UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
[ ] For the quarterly period ended March 31, 2003
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition period from to
Commission file number 1-14161
KEYSPAN CORPORATION
(Exact name of Registrant as specified in its Charter)
New York 11-3431358
-------- ----------
(State or other jurisdiction of (IRS Employer Identification No.)
incorporation or organization)
One MetroTech Center, Brooklyn, New York 11201
175 East Old Country Road, Hicksville, New York 11801
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(Address of principal executive offices) (Zip Code)
(718) 403-1000 (Brooklyn)
(631) 755-6650 (Hicksville)
---------------------------
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. [X]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). [X]
APPLICABLE ONLY TO CORPORATE ISSUERS:
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class of Common Stock Outstanding at April 16, 2003
--------------------- -----------------------------
$.01 par value 157,321,304
KEYSPAN CORPORATION AND SUBSIDIARIES
INDEX
-----
Part I. FINANCIAL INFORMATION Page No.
--------
Item 1. Financial Statements
Consolidated Balance Sheet -
March 31, 2003 and December 31, 2002 3
Consolidated Statement of Income -
Three Months Ended March 31, 2003 and 2002
5
Consolidated Statement of Cash Flows -
Three Months Ended March 31, 2003 and 2002 6
Notes to Consolidated Financial Statements 7
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 31
Item 3. Quantitative and Qualitative Disclosures
About Market Risk 56
Part II. OTHER INFORMATION
Item 1. Legal Proceedings 60
Item 6. Exhibits and Reports on Form 8-K 60
Signatures 62
2
CONSOLIDATED BALANCE SHEET
(Unaudited)
- -------------------------------------------------------------------------------------------
(In Thousands of Dollars) March 31, 2003 December 31, 2002
- -------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash and temporary cash investments $ 244,062 $ 170,617
Accounts receivable 1,626,587 1,122,022
Unbilled revenue 505,477 473,060
Allowance for uncollectible accounts (79,949) (63,029)
Gas in storage, at average cost 87,569 297,060
Material and supplies, at average cost 121,221 113,519
Other 63,386 93,980
------------------ --------------------
2,568,353 2,207,229
------------------ --------------------
Investments and Other 268,878 265,977
Property
Gas 6,202,733 6,124,281
Electric 2,027,866 1,974,352
Other 395,732 394,374
Accumulated depreciation (2,807,495) (2,740,516)
Gas exploration and production, at cost 2,567,738 2,438,998
Accumulated depletion (1,010,770) (973,889)
------------------ --------------------
7,375,804 7,217,600
------------------ --------------------
Deferred Charges
Regulatory assets 444,388 438,516
Goodwill, net of amortization 1,789,166 1,789,751
Other 684,217 695,233
------------------ --------------------
2,917,771 2,923,500
------------------ --------------------
Total Assets $ 13,130,806 $ 12,614,306
================== ====================
- -------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
3
CONSOLIDATED BALANCE SHEET
(Unaudited)
- --------------------------------------------------------------------------------------------
(In Thousands of Dollars) March 31, 2003 December 31, 2002
- --------------------------------------------------------------------------------------------
LIABILITIES AND CAPITALIZATION
Current Liabilities
Current Redemption of long-term debt $ 11,414 $ 11,413
Accounts payable and other liabilities 1,212,406 1,061,649
Commercial paper 677,332 915,697
Dividends payable 71,166 64,714
Taxes accrued 254,687 51,276
Customer deposits 38,876 38,387
Interest accrued 85,416 77,092
------------------ ---------------------
2,351,297 2,220,228
------------------ ---------------------
Deferred Credits and Other Liabilities
Regulatory liabilities 72,230 84,479
Deferred income tax 887,708 877,013
Postretirement benefits and other reserves 867,681 759,731
Other 205,934 189,912
------------------ ---------------------
2,033,553 1,911,135
------------------ ---------------------
Commitments and Contingencies (See Note 8) - -
Capitalization
Common stock 3,481,607 3,005,354
Retained earnings 694,630 522,835
Other comprehensive income (114,221) (108,423)
Treasury stock (448,867) (475,174)
------------------ ---------------------
Total common shareholders' equity 3,613,149 2,944,592
Preferred stock 83,849 83,849
Long-term debt 4,740,231 5,224,081
------------------ ---------------------
Total Capitalization 8,437,229 8,252,522
------------------ ---------------------
Minority Interest in Subsidiary Companies 308,727 230,421
------------------ ---------------------
Total Liabilities and Capitalization $ 13,130,806 $ 12,614,306
================== =====================
- --------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
4
CONSOLIDATED STATEMENT OF INCOME
(Unaudited)
- ------------------------------------------------------------------------------------------
Three Months Ended March 31,
(In Thousands of Dollars, Except Per Share Amounts) 2003 2002
- ------------------------------------------------------------------------------------------
Revenues
Gas Distribution $ 1,832,701 $ 1,222,966
Electric Services 334,394 314,685
Energy Services 192,371 241,559
Gas Exploration and Production 127,847 76,926
Energy Investments 25,212 17,442
----------------------------------
Total Revenues 2,512,525 1,873,578
----------------------------------
Operating Expenses
Purchased gas for resale 1,196,165 649,360
Fuel and purchased power 97,522 84,372
Operations and maintenance 498,189 498,075
Depreciation, depletion and amortization 144,971 125,997
Operating taxes 124,713 113,902
----------------------------------
Total Operating Expenses 2,061,560 1,471,706
----------------------------------
Operating Income 450,965 401,872
----------------------------------
Other Income and (Deductions)
Interest charges (68,939) (72,612)
Gain on sale of subsidiary stock 19,020 -
Cost of debt redemption (18,194) -
Minority interest (18,054) (4,431)
Other 21,126 15,111
----------------------------------
Total Other Income and (Deductions) (65,041) (61,932)
----------------------------------
Earnings Before Income Taxes 385,924 339,940
Income Taxes
Current 129,575 (68,292)
Deferred 13,258 193,601
----------------------------------
Total Income Taxes 142,833 125,309
----------------------------------
Earnings Before Change in Accounting Principle 243,091 214,631
Cummulative Effect of Change in Accounting Principle 174 -
----------------------------------
Net Income 243,265 214,631
Preferred stock dividend requirements 1,461 1,476
----------------------------------
Earnings for Common Stock $ 241,804 $ 213,155
==================================
Basic Earnings Per Share:
Before Change in Accounting Principle,
less preferred stock dividends $ 1.54 $ 1.52
Change in Accounting Principle - -
----------------------------------
Basic Earnings Per Share $ 1.54 $ 1.52
==================================
Diluted Earnings Per Share
Before Change in Accounting Principle,
less preferred stock dividends $ 1.53 $ 1.51
Change in Accounting Principle - -
----------------------------------
Diluted Earnings Per Share $ 1.53 $ 1.51
==================================
Average Common Shares Outstanding (000) 156,886 140,039
Average Common Shares Outstanding - Diluted (000) 158,045 141,012
- ------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
5
CONSOLIDATED STATEMENT OF CASH FLOWS
- ---------------------------------------------------------------------------------------
(Unaudited) Three Months Ended March 31,
(In Thousands of Dollars) 2003 2002
- ---------------------------------------------------------------------------------------
Operating Activities
Net Income $ 243,265 $ 214,631
Adjustments to reconcile net income to net
cash provided by (used in) operating activities
Depreciation, depletion and amortization 144,971 125,997
Deferred income tax 13,258 19,822
Income from equity investments (6,425) (4,154)
Amortization of interest rate swap (2,500) -
Changes in assets and liabilities
Accounts receivable (520,062) (109,904)
Materials and supplies, fuel oil and gas in storage 201,789 181,101
Accounts payable and other liabilities 349,722 (219,144)
Interest accrued 8,324 43,874
Other 57,547 80,326
---------------------------------
Net Cash Provided by Operating Activities 489,889 332,549
---------------------------------
Investing Activities
Construction expenditures (220,779) (244,153)
Proceeds from monetization of Houston Exploration 79,200 -
---------------------------------
Net Cash Used in Investing Activities (141,579) (244,153)
---------------------------------
Financing Activities
Treasury stock issued 26,307 34,058
Equity Issuance 473,573 -
Issuance of long-term debt 39,161 10,401
Payment of long-term debt (72,565) (25,356)
Payment of commercial paper (238,365) (9,947)
Redemption of Promissory Notes (447,005) -
Preferred stock dividends paid (1,461) (1,476)
Common stock dividends paid (63,557) (62,207)
Other 9,047 (2,420)
---------------------------------
Net Cash Used in Financing Activities (274,865) (56,947)
---------------------------------
Net Increase in Cash and Cash Equivalents $ 73,445 $ 31,449
Cash and Cash Equivalents at Beginning of Period 170,617 159,252
---------------------------------
Cash and Cash Equivalents at End of Period $ 244,062 $ 190,701
=================================
- ---------------------------------------------------------------------------------------
Cash equivalents are short-term marketable securities purchased with maturities
of three months or less that were carried at cost which approximates fair value.
See accompanying Notes to the Consolidated Financial Statements.
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
KeySpan Corporation (referred to in the Notes to the Financial Statements as
"KeySpan," "we," "us" and "our") is a registered holding company under the
Public Utility Holding Company Act of 1935, as amended ("PUHCA"). KeySpan
operates six regulated utilities that distribute natural gas to approximately
2.5 million customers in New York City, Long Island, Massachusetts and New
Hampshire, making KeySpan the fifth largest gas distribution company in the
United States and the largest in the Northeast. We also own and operate electric
generating plants in Nassau and Suffolk Counties on Long Island and in Queens
County in New York City and are the largest investor owned electric generation
operator in New York State. Under contractual arrangements, we provide power,
electric transmission and distribution services, billing and other customer
services for approximately one million electric customers of the Long Island
Power Authority ("LIPA"). KeySpan's other subsidiaries are involved in gas and
oil exploration and production; gas storage; wholesale and retail gas and
electric marketing; appliance service; plumbing; heating, ventilation and air
conditioning and other mechanical services; large energy-system ownership,
installation and management; engineering and consulting services; and fiber
optic services. We also invest and participate in the development of, natural
gas pipelines, natural gas processing plants, and other energy-related projects,
domestically and internationally. (See Note 2 "Business Segments" for additional
information on each operating segment.)
1. BASIS OF PRESENTATION
In our opinion, the accompanying unaudited Consolidated Financial Statements
contain all adjustments necessary to present fairly KeySpan's financial position
as of March 31, 2003, and the results of operations for the three months ended
March 31, 2003 and March 31, 2002, as well as cash flows for the three months
ended March 31, 2003 and March 31, 2002. The accompanying financial statements
should be read in conjunction with the consolidated financial statements and
notes included in KeySpan's Annual Report on Form 10K for the year ended
December 31, 2002. The December 31, 2002 financial statement information has
been derived from the 2002 audited financial statements. Income from interim
periods may not be indicative of future results. Certain reclassifications were
made to conform prior period financial statements with the current period
financial statement presentation.
Basic earnings per share ("EPS") is calculated by dividing earnings available
for common stock by the weighted average number of shares of common stock
outstanding during the period. No dilution for any potentially dilutive
securities is included. Diluted EPS assumes the conversion of all potentially
dilutive securities and is calculated by dividing earnings available for common
stock, as adjusted, by the sum of the weighted average number of shares of
common stock outstanding plus all potentially dilutive securities.
7
We have approximately 2.1 million common stock options outstanding at March 31,
2003, that were not included in the calculation of diluted EPS since the
exercise price associated with these options was greater than the average market
price of our common stock.
Under the requirements of Statement of Financial Accounting Standards ("SFAS")
No. 128, "Earnings Per Share" our basic and diluted EPS are as follows:
- ------------------------------------------------------------------------------------------
Three Months Ended March 31,
(In Thousands of Dollars, Except Per Share Amounts) 2003 2002
- ------------------------------------------------------------------------------------------
Earnings for common stock $ 241,804 $ 213,155
Interest savings on convertible preferred stock 133 142
Houston Exploration dilution (87) (96)
- ------------------------------------------------------------------------------------------
Earnings for common stock - adjusted $ 241,850 $ 213,201
- ------------------------------------------------------------------------------------------
Weighted average shares outstanding (000) 156,886 140,039
Add dilutive securities:
Options 931 729
Convertible preferred stock 228 244
- ------------------------------------------------------------------------------------------
Total weighted average shares outstanding - assuming dilution 158,045 141,012
- ------------------------------------------------------------------------------------------
Basic earnings per share $ 1.54 $ 1.52
- ------------------------------------------------------------------------------------------
Diluted earnings per share $ 1.53 $ 1.51
- ------------------------------------------------------------------------------------------
2. BUSINESS SEGMENTS
We have four reportable segments: Gas Distribution, Electric Services, Energy
Services and Energy Investments.
The Gas Distribution segment consists of six gas distribution subsidiaries.
KeySpan Energy Delivery New York ("KEDNY") provides gas distribution services to
customers in the New York City Boroughs of Brooklyn, Queens and Staten Island.
KeySpan Energy Delivery Long Island ("KEDLI") provides gas distribution services
to customers in the Long Island Counties of Nassau and Suffolk and the Rockaway
Peninsula of Queens County. The remaining gas distribution subsidiaries, Boston
Gas Company, Colonial Gas Company, Essex Gas Company and EnergyNorth Natural
Gas, Inc., collectively referred to as KeySpan Energy Delivery New England
("KEDNE"), provide gas distribution service to customers in Massachusetts and
New Hampshire.
The Electric Services segment consists of subsidiaries that: operate the
electric transmission and distribution system owned by LIPA; own and provide
capacity to and produce energy for LIPA from our generating facilities located
on Long Island; and manage fuel supplies for LIPA to fuel our Long Island
generating facilities. These services are provided in accordance with long-term
service contracts having remaining terms that range from four to twelve years.
Also, in the summer of 2002, we placed two 79.9 megawatt generating facilities
into service; the capacity of and energy from these facilities are dedicated to
LIPA under 25 year contracts. The Electric Services segment also includes
8
subsidiaries that own, lease and operate the 2,200 megawatt Ravenswood electric
generation facility ("Ravenswood facility"), located in Queens, New York. All of
the energy, capacity and ancillary services related to the Ravenswood facility
is sold to the New York Independent System Operator ("NYISO") energy markets.
The Energy Services segment includes companies that provide energy-related
services to customers located within the New York City metropolitan area
including New Jersey and Connecticut, as well as Rhode Island, Pennsylvania,
Massachusetts and New Hampshire, through the following three lines of business:
(i) Home Energy Services, which provides residential customers with service and
maintenance of energy systems and appliances, as well as the retail marketing of
electricity to residential and small commercial customers; (ii) Business
Solutions, which provides plumbing, heating, ventilation, air conditioning and
mechanical services, as well as operation and maintenance, design, engineering
and consulting services to commercial and industrial customers; and (iii) Fiber
Optic Services, which provides various services to carriers of voice and data
transmission on Long Island and in New York City.
The Energy Investments segment consists of our gas exploration and production
investments, as well as certain other domestic and international energy-related
investments. Our gas exploration and production subsidiaries are engaged in gas
and oil exploration and production, and the development and acquisition of
domestic natural gas and oil properties. These investments consist of our 56%
equity interest in The Houston Exploration Company ("Houston Exploration"), an
independent natural gas and oil exploration company, as well as KeySpan
Exploration and Production, LLC, our wholly owned subsidiary engaged in a joint
venture with Houston Exploration. On February 26, 2003, we reduced our ownership
interest in Houston Exploration from 66% to 56% following the repurchase, by
Houston Exploration, of three million shares of common stock owned by KeySpan.
We realized net proceeds of $79 million in connection with this repurchase.
KeySpan follows an accounting policy of income statement recognition for Parent
company gains or losses from common stock transactions initiated by its
subsidiaries. As a result, KeySpan realized a gain of $19 million on this
transaction. Income taxes were not provided, since this transaction was
structured as a return of capital.
KeySpan subsidiaries also hold a 20% equity interest in the Iroquois Gas
Transmission System LP, a pipeline that transports Canadian gas supply to
markets in the Northeastern United States; a 50% interest in the Premier
Transmission Pipeline and a 24.5% interest in Phoenix Natural Gas, both in
Northern Ireland; 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.
9
The accounting policies of the segments are the same as those used for the
preparation of the Consolidated Financial Statements. The segments are strategic
business units that are managed separately because of their different operating
and regulatory environments. Operating results of our segments are evaluated by
management on an operating income basis. At March 31, 2003, the total assets of
each reportable segment have not changed materially from those levels reported
at December 31, 2002. The reportable segment information is as follows:
- -----------------------------------------------------------------------------------------------------------------------------------
Energy Investments
--------------------------
Gas
Exploration
Gas Electric Energy and Other
(InThousands of Dollars) Distribution Services Services Production Investments Eliminations Consolidated
- -----------------------------------------------------------------------------------------------------------------------------------
Three Months Ended March 31, 2003
Unaffiliated revenue 1,832,701 334,394 192,371 127,847 25,212 - 2,512,525
Intersegment revenue - 25 1,426 - 1,252 (2,703) -
Operating Income 364,937 39,670 (9,148) 55,590 4,467 (4,551) 450,965
Three Months Ended March 31, 2002
Unaffiliated revenue 1,222,966 314,685 241,559 76,926 17,442 - 1,873,578
Intersegment revenue - 25 - - 194 (219) -
Operating Income 331,019 61,494 (9,358) 19,825 551 (1,659) 401,872
- -----------------------------------------------------------------------------------------------------------------------------------
Eliminating items include intercompany interest income and expense, the
elimination of certain intercompany accounts, as well as activities of our
corporate and administrative areas.
Because of the nature of our Electric Services business, electric revenues are
derived from two large customers - the NYISO and LIPA. Electric Services
revenues from these customers of $334.4 million and $314.7 million for the three
months ended March 31, 2003 and 2002 represent approximately 13% and 17% of our
consolidated revenues, respectively.
3. COMPREHENSIVE INCOME
The table below indicates the components of comprehensive income.
- --------------------------------------------------------------------------------------------------------------------
Three Months Ended March 31,
(In Thousands of Dollars) 2003 2002
- --------------------------------------------------------------------------------------------------------------------
Net Income $ 243,265 $ 214,631
- --------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax
Net losses (gains) on derivative instruments 2,354 (7,287)
Foreign currency translation adjustments 9,753 (1,713)
Unrealized gains (losses) on marketable securities (3,156) (1,041)
Accrued unfunded pension obligation - (1,132)
Unrealized losses on derivative financial instruments (14,749) (23,785)
- --------------------------------------------------------------------------------------------------------------------
Other comprehensive loss, net of tax (5,798) (34,958)
- --------------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 237,467 $ 179,673
- --------------------------------------------------------------------------------------------------------------------
Related tax (benefit) expense
Net losses (gains) on derivative instruments 1,267 $ (3,924)
Foreign currency translation adjustments 5,252 (923)
Unrealized gains (losses) on marketable securities (1,699) (560)
Accrued unfunded pension obligation - (610)
Unrealized losses on derivative financial instruments (7,942) (12,807)
- --------------------------------------------------------------------------------------------------------------------
Total Tax (Benefit) Expense $ (3,122) $ (18,824)
- --------------------------------------------------------------------------------------------------------------------
10
4. CAPITAL STOCK
On January 17, 2003, we issued 13.9 million shares of common stock in a public
offering that generated net proceeds of approximately $473 million. All shares
were offered by KeySpan pursuant to the effective shelf registration statement
filed with the Securities and Exchange Commission ("SEC").
5. LONG-TERM DEBT
In connection with the KeySpan/Long Island Lighting Company ("LILCO") business
combination in 1998, KeySpan and certain of its subsidiaries issued promissory
notes to LIPA to support certain debt obligations assumed by LIPA. At December
31, 2002, the remaining principal amount of promissory notes issued to LIPA was
approximately $600 million. To mitigate the dilutive effect of the equity
issuance previously mentioned in Note 4, in March 2003, we called approximately
$447 million aggregate principal amount of such promissory notes at the
applicable redemption prices plus accrued and unpaid interest through the dates
of redemption. We applied the provisions of Statement of Financial Accounting
Standards ("SFAS") 145 "Rescission of FASB Statement No. 4, 44 and 64, Amendment
of FASB Statement No. 13, and Technical Corrections" and recorded an expense of
$18.2 million, reflecting redemption costs, as well as the write-off of
previously deferred debt issuance costs. This expense has been recorded in Other
Income and Deductions in the Consolidated Statement of Income.
In April 2003, we issued $300 million of medium-term and long-term debt. The
debt was issued in the following two series: (i) $150 million 4.65% Notes due
2013; and (ii) $150 million 5.875% Notes due 2033. The proceeds of this issuance
were used to pay down outstanding commercial paper.
KeySpan has the ability under the Public Utility Holding Company Act ("PUHCA")
to issue up to $2.2 billion of securities through December 31, 2003. Following
the recent common stock offering previously mentioned and shares of common stock
expected to be issued for employee benefit and dividend reinvestment plans, we
have approximately $25 million available for the issuance of new securities
under our current PUHCA authorization. However, the issuance of securities in
connection with the redemption of existing securities (including the promissory
notes discussed previously) is permitted under our PUHCA authorization
notwithstanding the foregoing limit. We intend to seek authorization from the
SEC in the near term to enable us to among, other things, issue additional
securities in an aggregate amount not yet determined. It is anticipated that
this authorization will be obtained before the end of the year.
11
6. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS
Financially-Settled Commodity Derivative Instruments: From time to time KeySpan
has utilized derivative financial instruments, such as futures, options and
swaps, for the purpose of hedging exposure to commodity price risk and to hedge
the cash flow variability associated with a portion of peak electric energy
sales.
Houston Exploration has utilized collars, as well as over-the-counter ("OTC")
swaps, to hedge the cash flow variability associated with forecasted sales of a
portion of its natural gas and oil production. As of March 31, 2003, Houston
Exploration has hedged approximately 67% and 38% of its estimated 2003 and 2004
gas production, respectively. Further, Houston Exploration may enter into
additional derivative positions for 2004. Houston Exploration used standard New
York Mercantile Exchange ("NYMEX") futures prices and published volatility in
its Black-Scholes calculation to value its outstanding derivatives. The maximum
length of time over which Houston Exploration has hedged such cash flow
variability associated with: (i) forecasted natural gas production is through
December 2004; and (ii) forecasted oil production is through June 2003. The
estimated amount of losses associated with such derivative instruments that are
reported in Other Comprehensive Income and that are expected to be reclassified
into earnings over the next twelve months is $52.2 million, or $33.9 million
after-tax.
With respect to price exposure associated with fuel purchases for the Ravenswood
facility, KeySpan employs standard NYMEX natural gas futures contracts and
over-the-counter financially settled natural gas basis swaps to hedge the cash
flow variability of a portion of forecasted purchases of natural gas. KeySpan
also employs the use of financially-settled oil swap contracts to hedge the cash
flow variability of a portion of forecasted purchases of fuel oil that will be
consumed at the Ravenswood facility. The maximum length of time over which we
have hedged cash flow variability associated with: (i) forecasted purchases of
natural gas is through October 2003; and (ii) forecasted purchases of fuel oil
is through April 2004. We used standard NYMEX futures prices to value the gas
futures contracts and industry published oil indices for number 6 grade fuel oil
to value the oil swap contracts. The estimated amount of gains associated with
all such derivative instruments that are reported in Other Comprehensive Income
and that are expected to be reclassified into earnings over the next twelve
months is $3.0 million, or $2.0 million after-tax.
Our retail gas and electric marketing subsidiary, our domestic gas distribution
operations and KeySpan Canada employ NYMEX natural gas futures contracts and
natural gas swaps to lock-in a price for expected future natural gas purchases.
As applicable, we used standard NYMEX futures prices and relevant natural gas
indices to value the outstanding contracts. The maximum length of time over
which we have hedged such cash flow variability is through October 2004. The
estimated amount of gains associated with such derivative instruments that are
reported in Other Comprehensive Income and that are expected to be reclassified
into earnings over the next twelve months is $3.7 million, or $2.4 million
after-tax.
12
We have also engaged in the use of cash-settled swap instruments to hedge the
cash flow variability associated with (i) a portion of forecasted peak electric
energy sales from the Ravenswood facility and (ii) forecasted sales of Unforced
Capacity ("UCAP") to the NYISO. The maximum length of time over which we have
hedged cash flow variability is through March 2004. We used NYISO-location zone
published indices as well as published NYISO bidding prices to value these
outstanding derivatives. The estimated amount of losses associated with such
derivative instruments that are reported in Other Comprehensive Income and that
are expected to be reclassified into earnings over the next twelve months is
$0.9 million, or $0.6 million after-tax.
KeySpan Canada also employs electricity swap contracts to lock-in the purchase
price of electricity needed to operate its gas processing plants. These
contracts are not exchange-traded and local published indices were used to value
these outstanding swap agreements. The maximum length of time over which we have
hedged such cash flow variability is through December 2003. The estimated amount
of losses associated with such derivative instruments that are reported in Other
Comprehensive Income and that are expected to be reclassified into earnings over
the next twelve months is $1.1 million, or $0.7 million after-tax.
The following tables set forth selected financial data associated with these
derivative financial instruments noted above that were outstanding at March 31,
2003.
- --------------------------------------------------------------------------------------------------------------------------------
Year of Volumes Fixed Current Fair Value
Type of Contract Maturity mmcf Floor $ Ceiling $ Price $ Price $ ($000)
- --------------------------------------------------------------------------------------------------------------------------------
Gas
Collars 2003 41,250 3.48 4.92 - 5.06 - 5.30 (24,881)
2004 36,600 3.75 5.05 - 4.33 - 5.38 (10,200)
Swaps/Futures - Short Natural Gas 2003 11,214 - - 3.19 - 3.57 4.22 - 5.30 (21,519)
Swaps/Futures - Long Natural Gas 2003 4,550 - - 3.14 - 4.92 5.06 - 5.30 6,249
2004 90 - - 3.49 - 4.35 3.90 - 4.40 31
- --------------------------------------------------------------------------------------------------------------------------------
93,704 (50,320)
- --------------------------------------------------------------------------------------------------------------------------------
13
- -------------------------------------------------------------------------------------------------------------------------------
Year of Volumes Fair Value
Type of Contract Maturity Barrels Fixed Price $ Current Price $ ($000)
- -------------------------------------------------------------------------------------------------------------------------------
Oil
Swaps - Short Fuel Oil 2003 91,000 29.70 28.03 - 30.42 (116)
Swaps - Long Fuel Oil 2003 81,697 20.60 - 23.50 26.41 - 33.58 639
2004 5,548 20.50 - 23.70 25.49 - 26.07 22
- -------------------------------------------------------------------------------------------------------------------------------
178,245 545
- -------------------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------------------
Year of Fixed Margin/ Fair Value
Type of Contract Maturity Capacity MWh Price $ Current Price $ ($000)
- ---------------------------------------------------------------------------------------------------------------------------------
Electricity
Swaps - Energy 2003 - 447,200 30.50 - 61.91 36.02 - 49.52 (647)
2004 99,200 14.00 23.56 - 32.41 (1,488)
Swaps - Capacity 2003 100 - 7.75 7.00 75
- ---------------------------------------------------------------------------------------------------------------------------------
100 546,400 (2,060)
- ---------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------
2003
Change in Fair Value of Derivative Instruments ($000)
- ------------------------------------------------------------------------------
Fair value of contracts at January 1, $ (32,628)
Losses on contracts realized 3,621
Fair value of new contracts when entered into during period -
(Decrease) in fair value of all open contracts (22,828)
- ------------------------------------------------------------------------------
Fair value of contracts outstanding at March 31, $ (51,835)
- ------------------------------------------------------------------------------
14
- -----------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- -----------------------------------------------------------------------------------------------------
Fair Value of Contracts
- -----------------------------------------------------------------------------------------------------
Maturity Maturity Total
Sources of Fair Value 2003 2004 Fair Value
- -----------------------------------------------------------------------------------------------------
Prices actively quoted $ (29,898) $ 31 $ (29,867)
Prices provided by external sources 417 - 417
Prices based on models and
other valuation methods (16,423) (4,424) (20,847)
Local published indicies (1,538) - (1,538)
- -----------------------------------------------------------------------------------------------------
$ (47,442) $ (4,393) $ (51,835)
- -----------------------------------------------------------------------------------------------------
NYMEX futures are also used to economically hedge the cash flow variability
associated with the purchase of fuel for a portion of our fleet vehicles.
Further, KeySpan Canada has a portfolio of financially-settled natural gas
collars and natural gas liquid swap transactions. Such contracts are executed by
KeySpan Canada to: (i) synthetically fix the price that is paid or received by
KeySpan Canada for certain physical transactions involving natural gas and
natural gas liquids and (ii) transfer the price exposure of such instruments to
counterparties. These derivative financial instruments do not qualify for hedge
accounting under SFAS 133. At March 31, 2003, these instruments had a net fair
market value of $0.06 million, that was recorded on the Consolidated Balance
Sheet. Based on the non-hedge designation of these instruments, the gain was
recognized in the Consolidated Statement of Income.
Firm Gas Sales Derivative Instruments - Regulated Utilities: We use derivative
financial instruments to reduce the cash flow variability associated with the
purchase price for a portion of future natural gas purchases associated with our
Gas Distribution operations. Our strategy is to minimize fluctuations in firm
gas sales prices to our regulated firm gas sales customers in our New York and
New Hampshire service territories. Since these derivative instruments are
employed to reduce the variability of the purchase price of natural gas to be
sold to regulated firm gas sales customers, the accounting for these derivative
instruments is subject to SFAS 71 "Accounting for the Effects of Certain Types
of Regulation". Therefore, changes in the market value of these derivatives have
been recorded as a Regulatory Asset or Regulatory Liability on the Consolidated
Balance Sheet. Gains or losses on the settlement of these contracts are
initially deferred and then refunded to or collected from our firm gas sales
customers consistent with regulatory requirements.
The following table sets forth selected financial data associated with these
derivative financial instruments that were outstanding at March 31, 2003.
- ---------------------------------------------------------------------------------------------------------------------
Year of Volumes Fair Value
Type of Contract Maturity mmcf Fixed Price $ Current Price $ ($000)
- ---------------------------------------------------------------------------------------------------------------------
Options 2003 1,030 4.01 - 6.00 5.06 - 5.30 (27)
2004 2,140 5.00 - 6.00 4.54 - 5.38 (793)
Swaps 2003 10,470 4.01 - 5.84 5.06 - 5.30 (2,682)
2004 3,890 4.42 - 5.93 4.41 - 5.38 (1,337)
- ---------------------------------------------------------------------------------------------------------------------
17,530 (4,839)
- ---------------------------------------------------------------------------------------------------------------------
15
Physically-Settled Commodity Derivative Instruments: Derivative Implementation
Group ("DIG") Issue C15 and C16 of Statement of Financial Accounting Standard
133, "Accounting for Derivative Instruments and Hedging Activities", as amended
and interpreted, incorporating SFAS 137 and SFAS 138 and certain implementation
issues (collectively "SFAS 133") establishes criteria that must be satisfied in
order for option-type and forward contracts in electricity to be exempted as
normal purchases and sales, and relates to the exemption (as normal purchases
and normal sales) of contracts that combine a forward contract and a purchased
option contract. Based upon a continuing review of our physical commodity
contracts, we determined that certain contracts for the physical purchase of
natural gas are not exempt as normal purchases from the requirements of SFAS
133. At March 31, 2003, the fair value of these contracts was a negative $4.9
million. Since these contracts are for the purchase of natural gas sold to
regulated firm gas sales customers, the accounting for these contracts is
subject to SFAS 71. Therefore, changes in the market value of these contracts
have been recorded as a Regulatory Asset or Regulatory Liability on the
Consolidated Balance Sheet.
Interest Rate Derivative Instruments: During 2002 we had interest rate swap
agreements in which approximately $1.3 billion of fixed rate debt had been
synthetically modified to floating rate debt. Under the terms of the agreements,
we received the fixed coupon rate associated with these bonds and paid the
counterparties a variable interest rate that was reset on a quarterly basis.
These swaps were designated as fair-value hedges and qualified for "short-cut"
hedge accounting treatment under SFAS 133.
In 2002, we terminated two interest rate swap agreements with an aggregate
notional amount of $1.0 billion. The remaining swap, which had a notional amount
of $270.0 million, was terminated on February 25, 2003. We received $18.4
million from our swap counterparties as a result of the latter termination, of
which $8.1 million represented accrued swap interest. The difference between the
termination settlement amount and the amount of accrued interest, $10.3 million,
was recorded to earnings in the first quarter of 2003. This swap was used to
hedge a portion of our outstanding promissory notes to LIPA. As discussed in
Note 5 "Long-Term Debt", we called a portion of these promissory notes during
the first quarter of 2003.
Additionally, we had an interest rate swap agreement that hedged the cash flow
variability associated with the forecasted issuance of a series of commercial
paper offerings. This hedge expired in March 2003.
16
Weather Derivatives: The utility tariffs associated with KEDNE's operations do
not contain weather normalization adjustments. As a result, fluctuations from
normal weather may have a significant positive or negative effect on the results
of these operations. To mitigate a substantial portion of the effect of
fluctuations from normal weather on our financial position and cash flows, we
sold heating degree-day call options and purchased heating-degree day put
options for the November 2002-March 2003 winter season. With respect to sold
call options, KeySpan was required to make a payment of $40,000 per heating
degree day to its counterparties when actual weather experienced during the
November 2002 - March 2003 time frame was above 4,470 heating degree days, which
equates to approximately 1% colder than normal weather. With respect to
purchased put options, KeySpan would receive a $20,000 per heating degree day
payment from its counterparties when actual weather was below 4,150 heating
degree days, or approximately 7% warmer than normal. Based on the terms of such
contracts, we account for such instruments pursuant to the requirements of EITF
99-2, "Accounting for Weather Derivatives." In this regard, we account for such
instruments using the "intrinsic value method" as set forth in such guidance.
During the first quarter of 2003, weather was 10% colder than normal and, as a
result, $11.9 million has been recorded as a reduction to revenues.
Derivative contracts are primarily used to manage exposure to market risk
arising from changes in commodity prices and interest rates. In the event of
nonperformance by a counterparty to a derivative contract, the desired impact
may not be achieved. The risk of counterparty nonperformance is generally
considered credit risk and is actively managed by assessing each counterparty
credit profile and negotiating appropriate levels of collateral and credit
support.
7. RECENT ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board ("FASB") issued SFAS 143,
"Accounting for Asset Retirement Obligations." SFAS 143 requires an entity to
record a liability and corresponding asset representing the present value of
legal obligations associated with the retirement of tangible, long-lived assets.
SFAS 143 was effective for fiscal years beginning after June 2002.
At March 31, 2003, the present value of our future Asset Retirement Obligation
("ARO") was approximately $57 million, primarily related to our investment in
Houston Exploration. The cumulative effect of SFAS 143 and the change in
accounting principle was a benefit to net income of $0.6 million, or $0.2
million, after-tax. KeySpan's largest asset base is its gas transmission and
distribution system. A legal obligation exists due to certain safety
requirements at final abandonment. In addition, a legal obligation may be
construed to exist with respect to KeySpan's liquefied natural gas ("LNG")
storage tanks due to clean up responsibilities upon cessation of use. However,
mass assets such as storage, transmission and distribution assets are believed
to operate in perpetuity and, therefore, have indeterminate cash flow estimates.
Since that exposure is in perpetuity and cannot be measured, no liability will
be recorded. KeySpan's ARO will be re-evaluated in future periods until
sufficient information exists to determine a reasonable estimate of fair value.
17
KeySpan recovers certain asset retirement costs through rates charged to
customers as a portion of depreciation expense. When depreciable properties are
retired, the original cost plus cost of removal less salvage, is charged to
accumulated depreciation. As of March 31, 2003, KeySpan had costs recovered in
excess of costs incurred totaling $422.5 million.
In January 2003, the FASB issued FASB Interpretation No. 46 "FIN 46",
"Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51."
FIN 46 requires certain variable interest entities to be consolidated by the
primary beneficiary of the entity if the equity investors in the entity do not
have the characteristics of a controlling financial interest or do not have
sufficient equity at risk for the entity to finance its activities without
additional subordinated financial support from other parties. FIN 46 is
effective for all new variable interest entities created or acquired after
January 31, 2003. For variable interest entities created or acquired prior to
February 1, 2003, the provisions of FIN 46 must be applied for the first interim
or annual period beginning after June 15, 2003. We currently have an arrangement
with a variable interest entity through which we lease a portion of the
Ravenswood facility and we will apply the provisions of FIN 46 beginning July 1,
2003. (See Note 9 "Variable Interest Entity" for a detailed description of this
leasing arrangement).
8. FINANCIAL GUARANTEES AND CONTINGENCIES
Environmental Matters
New York Sites. We have identified 28 manufactured gas plant ("MGP") sites and
related facilities in New York State that were historically owned or operated by
KeySpan subsidiaries or such companies' predecessors. Twenty seven of these
former sites, some of which are no longer owned by KeySpan, were associated with
the regulated gas businesses, and have been identified to both the Department of
Environmental Conservation ("DEC") for inclusion on appropriate site inventories
and listing with the New York Public Service Commission ("NYPSC"). The remaining
former MGP site was acquired when the Ravenswood facility was purchased from
Consolidated Edison Company of New York Inc. ("Consolidated Edison"). Fourteen
sites are currently the subjects of Administrative Orders on Consent ("ACOs") or
Voluntary Clean-Up Agreements ("VCAs") with the DEC.
We presently estimate the remaining environmental cleanup costs related to our
New York MGP sites will be $137.9 million, which amount has been accrued as a
reasonable estimate of probable cost for known sites. Expenditures incurred to
date with respect to these MGP-related sites total $53.5 million. The KEDNY and
KEDLI rate plans generally provide for the recovery of MGP related investigation
and remediation costs in rates charged to gas distribution customers. Under
prior rate orders, KEDNY has offset certain refunds due customers against its
estimated environmental cleanup costs for MGP sites. A regulatory asset of
$121.6 million for the New York/Long Island MGP sites is reflected at March 31,
2003.
18
KeySpan is also responsible for environmental obligations associated with the
Ravenswood electric generating facility. Our obligations do not include those
arising from disposal of waste at off-site locations prior to our acquisition of
the Ravenswood facility, or any from Consolidated Edison's post-closing conduct
associated with its transmission facilities at the site. Based on information
currently available, a liability of $3.6 million has been accrued. Expenditures
incurred to date with respect to these environmental obligations total $1.4
million.
New England Sites. Within the Commonwealth of Massachusetts and the State of New
Hampshire, we are aware of 76 former MGP sites and related facilities within the
existing or former service territories of KEDNE.
Boston Gas Company, Colonial Gas Company and Essex Gas Company may have or share
responsibility under applicable environmental laws for the remediation of 66 MGP
sites and related facilities. A subsidiary of National Grid USA ("National
Grid"), formerly New England Electric System, has assumed responsibility for
remediating 11 of these sites, subject to a limited contribution from Boston Gas
Company, and has provided full indemnification to Boston Gas Company with
respect to eight other sites. At this time, there is substantial uncertainty as
to whether Boston Gas Company, Colonial Gas Company or Essex Gas Company have or
share responsibility for remediating any of these other sites. No notice of
responsibility has been issued to us for any of these sites from any
governmental environmental authority.
We presently estimate the remaining cost of New England MGP-related
environmental cleanup activities will be $46.9 million, which amount has been
accrued as a reasonable estimate of probable cost for known sites. Expenditures
incurred since our acquisition of Eastern Enterprises on November 8, 2000 with
respect to these MGP-related activities total $16.7 million.
The Massachusetts Department of Telecommunications and Energy ("DTE") and the
New Hampshire Public Utilities Commission ("NHPUC") have issued rate orders that
provide for the recovery of site investigation and remediation costs in rates
charged to gas distribution customers. Accordingly, a regulatory asset of $58.4
million for the KEDNE MGP sites is reflected at March 31, 2003. 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 asset.
However, rate plans in effect for these subsidiaries provide for the recovery of
investigation and remediation costs.
KeySpan New England LLC Sites. We are aware of three non-utility sites
associated with the historical operations of KeySpan New England, LLC, the
successor company to Eastern Enterprises, for which we may have or share
environmental remediation responsibility or ongoing maintenance: the former
Philadelphia Coke site located in Pennsylvania; the former Connecticut Coke site
located in New Haven, Connecticut; and the Everett site, which includes the
19
former Coal Tar Processing Facility (the "Everett Coal Tar Facility"), Coke
Plant and a by-products facility located in Massachusetts. Honeywell
International, Inc. and Beazer East, Inc. (both former owners or operators of
the Everett Coal Tar Facility) together with KeySpan have entered into an ACO
with the Massachusetts Department of Environmental Protection for the
investigation and development of a remedial response plan for the Everett Coal
Tar Facility.
We presently estimate the remaining cost of our environmental cleanup activities
for the three non-utility sites will be approximately $38.8 million, which
amount has been accrued as a reasonable estimate of probable costs for known
sites. Expenditures incurred since November 8, 2000, with respect to these sites
total $4.5 million.
We believe that in the aggregate, the accrued liability for investigation and
remediation of sites and related facilities identified above are reasonable
estimates of likely cost within a range of reasonable, foreseeable costs. We may
be required to investigate and, if necessary, remediate each of these, or other
currently unknown former sites and related facility sites, the cost of which is
not presently determinable but may be material to our financial position,
results of operations or liquidity. Remediation costs for each site may be
materially higher than noted, depending upon remediation experience, selected
end use for each site, and actual environmental conditions encountered.
See KeySpan's Annual Report on Form 10K for the year ended December 31, 2002
Note 7 to those Consolidated Financial Statements "Contractual Obligations and
Contingencies" for further information on environmental matters.
Legal Matters
From time to time we are subject to various legal proceedings arising out of the
ordinary course of our business. Except as described below, or in KeySpan's
Annual Report on Form 10K for the year ended December 31, 2002, we do not
consider any of such proceedings to be material to our business or likely to
result in a material adverse effect on our results of operations, financial
condition or cash flows.
KeySpan has been cooperating in preliminary inquiries regarding trading in
KeySpan Corporation stock by individual officers of KeySpan prior to the July
17, 2001 announcement that KeySpan was taking a special charge in its Energy
Services business and otherwise reducing its 2001 earnings forecast. These
inquiries are being conducted by the U.S. Attorney's Office, Southern District
of New York and the SEC.
As previously reported, as part of its continuing inquiry, on March 5, 2002, the
SEC issued a formal order of investigation, pursuant to which it will review the
trading activity of certain company insiders from May 1, 2001 to the present, as
well as KeySpan's compliance with its reporting rules and regulations, generally
during the period following the acquisition by KeySpan Services, Inc., a KeySpan
subsidiary, of the Roy Kay companies through the July 17th announcement.
20
KeySpan and certain of its officers and directors are defendants in a number of
class action lawsuits filed in the United States District Court for the Eastern
District of New York after the July 17th announcement. These lawsuits allege,
among other things, violations of Sections 10(b) and 20(a) of the Securities
Exchange Act of 1934, as amended ("Exchange Act"), in connection with
disclosures relating to or following the acquisition of the Roy Kay companies
and the announcement of the agreement to acquire Eastern Enterprises and Energy
North Inc.. In October 2001, a shareholder's derivative action was commenced in
the same court against certain officers and directors of KeySpan, alleging,
among other things, breaches of fiduciary duty, violations of the New York
Business Corporation Law and violations of Section 20(a) of the Exchange Act. In
addition, a second derivative action has been commenced asserting similar
allegations. Each of the proceedings seek monetary damages in an unspecified
amount. On March 18, 2003 the court granted our motion to dismiss the class
action complaint. The court's order dismissed certain class allegations with
prejudice, but provided the plaintiffs a final opportunity to file an amended
complaint concerning the remaining allegations. In April 2003, the plaintiff
filed an amended complaint and we intend to file a motion to dismiss the
complaint. We are unable to predict the outcome of these proceedings or effect,
if any, such outcome will have on our financial condition, results of operations
or cash flows.
KeySpan subsidiaries, along with several other parties, have been named as
defendants in numerous proceedings filed by plaintiffs claiming various degrees
of injury from asbestos exposure at generating facilities formerly owned by Long
Island Lighting Company and others. In March 2003, a jury rendered a verdict in
one such proceeding against our subsidiary, KeySpan Generation LLC ("KeySpan
Generation"), and other defendants in the amount of $47 million. KeySpan has
moved to set aside this verdict and, if necessary, will prosecute an appeal, on
the grounds that, among other things, the amount of the verdict is excessive and
unreasonable and the finding of liability against KeySpan Generation is not
supported by the evidence.
In connection with the May 1998 transaction with the Long Island Power Authority
("LIPA"), costs incurred by KeySpan for liabilities for asbestos exposure
arising from the activities of the generating facilities previously owned by the
Long Island Lighting Company, including the facility involved in the case
referred to above, are recoverable from LIPA through the Power Supply Agreement
between LIPA and KeySpan. KeySpan's cost recovery under the Power Supply
Agreement is reduced by any insurance recoveries received by KeySpan Generation
and by amounts received by KeySpan Generation from other indemnification claims
it is pursuing.
KeySpan is unable to determine the outcome of the appeals of the above
referenced action or the outcome of any of these other proceedings, but does not
believe, for the reasons set forth above, that such outcome, if adverse, will
have a material effect on its financial condition or results of operation.
KeySpan believes that its cost recovery rights under the Power Supply Agreement,
its indemnification rights against third parties and its insurance coverage
(above applicable deductible limits) cover its exposure in this case and for
asbestos liabilities generally.
Financial Guarantees
KeySpan has issued financial guarantees in the normal course of business,
primarily on behalf of its subsidiaries, to various third party creditors. At
March 31, 2003, the following amounts would have to be paid by KeySpan in the
event of non-payment by the primary obligor at the time payment is due:
- ------------------------------------------------------------------------------------------------------------
Amount of Expiration
Nature of Guarantee (In Thousands of Dollars) Exposure Dates
- ------------------------------------------------------------------------------------------------------------
Guarantees for Subsidiaries
Medium-Term Notes - KEDLI (i) $ 525,000 2008-2010
Master Lease - Ravenswood (ii) 425,000 2004
Revolving Credit Agreement - KeySpan Canada (iii) 130,000 2004
Surety Bonds (iv) 150,080 Revolving
Commodity Guarantees and Other (v) 99,967 2005
Letters of Credit (vi) 64,822 2003
- ------------------------------------------------------------------------------------------------------------
Guarantees for Non-Affiliates
Third Party Line of Credit (vii) 25,000 2004
Surety Bonds (vii) 8,725 Revolving
- ------------------------------------------------------------------------------------------------------------
$ 1,428,594
- ------------------------------------------------------------------------------------------------------------
21
The following is a description of KeySpan's outstanding subsidiary guarantees:
(i) KeySpan has fully and unconditionally guaranteed $525 million to holders of
Medium-Term Notes issued by KEDLI. These notes are due to be repaid on
January 15, 2008 and February 1, 2010. KEDLI is required to comply with
certain financial covenants under the debt agreements. Currently, KEDLI is
in compliance with all covenants and management does not anticipate that
KEDLI will have any difficulty maintaining such compliance. The face value
of these notes is included in Long-Term Debt on the Consolidated Balance
Sheet.
(ii) KeySpan has guaranteed all payment and performance obligations of KeySpan
Ravenswood, LLC, the lessee under the $425 million Ravenswood Master Lease
(the "Master Lease") associated with the lease of the Ravenswood facility.
The initial term of the lease expires on June 20, 2004 and may be extended
until June 20, 2009. For further information, see Note 9 "Variable Interest
Entity."
(iii)KeySpan has fully and unconditionally guaranteed a US $130 million
revolving credit agreement associated with KeySpan Canada. The term of the
agreement expires January 1, 2004.
(iv) KeySpan has agreed to indemnify the issuers of various surety and
performance bonds associated with certain construction projects currently
being performed by subsidiaries within the Energy Services segment. In the
event that the operating companies in the Energy Services segment fail to
perform their obligations under contract, the injured party may demand that
the surety make payments or provide services under the bond. KeySpan would
then be obligated to reimburse the surety for any expenses or cash outlays
it incurs.
(v) KeySpan has guaranteed commodity-related payments for subsidiaries within
the Energy Services segment, as well as KeySpan Ravenswood, LLC. These
guarantees are provided to third parties to facilitate physical and
financial transactions involved in the purchase of natural gas, oil and
other petroleum products for electric production and marketing activities.
The guarantees cover actual purchases by these subsidiaries that are still
outstanding as of March 31, 2003.
(vi) KeySpan has arranged for stand-by letters of credit in the amount of $64.8
million to be issued to third parties that have extended credit to certain
subsidiaries. Certain vendors require us to post letters of credit to
guarantee subsidiary performance under our contracts and to ensure payment
to our subsidiary subcontractors and vendors under those contracts. Certain
of our vendors also require letters of credit to ensure reimbursement for
amounts they are disbursing on behalf of our subsidiaries, such as to
beneficiaries under our self-funded insurance programs. Such letters of
credit are generally issued by a bank or similar financial institution. The
letters of credit commit the issuer to pay specified amounts to the holder
of the letter of credit if the holder demonstrates that we have failed to
perform specified actions. If this were to occur, KeySpan would be required
to reimburse the issuer of the letter of credit.
22
To date, KeySpan has not had a claim made against it for any of the above
guarantees and we have no reason to believe that our subsidiaries will default
on their current obligations. However, we cannot predict when or if any defaults
may take place or the impact such defaults may have on our consolidated results
of operations, financial condition or cash flows.
The following is a description of KeySpan's outstanding guarantees to
non-affiliates:
(vii)KeySpan has agreed to support a line of credit up to $25 million on behalf
of Hawkeye Construction ("Hawkeye"), a non-affiliated company. It also
assisted Hawkeye in obtaining performance bonds. The guarantees related to
their line of credit extend through 2004. To the extent Hawkeye does not
meet its obligations, KeySpan could be liable for the amount of the
outstanding guarantees. At March 31, 2003, the amount guaranteed was $25
million.
If Hawkeye fails to perform under a contract or to pay subcontractors and
vendors, the counterparty that requested the performance bond may demand
that the surety make payments or provide services under the bond. KeySpan
would then have to reimburse the surety for any expenses or outlays the
surety incurs. To date, we have not had a claim made against either the
guarantee associated with the line of credit or the performance bonds.
KeySpan is presently engaged in a legal action with Hawkeye. (See KeySpan's
Annual Report on form 10K for the year ended December 31, 2002 Note 7
"Contractual Obligations, Financial Guarantees and Contingencies" for
further information on this legal proceeding.)
9. VARIABLE INTEREST ENTITY
KeySpan has an arrangement with a variable interest entity through which we
lease a portion of the Ravenswood facility. We acquired the Ravenswood facility,
in part, through the variable interest entity from Consolidated Edison on June
18, 1999 for approximately $597 million. In order to reduce the initial cash
requirements, we entered into the Master Lease with a variable interest,
unaffiliated financing entity that acquired a portion of the facility, three
steam generating units, directly from Consolidated Edison and leased it to our
subsidiary. The variable interest unaffiliated financing entity acquired the
property for $425 million, financed with debt of $412.3 million (97% of
capitalization) and equity of $12.7 million (3% of capitalization). KeySpan has
no ownership interests in the steam units or in the variable interest entity.
KeySpan has guaranteed all payment and performance obligations of our subsidiary
under the Master Lease. The Master Lease represents approximately $425 million
of the acquisition cost of the facility, which is the amount of debt that would
have been recorded on our Consolidated Balance Sheet had the variable interest
entity not been utilized and conventional debt financing been employed. Further,
we would have recorded an asset in the same amount. Monthly lease payments equal
the monthly interest expense on such debt securities. The Master Lease currently
qualifies as an operating lease for financial reporting purposes.
23
The initial term of the Master Lease expires on June 20, 2004 and may be
extended until June 20, 2009. In June 2004, we have the right to: (i) either
purchase the facility for the original acquisition cost of $425 million, plus
the present value of the lease payments that would otherwise have been paid
through June 2009; (ii) terminate the Master Lease and dispose of the facility;
or (iii) otherwise extend the Master Lease to 2009. If the Master Lease is
terminated in 2004, KeySpan has guaranteed an amount approximately equal to 83%
of the residual value of the original cost of the property, plus the present
value of the lease payments that would have otherwise been paid through June 20,
2009. In June 2009, when the Master Lease terminates, we may purchase the
facility in an amount equal to the original acquisition cost, subject to
adjustment, or surrender the facility to the lessor. If we elect not to purchase
the property, the Ravenswood facility will be sold by the lessor. We have
guaranteed to the lessor 84% of the residual value of the original cost of the
property.
In January 2003, the FASB issued FIN 46, "Consolidation of Variable Interest
Entities, an Interpretation of ARB No. 51." FIN 46 requires KeySpan, based upon
its current status as the primary beneficiary, to consolidate this variable
interest entity for the first interim period ending after June 15, 2003. It also
requires that assets, liabilities and non-controlling interests of the variable
interest entity be consolidated at fair value, except to the extent that to do
so would result in a gain to KeySpan. KeySpan believes that the fair market
value of the Ravenswood facility exceeds the fair market value of the lease
obligation.
Prospectively, KeySpan will have a $425 million asset that will be amortized
over the economic life of the leased property. However, upon implementation,
there will be a cumulative catch-up adjustment for a change in accounting policy
as if the asset had been owned from inception, or June 20, 1999. Therefore, at
July 1, 2003, assuming a 35 year economic life, KeySpan will be deemed to have
owned the asset for approximately 4 years and it is anticipated that we will
record a $29.1 million after-tax charge, or $0.18 per share, change in
accounting principle on the Consolidated Statement of Income. Upon
implementation of FIN 46, therefore, we anticipate recording an asset of
approximately $376 million and debt of $425 million.
Based upon expected average outstanding shares, we anticipate the incremental
impact of the additional depreciation expense for the remaining six months of
2003 to be approximately $0.02 per share. In addition, KeySpan is also
conducting a study to determine the fair value of the Ravenswood facility.
Although considered unlikely, to the extent the fair value of the Ravenswood
facility was less than the value of the lease obligation, then a loss would be
recognized upon consolidation.
If our subsidiary that leases the Ravenswood facility was not able to fulfill
its payment obligations with respect to the Master Lease payments, then the
maximum amount KeySpan would be exposed to under its current guarantees would be
$425 million plus the present value of the remaining lease payments through June
20, 2009.
24
10. STOCK OPTIONS
Stock options have been issued to KeySpan officers, directors and certain other
management employees and consultants as approved by the Board of Directors.
These options generally vest over a three-to-five year period and have a
ten-year exercise period. Moreover, under a separate plan, Houston Exploration
has issued stock options to its directors and key Houston Exploration employees.
During 2002, we announced our intention to record stock options as a
compensation expense beginning with those options granted in 2003. In 2003,
KeySpan and Houston Exploration adopted the prospective method of transition in
accordance with SFAS 148 "Accounting for Stock-Based Compensation - Transition
and Disclosure". Accordingly, compensation expense has been recognized by
employing the fair value recognition provisions of SFAS 123 "Accounting for
Stock-Based Compensation" for grants awarded after January 1, 2003.
KeySpan and Houston Exploration continue to apply APB Opinion 25, "Accounting
for Stock Issued to Employees," and related Interpretations in accounting for
grants awarded prior to January 1, 2003. Accordingly, no compensation cost has
been recognized for these fixed stock option plans in the Consolidated Financial
Statements since the exercise prices and market values were equal on the grant
dates. Had compensation cost for these plans been determined based on the fair
value at the grant dates for awards under the plans consistent with SFAS 123,
our net income and earnings per share would have decreased to the pro-forma
amounts indicated below:
- ------------------------------------------------------------------------------------------------------------------------------
Three Months Ended March 31,
(In Thousands of Dollars, Except Per Share Amounts) 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Earnings available for common stock:
As reported $ 241,804 $ 213,155
Add: recorded stock-based compensation expense, net of tax 857 -
Deduct: total stock-based compensation expense, net of tax (2,913) (1,831)
- ------------------------------------------------------------------------------------------------------------------------------
Pro-forma earnings $ 239,748 $ 211,324
- ------------------------------------------------------------------------------------------------------------------------------
Earnings per share:
Basic - as reported $ 1.54 $ 1.52
Basic - pro-forma $ 1.53 $ 1.51
Diluted - as reported $ 1.53 $ 1.51
Diluted - pro-forma $ 1.52 $ 1.50
- ------------------------------------------------------------------------------------------------------------------------------
11. SUBSEQUENT EVENTS
Boston Gas Company's gas rates for local distribution service were governed by a
five-year performance-based rate plan approved by the Department of
Telecommunications and Energy ("DTE") in 1996 (the "Plan"), that expired in
October 2002. Boston Gas Company filed a base rate case and performance based
rate plan on April 16, 2003, to be effective in the fourth quarter of 2003. The
filing requests an annual revenue increase of approximately $61 million and a
performance based rate plan term of five years.
25
In its order approving the acquisition by KeySpan of Eastern Enterprises Inc.,
the SEC reserved jurisdiction on its determination of whether the Energy
Services companies were retainable under existing PUHCA rule or precedent. On
April 24, 2003, the SEC issued an order authorizing the retention of these
companies.
On May 1, 2003, KeySpan's gas and electric marketing subsidiary, KeySpan Energy
Services, assigned a substantial portion of its retail natural gas customers,
consisting mostly of residential and small commercial customers, to ECONnergy
Energy Co., Inc. ("ECONnergy"). ECONnergy is one of the largest deregulated
energy service companies in the Northeast. KeySpan Energy Services will continue
to provided retail natural gas marketing to a small number of customers in New
Jersey and will continue its electric marketing activities.
12. KEYSPAN GAS EAST CORPORATION SUMMARY FINANCIAL INFORMATION
KEDLI is a wholly owned subsidiary of KeySpan. KEDLI was formed on May 7, 1998
and on May 28, 1998 acquired substantially all of the assets related to the gas
distribution business of LILCO. KEDLI established a program for the issuance,
from time to time, of up to $600 million aggregate principal amount of
Medium-Term Notes, which are fully and unconditionally guaranteed by the parent,
KeySpan Corporation. On February 1, 2000, KEDLI issued $400 million of 7.875%
Medium-Term Notes due 2010. In January 2001, KEDLI issued an additional $125
million of Medium-Term Notes at 6.9% due January 2008. The following condensed
financial statements are required to be disclosed by SEC regulations and set
forth those of KEDLI, KeySpan Corporation as guarantor of the Medium-Term Notes
and our other subsidiaries on a combined basis. The March 31, 2002 disclosures
have been revised to separately present our other subsidiaries.
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Income
- ------------------------------------------------------------------------------------------------------------------------------------
Three Months Ended March 31, 2003
(In Thousands of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Revenues $ 143 $478,345 $2,034,180 $ (143) $ 2,512,525
Operating Expenses
Purchased gas - 287,009 909,156 - 1,196,165
Fuel and purchased power - - 97,522 - 97,522
Operations and maintenance 7,259 38,220 452,710 - 498,189
Intercompany expense 34 1,182 (1,182) (34) -
Depreciation and amortization (20) 26,920 118,071 - 144,971
Operating taxes - 24,005 100,708 - 124,713
------------------------------------------------------------------------------------
Total Operating Expenses 7,273 377,336 1,676,985 (34) 2,061,560
------------------------------------------------------------------------------------
Operating Income (Loss) (7,130) 101,009 357,195 (109) 450,965
Interest charges (46,477) (15,006) (52,299) 44,843 (68,939)
Other income and (deductions) 293,453 (7,217) 10,243 (292,581) 3,898
------------------------------------------------------------------------------------
Total Other Income and (Deductions) 246,976 (22,223) (42,056) (247,738) (65,041)
Income (Loss) Before Income Taxes 239,846 78,786 315,139 (247,847) 385,924
Income Taxes (3,419) 28,312 117,940 - 142,833
------------------------------------------------------------------------------------
Earnings before Change in Accounting Principle $ 243,265 $ 50,474 $ 197,199 $ (247,847) $ 243,091
Cumulative Effect of Change in Accouting
Principle - - 174 - 174
------------------------------------------------------------------------------------
Net Income $ 243,265 $ 50,474 $ 197,373 $ (247,847) $ 243,265
====================================================================================
26
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Income
- ------------------------------------------------------------------------------------------------------------------------------------
Three Months Ended March 31, 2002
(In Thousands of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Revenues $ 104 $ 318,947 $ 1,554,631 $ (104) $ 1,873,578
Operating Expenses
Purchased gas - 142,867 506,493 - 649,360
Fuel and purchased power - - 84,372 - 84,372
Operations and maintenance 1,506 12,001 484,568 - 498,075
Intercompany expense 56 18,209 (18,209) (56) -
Depreciation and amortization - 20,241 105,756 - 125,997
Operating taxes 570 25,386 87,946 - 113,902
--------------------------------------------------------------------------------------
Total Operating Expenses 2,132 218,704 1,250,926 (56) 1,471,706
--------------------------------------------------------------------------------------
Operating Income (Loss) (2,028) 100,243 303,705 (48) 401,872
Interest charges (46,929) (15,202) (67,772) 57,291 (72,612)
Other income and (deductions) 263,251 2,902 17,056 (272,529) 10,680
--------------------------------------------------------------------------------------
Total Other Income and (Deductions) 216,322 (12,300) (50,716) (215,238) (61,932)
Income (Loss) Before Income Taxes 214,294 87,943 252,989 (215,286) 339,940
Income Taxes (337) 37,081 88,565 - 125,309
--------------------------------------------------------------------------------------
Net Income $ 214,631 $ 50,862 $ 164,424 $ (215,286) $ 214,631
======================================================================================
27
- -----------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
- -----------------------------------------------------------------------------------------------------------------------------------
March 31, 2003
Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
--------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash & temporary cash investments $ 90,558 $ 14,285 $ 139,219 $ - $ 244,062
Accounts receivable, net 8,206 331,104 1,712,805 - 2,052,115
Other current assets 1,550 13,048 257,578 - 272,176
--------------------------------------------------------------------------------------
100,314 358,437 2,109,602 - 2,568,353
--------------------------------------------------------------------------------------
Investments and Other 3,922,991 2,629 207,382 (3,864,124) 268,878
--------------------------------------------------------------------------------------
Property
Gas - 1,796,884 4,405,849 - 6,202,733
Other - - 4,991,336 - 4,991,336
Accumulated depreciation and depletion - (330,384) (3,487,881) - (3,818,265)
--------------------------------------------------------------------------------------
- 1,466,500 5,909,304 - 7,375,804
--------------------------------------------------------------------------------------
Intercompany Accounts Receivable 3,683,508 13,637 634,910 (4,332,055) -
Deferred Charges 323,858 187,739 2,406,174 - 2,917,771
--------------------------------------------------------------------------------------
Total Assets $ 8,030,671 $ 2,028,942 $ 11,267,372 $ (8,196,179) $ 13,130,806
======================================================================================
LIABILITIES AND CAPITALIZATION
Current Liabilities
Accounts payable $ 74,724 $ 121,056 $ 1,016,626 $ - $ 1,212,406
Commercial paper 677,332 - - - 677,332
Other current liabilities 325,258 163,662 (27,361) - 461,559
--------------------------------------------------------------------------------------
1,077,314 284,718 989,265 - 2,351,297
--------------------------------------------------------------------------------------
Intercompany Accounts Payable - 105,215 2,095,456 (2,200,671) -
--------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax (45,924) 142,933 790,699 - 887,708
Other deferred credits and liabilities 509,695 97,609 538,541 - 1,145,845
--------------------------------------------------------------------------------------
463,771 240,542 1,329,240 - 2,033,553
--------------------------------------------------------------------------------------
Capitalization
Common shareholders' equity 3,655,742 697,563 3,123,968 (3,864,124) 3,613,149
Preferred stock 83,849 - - - 83,849
Long-term debt 2,749,995 700,904 3,420,716 (2,131,384) 4,740,231
--------------------------------------------------------------------------------------
Total Capitalization 6,489,586 1,398,467 6,544,684 (5,995,508) 8,437,229
--------------------------------------------------------------------------------------
Minority Interest in Subsidiary Companies - - 308,727 - 308,727
--------------------------------------------------------------------------------------
Total Liabilities & Capitalization $ 8,030,671 $ 2,028,942 $ 11,267,372 $ (8,196,179) $ 13,130,806
======================================================================================
28
- -----------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
- -----------------------------------------------------------------------------------------------------------------------------------
December 31, 2002
Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
----------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash & temporary cash investments $ 88,308 $ 6,472 $ 75,837 $ - $ 170,617
Accounts receivable, net 23,982 208,512 1,299,559 - 1,532,053
Other current assets 1,757 79,206 423,596 - 504,559
----------------------------------------------------------------------------------------
114,047 294,190 1,798,992 - 2,207,229
----------------------------------------------------------------------------------------
Investments and Other 3,797,964 2,717 201,675 (3,736,379) 265,977
----------------------------------------------------------------------------------------
Property
Gas - 1,771,780 4,352,501 - 6,124,281
Other - - 4,807,724 - 4,807,724
Accumulated depreciation and depletion - (322,236) (3,392,169) - (3,714,405)
----------------------------------------------------------------------------------------
- 1,449,544 5,768,056 - 7,217,600
----------------------------------------------------------------------------------------
Intercompany Accounts Receivable 3,619,515 54,549 822,725 (4,496,789) -
Deferred Charges 339,443 192,652 2,391,405 - 2,923,500
----------------------------------------------------------------------------------------
Total Assets $ 7,870,969 $ 1,993,652 $ 10,982,853 $ (8,233,168) $ 12,614,306
========================================================================================
LIABILITIES AND CAPITALIZATION
Current Liabilities
Accounts payable $ 132,966 $ 68,772 $ 859,911 $ - $ 1,061,649
Commercial paper 915,697 - - - 915,697
Other current liabilities 107,605 104,975 30,302 - 242,882
----------------------------------------------------------------------------------------
1,156,268 173,747 890,213 - 2,220,228
----------------------------------------------------------------------------------------
Intercompany Accounts Payable - 233,392 2,182,013 (2,415,405) -
----------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax (43,110) 139,715 780,408 - 877,013
Other deferred credits and liabilities 481,964 98,805 453,353 - 1,034,122
----------------------------------------------------------------------------------------
438,854 238,520 1,233,761 - 1,911,135
----------------------------------------------------------------------------------------
Capitalization
Common shareholders' equity 2,983,214 647,089 3,050,668 (3,736,379) 2,944,592
Preferred stock 83,849 - - - 83,849
Long-term debt 3,208,784 700,904 3,395,777 (2,081,384) 5,224,081
----------------------------------------------------------------------------------------
Total Capitalization 6,275,847 1,347,993 6,446,445 (5,817,763) 8,252,522
----------------------------------------------------------------------------------------
Minority Interest in Subsidiary Companies - - 230,421 - 230,421
----------------------------------------------------------------------------------------
Total Liabilities & Capitalization $ 7,870,969 $ 1,993,652 $ 10,982,853 $ (8,233,168) $ 12,614,306
========================================================================================
29
- -------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
- -------------------------------------------------------------------------------------------------------------------------------
Three Months Ended March 31, 2003
------------------------------------------------------------------------
Guarantor KEDLI Other Subsidiaries Consolidated
------------------------------------------------------------------------
Operating Activities
Net Cash Provided by Operating Activities $ 239,598 $ 121,019 $ 129,272 $ 489,889
------------------------------------------------------------------------
Investing Activities
Capital expenditures - (25,941) (194,838) (220,779)
Proceeds from Monetization of Houston Exploration 79,200 - - 79,200
------------------------------------------------------------------------
Net Cash Provided by (Used in) Investing Activities 79,200 (25,941) (194,838) (141,579)
------------------------------------------------------------------------
Financing Activities
Treasury stock issued 26,307 - - 26,307
Equity Issuance 473,573 - - 473,573
Redemption of Promissory Notes (447,005) - - (447,005)
Payment of debt, net (238,365) - (33,404) (271,769)
Common and preferred stock dividends paid (65,018) - - (65,018)
Other 7,153 - 1,894 9,047
Net intercompany accounts (73,193) (87,265) 160,458 -
-
------------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities (316,548) (87,265) 128,948 (274,865)
------------------------------------------------------------------------
Net Increase in Cash and Cash Equivalents $ 2,250 $ 7,813 $ 63,382 $ 73,445
Cash and Cash Equivalents at Beginning of Period 88,308 6,472 75,837 170,617
------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 90,558 $ 14,285 $ 139,219 $ 244,062
========================================================================
- ---------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
- ---------------------------------------------------------------------------------------------------------------------------------
Three Months Ended March 31, 2002
------------------------------------------------------------------------
Guarantor KEDLI Other Subsidiaries Consolidated
------------------------------------------------------------------------
Operating Activities
Net Cash Provided by (Used in) Operating Activities $ 60,515 $ 302,490 $ (30,456) $ 332,549
------------------------------------------------------------------------
Investing Activities
Capital expenditures - (29,168) (214,985) (244,153)
------------------------------------------------------------------------
Net Cash Used in Investing Activities - (29,168) (214,985) (244,153)
------------------------------------------------------------------------
Financing Activities
Treasury stock issued 34,058 - - 34,058
Payment of debt, net (9,947) - (14,955) (24,902)
Common and preferred stock dividends paid (63,683) - - (63,683)
Other 8,127 - (10,547) (2,420)
Net intercompany accounts 124,019 (273,322) 149,303 -
-
------------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities 92,574 (273,322) 123,801 (56,947)
------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents $ 153,089 $ - $ (121,640) $ 31,449
Cash and Cash Equivalents at Beginning of Period - - 159,252 159,252
------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 153,089 $ - $ 37,612 $ 190,701
========================================================================
30
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, 2003, compared to the three months ended March 31, 2002.
Capitalized terms used in the following discussion, but not otherwise defined,
have the same meaning as when used in the Notes to the Consolidated Financial
Statements included under Item 1. References to "KeySpan", "we", "us", and "our"
mean KeySpan Corporation, together with its consolidated subsidiaries.
Operating income by segment, as well as consolidated earnings available for
common stock is set forth in the following table for the periods indicated.
- --------------------------------------------------------------------------------
(In Thousands of Dollars, Except per Share)
- -------------------------------------------------------------------------------
Quarter Ended March 31, 2003 2002
- -------------------------------------------------------------------------------
Gas Distribution $364,937 $331,019
Electric Services 39,670 61,494
Energy Services (9,148) (9,358)
Energy Investments 60,057 20,376
Eliminations and other (4,551) (1,659)
- -------------------------------------------------------------------------------
Operating Income 450,965 401,872
Other Income and (Deductions) (65,041) (61,932)
Income taxes 142,833 125,309
- -------------------------------------------------------------------------------
Income before cumulative effect
of a change in accounting principle 243,091 214,631
Cumulative effect of a change
in accounting principle (See Note 7) 174 -
- -------------------------------------------------------------------------------
Net Income 243,265 214,631
Preferred stock dividend requirements 1,461 1,476
- -------------------------------------------------------------------------------
Earnings for Common Stock $241,804 $213,155
- -------------------------------------------------------------------------------
Basic Earnings per Share
Income before cumulative effect
of a change in accounting principle $ 1.54 $ 1.52
Change in accounting principle - -
- -------------------------------------------------------------------------------
$ 1.54 $ 1.52
- -------------------------------------------------------------------------------
As indicated in the above table, operating income increased by $49.1 million, or
12%, for the quarter ended March 31, 2003, compared to the corresponding period
last year. The increase in operating income reflects higher earnings from the
Energy Investments and Gas Distribution segments, somewhat offset by a decrease
in earnings from the Electric Services segment. The Energy Investment segment
benefited from higher earnings associated with gas exploration and production
activities as a result of significantly higher realized gas prices. The Gas
31
Distribution segment benefited from significantly colder weather during the
first quarter of 2003 compared to the first quarter of 2002, as well as from
load growth. Lower results from the Electric Services segment are attributable
to higher operating costs as a result of increases in plant maintenance expenses
and pension and other postretirement costs, as well as lower capacity revenues
from our merchant generating facility. (See the discussion under the caption
"Review of Operating Segments" for further details on each segment.)
Included in Other Income and Deductions are interest charges of $68.9 million
and $72.6 million for the three months ended March 31, 2003 and 2002,
respectively. The decrease in interest expense of $3.7 million, or 5%, reflects
the benefits associated with interest rate swaps. In February 2003, we
terminated an interest rate swap agreement with a notional amount of $270
million. This swap was used to hedge a portion of outstanding promissory notes
that were issued to the Long Island Power Authority ("LIPA") in connection with
the KeySpan/Long Island Lighting Company ("LILCO") business combination
completed in May 1998. In March 2003, we called approximately $447 million of
the outstanding promissory notes and recorded debt redemption charges of $18.2
million in Other Income and Deductions. The cash proceeds from the termination
of the interest rate hedge were $18.4 million, of which $8.1 million represented
accrued swap interest. The difference between the termination settlement amount
and the amount of accrued interest, $10.3 million, was recorded to earnings (as
an adjustment to interest expense) in the first quarter of 2003 and effectively
offset a portion of the redemption charges.
In November 2002, we terminated two interest rate swap agreements. The
difference between the termination settlement amount and the amount of accrued
swap interest, $57.4 million, is currently being amortized to earnings (as an
adjustment to interest expense) on a level yield basis over the remaining lives
of the originally hedged debt obligations. The combination of the termination of
the interest rate swap agreement in February 2003 ($10.3 million), plus the
amortization of last year's terminated swap agreement reduced interest expense
by $13.9 million for the three months ended March 31, 2003. The use of interest
rate swaps reduced interest expense by $10.9 million during the three months
ended March 31, 2002. (See Note 6 to the Consolidated Financial Statements
"Hedging and Derivative Financial Instruments" for a description of these
instruments.)
Also included in Other Income and Deductions is a gain of $19.0 million
reflecting the monetization of a portion of our ownership interest in The
Houston Exploration Company ("Houston Exploration"), a gas exploration and
production subsidiary. On February 26, 2003, we reduced our ownership interest
in Houston Exploration from 66% to approximately 56% following the repurchase,
by Houston Exploration, of three million shares of common stock owned by
KeySpan. Income taxes were not provided on this transaction, since the
transaction was structured as a return of capital. Further, in July 2002,
Houston Exploration received an abatement of severance taxes for certain
qualifying wells. As a result of this abatement, during the first quarter of
2003 Houston Exploration recorded a $10.6 million severance tax refund for
severance taxes paid in 2002 and earlier periods, which has also been reflected
in Other Income and Deductions. Offsetting, to some extent, these benefits to
Other Income and Deductions is the adjustment for minority interest.
32
The remaining major components reflected in Other Income and Deductions are
equity earnings associated with our ownership interest in the Iroquois Gas
Transmission System LP and subsidiaries located in Northern Ireland, which have
remained consistent with the prior year, as well as carrying charges on certain
regulatory assets.
The increase in income tax expense generally reflects the higher level of
pre-tax income for the first quarter of 2003, compared to the corresponding
period last year. Further, 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/LILCO business
combination. This adjustment was a result of a revised valuation study and the
filing of an amended tax return. Concurrent with the deferred tax adjustment, we
reduced current income taxes payable by $183.2 million, resulting in a $5.5
million income tax benefit.
Earnings available for common stock for the three months ended March 31, 2003
increased by $28.6 million, or $0.02 per share, compared to the same period last
year. Average common shares outstanding for the quarter ended March 31, 2003
increased by 12%, primarily reflecting the issuance of 13.9 million shares of
common stock on January 17, 2003, as well as the re-issuance of shares held in
treasury pursuant to dividend reinvestment and employee benefit plans. This
increase in average common shares outstanding reduced first quarter 2003
earnings per share by $0.19 compared to the corresponding period in 2002. To
reduce the dilutive effect of the equity offering we redeemed a portion of
outstanding promissory notes that were issued to LIPA, as previously mentioned.
Interest savings associated with this redemption are estimated to be $15.6
million after-tax, or $0.09 per share, in 2003.
Consolidated earnings are seasonal in nature due to the significant contribution
to earnings of the gas distribution operations. As a result, we expect to earn
most of our annual earnings in the first and fourth quarters of our fiscal year,
and breakeven or marginally profitable earnings are anticipated to be achieved
in the second and third quarters of our fiscal year.
Review of Operating Segments
- ----------------------------
In response to new disclosure regulations adopted by the Securities and Exchange
Commission as part of its implementation of the Sarbanes-Oxley Act of 2002 -
specifically Regulation G which became effective March 2003 - we will be
reporting all of KeySpan's segment results on an Operating Income basis for 2003
and 2002. Management believes that this Generally Accepted Accounting Principle
(GAAP) based measure provides a true indication of KeySpan's underlying
performance associated with its operations. The following is a discussion of
financial results achieved by KeySpan's operating segments presented on an
Operating Income basis.
33
Gas Distribution
KeySpan Energy Delivery New York ("KEDNY") provides gas distribution service to
customers in the New York City Boroughs of Brooklyn, Staten Island and a portion
of Queens, and KeySpan Energy Delivery Long Island ("KEDLI") provides gas
distribution service to customers in the Long Island counties of Nassau and
Suffolk and the Rockaway Peninsula of Queens County. Four gas distribution
companies - Boston Gas Company, Colonial Gas Company, Essex Gas Company, and
EnergyNorth Natural Gas Inc., each doing business under the name KeySpan Energy
Delivery New England ("KEDNE"), provide gas distribution service to customers in
Massachusetts and New Hampshire.
The table below highlights certain significant financial data and operating
statistics for the Gas Distribution segment for the periods indicated. Net
revenues for 2002 have been restated to reflect a reclassification of gross
receipt taxes from revenue taxes to state income taxes, which is not an
operating income measure.
- -----------------------------------------------------------------------------------------------------------
Three Months Ended March 31,
(In Thousands of Dollars) 2003 2002
- -----------------------------------------------------------------------------------------------------------
Revenues $ 1,832,701 $ 1,222,966
Cost of gas 1,154,132 613,584
Revenue taxes 38,616 32,556
- -----------------------------------------------------------------------------------------------------------
Net Revenues 639,953 576,826
- -----------------------------------------------------------------------------------------------------------
Operating Expenses
Operations and maintenance 166,090 145,539
Depreciation and amortization 70,817 63,018
Operating taxes 38,109 37,250
- -----------------------------------------------------------------------------------------------------------
Total Operating Expenses 275,016 245,807
- -----------------------------------------------------------------------------------------------------------
Operating Income 364,937 331,019
- -----------------------------------------------------------------------------------------------------------
Firm gas sales and transportation (MDTH) 155,666 116,518
Transportation - Electric
Generation (MDTH) 5,003 13,359
Other Sales (MDTH) 53,670 62,912
Warmer (Colder) than Normal - New York (8.5)% 18.0%
Warmer (Colder) than Normal - New England (10.0)% 16.0%
- -----------------------------------------------------------------------------------------------------------
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.
34
Net Revenues
Net gas revenues (revenues less the cost of gas and associated revenue taxes)
from our gas distribution operations increased by $63.1 million, or 11%, in the
first quarter of 2003 compared to same quarter last year. Both our New York and
New England based gas distribution operations benefited from the significantly
colder than normal weather experienced throughout the Northeastern United
States. Based on heating degree days, weather for the first quarter of 2003 was
approximately 8.5%-10% colder than normal and approximately 35% colder than last
year in our New York and New England service territories.
Net revenues from firm gas customers (residential, commercial and industrial
customers) in our New York service territory increased by $29.1 million for the
first quarter of 2003 compared to the same period last year. The combination of
conversions of oil heating customers to natural gas, as well as higher customer
consumption due to the colder than normal weather added $38.9 million to net
revenues during the first quarter of 2003. However, KEDNY and KEDLI each operate
under a utility tariff that contains a weather normalization adjustment that
significantly offsets variations in firm net revenues due to fluctuations in
normal weather. These weather normalization adjustments resulted in a $19.2
million refund to firm gas customers during the first quarter of 2003. Further,
included in net revenues is the recovery of certain taxes that added $9.4
million to net revenues during the first quarter of 2003. These revenues,
however, do not impact net income since the taxes they are designed to recover
are expensed as amortization charges and income taxes, as appropriate, on the
Consolidated Statement of Income.
Net revenues from firm gas customers in our New England service territory
increased by $19.9 million for the first quarter of 2003 compared to the same
period last year. The combination of conversions to natural gas as well as
higher customer consumption due to the colder than normal weather added $35.7
million to net revenues during the first quarter of 2003. The gas distribution
operations of our New England based subsidiaries do not have a weather
normalization adjustment. To mitigate the effect of fluctuations in normal
weather patterns on KEDNE's results of operations and cash flows, weather
derivatives were in place for the 2002/2003 winter heating season. Since weather
during the first quarter of 2003 was 10% colder than normal in the New England
service territory, we recorded an $11.9 million reduction to revenues to reflect
the loss on these derivative transactions. (See Note 6 to the Consolidated
Financial Statements "Hedging and Derivative Financial Instruments" for further
information). Further, included in net revenues for the first quarter of 2002,
was a benefit of $3.9 million as a result of a favorable ruling from the
Massachusetts Supreme Judicial Court relating to the appeal by Boston Gas
Company of its Performance Based Rate Plan ("PBR").
Firm gas distribution rates in the first quarter of 2003, other than for the
recovery of gas costs, have remained substantially unchanged from rates charged
last year in all of our service territories.
In our large-volume heating and other interruptible (non-firm) markets, which
include large apartment houses, government buildings and schools, gas service is
provided under rates that are designed to compete with prices of alternative
fuel, including No. 2 and No. 6 grade heating oil. Net revenues from sales to
these markets increased by $14.1 million during the first quarter of 2003
compared to same period last year as a result of aggressive pricing. The
majority of interruptible profits earned by KEDNE and KEDLI are returned to firm
customers as an offset to gas costs.
35
We are committed to our expansion strategies initiated during the past few
years. We believe that significant growth opportunities exist on Long Island and
in our New England service territories. We estimate that on Long Island
approximately 35% of the residential and multi-family markets, and approximately
55% of the commercial market, currently use natural gas for space heating.
Further, we estimate that in our New England service territories approximately
50% of the residential and multi-family markets, and approximately 45% of the
commercial market, currently use natural gas for space heating purposes. We will
continue to seek growth, in all our market segments, through the expansion of
our gas distribution system, as well as through the conversion of residential
homes from oil-to-gas for space heating purposes and the pursuit of
opportunities to grow multi-family, industrial and commercial markets.
Firm Sales, Transportation and Other Quantities
Firm gas sales and transportation quantities increased by 34% during the three
months ended March 31, 2003, compared to the same period in 2002, due to higher
customer consumption as a result of the significantly colder weather, as well as
from conversions to natural gas. Net revenues are not affected by customers
opting to purchase their gas supply from other sources, since delivery rates
charged to transportation customers generally are the same as delivery rates
charged to 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. During the first quarter of 2003, we had an
agreement with Coral Resources, L.P. ("Coral"), a subsidiary of Shell Oil
Company, under which Coral assisted in the origination, structuring, valuation
and execution of energy-related transactions on behalf of KEDNY and KEDLI. We
also had a portfolio management contract with Entergy-Koch, under which
Entergy-Koch provided all of the city gate supply requirements at market prices
and managed certain upstream capacity, underground storage and term supply
contracts for KEDNE. Our agreements with Coral and Entergy-Koch expired on March
31, 2003 and were renewed through March 31, 2006.
Purchased Gas for Resale
The increase in gas costs for the first quarter of 2003 compared to the first
quarter of 2002 of $540.6 million, or 88%, reflects an increase of 40% in the
price per dekatherm of gas purchased, and a 34% increase in the quantity of gas
purchased. Fluctuations in utility gas costs associated with firm gas customers
have no impact on operating results. The current gas rate structure of each of
our gas distribution utilities includes a gas adjustment clause, pursuant to
which variations between actual gas costs incurred and gas costs billed are
deferred and refunded to or collected from customers in a subsequent period.
36
Operating Expenses
Operating expenses during the first quarter of 2003 compared to the same quarter
last year have increased by $29.2 million, or 12%. The increase in operating
expense in 2003 is attributable, in part, to higher pension and other
postretirement benefits which increased by $9.2 million, net of amounts deferred
and subject to regulatory true-ups, over the level incurred in 2002. The cost of
these benefits has risen primarily as a result of lower actual returns on plan
assets, as well as increased health care costs. Further, the colder weather
experienced in the first quarter of 2003 resulted in increased repair and
maintenance work on our gas distribution infrastructure that increased operating
expenses by approximately $6 million. Also, the bad debt reserve has increased
primarily as a result of higher account receivables due to the cold weather and
higher cost of gas purchased. Depreciation and amortization expense has
increased as a result of the continued expansion of the gas distribution system.
Further, included in depreciation and amortization expense is the amortization
of certain property taxes previously deferred and currently being recovered
through revenues.
Other Matters
To take advantage of the anticipated gas sales growth opportunities in our New
York service territory, in 2000 we formed the Islander East Pipeline, LLC
("Islander East"), a limited liability company in which a KeySpan subsidiary and
a subsidiary of Duke Energy Corporation each own a 50% equity interest. Islander
East has obtained all required permits in New York State for the construction of
the facility. However, the State of Connecticut has issued a moratorium on the
issuance of permits relating to the construction of energy projects until June
2003. Islander East has therefore been unable to obtain the necessary permits
from the State of Connecticut at this time. Islander East has also appealed a
denial by the State of Connecticut of the coastal zone management permit to the
U.S. Department of Commerce and such appeal is currently pending. Assuming the
receipt of approvals from the State of Connecticut by September 2003, the
Islander East pipeline is expected to begin operating by year-end 2004. The
pipeline will transport 260,000 DTH daily to the Long Island and New York City
energy markets, enough fuel to heat 600,000 homes, as well as allow us to
further diversify the geographic sources of our gas supply. Various options for
the financing of this pipeline are currently being evaluated.
Electric Services
The Electric Services segment primarily consists of subsidiaries that own and
operate oil and gas fired electric generating plants in the Borough of Queens
(the "Ravenswood facility") and the counties of Nassau and Suffolk on Long
Island. In addition, through long-term contracts of varying lengths, we manage
the electric transmission and distribution ("T&D") system, the fuel and electric
purchases, and the off-system electric sales for LIPA.
37
Selected financial data for the Electric Services segment is set forth in the
table below for the periods indicated.
- -------------------------------------------------------------------------------
Three Months Ended March 31,
(In Thousands of Dollars) 2003 2002
- -------------------------------------------------------------------------------
Revenues $ 334,419 $ 314,710
Purchased fuel 79,268 53,993
- -------------------------------------------------------------------------------
Net Revenues 255,151 260,717
- -------------------------------------------------------------------------------
Operating Expenses
Operations and maintenance 161,304 148,119
Depreciation 16,538 13,733
Operating taxes 37,639 37,371
- -------------------------------------------------------------------------------
Total Operating Expenses 215,481 199,223
- -------------------------------------------------------------------------------
Operating Income 39,670 61,494
- -------------------------------------------------------------------------------
Electric sales (MWH)* 767,349 1,091,243
Capacity(MW)* 2,200 2,200
Cooling degree days N/A N/A
- -------------------------------------------------------------------------------
*Reflects the operations of the Ravenswood facility only.
Net Revenues
Total electric net revenues decreased by $5.6 million, or 2%, in the first
quarter of 2003, compared to the same quarter of 2002. Lower comparative net
revenues from the Ravenswood facility of $12.9 million were offset, in part, by
net revenues from the Glenwood Landing and Port Jefferson electric "peaking"
facilities located on Long Island. The Glenwood facility was placed in service
on June 1, 2002, while the Port Jefferson facility was placed in service on July
1, 2002. Net revenues from these facilities were $7.9 million during the three
months ended March 31, 2003. Net revenues from the LIPA service agreements were
consistent with last year.
As mentioned, net revenues from the Ravenswood facility were $12.9 million, or
18% lower during the first quarter of 2003, compared to the same period in 2002
reflecting, primarily, a decrease in capacity sales of $11.8 million, or 20%.
Lower capacity revenues reflect more competitive pricing by the electric
generators that bid into the New York Independent System Operator ("NYISO")
energy market which lowered capacity clearing prices by approximately 26%
compared to last year. Net revenues from energy sales remained relatively flat
compared to last year. Due to a major overhaul of our largest steam generator,
energy sales quantities were lower during the first quarter of 2003 compared to
the same period last year. However, the impact of lower sales quantities were
offset by significantly higher "spark-spreads" (the selling price of electricity
less cost of fuel).
38
The rules and regulations for capacity, energy sales and the sale of certain
ancillary services to the NYISO energy markets continue to evolve and the
Federal Energy Regulatory Commission ("FERC") has adopted several price
mitigation measures that have adversely impacted earnings from the Ravenswood
facility. Certain of these mitigation measures are still subject to rehearing
and possible judicial review. The final resolution of these issues and their
effect on our financial position, results of operations and cash flows cannot be
fully determined at this time. (See KeySpan's 2002 Annual Report on Form 10K for
the Year Ended December 31, 2002 Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations under the caption "Market and
Credit Risk Management Activities" for a further discussion of these matters.)
Operating Expenses
Operating expenses increased by $16.3 million, or 8%, in the first quarter of
2003 compared to the same quarter of 2002, primarily as a result of higher
comparative pension and other postretirement benefits. LIPA reimburses KeySpan
for costs directly incurred by KeySpan in providing service to LIPA, subject to
certain sharing provisions. These reimbursements are based on predetermined
estimates of operating costs. Variations between certain actual operating costs
incurred (i.e. postretirement costs and property taxes) and the predetermined
estimates are deferred and refunded to or collected from LIPA in subsequent
periods. As a result of an adjustment recorded in 2002 relating to this
"true-up", comparative pension and other postretirement costs were approximately
$11 million higher in this quarter compared to this time last year. Further,
plant maintenance costs were $5.3 million higher during the first quarter of
2003 compared to the first quarter of 2002, due to the major overhaul of our
largest steam generator as previously mentioned.
Other Matters
During 2002, construction began on a new 250 MW combined cycle generating
facility at the Ravenswood facility site. The new facility is expected to
commence operations in late 2003. The capacity and energy produced from this
plant are anticipated to be sold into the NYISO energy markets. We are also
progressing through the siting process before the New York State Board on
Electric Generation Siting and the Environment with a proposal to build a
similar 250 MW combined cycle electric generating facility on Long Island. On
February 4, 2003, an Examiners' Recommended Decision was issued recommending the
granting of a certificate of environmental capability and public need for this
proposed facility. In addition, as part of our growth strategy, we continually
evaluate the possible acquisition of additional generating facilities in the
Northeast. However, we are unable to predict when or if any such facilities will
be acquired and the effect any such acquired facilities will have on our
financial condition, results of operations or cash flows.
39
Energy Services
The Energy Services segment primarily includes companies that provide services
through three lines of business to clients primarily located within the New York
City metropolitan area, including New Jersey and Connecticut, as well as in
Rhode Island, Pennsylvania, Massachusetts and New Hampshire. The lines of
business are Home Energy Services, Business Solutions, and Fiber Optic Services.
The table below highlights selected financial information for the Energy
Services segment.
- --------------------------------------------------------------------------------
Three Months Ended March 31,
(In Thousands of Dollars) 2003 2002
- --------------------------------------------------------------------------------
Revenues $ 193,797 $ 241,559
Less: cost of gas and fuel 60,153 66,155
- --------------------------------------------------------------------------------
Net Revenues 133,644 175,404
Other operating expenses 142,792 184,762
- --------------------------------------------------------------------------------
Operating Income (9,148) (9,358)
- --------------------------------------------------------------------------------
Net revenues decreased by 24% during the first quarter of 2003 compared to the
same period last year, primarily as a result of the discontinuation of the
general contracting business of one of our subsidiaries. Excluding those
operations, net revenues decreased by 7% during the first quarter of 2003
compared to the same quarter last year, due to lower margins realized on large
construction projects as result of the continued down turn in the economy.
Operating Income for the Business Solutions group of companies, which provide
mechanical contracting, plumbing, engineering and consulting services to
commercial, institutional, and industrial customers, decreased by $2.0 million
for the first quarter of 2003 compared to the corresponding quarter of last
year. This decrease reflects the slow down in the economy, which has delayed the
start-up of certain engineering and construction projects. Further, as
mentioned, the continued down turn in the economy has lowered margins realized
on construction projects currently in progress. This is further reflected by a
backlog of approximately $479 million at March 31, 2003, compared to $ 514 at
December 31, 2002 and $647 million at March 31, 2002.
Offsetting the results of the Business Solutions group of companies, was an
increase in operating income of $2.2 million associated with the Home Energy
Services group of companies. These companies provide residential and small
commercial customers with service and maintenance contracts, as well as the
retail marketing of natural gas and electricity. In the first quarter of 2002,
these companies recorded an additional reserve for bad debts of approximately $5
million.
40
Energy Investments
The Energy Investment segment consists of our gas exploration and production
operations, certain other domestic and international energy-related investments,
as well as certain technology related investments. Our gas exploration and
production subsidiaries, Houston Exploration and KeySpan Exploration and
Production LLC ("KES E&P") are engaged in gas and oil exploration and
production, and the development and acquisition of domestic natural gas and oil
properties. In line with our strategy of monetizing or divesting certain
non-core assets, in October 2002 we monetized a portion of our assets in the
joint venture drilling program with Houston Exploration that was initiated in
1999. Further, in February 2003, we reduced our ownership interest in Houston
Exploration to approximately 56% (from the previous level of 66%) through the
repurchase, by Houston Exploration, of three million shares of common stock
owned by KeySpan. The net proceeds of approximately $79 million received in
connection with this repurchase were used to pay down short-term debt. We
realized a $19.0 million gain on this transaction that was recorded in Other
Income and Deductions in the Consolidated Statement of Income. Income taxes were
not provided on this transaction, since the transaction was structured as a
return of capital.
Selected financial data and operating statistics for our gas exploration and
production activities are set forth in the following table for the periods
indicated.
- ------------------------------------------------------------------------------------------------
Three Months Ended March 31,
(In Thousands of Dollars) 2003 2002
- ------------------------------------------------------------------------------------------------
Revenues $ 127,847 $ 76,926
Depletion and amortization expense 47,443 41,446
Other operating expenses 24,814 15,655
- ------------------------------------------------------------------------------------------------
Operating Income 55,590 19,825
- ------------------------------------------------------------------------------------------------
Natural gas and oil production (Mmcf) 26,086 25,670
Natural gas (per Mcf) realized $ 4.91 $ 2.98
Natural gas (per Mcf) unhedged $ 6.35 $ 2.29
- ------------------------------------------------------------------------------------------------
*Operating income above represents 100% of our gas exploration and production
subsidiaries' results for the periods indicated. Gas reserves and production are
stated in BCFe and Mmcfe, which includes equivalent oil reserves.
The increase in operating income of $35.8 million for the three months ended
March 31, 2003, compared to the corresponding period last year, reflects, in
part, a significant increase in revenues offset, to some extent, by an increase
in operating expenses associated with higher production volumes. Revenues for
the first quarter of 2003, compared to the first quarter of 2002, benefited by
the significant increase in comparative average realized gas prices (average
wellhead price received for production including hedging gains and losses).
Average realized gas prices increased 65% for the first quarter of 2003,
compared with the corresponding period last year (from $2.98 per Mcf in 2002 to
$4.91 per Mcf in 2003). Revenues also benefited from an increase of 2% in
production volumes.
41
The average realized gas price for 2003 was 77% of the average unhedged natural
gas price, resulting in revenues that were $34.7 million lower than revenues
that would have been achieved if derivative financial instruments had not been
in place during the first quarter of 2003. Houston Exploration hedged almost 70%
of its 2003 first quarter production, principally through the use of costless
collars. The average realized gas price for the first quarter of 2002 was 130%
of the average unhedged natural gas price, resulting in revenues that were $17.0
million higher than revenues that would have been achieved if derivative
financial instruments had not been employed during the first quarter of 2002.
These derivative instruments are designed to provide Houston Exploration with a
more predictable cash flow, as well as to reduce its exposure to fluctuations in
natural gas prices. At March 31, 2003 Houston Exploration had derivative
positions in place to hedge approximately 67% of its estimated 2003 production
and approximately 38% of its estimated 2004 production, again principally
through the use of costless collars. Depending upon market conditions, Houston
Exploration may enter into additional derivative positions during 2003 to hedge
a larger portion of its estimated 2004 production. (See Note 6 to the
Consolidated Financial Statements, "Hedging and Derivative Financial
Instruments" for further information on these derivative positions.)
The depletion rate was $1.77 per Mcf for the three months ended March 31, 2003,
compared to $1.63 per Mcf for the same period in 2002. The depletion rate has
increased as Houston Exploration completed the evaluation of several properties
that were classified as unproved during the fourth quarter of 2002. As the
evaluation is completed, the costs associated with these properties were
reclassified into the amortization base without incremental reserve additions.
In addition, future development costs have increased from prior year estimates.
The table below indicates the net proved reserves of our gas exploration and
production subsidiaries at December 31, 2002.
BCFe %
- -------------------------------------------------------------------
Houston Exploration 650 96.7%
KSE E&P 22 3.3%
- -------------------------------------------------------------------
Total 672 100.0%
- -------------------------------------------------------------------
This segment also consists of KeySpan Canada; our 20% interest in Iroquois Gas
Transmission System LP ("Iroquois"); and our 50% interest in the Premier
Transmission Pipeline and 24.5% interest in Phoenix Natural Gas, both located in
Northern Ireland.
Selected financial data and operating statistics for our other energy-related
investments are set forth in the following table for the periods indicated.
- --------------------------------------------------------------------------------
Three Months Ended March 31,
(In Thousands of Dollars) 2003 2002
- --------------------------------------------------------------------------------
Revenues $ 26,464 $ 17,636
Operation and maintenance expense 16,644 14,056
Other operating expenses 5,353 3,029
- --------------------------------------------------------------------------------
Operating Income 4,467 551
- --------------------------------------------------------------------------------
42
The increase in operating income for the first quarter of 2003 compared to the
same quarter last year primarily reflects lower comparative losses associated
with certain technology-related investments, as well as slightly higher
operating income associated with our Canadian investments. The earnings
associated with Iroquois and our Northern Ireland investments are recorded on
the equity method and appropriately recorded in Other Income and Deductions, and
are therefore not reflected in the above table.
We do not consider certain businesses contained in the Energy Investments
segment to be part of our core asset group. We have stated in the past that we
may sell or otherwise dispose of all or a portion of our non-core assets. In
furtherance of this objective, we recently sold our approximate 20% ownership
interest in Taylor NGL Limited Partnership, which owns and operates two
extraction plants, one located in British Columbia, and one in Alberta, Canada,
to AltaGas Services, Inc. We are also in the process of monetizing a portion of
our interests in KeySpan Canada through the establishment of an open-ended
income fund trust (the "Fund") organized under the laws of Alberta, Canada. The
Fund would initially acquire an approximate 33% of the ownership interests of
KeySpan Canada through an indirect subsidiary, and would issue trust units to
the public through an initial public offering. Each trust unit will represent a
beneficial interest in the Fund and will be registered on the Toronto Stock
Exchange. Based on current market conditions, however, we cannot predict when,
or if, the KeySpan Canada transaction, or any such other sales or dispositions
of our non-core assets may take place, or the effect that any such sale or
disposition may have on our financial position, results of operations or cash
flows.
Allocated Costs
We are subject to the jurisdiction of the SEC under the Public Utility Holding
Company Act ("PUHCA") as amended. As part of the regulatory provisions of PUHCA,
the SEC regulates various transactions among affiliates within a holding company
system. In accordance with the SEC's regulations under PUHCA and the New York
State Public Service Commission, we have service companies that provide: (i)
traditional corporate and administrative services; (ii) gas and electric
transmission and distribution systems planning, marketing, and gas supply
planning and procurement; and (iii) engineering and surveying services to
subsidiaries. During the first quarter of 2003, these non-operating subsidiaries
incurred general corporate expenses primarily related to consulting, auditing
and legal costs associated with the implementation of the Sarbanes-Oxley Act
that were not allocated to the various operating subsidiaries.
Liquidity
Cash flow from operations increased by $157.3 million during the first quarter
of 2003 compared to the same quarter last year. This increase reflects, in part,
significantly higher gas prices, which benefited our gas exploration and
production operations. Further, outstanding receivables at December 2002
associated with gas distribution operations were significantly higher than the
prior year and, therefore, resulted in higher collections during the first
quarter of 2003. In addition, cash earnings were higher in the first quarter of
2003 compared to the same period last year, due in part, to the termination of
an interest rate swap, as well as the gain from the monetization of a portion of
our investment in Houston Exploration.
43
A substantial portion of consolidated revenues are derived from the operations
of businesses within the Electric Services segment, that are largely dependent
upon two large customers - LIPA and the NYISO. Accordingly, our cash flows are
dependent upon the timely payment of amounts owed to us by these customers.
At March 31, 2003, we had cash and temporary cash investments of $244.1 million.
During the three months ended March 31, 2003, we repaid $238.4 million of
commercial paper and, at March 31, 2003, $677.3 million of commercial paper was
outstanding at a weighted average annualized interest rate of 1.37%. We had the
ability to borrow up to an additional $622.7 million at March 31, 2003, under
the terms of our credit facility.
KeySpan has an existing 364-day revolving credit agreement with a commercial
bank syndicate of 16 banks totaling $1.3 billion. The credit facility is used to
back up the $1.3 billion commercial paper program. The fees for the facility are
subject to a ratings-based grid, with an annual fee of .075% on the total amount
of the revolving facility. The credit agreement allows for KeySpan to borrow
using several different types of loans; specifically, Eurodollar loans,
Adjustable Bank Rate ("ABR") loans, or competitively bid loans. Eurodollar loans
are based on the Eurodollar rate plus a margin of 42.5 basis points for loans up
to 33% of the facility, and an additional 12.5 basis points for loans over 33%
of the total facility. ABR loans are based on the greater of the Prime Rate, the
base CD rate plus 1%, or the Federal Funds Effective Rate plus 0.5%. Competitive
bid loans are based on bid results requested by KeySpan from the lenders. We do
not anticipate borrowing against this facility; however, if the credit rating on
our commercial paper program were to be downgraded, it may be necessary to do
so.
The credit facility contains certain affirmative and negative operating
covenants, including restrictions on KeySpan's ability to mortgage, pledge,
encumber or otherwise subject its property to any lien, as well as certain
financial covenants that require us to, among other things, maintain a
consolidated indebtedness to consolidated capitalization ratio of no more than
66%.
Under the terms of the credit facility, KeySpan's debt-to-total capitalization
ratio reflects 80% equity treatment for the MEDS Equity Units issued in May
2002. In addition, the $425 million Ravenswood Master Lease is treated as debt.
At March 31, 2003, consolidated indebtedness, as calculated under the terms of
the credit facility, was 57.4% of consolidated capitalization. Violation of this
covenant could result in the termination of the credit facility and the required
repayment of amounts borrowed thereunder, as well as possible cross defaults
under other debt agreements. (See discussion under "Off-Balance Sheet
Arrangements" for an explanation of the Ravenswood Master Lease.)
The credit facility also requires that net cash proceeds from the sale of
significant subsidiaries be applied to reduce consolidated indebtedness.
Further, an acceleration of indebtedness of KeySpan or one of its subsidiaries
for borrowed money in excess of $25 million in the aggregate, if not annulled
within 30 days after written notice, would create an event of default under the
Indenture dated November 1, 2000, between KeySpan Corporation and the
JPMorganChase Bank as Trustee. At March 31, 2003, KeySpan was in compliance with
all covenants.
44
Houston Exploration has a revolving credit facility with a commercial banking
syndicate that provides Houston Exploration with a commitment of $300 million,
which can be increased at its option to a maximum of $350 million with prior
approval from the banking syndicate. The credit facility is subject to borrowing
base limitations, initially set at $300 million and will be re-determined
semi-annually. Up to $25 million of the borrowing base is available for the
issuance of letters of credit. The credit facility matures on July 15, 2005, is
unsecured and ranks senior to all existing debt of Houston Exploration.
Under the Houston Exploration credit facility, interest on base rate loans is
payable at a fluctuating rate, or base rate, equal to the sum of (a) the greater
of the federal funds rate plus 0.50% or the bank's prime rate plus (b) a
variable margin between 0% and 0.50%, depending on the amount of borrowings
outstanding under the credit facility. Interest on fixed rate loans is payable
at a fixed rate equal to the sum of (a) a quoted reserve adjusted LIBOR rate,
plus (b) a variable margin between 1.25% and 2.00%, depending on the amount of
borrowings outstanding under the credit facility.
Financial covenants require Houston Exploration to, among other things, (i)
maintain an interest coverage ratio of at least 3.00 to 1.00 of earnings before
interest, taxes and depreciation ("EBITDA") to cash interest; (ii) maintain a
total debt to EBITDA ratio of not more than 3.50 to 1.00; and (iii) hedge no
more than 70% of natural gas production during any 12-month period. At March 31,
2003, Houston Exploration was in compliance with all financial covenants.
During the first quarter of 2003, Houston Exploration borrowed $18 million under
its credit facility and repaid $40 million. At March 31, 2003, $130 million of
borrowings remained outstanding at a weighted average annualized interest rate
of 3.31%. Also, $15.5 million was committed under outstanding letters of credit
obligations. At March 31, 2003, $154.5 million of borrowing capacity was
available.
KeySpan Canada has two revolving credit facilities with financial institutions
in Canada. Repayments under these agreements totaled approximately US $10.5
million during the first quarter of 2003. At March 31, 2003, approximately US
$148.7 million was outstanding at a weighted average annualized interest rate of
3.65%. KeySpan Canada currently has available borrowings of approximately US
$38.4 million. These revolving credit agreements have been extended through
January 2004. KeySpan is a guarantor under one of these credit facilities and an
event of default would exist thereunder if KeySpan, as guarantor, falls below
investment grade rating or its ratings fall below A3 (by Moody's Investor
Services) or A- (by Standard & Poor's) at a time when its consolidated
indebtedness, as measured using the same criteria employed under KeySpan's
credit facility, is greater than 66% of consolidated capitalization or its cash
flow to interest expense is less than 2.25 to 1.00. At March 31, 2003, KeySpan
and KeySpan Canada were in compliance with all covenants.
45
On January 17, 2003, KeySpan sold 13.9 million shares of common stock to the
open market and realized net proceeds of approximately $473 million. All shares
were offered by KeySpan pursuant to the effective shelf registration statement
filed with the Securities and Exchange Commission. Net proceeds from the equity
sale were used initially to pay down commercial paper. In addition, as
previously noted, we used the net proceeds of approximately $79 million received
in February 2003 in connection with the partial monetization of Houston
Exploration to repay short-term debt.
We satisfy our seasonal working capital requirements primarily through
internally generated funds and the issuance of commercial paper. We believe that
these sources of funds are sufficient to meet our seasonal working capital
needs. In addition, we currently use treasury stock to satisfy the requirements
of our dividend reinvestment and employee benefit plans.
Capital Expenditures and Financing
Construction Expenditures
The table below sets forth our construction expenditures by operating segment
for the periods indicated:
- ------------------------------------------------------------------------------
Three Months Ended March 31,
(In Thousands of Dollars) 2003 2002
- ------------------------------------------------------------------------------
Gas Distribution $ 78,013 $ 84,366
Electric Services 56,731 88,544
Energy Investments 84,309 67,697
Energy Services 1,726 3,546
- ------------------------------------------------------------------------------
$ 220,779 $ 244,153
- ------------------------------------------------------------------------------
Construction expenditures related to the Gas Distribution segment are primarily
for the renewal and replacement of mains and services and for the expansion of
the gas distribution system. Construction expenditures for the Electric Services
segment reflect costs to: (i) maintain our generating facilities; (ii) expand
the Ravenswood facility; and (iii) construct new Long Island generating
facilities as previously noted. Construction expenditures related to the Energy
Investments segment primarily reflect costs associated with gas exploration and
production activities. These costs are related to the exploration and
development of properties primarily in Southern Louisiana and in the Gulf of
Mexico. Expenditures also include development costs associated with the joint
venture with Houston Exploration, as well as costs related to KeySpan Canada's
gas processing facilities.
At March 31, 2003, total expenditures associated with the siting, permitting and
construction of the Ravenswood expansion project, the siting, permitting and
procurement of equipment for the Long Island 250MW combined cycle generation
plant, and the siting and permitting of the Islander East pipeline project were
$270.4 million.
46
Financing
In connection with the KeySpan/LILCO business combination, KeySpan and certain
of its subsidiaries issued promissory notes to LIPA to support certain debt
obligations assumed by LIPA. At December 31, 2002 the remaining principal amount
of promissory notes issued to LIPA was approximately $600 million. Under these
promissory notes, KeySpan is required to obtain letters of credit to secure its
payment obligations if its long-term debt is not rated at least in the "A" range
by at least two nationally recognized statistical rating agencies. In an effort
to mitigate the dilutive effect of the equity issuance previously mentioned, in
March 2003, we called approximately $447 million aggregate principal amount of
such promissory notes at the applicable redemption prices plus accrued and
unpaid interest through the dates of redemption. Interest savings associated
with this redemption are estimated to be $15.6 million after-tax, or $0.09 per
share, in 2003.
In April 2003, we issued $300 million of medium-term and long-term debt. The
debt was issued in the following two series: (i) $150 million 4.65% Notes due
2013; and (ii) $150 million 5.875% Notes due 2033. The proceeds of this issuance
were used to pay down outstanding commercial paper.
KeySpan has the ability under the Public Utility Holding Company Act ("PUHCA")
to issue up to $2.2 billion of securities through December 31, 2003. Following
the recent common stock offering previously mentioned and after accounting for
the shares of common stock expected to be issued for employee benefit and
dividend reinvestment plans, we have approximately $25 million available for the
issuance of new securities under our current PUHCA authorization. However, the
issuance of securities in connection with the redemption of existing securities
(including the promissory notes discussed previously) is permitted under our
PUHCA authorization notwithstanding the foregoing limit. We intend to seek
authorization from the SEC in the near term to enable us to, among other things,
issue additional securities in an aggregate amount not yet determined. It is
anticipated that this authorization will be obtained before the end of the year.
During 2003, we intend to issue approximately $150 million of either taxable or
tax-exempt long-term debt securities in a manner that will be exempt from PUCHA
restrictions. We anticipate that the proceeds from the issuance will be used to
re-pay the outstanding commercial paper related to the construction of the two
Long Island peaking-power plants. We will continue to evaluate our capital
structure and financing strategy for 2003 and beyond. We believe that our
current sources of funding (i.e., internally generated funds, the issuance of
additional securities as noted above, and the availability of commercial paper),
together with the cash proceeds from the recent equity offering, are sufficient
to meet our anticipated working capital needs for the foreseeable future.
47
The following table represents the ratings of our long-term debt at March 31,
2003. Currently, these ratings are all on stable outlook with the exception of
Standard & Poor's rating on KeySpan Corporation, which is on negative outlook.
- --------------------------------------------------------------------------------
Moody's Investor Standard
Services & Poor's FitchRatings
- --------------------------------------------------------------------------------
KeySpan Corporation A3 A A-
KEDNY A2 A+ A+
KEDLI A2 A+ A-
Boston Gas A2 A2 N/A
Colonial Gas A A N/A
- --------------------------------------------------------------------------------
Off-Balance Sheet Arrangements
Guarantees
KeySpan has a number of financial guarantees with its subsidiaries that have
remained substantially unchanged since December 31, 2002. At March 31, 2003,
KeySpan has fully and unconditionally guaranteed certain medium-term notes
issued by KEDLI under KEDLI's current shelf registration, as well as guaranteed
a revolving credit agreement associated with its Canadian subsidiary. Both the
medium-term notes and outstanding borrowings under the credit facility are
reflected on the Consolidated Balance Sheet. Further, KeySpan has guaranteed:
(i) surety bonds associated with certain construction projects currently being
performed by subsidiaries within the Energy Services segment; (ii) certain
supply contracts, margin accounts and purchase orders for certain subsidiaries;
(iii) the obligations of KeySpan Ravenswood LLC, the lessee under the $425
million Master Lease Agreement associated with the Ravenswood facility; and (iv)
certain subsidiary letters of credit. KeySpan has also guaranteed $25 million
associated with a non-affiliated company's line of credit. These guarantees are
not recorded on the Consolidated Balance Sheet. At this time, we have no reason
to believe that our subsidiaries or the non-affiliated company will default on
their current obligations. However, we cannot predict when or if any defaults
may take place or the impact such defaults may have on our consolidated results
of operations, financial condition or cash flows (See Note 8 to the Consolidated
Financial Statements, "Financial Guarantees and Contingencies" and Note 9
"Variable Interest Entity" for a description of the leasing arrangement
associated with the Ravenswood Master Lease Agreement and additional information
regarding KeySpan's guarantees.)
Variable Interest Entity
We have an arrangement with a variable interest entity through which we lease a
portion of the Ravenswood facility. We acquired the Ravenswood facility, in
part, through the variable interest entity from The Consolidated Edison Company
of New York ("Consolidated Edison") on June 18, 1999 for approximately $597
million. In order to reduce the initial cash requirements, we entered into a
lease agreement (the "Master Lease") with a variable interest, unaffiliated
financing entity that acquired a portion of the facility, three steam generating
48
units, directly from Consolidated Edison and leased it to a KeySpan subsidiary.
The variable interest unaffiliated financing entity acquired the property for
$425 million, financed with debt of $412.3 million (97% of capitalization) and
equity of $12.7 million (3% of capitalization). Monthly lease payments equal the
monthly interest expense on the debt securities. The Master Lease currently
qualifies as an operating lease for financial reporting purposes while
preserving our ownership of the facility for federal and state income tax
purposes.
In January 2003, The Financial Accounting Standards Board (the "Board") issued
Interpretation No. 46 ("FIN 46"), "Consolidation of Variable Interest Entities,
an Interpretation of ARB No. 51." This Interpretation would require us to, among
other things, consolidate this variable interest entity for the first interim
period ending after June 15, 2003, so long as the current variable interest
structure remains intact. FIN 46 will require us to classify the Master Lease as
debt on the Consolidated Balance Sheet at an amount approximately equal to fair
market value. As previously mentioned, under the terms of our credit facility
the Master Lease is considered debt in the ratio of debt-to-total capitalization
and therefore, implementation of FIN 46 will have no impact on our credit
facility. Further, we will be required to record an asset on the Consolidated
Balance Sheet for an amount equal to the fair market value of the leased assets.
The Interpretation contains certain other provisions that we will be required to
implement in 2003 and such provisions may impact future earnings. (See Note 9 to
the Consolidated Financial Statements "Variable Interest Entity" for a more
detailed description of the Master Lease and FIN 46 implementation issues.)
Contractual Obligations
KeySpan has certain contractual obligations related to its outstanding long-term
debt, outstanding credit facility borrowings, outstanding commercial paper
borrowings, operating and capital leases, and demand charges associated with
certain commodity purchases. These obligations have remained substantially
unchanged since December 31, 2002. (For additional details regarding these
obligations see KeySpan's Annual Report on Form 10K for the Year Ended December
31, 2002, Item 7 Management's Discussion and Analysis of Financial Condition and
Results of Operations, Note 6 to those Consolidated Financial Statements
"Long-Term Debt", as well as Note 7 to those Consolidated Financial Statements
"Contractual Obligations, Financial Guarantees and Contingencies.")
Discussions of Critical Accounting Policies and Assumptions
In preparing our financial statements, the application of certain accounting
policies requires difficult, subjective and/or complex judgments. The
circumstances that make these judgments difficult, subjective and/or complex
have to do with the need to make estimates about the impact of matters that are
inherently uncertain. Actual effects on our financial position and results of
operations may vary significantly from expected results if the judgments and
assumptions underlying the estimates prove to be inaccurate. At March 31, 2003,
49
KeySpan's critical accounting policies and assumptions have remained
substantially unchanged since December 31, 2002. Below is a brief discussion of
those critical accounting policies requiring such subjectivity. For a more
detailed discussion of these policies and assumptions see KeySpan's Annual
Report on Form 10K for the Year Ended December 31, 2002, Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations
"Discussion of Critical Accounting Policies and Assumptions."
Percentage of Completion Accounting
Percentage-of-completion accounting is the prescribed method of accounting for
long-term construction type contracts in accordance with Generally Accepted
Accounting Principles and, accordingly, the method used for revenue recognition
by the Energy Services segment. Due to uncertainties inherent within estimates
employed to apply percentage-of-completion accounting, it is possible that
estimates will be revised as project work progresses. Changes in estimates
resulting in additional future costs to complete projects can result in reduced
margins or loss contracts.
Valuation of Goodwill
KeySpan records goodwill on purchase transactions, representing the excess of
acquisition cost over the fair value of net assets acquired. In testing for
goodwill impairment under Statement of Financial Accounting Standards ("SFAS")
142, significant reliance is placed upon estimated future cash flows requiring
broad assumptions and significant judgment by management. Cash flow estimates
are determined based upon future commodity prices, customer rates, customer
demand, operating costs, rate relief from regulators, customer growth and other
items. A change in the fair value of our investments could cause a significant
change in the carrying value of goodwill. While we believe that our assumptions
are reasonable, actual results may differ from our projections. The assumptions
used to measure the fair value of our investments are the same as those used by
us to prepare yearly operating segment and consolidated earnings and cash flow
forecasts. In addition, these assumptions are used to set yearly budgetary
guidelines.
Accounting for the Effects of Rate Regulation on Gas Distribution Operations
The financial statements of the Gas Distribution segment reflect the ratemaking
policies and orders of the New York Public Service Commission ("NYPSC"), the New
Hampshire Public Utilities Commission ("NHPUC"), and the Massachusetts
Department of Telecommunications and Energy ("DTE").
Four of our six regulated gas utilities (KEDNY, KEDLI, Boston Gas Company and
EnergyNorth Natural Gas, Inc.) are subject to the provisions of SFAS 71,
"Accounting for the Effects of Certain Types of Regulation." This statement
recognizes the actions of regulators, through the ratemaking process, to create
future economic benefits and obligations affecting rate-regulated companies.
50
In separate merger-related orders issued by the DTE, the base rates charged by
Colonial Gas Company and Essex Gas Company have been frozen at their current
levels for a ten-year period ending 2009. Due to the length of these base rate
freezes, the Colonial and Essex Gas Companies had previously discontinued the
application of SFAS 71.
Rate regulation is undergoing significant change as regulators and customers
seek lower prices for utility service and greater competition among energy
service providers. In the event that regulation significantly changes the
opportunity for us to recover costs in the future, all or a portion of our
regulated operations may no longer meet the criteria for the application of SFAS
71. In that event, a write-down of our existing regulatory assets and
liabilities could result. In management's opinion, our regulated subsidiaries
that currently are subject to the provisions of SFAS 71 will continue to be
subject to SFAS 71 for the foreseeable future.
As is further discussed under the caption "Regulation and Rate Matters," the
rate plans previously in effect for KEDNY, KEDLI and Boston Gas Company have all
expired. The continued application of SFAS 71 to record the activities of these
subsidiaries is contingent upon the actions of regulators with regard to future
rate plans. We filed a base rate case and a performance based rate plan for
Boston Gas Company on April 16, 2003. Further, we are currently evaluating
various options that may be available to us including, but not limited to,
proposing new plans for KEDNY and KEDLI. The ultimate resolution of any future
rate plans could have a significant impact on the application of SFAS 71 to
these entities and, accordingly, on our financial position, results of
operations and cash flows. However, management believes that currently available
facts support the continued application of SFAS 71 and that all regulatory
assets and liabilities are recoverable or refundable through the regulatory
environment.
Pension and Other Postretirement Benefits
KeySpan participates in both non-contributory defined benefit pension plans, as
well as other post-retirement benefit ("OPEB") plans (collectively
"postretirement plans"). KeySpan's reported costs of providing pension and OPEB
benefits are dependent upon numerous factors resulting from actual plan
experience and assumptions of future experience. Pension and OPEB costs
(collectively "postretirement costs") are impacted by actual employee
demographics, the level of contributions made to the plans, earnings on plan
assets, and health care cost trends. Changes made to the provisions of these
plans may also impact current and future postretirement costs. Postretirement
costs may also be significantly affected by changes in key actuarial
assumptions, including anticipated rates of return on plan assets and the
discount rates used in determining the postretirement costs and benefit
obligations.
Historically, we have funded our pension plans in excess of the amount required
to satisfy minimum ERISA funding requirements. At December 31, 2002, we had a
funding balance in excess of the ERISA minimum funding requirements and as a
result KeySpan will not be required to make any contribution to its pension
plans in 2003. However, although we presently exceed ERISA funding requirements,
our pension plans, on an actuarial basis, are currently underfunded. Future
funding requirements are heavily dependent on actual return on plan assets.
Therefore, if the actual return on plan assets continues to be significantly
51
below the expected returns, we may elect to fund the pension plans in 2003. (In
addition to Item 7 Management's Discussion and Analysis of Financial Condition
and Results of Operations in KeySpan's Annual Report on Form 10K for the Year
Ended December 31, 2002, see also Note 4 of those Consolidated Financial
Statements, "Postretirement Benefits.")
Full Cost Accounting
Our gas exploration and production subsidiaries use the full cost method to
account for their natural gas and oil properties. Under full cost accounting,
all costs incurred in the acquisition, exploration, and development of natural
gas and oil reserves are capitalized into a "full cost pool". Capitalized costs
include costs of all unproved properties, internal costs directly related to
natural gas and oil activities, and capitalized interest.
Under full cost accounting rules, total capitalized costs are limited to a
ceiling equal to the present value of future net revenues, discounted at 10%,
plus the lower of cost or fair value of unproved properties less income tax
effects (the "ceiling limitation"). A quarterly ceiling test is performed to
evaluate whether the net book value of the full cost pool exceeds the ceiling
limitation. If capitalized costs (net of accumulated depreciation, depletion and
amortization) less deferred taxes are greater than the discounted future net
revenues or ceiling limitation, a write-down or impairment of the full cost pool
is required.
Natural gas and oil reserve quantities represent estimates only. Under full cost
accounting, reserve estimates are used to determine the full cost ceiling
limitation as well as the depletion rate. Houston Exploration estimates its
proved reserves and future net revenues using sales prices estimated to be in
effect as of the date it makes the reserve estimates. Natural gas prices, which
have fluctuated widely in recent years, affect estimated quantities of proved
reserves and future net revenues. Any estimates of natural gas and oil reserves
and their values are inherently uncertain, including many factors beyond our
control.
Valuation of Derivative Instruments
We employ derivative instruments to hedge a portion of our exposure to commodity
price risk and interest rate risk, to partially hedge the cash flow variability
associated with our electric energy and capacity sales from the Ravenswood
facility, as well as to economically hedge certain other commodity exposures. In
addition, KeySpan Canada has used swap instruments to lock-in the purchase price
on the purchase of electricity needed to operate its gas processing plants. All
of our derivative instruments, except for certain weather derivatives, meet the
SFAS 133 definition of a derivative. Further, none of our currently outstanding
derivatives qualify as "energy trading contracts" as defined by current
accounting literature.
When available, quoted market prices are used to record a contract's fair value.
However, market values for certain derivative contracts may not be readily
available or determinable. A number of our commodity related derivative
instruments are exchange traded and, accordingly, fair value measurements are
generally based on standard New York Mercantile Exchange ("NYMEX") quotes. We
use industry-published indices, NYISO location zone indices, as well as other
52
local published indices to value contracts for commodities that are not exchange
traded, such as No. 6 grade fuel oil and electricity. The fair value of our
electric capacity hedges is based on published NYISO capacity bidding prices.
Further, if no active market exists for a commodity, fair values may be based on
pricing models. (See Note 6 to the Consolidated Financial Statements "Hedging
and Derivative Financial Instruments" for a further description of all our
derivative instruments.)
Regulation and Rate Matters
Gas Matters
As of March 31, 2003, the rate agreements for KEDNY, KEDLI and Boston Gas
Company have all expired. Under the terms of the KEDNY and KEDLI rate
agreements, gas distribution rates and all other provisions will remain in
effect until changed by the NYPSC. At this time, we are currently evaluating
various options that may be available to us regarding the KEDNY and KEDLI rate
plans, including but not limited to, proposing new rate plans. Regarding the
Boston Gas Company, we filed a base rate case and performance based rate plan on
April 16, 2003, to be effective in the fourth quarter of 2003. The filing
requests an annual revenue increase of approximately $61 million and a
performance based rate plan term of five years.
For an additional discussion of our current gas distribution rate agreements,
see KeySpan's Annual Report on Form 10K for the Year Ended December 31, 2002,
Item 7 Management's Discussion and Analysis of Financial Condition and Results
of Operations "Regulation and Rate Matters."
Securities and Exchange Commission Regulation
KeySpan and its subsidiaries are subject to the jurisdiction of the SEC under
PUHCA. The rules and regulations under PUHCA generally limit the operations of a
registered holding company to a single integrated public utility system, plus
additional energy-related businesses. In addition, the principal regulatory
provisions of PUHCA: (i) regulate certain transactions among affiliates within a
holding company system including the payment of dividends by such subsidiaries
to a holding company; (ii) govern the issuance, acquisition and disposition of
securities and assets by a holding company and its subsidiaries; (iii) limit the
entry by registered holding companies and their subsidiaries into businesses
other than electric and/or gas utility businesses; and (iv) require SEC approval
for certain utility mergers and acquisitions.
The SEC's order issued on November 8, 2000, in connection with our acquisition
of Eastern Enterprises and Energy North Inc. as amended on December 6, 2002 and
February 14, 2003, provides us with, among other things, authorization to do the
following through December 31, 2003 (the "Authorization Period"): (a) subject to
an aggregate amount of $5.8 billion, (i) maintain existing financing agreements,
(ii) issue and sell up to $2.2 billion of additional securities in compliance
with certain defined parameters, (iii) issue additional guarantees and other
forms of credit support in an aggregate amount of $2.0 billion at any time in
addition to any such securities, guarantees and credit support outstanding or
existing as of November 8, 2000, and (iv) amend, renew, extend, supplement or
replace any of the foregoing; (b) issue shares of common stock or reissue shares
of common
53
stock held in treasury under dividend reinvestment and stock-based management
incentive and employee benefit plans; (c) maintain existing and enter into
additional hedging transactions with respect to outstanding indebtedness in
order to manage and minimize interest rate costs; (d) invest up to $2.2 billion
in exempt wholesale generators; and (e) pay dividends out of capital and
unearned surplus as well as paid-in-capital with respect to certain
subsidiaries, subject to certain limitations.
In addition, we have committed that during the Authorization Period, our common
equity will be at least 30% of our consolidated capitalization and each of our
utility subsidiaries' common equity will be at least 30% of such entity's
capitalization. At March 31, 2003, our consolidated common equity was 39.5% of
our consolidated capitalization, including commercial paper, and each of our
utility subsidiaries common equity was at least 35% of its respective
capitalization.
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 $188.4 million
and we have recorded a related liability for such amount. We have also recorded
an additional $38.8 million liability representing the estimated environmental
cleanup costs related to a former coal tar processing facility. Further, as of
March 31, 2003, we have expended a total of $76.1 million on environmental
remediation. (See Note 8 to the Consolidated Financial Statements, "Financial
Guarantees and Contingencies".)
Market and Credit Risk Management Activities
Market Risk: We are exposed to market risk arising from potential changes in one
or more market variables, such as energy commodity price risk, interest rate
risk, foreign currency exchange rate risk, volumetric risk due to weather or
other variables. Such risk includes any or all changes in value whether caused
by commodity positions, asset ownership, business or contractual obligations,
debt covenants, exposure concentration, currency, weather, and other factors
regardless of accounting method. We manage our exposure to changes in market
prices using various risk management techniques for non-trading purposes,
including hedging through the use of derivative instruments, both
exchange-traded and over-the-counter contracts, purchase of insurance and
execution of other contractual arrangements. (See Note 6 to the Consolidated
Financial Statements "Hedging and Derivative Financial Instruments" for a
further explanation of derivative financial instruments.)
Credit Risk: We are exposed to credit risk arising from the potential that our
counterparties fail to perform on their contractual obligations. Our credit
exposures are created primarily through the sale of gas and transportation
services to residential, commercial, electric generation, and industrial
customers and the provision of retail access services to gas marketers, by our
regulated gas businesses; the sale of commodities and services to LIPA and the
NYISO; the sale of gas, power and services to our retail customers by our
unregulated energy service businesses; entering into financial and energy
derivative contracts with energy marketing companies and financial institutions;
and the sale of gas, natural gas liquids, oil and processing services to energy
marketing and oil and gas production companies.
54
We have regional concentration of credit risk due to receivables from
residential, commercial and industrial customers in New York, New Hampshire and
Massachusetts, although this credit risk is spread over a diversified base of
residential, commercial and industrial customers. Customers' payment records are
monitored and action is taken, when appropriate. Companies within the Energy
Services segment have a concentration of credit risk to large customers and to
the governmental and healthcare industries.
We also have concentrations of credit risk from LIPA, our largest customer, and
from other energy companies. Concentration of energy company counterparties may
impact overall exposure to credit risk in that our counterparties may be
similarly impacted by changes in economic, regulatory or other considerations.
We actively monitor the credit profile of our wholesale counterparties in
derivative and other contractual arrangements, and manage our level of exposure
accordingly. Over the past year, the credit quality of certain energy companies
has declined. In instances where counter-parties' credit quality has declined,
we may limit our credit exposure by restricting new transactions with the
counterparty, requiring additional collateral or credit support and negotiating
the early termination of certain agreements.
Regulatory Issues and Competitive Environment: We are subject to various other
risk exposures and uncertainties associated with our gas and electric
operations. The most significant contingency involves the evolution of the gas
distribution and electric industries towards more competitive and deregulated
environments. These risks have not changed substantially since December 31,
2002. For additional information regarding these risks see KeySpan's Annual
Report on Form 10K for the Year Ended December 31, 2002, Item 7 Management's
Discussion and Analysis of Financial Condition and Results of Operations "Market
and Credit Risk Management Activities".
Cautionary Statement Regarding Forward-Looking Statements
Certain statements contained in this Quarterly Report on Form 10Q concerning
expectations, beliefs, plans, objectives, goals, strategies, future events or
performance and underlying assumptions and other statements that are other than
statements of historical facts, are "forward-looking statements" within the
meaning of Section 21E of the Securities Exchange Act of 1934, as amended.
Without limiting the foregoing, all statements under the captions "Item 2.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Item 3. Quantitative and Qualitative Disclosures About Market
Risk" relating to our future outlook, anticipated capital expenditures, future
cash flows and borrowings, pursuit of potential future acquisition opportunities
and sources of funding, are forward-looking statements. Such forward-looking
statements reflect numerous assumptions and involve a number of risks and
uncertainties and actual results may differ materially from those discussed in
such statements.
55
Among the factors that could cause actual results to differ materially are:
- - volatility of energy prices of fuel used to generate electricity;
- - fluctuations in weather and in gas and electric prices;
- - general economic conditions, especially in the Northeast United States;
- - our ability to successfully reduce our cost structure and operate
efficiently;
- - our ability to successfully contract for natural gas supplies required to
meet the needs of our firm customers;
- - implementation of new accounting standards;
- - inflationary trends and interest rates;
- - the ability of KeySpan to identify and make complementary acquisitions, as
well as the successful integration of recent and future acquisitions;
- - available sources and cost of fuel;
- - creditworthiness of counter-parties to derivative instruments and commodity
contracts;
- - retention of key personnel;
- - federal and state regulatory initiatives that increase competition,
threaten cost and investment recovery, and place limits on the type and
manner in which we invest in new businesses;
- - the impact of federal and state utility regulatory policies and orders on
our regulated and unregulated businesses;
- - potential write-down of our investment in natural gas properties when
natural gas prices are depressed or if we have significant downward
revisions in our estimated proved gas reserves;
- - competition in general facing our unregulated Energy Services businesses,
including but not limited to competition from other mechanical, plumbing,
heating, ventilation and air conditioning, and engineering companies, as
well as, other utilities and utility holding companies that are permitted
to engage in such activities;
- - the degree to which we develop unregulated business ventures, as well as
federal and state regulatory policies affecting our ability to retain and
operate such business ventures profitably;
- - changes in political conditions, acts of war or terrorism;
- - changes in rates of return on overall debt and equity markets could have an
adverse impact on the value of pension assets;
- - changes in accounting standards or GAAP which may require adjustment to
financial statements; and
56
- - 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.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Financially-Settled Commodity Derivative Instruments: From time to time KeySpan
has utilized derivative financial instruments, such as futures, options and
swaps, for the purpose of hedging exposure to commodity price risk and to hedge
the cash flow variability associated with a portion of peak electric energy
sales.
Houston Exploration has utilized collars, as well as over-the-counter ("OTC")
swaps, to hedge the cash flow variability associated with forecasted sales of a
portion of its natural gas and oil production. As of March 31, 2003, Houston
Exploration has hedged approximately 67% and 38% of its estimated 2003 and 2004
gas production, respectively. Further, Houston Exploration may enter into
additional derivative positions for 2004. Houston Exploration used standard New
York Mercantile Exchange ("NYMEX") futures prices and published volatility in
its Black-Scholes calculation to value its outstanding derivatives. The maximum
length of time over which Houston Exploration has hedged such cash flow
variability associated with: (i) forecasted natural gas production is through
December 2004; and (ii) forecasted oil production is through June 2003. The
estimated amount of losses associated with such derivative instruments that are
reported in Other Comprehensive Income and that are expected to be reclassified
into earnings over the next twelve months is $52.2 million, or $33.9 million
after-tax.
With respect to price exposure associated with fuel purchases for the Ravenswood
facility, KeySpan employs standard NYMEX natural gas futures contracts and
over-the-counter financially settled natural gas basis swaps to hedge the cash
flow variability of a portion of forecasted purchases of natural gas. KeySpan
also employs the use of financially-settled oil swap contracts to hedge the cash
flow variability of a portion of forecasted purchases of fuel oil that will be
consumed at the Ravenswood facility. The maximum length of time over which we
have hedged cash flow variability associated with: (i) forecasted purchases of
natural gas is through October 2003; and (ii) forecasted purchases of fuel oil
is through April 2004. We used standard NYMEX futures prices to value the gas
futures contracts and industry published oil indices for number 6 grade fuel oil
to value the oil swap contracts. The estimated amount of gains associated with
all such derivative instruments that are reported in Other Comprehensive Income
and that are expected to be reclassified into earnings over the next twelve
months is $3.0 million, or $2.0 million after-tax.
57
Our retail gas and electric marketing subsidiary, our domestic gas distribution
operations and KeySpan Canada employed NYMEX natural gas futures contracts and
natural gas swaps to lock-in a price for expected future natural gas purchases.
As applicable, we used standard NYMEX futures prices and relevant natural gas
indices to value the outstanding contracts. The maximum length of time over
which we have hedged such cash flow variability is through October 2004. The
estimated amount of gains associated with such derivative instruments that are
reported in Other Comprehensive Income and that are expected to be reclassified
into earnings over the next twelve months is $3.7 million, or $2.4 million
after-tax.
We have also engaged in the use of cash-settled swap instruments to hedge the
cash flow variability associated with (i) a portion of forecasted peak electric
energy sales from the Ravenswood facility and (ii) forecasted sales of Unforced
Capacity ("UCAP") to the NYISO. The maximum length of time over which we have
hedged cash flow variability is through March 2004. We used NYISO-location zone
published indices as well as published NYISO bidding prices to value these
outstanding derivatives. The estimated amount of losses associated with such
derivative instruments that are reported in Other Comprehensive Income and that
are expected to be reclassified into earnings over the next twelve months is
$0.9 million, or $0.6 million after-tax.
KeySpan Canada also employs electricity swap contracts to lock-in the purchase
price of electricity needed to operate its gas processing plants. These
contracts are not exchange-traded and local published indices were used to value
these outstanding swap agreements. The maximum length of time over which we have
hedged such cash flow variability is through December 2003. The estimated amount
of losses associated with such derivative instruments that are reported in Other
Comprehensive Income and that are expected to be reclassified into earnings over
the next twelve months is $1.1 million, or $0.7 million after-tax.
The following tables set forth selected financial data associated with these
derivative financial instruments noted above that were outstanding at March 31,
2003.
- -----------------------------------------------------------------------------------------------------------------------------
Year of Volumes Fixed Current Fair Value
Type of Contract Maturity mmcf Floor $ Ceiling $ Price $ Price $ ($000)
- -----------------------------------------------------------------------------------------------------------------------------
Gas
Collars 2003 41,250 3.48 4.92 - 5.06 - 5.30 (24,881)
2004 36,600 3.75 5.05 - 4.33 - 5.38 (10,200)
Swaps/Futures - Short Natural Gas 2003 11,214 - - 3.19 - 3.57 4.22 - 5.30 (21,519)
Swaps/Futures - Long Natural Gas 2003 4,550 - - 3.14 - 4.92 5.06 - 5.30 6,249
2004 90 - - 3.49 - 4.35 3.90 - 4.40 31
- -----------------------------------------------------------------------------------------------------------------------------
93,704 (50,320)
- -----------------------------------------------------------------------------------------------------------------------------
58
- ----------------------------------------------------------------------------------------------------------------------
Year of Volumes Fair Value
Type of Contract Maturity Barrels Fixed Price $ Current Price $ ($000)
- ----------------------------------------------------------------------------------------------------------------------
Oil
Swaps - Short Fuel Oil 2003 91,000 29.70 28.03 - 30.42 (116)
Swaps - Long Fuel Oil 2003 81,697 20.60 - 23.50 26.41 - 33.58 639
2004 5,548 20.50 - 23.70 25.49 - 26.07 22
- ----------------------------------------------------------------------------------------------------------------------
178,245 545
- ----------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------------------
Year of Fixed Margin/ Fair Value
Type of Contract Maturity Capacity MWh Price $ Current Price $ ($000)
- --------------------------------------------------------------------------------------------------------------------------------
Electricity
Swaps - Energy 2003 - 447,200 30.50 - 61.91 36.02 - 49.52 (647)
2004 99,200 14.00 23.56 - 32.41 (1,488)
Swaps - Capacity 2003 100 - 7.75 7.00 75
- --------------------------------------------------------------------------------------------------------------------------------
100 546,400 (2,060)
- --------------------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
2003
Change in Fair Value of Derivative Instruments ($000)
- -------------------------------------------------------------------------------
Fair value of contracts at January 1, $ (32,628)
Losses on contracts realized 3,621
Fair value of new contracts when entered into during period -
(Decrease) in fair value of all open contracts (22,828)
- -------------------------------------------------------------------------------
Fair value of contracts outstanding at March 31, $ (51,835)
- -------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- ----------------------------------------------------------------------------------------------------
Fair Value of Contracts
- ----------------------------------------------------------------------------------------------------
Maturity Maturity Total
Sources of Fair Value 2003 2004 Fair Value
- ----------------------------------------------------------------------------------------------------
Prices actively quoted $ (29,898) 31 $ (29,867)
Prices provided by external sources 417 - 417
Prices based on models and
other valuation methods (16,423) (4,424) (20,847)
Local published indicies (1,538) - (1,538)
- ----------------------------------------------------------------------------------------------------
$ (47,442) $ (4,393) $ (51,835)
- ----------------------------------------------------------------------------------------------------
NYMEX futures are also used to economically hedge the cash flow variability
associated with the purchase of fuel for a portion of our fleet vehicles.
Further, KeySpan Canada has a portfolio of financially-settled natural gas
collars and natural gas liquid swap transactions. Such contracts are executed by
KeySpan Canada to: (i) synthetically fix the price that is paid or received by
KeySpan Canada for certain physical transactions involving natural gas and
natural gas liquids and (ii) transfer the price exposure of such instruments to
counterparties. These derivative financial instruments do not qualify for hedge
accounting under SFAS 133. At March 31, 2003, these instruments had a net fair
market value of $0.06 million, which was recorded on the Consolidated Balance
Sheet. Based on the non-hedge designation of these instruments, the gain was
recognized in the Consolidated Statement of Income.
59
Firm Gas Sales Derivative Instruments - Regulated Utilities: We use derivative
financial instruments to reduce the cash flow variability associated with the
purchase price for a portion of future natural gas purchases associated with our
Gas Distribution operations. Our strategy is to minimize fluctuations in firm
gas sales prices to our regulated firm gas sales customers in our New York and
New Hampshire service territories. Since these derivative instruments are
employed to reduce the variability of the purchase price of natural gas to be
sold to regulated firm gas sales customers, the accounting for these derivative
instruments is subject to SFAS 71 "Accounting for the Effects of Certian Types
of Regulation". Therefore, changes in the market value of these derivatives have
been recorded as a Regulatory Asset or Regulatory Liability on the Consolidated
Balance Sheet. Gains or losses on the settlement of these contracts are
initially deferred and then refunded to or collected from our firm gas sales
customers consistent with regulatory requirements.
The following table sets forth selected financial data associated with these
derivative financial instruments that were outstanding at March 31, 2003.
- ---------------------------------------------------------------------------------------------------------------------
Year of Volumes Fair Value
Type of Contract Maturity mmcf Fixed Price $ Current Price $ ($000)
- ---------------------------------------------------------------------------------------------------------------------
Options 2003 1,030 4.01 - 6.00 5.06 - 5.30 (27)
2004 2,140 5.00 - 6.00 4.54 - 5.38 (793)
Swaps 2003 10,470 4.01 - 5.84 5.06 - 5.30 (2,682)
2004 3,890 4.42 - 5.93 4.41 - 5.38 (1,337)
- ---------------------------------------------------------------------------------------------------------------------
17,530 (4,839)
- ---------------------------------------------------------------------------------------------------------------------
Physically-Settled Commodity Derivative Instruments: Derivative Implementation
Group ("DIG") Issue C15 and C16 of Statement of Financial Accounting Standard
133, "Accounting for Derivative Instruments and Hedging Activities", as amended
and interpreted, incorporating SFAS 137 and SFAS 138 and certain implementation
issues (collectively "SFAS 133") establishes criteria that must be satisfied in
order for option-type and forward contracts in electricity to be exempted as
normal purchases and sales, and relates to the exemption (as normal purchases
and normal sales) of contracts that combine a forward contract and a purchased
option contract. Based upon a continuing review of our physical commodity
contracts, we determined that certain contracts for the physical purchase of
natural gas are not exempt as normal purchases from the requirements of SFAS
133. At March 31, 2003, the fair value of these contracts was a negative $4.9
million. Since these contracts are for the purchase of natural gas sold to
regulated firm gas sales customers, the accounting for these contracts is
subject to SFAS 71. Therefore, changes in the market value of these contracts
have been recorded as a Regulatory Asset or Regulatory Liability on the
Consolidated Balance Sheet.
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Interest Rate Derivative Instruments: During 2002, we had interest rate swap
agreements in which approximately $1.3 billion of fixed rate debt had been
synthetically modified to floating rate debt. Under the terms of the agreements,
we received the fixed coupon rate associated with these bonds and paid the
counter-parties a variable interest rate that was reset on a quarterly basis.
These swaps were designated as fair-value hedges and qualified for "short-cut"
hedge accounting treatment under SFAS 133.
In 2002, we terminated two interest rate swap agreements with an aggregate
notional amount of $1.0 billion. The remaining swap, which had a notional amount
of $270.0 million, was terminated on February 25, 2003. We received $18.4
million from our swap counterparties as a result of the latter termination, of
which $8.1 million represented accrued swap interest. The difference between the
termination settlement amount and the amount of accrued interest, $10.3 million,
was recorded to earnings in the first quarter of 2003. This swap was used to
hedge a portion of our outstanding promissory notes to LIPA. As discussed in
Note 5 "Long-Term Debt", we redeemed a portion of these promissory notes during
the first quarter of 2003.
Additionally, we had an interest rate swap agreement that hedged the cash flow
variability associated with the forecasted issuance of a series of commercial
paper offerings. This hedge expired in March 2003.
Weather Derivatives: The utility tariffs associated with KEDNE's operations do
not contain weather normalization adjustments. As a result, fluctuations from
normal weather may have a significant positive or negative effect on the results
of these operations. To mitigate a substantial portion of the effect of
fluctuations from normal weather on our financial position and cash flows, we
sold heating degree-day call options and purchased heating-degree day put
options for the November 2002-March 2003 winter season. With respect to sold
call options, KeySpan is required to make a payment of $40,000 per heating
degree day to its counterparties when actual weather experienced during the
November 2002 - March 2003 time frame was above 4,470 heating degree days, which
equates to approximately 1% colder than normal weather. With respect to
purchased put options, KeySpan would receive a $20,000 per heating degree day
payment from its counterparties when actual weather was below 4,150 heating
degree days, or approximately 7% warmer than normal. Based on the terms of such
contracts, we account for such instruments pursuant to the requirements of EITF
99-2, "Accounting for Weather Derivatives." In this regard, we account for such
instruments using the "intrinsic value method" as set forth in such guidance.
During the first quarter of 2003, weather was 10% colder than normal and, as a
result, $11.9 million has been recorded as a reduction to revenues.
Derivative contracts are primarily used to manage exposure to market risk
arising from changes in commodity prices and interest rates. In the event of
nonperformance by a counterparty to a derivative contract, the desired impact
may not be achieved. The risk of counterparty nonperformance is generally
considered credit risk and is actively managed by assessing each counterparty
credit profile and negotiating appropriate levels of collateral and credit
support.
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PART II. OTHER INFORMATION
- ---------------------------
Item 1. Legal Proceedings
See Note 8 to Consolidated Financial Statements "Financial Guarantees and
Contingencies" for a discussion of certain legal proceedings.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
(b) Reports on Form 8-K
In our report on Form 8-K dated January 13, 2003, we disclosed that we had
issued a press release announcing our proposed issuance of 14,000,000 shares of
common stock.
In our report on Form 8-K dated January 14, 2003, we disclosed that we had
issued a press release discussing the anticipated net proceeds from the offering
of common stock announced on January 13, 2003.
In our report on Form 8-K dated January 15, 2003, we disclosed that we had
issued a press release concerning, among other things, our issuance of common
stock.
In our report on Form 8-K dated January 28, 2003, we disclosed that we had
issued a press release concerning, among other things, our consolidated earnings
for the year ended December 31, 2002.
In our report on Form 8-K dated February 21, 2003, we disclosed that we had
issued a press release concerning, among other things, a proposed sale of a
portion of our ownership interest in The Houston Exploration Company.
In our report on Form 8-K dated April 4, 2003, we disclosed that we had issued
$150,000,000 4.650% Notes due 2013 and $150,000,000 5.875% Notes due 2033. The
Notes were issued under the Company's previously filed Registration Statement on
Form S-3 (Reg. No. 333-82230), which became effective February 14, 2002 (the
"Registration Statement"), and the related prospectus supplement, dated April 1,
2003 (the "Prospectus Supplement"). The Notes were offered by ABN AMRO
Incorporated, Salomon Smith Barney Inc., The Royal Bank of Scotland plc, Fleet
Securities, Inc., Scotia Capital (USA) Inc. and Wachovia Securities, Inc., as
underwriters.
Exhibits
99.1*Certification of Chief Executive Officer pursuant to 18 U.S.C. 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.2*Certification of Chief Financial Officer pursuant to 18 U.S.C. 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
- ----------------------
*Filed Herewith
62
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: May 1, 2003 /s/ Gerald Luterman
--------------------------
Gerald Luterman
Executive Vice President and
Chief Financial Officer
Date: May 1, 2003 /s/ Joseph Bodanza
---------------------------
Joseph Bodanza
Senior Vice President
and Chief Accounting Officer
Date: May 1, 2003 /s/ Theresa Balog
--------------------------
Theresa Balog
Vice President and Controller
63
CHIEF EXECUTIVE OFFICER'S CERTIFICATION
I, Robert B Catell, certify that:
1. I have reviewed this quarterly report on Form 10-Q of KeySpan Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) Designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) Evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) Presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our evaluation
as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
the registrant's board of directors (or persons performing the equivalent
function):
a) All significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
64
6. The registrant's other certifying officer and I have indicated in this
quarterly report whether there were significant changes in internal controls or
in other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: May 1, 2003 /s/ Robert B. Catell
------------------------------
Robert B. Catell
Chairman of the Board of Directors
and Chief Executive Officer
65
CHIEF FINANCIAL OFFICER'S CERTIFICATION
I, Gerald Luterman, certify that:
1. I have reviewed this quarterly report on Form 10-Q of KeySpan Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) Designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) Evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) Presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our evaluation
as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
the registrant's board of directors (or persons performing the equivalent
function):
a) All significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
66
6. The registrant's other certifying officer and I have indicated in this
quarterly report whether there were significant changes in internal controls or
in other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: May 1, 2003 /s/ Gerald Luterman
---------------------
Gerald Luterman
Executive Vice President
and Chief Financial Officer
67