptions "Pension and Other
Postretirement Benefits" for a further discussion of these matters.) Further,
higher natural gas prices during the nine months ended September 30, 2003,
compared to the same period last year resulted in significantly higher cash
expenditures required to re-fill natural gas storage levels.
Offsetting, to a large degree, these adverse impacts to operating cash flow, was
an increase in comparative operating cash flow from the collection of gas
accounts receivable associated with winter gas heating sales. As a result of
load additions, colder than normal winter weather, and higher natural gas
prices, cash receipts from the prior winter heating sales were higher during the
nine months ended September 30, 2003 compared to the same period in 2002.
Further, the higher natural gas prices resulted in an increase in operating cash
flow associated with the operations of Houston Exploration.
During 2003, KeySpan performed an analysis of costs capitalized to
self-constructed property and inventory for income tax purposes. Keyspan filed a
change of accounting method for income tax purposes resulting in a cumulative
deduction for costs previously capitalized. As a result of this tax method
change, along with accelerated deductions resulting from bonus depreciation,
Keyspan generated a net operating loss on its 2002 tax return. Consequently, in
October 2003, we received a $192.3 million refund from the Internal Revenue
Service associated with the refund of prior year taxes. We anticipate receiving
an additional refund of $40 million in early 2004.
52
At September 30, 2003, we had cash and temporary cash investments of $118.1
million. During the nine months ended September 30, 2003, we repaid $271.3
million of commercial paper and, at September 30, 2003, $644.4 million of
commercial paper was outstanding at a weighted average annualized interest rate
of 1.15%. We had the ability to borrow up to an additional $655.6 million at
September 30, 2003, under the terms of our credit facility.
In June 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 that ranges from eight to twenty five
basis points on the 364-day facility and ten to twenty basis points 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. 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%, plus a margin. Competitive bid loans are based on bid results requested by
KeySpan from the lenders. The margins on both facilities are ratings based and
range from zero basis points to 112.5 basis points. The margins are increased if
outstanding loans are in excess of 33% of the total facility. 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.
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 September 30, 2003, consolidated indebtedness, as calculated under the terms
of the credit facility was 58.4% of consolidated capitalization. (See 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
53
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 September 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) generally
prohibits the hedging of more than 70% of natural gas and oil production during
any 12-month period. At September 30, 2003, Houston Exploration was in
compliance with all financial covenants.
During the nine months ended September 30, 2003, Houston Exploration borrowed
$71 million under its credit facility and repaid $223 million. At September 30,
2003, Houston Exploration had no outstanding borrowings under its credit
facility. However, $0.4 million was committed under outstanding letters of
credit obligations and $299.6 million of borrowing capacity was available.
Subsequent to September 30, 2003, Houston Exploration borrowed $115 million
under this credit facility to fund a portion of the purchase price for the
producing properties acquired from Transworld Exploration and Production Inc.,
as previously mentioned.
In June 2003, KeySpan Canada replaced its two outstanding credit facilities with
one new facility with three tranches that combined allowed KeySpan Canada to
borrow up to approximately $125 million. 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. Then, during the third quarter of
2003, KeySpan Canada issued Cdn$125 million, or approximately US$93 million, in
long-term secured notes in a private placement. The proceeds of the offering
were used to pay-down, in its entirety, outstanding borrowings under the credit
facility. Further, one tranch of the credit facility was discontinued. (See
"Financing" below for further information regarding the long-term debt
issuance.) At September 30, 2003, KeySpan Canada's credit facility has the
following two tranches with the following maturities: (i) $37.5 million matures
in 364 days: and (ii) $37.5 million matures in two years. For the nine months
54
ended September 30, 2003, KeySpan Canada borrowed $71.5 million from its prior
credit facilities and repaid $240.2 million. At September 30, 2003, there are no
outstanding borrowings under the credit facility, and $75 million is available
for future borrowing. KeySpan is not a guarantor of this facility.
In September 2003, the Boston Gas Company redeemed all 562,700 shares of its
outstanding Variable Term Cumulative Preferred Stock, 6.42 % Series A at its par
value of $25 per share. The total payment was $14.3 million which included $0.2
million of accumulated dividends. This preferred stock series had been reflected
as Minority Interest on KeySpan's Consolidated Balance Sheet.
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.
Capital Expenditures and Financing
Construction Expenditures
The table below sets forth our construction expenditures by operating segment
for the periods indicated:
- ------------------------------------------------------------------------------
Nine Months Ended September 30,
(In Thousands of Dollars) 2003 2002
- ------------------------------------------------------------------------------
Gas Distribution $ 274,702 $ 294,774
Electric Services 200,425 290,790
Energy Investments 235,322 216,157
Energy Services and other 9,768 13,434
- ------------------------------------------------------------------------------
$ 720,217 $ 815,155
- ------------------------------------------------------------------------------
55
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 nine months ended September 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 September 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
$338 million.
Financing
During the third quarter of 2003, KeySpan Canada, issued Cdn$125 million, or
approximately US$93 million, long-term secured notes in a private placement to
investors in Canada and the United States. The notes were issued in the
following three series: (i) Cdn$20 million 5.42% senior secured notes due 2008;
(ii) Cdn$52.5 million 5.79% senior secured notes due 2010; and (iii) Cdn$52.5
million 6.16% senior secured notes due 2013. The proceeds of the offering have
been used to re-pay KeySpan Canada's credit facility.
In June 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% with proceeds from an equity
offering. Houston Exploration incurred approximately $4.5 million of debt
issuance costs on this private placement. In July 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% 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 bank revolving credit facility.
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.
56
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 have 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 the necessary flexibility to finance
our future capital requirements over the next three years.
During the remainder of 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 outstanding commercial paper related to the
construction of the two Long Island peaking-power plants that became operational
in 2002. In addition we anticipate replacing outstanding commercial paper
related to the construction of the 250 MW combined cycle generating facility at
the Ravenswood facility site with permanent financing by the end of the second
quarter of 2004. 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 capital needs for the foreseeable future.
The following table represents the ratings of our long-term debt at September
30, 2003. Currently, these ratings are all on stable outlook with the exception
of Standard & Poor's ratings on KeySpan's and its subsidiaries' long-term debt,
which are on negative outlook.
57
- ----------------------------------------------------------------------------------------------------
Moody's Investor Standard
Services & Poor's FitchRatings
- ----------------------------------------------------------------------------------------------------
KeySpan Corporation A3 A A-
KEDNY N/A A+ A+
KEDLI A2 A+ A-
Boston Gas A2 A N/A
Colonial Gas A2 A+ 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 September 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 had also guaranteed a $25 million
line of credit for Hawkeye Electric, LLC, and Hawkeye Construction, LLC
(collectively "Hawkeye"), a non-affiliated company. As part of a settlement
agreement with Hawkeye, KeySpan's guarantee of such line of credit has been
terminated. These guarantees are not recorded on the Consolidated Balance Sheet.
At this time, we have no reason to believe that our subsidiaries will default on
their current obligations. However, we cannot predict when or if any defaults
may take place or the impact such defaults may have on our consolidated results
of operations, financial condition or cash flows. (See Note 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.)
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.
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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 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. As issued, FIN 46 was effective for the first interim period
ending after June 15, 2003. In accordance with a Financial Accounting Standards
Board ("FASB") announcement, implementation of FIN 46 is now scheduled for the
fourth quarter of 2003. (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
operations may vary significantly from expected results if the judgments and
assumptions underlying the estimates prove to be inaccurate. At September 30,
2003, KeySpan's critical accounting policies and assumptions have remained
59
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.
KeySpan currently has $1.8 billion of recorded goodwill; the majority of which
is recorded in the Gas Distribution and Energy Investments segment, with $169
million recorded in the Energy Services segment. As permitted under SFAS 142, we
can rely on our previous valuations for the annual impairment testing provided
that the following criteria for each reporting unit are met: (a) the assets and
liabilities that make up the reporting unit have not changed significantly since
the most recent fair value determination; and (b) the most recent fair value
determination resulted in an amount that exceeded the carrying amount of the
reporting unit by a substantial margin and there is no economic indication that
the carrying value of goodwill may be impaired.
In the case of the Gas Distribution and the Energy Investments segment, the
above criteria have been met and no further evaluation is required. In regard to
the Energy Services segment, criteria (b) was not met since the fair value
valuation performed last year did not exceed the carrying value by an amount
deemed by us to be substantial. As a result, we will be conducting an impairment
test during the fourth quarter of 2003.
60
Accounting for the Effects of Rate Regulation on Gas Distribution Operations
The financial statements of the Gas Distribution segment reflect the ratemaking
policies and orders of the NYPSC, the New Hampshire Public Utilities Commission
("NHPUC"), and the Massachusetts Department of Telecommunications and Energy
("DTE").
Four of our six regulated gas utilities (KEDNY, KEDLI, Boston Gas Company and
EnergyNorth Natural Gas, Inc.) are subject to the provisions of SFAS 71,
"Accounting for the Effects of Certain Types of Regulation." This statement
recognizes the actions of regulators, through the ratemaking process, to create
future economic benefits and obligations affecting rate-regulated companies.
In separate merger-related orders issued by the DTE, the base rates charged by
Colonial Gas Company and Essex Gas Company have been frozen at their current
levels for 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. On October 31, 2003, the DTE rendered its
decision on the rate proposal and allowed for, among other things, continued
application of SFAS 71. 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
61
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 is not 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. In order to
limit future funding requirements, we follow a multi-year funding strategy. As
such, we contributed approximately $90 million to KeySpan's pension plans during
the nine months ended September 30, 2003. In addition, we contributed $35
million in other postretirement funding. We will continue to monitor our funding
strategy, and may elect to make additional contributions during the fourth
quarter of 2003. For the fiscal year ended December 31, 2002 we contributed
approximately $130 million to KeySpan's pension and other postretirement plans.
(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.
62
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
generally based on standard New York Mercantile Exchange ("NYMEX") quotes. We
use industry-published indices, NYMEX day-ahead forward pricing, 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 day-ahead award
pricing. 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 September 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. On October 31, 2003, the DTE rendered its decision on the Boston Gas
Company's proposal and approved a $26 million increase in base revenues with an
allowed return on equity of 10.2% assuming an equal balance of debt and equity.
The DTE also approved a true-up mechanism for pension and other postretirement
benefit costs under which variations between actual pension and other
postretirement benefit costs and amounts used to establish rates are deferred
and collected from or refunded to customers in subsequent periods through an
adjustment clause. This true-up mechanism allows for carrying charges on
deferred assets and liabilities at Boston Gas Company's weighted-average cost of
capital.
63
The DTE also approved a Performance Based Rate Plan (the "Plan") for up to ten
years. The Plan allows for an annual revenue adjustment based on inflation, less
a .41 percent-productivity adjustment.
For additional information regarding KeySpan's 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."
Electric Rate Matters
A KeySpan subsidiary sells to LIPA all of the capacity and, to the extent
requested, energy conversion services from our existing Long Island based oil
and gas-fired generating plants. Sales of capacity and energy conversion
services are made under rates approved by the FERC. The current FERC approved
rates, which have been in effect since May 1998, are set to expire on December
31, 2003. KeySpan filed with the FERC an updated cost of service for our
existing Long Island based oil and gas-fired generating plants on October 31,
2003. The rate filing included, among other things, an annual revenue increase
of 2.1% or approximately $6.4 million, a return on equity of 11%, updated
operating and maintenance expense levels and recovery of certain other costs. It
is anticipated that the new rates will be in effect for a five-year period
beginning January 1, 2004.
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
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
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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 September 30,
2003, our consolidated common equity was 39.6% of our consolidated
capitalization, including commercial paper 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 $173.3 million
and we have recorded a related liability for such amount. We have also recorded
an additional $37.8 million liability representing the estimated environmental
cleanup costs related to a former coal tar processing facility. Further, as of
September 30, 2003, we have expended a total of $92.5 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.)
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
65
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
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.
66
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;
- 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;
67
- a change in the fair value of our investments that could cause a
significant change in the carrying value of goodwill;
- timely receipts of payments from our two largest customers LIPA and
the NYISO; 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 purchased 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
September 30, 2003, Houston Exploration has hedged slightly less than 70% of its
estimated 2003 gas production and a similar amount of its 2004 gas production.
Houston Exploration used standard New York Mercantile Exchange ("NYMEX") futures
prices to value its swap positions, 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 $10.5
million, or $6.8 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 for 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 for 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 forecasted purchases of
natural gas and fuel oil is through September 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 $0.2 million, or $0.1
million after-tax.
68
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 2003. The estimated amount
of gains or 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 September 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, as well as forecasted sales of
Unforced Capacity ("UCAP") to the NYISO. The maximum length of time over which
we have hedged cash flow variability is through December 2004. We used NYMEX
day-ahead forward pricing, as well as published NYISO day-ahead award prices to
value these outstanding derivatives. The estimated amount of losses associated
with such derivative instruments that are reported in Other Comprehensive Income
and that are expected to be reclassified into earnings over the next twelve
months is $1.3 million, or $0.8 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 $0.4 million, or $0.3 million after-tax.
The following tables set forth selected financial data associated with these
derivative financial instruments noted above that were outstanding at September
30, 2003.
- ------------------------------------------------------------------------------------------------------------------------------------
Year of Volumes Floor Ceiling Fixed Price Current Price Fair Value
Type of Contract Maturity (mmcf) ($) ($) ($) ($) ($000)
- ------------------------------------------------------------------------------------------------------------------------------------
Gas
Collars 2003 13,800 3.48 4.91 - 4.43 - 5.08 (4,085)
2004 64,100 3.50 - 4.50 4.75 - 7.00 - 4.70 - 5.26 (7,757)
Put Options - Short Natural Gas 2004 9,100 5.00 - - 5.11 - 5.26 4,228
Swaps/Futures - Short Natural Gas 2003 3,711 - - 3.19 4.43 - 5.08 (5,842)
2004 14,640 - - 4.96 4.76 - 5.26 1,152
Swaps/Futures - Long Natural Gas 2004 50 - - 5.11 - 5.14 4.71 - 4.72 (25)
2005 10 - - 4.95 4.46 (5)
- ------------------------------------------------------------------------------------------------------------------------------------
105,411 (12,334)
- ------------------------------------------------------------------------------------------------------------------------------------
69
- --------------------------------------------------------------------------------------------------------------------------
Year of Volumes Fixed Price Current Price Fair Value
Type of Contract Maturity (Barrels) ($) ($) ($000)
- --------------------------------------------------------------------------------------------------------------------------
Oil
Swaps - Long Fuel Oil 2003 55,367 20.60 - 30.07 28.54 - 29.80 204
2004 100,548 20.55 - 29.60 25.88 - 28.61 37
2005 28,000 24.65 - 27.25 25.25 - 25.59 (31)
- --------------------------------------------------------------------------------------------------------------------------
183,915 210
- --------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------
Year of Fixed Price Current Price Fair Value
Type of Contract Maturity Capacity MWh ($) ($) ($000)
- ------------------------------------------------------------------------------------------------------------------------------
Electricity
Swaps - Energy 2003 222,464 15.00 - 67.44 15.90 - 42.98 (613)
2004 340,800 14.00 - 26.50 17.15 - 41.96 (953)
Swaps - Capacity 2003 100 7.00 6.98 2
2004 200 7.00 6.98 4
- ------------------------------------------------------------------------------------------------------------------------------
300 563,264 (1,560)
- ------------------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
(In Thousands of Dollars) 2003
Change in Fair Value of Derivative Hedging Instruments ($000)
- -------------------------------------------------------------------------------
Fair value of contracts at January 1, $ (32,628)
Net losses on contracts realized 30,157
(Decrease) in fair value of all open contracts (11,213)
- -------------------------------------------------------------------------------
Fair value of contracts outstanding at September 30, $ (13,684)
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------
Fair Value of Contracts
- -------------------------------------------------------------------------------------------------------
Maturity Maturity Total
Sources of Fair Value In 12 Months Through 2005 Fair Value
- -------------------------------------------------------------------------------------------------------
Prices actively quoted $ (9,251) $ (215) $ (9,466)
Prices provided by external sources (5) - (5)
Prices based on models and
other valuation methods (1,223) (1,636) (2,859)
Local published indicies (1,413) 59 (1,354)
- -------------------------------------------------------------------------------------------------------
$ (11,892) $ (1,792) $ (13,684)
- -------------------------------------------------------------------------------------------------------
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, "Accounting for Derivative Instruments and Hedging Activities." At
September 30, 2003, these instruments had a net fair market value of $1.3
million, which was recorded on the Consolidated Balance Sheet. Based on the
non-hedge designation of these instruments, the gain was recognized in the
Consolidated Statement of Income.
70
Firm Gas Sales Derivative Instruments - Regulated Utilities: We use derivative
financial instruments to reduce the cash flow variability associated with the
purchase price for a portion of future natural gas purchases associated with our
Gas Distribution operations. Our strategy is to minimize fluctuations in firm
gas sales prices to our regulated firm gas sales customers in our New York and
New Hampshire service territories. Since these derivative instruments are
employed to reduce the variability of the purchase price of natural gas to be
sold to regulated firm gas sales customers, the accounting for these derivative
instruments is subject to SFAS 71 "Accounting for the Effects of Certain Types
of Regulation". Therefore, changes in the market value of these derivatives have
been recorded as a Regulatory Asset or Regulatory Liability on the Consolidated
Balance Sheet. Gains or losses on the settlement of these contracts are
initially deferred and then refunded to or collected from our firm gas sales
customers consistent with regulatory requirements.
The following table sets forth selected financial data associated with these
derivative financial instruments that were outstanding at September 30, 2003.
- ------------------------------------------------------------------------------------------------------------------------------------
Year of Volumes Floor Ceiling Fixed Price Current Price Fair Value
Type of Contract Maturity mmcf ($) ($) ($) ($) ($000)
- ------------------------------------------------------------------------------------------------------------------------------------
Options 2003 2,650 4.00 - 5.00 5.15 - 6.00 - 4.90 - 5.13 (712)
2004 7,420 4.00 - 5.00 5.15 - 6.00 - 4.83 - 5.25 (411)
Swaps 2003 10,710 - - 5.00 - 6.23 4.90 - 5.13 (5,304)
2004 20,530 - - 4.42 - 6.23 4.83 - 5.25 (6,848)
- ------------------------------------------------------------------------------------------------------------------------------------
41,310 (13,275)
- ------------------------------------------------------------------------------------------------------------------------------------
Physically-Settled Commodity Derivative Instruments: Derivative Implementation
Group ("DIG") Issue C15 and C16 of SFAS 133, 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 gas and electric commodity contracts, we
determined that certain contracts for the physical purchase of natural gas
associated with our regulated gas utilities are not exempt as normal purchases
from the requirements of SFAS 133. At September 30, 2003, the fair value of
these contracts was $2.8 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 interest rate
swap agreements 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.
71
These swaps are designated as fair-value hedges and qualify for "short-cut"
hedge accounting treatment under SFAS 133. During the period ended September 30,
2003, we paid our counterparty an interest rate of 6.42%, and as a result, we
realized interest savings of $0.4 million. The fair market value of this
derivative was $1.4 million at September 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
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 have received 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.
In October 2003, we entered into heating-degree day call and put options to
mitigate the effect of fluctuations from normal weather on KEDNE's financial
position and cash flows for the 2003/2004 winter heating season - November 2003
through March 2004. With respect to sold call options, KeySpan will be required
to make a payment of $27,500 per heating degree day to its counterparties when
actual weather experienced during this time frame is above 4,440 heating degree
72
days, which equates to approximately 2% colder than normal weather, based on the
most recent 20-year average for normal weather. The maximum amount KeySpan may
be required to pay on its sold call options is $5.5 million. With respect to
purchased put options, KeySpan will receive a $27,500 per heating degree day
payment from its counterparties when actual weather is below 4,266 heating
degree days, or approximately 2% warmer than normal. The maximum amount KeySpan
may receive on its purchased put options is $11 million. The total premium cost
for these options was $0.4 million. We will account for these derivatives
pursuant to the requirements of EITF 99-2.
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 a credit risk and is actively managed by assessing each counterparty
credit profile and negotiating appropriate levels of collateral and credit
support.
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 September 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.
73
PART II. OTHER INFORMATION
- ---------------------------
Item 1. Legal Proceedings
See Note 8 to the Consolidated Financial Statements "Financial Guarantees and
Contingencies."
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
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.
(b) Reports on Form 8-K
In our report on Form 8-K dated On August 6, 2003, we reported that KeySpan had
issued a press release concerning, among other things, its financial results for
the quarter ended June 30, 2003.
In our report on Form 8-K dated September 26, 2003, we reported that KeySpan had
issued a press release announcing the election of Robert J. Fani as President
and Chief Operating Officer, the election of Steven L. Zelkowitz as President,
Energy Assets and Supply Group and the continued role of Wallace P. Parker Jr.,
as President, Energy Delivery and Customer Relationship Group.
In our report on Form 8-K dated October 15, 2003, we reported that our
subsidiary, KeySpan Generation, LLC had agreed to pay $400,000 to settle a
proceeding in which a jury rendered a verdict against KeySpan Generation, LLC
and other defendants in the amount of $47 million for injuries from asbestos
exposure at generating facilities formerly owned by the Long Island Lighting
Company and others.
- ----------------------
*Filed Herewith
74
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: November 5, 2003 /s/ Gerald Luterman
------------------
Gerald Luterman
Executive Vice President and
Chief Financial Officer
75