UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
Form 10-Q
(Mark One)
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
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EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2002
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OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
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EXCHANGE ACT OF 1934
For the transition period from to
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Commission file number 1-14161
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KEYSPAN CORPORATION
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(Exact name of Registrant as specified in its charter)
New York 11-3431358
- -------------------------------- ------------------------------------
(State or other jurisdiction of (I.R.S. 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)
(Former name, former address and former fiscal year, if changed since last
report)
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. Yes X No
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 April 17, 2002
- --------------------------- ------------------------------
$.01 par value 140,722,725
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 -
March 31, 2002 and December 31, 2001 3
Consolidated Statement of Income -
Three Months Ended March 31, 2002 and 2001 5
Consolidated Statement of Cash Flows -
Three Months Ended March 31, 2002 and 2001 6
Notes to Consolidated Financial Statements 7
Item 2. Management's Discussion and Analysis Of Financial
Condition and Results of Operations 23
Item 3. Quantitative and Qualitative Disclosures
About Market Risk 43
Part II. OTHER INFORMATION
Item 1. Legal Proceedings 46
Item 6. Exhibits and Reports on Form 8-K 47
Signatures 48
2
CONSOLIDATED BALANCE SHEET
(Unaudited)
(In Thousands of Dollars)
March 31, 2002 December 31, 2001
- ------------------------------------------------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents $ 190,701 $ 159,252
Customer accounts receivable 1,576,142 1,344,898
Allowance for uncollectible accounts (86,839) (72,299)
Gas in storage, at average cost 155,043 334,999
Materials and supplies, at average cost 104,548 105,693
Other 90,848 125,944
------------------------- -------------------------
2,030,443 1,998,487
------------------------- -------------------------
Assets Held for Disposal 191,055 191,055
Equity Investments and Other 230,503 223,249
------------------------- -------------------------
Property
Gas 5,783,612 5,704,857
Electric 1,703,568 1,629,768
Other 416,206 400,643
Accumulated depreciation (2,588,247) (2,533,466)
Gas exploration and production, at cost 2,245,842 2,200,851
Accumulated depletion (838,198) (796,722)
------------------------- -------------------------
6,722,783 6,605,931
------------------------- -------------------------
Deferred Charges
Regulatory assets 448,873 458,191
Goodwill, net of amortization 1,785,340 1,782,826
Other 454,473 529,867
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2,688,686 2,770,884
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Total Assets $ 11,863,470 $ 11,789,606
========================= =========================
See accompanying Notes to the Consolidated Financial Statements.
3
CONSOLIDATED BALANCE SHEET
(Unaudited)
(In Thousands of Dollars)
March 31, 2002 December 31, 2001
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LIABILITIES AND CAPITALIZATION
Current Liabilities
Current redemption of long term debt $ 1,478 $ 993
Accounts payable and accrued expenses 761,534 1,091,430
Commercial paper 1,038,503 1,048,450
Dividends payable 63,606 63,442
Taxes accrued 84,676 50,281
Customer deposits 36,460 36,151
Interest accrued 137,836 93,962
-------------------------- ------------------------
2,124,093 2,384,709
-------------------------- ------------------------
Deferred Credits and Other Liabilities
Regulatory liabilities 46,107 39,442
Deferred income tax 784,669 598,072
Postretirement benefits and other reserves 712,158 694,680
Other 185,780 207,992
-------------------------- ------------------------
1,728,714 1,540,186
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Capitalization
Common stock, $.01 par value, authorized
450,000,000 shares; outstanding 140,570,579 and
137,251,386 shares stated at 2,991,307 2,995,797
Retained earnings 602,990 452,206
Other comprehensive income (30,475) 4,483
Treasury stock purchased (527,826) (561,884)
-------------------------- ------------------------
Total common shareholders' equity 3,035,996 2,890,602
Preferred stock 84,077 84,077
Long-term debt 4,693,403 4,697,649
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Total Capitalization 7,813,476 7,672,328
-------------------------- ------------------------
Minority Interest in Subsidiary Companies 197,187 192,383
-------------------------- ------------------------
Total Liabilities and Capitalization $ 11,863,470 $ 11,789,606
========================== ========================
See accompanying Notes to the Consolidated Financial Statements.
4
CONSOLIDATED STATEMENT OF INCOME
(Unaudited)
(In Thousands of Dollars, Except Per Share Amounts)
Three Months Ended Three Months Ended
March 31, 2002 March 31, 2001
- ----------------------------------------------------------------------------------------------------------------------
Revenues
Gas Distribution $ 1,222,966 $ 1,753,644
Electric Services 314,685 343,371
Energy Services 241,559 319,093
Gas Exploration 74,714 132,011
Energy Investments 17,636 26,969
------------------------ -------------------------
Total Revenues 1,871,560 2,575,088
------------------------ -------------------------
Operating Expenses
Purchased gas for resale 649,360 1,197,349
Fuel and purchased power 84,372 143,300
Operations and maintenance 493,563 503,883
Depreciation, depletion and amortization 125,997 131,164
Operating taxes 120,391 141,990
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Total Operating Expenses 1,473,683 2,117,686
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Operating Income 397,877 457,402
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Other Income and (Deductions)
Minority interest (4,431) (15,411)
Other income 12,617 20,113
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Total Other Income 8,186 4,702
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Income Before Interest Charges
and Income Taxes 406,063 462,104
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Interest Charges 72,612 93,303
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Income Taxes
Current (84,159) 110,743
Deferred 202,979 33,944
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Total Income Taxes 118,820 144,687
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Net Income 214,631 224,114
Preferred stock dividend requirements 1,476 1,476
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Earnings from Continuing Operations 213,155 222,638
Income from Discontinued Operations - 661
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Earnings for Common Stock $ 213,155 $ 223,299
======================== =========================
Basic Earnings Per Share from Continuing Operations 1.52 1.63
Basic Earnings Per Share from Discontinued Operations - -
------------------------ -------------------------
Basic Earnings Per Share $ 1.52 $ 1.63
======================== =========================
Diluted Earnings Per Share $ 1.51 $ 1.61
======================== =========================
Average Common Shares Outstanding (000) 140,039 136,961
Average Common Shares Outstanding - Diluted (000) 141,012 138,503
See accompanying Notes to the Consolidated Financial Statements.
5
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
(In Thousands of Dollars)
Three Months Three Months
Ended Ended
March 31, 2002 March 31, 2001
- ---------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net Income $ 214,631 $ 224,114
Adjustments to reconcile net income to net cash
provided by (used in) operating activities
Depreciation, depletion and amortization 125,997 131,164
Deferred income tax 202,979 33,944
Income from equity investments (4,154) (3,956)
Changes in assets and liabilities
Accounts receivable (216,704) (140,655)
Materials and supplies, fuel oil and gas in storage 181,101 215,626
Accounts payable and accrued expenses (295,501) (405,816)
Interest accrued 43,874 43,124
Other 80,326 125,182
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Net Cash Provided by Operating Activities 332,549 222,727
----------------------- ---------------------
Investing Activities
Capital expenditures (244,153) (125,909)
Proceeds from sale of assets - 18,458
Other - (1,268)
----------------------- ---------------------
Net Cash Used in Investing Activities (244,153) (108,719)
----------------------- ---------------------
Financing Activities
Issuance of treasury stock 34,058 30,292
Issuance of long-term debt 10,401 182,000
Payment of long-term debt (25,356) (102,000)
Issuance / (Payment) of commercial paper (9,947) (160,407)
Preferred stock dividends paid (1,476) (1,476)
Common stock dividends paid (62,207) (61,215)
Other (2,420) (461)
----------------------- ---------------------
Net Cash (Used in) Financing Activities (56,947) (113,267)
----------------------- ---------------------
Net increase in Cash and Cash Equivalents $ 31,449 $ 741
======================= =====================
Cash and cash equivalents at beginning of period $ 159,252 $ 83,329
Net increase in cash and cash equivalents 31,449 741
----------------------- ---------------------
Cash and Cash Equivalents at End of Period $ 190,701 $ 84,070
======================= =====================
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"). We operate six
utilities that distribute natural gas to approximately 2.5 million customers in
New York City, Long Island, Massachusetts and New Hampshire, making us the fifth
largest gas distribution company in the United States and the largest in the
Northeast. We also own and operate electric generating plants in Nassau and
Suffolk Counties on Long Island and in Queens County in New York City. 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"). Our
other subsidiaries are involved in gas and oil exploration and production; gas
storage; wholesale and retail gas and electric marketing; appliance service;
heating, ventilation and air conditioning installation and services; large
energy-system ownership, installation and management; engineering services; and
fiber optic services. We also invest and participate in the development of,
natural gas pipelines, electric generation 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 our financial position as of
March 31, 2002, and the results of our operations for the three months ended
March 31, 2002 and March 31, 2001, as well as cash flows for the three months
ended March 31, 2002 and March 31, 2001. The accompanying financial statements
should be read in conjunction with the consolidated financial statements and
notes included in our Annual Report on Form 10-K for the year ended December 31,
2001. The December 31, 2001 financial statement information has been derived
from the 2001 audited financial statements. Income from interim periods may not
be indicative of future results. Certain reclassifications were made to conform
prior period financial statements with the current period financial statement
presentation. Other than as noted, adjustments were of a normal, recurring
nature.
Basic earnings per share ("EPS") is calculated by dividing net income 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 net income, as adjusted, by the sum of the weighted average number
of shares of common stock outstanding plus all potentially dilutive securities.
7
Under the requirements of Statement of Financial Accounting Standards (SFAS")
No. 128, "Earnings Per Share" our basic and diluted EPS are as follows:
(In Thousands of Dollars, Except Per Share)
- -------------------------------------------------------------------------------------------------------------------------------
Three Months Ended Three Months Ended
March 31, 2002 March 31, 2001
- ---------------------------------------------------------------------- --------------------------- ---------------------------
Earnings for common stock $ 213,155 $ 223,299
Interest savings on convertible preferred stock 142 142
Houston Exploration dilution (options) (96) (569)
- ---------------------------------------------------------------------- --------------------------- ---------------------------
Earnings for common stock - adjusted 213,201 222,872
- ---------------------------------------------------------------------- --------------------------- ---------------------------
Weighted average shares outstanding (000) 140,039 136,961
Add dilutive securities:
Options 729 1,298
Convertible preferred stock 244 244
- ---------------------------------------------------------------------- --------------------------- ---------------------------
Total weighted average shares outstanding - assuming dilution 141,012 138,503
- ---------------------------------------------------------------------- --------------------------- ---------------------------
Basic Earnings (Loss) Per Share $ 1.52 $ 1.63
- ---------------------------------------------------------------------- --------------------------- ---------------------------
Diluted Earnings Per Share $ 1.51 $ 1.61
- ---------------------------------------------------------------------- --------------------------- ---------------------------
2. BUSINESS SEGMENTS
We have four reportable segments: Gas Distribution, Electric Services, Energy
Services and Energy Investments.
The Gas Distribution segment consists of our six gas distribution subsidiaries.
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 six to twelve years.
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. We sell all of the energy, capacity and
ancillary services related to the Ravenswood facility to the New York
Independent System Operator ("NYISO") energy markets. Currently, our primary
electric generation customers are LIPA and the NYISO energy markets.
8
The Energy Services segment includes companies that provide energy-related
services to customers located within the New York City metropolitan area, as
well as, Rhode Island, Pennsylvania, Massachusetts and New Hampshire, through
the following three lines of business: (i) Home Energy Services, which provides
residential customers with service and maintenance of energy systems and
appliances, as well as the retail marketing of natural gas and electricity to
residential and small commercial customers; (ii) Business Solutions, which
provides professional engineering-consulting and design of energy systems for
commercial and industrial customers, including installation of plumbing,
heating, ventilation and air conditioning equipment; and (iii) Fiber Optic
Services, which provides various services to carriers of voice and data
transmission on Long Island and in New York City.
The Energy Investments segment consists of our gas exploration and production
investments, as well as certain other domestic and international energy-related
investments. Our gas exploration and production subsidiaries are engaged in gas
and oil exploration and production, and the development and acquisition of
domestic natural gas and oil properties. These investments consist of our 67%
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.
Subsidiaries in this segment also hold a 20% equity interest in the Iroquois Gas
Transmission System LP, a pipeline that transports Canadian gas supply to
markets in the Northeastern United States; a 50% interest in the Premier
Transmission Pipeline and a 24.5% interest in Phoenix Natural Gas, both in
Northern Ireland; and investments in certain midstream natural gas assets in
Western Canada through KeySpan Canada. With the exception of KeySpan Canada,
which is consolidated in our financial statements, these subsidiaries are
accounted for under the equity method. Accordingly, equity income from these
investments is reflected in Other Income and (Deductions) in the Consolidated
Statement of Income.
The accounting policies of the segments are the same as those used for the
preparation of the Consolidated Financial Statements. Our segments are strategic
business units that are managed separately because of their different operating
and regulatory environments. Operating results of our segments are evaluated by
management on a earnings before interest and taxes ("EBIT") basis. At March 31,
2002, the total assets of each reportable segment have not changed materially
from those levels reported at December 31, 2001. In the first quarter of 2002,
we reclassified KeySpan Energy Supply, a subsidiary that provides management and
procurement services for fuel supply and management of energy sales, primarily
for and from the Ravenswood facility, from the Energy Services segment to the
Electric Services segment. We also reclassified the first quarter of 2001to
reflect this change. Due to the anticipated sale of Midland Enterprises Inc.,
our marine barge business, this subsidiary is reported as discontinued
operations in 2002 and 2001. The reportable segment information, excluding
Midland, is as follows:
9
(In Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------------------------------
Energy Investments
------------------------------
Gas Electric Energy Gas Exploration Other
Distribution Services Services and Production Investments Eliminations Consolidated
- -------------------------- --------------- ------------- ---------- ------------------ --------------- -------------- --------------
Three Months Ended
March 31, 2002
Unaffiliated Revenue 1,222,966 314,685 241,559 74,714 17,636 - 1,871,560
Intersegment Revenue - 25 - - - (25) -
Earnings Before Interest 329,654 65,647 (9,198) 15,672 4,894 (606) 406,063
and Taxes
Three Months Ended
March 31, 2001
Unaffiliated Revenue 1,753,644 343,371 319,093 132,011 26,969 - 2,575,088
Intersegment Revenue - 25 - - - (25) -
Earnings Before Interest 330,681 65,581 (6,379) 65,516 9,253 (2,548) 462,104
and Taxes
- -------------------------- --------------- ------------- ---------- ------------------ -------------- -------------- --------------
Eliminating items include intercompany interest income and expense, the
elimination of certain intercompany accounts, as well as activities of our
corporate and administrative areas.
Electric Services revenues from the NYISO and LIPA of $314.7 million and $343.4
million for the three months ended March 31, 2002 and 2001 represent
approximately 17% and 13% of our consolidated revenues, respectively.
10
3. COMPREHENSIVE INCOME
The table below indicates the components of comprehensive income.
(In Thousands of Dollars)
- --------------------------------------------------------------------------------------------------------------------------
Three Months Three Months
Ended Ended
March 31, 2002 March 31, 2001
- --------------------------------------------------------- ----------------------------- --------------------------------
Net Income $ 214,631 $ 224,775
- --------------------------------------------------------- ----------------------------- --------------------------------
Other comprehensive income (loss), net of tax
Net (gains) losses on derivative instruments (7,287) 13,608
Reclassification adjustment for other gains
reclassified to net income - (3,242)
Foreign currency translation adjustments (1,713) (9,682)
Unrealized gains ( losses) on marketable securities (1,041) 2,617
Accrued unfunded pension obligation (1,132) -
Unrealized gains (losses) on derivative
financial instruments (23,785) (12,657)
- --------------------------------------------------------- ----------------------------- --------------------------------
Other comprehensive income (loss) (34,958) (9,356)
- --------------------------------------------------------- ----------------------------- --------------------------------
Comprehensive income $ 179,673 $ 215,419
- --------------------------------------------------------- ----------------------------- --------------------------------
Related tax (benefit) expense
Net (gains) losses on derivative instruments (3,924) 7,328
Reclassification adjustment for other gains
reclassified to net income - (1,746)
Foreign currency translation adjustments (923) (5,213)
Unrealized gains (losses) on marketable securities (560) 1,409
Accrued unfunded pension obligation (610) -
Unrealized gains (losses) on derivative
financial instruments (12,807) (6,816)
- --------------------------------------------------------- ----------------------------- --------------------------------
Total tax expense (benefit) $ (18,824) $ (5,038)
- --------------------------------------------------------- ----------------------------- --------------------------------
4. ENVIRONMENTAL MATTERS
New York Sites. Within the State of New York we have identified 28 manufactured
gas plant ("MGP") sites and related facilities which were historically owned or
operated by KeySpan subsidiaries or such companies' predecessors. Twenty seven
of these former sites, some of which are no longer owned by us, were associated
with our regulated gas businesses, KEDNY and KEDLI, and have been identified to
both the Department of Environmental Conservation ("DEC") for inclusion on
appropriate site inventories and listing with the New York Public Service
Commission ("NYPSC"). The remaining former MGP site was acquired when we
purchased the Ravenswood facility from Consolidated Edison Company of New York.
Thirteen sites are currently the subject of Administrative Orders on Consent
("ACOs") with the DEC.
11
We presently estimate the remaining environmental cleanup cost of our New York
MGP sites will be $154.2 million, which amount has been accrued by us as a
reasonable estimate of probable cost for known sites. Expenditures incurred to
date by us with respect to these MGP-related activities total $37.1 million.
With respect to remediation costs, the KEDNY and KEDLI rate plans generally
provide for the recovery of investigation and remediation costs. Under prior
rate orders, KEDNY has offset certain monies due to ratepayers against its
estimated environmental cleanup costs for MGP sites. At March 31, 2002, we have
reflected a regulatory asset of $122.5 million for our New York/Long Island MGP
sites.
We are also responsible for environmental obligations associated with the
Ravenswood electric generating facility. The extent of our liability does not
include liabilities arising from disposal of waste at off-site locations prior
to the acquisition closing and any monetary fines arising from Consolidated
Edison's pre-closing conduct. Based on information currently available for
environmental contingencies related to the Ravenswood facility acquisition, we
have accrued a $5 million liability.
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.
We may have or share responsibility under applicable environmental laws for the
remediation of 10 MGP sites and related facilities associated with the historic
operations of EnergyNorth. EnergyNorth has received notice of its potential
responsibility for contamination at two former MGP sites and, together with
other potentially responsible parties, has received notice of potential
responsibility for contamination associated with four other sites.
We presently estimate the remaining cost of New England MGP-related
environmental cleanup activities will be $52.8 million, which amount has been
accrued by us as a reasonable estimate of probable cost for known sites.
Expenditures incurred since November 8, 2000 with respect to these MGP-related
activities total $14.7 million.
The Massachusetts Department of Telecommunications and Energy and the New
Hampshire Public Utilities Commission have issued rate orders which provide for
the recovery of site investigation and remediation costs, and accordingly, at
March 31, 2002, we have reflected a regulatory asset of $63.6 million for the
KEDNE MGP sites. Colonial Gas Company and Essex Gas Company are not subject to
the provisions of Statement of Financial Accounting Standards ("SFAS") 71
"Accounting for the Effects of Certain Types of Regulation" and therefore have
recorded no regulatory assets. However, rate plans currently in effect for these
subsidiaries provide for the recovery of investigation and remediation costs.
12
Eastern Enterprises Sites. We are aware of three non-utility sites associated
with the historic operations of Eastern Enterprises, for which we may have or
share environmental remediation responsibility or ongoing maintenance: the
former Philadelphia Coke site located in Pennsylvania; the former Connecticut
Coke site located in New Haven, Connecticut; and the former Everett Coal Tar
Processing Facility (the "Everett Facility") located in Massachusetts.
The Everett Facility is the principle site. Honeywell International, Inc. and
Beazer East, Inc. (both former owners and operators of the Everett Facility),
together with KeySpan have entered into an ACO with the Massachusetts Department
of Environmental Protection for the investigation and development of a remedial
response plan for the site.
We presently estimate the remaining cost of our environmental cleanup activities
for the three non- utility sites will be approximately $42.1 million, which
amount has been accrued by us a reasonable estimate of probable costs for known
sites; however the actual remediation cost for these sites may be substantially
higher. Expenditures incurred since November 8, 2000 with respect to these sites
total $0.4 million.
We believe that in the aggregate, the accrued liability for investigation and
remediation of the New York and New England sites and related facilities
identified above are reasonable estimates of likely cost within a range of
reasonable, foreseeable costs. We may be required to investigate and, if
necessary, remediate each of these, or other currently unknown, former sites and
related facility sites, the cost of which is not presently determinable but may
be material to our financial position, results of operations or liquidity.
Remediation costs for each site may be materially higher than noted, depending
upon remediation experience, selected end use for each site, and actual
environmental conditions encountered.
See our Annual Report on Form 10-K for the year ended December 31, 2001 Note 8
to those Consolidated Financial Statements "Contractual Obligations and
Contingencies" for further information on environmental matters.
5. LONG-TERM DEBT
At December 31, 2001 we had an existing $1 billion shelf registration statement
on file with the Securities and Exchange Commission ("SEC"), with $500 million
available for issuance. In February 2002, we updated our shelf registration for
the issuance of an additional $1.2 billion of securities, thereby giving us the
ability to issue up to $1.7 billion of debt, equity or various forms of
preferred stock. Currently, we have the authority under PUHCA to issue up to
$1.0 billion of this amount. We have filed an application with the SEC for
additional authorization.
13
6. DERIVATIVE FINANCIAL INSTRUMENTS
Commodity Contracts and Electric Derivative Instruments: From time to time we
utilize derivative financial instruments, such as futures, options and swaps,
for the purpose of hedging exposure to commodity price risk and to fix the
selling price on a portion of our peak electric energy sales. Our hedging
objectives and strategies have remained substantially unchanged from year-end.
Houston Exploration utilizes collars, as well as, over- the- counter ("OTC")
swaps to hedge future sales prices on a portion of its natural gas production to
achieve a more predictable cash flow and reduce its exposure to adverse price
fluctuations of natural gas. As of March 31 2002, Houston Exploration has hedged
approximately 65% of its estimated 2002 yearly production and 20% of its
estimated 2003 yearly production. Houston Exploration uses standard New York
Mercantile Exchange ("NYMEX") futures prices and published volatility in its
Black-Scholes calculation to value its outstanding derivatives. Houston
Exploration recorded a benefit of $17.0 million in Revenues for derivative
instruments that settled during the first quarter of 2002.
We also employ standard NYMEX gas futures contracts, as well as oil swap
derivative contracts to fix the purchase price for a portion of the fuel used at
the Ravenswood facility. We use 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. These contracts extend through 2003. During the
first quarter of 2002, we realized a loss of $3.5 million on the settlement of
derivative instruments and recorded this loss as an increase to Fuel and
Purchased Power expense.
Our gas and electric marketing subsidiary, as well as our gas distribution
operations, have fixed rate gas sales contracts and utilize standard NYMEX
futures contracts to lock-in a price for future natural gas purchases. We use
standard NYMEX futures prices to value the outstanding contracts. During the
first quarter of 2002, we realized a loss of $7.8 million on derivatives that
settled during this period and recorded this loss as an increase to Purchased
Gas for Resale.
We have also engaged in the use of derivative swap instruments to fix the
selling price on a portion of our estimated 2002 summer and winter peak electric
energy sales from the Ravenswood facility to protect against a potential
degradation in market prices. We have financially settled tolling arrangements
under which we have effectively "locked-in" a profit on a portion of 2002 sales.
We currently have hedge positions for approximately 50% of our estimated 2002
summer peak electric profits from the Ravenswood facility. We use NYISO-location
zone published indices and standard NYMEX prices to value these outstanding
derivatives. During the first quarter of 2002, we realized a gain of $5.6
million on the settlement of certain derivative instruments and recorded this
gain in Revenues. Further, KeySpan Canada employs electric swap contracts to
lock-in the purchase price on the purchase of electricity needed to operate its
gas processing plants. These contracts are not exchange traded and we use local
published indices to value these outstanding options. We realized a loss of $0.4
million on the settlement of certain swap derivative instruments.
All of our commodity contracts and electric derivative instruments detailed
above are cash-flow hedges and qualify for hedge accounting. Periodic changes in
the market value of derivatives which meet the definition of a cash-flow hedge
are recorded as comprehensive income, subject to effectiveness, and then
included in net income to match the underlying hedged transactions.
14
The following tables set forth selected financial data associated with these
derivative financial instruments noted above that were outstanding at March 31,
2002.
Year of Volumes Fixed Current Fair Value
Type of Contract Maturity mmcf Floor $ Ceiling $ Price $ Price $ ($000)
- ------------------------- ------------ -------------- ------------- -------------- --------------- --------------- -----------
Gas
Collars 2002 44,000 3.56 5.14 - 3.28 - 3.87 13,869
2003 7,300 3.30 4.07 - 3.49 - 3.97 (1,023)
Swaps -Short Natural Gas 2002 8,250 - - 3.01 3.28 - 3.87 (3,674)
2003 14,600 - - 3.19 3.49 - 3.97 (7,043)
Swaps - Long Natural Gas 2002 6,920 - - 2.24 - 3.72 3.28 - 3.87 2,460
2003 2,070 - - 3.08 - 3.77 3.49 - 3.97 613
- ------------------------- ------------ -------------- ------------- -------------- --------------- --------------- -----------
83,140 5,202
- ------------------------- ------------ -------------- ------------- -------------- --------------- --------------- -----------
Year of Volumes Fair Value
Type of Contract Maturity Barrels Fixed Price $ Current Price $ ($000)
- ------------------------------ ----------------- ----------------- ------------------------ ---------------------- -------------
Oil
Swaps - Long Fuel Oil 2002 191,438 19.85 - 26.40 22.70 - 24.55 420
2003 345,389 20.02 - 26.72 21.84 - 23.06 132
- ------------------------------ ----------------- ----------------- ------------------------ ---------------------- -------------
536,827 552
- ------------------------------ ----------------- ----------------- ------------------------ ---------------------- -------------
Year of Current Estimated Fair Value
Type of Contract Maturity MWh Fixed Profit /Price $ Price $ Profit $ ($000)
- ----------------------- -------------- ---------------- ------------------------- ------------- ----------------- -------------
Electricity
Tolling Arrangements 2002 624,000 4.75 - 47.50 - 1.00 - 51.62 825
Swaps 2002 58,752 54.84 - 57.03 31.39 - (1,380)
2003 70,080 54.84 - 57.03 29.69 - (1,765)
- ----------------------- -------------- ---------------- ------------------------- ------------- ----------------- -------------
752,832 (2,320)
- ----------------------- -------------- ---------------- ------------------------- ------------- ----------------- -------------
Non-firm Gas Sales Derivative Instruments: Utility tariffs applicable to certain
large-volume customers permit gas to be sold at prices established monthly
within a specified range expressed as a percentage of prevailing alternate fuel
oil prices. We use gas swap contracts, with offsetting positions in oil swap
contracts of equivalent energy value, with third parties to hedge the cash flow
variability of specified portions of gas purchases and sales. All positions that
were outstanding at December 31, 2001 settled during the first quarter of 2002.
15
The final settlement of these positions during the first quarter of 2002 did not
have a material effect on our results of operations. We intend to enter into
additional derivative instruments of this nature during 2002 if market
conditions so warrant.
Firm Gas Sales Derivative Instruments - Regulated Utilities: We utilize
derivative financial instruments to "lock-in" the purchase price for a portion
of our future natural gas purchases. Our strategy is to minimize fluctuations in
firm gas sales prices to our regulated firm gas sales customers in our New York
service territory. All positions that were outstanding at December 31, 2001
settled during the first quarter of 2002. Since these derivative instruments
were not designed as hedges and were employed to support our gas sales prices to
regulated firm gas sales customers, the accounting for these derivative
instruments was subject to SFAS 71. Therefore, changes in the market value of
these derivatives were recorded as a Regulatory Asset or Regulatory Liability on
the Consolidated Balance Sheet. Gains or losses on the settlement of these
contracts were initially deferred and then refunded to or collected from our
firm gas sales customers during the appropriate winter heating season consistent
with regulatory requirements. We intend to enter into additional derivative
instruments of this nature for the remainder of 2002 if market conditions so
warrant.
Interest Rate Swaps: We also have interest rate swap agreements in which
approximately $1.4 billion of fixed rate debt have effectively been changed to
floating rate debt. For the term of the agreements, we will receive the fixed
coupon rate associated with these bonds and pay the counter parties a variable
interest rate that is reset on a weekly and/or quarterly basis as appropriate.
These bonds are fair- value hedges and qualify for hedge accounting. The swap
agreements associated with the Medium Term Notes, as displayed in the table
below, qualify for "short-cut" hedge accounting treatment under SFAS 133. The
fair-value hedge associated with a Gas Facilities Revenue Bond does not qualify
for "short-cut" hedge accounting treatment. Through the utilization of our
interest rate swap agreements, we reduced recorded interest expense by $11.6
million during the first quarter of 2002. Further, we recorded a first quarter
benefit of $1.3 million as a result of the fair value measurements. The fair
values of these derivative instruments are provided to us by third party
appraisers and represent the present value of future cash-flows based on a
forward interest rate curve for the life of the derivative instrument. The fair
values at March 31, 2002, as indicated in the table below, reflect an assumption
of higher interest rates in the future.
16
The table below summarizes selected financial data associated with these
derivative financial instruments that were outstanding at March 31, 2002.
Average
Maturity Date of Notional Amount Fixed Rate Variable Rate Fair Value
Bond Swaps ($000) Received Paid ($000)
- ---------------------------------- ------------------- -------------------- ---------------- ------------------ ----------------
Gas Facilities Revenue Bonds 2024 90,000 5.540% 1.270% 10
Medium Term Notes 2010 500,000 7.625% 4.320% (6,327)
Medium Term Notes 2006 500,000 6.150% 3.680% (13,985)
Medium Term Notes 2023 270,000 8.200% 3.390% (16,377)
- ---------------------------------- ------------------- -------------------- ---------------- ------------------ ----------------
1,360,000 (36,679)
- ---------------------------------- ------------------- -------------------- ---------------- ------------------ ----------------
Additionally, we have a swap agreement that effectively exchanges $270 million
of outstanding commercial paper with fixed-rate debt. This swap is a cash-flow
hedge and qualifies for hedge accounting under SFAS 133. We recorded additional
interest expense associated with this swap of $0.7 million during the first
quarter of 2002 and there was no impact on earnings from ineffectiveness. At
March 31, 2002, the fair value of this swap, which was reflected as an asset,
was $0.4 million.
Weather Derivative: The utility tariffs associated with our New England gas
distribution operations do not contain a weather normalization clause. As a
result, fluctuations from normal weather may have a significant positive or
negative effect on the results of these operations. To mitigate the effect of
weather fluctuations on our financial position and cash flows, we entered into a
weather swap in October 2001. This derivative hedged approximately 15% of our
weather related risk for the November 2001 - March 2002 winter season. In
January 2002, we settled all our remaining weather derivatives and recorded a
gain of $0.3 million in Other Income. We intend to enter into additional
derivative instruments of this nature during 2002 if market conditions so
warrant.
We are exposed to credit risk in the event of nonperformance by counter parties
to derivative contracts, as well as nonperformance by the counter parties of the
transactions hedged against. We believe that the credit risk related to the
above noted contracts is no greater than that associated with the primary
contracts which they hedge, as these contracts are with major investment grade
financial institutions, and that elimination of the price risk lowers overall
business risk.
7. WORKFORCE REDUCTION PROGRAMS
As a result of the Eastern acquisition, we implemented early retirement and
severance programs in an effort to reduce our workforce. In 2000, we recorded a
$22.7 million liability associated with these programs. This severance program
is targeted to reduce the workforce by 500 employees and will continue through
2002. In 2001, we reduced this liability by $4.1 million as a result of lower
than anticipated costs per employee. At March 31, 2002, we paid $12.4 million
for these programs and had a remaining liability of $6.2 million.
17
8. RECENT ACCOUNTING PRONOUNCEMENTS
On January 1, 2002, we adopted SFAS 141, "Business Combinations", and SFAS 142
"Goodwill and Other Intangible Assets". The key concepts from the two
interrelated Statements include mandatory use of the purchase method when
accounting for business combinations, discontinuance of goodwill amortization, a
revised framework for testing goodwill impairment at a "reporting unit" level,
and new criteria for the identification and potential amortization of other
intangible assets. Other changes to existing accounting standards involve the
amount of goodwill to be used in determining the gain or loss on the disposal of
assets, and a requirement to test goodwill for impairment at least annually. The
annual impairment test is to be performed within six months of adopting SFAS 142
with any resulting impairment reflected as either a change in accounting
principle, or a charge to operations in the financial statements. We have
completed our analysis for our Gas Distribution and Energy Services reporting
units, determining that no impairment exists. The results of our analysis on our
Energy Investments reporting units is not complete at this time, and we are
unable to determine the impact, if any, this analysis may have on our results of
operations or financial condition.
For the three months ended March 31, 2001, goodwill amortization was recorded in
each segment as follows: Gas Distribution $8.9 million; Energy Services $2.1
million; Energy Investments $0.5 million; and at the Parent holding company
level for $1.1 million. As required by SFAS 142, below is a reconciliation of
reported net income for the three months ended March 31, 2001 and pro-forma net
income, for the same period, adjusted for the discontinuance of goodwill
amortization.
Three Months Three Months
Ended Ended
March 31, 2002 March 31, 2001
- ------------------------------------------- ---------------------------- ----------------------------
Earnings available for common stock $ 213,155 $ 222,638
Add back: goodwill amortization - 12,551
- ------------------------------------------- ---------------------------- ----------------------------
Adjusted net income $ 213,155 $ 235,189
- ------------------------------------------- ---------------------------- ----------------------------
Basic earnings per share $ 1.52 $ 1.63
Add back: goodwill amortization - 0.09
- ------------------------------------------- ---------------------------- ----------------------------
Adjusted basic earnings per share $ 1.52 $ 1.72
- ------------------------------------------- ---------------------------- ----------------------------
Diluted earnings per share $ 1.51 $ 1.61
Add back: goodwill amortization - 0.09
- ------------------------------------------- ---------------------------- ----------------------------
Adjusted diluted earnings per share $ 1.51 $ 1.70
- ------------------------------------------- ---------------------------- ----------------------------
18
In July of 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations". The Standard requires entities to record the fair value of a
liability for an asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity will capitalize a
cost by increasing the carrying amount of the related long-lived asset. Over
time, the liability is accreted to its then present value, and the capitalized
cost is depreciated over the useful life of the related asset. Upon settlement
of the liability, an entity either settles the obligation for its recorded
amount or incurs a gain or loss upon settlement. The standard is effective for
fiscal years beginning after June 15, 2002, with earlier application encouraged.
We are currently evaluating the impact, if any, that this Statement may have on
our results of operations and financial condition.
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets,"
was effective January 1, 2002, and addresses accounting and reporting for the
impairment or disposal of long-lived assets. SFAS No. 144 supersedes SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of" and APB Opinion No. 30, "Reporting the Results of
Operations-Reporting the Effects of Disposal of a Segment of a Business." SFAS
No. 144 retains the fundamental provisions of SFAS No. 121 and expands the
reporting of discontinued operations to include all components of an entity with
operations that can be distinguished from the rest of the entity and that will
be eliminated from the ongoing operations of the entity in a disposal
transaction. As of March 31, 2002, implementation of this Statement did not have
a significant effect on our results of operations and financial condition.
9. KEYSPAN GAS EAST CORPORATION SUMMARY FINANCIAL INFORMATION
KEDLI, a wholly owned subsidiary of KeySpan, established a program for the
issuance, from time to time, of up to $600 million aggregate principal amount of
medium term notes, which are unconditionally guaranteed by us. 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 15, 2008. The following condensed financial statements are required to
be disclosed by the SEC and are those of KEDLI and KeySpan as guarantor of the
medium term notes.
19
Statement of Income
(In Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------------------------------
Three Months Ended March 31, 2002 Three Months Ended March 31, 2001
- --------------------- -------------------------------------------------------------------- ---------------------------------------
Guarantor KEDLI Eliminations Consolidated Guarantor KEDLI Eliminations Consolidated
- ---------------------------------- ----------- ------------ ------------- ------------ ---------- -------------- -------------
Revenues $ 1,552,613 $ 318,947 $ - $ 1,871,560 $ 2,144,590 $ 430,498 $ - $ 2,575,088
------------- ----------- ------------ ------------- ------------ ---------- -------------- -------------
Operating Expenses
Purchased gas 506,493 142,867 - 649,360 939,219 258,130 - 1,197,349
Fuel and purchased
power 84,372 - - 84,372 143,300 - - 143,300
Operations and
maintenance 481,562 12,001 - 493,563 488,739 15,144 - 503,883
Intercompany expense (18,209) 18,209 - - (21,544) 21,544 - -
Depreciation and
amortization 105,756 20,241 - 125,997 112,134 19,030 - 131,164
Operating taxes 95,005 25,386 - 120,391 112,004 29,986 - 141,990
------------- ----------- ------------ ------------- ------------ ---------- -------------- -------------
Total Operating
Expenses 1,254,979 218,704 - 1,473,683 1,773,852 343,834 - 2,117,686
------------- ----------- ------------ ------------- ------------ ---------- -------------- -------------
Operating Income 297,634 100,243 - 397,877 370,738 86,664 - 457,402
Other Income and
(Deductions) 10,455 2,902 (5,171) 8,186 9,279 2,991 (7,568) 4,702
------------- ----------- ------------ ------------- ------------ ---------- -------------- -------------
Income Before
Interest Charges
and Income Taxes 308,089 103,145 (5,171) 406,063 380,017 89,655 (7,568) 462,104
Interest Expense 62,581 15,202 (5,171) 72,612 83,631 17,240 (7,568) 93,303
Income Taxes 81,739 37,081 - 118,820 119,636 25,051 - 144,687
------------- ----------- ------------ ------------- ------------ ---------- -------------- -------------
Earnings Available
for Common Stock $ 163,769 $ 50,862 $ - $ 214,631 $ 176,750 $ 47,364 $ - $ 224,114
============= =========== ============ ============= ============ ========== ============== =============
20
Balance Sheet
(In Thousands of dollars)
- ----------------------------------------------------------------------------------------------------------------------------------
March 31, 2002 December 31, 2001
- ----------------------------------------------------------------------------------------------------------------------------------
Guarantor KEDLI Eliminations Consolidated Guarantor KEDLI Eliminations Consolidated
- --------------------------- ----------- ----------- ------------- ------------ ----------- ----------- ------------- ------------
ASSETS
Current Assets
Cash and temporary cash
investments $ 190,701 $ - $ - $ 190,701 $ 159,252 $ - $ - $ 159,252
Accounts receivable, net 1,547,282 169,195 (227,174) 1,489,303 1,540,082 233,013 (500,496) 1,272,599
Other current assets 225,670 124,769 - 350,439 454,319 112,317 - 566,636
- --------------------------- ----------- ----------- ------------- ------------ ----------- ----------- ------------- ------------
1,963,653 293,964 (227,174) 2,030,443 2,153,653 345,330 (500,496) 1,998,487
- --------------------------- ----------- ----------- ------------- ------------ ----------- ----------- ------------- ------------
Assets Held for Disposal 191,055 - - 191,055 191,055 - - 191,055
Equity Investments 763,365 - (532,862) 230,503 756,111 - (532,862) 223,249
- --------------------------- ----------- ----------- ------------- ------------ ----------- ----------- ------------- ------------
Property
Gas 4,124,564 1,659,048 - 5,783,612 4,074,894 1,629,963 - 5,704,857
Other 4,365,616 - - 4,365,616 4,231,262 - - 4,231,262
Accumulated depreciation
and depletion (3,124,232) (302,213) - (3,426,445) (3,035,788) (294,400) - (3,330,188)
- --------------------------- ----------- ----------- ------------- ------------ ----------- ----------- ------------- ------------
5,365,948 1,356,835 - 6,722,783 5,270,368 1,335,563 - 6,605,931
- --------------------------- ----------- ----------- ------------- ------------ ----------- ----------- ------------- ------------
Deferred Charges 2,503,757 184,929 - 2,688,686 2,571,029 199,855 - 2,770,884
- --------------------------- ----------- ----------- ------------- ------------ ----------- ----------- ------------- ------------
Total Assets $10,787,778 $1,835,728 $ (760,036) $11,863,470 $10,942,216 $1,880,748 $ (1,033,358) $11,789,606
=========== =========== ============= ============ =========== ========== ============= ============
LIABILITIES AND
CAPITALIZATION
Current Liabilities
Accounts payable
and accrued expenses $ 683,922 $ 77,612 $ - $ 761,534 $975,873 $ 115,557 $ - $ 1,091,430
Commercial paper 1,038,503 - - 1,038,503 1,048,450 - - 1,048,450
Other current
liabilities 241,433 82,623 - 324,056 220,985 23,844 - 244,829
- --------------------------- ----------- ----------- ------------- ------------ ----------- ----------- ------------- ------------
1,963,858 160,235 - 2,124,093 2,245,308 139,401 - 2,384,709
- --------------------------- ----------- ----------- ------------- ------------ ----------- ----------- ------------- ------------
Intercompany Accounts
Payable - 51,270 (51,270) - - 324,592 (324,592) -
- --------------------------- ----------- ----------- ------------- ------------ ----------- ----------- ------------- ------------
Deferred Credits and
Other Liabilities
Deferred income tax 612,320 172,349 - 784,669 593,300 4,772 - 598,072
Other deferred credits
and liabilities 854,564 89,481 - 944,045 841,662 100,452 - 942,114
- --------------------------- ----------- ----------- ------------- ------------ ----------- ----------- ------------- ------------
1,466,884 261,830 - 1,728,714 1,434,962 105,224 - 1,540,186
- --------------------------- ----------- ----------- ------------- ------------ ----------- ----------- ------------- ------------
Capitalization
Common shareholders'
equity 2,907,369 661,489 (532,862) 3,035,996 2,812,837 610,627 (532,862) 2,890,602
Preferred stock 84,077 - - 84,077 84,077 - - 84,077
Long-term debt 4,168,403 700,904 (175,904) 4,693,403 4,172,649 700,904 (175,904) 4,697,649
- --------------------------- ----------- ----------- ------------- ------------ ----------- ----------- ------------- ------------
Total Capitalization 7,159,849 1,362,393 (708,766) 7,813,476 7,069,563 1,311,531 (708,766) 7,672,328
- --------------------------- ----------- ----------- ------------- ------------ ----------- ----------- ------------- ------------
Minority Interest in
Subsidiary Companies 197,187 - - 197,187 192,383 - - 192,383
- --------------------------- ----------- ----------- ------------- ------------ ----------- ----------- ------------- ------------
Total Liabilities and
Capitalization $ 10,787,778 $ 1,835,728 $(760,036) $ 11,863,470 $10,942,216 $1,880,748 $(1,033,358) $11,789,606
=========== =========== ============= ============ =========== =========== ============= ============
21
Statement of Cash Flows (In Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------------------------------
Three Months Ended March 31, 2002 Three Months Ended March 31, 2001
- ------------------------------------ --------------------------------------------- -----------------------------------------------
Guarantor KEDLI Consolidated Guarantor KEDLI Consolidated
- ----------------------------------- --------------- ----------- ---------------- ---------------- ----------- ----------------
Operating Activities
Net Cash Provided by
Operating Activities $ 30,059 $ 302,490 $ 332,549 $ 161,893 $ 60,834 $ 222,727
-------------- ----------- ---------------- ---------------- ----------- ----------------
Investing Activities
Capital expenditures (214,985) (29,168) (244,153) (114,218) (11,691) (125,909)
Other - - - 17,190 - 17,190
-------------- ----------- ---------------- ---------------- ----------- ----------------
Net Cash Used in
Investing Activities (214,985) (29,168) (244,153) (97,028) (11,691) (108,719)
-------------- ----------- ---------------- ---------------- ----------- ----------------
Financing Activities
Issuance of treasury stock 34,058 - 34,058 30,292 - 30,292
Issuance of long-term debt 10,401 - 10,401 57,000 125,000 182,000
Payment of long-term debt (25,356) - (25,356) (102,000) - (102,000)
Payment of commercial paper (9,947) - (9,947) (160,407) - (160,407)
Preferred stock dividends paid (1,476) - (1,476) (1,476) - (1,476)
Common stock dividends paid (62,207) - (62,207) (61,215) - (61,215)
Net intercompany accounts payable 273,322 (273,322) - 174,143 (174,143) -
Other (2,420) - (2,420) (461) - (461)
-------------- ----------- ---------------- ---------------- ----------- ----------------
Net Cash Provided by
(Used in) Financing Activities $ 216,375 $ (273,322) $ (56,947) (64,124) (49,143) (113,267)
-------------- ----------- ---------------- ---------------- ----------- ----------------
Net Increase
in Cash and Cash Equivalents $ 31,449 $ - $ 31,449 $ 741 $ - $ 741
============== =========== ================ ================ =========== ================
Cash and Cash Equivalents
at Beginning of Period $ 159,252 $ - $ 159,252 $ 83,329 $ - $ 83,329
Net Increase
in Cash and Cash Equivalents $ 31,449 $ - $ 31,449 $ 741 $ - $ 741
-------------- ----------- ---------------- ---------------- ----------- ----------------
Cash and Cash Equivalents
at End of Period $ 190,701 $ - $ 190,701 $ 84,070 $ - $ 84,070
============== =========== ================ ================ =========== ================
22
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 months
ended March 31, 2002, compared to the three months ended March 31, 2001.
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.
Consolidated earnings from continuing operations for the three months ended
March 31, 2002 were $213.2 million, or $1.52 per share, compared to earnings
from continuing operations of $222.6 million, or $1.63 per share for the same
period last year. Average common shares outstanding for the quarter ended March
31, 2002 increased 2.2 % compared to the same period last year reflecting the
re-issuance of shares held in treasury pursuant to dividend reinvestment and
employee benefit plans. This increase in average common shares outstanding
reduced first quarter 2002 earnings per share by $0.04 compared to the
corresponding period in 2001.
On January 24, 2002, we announced that we have entered into an agreement to sell
Midland Enterprises Inc. ("Midland"), our marine barge business. In anticipation
of this divestiture, which we expect to close in the second quarter of 2002, we
have reported Midland's operations as discontinued for 2002 and 2001. (See our
Annual Report on Form 10K for the year ended December 31, 2001 Item 7, as well
as Note 10 to those Consolidated Financial Statements "Discontinued Operations"
for further disclosures regarding the potential sale of Midland.) In the fourth
quarter of 2001, we recorded an estimated loss on the sale of Midland as well as
an estimate for Midland's results of operations for the first six months of
2002. As a result, there should be no significant reported results of operations
for Midland during 2002. At the time of the actual sale of Midland we will
adjust the loss provision recorded in 2001 if necessary, based upon the final
sales price under the sales agreement. Earnings available for common stock for
the first quarter of 2001, which includes results of both continuing and
discontinued operations were $223.3 million or $1.63 per share. Diluted earnings
per share were $1.51 in for the first quarter of 2002 and $1.61 for the
corresponding period of 2001.
Earnings before interest and taxes ("EBIT") decreased by $56.0 million, or 12%,
for the first quarter of 2002 compared to the corresponding period last year.
This decrease was attributable almost entirely to the results of our gas
exploration and production subsidiaries, which were adversely impacted by
significantly lower realized gas prices in the first quarter of 2002 compared to
the same quarter last year. EBIT results for the first quarter of 2002 for our
other lines of business were comparable to EBIT results for the same period in
2001. The adverse impact of significantly warmer weather on EBIT from our gas
distribution operations was offset, for the most part, by the discontinuance of
goodwill amortization, lower operations and maintenance costs, as well as the
23
benefits of conversions to natural gas. EBIT from Electric services for the
first quarter of 2001 was comparable with EBIT results for the same period last
year. (See "Review of Operating Segments" and Note 2 to the Consolidated
Financial Statements "Business Segments" for a detailed discussion of EBIT
results for each of our lines of business.)
Partially offsetting the comparative decrease in EBIT was a $20.7 million, or
22%, decrease in interest expense. The average interest rate on outstanding
commercial paper was approximately 330 basis points lower during the first
quarter 2002 compared to the same period last year. Further, average commercial
paper borrowings for the first quarter of 2002 were approximately 14% lower than
the first quarter of 2001. In addition, we have a number of interest rate swap
agreements in which we have effectively changed fixed rate debt to floating rate
debt. As a result of these derivative instruments, we have reduced interest
expense, on a comparative basis, by $10.9 million. (See Note 6 to the
Consolidated Financial Statements "Derivative Financial Instruments " for a
description of these instruments.)
The decrease in income tax expense generally reflects the lower level of pre-tax
income for the first quarter of 2002, compared to the corresponding period last
year. 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 KeySpan / Long Island Lighting Company merger
that was completed in May 1998. This adjustment was a result of a revised
valuation study recently concluded 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.
Overall consolidated earnings are seasonal in nature due to the significant
contribution to earnings of our gas distribution operations. As a result, we
expect to earn approximately 60%, and 30% to 35% of our yearly earnings in the
first and fourth quarters, respectively and breakeven or marginally profitable
earnings are anticipated to be achieved in the second and third quarters.
Consistent with the guidance issued in December 2001, KeySpan's 2002 earnings
from core operations (defined for this purpose as all operations other than gas
exploration and production) are forecasted to be approximately $2.40 to $2.45
per share. KeySpan's 2002 earnings forecast for its gas exploration and
production operations is approximately $0.20 - $0.30 per share, based on the
most recent guidance issued by Houston Exploration. For the first quarter of
2002, earnings from core operations were $1.46 per share, and $0.06 per share
from our gas exploration and production operations. Houston Exploration's
earnings forecast may vary significantly during the year due to, among other
things, changing energy market conditions.
Pursuant to Securities and Exchange Commission rules for gas exploration and
production companies which use the "full cost" accounting method, a quarterly
"ceiling test" calculation is required using commodity prices as of the end of
the reporting period. As a result, depending on the then prevailing commodity
prices, our gas exploration and production subsidiaries may be required to
recognize a non-cash impairment charge at the end of any given future reporting
period.
24
Review of Operating Segments
- ----------------------------
Gas Distribution
KeySpan Energy Delivery New York ("KEDNY") provides gas distribution service to
customers in the New York City Boroughs of Brooklyn, Queens and Staten Island,
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. Boston Gas Company, Colonial Gas Company,
Essex Gas Company, and EnergyNorth Natural Gas Inc., each doing business under
the name KeySpan Energy Delivery New England ("KEDNE"), provide gas distribution
service to customers in Massachusetts and New Hampshire.
The table below highlights certain significant financial data and operating
statistics for the Gas Distribution segment for the periods indicated.
(In Thousands of Dollars)
- ---------------------------------------------------------------------------------------------------------------
Three Months Ended Three Months Ended
March 31, 2002 March 31, 2001
- ----------------------------------------------------- --------------------------- ---------------------------
Revenues $ 1,222,966 $ 1,753,644
Cost of gas 613,584 1,105,308
Revenue taxes 38,295 56,479
- ----------------------------------------------------- --------------------------- ---------------------------
Net Revenues 571,087 591,857
- ----------------------------------------------------- --------------------------- ---------------------------
Operating expenses
Operations and maintenance 145,539 158,872
Depreciation and amortization 63,018 68,583
Operating taxes 38,000 37,976
- ----------------------------------------------------- --------------------------- ---------------------------
Total Operating Expenses 246,557 265,431
- ----------------------------------------------------- --------------------------- ---------------------------
Operating Income 324,530 326,426
Other Income and (Deductions) 5,124 4,255
- ----------------------------------------------------- --------------------------- ---------------------------
Earnings Before Interest and Taxes $ 329,654 $ 330,681
- ----------------------------------------------------- --------------------------- ---------------------------
Firm gas sales (MDTH) 107,274 126,816
Firm transportation (MDTH) 29,998 34,240
Transportation - Electric
Generation (MDTH) 13,359 4,378
Other sales (MDTH) 37,901 25,515
Warmer than normal - New York 18.0% 1.0%
Warmer (Colder) than normal - New England 16.0% (1.0)%
- ----------------------------------------------------- --------------------------- ---------------------------
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.
25
Net Revenues
Net gas revenues (revenues less the cost of gas and associated revenue taxes)
associated with both our New York and New England based gas distribution
operations were adversely impacted by the significantly warmer than normal
weather experienced throughout the Northeastern United States. Based on heating
degree days, weather for the first quarter of 2002 was the warmest in the past
30 years, and approximately 18% warmer than last year in our New York and New
England service territories. The significantly warmer than normal weather
resulted in a decrease of $20.8 million, or 4%, in net gas revenues for the
three months ended March 31, 2002, compared to the corresponding period last
year.
KEDNY and KEDLI each operate under a utility tariff that contains a weather
normalization adjustment that largely offsets variations in firm net revenues
due to fluctuations in normal weather patterns. These weather normalization
adjustments, resulted in a $32.8 million benefit to net gas revenues during the
first quarter of 2002. Nevertheless, net revenues from firm gas customers
(residential, commercial and industrial customers) in our New York service
territory decreased by $8.2 million for the first quarter of 2002 compared to
the same period last year, primarily as a result of lower customer consumption
due to the extremely warm weather, offset, in part, by the benefits from
conversions to natural gas.
Net revenues from firm gas customers in our New England service territory
decreased by $8.3 million for the first quarter of 2002 compared to the same
period last year also as a result of the extremely warm weather. The gas
distribution operations of our New England based subsidiaries do not have a
weather normalization adjustment. Included in net revenues for the first quarter
of 2002, is a benefit of $5.5 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"). The court found that the
"accumulated inefficiencies" component of the productivity factor in the PBR,
imposed by the Massachusetts Department of Telecommunications and Energy, was
not supported by substantial evidence.
Firm gas distribution rates in the first quarter of 2002 , 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 markets and other interruptible (non-firm) markets,
which include large apartment houses, government buildings and schools, gas
service is provided under rates that are established to compete with prices of
alternative fuel, including No. 2 and No. 6 grade heating oil. The extremely
warm weather resulted in a decrease of $4.3 million in net revenues from sales
to these markets during the first quarter of 2002 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.
26
To mitigate the effect of fluctuations in normal weather patterns on our
financial position and cash flows, we may employ derivative hedging strategies
for the 2002/2003 winter heating season. (See Note 6 to the Consolidated
Financial Statements "Derivative Financial Instruments for further information.)
We are committed to our expansion strategies initiated during the past few
years. We believe that significant growth opportunities exist on Long Island and
in our New England service territories. We estimate that on Long Island
approximately 35% of the residential and multi-family markets, and approximately
55% of the commercial market currently use natural gas for space heating.
Further, we estimate that in our New England service territories approximately
45% of the residential and multi-family markets, and approximately 30% 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 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.
Sales, Transportation and Other Quantities
Firm gas sales and transportation quantities decreased by 15% during the three
months ended March 31, 2002, compared to the same period in 2001 due to the
extremely warm weather in all our service territories as previously mentioned.
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 full 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
El Paso Energy Marketing, Inc. ("El Paso"), under which El Paso provides all of
the city gate supply requirements at market prices and manages certain upstream
capacity, underground storage and term supply contracts for KEDNE.
Operating Expenses
Operating expenses decreased by $18.9 million, or 7%, in the first quarter of
2002 compared to the same period last year, primarily due to the discontinuance
of goodwill amortization, cost saving synergies and the effects of warmer than
normal weather. In January 2002, we adopted Statement of Accounting Standard
("SFAS") 142 "Goodwill and Other Intangible Assets". The key requirements of
this Statement include discontinuance of goodwill amortization, a revised
27
framework for testing goodwill impairment and new criteria for the
identification of intangible assets. Goodwill amortization in the gas
distribution segment for the first quarter of 2001 was $8.9 million and for the
twelve months ended December 31, 2001 was $35.6 million. (See "Critical
Accounting Policies and Assumptions" for a further discussion of goodwill
valuation.)
Further contributing to the reduction in comparative operating expenses, are
cost saving synergies currently being realized primarily as a result of early
retirement and severance programs implemented in the fourth quarter of 2000
designed to reduce our workforce by approximately 500 employees. The early
retirement portion of the program was completed in 2000, but the severance
feature is expected to continue through 2002. Further, the warmer than normal
weather experienced in the first quarter of 2002 resulted in less repair and
maintenance work needed on our gas distribution infrastructure. We anticipate
that by year-end, operating expenses will be slightly lower than such expenses
incurred in 2001.
Other Matters
To take advantage of the anticipated gas sales growth opportunities in the New
York City metropolitan area, in 2000 we formed the Islander East Pipeline, LLC,
a limited liability company in which a KeySpan subsidiary and a subsidiary of
Duke Energy Corporation each own a 50% equity interest. Islander East Pipeline,
LLC has received a positive preliminary determination from the Federal Energy
Regulatory Commission ("FERC") to construct, own and operate a natural gas
pipeline facility consisting of approximately 50 miles of interstate natural gas
pipeline extending from Algonquin Gas Transmission Company's facilities in
Connecticut, across the Long Island Sound and connecting with KEDLI's facilities
on Long Island. The Islander East Pipeline, which is expected to begin operating
in 2003, will transport 260,000 dth daily to the Long Island and New York City
energy markets, enough fuel to cool and heat 600,000 homes, as well as allow us
to further diversify the geographic sources of our gas supply. We are currently
evaluating various options for the financing of this pipeline.
28
Electric Services
The Electric Services segment primarily consists of subsidiaries that own and
operate oil and gas fired electric generating plants in Queens and Long Island
and, through long-term contracts, manage the electric transmission and
distribution ("T&D") system, the fuel and electric purchases, and the off-system
electric sales for the Long Island Power Authority ("LIPA").
Selected financial data for the Electric Services segment is set forth in the
table below for the periods indicated.
(In Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------
Three Months Ended Three Months Ended
March 31, 2002 March 31, 2001
- ------------------------------------------ ----------------------------- ------------------------------
Revenues $ 314,710 $ 343,396
Purchased fuel 53,993 79,327
- ------------------------------------------ ----------------------------- ------------------------------
Net Revenues 260,717 264,069
- ------------------------------------------ ----------------------------- ------------------------------
Operating expenses
Operations and maintenance 148,119 144,774
Depreciation 13,733 12,574
Operating taxes 37,371 43,304
- ------------------------------------------ ----------------------------- ------------------------------
Total Operating Expenses 199,223 200,652
- ------------------------------------------ ----------------------------- ------------------------------
Operating Income 61,494 63,417
Other Income and (Deductions) 4,153 2,164
- ------------------------------------------ ----------------------------- ------------------------------
Earnings Before Interest and Taxes $ 65,647 $ 65,581
- ------------------------------------------ ----------------------------- ------------------------------
Electric sales (MWH)* 1,091,000 1,023,000
Capacity (MW)* 2,200 2,200
- ------------------------------------------ ----------------------------- ------------------------------
*Reflects the operations of the Ravenswood facility only.
Net Revenues
Total electric net revenues decreased slightly in the first quarter of 2002,
compared to the same quarter of 2001. Lower comparative net revenues from the
Ravenswood facility were mostly offset by higher comparative net revenues from
the LIPA service agreements. Net revenues from the Ravenswood facility were
$16.2 million, or18% lower during the first quarter of 2002, compared to the
same period in 2001, reflecting a 30% decrease in electric energy prices and
lower capacity sales, offset, in part, by a 7% increase in electric sales
quantities. Realized energy prices and capacity sales for the quarter ended
March 31, 2002 were adversely impacted by a more competitive the New York
Independent System Operator ("NYISO") energy markets and an increase in
available capacity in New York City.
The pricing for both energy sales and the sale of certain ancillary services to
the NYISO energy markets is still evolving and the FERC has adopted several
price mitigation measures which are 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 can not be determined at this
time.
29
(See our Annual Report on Form 10K Item 7A. Quantitative and Qualitative
Disclosures About Market Risk for a further discussion of these matters.)
Revenues from the LIPA service agreements increased by $12.8 million, or 7%, for
the first quarter of 2002 compared to the same period last year. Included in
revenues for 2002, are billings to LIPA for certain third party construction
costs that were significantly higher than such billings last year. These
revenues have no impact on net income since we record a similar amount of costs
in operating expense. Excluding these third party construction billings,
revenues for the quarter ended March 31, 2002 associated with the LIPA service
agreements were comparable to such revenues earned during the same period last
year.
Operating Expenses
Operating expenses for the quarter ended March 31, 2002 were comparable to the
same period last year.
Other Matters
We are in the process of constructing two 79 MW electric generating facilities
on Long Island that will serve LIPA in the summer of 2002. Capital expenditures
to construct these facilities are estimated to be approximately $200 million. We
are currently evaluating various options for the financing of these facilities.
(See the discussion under "Capital Expenditures and Financing" for more
information on our financing plans for 2002.) Further, we are progressing with
our plans to build a new 250 MW cogeneration facility at the Ravenswood facility
site. The new facility is expected to commence operations in late 2003 or early
2004. The capacity and energy produced from this plant is anticipated to be sold
into the NYISO energy markets. We are also progressing through the siting
process before the New York State Board on Electric Generation Siting and the
Environment with our proposal to build a similar 250 MW combined cycle electric
generating facility on Long Island. This facility is anticipated to commence
operations in late 2004 or early 2005. We anticipate that 50% of the plant's
capacity will be under long-term contract to LIPA. Construction of the two 250
MW facilities is not expected to begin until late 2002 or early 2003. At that
time we will evaluate various options for the financing of those facilities. In
the normal course of reviewing our operations, we routinely evaluate the
acquisition of electric generating facilities, primarily in the Northeast. Any
such facilities we may acquire will likely be financed initially with cash
on-hand or short-term borrowings.
Under the Generation Purchase Right Agreement ("GPRA"), LIPA had the right for a
one-year period, beginning on May 28, 2001, to acquire all of our Long Island
based generating assets formerly owned by LILCO at fair market value at the time
of the exercise of such right. By agreement dated March 29, 2002, LIPA and
KeySpan amended the GPRA to provide for a new six month option period ending on
May 28, 2005. The other terms of the option reflected in the GPRA remained
unchanged.
30
In return for providing LIPA an extension of the GPRA, KeySpan and LIPA have
agreed to an extension of 31 months for the Management Services Agreement under
which KeySpan manages the day-to-day operations, maintenance and capital
improvements of LIPA's transmission and distribution system. That extension is
subject to approval by the New York State Public Authorities Control Board and
the State Controller.
The extension is the result of a new initiative established by LIPA to work with
KeySpan and others to review Long Island's long-term energy needs. LIPA and
KeySpan will jointly analyze new energy supply options including re-powering
existing plants, renewable energy technologies, distributed generation,
conservation initiatives and retail competition. The extension allows both LIPA
and KeySpan to explore alternatives to the GPRA including re-powering existing
facilities, the sale of some or all of KeySpan's plants to LIPA, or the sale of
some or all of these plants to other private operators.
Energy Services
The Energy Services segment primarily includes companies that provide services
through three lines of business to clients located within the New York City
metropolitan area, 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.
(In Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------------
Three Months Ended Three Months Ended
March 31, 2002 March 31, 2001
- ------------------------------------------------ ------------------------------- --------------------------------
Revenues $ 241,559 $ 319,093
Less: cost of gas and fuel 66,155 153,283
- ------------------------------------------------ ------------------------------- --------------------------------
Net revenues 175,404 165,810
Other operating expenses 184,762 172,622
- ------------------------------------------------ ------------------------------- --------------------------------
Operating Loss (9,358) (6,812)
Other Income and (Deductions) 160 433
- ------------------------------------------------ ------------------------------- --------------------------------
Loss Before Interest and Taxes $ (9,198) $ (6,379)
- ------------------------------------------------ ------------------------------- --------------------------------
Net revenues increased by 6% during the first quarter of 2002 compared to the
same period last year; lower revenues were offset by lower natural gas and fuel
costs. EBIT results for the three months ended March 31, 2002, however,
decreased compared to the same period last year. Home Energy and Business
Solutions operations were adversely impacted by the general "down-turn" in the
New York metropolitan economy. In addition, the extremely warm weather has
reduced the number of service calls and repair orders received this quarter
compared to the same period last year.
In 2001, we discontinued the general contracting activities related to one of
our subsidiaries, the former Roy Kay companies, based upon our view that the
general contracting business is not a core competency of these companies. (See
our Annual Report on Form 10K for the year ended December 31, 2001 Item 7 and
Note 11 to those Consolidated Financial Statements "Roy Kay Operation" for a
31
more detailed discussion.)We are completing the contracts entered into by the
former Roy Kay companies and, for the first quarter of 2002, we incurred an EBIT
loss of $1.5 million associated with the discontinuance of this business. For
the three months ended March 31, 2001, we incurred an EBIT loss of $7.9 million
associated with the operations of the former Roy Kay companies. Excluding the
results of the former Roy Kay companies, the Energy Services segment reflected
an EBIT loss of $7.7 million for the first quarter of 2002, compared to positive
EBIT of $1.5 million for the same period last year for the reason noted above.
This quarter's results also benefitted from the elimination of goodwill
amortization, which for the first quarter of 2001 amounted to $2.1 million.
Energy Investments
The Energy Investment segment consists of our gas exploration and production
operations 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 67%
equity interest in Houston Exploration, as well as our wholly-owned subsidiary,
KeySpan Exploration and Production, LLC.
This segment also consists of KeySpan Canada; our 20% interest in the Iroquois
Gas Transmission System LP ("Iroquois"); and our 50% interest in the Premier
Transmission Pipeline and 24.5% interest in Phoenix Natural Gas.
Selected financial data and operating statistics for our gas exploration and
production activities are set forth in the following table for the periods
indicated.
(In Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------
Three Months Ended Three Months Ended
March 31, 2002 March 31, 2001
- --------------------------------------------- ---------------------------- --------------------------------
Revenues $ 74,714 $ 132,011
Depletion and amortization expense 41,446 33,633
Other operating expenses 13,443 19,162
- --------------------------------------------- ---------------------------- --------------------------------
Operating Income 19,825 79,216
Other Income and (Deductions)* (4,153) (13,700)
- --------------------------------------------- ---------------------------- --------------------------------
Earnings Before Interest and Taxes* $ 15,672 $ 65,516
- --------------------------------------------- ---------------------------- --------------------------------
Natural gas and oil production (Mmcf) 25,670 23,777
Natural gas price (per Mcf) realized $ 2.89 $ 5.53
Natural gas price (per Mcf) unhedged $ 2.20 $ 6.85
Proved reserves at year-end (BCFe) 647 593
- --------------------------------------------- ---------------------------- --------------------------------
*Operating income above represents 100% of our gas exploration and
production subsidiaries' results for the periods indicated. Earnings
before interest and taxes, however, is adjusted to reflect minority
interest. Gas reserves and production are stated in BCFe and Mmcfe,
which includes equivalent oil reserves.
32
Earnings Before Interest and Taxes
The decrease in EBIT of $49.8 million for the three months ended March 31, 2002,
compared to the corresponding period last year, reflects a significant decrease
in revenues and, to a smaller degree, an increase in operating expenses
associated with higher production volumes. Revenues for the first quarter of
2002, compared to the first quarter of 2001, were adversely impacted by the
significant decline in comparative average realized gas prices (average wellhead
price received for production including hedging gains and losses). Average
realized gas prices decreased 48% for the first quarter of 2002, compared with
the corresponding period last year. The adverse effect on revenues resulting
from the decline in average realized gas prices was partially offset by an
increase of 8% in production volumes during the first quarter of 2002 compared
to the same period last year.
The average realized gas price in the first quarter of 2002 was 131% of the
average unhedged natural gas price compared to 81% for the first quarter of
2001. Houston Exploration entered into derivative financial positions in 2001 to
hedge a substantial portion of its anticipated 2002 production. These derivative
instruments are designed to provide Houston Exploration with a more predictable
cash flow, as well as to reduce its exposure to adverse price fluctuations in
natural gas. The settlement of derivative instruments during the first quarter
of 2002 resulted in a benefit to revenues of $17 million. (See Note 6 to the
Consolidated Financial Statements, "Derivative Financial Instruments" for
further information.)
Natural gas prices continue to fluctuate and the risk that we may be required to
write-down our full cost pool increases when natural gas prices are depressed or
if we have significant downward revisions in our estimated proved reserves.
At December 31, 2001, our gas exploration and production subsidiaries had 647
BCFe of net proved reserves of natural gas, of which approximately 72% were
classified as proved developed.
Selected financial data and operating statistics for our other energy-related
investments are set forth in the following table for the periods indicated.
(In Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------------
Three Months Ended Three Months Ended
March 31, 2002 March 31, 2001
- ------------------------------------------- --------------------------------- ----------------------------------
Revenues $ 17,636 $ 26,969
Operation and maintenance expense 14,056 17,265
Other operating expenses 3,029 3,763
- ------------------------------------------- --------------------------------- ----------------------------------
Operating Income 551 5,941
Other Income and (Deductions) 4,343 3,312
- ------------------------------------------- --------------------------------- ----------------------------------
Earnings Before Interest and Taxes $ 4,894 $ 9,253
- ------------------------------------------- --------------------------------- ----------------------------------
33
The decrease in EBIT of $4.4 million, or 47%, is primarily due to the operations
of KeySpan Canada and losses incurred from certain technology-related
investments. KeySpan Canada experienced lower per unit sales prices, as well as
lower quantities of sales of natural gas liquids in the first quarter 2002,
compared to 2001, as a result of generally lower oil prices. The pricing of
natural gas liquids is directly related to oil prices.
We do not consider the 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. Except for the
sale of Midland Enterprises as previously discussed, we can not predict when, or
if, any such sale or disposition may take place, or the effect that any such
sale or disposition may have on our financial position, results of operations or
cash flows.
Liquidity
The increase in cash flow from operations for the first quarter of 2002,
compared to the corresponding period last year, is primarily attributable to
lower interest and income tax payments. As previously mentioned, interest
payments decreased this quarter, compared to last year, due to the use of
derivative financial instruments to hedge a portion of our exposure to interest
rate risk, as well as to lower interest rates on outstanding commercial paper.
Further, state and local tax payments were lower for the first quarter of 2002
compared to the same period last year since we are currently in a refund
position with regards to such payments. Operating cash flow from our gas
exploration and production activities, however, were adversely impacted by
significantly lower realized gas prices this quarter compared to the same period
last year. (See Note 6 to the Consolidated Financial Statements "Derivative
Financial Instruments" for an explanation of the interest rate hedges.)
At March 31, 2002, we had cash and temporary cash investments of $190.7 million.
During the three months ended March 31, 2002, we repaid $9.9 million of
commercial paper and, at March 31, 2002, $1.0 billion of commercial paper was
outstanding at a weighted average annualized interest rate of 2.07%. We had the
ability to borrow up to an additional $361 million at March 31, 2002 under the
terms of our credit facility. Under this facility, our consolidated indebtedness
may not exceed 68% of our consolidated capitalization at the end of any fiscal
quarter. At March 31, 2002, our consolidated indebtedness was 64.75% of our
consolidated capitalization. Violation of this covenant could result in the
termination of the credit facility, and the required repayment of amounts due
thereunder.
Houston Exploration has an unsecured line of credit with a commercial bank that
provides for a maximum commitment of $250 million, subject to a borrowing base
limitation of $250 million. During the three months ended March 31, 2002,
Houston Exploration borrowed $9.0 million under this facility and repaid $4.0
million; at March 31, 2002, $149 million remained outstanding at a weighted
average annualized interest rate of 3.19%. At March 31, 2002, Houston
Exploration had available borrowings of $101 million. Also, KeySpan Canada has
two revolving loan agreements with financial institutions in Canada. Repayments
under these agreements totaled approximately
34
$20 million for the three months ended March 31, 2002. At March 31, 2002,
approximately $155 million was outstanding at a weighted average annualized
interest rate of 2.99%. KeySpan Canada currently has available borrowings of
approximately $49 million.
KeySpan has fully and unconditionally guaranteed $525 million of medium- term
notes issued by KEDLI under KEDLI's current shelf registration, as well as a
$125 million revolving credit agreement associated with its Canadian
subsidiaries. Both the medium- term notes and credit agreement are reflected on
the Consolidated Balance Sheet.
Further, KeySpan has: (i) guaranteed $167.9 million of surety bonds associated
with certain construction projects currently being performed by subsidiaries
within the Energy Services segment; (ii) guaranteed certain supply contracts,
margin accounts and purchase orders for certain subsidiaries in the aggregate
amount of $81.1 million; and (iii) guaranteed the $425 million Master Lease
Agreement Liability associated with the lease of the Ravenswood facility. These
guarantees are not recorded on the Consolidated Balance Sheet. The guarantee of
the medium- term notes expires in 2010, while the other guarantees have terms
that do not extend beyond 2005; however the Master Lease Agreement can be
extended to 2009. At this point in time, we have no reason to believe that our
subsidiaries will default on their current obligations. However, we can not
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 the discussion of the Ravenswood lease under the heading "Capital
Expenditures and Financing" for a description of the leasing arrangement.
We satisfy our seasonal working capital requirements primarily through
internally generated funds and the issuance of commercial paper. In addition, we
anticipate realizing approximately $165 million in proceeds from the sale of
Midland in 2002. We believe that these sources of funds are sufficient to meet
our seasonal working capital needs. In addition, we use treasury stock to
satisfy the requirements of our employee common stock, dividend reinvestment and
benefit plans.
Capital Expenditures and Financing
Construction Expenditures
The table below sets forth our construction expenditures by operating segment
for the periods indicated:
(In Thousands of Dollars)
- ----------------------------------------------------------------------------
Three Months Ended Three Months Ended
March 31, 2002 March 31 ,2001
- -------------------- ------------------------- ---------------------------
Gas Distribution $ 84,366 $ 46,066
Electric Services 88,544 10,289
Energy Investments 67,697 65,768
Energy Services 3,546 3,786
- -------------------- ------------------------- ---------------------------
$ 244,153 $ 125,909
- -------------------- ------------------------- ---------------------------
35
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 primarily costs to maintain our electric generating facilities
and costs to expand the Ravenswood facility and construct new electric
generating facilities as previously noted. Construction expenditures related to
the Energy Investments segment primarily reflect costs associated with our gas
exploration and production activities. These costs are related to the
development of properties in Southern Louisiana and in the Gulf of Mexico.
Expenditures also include development costs associated with our joint venture
with Houston Exploration, as well as costs related to Canadian affiliates.
The amount of future construction expenditures is reviewed on an ongoing basis
and can be affected by timing, scope and changes in investment opportunities.
Financing
At December 31, 2001, we had an existing $1 billion shelf registration statement
on file with the Securities and Exchange Commission ("SEC"), with $500 million
available for issuance. In February 2002, we updated our shelf registration for
the issuance of an additional $1.2 billion of securities, thereby giving us the
ability to issue up to $1.7 billion of debt, equity or various forms of
preferred stock. Currently, we have the authority under Public Utility Holding
Company Act ("PUHCA") to issue up to $1.0 billion of this amount. We have filed
an application with the SEC for additional authorization.
In order to take advantage of opportunities currently available, we anticipate
issuing at least $400 million of MED's Equity Units in May 2002 consisting of a
purchase contract for our common stock and a six-year note. The purchase
contract commits us three years from the date of issue of the MEDS equity units
to issue, and investors to purchase, a number of shares of our common stock
based on a formula tied to the value of our common stock at that time. These
instruments will be recorded as long-term debt on our Consolidated Balance
Sheet, but rating agencies will consider a portion of the instruments as equity
for purposes of calculating debt-to-equity ratios. We expect to reduce
outstanding commercial paper with the proceeds from this issuance. We anticipate
that these securities will not be considered convertible instruments for
purposes of applying FAS 128 "Earnings Per Share" calculations, unless or until
such time as the market value of our common stock reaches a threshold
appreciation price which will be higher than our current per share market value.
Interest payments will, however, reduce net income and earnings per share.
The Emerging Issues Task Force of the Financial Accounting Standards Board is
considering proposals related to accounting for certain securities and financial
instruments, including securities such as the Equity Units. The current
proposals being considered include rulemaking that, if adopted, would endorse
the method of accounting discussed above. Alternatively, other proposals being
considered could result in the common shares issuable pursuant to the purchase
contract to be deemed outstanding and included in the calculation of diluted
earnings per share, and could result in periodic "marking to market" of the
purchase contracts, causing periodic charges or credits to income. If this
latter approach were adopted, our diluted earnings per share could increase and
decrease from quarter to quarter to reflect the lesser and greater number of
shares issuable upon satisfaction of the purchase contract.
We currently anticipate that the SEC will issue an order relating to our
application for additional authorization to issue securities under PUHCA by the
latter part of this year. Until that time, we will continue to finance the
construction of our two new electric peaking-power plants and the Islander East
Pipeline through the issuance of commercial paper. At the time of such SEC
approval, we intend to issue approximately $150 to $200 million of either
taxable or tax-exempt debt securities, the proceeds of which, it is anticipated,
will be used to re-pay outstanding commercial paper. We may also issue
additional long-term debt towards the latter part of 2002 to replace outstanding
commercial paper, if market conditions are favorable.
36
We will continue to evaluate our capital structure and financing strategy for
2002 and beyond. We believe that our current sources of funding (i.e.,
internally generated funds, the issuance of additional securities as noted
above, and the availability of commercial paper), together with the cash
proceeds from the sale of Midland, are sufficient to meet our anticipated
working capital needs for the foreseeable future.
As noted, as part of our strategy to maintain an optimal level of floating rate
debt, we have several interest rate swap agreements on a portion of our existing
fixed rate medium-term and long-term debt that effectively change the debt to
floating rate debt. These swap agreements qualify for hedge accounting and were
completed with several major financial institutions in order to reduce credit
risk. (See Note 6 to the Consolidated Financial Statements "Derivative Financial
Instruments" for additional information on these swap agreements.)
We also have an arrangement with a special purpose financing entity through
which we lease a portion of the Ravenswood facility. We acquired the Ravenswood
facility from Consolidated Edison on June 18, 1999 for approximately $597
million. In order to reduce our initial cash requirements, we entered into a
lease agreement with a special purpose, unaffiliated financing entity that
acquired a portion of the facility directly from Consolidated Edison and leased
it to our subsidiary. We have guaranteed all payment and performance obligations
of our subsidiary under the lease. The lease represents approximately $425
million of the acquisition cost of the facility, which is the amount of debt
that would have been recorded on our Consolidated Balance Sheet had the special
purpose financing entity not been utilized and conventional debt financing been
employed. Further, we would have recorded an asset in the same amount. Monthly
lease payments represent interest only. The lease qualifies as an operating
lease for financial reporting purposes while preserving our ownership of the
facility for federal and state income tax purposes.
The initial term of the lease expires on June 20, 2004 and may be extended until
June 20, 2009. In June 2004 , we have the right to either purchase the facility
or terminate the lease and dispose of the facility for an amount generally equal
to the original acquisition cost, $425 million, plus the present value of the
lease payments that would have otherwise been paid through June 20, 2009. In
June 2009, when the lease terminates, we may purchase the facility in an amount
generally equal to the original acquisition cost or surrender the facility to
the lessor. At this time, we believe that the fair market value of the leased
assets is well in excess of the original acquisition cost.
The Financial Accounting Standards Board (the "Board") is currently reviewing
issues related to special purpose entities. It is anticipated that in mid 2002,
the Board will issue for public comment guidance regarding the accounting for,
and disclosure of special purpose entities. It is expected that the final
guidance will be issued in the summer of 2002, and be effective January 1, 2003.
It is possible that we may be required to classify the lease under which we
operate the Ravenswood facility as $425 million of indebtedness.
37
This classification would increase the amount of our indebtedness for purposes
of calculating our financial covenants under our credit agreement expiring on
September 19, 2002 and, accordingly, if these covenants were then applicable,
would reduce our available borrowing capacity. We anticipate negotiating a new
credit agreement prior to the expiration of the existing credit agreement. At
this time, however, we are unable to determine what the requirements will be
under the final guidance, if and when an accounting Standard is issued, as well
as the actual impact on our results of operations and financial position.
The ratings on our long-term debt have remained unchanged from December 31,
2001. Moody's Investor Services rated: (i) KeySpan's long-term debt at A3; and
(ii) KEDNY's, KEDLI's, Boston Gas Company's and Colonial Gas Company's long-term
debt at A2. Standard and Poor's rating agency rated: (i) the long-term debt of
KeySpan, KeySpan Generation, Boston Gas Company and Colonial Gas Company at A;
and (ii) KEDNY's and KEDLI's long-term debt at A+.
Our contractual cash obligations and associated maturities have remained
basically unchanged from December 31, 2001.
The table below reflects maturity schedules for our cash contractual obligations
at March 31, 2002:
(In Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------------------
Contractual Obligations
Total 1-3 Years 4-5 Years After 5 Years
- ---------------------------------- ---------------- ------------------- --------------------- -----------------------
Long-Term Debt $ 4,796,584 $ 11,149 $ 1,227,333 $ 3,558,102
Capital Lease Obligations 15,007 2,851 2,176 9,980
Operating Leases 633,313 261,953 165,441 205,919
- ---------------------------------- ---------------- ------------------- --------------------- -----------------------
Total Contractual
Cash Obligations $ 5,441,514 $ 275,953 $ 1,394,950 $ 3,770,611
- ---------------------------------- ---------------- ------------------- --------------------- -----------------------
Commercial Paper $ 1,038,503 Revolving
- ---------------------------------- ---------------- ------------------- --------------------- -----------------------
Discussions of Critical Accounting Policies and Assumptions
In preparing our financial statements, the application of certain accounting
policies requires difficult, subjective and/or complex judgements. The
circumstances that make these judgements 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 judgements and
assumptions underlying our estimates prove to be inaccurate. The critical
accounting policies requiring such subjectivity are discussed below.
38
Percentage of Completion Accounting
Significant reliance is placed upon estimates of future job costs in computing
revenue and subsequent net income under the percentage of completion method of
revenue recognition for the designing, building and installation of heating,
ventilation and air-conditioning systems by subsidiaries in our Energy Services
segment. This accounting method measures the percentage of costs incurred and
accrued to date for each contract to the estimated total costs for each contract
at completion. These estimates are based upon available information at the time
of review, and changes in estimates resulting in additional future costs to
complete projects can result in reduced margins or loss contracts. Provisions
for estimated losses on uncompleted contracts are made in the period such losses
are determined. Changes in job performance, job conditions and estimated
profitability are recognized in the period the revisions are determined.
Valuation of Goodwill
On January 1, 2002, we adopted SFAS 141, "Business Combinations", and SFAS 142
"Goodwill and Other Intangible Assets". The key concepts from the two
interrelated Statements include mandatory use of the purchase method when
accounting for business combinations, discontinuance of goodwill amortization, a
revised framework for testing goodwill impairment at a "reporting unit" level,
and new criteria for the identification and potential amortization of other
intangible assets.
Other changes to existing accounting standards involve a requirement to test
goodwill for impairment at least annually. The initial impairment test is to be
performed within six months of adopting SFAS 142 with any resulting impairment
reflected as either a change in accounting principle, or a charge to operations
in the financial statements, as appropriate.
We record goodwill on purchase transactions, representing the excess of
acquisition cost over the fair value of net assets acquired. In testing for
goodwill impairment under SFAS 142, significant reliance is placed upon
estimated future cash flows. Cash flow estimates are determined based upon our
projected market conditions and demand for our products and services. A change
in the fair value of our investments could cause a significant change in the
carrying value of goodwill.
We have completed our analysis for our Gas Distribution and Energy Services
reporting units, determining that no impairment exists. The results of our
analysis for our Energy Investments reporting unit is not complete at this time,
and we are unable to determine the impact, if any, this analysis may have on our
results of operations or financial condition.
Valuation of Derivative Instruments
We employ derivative instruments to hedge a portion of our exposure to commodity
price risk and interest rate risk, as well as to fix the selling price on a
portion of our electric energy sales from the Ravenswood facility. A number of
our derivative instruments are exchange traded and, accordingly, fair value
measurements are generally based on standard New York Mercantile Exchange
39
("NYMEX") quotes. However, the oil derivative instruments we employ to hedge the
purchase price on a portion of the oil used to fuel the Ravenswood facility are
not exchange traded. We use industry published oil indices for No. 6 grade fuel
oil to value these oil swap contracts. We have also engaged in the use of
derivative swap instruments to fix the selling price on a portion of our
electric energy sales from the Ravenswood facility. Further, we have tolling
arrangements under which we have effectively "locked-in" a profit on a portion
of electric sales. In addition, our Canadian subsidiary uses swap instruments to
lock-in the purchase price on the purchase of electricity needed to operate its
gas processing plants. These arrangements are also non-exchange traded and we
use NYISO-location zone and local published indices to value these outstanding
derivatives. For collar transactions relating to natural gas sales associated
with our gas exploration and production subsidiaries, we use standard NYMEX
quotes, as well as Black- Scholes valuations to calculate the fair value of
these instruments. Finally, we also have interest rate swap agreements in which
approximately $1.4 billion of fixed rate debt have been effectively converted to
floating rate debt. The fair values of these derivative instruments are provided
to us by third party appraisers and represent the present value of estimated
future cash-flows based on a forward interest rate curve for the life of the
derivative instrument. All fair value measurements, whether calculated using
standard NYMEX quotes or other valuation techniques, are subjective and subject
to fluctuations in commodity prices, interest rates and overall economic market
conditions and, as a result, our fair value measurements may not be precise and
can fluctuate significantly from period to period. (See Note 6 to the
Consolidated Financial Statements "Derivative Financial Instruments" for a
further description of the instruments.)
Regulation and Rate Matters
Gas Matters
In March 2002, we notified the Massachusetts Department of Telecommunications
and Energy ("DTE") that we may file a rate proceeding for Boston Gas Company
during the second quarter of 2002. The Performance Based Ratemaking Plan ("PBR")
in effect for Boston Gas will expire on October 31, 2002. We are currently
evaluating various options available to us, including but not limited to, an
extension of the existing plan or proposing a new rate plan.
For an additional discussion of our current gas distribution rate agreements,
see our Annual Report on Form 10-K for the year ended December 31, 2001, Item 7.
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
40
entry by registered holding companies and their subsidiaries into businesses
other than electric and/or gas utility businesses; and (iv) require SEC approval
for certain utility mergers and acquisitions.
The SEC's order issued on November 8, 2000, in connection with our acquisition
of Eastern and ENI, 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 $5.1 billion, (i) maintain existing financing
agreements, (ii) issue and sell up to $1.5 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, review, extend,
supplement or replace any of the foregoing; (b) issue shares of common stock or
reissue shares of common stock held in treasury under dividend reinvestment and
stock-based management incentive and employee benefit plans; (c) maintain
existing and enter into additional hedging transactions with respect to
outstanding indebtedness in order to manage and minimize interest rate costs;
(d) invest up to 250% of our consolidated retained earnings in exempt wholesale
generators and foreign utility companies; 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 March 31, 2002 our consolidated common equity was 35% of our
consolidated capitalization, including commercial paper.
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 $212 million and
we have recorded a related liability for such amount. We have also recorded an
additional $42.1 million liability representing the estimated environmental
cleanup costs related to a former coal tar processing facility. Further, as of
March 31, 2002, we have expended a total of $52.2 million. (See Note 4 to the
Consolidated Financial Statements, "Environmental Matters.")
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
41
cash flows and borrowings, pursuit of potential future acquisition opportunities
and sources of funding, are forward-looking statements. Such forward-looking
statements reflect numerous assumptions and involve a number of risks and
uncertainties and actual results may differ materially from those discussed in
such statements.
Among the factors that could cause actual results to differ materially are:
- volatility of energy prices in a deregulated market environment, as
well as in natural gas and fuel used to generate electricity;
- fluctuations in weather and in gas and electric prices;
- general economic conditions, especially in the Northeast United
States;
- our ability to successfully reduce our cost structure;
- 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 such
acquisitions;
- available sources and cost of fuel;
- federal and state regulatory initiatives that increase competition,
threaten cost and investment recovery, and impact the rate structures
of our regulated businesses;
- the exercise by LIPA of its right to acquire our Long Island
generation operations and the possible deployment of the proceeds
received in connection therewith;
- 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, heating, ventilation and air conditioning ("HVAC"), and
engineering companies and other utilities which 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;
- other risks detailed from time to time in other reports and other
documents filed by KeySpan with the Securities and Exchange Commission
("SEC").
For any of these statements, KeySpan claims the protection of the safe harbor
for forward-looking information contained in the Private Securities Litigation
Reform Act of 1995, as amended. For additional discussion on these risks,
uncertainties and assumptions, see "Item 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.
42
Item 3. Quantitative and Qualitative Disclosures About Market Risk
We are subject to various risks and uncertainties associated with our
operations. The most significant of which involves the evolution of the gas
distribution and electric industries towards a more competitive and deregulated
environment. In addition, we are exposed to commodity price risk, interest rate
risk and, to a much less degree, foreign currency translation risk.
Our exposure to the above mentioned market risks has remained substantially
unchanged from December 31, 2001. See our Annual Report on Form 10K for the year
ended December 31, 2001 Item 7A for a discussion of the various risks associated
with our operations. Below are our derivative instruments outstanding at March
31, 2002.
Commodity Contracts and Electric Derivative Instruments: From time to time we
utilize derivative financial instruments, such as futures, options and swaps,
for the purpose of hedging exposure to commodity price risk and to fix the
selling price on a portion of our peak electric energy sales. Our hedging
objectives and strategies have remained substantially unchanged from year-end.
Houston Exploration utilizes collars, as well as, over- the- counter ("OTC")
swaps to hedge future sales prices on a portion of its natural gas production to
achieve a more predictable cash flow and reduce its exposure to adverse price
fluctuations of natural gas. As of March 31 2002, Houston Exploration has hedged
approximately 65% of its estimated 2002 yearly production and 20% of its
estimated 2003 yearly production. Houston Exploration uses standard New York
Mercantile Exchange ("NYMEX") futures prices and published volatility in its
Black-Scholes calculation to value its outstanding derivatives. Houston
Exploration recorded a benefit of $17.0 million in Revenues for derivative
instruments that settled during the first quarter of 2002.
We also employ standard NYMEX gas futures contracts, as well as oil swap
derivative contracts to fix the purchase price for a portion of the fuel used at
the Ravenswood facility. We use 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. These contracts extend through 2003. During the
first quarter of 2002, we realized a loss of $3.5 million on the settlement of
derivative instruments and recorded this loss as an increase to Fuel and
Purchased Power expense.
Our gas and electric marketing subsidiary, as well as our gas distribution,
operations have fixed rate gas sales contracts and utilize standard NYMEX
futures contracts to lock-in a price for future natural gas purchases. We use
standard NYMEX futures prices to value the outstanding contracts. During the
first quarter of 2002, we realized a loss of $7.8 million on derivatives that
settled during this period and recorded this loss as an increase to Purchased
Gas for Resale.
We have also engaged in the use of derivative swap instruments to fix the
selling price on a portion of our estimated 2002 summer and winter peak electric
energy sales from the Ravenswood facility to protect against a potential
degradation in market prices. We have financially settled tolling arrangements
under which we have effectively "locked-in" a profit on a portion of 2002 sales.
We currently have hedge positions for approximately 50% of the estimated 2002
summer peak electric profits associated with the Ravenswood facility. We use
NYISO-location zone published indices and standard NYMEX prices to value these
outstanding derivatives. During the first quarter of 2002, we realized a gain of
$5.6 million on the settlement of certain derivative instruments and recorded
this gain in Revenues.
43
Further, KeySpan Canada employs electric swap contracts to lock-in the purchase
price on the purchase of electricity needed to operate its gas processing
plants. These contracts are not exchange traded and we use local published
indices to value these outstanding options. We realized a loss of $0.4 million
on the settlement of certain swap derivative instruments.
All of our commodity contracts and electric derivative instruments detailed
above are cash-flow hedges and qualify for hedge accounting. Periodic changes in
the market value of derivatives which meet the definition of a cash-flow hedge
are recorded as comprehensive income, subject to effectiveness, and then
included in net income to match the underlying hedged transactions.
The following tables set forth selected financial data associated with these
derivative financial instruments noted above that were outstanding at March 31,
2002.
Year of Volumes Fixed Current Fair Value
Type of Contract Maturity mmcf Floor $ Ceiling $ Price $ Price $ ($000)
- -------------------------- ---------- ---------- ----------- -------------- --------------- --------------- ---------------
Gas
Collars 2002 44,000 3.56 5.14 - 3.28 - 3.87 13,869
2003 7,300 3.30 4.07 - 3.49 - 3.97 (1,023)
Swaps -Short Natural Gas 2002 8,250 - - 3.01 3.28 - 3.87 (3,674)
2003 14,600 - - 3.19 3.49 - 3.97 (7,043)
Swaps - Long Natural Gas 2002 6,920 - - 2.24 - 3.72 3.28 - 3.87 2,460
2003 2,070 - - 3.08 - 3.77 3.49 - 3.97 613
- -------------------------- ---------- ---------- ----------- -------------- --------------- --------------- ---------------
83,140 5,202
- -------------------------- ---------- ---------- ----------- -------------- --------------- --------------- ---------------
Year of Volumes Fair Value
Type of Contract Maturity Barrels Fixed Price $ Current Price $ ($000)
- --------------------------- ---------------- ----------------- -------------------- ---------------------- ---------------------
Oil
Swaps - Long Fuel Oil 2002 191,438 19.85 - 26.40 22.70 - 24.55 420
2003 345,389 20.02 - 26.72 21.84 - 23.06 132
- --------------------------- ---------------- ----------------- -------------------- ---------------------- ---------------------
536,827 552
- --------------------------- ---------------- ----------------- -------------------- ---------------------- ---------------------
Year of Current Estimated Fair Value
Type of Contract Maturity MWh Fixed Profit /Price $ Price $ Profit $ ($000)
- ----------------------- -------------- -------------- ------------------------- -------------- ----------------- ---------------
Electricity
Tolling Arrangements 2002 624,000 4.75 - 47.50 - 1.00 - 51.62 825
Swaps 2002 58,752 54.84 - 57.03 31.39 - (1,380)
2003 70,080 54.84 - 57.03 29.69 - (1,765)
- ----------------------- -------------- -------------- ------------------------- -------------- ----------------- ---------------
752,832 (2,320)
- ----------------------- -------------- -------------- ------------------------- -------------- ----------------- ---------------
44
Non-firm Gas Sales Derivative Instruments: Utility tariffs applicable to certain
large-volume customers permit gas to be sold at prices established monthly
within a specified range expressed as a percentage of prevailing alternate fuel
oil prices. We use gas swap contracts, with offsetting positions in oil swap
contracts of equivalent energy value, with third parties to hedge the cash-flow
variability of specified portions of purchases and sales. All positions that
were outstanding at December 31, 2001 settled during the first quarter of 2002.
The final settlement of these positions during the first quarter of 2002 did not
have a material effect on our results of operations. We intend to enter into
additional derivative instruments of this nature during 2002 if market
conditions so warrant.
Firm Gas Sales Derivative Instruments - Regulated Utilities: We utilize
derivative financial instruments to "lock-in" the purchase price for a portion
of our future natural gas purchases. Our strategy is to minimize fluctuations in
firm gas sales prices to our regulated firm gas sales customers in our New York
service territory. All positions that were outstanding at December 31, 2001
settled during the first quarter of 2002. Since these derivative instruments
were not designed as hedges and were employed to support our gas sales prices to
regulated firm gas sales customers, the accounting for these derivative
instruments was subject to SFAS 71. Therefore, changes in the market value of
these derivatives were recorded as a Regulatory Asset or Regulatory Liability on
the Consolidated Balance Sheet. Gains or losses on the settlement of these
contracts were initially deferred and then refunded to or collected from our
firm gas sales customers during the appropriate winter heating season consistent
with regulatory requirements. We intend to enter into additional derivative
instruments of this nature during 2002 if market conditions so warrant.
Interest Rate Swaps: We also have interest rate swap agreements in which
approximately $1.4 billion of fixed rate debt have effectively been changed to
floating rate debt. For the term of the agreements, we will receive the fixed
coupon rate associated with these bonds and pay the counter parties a variable
interest rate that is reset on a weekly and/or quarterly basis as appropriate.
These bonds are fair- value hedges and qualify for hedge accounting. The swap
agreements associated with the Medium Term Notes, as displayed in the table
below, qualify for "short-cut" hedge accounting treatment under SFAS 133. The
fair-value hedge associated with a Gas Facilities Revenue Bond does not qualify
for "short-cut" hedge accounting treatment. Through the utilization of our
interest rate swap agreements, we reduced recorded interest expense by $11.6
million during the first quarter of 2002. Further, we recorded, a first quarter
benefit of $1.3 million as a result of the fair value measurements. The fair
values of these derivative instruments are provided to us by third party
appraisers and represent the present value of future cash-flows based on a
forward interest rate curve for the life of the derivative instrument. The fair
values at March 31, 2002, as indicated in the table below, reflect an assumption
of higher interest rates in the future.
45
The table below summarizes selected financial data associated with these
derivative financial instruments that were outstanding at March 31, 2002.
Average
Maturity Date of Notional Amount Fixed Rate Variable Rate Fair Value
Bond Swaps ($000) Received Paid ($000)
- -------------------------------- ------------------- ------------------- ----------------- ------------------ ------------------
Gas Facilities Revenue Bonds 2024 90,000 5.540% 1.270% 10
Medium Term Notes 2010 500,000 7.625% 4.320% (6,327)
Medium Term Notes 2006 500,000 6.150% 3.680% (13,985)
Medium Term Notes 2023 270,000 8.200% 3.390% (16,377)
- -------------------------------- ------------------- ------------------- ----------------- ------------------ ------------------
1,360,000 (36,679)
- -------------------------------- ------------------- ------------------- ----------------- ------------------ ------------------
Additionally, we have a swap agreement that effectively exchanges $270 million
of outstanding commercial paper with fixed-rate debt. This swap is a cash-flow
hedge and qualifies for hedge accounting under SFAS 133. We recorded additional
interest expense associated with this swap of $0.7 million during the first
quarter of 2002 and there was no impact on earnings from ineffectiveness. At
March 31, 2002, the fair value of this swap, which was reflected as an asset,
was $0.4 million.
Weather Derivative: The utility tariffs associated with our New England gas
distribution operations do not contain a weather normalization clause. As a
result, fluctuations from normal weather may have a significant positive or
negative effect on the results of these operations. To mitigate the effect of
weather fluctuations on our financial position and cash flows, we entered into a
weather swap in October 2001. This derivative hedged approximately 15% of our
weather related risk for the November 2001 - March 2002 winter season. In
January 2002, we settled all our remaining weather derivatives and recorded a
gain of $0.3 million in Other Income. We intend to enter into additional
derivative instruments of this nature during 2002 if market conditions so
warrant.
PART II. OTHER INFORMATION
- ---------------------------
Item 1. Legal Proceedings
KeySpan has been cooperating in preliminary inquiries regarding trading in
KeySpan Corporation stock by individual officers of KeySpan prior to the July
17, 2001 announcement that KeySpan was taking a special charge in its Energy
Services business and otherwise reducing its 2001 earnings forecast. These
inquiries are being conducted by the U.S. Attorney's Office, Southern District
of New York, and the SEC.
As part of its continuing inquiry, on March 5, 2002, the SEC issued a formal
order of investigation, pursuant to which it will review the trading activity of
certain company insiders from May 1, 2001 to the present, as well as the
Company's compliance with its reporting rules and regulations, generally during
the period following the acquisition of the Roy Kay companies through the July
17th announcement.
Furthermore, KeySpan and certain of its officers and directors are defendants in
a number of class action lawsuits filed in the United States District Court for
the Eastern District of New York after the July 17th announcement.
46
These lawsuits allege, among other things, violations of Sections 10(b) and
20(a) of the Securities Exchange Act of 1934, as amended ("Exchange Act"), in
connection with disclosures relating to or following the acquisition of the Roy
Kay companies by KeySpan Services, Inc., a KeySpan subsidiary. Finally, in
October 2001, a shareholder's derivative action was commenced in the same court
against certain officers and directors of KeySpan, alleging, among other things,
breaches of fiduciary duty, violations of the New York Business Corporation Law
and violations of Section 20(a) of the Exchange Act. Each of the proceedings
seeks monetary damages in an unspecified amount. We are unable to determine the
outcome of these proceedings and what effect, if any, such outcome will have on
our financial condition, results of operations or cash flows.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
3.1* By-Laws
10.1* Amendment dated as of March 29, 2002 to Generation Purchase Right
Agreement by and between KeySpan Corporation, as Seller, and Long
Island Lighting Company d/b/a LIPA, as Buyer, dated of June 26, 1997.
12.1* Computation in support of ratio earnings to fixed charges.
b) Reports on Form 8-K
In our Report on Form 8-K, dated January 24, 2002, we disclosed our consolidated
earnings for the fiscal year ended December 31, 2001.
In our Report on Form 8-K, dated February 26, 2002, we disclosed an adjustment
to our earnings for the fiscal year ended December 31, 2001.
In our Report on Form 8-K, dated March 12, 2002, we disclosed that we had issued
a press release announcing, among other things, that we reached an agreement in
principle with the Long Island LIPA to extend LIPA's option to acquire our Long
Island power plants.
In our Report on Form 8-K, dated April 5, 2002, we disclosed that on March 29,
2002, our Board of Directors, upon recommendation of the Audit Committee,
determined not to renew the engagement of Arthur Andersen LLP as independent
public accountants and appointed Deloitte & Touche as our independent public
accountants.
In our Report on Form 8-K dated April 25, 2002, we disclosed that we had issued
a press release concerning, among other things, our earnings for the first
quarter ended March 31, 2002.
- ----------------------
*Filed Herewith
47
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: April 26, 2002 /s/ Gerald Luterman
------------------------------
Gerald Luterman
Senior Vice President and
Chief Financial Officer
Date: April 26, 2002 /s/ Ronald S. Jendras
--------------------------------
Ronald S. Jendras
Vice President, Controller
and Chief Accounting Officer
48