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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2002
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
incorporation or organization Identification No.)
One MetroTech Center, Brooklyn, New York 11201
175 East Old Country Road, Hicksville, New York 11801
(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/
APPLICABLE ONLY TO CORPORATE ISSUERS:
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class of Common Stock Outstanding at October 31, 2002
--------------------- -------------------------------
$.01 par value 142,026,375
KEYSPAN CORPORATION AND SUBSIDIARIES
Table of Contents
Page
----
PART I FINANCIAL INFORMATION
---------------------
Item 1 Financial Statements
Consolidated Balance Sheet:
September 30, 2002 and December 31, 2001
3
Consolidated Statement of Income:
Three and Nine Months Ended
September 30, 2002 and 2001 5
Consolidated Statement of Cash Flows:
Nine Months Ended September 30, 2002 and 2001 6
Notes to Consolidated Financial Statements 7
Item 2 Management's Discussion and Analysis of Financial
Condition and Results of Operations 28
Item 3 Quantitative and Qualitative Disclosures
About Market Risk 56
PART II OTHER INFORMATION
- ------- -----------------
Item 1 Legal Proceedings 63
Item 4 Controls and Procedures 63
Item 6 Exhibits and Reports on Form 8-K 63
Signatures 65
Certifications 66
CONSOLIDATED BALANCE SHEET
(Unaudited)
(In Thousands)
- -----------------------------------------------------------------------------------------------------------------------------
September 30, 2002 December 31, 2001
--------------------------- ---------------------------
ASSETS
Current Assets
Cash and cash equivalents $ 53,925 $ 159,252
Accounts receivable 1,100,805 1,344,898
Allowance for uncollectible accounts (67,775) (72,299)
Gas in storage, at average cost 327,246 334,999
Materials and supplies, at average cost 107,507 105,693
Other 187,050 125,944
--------------------------- ---------------------------
1,708,758 1,998,487
--------------------------- ---------------------------
Net Assets Held for Disposal - 191,055
--------------------------- ---------------------------
Equity Investments and Other 237,624 223,249
--------------------------- ---------------------------
Property
Gas 5,977,669 5,704,857
Electric 1,904,995 1,629,768
Other 390,526 400,643
Accumulated depreciation (2,671,817) (2,533,466)
Gas exploration and production, at cost 2,378,828 2,200,851
Accumulated depletion (927,666) (796,722)
--------------------------- ---------------------------
7,052,535 6,605,931
--------------------------- ---------------------------
Deferred Charges
Regulatory assets 430,284 458,191
Goodwill, net of amortization 1,785,029 1,782,826
Other 667,243 529,867
--------------------------- ---------------------------
2,882,556 2,770,884
--------------------------- ---------------------------
Total Assets $ 11,881,473 $ 11,789,606
=========================== ===========================
See accompanying Notes to the Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEET
(Unaudited)
(In Thousands)
- ----------------------------------------------------------------------- ---- --------------------------- --- -----------------------
September 30, 2002 December 31, 2001
--------------------------- -----------------------
LIABILITIES AND CAPITALIZATION
Current Liabilities
Current redemption of long-term debt $ 1,431 $ 993
Accounts payable and accrued expenses 851,433 1,091,430
Commercial paper 529,228 1,048,450
Dividends payable 64,297 63,442
Taxes accrued 42,650 50,281
Customer deposits 36,500 36,151
Interest accrued 114,535 93,962
--------------------------- -----------------------
1,640,074 2,384,709
--------------------------- -----------------------
Deferred Credits and Other Liabilities
Regulatory liabilities 68,311 39,442
Deferred income tax 843,956 598,072
Postretirement benefits and other reserves 715,817 694,680
Other 163,268 207,992
--------------------------- -----------------------
1,791,352 1,540,186
--------------------------- -----------------------
Capitalization
Common stock, $.01 par value, authorized
450,000,000 shares; outstanding 141,865,724 2,995,666 2,995,797
and 137,251,386 shares stated at
Retained earnings 439,181 452,206
Other comprehensive income (42,507) 4,483
Treasury stock purchased (494,576) (561,884)
--------------------------- -----------------------
Total common shareholders equity 2,897,764 2,890,602
Preferred stock 83,849 84,077
Long-term debt 5,260,109 4,697,649
--------------------------- -----------------------
Total Capitalization 8,241,722 7,672,328
--------------------------- -----------------------
Minority Interest in Subsidiary Companies 208,325 192,383
--------------------------- -----------------------
Total Liabilities and Capitalization $ 11,881,473 $ 11,789,606
=========================== =======================
See accompanying Notes to the Consolidated Financial Statements
CONSOLIDATED STATEMENT OF INCOME
(Unaudited)
(In Thousands, Except Per Share Amounts)
- ------------------------------------------------------------------------------------------------------------------------------------
Three Months Three Months Nine Months Nine Months
Ended Ended Ended Ended
September 30, 2002 September 30, 2001 September 30, 2002 September 30, 2001
- ------------------------------------------------------------------------------------------------------------------------------------
Revenues
Gas Distribution $ 337,785 $ 346,703 $ 2,082,577 $ 2,721,032
Electric Services 414,868 387,881 1,084,309 1,089,156
Energy Services 217,104 263,047 687,975 814,911
Gas Exploration 86,464 82,362 249,452 318,093
Energy Investments 23,599 22,436 62,784 73,627
------------------- ------------------ --------------------- ----------------------
Total Revenues 1,079,820 1,102,429 4,167,097 5,016,819
------------------- ------------------ --------------------- ----------------------
Operating Expenses
Purchased gas for resale 138,607 148,893 1,037,907 1,694,591
Fuel and purchased power 139,538 164,555 317,253 454,212
Operations and maintenance 485,157 507,113 1,531,394 1,544,799
Depreciation, depletion and amortization 127,301 135,937 380,758 388,679
Operating taxes 96,298 94,909 304,076 337,734
------------------- ------------------ --------------------- ----------------------
Total Operating Expenses 986,901 1,051,407 3,571,388 4,420,015
------------------- ------------------ --------------------- ----------------------
Operating Income 92,919 51,022 595,709 596,804
------------------- ------------------ --------------------- ----------------------
Other Income and (Deductions)
Minority interest (5,353) (7,694) (15,920) (34,970)
Other (1,293) 6,464 24,821 35,286
------------------- ------------------ --------------------- ----------------------
Total Other Income (6,646) (1,230) 8,901 316
------------------- ------------------ --------------------- ----------------------
Earnings Before Interest Charges
and Income Taxes 86,273 49,792 604,610 597,120
------------------- ------------------ --------------------- ----------------------
Interest Charges 79,937 78,735 222,594 263,967
------------------- ------------------ --------------------- ----------------------
Income Taxes
Current (31,903) (31,088) (110,403) 53,088
Deferred 33,275 39,572 243,652 103,796
------------------- ------------------ --------------------- ----------------------
Total Income Taxes 1,372 8,484 133,249 156,884
------------------- ------------------ --------------------- ----------------------
Earnings (Loss) from Continuing Operations 4,964 (37,427) 248,767 176,269
------------------- ------------------ --------------------- ----------------------
Discontinued Operations
Income from operations, net of tax - 2,253 (3,356) 6,806
Loss on Disposal, net of tax of $13,050 - - (16,306) -
------------------- ------------------ --------------------- ----------------------
Earnings (Loss) from Discontinued Operations - 2,253 (19,662) 6,806
------------------- ------------------ --------------------- ----------------------
Net Income 4,964 (35,174) 229,105 183,075
Preferred stock dividend requirements 1,335 1,473 4,287 4,425
------------------- ------------------ --------------------- ----------------------
Earnings (Loss) Available for Common Stockholders $ 3,629 $ (36,647) $ 224,818 $ 178,650
=================== ================== ===================== ======================
Basic Earnings (Loss) Per Share:
Continuing Operations, less Preferred
Stock Requirements 0.03 (0.28) 1.74 1.25
Discontinued Operations 0.00 0.02 (0.14) 0.05
------------------- ------------------ --------------------- ----------------------
Basic Earnings (Loss) Per Share $ 0.03 $ (0.26) $ 1.60 $ 1.30
=================== ================== ===================== ======================
Diluted Earnings (Loss) Per Share:
Continuing Operations, less Preferred
Stock Requirements 0.02 (0.28) 1.72 1.23
Discontinued Operations 0.00 0.02 (0.14) 0.05
------------------- ------------------ --------------------- ----------------------
Diluted Earnings (Loss) Per Share $ 0.02 $ (0.26) $ 1.58 $ 1.28
=================== ================== ===================== ======================
Average Shares Outstanding (000)
Basic 141,686 138,693 140,929 137,856
Diluted 142,359 139,508 141,760 138,921
See accompanying Notes to the Consolidated Financial Statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
(In Thousands)
- ------------------------------------------------------------------------------------------------------------------------------------
Nine Months Nine Months
Ended Ended
September 30, 2002 September 30, 2001
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Earnings from continuing operations $ 248,767 $ 176,269
Adjustments to reconcile earnings from continuing
operations to net cash provided by (used in) operating
activities
Depreciation, depletion and amortization 380,758 388,679
Deferred income tax 60,495* 103,796
Income from equity investments (9,713) (9,249)
Dividends from equity investments 1,777 2,901
Gain from class action settlement - (33,510)
Provision for loss on contracting business - 63,682
Changes in assets and liabilities
Accounts receivable 239,569 630,820
Materials and supplies, fuel oil and gas in storage 5,939 (110,107)
Accounts payable and accrued expenses (147,188) (634,596)
Interest accrued 20,573 85,580
Other (16,139)* 13,202
-------------------------- -------------------------------
Net Cash Provided by Operating Activities 784,838 677,467
-------------------------- -------------------------------
Investing Activities
Capital expenditures (835,980) (668,494)
Proceeds from sale of assets 173,935 18,458
Other - (356)
-------------------------- -------------------------------
Net Cash Used in Investing Activities (662,045) (650,392)
-------------------------- -------------------------------
Financing Activities
Issuance of treasury stock 67,308 82,025
Issuance of long-term debt 515,774 721,474
Payment of long-term debt (99,845) (168,937)
Payment of commercial paper (519,222) (410,307)
Preferred stock dividends paid (4,287) (4,425)
Common stock dividends paid (187,857) (184,052)
Other 9 1,496
-------------------------- -------------------------------
Net Cash (Used in) Provided By Financing Activities (228,120) 37,274
-------------------------- -------------------------------
Net (Decrease) Increase in Cash and Cash Equivalents (105,327) 64,349
Cash and Cash Equivalents at Beginning of Period 159,252 83,329
-------------------------- -------------------------------
Cash and Cash Equivalents at End of Period $ 53,925 $ 147,678
========================== ===============================
Cash equivalents are short-term marketable securities purchased with maturities
of three months or less that were carried at cost which approximates fair value.
*Includes a non-cash reduction to current taxes payable of $183.2 million
resulting from the finalization of certain tax issues associated with the
KeySpan/Long Island Lighting Company merger.
See accompanying Notes to the Consolidated Financial Statements.
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. Under contractual arrangements, we provide power,
electric transmission and distribution services, billing and other customer
services for approximately one million electric customers of the Long Island
Power Authority ("LIPA"). Our other subsidiaries are involved in gas and oil
exploration and production; gas storage; wholesale and retail gas and electric
marketing; appliance service; plumbing; heating, ventilation and air
conditioning installation and services; large energy-system ownership,
installation and management; engineering and consulting services; and fiber
optic services. We also invest and participate in the development of, natural
gas pipelines, natural gas processing plants, electric generation, and other
energy-related projects, domestically and internationally. (See Note 2 "Business
Segments" for additional information on each operating segment.)
1. BASIS OF PRESENTATION
In our opinion, the accompanying unaudited Consolidated Financial Statements
contain all adjustments necessary to present fairly our financial position as of
September 30, 2002, and the results of operations for the three and nine months
ended September 30, 2002 and September 30, 2001, as well as cash flows for the
nine months ended September 30, 2002 and September 30, 2001. The accompanying
financial statements should be read in conjunction with the consolidated
financial statements and notes included in KeySpan's Annual Report on Form 10-K
for the year ended December 31, 2001, as amended, as well as KeySpan's Quarterly
Reports on Form 10-Q for the quarters ended June 30, 2002 and March 31, 2002.
The December 31, 2001 financial statement information has been derived from the
2001 audited financial statements. Income from interim periods may not be
indicative of future results.
Basic earnings per share ("EPS") is calculated by dividing earnings available
for common stock by the weighted average number of shares of common stock
outstanding during the period. No dilution for any potentially dilutive
securities is included. Diluted EPS assumes the conversion of all potentially
dilutive securities and is calculated by dividing earnings available for common
stock, as adjusted, by the sum of the weighted average number of shares of
common stock outstanding plus all potentially dilutive securities.
We have approximately 2.1 million common stock options outstanding at September
30, 2002 that were not included in the calculation of diluted EPS since the
exercise price associated with these options was greater than the average market
price of our common stock. Further, we have 90,770 shares of convertible
preferred stock outstanding that can be converted into 244,104 shares of common
stock. These shares were not in the calculation of diluted EPS for the three and
nine months ended September 30, 2002 and September 30, 2001, since to do so
would have been anti-dilutive.
Under the requirements of Statement of Financial Accounting Standards ("SFAS")
128, "Earnings Per Share", our basic and diluted EPS are as follows:
(In Thousands, Except Per Share)
- --------------------------------------------------------------- ---------------- ----------------- ---------------- ----------------
Three Months Three Months Nine Months Nine Months
Ended Ended Ended Ended
September 30, September 30, September 30, September 30,
2002 2001 2002 2001
- --------------------------------------------------------------- ---------------- ----------------- ---------------- ----------------
Earnings (Loss) from Continuing Operations $ 4 ,964 $ (37,427) $ 248,767 $ 176,269
Preferred stock dividends (1,335) (1,473) (4,287) (4,425)
Houston Exploration dilution (options) (96) (200) (321) (1,040)
- --------------------------------------------------------------- ---------------- ----------------- ---------------- ----------------
Earnings (Loss) from Continuing Operations
available to common stockholders - adjusted 3,533 (39,100) 244,159 170,804
- --------------------------------------------------------------- ---------------- ----------------- ---------------- ----------------
Weighted average shares outstanding (000) 141,686 138,693 140,929 137,856
Add dilutive securities:
Options 673 815 831 1,065
- --------------------------------------------------------------- ---------------- ----------------- ---------------- ----------------
Total weighted average shares outstanding - assuming dilution 142,359 139,508 141,760 138,921
- --------------------------------------------------------------- ---------------- ----------------- ---------------- ----------------
Basic Earnings (Loss) Per Share from Continuing Operations $ 0.03 $ (0.28) $ 1.74 $ 1.25
- --------------------------------------------------------------- ---------------- ----------------- ---------------- ----------------
Diluted Earnings (Loss) Per Share from Continuing Operations $ 0.02 $ (0.28) $ 1.72 $ 1.23
- --------------------------------------------------------------- ---------------- ----------------- ---------------- ----------------
2. BUSINESS SEGMENTS
We have four reportable segments: Gas Distribution, Electric Services, Energy
Services and Energy Investments.
The Gas Distribution segment consists of six regulated gas distribution
subsidiaries. KeySpan Energy Delivery New York ("KEDNY") provides gas
distribution services to customers in the New York City Boroughs of Brooklyn,
Queens and Staten Island. KeySpan Energy Delivery Long Island ("KEDLI") provides
gas distribution services to customers in the Long Island Counties of Nassau and
Suffolk and the Rockaway Peninsula of Queens County. The remaining gas
distribution subsidiaries, Boston Gas Company, Colonial Gas Company, Essex Gas
Company and EnergyNorth Natural Gas, Inc., collectively referred to as KeySpan
Energy Delivery New England ("KEDNE"), provide gas distribution service to
customers in Massachusetts and New Hampshire.
The Electric Services segment consists of subsidiaries that: operate the
electric transmission and distribution system owned by LIPA; own and provide
capacity to and produce energy for LIPA from our generating facilities located
on Long Island; and manage fuel supplies for LIPA to fuel our Long Island
generating facilities. These services are provided in accordance with long-term
service contracts having remaining terms that range from six to twelve years.
The Electric Services segment also includes subsidiaries that own, lease and
operate the 2,200 megawatt Ravenswood electric generation facility ("Ravenswood
facility"), located in Queens, New York.
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. Further, two 79 megawatt generating facilities located on Long Island
were placed in service in June and July 2002. The capacity of and energy from
these facilities are dedicated to LIPA under 25 year contracts.
The Energy Services segment includes companies that provide energy-related
services to customers located within the New York City metropolitan area
including New Jersey and Connecticut, as well as, Rhode Island, Pennsylvania,
Massachusetts and New Hampshire, through the following three lines of business:
(i) Home Energy Services, which provides residential customers with service and
maintenance of energy systems and appliances, as well as the retail marketing of
natural gas and electricity to residential and small commercial customers; (ii)
Business Solutions, which provides mechanical contracting, plumbing, engineering
and consulting services to commercial and industrial customers, including
installation of plumbing, heating, ventilation and air conditioning equipment;
and (iii) Fiber Optic Services, which provides various services to carriers of
voice and data transmission on Long Island and in New York City.
The Energy Investments segment consists of our gas exploration and production
investments, as well as certain other domestic and international energy-related
investments. Our gas exploration and production subsidiaries are engaged in gas
and oil exploration and production and the development and acquisition of
domestic natural gas and oil properties. These investments consist of our 67%
equity interest in The Houston Exploration Company ("Houston Exploration" -
NYSE: THX), 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.
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.
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 the segments are evaluated by
management on an earnings before interest and taxes ("EBIT") basis. At September
30, 2002, the total assets of each reportable segment have not changed
materially from December 31, 2001. To reflect a complete picture of the electric
operations, we reclassified, for all periods presented, KeySpan Energy Supply
from the Energy Services segment to the Electric Services segment. This
subsidiary provides management and procurement services for fuel supply and
management of energy sales, primarily for and from the Ravenswood facility. Due
to the July 2002 sale of Midland Enterprises LLC, an inland marine barge
business, this subsidiary is reported as discontinued operations in 2002 and
2001.
The reportable segment information, excluding Midland, is as follows:
(In Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------------------------------
Energy Investments
-------------------------------
Gas Electric Energy Gas Exploration Other
Distribution Services Services and Production Investments Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Three Months Ended
September 30, 2002
Unaffiliated Revenue 337,785 414,868 217,104 86,464 23,599 - 1,079,820
Intersegment Revenue - 25 - - 194 (219) -
Earnings Before Interest
and Taxes (38,878) 113,278 (4,455) 21,275 10,935 (15,882) 86,273
Three Months Ended
September 30, 2001
Unaffiliated Revenue 346,703 387,881 263,047 82,362 22,436 - 1,102,429
Intersegment Revenue - 25 - - - (25) -
Earnings Before Interest
and Taxes (31,009) 96,519 (69,594) 26,787 2,418 24,671 49,792
- ------------------------------------------------------------------------------------------------------------------------------------
Eliminating items include intercompany interest income and expense, the
elimination of certain intercompany accounts, as well as activities of our
corporate and administrative areas. Included in the three months ended September
30, 2001 is the favorable court decision regarding the class action settlement
recorded by our corporate holding company that increased EBIT by $22.0 million.
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 $414.9 million and $387.9 million for the three
months ended September 30, 2002 and 2001 represent approximately 38% and 35% of
our consolidated revenues, respectively.
(In Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------------------------------
Energy Investments
-------------------------------
Gas Electric Energy Gas Exploration Other
Distribution Services Services and Production Investments Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Nine months Ended
September 30, 2002
Unaffiliated Revenue 2,082,577 1,084,309 687,975 249,452 62,784 - 4,167,097
Intersegment Revenue - 75 - - 582 (657) -
Earnings Before Interest
and Taxes 320,016 243,651 (23,901) 60,542 17,089 (12,787) 604,610
Nine months Ended
September 30, 2001
Unaffiliated Revenue 2,721,032 1,089,156 814,911 318,093 73,627 - 5,016,819
Intersegment Revenue - 75 - - - (75) -
Earnings Before Interest
and Taxes 318,596 229,825 (133,013) 136,260 18,819 26,633 597,120
- ------------------------------------------------------------------------------------------------------------------------------------
Eliminating items include intercompany interest income and expense, the
elimination of certain intercompany accounts, as well as activities of our
corporate and administrative areas. Included in the nine months ended September
30, 2001, is the favorable court decision regarding the class action settlement
recorded by our corporate holding company that increased EBIT by $22.0 million.
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 $ 1.1 billion for the nine months ended
September 30, 2002 and 2001 represent approximately 26% and 22% of our
consolidated revenues, respectively.
3. COMPREHENSIVE INCOME
The table below indicates the components of comprehensive income.
(In Thousands)
- --------------------------------------------------------- ------------------ ----------------- ------------------ -----------------
Three Months Three Months Nine Months Nine Months
Ended Ended Ended Ended
September 30, September 30, September 30, September 30,
2002 2001 2002 2001
- --------------------------------------------------------- ------------------ ----------------- ------------------ -----------------
Earnings (loss) available for common stockholders $ 3,629 $ (36,647) $ 224,818 $ 178,650
- --------------------------------------------------------- ------------------ ----------------- ------------------ -----------------
Other comprehensive income (loss), net of tax
Reclassification adjustment for gains
realized in net income (7,529) (13,584) (17,814) (11,683)
Foreign currency translation adjustments (2,313) (179) 6,804 (8,307)
Unrealized losses on marketable securities (4,027) (2,672) (8,263) (5,032)
Accrued unfunded pension obligation - - (1,132) -
Unrealized (losses) gains on derivative financial
instruments (641) 39,004 (26,585) 54,936
- --------------------------------------------------------- ------------------ ----------------- ------------------ -----------------
Other comprehensive income (loss) (14,510) 22,569 (46,990) 29,914
- --------------------------------------------------------- ------------------ ----------------- ------------------ -----------------
Comprehensive income (loss) $ (10,881) $ (14,078) $ 177,828 $ 208,564
- --------------------------------------------------------- ------------------ ----------------- ------------------ -----------------
Related tax expense (benefit)
Reclassification adjustment for gains
realized in net income (4,054) (7,315) (9,592) (6,291)
Foreign currency translation adjustments (1,245) (97) 3,663 (4,473)
Unrealized losses on marketable securities (2,168) (1,439) (4,449) (2,709)
Accrued unfunded pension obligation - - (610) -
Unrealized (losses) gains on derivative financial
instruments (346) 21,003 (14,316) 29,581
- --------------------------------------------------------- ------------------ ----------------- ------------------ -----------------
Total tax expense (benefit) $ (7,813) $ 12,152 $ (25,304) $ 16,108
- --------------------------------------------------------- ------------------ ----------------- ------------------ -----------------
4. 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 us, were associated with our
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 $146.9 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 $44.4 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 $122.4 million for the New York/Long Island MGP sites is
reflected at September 30, 2002.
We are also responsible for environmental obligations associated with the
Ravenswood electric generating facility. The extent of our obligations does not
include liabilities arising from the disposal of waste at off-site locations
prior to the acquisition of the Ravenswood facility, or from Consolidated
Edison's pre-closing conduct. Based on information currently available, a
liability of $3.9 million has been accrued. Expenditures incurred to date with
respect to these environmental obligations total $1.1 million.
New England Sites. Within the Commonwealth of Massachusetts and the State of New
Hampshire, we are aware of 75 former MGP sites and related facilities within the
existing or former service territories of KEDNE or their predecessor companies.
Boston Gas Company, Colonial Gas Company and Essex Gas Company may have or share
responsibility under applicable environmental laws for the remediation of 65 MGP
sites and related facilities, and EnergyNorth Natural Gas may have or share
responsibility under applicable environmental laws for the remediation of 10 MGP
sites and related facilities.
We presently estimate the remaining cost of New England MGP-related
environmental cleanup activities will be $50.1 million, which amount has been
accrued as a reasonable estimate of probable cost for known sites. Expenditures
incurred since November 8, 2000 with respect to these MGP-related activities
total $13.3 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 $59.6
million for the KEDNE MGP sites is reflected at September 30, 2002. 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 historic operations of KeySpan New England, LLC, a successor
company to Eastern Enterprises for which we may have or share environmental
remediation responsibility or ongoing maintenance: the former Philadelphia Coke
site located in Pennsylvania; the former Connecticut Coke site located in New
Haven, Connecticut; and the former Everett Coal Tar Processing Facility (the
"Everett Facility") located in Massachusetts. Honeywell International, Inc. and
Beazer East, Inc. (both former owners and operators of the Everett Facility)
together with KeySpan have entered into an ACO with the Massachusetts Department
of Environmental Protection for the investigation and development of a remedial
response plan for the site.
We presently estimate the remaining cost of our environmental cleanup activities
for the three non-utility sites will be approximately $41.2 million, which
amount has been accrued as a reasonable estimate of probable costs for known
sites. Expenditures incurred since November 8, 2000, with respect to these sites
total $2.0 million. See Note 10 "Legal Matters" for further information on New
England environmental matters.
We believe that in the aggregate, the accrued liability for investigation and
remediation of sites and related facilities identified above are reasonable
estimates of likely cost within a range of reasonable, foreseeable costs. We may
be required to investigate and, if necessary, remediate each of these, or other
currently unknown former sites and related facility sites, the cost of which is
not presently determinable but may be material to our financial position,
results of operations or liquidity. Remediation costs for each site may be
materially higher than noted, depending upon remediation experience, selected
end use for each site, and actual environmental conditions encountered.
See KeySpan's Annual Report on Form 10-K for the year ended December 31, 2001
Note 8 to those Consolidated Financial Statements "Contractual Obligations and
Contingencies" for further information on environmental matters.
5. LONG-TERM DEBT
At December 31, 2001, KeySpan had an effective $1 billion shelf registration
statement on file with the Securities and Exchange Commission ("SEC"), with $500
million available for issuance. In February 2002, we updated the shelf
registration for the issuance of an additional $1.2 billion of securities,
thereby giving KeySpan the ability to issue up to $1.7 billion of debt, equity
or various forms of preferred stock. At December 31, 2001, we had authority
under PUHCA to issue up to $1 billion of this amount.
On April 30, 2002, we issued $460 million of MEDS Equity Units at 8.75%
consisting of a three-year forward purchase contract for our common stock and a
six-year note. The purchase contract commits us, three years from the date of
issuance of the MEDS Equity Units, to issue and the investors to purchase, a
number of shares of our common stock based on a formula tied to the market price
of our common stock at that time. The 8.75% coupon is composed of interest
payments on the six-year note of 4.9% and premium payments on the three-year
equity forward contract of 3.85%. These instruments have been recorded as
long-term debt on the Consolidated Balance Sheet. Further, upon issuance of the
MEDS Equity Units, we recorded a direct charge to Retained Earnings of $49.1
million, which represents the present value of the forward contract's premium
payments.
The issuance of the MEDS equity units utilized $920 million of KeySpan's
financing authority under both the shelf registration and the PUHCA financing
authority. Both the $460 million six-year note and the $460 million forward
equity contract are considered current issuances under these arrangements.
Therefore, we have $780 million available for issuance under the shelf
registration and $80 million available under PUHCA authorization. We have filed
a financing amendment with the SEC under PUHCA to increase the financing
authority by $700 million, thereby matching the shelf availability. We
anticipate a decision by the SEC on this application by year-end.
These securities are currently not considered convertible instruments for
purposes of applying SFAS 128 "Earnings Per Share" calculations, unless or until
such time as the market value of our common stock reaches a threshold
appreciation price ($42.36 per share) which is higher than the current per share
market value. Interest payments do, however, reduce net income and earnings per
share.
The Emerging Issues Task Force of the Financial Accounting Standards Board is
considering proposals related to accounting for certain securities and financial
instruments, including securities such as the Equity Units. The current
proposals being considered include the method of accounting discussed above.
Alternatively, other proposals being considered could result in the common
shares issuable pursuant to the purchase contract to be deemed outstanding and
included in the calculation of diluted earnings per share, and could result in
periodic "marking to market" of the purchase contracts, causing periodic charges
or credits to income. If this latter approach were adopted, our basic and
diluted earnings per share could increase and decrease from quarter to quarter
to reflect the lesser and greater number of shares issuable upon satisfaction of
the contract, as well as charges or credits to income.
In May 2002, Colonial Gas Company repaid $15 million of its 6.81% Series A First
Mortgage Medium -Term Notes. These Notes would have matured on May 19, 2027, but
the holder of the Notes elected to exercise a put option to redeem the Notes
early.
6. DERIVATIVE FINANCIAL INSTRUMENTS
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. Hedging
objectives and strategies have remained substantially unchanged from year-end.
Houston Exploration has utilized collars, as well as, over-the-counter ("OTC")
swaps to hedge the cash flow variability associated with forecasted sales of a
portion of its natural gas production. As of October 31, 2002, Houston
Exploration has hedged approximately 65% of its estimated 2002 and 2003
production. Further, Houston Exploration may enter into additional derivative
positions for 2003 and 2004. Houston Exploration used standard New York
Mercantile Exchange ("NYMEX") futures prices and published volatility in its
Black-Scholes calculation to value its outstanding derivatives. The maximum
length of time over which Houston Exploration has hedged such cash flow
variability is through December 2003. The estimated amount of losses associated
with such derivative instruments that are reported in Accumulated Other
Comprehensive Income and that are expected to be reclassified into earnings over
the next twelve months is $14.6 million.
KeySpan has also employed standard NYMEX gas futures contracts, as well as oil
swap derivative contracts, to hedge the cash flow variability of a portion of
forecasted purchases of natural gas and fuel oil that will be consumed at the
Ravenswood facility. Natural gas basis swaps are also utilized to hedge
forecasted purchases of natural gas transportation. The maximum length of time
over which we have hedged cash flow variability associated with: (i) forecasted
purchases of natural gas is October 2003; (ii) forecasted purchases of fuel oil
is through April 2004; and (iii) forecasted purchases of natural gas
transportation is through December 2003. 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 Accumulated
Other Comprehensive Income and that are expected to be reclassified into
earnings over the next twelve months is $4.1 million.
Our retail gas and electric marketing subsidiary, our domestic gas distribution
operations and KeSpan 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 2003. The
estimated amount of gains associated with such derivative instruments that are
reported in Accumulated Other Comprehensive Income and that are expected to be
reclassified into earnings over the next twelve months is $2.5 million.
We have also engaged in the use of cash-settled swap instruments to hedge the
cash flow variability associated with a portion of 2002 peak electric energy
sales from the Ravenswood facility. All hedge positions for the summer of 2002
have been settled. We currently have a number of remaining derivatives that are
employed to hedge cash flow variability through December 2002. We used
NYISO-location zone published indices to value these outstanding derivatives.
The estimated amount of gains associated with such derivative instruments that
are reported in Accumulated Other Comprehensive Income and that are expected to
be reclassified into earnings over the next twelve months is $2.4 million.
KeySpan Canada also has employed electricity swap contracts to lock-in the
purchase price of electricity needed to operate its gas processing plants. These
contracts are not exchange- traded and local published indices were used to
value these outstanding swap agreements. The maximum length of time over which
we have hedged such cash flow variability is through December 2003. The
estimated amount of losses associated with such derivative instruments that are
reported in Accumulated Other Comprehensive Income and that are expected to be
reclassified into earnings over the next twelve months is $1.7 million.
The following tables set forth selected financial data associated with these
derivative financial instruments noted above that were outstanding at September
30, 2002.
- -------------------------------- ------------ ------------- ------------ ------------- --------------- -------------- --------------
Year of Volumes Fixed Current Fair Value
Type of Contract Maturity mmcf Floor $ Ceiling $ Price $ Price $ ($000)
- -------------------------------- ------------ ------------- ------------ ------------- --------------- -------------- --------------
Gas
Collars 2002 14,720 3.56 5.14 - 3.69 - 4.32 (1,141)
2003 32,350 3.34 4.97 - 3.90 - 4.40 (2,498)
Swaps / Futures-Short
Natural Gas 2002 3,191 - - 3.01 3.69 - 4.32 (2,662)
2003 15,208 - - 3.19 3.90 - 4.40 (12,394)
Swaps / Futures - Long
Natural Gas 2002 2,990 - - 2.68 - 4.24 3.90 - 4.32 1,227
2003 8,210 - - 3.10 - 4.35 3.90 - 4.40 2,359
- -------------------------------- ------------ ------------- ------------ ------------- --------------- -------------- --------------
76,669 (15,109)
- -------------------------------- ------------ ------------- ------------ ------------- --------------- -------------- --------------
- ------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
Type of Contract Year of Volumes Fair Value
Maturity Barrels Fixed Price $ Current Price $ ($000)
- ------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
Oil
Swaps - Long Fuel Oil 2002 146,994 19.75 - 26.40 28.65 - 29.00 1,024
2003 307,822 20.10 - 26.72 23.01 - 28.96 1,613
2004 5,404 20.50 - 23.70 22.84 - 23.33 7
- ------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
460,220 2,644
- ------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
- -------------------------- ------------- ----------------- ----------------------- -------------- --------------- ------------------
Type of Contract Year of Current Estimated Fair Value
Maturity MWh Fixed Profit /Price $ Price $ Profit $ ($000)
- -------------------------- ------------- ----------------- ----------------------- -------------- --------------- ------------------
Electricity
Tolling Arrangements 2002 102,400 26.00 - 1.61 - 3.85 2,383
Swaps - Long 2002 17,664 56.07 - 57.33 30.87 - (429)
2003 70,080 56.07 - 57.33 29.61 - (1,791)
- -------------------------- ------------- ----------------- ----------------------- -------------- --------------- ------------------
190,144 163
- -------------------------- ------------- ----------------- ----------------------- -------------- --------------- ------------------
NYMEX futures are also used to economically hedge the cash flow variability
associated with the purchase of fuel for a portion of our fleet vehicles.
Further, KeySpan Canada has a portfolio of financially-settled natural gas
collars and natural gas liquid swap transactions. Such contracts are executed by
KeySpan Canada to: (i) synthetically fix the price that is paid or received by
KeySpan Canada for certain physical transactions involving natural gas and
natural gas liquids and (ii) transfer the price exposure of such instruments to
other trading partners. These derivative financial instruments do not qualify
for hedge accounting under SFAS 133. At September 30, 2002, these instruments
had a favorable net mark-to-market value of $0.4 million, which was recorded on
the Consolidated Balance Sheet and recorded to earnings for the quarter and nine
months ended September 30, 2002.
Non-firm Gas Sales Derivative Instruments: Utility tariffs applicable to certain
large-volume customers permit gas to be sold at prices established monthly
within a specified range expressed as a percentage of prevailing alternate fuel
oil prices. We use natural gas swap contracts, with offsetting positions in fuel
oil swap contracts of equivalent energy value, to hedge the cash-flow
variability of specified portions of gas purchases and sales. Currently, no
derivative transactions outstanding correspond to this particular price risk
strategy, although we intend to enter into derivative instruments of this nature
during the fourth quarter of 2002 if market conditions warrant.
Firm Gas Sales Derivative Instruments - Regulated Utilities: We also use
derivative financial instruments to reduce the cash flow variability associated
with the purchase price for a portion of future natural gas purchases. Our
strategy is to minimize fluctuations in firm gas sales prices to our regulated
firm gas sales customers in our New York and New Hampshire service territories.
Since these derivative instruments are employed to reduce the variability of the
purchase price of natural gas to be sold to regulated firm gas sales customers,
the accounting for these derivative instruments is subject to SFAS 71.
Therefore, changes in the market value of these derivatives have been recorded
as a Regulatory Asset or Regulatory Liability on the Consolidated Balance Sheet.
Gains or losses on the settlement of these contracts are initially deferred and
then refunded to or collected from our firm gas sales customers during the
appropriate winter heating season consistent with regulatory requirements.
The following table sets forth selected financial data associated with these
derivative financial instruments that were outstanding at September 30, 2002.
- ------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
Type of Contract Year of Volumes Fair Value
Maturity Mmcf Fixed Price $ Current Price $ ($000)
- ------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
Gas
Options 2002 7,980 3.85 - 4.50 4.23 1,549
2003 12,960 3.85 - 4.50 4.27 2,946
Swaps - Long 2002 300 4.11 4.24 42
2003 600 4.11 4.21 59
- ------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
21,840 4,596
- ------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
Other Commodity Derivative Instruments: On April 1, 2002 we implemented
Derivative Implementation Group (DIG) Issue C15 and C16 of Statement of
Financial Accounting Standard 133, "Accounting for Derivative Instruments and
Hedging Activities", as amended and interpreted, incorporating SFAS 137 and 138
and certain implementation issues (collectively "SFAS 133"). Issue C15
establishes new criteria that must be satisfied in order for option-type and
forward contracts in electricity to be exempted as normal purchases and sales,
while Issue C16 relates to the exemption (as normal purchases and normal sales)
of contracts that combine a forward contract and a purchased option contract.
Based upon a review of our physical commodity contracts, we determined that
certain contracts for the physical purchase of natural gas can no longer be
exempted as normal purchases from the requirements of SFAS 133. At September 30,
2002, the fair value of these contracts was $2.0 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: At September 30, 2002, we had interest
rate swap agreements in which approximately $1.3 billion of fixed rate debt had
been synthetically modified to floating rate debt. Under the terms of the
agreements, we received the fixed coupon rate associated with these bonds and
paid the counter-parties a variable interest rate that was reset on a quarterly
basis. These swaps were designated as fair-value hedges and qualified for
"short-cut" hedge accounting treatment under SFAS 133. Through the utilization
of these agreements, we reduced recorded interest expense by $30.5 million for
the nine months ended September 30, 2002.
In early November 2002, we terminated two interest rate swap agreements with an
aggregate notional amount of $1.0 billion and received $81.0 million from our
swap counter-parties, of which $23.0 million represents accrued swap interest.
The difference between the termination settlement amount and the amount of
accrued swap interest, $58.0 million, will be amortized to earnings (as an
adjustment to interest expense) on a level yield basis over the remaining lives
of the originally hedged debt obligations. The remaining swap, which has a
notional amount of $270.0 million, will continue to be accounted for as a fair
value hedge.
The table below summarizes selected financial data associated with these
derivative financial instruments that were outstanding at September 30, 2002.
The fair values of these derivative instruments were provided to us by our swap
counter-parties and represent the present value of expected future cash-flows
associated with such transactions.
- -------------------------------------- ------------------- --------------------- ---------------- -------------------- -------------
Average Variable
Maturity Date of Notional Amount Fixed Rate Rate Paid Fair Value
Bond Swaps ($000) Received Year to Date ($000)
- -------------------------------------- ------------------- --------------------- ---------------- -------------------- -------------
Medium Term Notes 2010 500,000 7.625% 4.250% 55,077
Medium Term Notes 2006 500,000 6.150% 3.590% 37,145
Long Term Notes 2023 270,000 8.200% 3.770% 6,843
- -------------------------------------- ------------------- --------------------- ---------------- -------------------- -------------
1,270,000 99,065
- -------------------------------------- ------------------- --------------------- ---------------- -------------------- -------------
Additionally, we also have an interest rate swap agreement that hedges the cash
flow variability associated with the forecasted issuance of a series of
commercial paper offerings. The maximum length of time over which we have hedged
such cash flow variability is through March 2003. The estimated amount of gains
or losses associated with such derivative instruments that are reported in
Accumulated Other Comprehensive Income and that are expected to be reclassified
into earnings over the next twelve months is a loss of $1.6 million.
Weather Derivatives: The utility tariffs associated with the New England gas
distribution operations do not contain a weather normalization adjustment. As a
result, fluctuations from normal weather may have a significant positive or
negative effect on the results of these operations. To mitigate the effect of
fluctuations from normal weather on our financial position and cash flows, we
entered into weather collars during the quarter ended September 30, 2002. These
derivatives will hedge approximately 60% of expected gas throughput of the New
England gas distribution companies during the November 2002 - March 2003 winter
season. The collars have been established with a ceiling that reflects 1% colder
than normal weather and a floor that reflects 7% warmer than normal weather.
KeySpan will be required to make payment to its counter-parties when actual
weather experienced during the November 2002 - March 2003 time frame is 1% or
more colder than normal, based on the 1975 - 1995 20 year average. In the event
that actual weather is 7% or more warmer than normal the counter-parties will be
required to make payment to KeySpan. These derivatives will be accounted for by
applying the "intrinsic value method" and are outside the scope of SFAS 133.
Derivative contracts are primarily used to manage exposure to market risk
arising from changes in commodity prices and interest rates. In the event of
nonperformance by a counter-party to a derivative contract, the desired impact
may not be achieved. The risk of a counter-party nonperformance is generally
considered credit risk and is actively managed by assessing each counter-party
credit profile and negotiating appropriate levels of collateral and credit
support. Currently the majority of KeySpan's derivative contracts are with
investment grade companies.
7. WORKFORCE REDUCTION PROGRAMS
As a result of the Eastern acquisition, we implemented early retirement and
severance programs in an effort to reduce our workforce. In 2000, we recorded a
$22.7 million liability associated with these programs. This severance program
is targeted to reduce the workforce by 500 employees and will continue through
2002. In 2001, we reduced this liability by $4.1 million as a result of lower
than anticipated costs per employee. As of September 30, 2002, we had paid $11.9
million for these programs and had a remaining liability of $6.7 million.
8. RECENT ACCOUNTING PRONOUNCEMENTS
On January 1, 2002, we adopted SFAS 141, "Business Combinations", and SFAS 142
"Goodwill and Other Intangible Assets". The key concepts from the two
interrelated Statements include mandatory use of the purchase method when
accounting for business combinations, discontinuance of goodwill amortization, a
revised framework for testing goodwill impairment at a "reporting unit" level,
and new criteria for the identification and potential amortization of other
intangible assets. Other changes to existing accounting standards involve the
amount of goodwill to be used in determining the gain or loss on the disposal of
assets, and a requirement to test goodwill for impairment at least annually. The
annual impairment test was to be performed within six months of adopting SFAS
142 with any resulting impairment reflected as either a change in accounting
principle, or a charge to operations in the financial statements. During the
second quarter of 2002, we completed our analysis for all of the reporting units
and determined that no consolidated impairment exists. Consistent with the
requirements of SFAS 142, we will annually test our goodwill for impairment in
the fourth quarter, absent the occurrence of any event that would cause us to
perform a test in the interim.
For the three and nine months ended September 30, 2001 respectively, goodwill
amortization was recorded in each segment as follows: Gas Distribution $8.9 and
$26.6 million; Energy Services $1.8 and $5.8 million; and Energy Investments and
other $1.4 and $4.5 million. As required by SFAS 142, below is a reconciliation
of reported earnings available for common stockholders for the three and nine
months ended September 30, 2001 and pro-forma net income, for the same period,
adjusted for the discontinuance of goodwill amortization.
(In Thousands)
- ------------------------------------------------------- ----------------- ------------------ ----------------- ------------------
Three Months Three Months Nine Months Nine Months
Ended Ended Ended Ended
September 30, September 30, September 30, September 30,
2002 2001 2002 2001
- ------------------------------------------------------- ----------------- ------------------ ----------------- ------------------
Earnings (loss) available for common stockholders $ 3,629 $ (36,647) $ 224,818 $ 178,650
Add back: goodwill amortization - 12,015 - 36,879
- ------------------------------------------------------- ----------------- ------------------ ----------------- ------------------
Adjusted net income 3,629 (24,632) 224,818 215,529
- ------------------------------------------------------- ----------------- ------------------ ----------------- ------------------
Basic earnings (loss) per share 0.03 (0.26) 1.60 1.30
Add back: goodwill amortization - 0.09 - 0.27
- ------------------------------------------------------- ----------------- ------------------ ----------------- ------------------
Adjusted basic earnings per share $ 0.03 $ (0.17) $ 1.60 $ 1.57
- ------------------------------------------------------- ----------------- ------------------ ----------------- ------------------
Diluted earnings (loss) per share 0.02 (0.26) 1.58 1.28
Add back: goodwill amortization - 0.09 - 0.27
- ------------------------------------------------------- ----------------- ------------------ ----------------- ------------------
Adjusted diluted earnings per share $ 0.02 $ (0.17) $ 1.58 $ 1.55
- ------------------------------------------------------- ----------------- ------------------ ----------------- ------------------
In July of 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement
Obligations". The Standard requires entities to record the fair value of a
liability for an asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity will capitalize a
cost by increasing the carrying amount of the related long-lived asset.
Over time, the liability is accreted to its then present value, and the
capitalized cost is depreciated over the useful life of the related asset. Upon
settlement of the liability, an entity either settles the obligation for its
recorded amount or incurs a gain or loss upon settlement. The standard is
effective for fiscal years beginning after June 15, 2002, with earlier
application encouraged. We are currently evaluating the impact, if any, that
this statement may have on our results of operations and financial position.
SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", was
effective January 1, 2002, and addresses accounting and reporting for the
impairment or disposal of long-lived assets. SFAS 144 supersedes SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of" and APB Opinion No. 30, "Reporting the Results of
Operations-Reporting the Effects of Disposal of a Segment of a Business". SFAS
144 retains the fundamental provisions of SFAS No. 121 and expands the reporting
of discontinued operations to include all components of an entity with
operations that can be distinguished from the rest of the entity and that will
be eliminated from the ongoing operations of the entity in a disposal
transaction. As of September 30, 2002, implementation of this Statement did not
have a significant effect on our results of operations and financial position.
In June of 2002, the FASB issued SFAS 146, "Accounting for Costs Associated with
Exit or Disposal Activities". This Statement addresses financial accounting and
reporting for costs associated with exit or disposal activities and nullifies
Emerging Issues Task Force Issue No.94-3, "Liability recognition for Certain
Employee Termination benefits and Other Costs to Exit an Activity". This
Statement is effective for exit or disposal activities initiated after December
31, 2002 with early application encouraged.
9. DISCONTINUED OPERATIONS
On November 8, 2000, KeySpan acquired Midland Enterprises LLC ("Midland"), an
inland marine transportation subsidiary, as part of the Eastern acquisition. In
its order issued under PUHCA approving the acquisition, the SEC required KeySpan
to sell this subsidiary by November 8, 2003 because its operations were not
functionally related to KeySpan's core utility operations. On July 2, 2002, the
sale of Midland to Ingram Industries Inc. was completed and net proceeds of
$173.9 million were received from the sale.
Discontinued operations for the year ended December 31, 2001 included an
anticipated after-tax loss on disposal of $30.4 million. As a result of a change
in the tax structuring strategy related to the sale of Midland, in the second
quarter of 2002, we recorded an additional provision for city and state taxes
and made adjustments to the estimations used in the December 31, 2001 loss
provision. These changes resulted in an additional after tax loss on disposal of
$19.7 million.
The following is selected financial information for Midland for the three and
nine months ended September 30, 2002 and September 30, 2001:
(In Thousands)
- --------------------------------------------- --- ----------------- --- ---------------- --- ----------------- --- ---------------
Three Months Three Months Nine Months Nine Months
Ended Ended Ended Ended
September 30, September 30, September 30, September 30,
2002 2001 2002 2001
- --------------------------------------------- --- ----------------- --- ---------------- --- ----------------- --- ---------------
Revenues $ - $ 67,342 $ 116,149 $ 202,705
Pretax income (loss) - 3,868 (4,624) 11,727
Income tax (expense) benefit - (1,615) 1,268 (4,921)
- --------------------------------------------- --- ----------------- --- ---------------- --- ----------------- --- ---------------
Income (loss) from discontinued operations - 2,253 (3,356) 6,806
- --------------------------------------------- --- ----------------- --- ---------------- --- ----------------- --- ---------------
Loss on disposal - - (16,306) -
- --------------------------------------------- --- ----------------- --- ---------------- --- ----------------- --- ---------------
Loss from discontinued operations $ - $ 2,253 $ (19,662) $ 6,806
- --------------------------------------------- --- ----------------- --- ---------------- --- ----------------- --- ---------------
Assets and liabilities of the discontinued operations are as follows:
(In Thousands)
-------------------------------------------- -- ------------------------ --- -----------------------
September 30, 2002 December 31, 2001
----------------------------------------------------------------------------------------------------
Current assets $ - $ 139,522
Property, plant and equipment, net - 316,626
Long-term assets - 35,233
Current liabilities - (58,835)
Long-term liabilities - (241,491)
-------------------------------------------- -- ------------------------ --- -----------------------
Net assets held for disposal $ - $ 191,055
-------------------------------------------- -- ------------------------ --- -----------------------
10. LEGAL MATTERS
KeySpan has been cooperating in preliminary inquiries regarding trading in
KeySpan Corporation stock by individual officers of KeySpan prior to the July
17, 2001 announcement that KeySpan was taking a special charge in its Energy
Services business and otherwise reducing its 2001 earnings forecast. These
inquiries are being conducted by the U.S. Attorney's Office, Southern District
of New York, and the SEC.
As previously reported, as part of its continuing inquiry, on March 5, 2002, the
SEC issued a formal order of investigation, pursuant to which it will review the
trading activity of certain company insiders from May 1, 2001 to the present, as
well as KeySpan's compliance with its reporting rules and regulations, generally
during the period following the acquisition of the Roy Kay companies through the
July 17th announcement.
Furthermore, KeySpan and certain of its officers and directors are defendants in
a number of class action lawsuits filed in the United States District Court for
the Eastern District of New York after the July 17th announcement. These
lawsuits allege, among other things, violations of Sections 10(b) and 20(a) of
the Securities Exchange Act of 1934, as amended ("Exchange Act"), in connection
with disclosures relating to or following the acquisition of the Roy Kay
companies by KeySpan Services, Inc., a KeySpan subsidiary. Finally, in October
2001, a shareholder's derivative action was commenced in the same court against
certain officers and directors of KeySpan, alleging, among other things,
breaches of fiduciary duty, violations of the New York Business Corporation Law
and violations of Section 20(a) of the Exchange Act. In addition, a second
derivative action has been commenced asserting similar allegations. Each of the
proceedings seek monetary damages in an unspecified amount. On November 1, 2002,
we filed a motion to dismiss the class action lawsuits. We are unable to
determine the outcome of these proceedings and what effect, if any, such outcome
will have on our financial condition, results of operations or cash flows.
On June 14, 2002, a complaint was filed by Donna Gay, et al. against KeySpan
Corporation in the United States District Court for the District of
Massachusetts. The complaint alleges liabilities stemming from alleged
environmental contaminants at the Oxbow Site in Everett, Massachusetts. On June
26, 2002, a complaint was filed by Beazer East, Inc. in the United States
District Court for the Eastern District of New York, seeking both contribution
from KeySpan for costs and declaratory relief as to the respective former and
future liabilities associated with responding to the actual or threatened
release of hazardous substances into the environment and the Everett site. At
the present time, KeySpan is unable to determine the outcome of these
proceedings, but does not believe that such outcome, if adverse, will have a
material effect on its financial condition or results of operation.
In June 2002, Hawkeye Electric, LLC et al. ("Hawkeye") commenced an action in
New York State Supreme Court, Suffolk County against KeySpan and certain of its
subsidiaries alleging, among other things, that KeySpan and its subsidiaries
breached certain contractual obligations to Hawkeye with respect to the
provision of certain gas, electric and telecommunications construction services
offered by Hawkeye. Hawkeye is seeking damages in excess of $90 million and
KeySpan has alleged a number of counterclaims seeking damages in excess of $4
million. At this time, we are unable to determine the outcome of this proceeding
and what effect, if any, such outcome will have on our financial position,
results of operation or cash flow.
KeySpan subsidiaries, along with several other parties, have been named as
defendants in numerous proceedings filed by plaintiffs claiming various degrees
of injury from asbestos exposure. Most of these proceedings have been commenced
in the New York State Supreme Court for New York County by contractor employees
allegedly as a result of exposure to asbestos in connection with the
construction and maintenance of our electric generating facilities. At the
present time, KeySpan is unable to determine the outcome of these proceedings,
but does not believe that such outcome, if adverse, will have a material effect
on its financial condition or results of operation.
11. KEYSPAN GAS EAST CORPORATION SUMMARY FINANCIAL INFORMATION
KEDLI, a wholly owned subsidiary of KeySpan, established a program for the
issuance, from time to time, of up to $600 million aggregate principal amount of
medium term notes, which are unconditionally guaranteed by us. On February 1,
2000, KEDLI issued $400 million of 7.875% medium term notes due 2010. In January
2001, KEDLI issued an additional $125 million of medium term notes at 6.9% due
January 15, 2008. The following condensed financial statements are required to
be disclosed by SEC regulations and are those of KEDLI and KeySpan as guarantor
of the medium term notes.
Statement of Income
(In Thousands)
- ---------------------------------------------------------------------------------- -------------------------------------------------
Three Months Ended September 30, 2002 Three Months Ended September 30, 2001
- ------------------------------------------------------------------------------------------------------------------------------------
Guarantor KEDLI Eliminations Consolidated Guarantor KEDLI Eliminations Consolidated
Revenues $ 1,000,103 $ 79,717 $ - $ 1,079,820 $ 1,019,848 $ 82,581 $ - $ 1,102,429
Operating Expenses
Purchased Gas 102,658 35,949 - 138,607 117,511 31,382 - 148,893
Fuel and purchased power 139,538 - - 139,538 164,555 - - 164,555
Operations and maintenance 472,710 12,447 - 485,157 498,528 8,585 - 507,113
Intercompany expense (19,007) 19,007 - - (18,998) 18,998 - -
Depreciation and
amortization 115,351 11,950 - 127,301 125,504 10,433 - 135,937
Operating Taxes 78,764 17,534 - 96,298 76,556 18,353 - 94,909
------------ ------------ ------------- ------------- ------------- ----------- ------------- ------------
Total Operating Expenses 890,014 96,887 - 986,901 963,656 87,751 - 1,051,407
------------ ------------ ------------- ------------- ------------- ----------- ------------- ------------
Operating Income 110,089 (17,170) - 92,919 56,192 (5,170) - 51,022
Other Income and
(Deductions) (3,373) 1,769 (5,042) (6,646) 10 3,400 (4,640) (1,230)
------------ ------------ ------------- ------------- ------------- ----------- ------------- ------------
Income Before Interest
Charges and Income Taxes 106,716 (15,401) (5,042) 86,273 56,202 (1,770) (4,640) 49,792
Interest Expense 69,906 15,073 (5,042) 79,937 68,704 14,671 (4,640) 78,735
Income Taxes 12,945 (11,573) - 1,372 14,938 (6,454) - 8,484
------------ ------------ ------------- ------------- ------------- ----------- ------------- ------------
Earnings (Loss) From
Continuing Operations $ 23,865 $ (18,901) $ - $ 4,964 $ (27,440) $ (9,987) $ - $ (37,427)
============ ============ ============= ============= ============= =========== ============= ============
Statement of Income
(In Thousands)
- ------------------------------------------------------------------------------------------------------------------------------------
Nine months Ended September 30, 2002 Nine months Ended September 30, 2001
- ------------------------------------------------------------------------------------------------------------------------------------
Guarantor KEDLI Eliminations Consolidated Guarantor KEDLI Eliminations Consolidated
Revenues $ 3,630,496 $ 536,601 $ - $ 4,167,097 $ 4,365,604 $ 651,215 $ - $5,016,819
Operating Expenses
Purchased Gas 796,518 241,389 - 1,037,907 1,330,410 364,181 - 1,694,591
Fuel and purchased power 317,253 - - 317,253 454,212 - - 454,212
Operations and maintenance 1,493,880 37,514 - 1,531,394 1,504,442 40,357 - 1,544,799
Intercompany expense (57,250) 57,250 - - (64,198) 64,198 - -
Depreciation and
amortization 333,228 47,530 - 380,758 364,177 24,502 - 388,679
Operating Taxes 241,848 62,228 - 304,076 269,775 67,959 - 337,734
------------ ----------- ------------ -------------- ------------- ------------- ------------- -----------
Total Operating Expenses 3,125,477 445,911 - 3,571,388 3,858,818 561,197 - 4,420,015
------------ ----------- ------------ -------------- ------------- ------------- ------------- -----------
Operating Income 505,019 90,690 - 595,709 506,786 90,018 - 596,804
Other Income and
(Deductions) 18,122 6,860 (16,081) 8,901 5,711 9,979 (15,374) 316
------------ ----------- ------------ -------------- ------------- ------------- ------------- -----------
Income Before Interest
Charges and Income Taxes 523,141 97,550 (16,081) 604,610 512,497 99,997 (15,374) 597,120
Interest Expense 192,500 46,175 (16,081) 222,594 234,233 45,108 (15,374) 263,967
Income Taxes 110,466 22,783 - 133,249 139,094 17,790 - 156,884
------------ ----------- ------------ -------------- ------------- ------------- ------------- -----------
Earnings (Loss) from
Continuing Operations $ 220,175 $ 28,592 $ - $ 248,767 $ 139,170 $ 37,099 $ - $ 176,269
============ =========== ============ ============== ============= ============= ============= ===========
Balance Sheet (In Thousands)
- ------------------------------------------------------------------------------------------------------------------------------------
September 30, 2002 December 31, 2001
- ------------------------------------------------------------------------------------------------------------------------------------
ASSETS Guarantor KEDLI Eliminations Consolidated Guarantor KEDLI Eliminations Consolidated
Current Assets
Cash and temporary cash
investments $ 53,925 $ - $ - $ 53,925 $ 159,252 $ - $ - $ 159,252
Accounts Receivable, net 1,198,151 131,409 (296,530) 1,033,030 1,540,082 233,013 (500,496) 1,272,599
Other current assets 495,270 126,533 - 621,803 454,319 112,317 - 566,636
--------------------------------------------------- --------------------------------------------------
1,747,346 257,942 (296,530) 1,708,758 2,153,653 345,330 (500,496) 1,998,487
--------------------------------------------------- --------------------------------------------------
Assets Held for Disposal - - - - 191,055 - - 191,055
Equity Investments 770,486 - (532,862) 237,624 756,111 - (532,862) 223,249
--------------------------------------------------- --------------------------------------------------
Property
Gas 4,250,404 1,727,265 - 5,977,669 4,074,894 1,629,963 - 5,704,857
Other 4,674,349 - - 4,674,349 4,231,262 - - 4,231,262
Accumulated depreciation
and depletion (3,285,338) (314,145) - (3,599,483) (3,035,788) (294,400) - (3,330,188)
--------------------------------------------------- --------------------------------------------------
5,639,415 1,413,120 - 7,052,535 5,270,368 1,335,563 - 6,605,931
--------------------------------------------------- --------------------------------------------------
Deferred Charges 2,693,952 188,604 - 2,882,556 2,571,029 199,855 - 2,770,884
--------------------------------------------------- --------------------------------------------------
Total Assets $ 10,851,199 $1,859,666 $ (829,392) $11,881,473 $10,942,216 $1,880,748 $(1,033,358) $11,789,606
=================================================== ==================================================
LIABILITIES
AND CAPITALIZATION
Current Liabilities
Accounts Payable
and accrued expenses $ 805,704 $ 45,729 $ - $ 851,433 975,873 $ 115,557 $ - $ 1,091,430
Commercial Paper 529,228 - - 529,228 1,048,450 - - 1,048,450
Other current
liabilities 182,690 76,723 - 259,413 220,985 23,844 - 244,829
-------------------------------------------------- --------------------------------------------------
1,517,622 122,452 - 1,640,074 2,245,308 139,401 - 2,384,709
-------------------------------------------------- --------------------------------------------------
Intercompany
Accounts Payable - 120,626 (120,626) - - 324,592 (324,592) -
-------------------------------------------------- --------------------------------------------------
Deferred Credits
and Other Liabilities
Deferred Income Tax 664,859 179,097 - 843,956 593,300 4,772 - 598,072
Other deferred credits
and liabilities 850,028 97,368 - 947,396 841,662 100,452 - 942,114
-------------------------------------------------- --------------------------------------------------
1,514,887 276,465 - 1,791,352 1,434,962 105,224 - 1,540,186
-------------------------------------------------- --------------------------------------------------
Capitalization
Common shareholders'
equity 2,791,407 639,219 (532,862) 2,897,764 2,812,837 610,627 (532,862) 2,890,602
Preferred stock 83,849 - - 83,849 84,077 - - 84,077
Long-term debt 4,735,109 700,904 (175,904) 5,260,109 4,172,649 700,904 (175,904) 4,697,649
-------------------------------------------------- --------------------------------------------------
Total Capitalization 7,610,365 1,340,123 (708,766) 8,241,722 7,069,563 1,311,531 (708,766) 7,672,328
-------------------------------------------------- --------------------------------------------------
Minority Interest
in Subsidiary Companies 208,325 - - 208,325 192,383 - - 192,383
-------------------------------------------------- --------------------------------------------------
Total Liabilities
and Capitalization $10,851,199 $1,859,666 $ (829,392) $11,881,473 $10,942,216 $1,880,748 $(1,033,358) $ 11,789,606
================================================== ==================================================
Statement of Cash Flows (In Thousands)
- ------------------------------------------------------------------------------------ -----------------------------------------------
Nine Months Ended September 30, 2002 Nine Months Ended September 30, 2001
- ------------------------------------------------------------------------------------ -----------------------------------------------
Guarantor KEDLI Consolidated Guarantor KEDLI Consolidated
- ----------------------------------------------- ----------------- ------------------ ---------------- ---------------- -------------
Operating Activities
Net Cash Provided by
Operating Activities $ 492,665 $ 292,173 $ 784,838 $ 614,227 $ 63,240 $ 677,467
---------------- ----------------- ------------------ ---------------- ---------------- -------------
Investing Activities
Capital expenditures (734,136) (101,844) (835,980) (590,104) (78,390) (668,494)
Sale of Assets 173,935 - 173,935 18,458 - 18,458
Other - - - (356) - (356)
---------------- ----------------- ------------------ ---------------- ---------------- -------------
Net Cash Used in
Investing Activities (560,201) (101,844) (662,045) (572,002) (78,390) (650,392)
---------------- ----------------- ------------------ ---------------- ---------------- -------------
Financing Activities
Issuance of Treasury Stock 67,308 - 67,308 82,025 - 82,025
Issuance of long-term debt 515,774 - 515,774 596,474 125,000 721,474
Payment of long-term debt (99,845) - (99,845) (168,937) - (168,937)
Payment of commercial paper (519,222) - (519,222) (410,307) - (410,307)
Preferred stock dividends paid (4,287) - (4,287) (4,425) - (4,425)
Common stock dividends paid (187,857) - (187,857) (184,052) - (184,052)
Net intercompany accounts
payable 190,329 (190,329) - 109,850 (109,850) -
Other 9 - 9 1,496 - 1,496
---------------- ----------------- ------------------ ---------------- ---------------- -------------
Net Cash Provided by
(Used in) Financing
Activities $ (37,791) $ (190,329) $ (228,120) $ 22,124 $ 15,150 $ 37,274
---------------- ----------------- ------------------ ---------------- ---------------- -------------
Net Increase in Cash and
Cash Equivalents $ (105,327) $ - $ (105,327) $ 64,349 $ - $ 64,349
================ ================= ================== ================ ================ =============
Cash and Cash Equivalents at
Beginning of Period $ 159,252 $ - $ 159,252 $ 83,329 $ - $ 83,329
---------------- ----------------- ------------------ ---------------- ---------------- -------------
Cash and Cash Equivalents at
End of Period $ 53,925 $ - $ 53,925 $ 147,678 $ - $ 147,678
================ ================= ================== ================ ================ =============
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Consolidated Review of Results
- ------------------------------
The following is a summary of transactions affecting comparative earnings and a
discussion of material changes in revenues and expenses during the three and
nine months ended September 30, 2002, compared to the three and nine months
ended September 30, 2001. Capitalized terms used in the following discussion,
but not otherwise defined, have the same meaning as when used in the Notes to
the Consolidated Financial Statements included under Item 1. References to
"KeySpan", "we", "us", and "our" mean KeySpan Corporation, together with its
consolidated subsidiaries.
Consolidated earnings from continuing operations for the three months ended
September 30, 2002 were $5.0 million compared to a loss of $37.4 million for the
same period last year. Consolidated earnings from continuing operations for the
nine months ended September 30, 2002 were $248.8 million compared to $176.3
million for the corresponding period last year. Earnings available for common
stock, which includes preferred stock dividends, as well as discontinued
operations as discussed below, were $3.6 million, or $0.03 per share for the
three months ended September 30, 2002 compared to a loss of $36.6 million, or
$0.26 per share for the same quarter last year. Earnings available for common
stock for the nine months ended September 30, 2002 were $224.8 million, or $1.60
per share compared to $178.7 million, or $1.30 per share for the same period
last year. Diluted earnings per share were $0.02 and $1.58 for the three and
nine months ended September 30, 2002, respectively. Diluted earnings per share
were $1.28 for the nine months ended September 30, 2001. Basic and diluted
earnings per share were the same for the three months ended September 30, 2001.
Average common shares outstanding for the nine months ended September 30, 2002
increased by 2.2% compared to the same period last year reflecting the
re-issuance of shares held in treasury pursuant to dividend reinvestment and
employee benefit plans. This increase in average common shares outstanding
reduced earnings per share for the nine months ended September 30, 2002, by
$0.03 compared to the corresponding period in 2001.
On January 24, 2002, we announced that we had entered into an agreement to sell
Midland Enterprises LLC ("Midland"), KeySpan's inland marine barge business. In
anticipation of this divestiture, which closed on July 2, 2002, Midland's
operations have been reported as discontinued for 2002 and 2001. (See KeySpan's
Annual Report on Form 10K for the year ended December 31, 2001 Item 7
"Management's Discussion and Analysis of Financial Conditions and Results of
Operations", as well as Note 10 to those Consolidated Financial Statements
"Discontinued Operations".) In the fourth quarter of 2001, an estimated loss on
the sale of Midland, as well as an estimate for Midland's results of operations
for the first six months of 2002 was recorded. During the second quarter of
2002, an additional after-tax loss of $19.7 million was recorded, primarily
reflecting a provision for certain city and state taxes that resulted from a
change in the tax structuring strategy for this transaction. (See Note 9 to the
Consolidated Financial Statements "Discontinued Operations" for further
disclosures on the sale of Midland.)
As discussed in more detail below, results from operations for the quarter and
nine months ended September 30, 2002 compared to the comparable periods last
year were principally impacted by the following factors: (i) losses incurred in
2001 by one of our unregulated subsidiaries; (ii) a reversal, in 2001, of a
previously recorded loss provision relating to a class action settlement; (iii)
the discontinuation of goodwill amortization in 2002; (iv) a significant
decrease in interest expense; and (v) a significant decrease in natural gas
prices, which reduced comparative earnings associated with gas exploration and
production operations.
In 2001, we discontinued the general contracting activities related to the
former Roy Kay companies, with the exception of work to be completed on existing
contracts, based upon our view that the general contracting business was not a
core competency of these companies. Losses incurred by the former Roy Kay
companies for the three and nine months ended September 30, 2001 were $56.6
million after-tax, or $0.41 per share and $92.2 million after-tax, or $0.67 per
share, respectively. (See KeySpan's Annual Report on Form 10K for the year ended
December 31, 2001 Item 7 "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and Note 11 to those Consolidated Financial
Statements "Roy Kay Operations" for a more detailed discussion.) We are in the
process of completing the contracts entered into by the former Roy Kay companies
and, for the three and nine months ended September 30, 2002, we incurred
after-tax losses of $3.6 million and $6.4 million, respectively, reflecting
increases in the estimates of and costs to complete these contracts and general
and administrative expenses.
Included in results of operations for the three and nine months ended September
30, 2001, is the reversal of a previously recorded loss provision regarding
certain rate refund issues relating to the 1989 RICO class action settlement.
This adjustment was due to the favorable United States Court of Appeals ruling
received in September 2001 and resulted in a positive after-tax adjustment to
earnings of $20.1 million, or $0.15 per share. This adjustment, which was
recorded at our holding company level, has been reflected as a $22.0 million
reduction to Operations and Maintenance expense and a reduction of $11.5 million
to Interest expense on the September 30, 2001 Consolidated Statement of Income.
(See KeySpan's Annual Report on Form 10K for the year ended December 31, 2001
Item 7 "Management's Discussion and Analysis of Financial Condition and Results
of Operations" and Note 12 to those Consolidated Financial Statements "Class
Action Settlement" for a more detailed discussion.)
In January 2002, we adopted Statement of Financial Accounting Standard ("SFAS")
142 "Goodwill and Other Intangible Assets". The key requirements of this
Statement include the discontinuance of goodwill amortization, a revised
framework for testing goodwill impairment and new criteria for the
identification of intangible assets. Consolidated goodwill amortization for the
three and nine months ended September 30, 2001 was $12.0 million, or $0.09 per
share, and $36.9 million, or $0.27 per share, respectively.
Interest expense, excluding the $11.5 million adjustment recorded in September
2001 for the RICO class action settlement previously mentioned, decreased by
$10.3 million ($6.7 million after-tax), or $0.05 per share and $52.9 million
($34.4 million after-tax) or $0.24 per share, for the three and nine months
ended September 30, 2002, respectively. The weighted average interest rate on
outstanding commercial paper during the nine months ended September 30, 2002 was
approximately 2.05% compared to approximately 5.20% for the corresponding period
last year. Further, KeySpan had a number of interest rate swap agreements which
effectively converted fixed rate debt to floating rate debt. The use of these
derivative instruments reduced interest expense by $30.5 million during the nine
months ended September 30, 2002. (See Note 6 to the Consolidated Financial
Statements "Derivative Financial Instruments" for a description of these
instruments.)
For the three and nine months ended September 30, 2002, net income from gas
exploration and production operations decreased by $4.2 million, or $0.03 per
share and by $43.1 million, or $0.32 per share, respectively compared to the
corresponding periods last year. The gas exploration and production subsidiaries
were adversely impacted by significantly lower realized gas prices during the
nine months ended September 30, 2002 compared to the same period in 2001.
Income tax expense generally reflects the level of pre-tax income for all
periods reported. Income tax expense also reflects tax benefits of $11.9 million
recognized during the nine months ended September 30, 2002, resulting from the
favorable resolution of certain outstanding tax issues related to the KeySpan /
Long Island Lighting Company ("LILCO") merger completed in May 1998. For the
three and nine months ended September 30, 2002, income tax expense also reflects
the beneficial effect of a change in federal income tax regulation. Beginning in
2002, certain costs associated with employee deferred compensation plans are now
tax-deductible for federal income tax purposes. These costs, however, can not be
expensed for "book" purposes, resulting in a permanent book-to-tax difference.
Further, during the first quarter of 2002, an adjustment to deferred income
taxes of $177.7 million was recorded to reflect a decrease in the tax basis of
the assets acquired at the time of the KeySpan / LILCO merger. This adjustment
resulted from a revised valuation study and the preparation of an amended tax
return. Concurrent with the deferred tax adjustment, KeySpan reduced current
income taxes payable by $183.2 million, resulting in a net $5.5 million income
tax benefit. In addition, goodwill amortization recorded in 2001 was not tax
deductible, also impacting comparative income tax expense.
Earnings before interest and taxes ("EBIT") increased by $36.5 million and $7.5
million for the three and nine months ended September 30, 2002, respectively
compared to the corresponding periods last year. Comparative EBIT results were
impacted by the items mentioned above, namely (i) EBIT losses of $72.6 million
and $133.7 million incurred by the Roy Kay companies for the three and nine
months ended September 30, 2001, respectively; (ii) the reversal of a previously
recorded loss provision relating to a class action settlement of $22.0 million;
(iii) the discontinuation of goodwill amortization in 2002 of $12.0 million and
$36.9 million for the three and nine months ended September 30, 2001,
respectively; and (iv) decreases in comparative EBIT results associated with gas
exploration and production subsidiaries of $5.5 million and $75.7 million for
the three and nine months ended September 30, 2002, respectively. The remaining
decrease in EBIT from core operations for the three and nine months ended
September 30, 2002 compared to last year, primarily reflects lower EBIT from the
Gas Distribution and Energy Services segments. See "Review of Operating
Segments" and Note 2 to the Consolidated Financial Statements "Business
Segments" for a detailed discussion of EBIT results for each of our lines of
business.
We are reaffirming our earnings guidance of $2.60 to $2.75 per share, which
includes earnings from continuing core operations (defined for this purpose as
all continuing operations other than gas exploration and production, less
preferred stock dividends) of approximately $2.40 to $2.45 per share and
earnings from gas exploration and production operations of approximately $0.20 -
$0.30 per share. The earnings forecast may vary significantly during the year
due to, among other things, changing market conditions, especially fluctuations
in natural gas and electricity prices, which remain volatile. It should be noted
that, starting in 2003, KeySpan will begin expensing stock options granted to
its employees in order to reflect all prospective compensation costs in
earnings. Based on current estimates, expensing stock options is not expected to
have a significant impact on results of operations in 2003.
Consolidated earnings are seasonal in nature due to the significant contribution
to earnings of our gas distribution operations. As a result, we expect to earn
approximately 60%, and 30% to 35% of our annual earnings in the first and fourth
quarters of our fiscal year, respectively and breakeven or marginally profitable
earnings are anticipated to be achieved in the second and third quarters of our
fiscal year.
Review of Operating Segments
- ----------------------------
The following discussion of financial results achieved by our operating segments
is presented on an EBIT basis. We use EBIT measures in our financial and
business planning process to provide a reasonable assurance that our financial
forecasts will provide, among other things, (i) shareholders with a competitive
return on their investment, (ii) adequate earnings to service debt; and (iii)
adequate interest coverage to maintain or improve our credit ratings.
Information concerning EBIT is presented as a measure of those financial
results. EBIT should not be construed as an alternative to net income or cash
flow from operating activities as determined by Generally Accepted Accounting
Principles.
Gas Distribution
KeySpan Energy Delivery New York ("KEDNY") provides gas distribution service to
customers in the New York City Boroughs of Brooklyn, Queens and Staten Island,
and KeySpan Energy Delivery Long Island ("KEDLI") provides gas distribution
service to customers in the Long Island Counties of Nassau and Suffolk and the
Rockaway Peninsula of Queens County. Boston Gas Company, Colonial Gas Company,
Essex Gas Company, and EnergyNorth Natural Gas, Inc., each doing business under
the name KeySpan Energy Delivery New England ("KEDNE"), provide gas distribution
service to customers in Massachusetts and New Hampshire.
The table below highlights certain significant financial data and operating
statistics for the Gas Distribution segment for the periods indicated.
(In Thousands )
------------------------------------------- ------------------- -------------------- ------------------- --------------------
Three Months Three Months Nine Months Nine Months
Ended Ended Ended Ended
September 30, September 30, September 30, September 30,
2002 2001 2002 2001
------------------------------------------- ------------------- -------------------- ------------------- --------------------
Revenues $ 337,785 $ 346,703 $ 2,082,577 $ 2,721,032
Purchased gas for resale 130,698 144,279 980,638 1,578,074
Revenue taxes 10,597 12,199 67,055 89,841
------------------------------------------- ------------------- -------------------- ------------------- --------------------
Net Revenues 196,490 190,225 1,034,884 1,053,117
------------------------------------------- ------------------- -------------------- ------------------- --------------------
Operating expenses
Operations and maintenance 147,023 125,276 445,330 442,504
Depreciation and amortization 56,174 60,341 177,312 191,677
Operating taxes 35,375 38,331 103,023 112,469
------------------------------------------- ------------------- -------------------- ------------------- --------------------
Total Operating Expenses 238,572 223,948 725,665 746,650
------------------------------------------- ------------------- -------------------- ------------------- --------------------
Operating Income (42,082) (33,723) 309,219 306,467
Other Income and (Deductions) 3,204 2,714 10,797 12,129
------------------------------------------- ------------------- -------------------- ------------------- --------------------
Earnings Before Interest and Taxes $ (38,878) $ (31,009) $ 320,016 $ 318,596
------------------------------------------- ------------------- -------------------- ------------------- --------------------
Firm gas sales (MDTH) 23,132 23,095 171,797 186,427
Firm transportation (MDTH) 22,429 20,330 65,924 76,818
Transportation - Electric
Generation (MDTH) 27,709 29,341 54,250 45,473
Other sales (MDTH) 32,157 26,356 93,571 75,190
Warmer than normal - New York N/A N/A 15.0% 2.0%
Warmer (Colder) than normal - New England N/A N/A 10.1% (2.3%)
------------------------------------------- ------------------- -------------------- ------------------- --------------------
An MDTH is 10,000 therms (British Thermal Units) and reflects the heating
content of approximately one million cubic feet of gas. A therm reflects the
heating content of approximately 100 cubic feet of gas. One billion cubic feet
(BCF) of gas equals approximately 1,000 MDTH.
Net Revenues
Net gas revenues (revenues less the cost of gas sold and associated revenue
taxes) associated with both the New York and New England based gas distribution
operations were adversely impacted by the significantly warmer than normal
weather experienced throughout the Northeastern United States during the past
winter heating season. Based on heating degree days, weather for the nine months
ended September 30, 2002 was approximately 10% - 15% warmer than normal, and
approximately 14% warmer than last year in the New York and New England service
territories. The significantly warmer than normal weather resulted in a decrease
of $18.2 million, or 2%, in net gas revenues for the nine months ended September
30, 2002, compared to the corresponding period last year.
KEDNY and KEDLI each operate under utility tariffs that contain a weather
normalization adjustment that largely offsets variations in firm net revenues
due to fluctuations in weather. These weather normalization adjustments resulted
in a $33.4 million benefit to net gas revenues in 2002. Nevertheless, net
revenues from firm gas customers (residential, commercial and industrial
customers) in our New York service territory decreased by $16.9 million for the
nine months ended September 30, 2002 compared to the same period last year. The
decrease in net revenues resulted from declining usage per customer due to the
extremely warm weather and the use of more efficient gas heating equipment
offset, in part, by the benefits from conversions to natural gas and $7.9
million of rate incentives and recoveries.
Net revenues from firm gas customers in the New England service territory
decreased by $1.8 million for the nine months ended September 30, 2002, compared
to the same period last year, also due to the extremely warm weather. The New
England based gas distribution subsidiaries do not have a weather normalization
adjustment. Included in net revenues for the nine months ended September 30,
2002 are base rate adjustments totaling $8.9 million associated with Boston Gas
Company's Performance Based Rate Plan ("PBR"). The largest component of this
adjustment reflects the beneficial effect of a favorable ruling of the
Massachusetts Supreme Judicial Court relating to the "accumulated
inefficiencies" component of the productivity factor in the PBR. The court found
that the "accumulated inefficiencies" component imposed by the Massachusetts
Department of Telecommunications and Energy, was not supportable. This ruling
resulted in a benefit to comparative net margins of $5.6 million. (See KeySpan's
Annual Report on Form 10K for the year ended December 31, 2001, Item 7
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Regulation and Rate Matters".)
Firm gas distribution rates in 2002, excluding gas cost recoveries, have
remained substantially unchanged from last year in all of our service
territories. To mitigate, to some extent, the effect of fluctuations in normal
weather patterns on KEDNE's financial position and cash flows, weather
derivatives are in place for the 2002/2003 winter heating season. See Note 6 to
the Consolidated Financial Statement "Derivative Financial Instruments" for
further information.
In our large-volume heating and other interruptible (non-firm) markets, which
include large apartment houses, government buildings and schools, gas service is
provided under rates that are established to compete with prices of alternative
fuel, including No. 2 and No. 6 grade heating oil. Net margins realized from
these customers for the nine months ended September 30, 2002 are comparable to
such margins realized last year. The majority of these margins earned by KEDNE
and KEDLI are returned to firm customers as an offset to gas costs.
We are committed to our expansion strategies initiated during the past few
years. We believe that significant growth opportunities exist on Long Island and
in the New England service territories. We estimate that on Long Island
approximately 35% of the residential and multi-family markets, and approximately
55% of the commercial market currently use natural gas for space heating.
Further, we estimate that in the New England service territories approximately
50% of the residential and multi-family markets, and approximately 45% of the
commercial market currently use natural gas for space heating purposes. We will
continue to seek growth in all our market segments, through the expansion of the
gas distribution system, as well as through the conversion of residential homes
from oil-to-gas for space heating purposes and the pursuit of opportunities to
grow multi-family, industrial and commercial markets.
Sales, Transportation and Other Quantities
Firm gas sales and transportation quantities decreased by 10% during the nine
months ended September 30, 2002, compared to the same period in 2001 due to the
extremely warm weather and declining usage per customer in all our service
territories. Net revenues are not affected by customers choosing to purchase
their gas supply from other sources, since delivery rates charged to
transportation customers generally are the same as the delivery component of
rates charged to full sales service customers.
Transportation quantities related to electric generation reflect the
transportation of gas to KeySpan's electric generating facilities located on
Long Island. Net revenues from these services are not material.
Other sales quantities include on-system interruptible quantities, off-system
sales quantities (sales made to customers outside of our service territories)
and related transportation. We have an agreement with Coral Resources, L.P.
("Coral"), a subsidiary of Shell Oil Company, under which Coral assists in the
origination, structuring, valuation and execution of energy-related transactions
on behalf of KEDNY and KEDLI. We also had a portfolio management contract with
El Paso Energy Marketing, Inc. ("El Paso"), under which El Paso provided all of
the city gate supply requirements at market prices and managed certain upstream
capacity, underground storage and term supply contracts for KEDNE. Our agreement
with El Paso expired on October 31, 2002 and our agreement with Coral expires on
March 31, 2003. We have negotiated a new agreement with Entergy-Koch to replace
the expired El Paso agreement. The new agreement with Entergy-Koch begins on
November 1, 2002 and extends through March 31, 2003.
Purchased Gas for Resale
The decrease in gas costs for the nine months ended September 30, 2002 of $597.4
million, or 38% reflects a decrease of 34% in the price per decatherm of gas
purchased, and a 10% reduction in the quantity of gas purchased, as a result of
the extremely warm winter. 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
cost recoveries are deferred and refunded to or collected from customers in a
subsequent period.
Operating Expenses
Operating expenses increased by $14.6 million, or 7%, in the third quarter of
2002 compared to the same period last year. For the nine months ended September
30, 2002, operating expenses decreased by $21.0 million or 3% compared to the
corresponding period last year. Comparative operating expenses were
significantly impacted by the discontinuation of goodwill amortization. In
January 2002, we adopted Statement of Accounting Standard ("SFAS") 142 "Goodwill
and Other Intangible Assets"). Goodwill amortization in the gas distribution
segment for the three and nine months ended September 30, 2001 was $8.9 million
and $26.6 million, respectively. Goodwill amortization for the twelve months
ended December 31, 2001 was $35.6 million. Excluding the effects of goodwill
amortization, operating expenses increased by $23.5 million and by $5.6 million
for the quarter and period ended September 30, 2002, respectively, compared to
the corresponding periods last year.
The increase in operating expense for both the quarter and nine months ended
September 30, 2002, is partly attributable to the timing of certain operations
and maintenance costs, as well as, an increase in pension and other
postretirement benefits. The cost of these benefits has increased due to a
reduction in the return on plan assets, as well as an increase in actual health
care costs. Further, depreciation expense, excluding 2001 goodwill amortization,
has also increased as a result of the continued expansion of the gas
distribution system.
Offsetting, to some extent, the increases in expenses noted above is a favorable
$7.4 million adjustment to operating taxes recorded in the second quarter of
2002 related to the reversal of excess tax reserves established for the KeySpan
/ LILCO merger and subsequent re-organization in May 1998. Further, we are
currently realizing cost saving synergies as a result of early retirement and
severance programs implemented in the fourth quarter of 2000. The early
retirement portion of the program was completed in 2000, but the severance
feature will continue through 2002
Other Matters
To take advantage of the anticipated gas sales growth opportunities in the New
York City metropolitan area, in 2000 we formed the Islander East Pipeline, LLC,
a limited liability company in which a KeySpan subsidiary and a subsidiary of
Duke Energy Corporation each own a 50% equity interest. In the third quarter of
2002, Islander East Pipeline, LLC received a certificate of public convenience
and necessity from the Federal Energy Regulatory Commission ("FERC") to
construct, own and operate a natural gas pipeline facility consisting of
approximately 50 miles of interstate natural gas pipeline extending from
Algonquin Gas Transmission Company's facilities in Connecticut, across the Long
Island Sound and connecting with KEDLI's facilities on Long Island.
Subsequent to the timely receipt of approvals from the State of Connecticut, the
Islander East Pipeline is expected to begin operating in late 2003 and will
transport 260,000 dth daily to the Long Island and New York City energy markets,
enough fuel to heat 600,000 homes, as well as allow us to further diversify the
geographic sources of our gas supply. We are currently evaluating various
options for the financing of this pipeline. (See the discussion under "Capital
Expenditures and Financing" for more information on our financing plans for the
remainder of 2002.)
Electric Services
The Electric Services segment primarily consists of subsidiaries that own and
operate oil and gas fired electric generating plants in Queens (the Ravenswood
facility) and Long Island and, through long-term contracts, manage the electric
transmission and distribution ("T&D") system, the fuel and electric purchases,
and the off-system electric sales for the Long Island Power Authority ("LIPA").
Selected financial data for the Electric Services segment is set forth in the
table below for the periods indicated.
(In Thousands)
------------------------------------------ -------------------- ------------------- -------------------- -------------------
Three Months Three Months Nine Months Nine Months
Ended Ended Ended Ended
September 30, September 30, September 30, September 30,
2002 2001 2002 2001
------------------------------------------ -------------------- ------------------- -------------------- -------------------
Revenues $ 414,893 $ 387,906 $ 1,084,384 $ 1,089,231
Purchased fuel 101,572 87,401 216,712 241,055
------------------------------------------ -------------------- ------------------- -------------------- -------------------
Net Revenues 313,321 300,505 867,672 848,176
------------------------------------------ -------------------- ------------------- -------------------- -------------------
Operating expenses
Operations and maintenance 149,682 153,881 481,732 465,787
Depreciation 16,176 13,200 43,835 38,490
Operating taxes 40,809 38,931 114,449 120,600
------------------------------------------ -------------------- ------------------- -------------------- -------------------
Total Operating Expenses 206,667 206,012 640,016 624,877
------------------------------------------ -------------------- ------------------- -------------------- -------------------
Operating Income 106,654 94,493 227,656 223,299
Other Income and (Deductions) 6,624 2,026 15,995 6,526
------------------------------------------ -------------------- ------------------- -------------------- -------------------
Earnings Before Interest and Taxes $ 113,278 $ 96,519 $ 243,651 $ 229,825
------------------------------------------ -------------------- ------------------- -------------------- -------------------
Electric sales (MWH)* 2,175,937 1,869,712 4,392,915 4,185,332
Cooling Degree Days 1,094 947 1,434 1,338
Capacity (MW)* 2,200 2,200 2,200 2,200
------------------------------------------ -------------------- ------------------- -------------------- -------------------
*Reflects the operations of the Ravenswood facility only.
Net Revenues
Total electric net revenues increased by $12.8 million, or 4% and $19.5 million,
or 2% for the three and nine months ended September 30, 2002, compared to the
same periods in 2001. Net revenues for the quarter and period ended September
30, 2002, reflect revenues of $8.1 million and $9.4 million, respectively from
our new Glenwood Landing and Port Jefferson electric generating facilities
located on Long Island. The Glenwood facility was placed in service on June 1,
2002, while the Port Jefferson facility was placed in service on July 1, 2002.
These facilities add a combined 158 MW of generating capacity to KeySpan's
electric portfolio. The capacity of and energy produced by these facilities are
dedicated to LIPA under 25 year contracts. Net revenues from the LIPA service
agreements and the Ravenswood facility for the quarter ended September 30, 2002,
remained relatively flat compared to the third quarter of last year. For the
nine months ended September 30, 2002, higher comparative net revenues from the
LIPA service agreements were mostly offset by lower comparative net revenues
from the Ravenswood facility.
Net revenues from the LIPA service agreements increased by $4.4 million, or 2%,
and by $36.5 million or 6% for the quarter and nine months ended September 30,
2002, respectively, compared to the same periods last year. Included in revenues
for 2002, are billings to LIPA for certain third party costs that were
significantly higher than such billings last year. These revenues have no impact
on earnings since we record a similar amount of costs in operating expense.
Excluding these third party billings, revenues for the quarter and nine months
ended September 30, 2002 associated with the LIPA service agreements were
comparable to such revenues during the same period last year.
Net revenues from the Ravenswood facility were flat for the third quarter of
2002 compared to the same period in 2001. Higher net revenues from the sale of
energy were entirely offset by lower capacity sales. While "spark-spread" (the
selling price of electricity less the cost of fuel) remained relatively constant
for the third quarter of 2002 compared to the same period last year, energy
sales benefited from a 16% increase in megawatt hours sold as a result of the
hot weather experienced during the summer. Measured in cooling degree days,
weather during the peak summer months of July through September 2002, was
approximately 16% warmer compared to last year.
Net revenues from the Ravenswood facility were $26.4 million, or 9%, lower
during the nine months ended September 30, 2002, compared to the same period in
2001. Net revenues from capacity sales decreased 18% compared to last year,
while margins associated with the sale of electric energy were 5% higher than
last year. Comparative energy sales benefited from a 5% increase in the megawatt
hours sold as a result of the hot summer weather offset, in part, by a reduction
in "spark-spread". Measured in cooling degree days, weather during the nine
months ended September 30, 2002, was approximately 7% warmer than the same
period last year.
The decrease in comparative net revenues from capacity sales for both the
quarter and nine months ended September 30, 2002, was due, in part, to more
competitive pricing by the electric generators that bid into the New York
Independent System Operator ("NYISO") energy market and a revised methodology
employed by the NYISO to assess the available supply of and demand for installed
capacity. However, in September 2002, the NYISO recognized a calculation flaw in
its revised methodology. This flaw resulted in insufficient capacity being
procured by the market, as well as a reliability concern. Prior to the recent
2002/2003 winter auction the NYISO corrected the calculation methodology to
ensure sufficient capacity is procured. Elimination of the flaw will ensure
compliance with New York State Reliability Rules. The Ravenswood facility and
the NYISO energy market should benefit from this correction since, as a result,
load serving entities, such as electric utilities, should procure sufficient
capacity to maintain reliability for customers. Further, the correction
addresses the lack of an appropriate price signal necessary to encourage greatly
needed new supply.
The rules and regulations for capacity, energy sales and the sale of certain
ancillary services to the NYISO energy markets are still evolving and the FERC
has adopted several price mitigation measures that have adversely impacted
comparative 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 can not fully be determined at this time. (See
KeySpan's Annual Report on Form 10K, Item 7A. Quantitative and Qualitative
Disclosures About Market Risk, as well as Item 3. of this Form 10Q for a further
discussion of these matters.)
Operating Expenses
Operating expenses for the quarter of 2002, remained consistent with the prior
year. Lower operating and maintenance costs were offset by slightly higher
depreciation and operating taxes. During the third quarter of 2002, we settled
certain outstanding issues with LIPA and Consolidated Edison that resulted in a
$13.0 million decrease to operating expenses. Partially offsetting these
favorable settlements, was an increase in third party costs. As previously
mentioned, these costs are fully recovered from LIPA. Operating expenses for the
nine months ended September 30, 2002 increased by $15.1 million, or 2% primarily
as a result of third party costs offset, in part, by the beneficial impact of
settlements previously mentioned.
Other Income and Deductions
The increase of $4.6 million and $9.5 million in Other Income is due primarily
to inter-company interest income earned by subsidiaries within the Electric
Services segment. For the most part, the various subsidiaries of KeySpan do not
maintain separate cash balances. Rather, liquid assets are maintained in a money
pool, from and to which subsidiaries can either borrow or lend. Inter-company
interest expense is charged to "borrowers", while inter-company interest income
is earned by "lenders". During the three and nine months ended September 30,
2002, the subsidiaries within the Electric Services segment have been net
"lenders" to the money pool and, accordingly, have reflected inter-company
interest income. Interest rates associated with money pool borrowings are
generally the same as KeySpan's short-term borrowing rate. All inter-company
interest income and expense is eliminated for consolidated financial reporting
purposes.
Other Matters
As previously mentioned, both the Glenwood Landing and Port Jefferson electric
generating facilities are fully operational. Short-term financing was used for
the construction of these facilities, but various financing options to
permanently finance these facilities are being explored. (See the discussion
under "Capital Expenditures and Financing" for more information on our financing
plans for 2002.) Further, construction has begun on a new 250 MW combined cycle
generating facility at the Ravenswood facility site. The new facility is
expected to commence operations in late 2003. The capacity and energy produced
from this plant are anticipated to be sold into the NYISO energy markets. We are
also progressing through the siting process before the New York State Board on
Electric Generation Siting and the Environment with a proposal to build a
similar 250 MW combined cycle electric generating facility on Long Island.
Under the Generation Purchase Right Agreement ("GPRA"), LIPA had the right for a
one-year period, beginning on May 28, 2001, to acquire all of our Long Island
based generating assets formerly owned by LILCO at fair market value at the time
of the exercise of such right. By agreement dated March 29, 2002, LIPA and
KeySpan amended the GPRA to provide for a new six month option period ending on
May 28, 2005. The other terms of the option reflected in the GPRA remain
unchanged.
In return for providing LIPA an extension of the GPRA, KeySpan and LIPA have
agreed to an extension for 31 months of the Management Services Agreement under
which KeySpan manages the day-to-day operations, maintenance and capital
improvements of LIPA's transmission and distribution system. The extension has
received the required governmental approvals.
The extensions are the result of a new initiative established by LIPA to work
with KeySpan and others to review Long Island's long-term energy needs. LIPA and
KeySpan will jointly analyze new energy supply options including re-powering
existing plants, renewable energy technologies, distributed generation,
conservation initiatives and retail competition. The extension allows both LIPA
and KeySpan to explore alternatives to the GPRA including re-powering existing
facilities, the sale of some or all of KeySpan's plants (formerly owned by
LILCO) to LIPA, or the sale of some or all of these plants to other private
operators.
Energy Services
The Energy Services segment primarily includes companies that provide services
through three lines of business to clients located within the New York City
metropolitan area, 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.
(In Thousands)
------------------------------------------ -------------------- -------------------- ------------------- --------------------
Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended
September 30, 2002 September 30, 2001 September 30, 2002 September 30, 2001
------------------------------------------ -------------------- -------------------- ------------------- --------------------
Revenues $ 217,104 $ 263,047 $ 687,975 $ 814,911
Less: cost of gas and fuel 45,809 81,768 157,694 326,943
------------------------------------------ -------------------- -------------------- ------------------- --------------------
Net revenues 171,295 181,279 530,281 487,968
Other operating expenses 176,129 251,174 555,337 622,033
------------------------------------------ -------------------- -------------------- ------------------- --------------------
Operating Loss (4,834) (69,895) (25,056) (134,065)
Other Income and (Deductions) 379 301 1,155 1,052
------------------------------------------ -------------------- -------------------- ------------------- --------------------
Loss Before Interest and Taxes $ (4,455) $ (69,594) $ (23,901) $ (133,013)
------------------------------------------ -------------------- -------------------- ------------------- --------------------
Comparative EBIT results for the three and nine months ended September 30, 2002
compared to the comparable periods last year were significantly impacted by
losses incurred by one of our subsidiaries. In 2001, we discontinued the general
contracting activities related to the former Roy Kay companies, with the
exception of completion of work on then existing contracts, based upon our view
that the general contracting business is not a core competency of these
companies. (See KeySpan's Annual Report on Form 10K for the year ended December
31, 2001 Item 7 "Management's Discussion of Financial Condition and Results of
Operations" and Note 11 to those Consolidated Financial Statements "Roy Kay
Operation" for a more detailed discussion.) For the three and nine months ended
September 30, 2001, we incurred EBIT losses of $72.6 million and $133.7 million,
respectively, associated with the operations of the former Roy Kay companies. We
are completing the contracts entered into by the former Roy Kay companies and,
for the three and nine months ended September 30, 2002, we incurred EBIT losses
of $4.9 million and $8.2 million, reflecting increases in the estimates of and
costs to complete these contracts, and general and administrative expenses.
Excluding the results of the former Roy Kay companies, the Energy Services
segment reflected a decrease in EBIT of $2.5 million and $16.4 million for the
three and nine months ended September 30, 2002, respectively compared to the
corresponding periods last year. Revenues, excluding the Roy Kay companies,
decreased by $29.9 million and $174.0 million for the three and nine months
ended September 30, 2002, respectively, while the cost of fuel decreased by
$36.0 million and $169.3 million during the same time periods. These declines,
which for the most part offset each other, reflect the operations of our gas and
electric marketing subsidiary. Beginning in 2002, this subsidiary focused its
marketing efforts on higher net margin customers and as a result has
substantially decreased its customer base.
EBIT results for the Business Solutions group of companies, which provide
mechanical contracting, plumbing, engineering and consulting services to
commercial, institutional, and industrial customers, improved by $7.1 million
and $6.3 million for the three and nine months ended September 30, 2002,
respectively compared to the same periods last year. These increases reflect
additional volume and the timing of completion of certain contracts.
Offsetting these increases in EBIT are decreases of $7.3 million and $21.4
million associated with the Home Energy Services group of companies. These
companies provide residential and small commercial customers with service and
maintenance of appliances, as well as, the retail marketing of natural gas and
electricity. The following factors contributed to the decreases in EBIT from
Home Energy Services: (i) the continued adverse impact of the down-turn in the
economy; (ii) cancellation of appliance service contracts; (iii) costs
associated with the closing of a service center; and (iv) an increase in the
reserve for bad debts. Comparative EBIT results in 2002 benefited from the
elimination of goodwill amortization, which for the three and nine months ended
September 30, 2001 amounted to $1.8 million and $5.8 million, respectively.
We are currently re-aligning / combining a number of our service centers in this
segment in order to reduce operating and general and administrative costs and
realize synergy savings.
Energy Investments
The Energy Investment segment consists of gas exploration and production
operations as well as certain other domestic and international energy-related
investments. Our gas exploration and production subsidiaries are engaged in gas
and oil exploration and production, and the development and acquisition of
domestic natural gas and oil properties. These investments consist of a 67%
equity interest in Houston Exploration, as well as a wholly-owned subsidiary,
KeySpan Exploration and Production, LLC. In line with our stated strategy of
exploring the monetization or diversiture of certain non-core assets, in October
2002, we monetized a portion of our assets in the joint venture drilling program
with Houston Exploration that was created in 1999. We received $26.5 million in
cash from Houston Exploration for 18.6 Bcfe of estimated proved and probable
reserves. The proceeds will be used to pay down short-term debt; there was no
earnings impact from this transaction.
This segment also consists of KeySpan Canada; a 20% interest in the Iroquois Gas
Transmission System LP ("Iroquois"); and a 50% interest in the Premier
Transmission Pipeline and a 24.5% interest in Phoenix Natural Gas.
Selected financial data and operating statistics for gas exploration and
production activities are set forth in the following table for the periods
indicated.
(In Thousands)
---------------------------------------------- ------------------- -------------------- -------------------- -------------------
Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended
September 30, 2002 September 30, 2001 September 30, 2002 September 30, 2001
---------------------------------------------- ------------------- -------------------- -------------------- -------------------
Revenues $ 86,464 $ 82,362 $ 249,452 $ 318,093
Depletion and amortization expense 44,880 35,697 130,766 102,749
Other operating expenses 15,230 12,471 43,053 44,915
---------------------------------------------- ------------------- -------------------- -------------------- -------------------
Operating Income 26,354 34,194 75,633 170,429
Other Income and (Deductions)* (5,079) (7,407) (15,091) (34,169)
---------------------------------------------- ------------------- -------------------- -------------------- -------------------
Earnings Before Interest and Taxes* $ 21,275 $ 26,787 $ 60,542 $ 136,260
--------------------------------------------- ------------------- -------------------- -------------------- -------------------
Natural gas and oil production (Mmcf) 26,913 23,265 79,641 69,947
Natural gas price (per Mcf) realized $ 3.14 $ 3.50 $ 3.08 $ 4.53
Natural gas price (per Mcf) unhedged $ 3.00 $ 2.72 $ 2.80 $ 4.71
Proved reserves at year-end (BCFe) 647 593 647 593
---------------------------------------------- ------------------- -------------------- -------------------- -------------------
*Operating income above represents 100% of our gas exploration and production
subsidiaries' results for the periods indicated. Earnings before interest and
taxes, however, is adjusted to reflect minority interest which is included in
Other Income and (Deductions). Gas reserves and production are stated in BCFe
and Mmcfe, which includes equivalent oil reserves.
Earnings Before Interest and Taxes
The decrease in EBIT of $5.5 million for the third quarter of 2002, compared to
the corresponding quarter last year primarily reflects an increase in operating
costs of $11.9 million, or 25%, offset in part by a $4.1 million, or 5% increase
in revenues. The increase in operating expenses is primarily due to an increase
in depletion and amortization expense as a result of a 16% increase in
production volumes. The increase in revenues reflects the benefits derived from
production volume increases, offset in part by a decrease of 10% in average
realized gas prices (average wellhead price received for production including
realized hedging gains and losses). The decrease in average realized gas prices
reflects lower hedging gains realized during the quarter ended September 30,
2002, compared to the same quarter last year.
The decrease in EBIT of $75.7 million, or 56% for the nine months ended
September 30, 2002, compared to the same period last year reflects a significant
reduction in revenues and, to a lesser degree, an increase in operating expenses
associated with higher levels of production. Revenues for the nine months ended
September 30, 2002, compared to the same period in 2001, were adversely impacted
by a 32% decline in average realized gas prices. The adverse effect on revenues
resulting from the decline in average realized gas prices was partially offset
by an increase of 14% in production volumes. The depreciation, depletion and
amortization rate was $1.64 per mcf for the nine months ended September 30,
2002, compared to $1.44 per mcf for the same period in 2001, reflecting higher
finding and development costs together with the addition of fewer new reserves.
The average realized gas price in the third quarter of 2002 was 105% of the
average unhedged natural gas price. The average realized gas price for the nine
months ended September 30, 2002 was 110% of the average unhedged natural gas
price during that period. The average realized gas price in the third quarter of
2001 was 129% of the average unhedged natural gas price, while the average
realized gas price for the nine months ended September 30, 2001 was 96% of the
average unhedged natural gas price. Houston Exploration entered into derivative
financial positions in 2001 to hedge a substantial portion of its anticipated
2002 production. These derivative instruments are designed to provide Houston
Exploration with a more predictable cash flow, as well as to reduce its exposure
to fluctuations in natural gas prices. The settlement of these derivative
instruments during the nine months ended September 30, 2002 resulted in a
comparative benefit to revenues of $32.3 million. (See Note 6 to the
Consolidated Financial Statements, "Derivative Financial Instruments" for
further information.)
Natural gas prices continue to fluctuate and the risk that we may be required to
write-down our investment in exploration and production properties increases
when natural gas prices are depressed or if there is a significant downward
revisions in estimated proved reserves.
At December 31, 2001, our gas exploration and production subsidiaries had 647
BCFe of net proved reserves of natural gas, of which approximately 72% were
classified as proved developed.
Selected financial data and operating statistics for our other energy-related
investments are set forth in the following table for the periods indicated.
(In Thousands)
------------------------------------------- -------------------- ------------------- -------------------- --------------------
Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended
September 30, 2002 September 30, 2001 September 30, 2002 September 30, 2001
------------------------------------------- -------------------- ------------------- -------------------- --------------------
Revenues $ 23,793 $ 22,436 $ 63,366 $ 73,627
Operation and maintenance expense 10,915 18,562 44,749 51,698
Other operating expenses 4,633 4,486 13,205 12,268
------------------------------------------- -------------------- ------------------- -------------------- --------------------
Operating Income (Loss) 8,245 (612) 5,412 9,661
Other Income and (Deductions) 2,690 3,030 11,677 9,158
------------------------------------------- -------------------- ------------------- -------------------- --------------------
Earnings Before Interest and Taxes $ 10,935 $ 2,418 $ 17,089 $ 18,819
------------------------------------------- -------------------- ------------------- -------------------- --------------------
The increase in EBIT for the third quarter of 2002 compared to the same quarter
last year, reflects the timing of certain expenses associated with
technology-related investments, as well as lower comparative losses associated
with these investments. The decrease in EBIT for the nine months ended September
30, 2002, is primarily due to the operations of KeySpan Canada and lower
earnings from our liquefied natural gas ("LNG") transportation subsidiary.
KeySpan Canada experienced lower per unit sales prices, as well as lower
quantities of sales of natural gas liquids in 2002, as a result of generally
lower oil prices. The pricing of natural gas liquids is directly related to oil
prices. Our LNG transportation subsidiary realized lower EBIT results in 2002 as
a result of lower demand for LNG due to the extremely warm winter weather. These
decreases to comparative EBIT results were substantially offset by lower
comparative losses associated with certain technology-related investments.
We do not consider the businesses contained in the Energy Investments segment to
be part of our core asset group. We have stated in the past that we may sell or
otherwise dispose of all or a portion of our non-core assets. Based on current
market conditions, we can not predict when, or if, any such sale or disposition
may take place, or the effect that any such sale or disposition may have on our
financial position, results of operations or cash flows.
Liquidity
The increase in cash flow from operations for the nine months ended September
30, 2002, compared to the corresponding period last year, is primarily
attributable to lower interest and income tax payments, as well as to a decrease
in cash payments for natural gas purchased for inventory. As previously
mentioned, interest payments have decreased due to the beneficial effect of
interest rate swaps, as well as to lower interest rates on outstanding
commercial paper. State and federal tax payments were lower for the nine months
ended September 30, 2002, compared to the same period last year, as KeySpan is
currently in a refund position with regards to such taxes. Further, due to the
extremely warm weather experienced during the past winter and the resulting
higher inventory levels, we purchased a lower quantity of natural gas for
storage purposes so far this year than we did during the corresponding period
last year, and at lower prices. As mentioned earlier, fluctuations in utility
gas costs have no impact on operating results, since the current gas rate
structure of each of our gas distribution utilities allow for full recovery of
these costs. Operating cash flow from gas exploration and production activities,
however, was adversely impacted by significantly lower realized gas prices for
the nine months ended September 30, 2002, compared to the same period last year.
(See Note 6 to the Consolidated Financial Statements "Derivative Financial
Instruments" for an explanation of the interest rate hedges.)
As previously indicated, a substantial portion of consolidated revenues are
derived from the operations of businesses within the Electric Services segment,
that are largely dependent upon two large customers - LIPA and the NYISO.
Accordingly, our cash flows are dependent upon the timely payment of amounts
owed to us by these customers.
In July 2002, KeySpan renewed its existing 364-day revolving credit agreement
with a commercial bank syndicate of 16 banks totaling $1.3 billion, a reduction
from the previous $1.4 billion facility. The credit facility is used to back up
the $1.3 billion commercial paper program. The fees for the facility are subject
to a ratings-based grid, with an annual fee of .075% on the total amount of the
revolving facility. The credit agreement allows for KeySpan to borrow using
several different types of loans; specifically, Eurodollar loans, ABR loans, or
competitively bid loans. Eurodollar loans are based on the Eurodollar rate plus
a margin of 42.5 basis points for loans up to 33% of the facility, and an
additional 12.5 basis points for loans over 33% of the total facility. ABR loans
are based on the greater of the Prime Rate, the base CD rate plus 1%, or the
Federal Funds Effective Rate plus 0.5%. Competitive bid loans are based on bid
results requested by KeySpan from the lenders. We do not anticipate borrowing
against this facility; however, if the credit rating on our commercial paper
program were to be downgraded, it may be necessary to borrow on the credit
facility.
At September 30, 2002, we had cash and temporary cash investments of $53.9
million. During the nine months ended September 30, 2002, we repaid $519.2
million of commercial paper and, at September 30, 2002, $529.2 million of
commercial paper was outstanding at a weighted average annualized interest rate
of 1.87%. We had the ability to borrow up to an additional $770.8 million at
September 30, 2002 under the commercial paper program.
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; further the $425 million Ravenswood Master Lease is treated as debt. The
financial covenant in the credit facility reflects a maximum debt-to-total
capitalization ratio of 66%, a decrease from the 68% ratio required under the
previous credit facility. At September 30, 2002, consolidated indebtedness, as
calculated under the terms of the new credit facility, was 63.6% 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 "Capital Expenditures and Financing for an explanation of the MEDS Equity
Units and Ravenswood Master Lease.)
On July 15, 2002, Houston Exploration entered into a new revolving credit
facility with a commercial banking syndicate that replaces the existing $250
million revolving credit facility. The new facility provides Houston Exploration
with an initial commitment of $300 million, which can be increased, at its
option to a maximum of $350 million with prior approval from the banking
syndicate. The new credit facility is subject to borrowing base limitations,
initially set at $300 million and will be re-determined semi-annually, with the
first re-determination scheduled for October 1, 2002. Up to $25.0 million of the
borrowing base is available for the issuance of letters of credit. The new
credit facility matures July 15, 2005, is unsecured and ranks senior to all
existing debt.
Under the Houston Exploration credit facility, interest on base rate loans is
payable at a fluctuating rate, or base rate, equal to the sum of (a) the greater
of the Federal funds rate plus .5% or the bank's prime rate plus (b) a variable
margin between 0% and 0.50%, depending on the amount of borrowings outstanding
under the credit facility. Interest on fixed loans is payable at a fixed rate
equal to the sum of (a) a quoted LIBOR rate divided by one minus the average
maximum rate during the interest period set for certain reserves of member banks
of the Federal Reserve System in Dallas, Texas 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 of not more than a ratio of 3.50 to 1.00; and (iii) hedge
no more than 70% of natural gas production during any 12-month period.
During the nine months ended September 30, 2002, Houston Exploration borrowed
$46.0 million under its prior credit facility and repaid $43.0 million. At
September 30, 2002, $147 million of borrowings remained outstanding at a
weighted average annualized interest rate of 3.38%; $103.0 million of borrowing
capacity was available.
KeySpan Canada has two revolving loan agreements with financial institutions in
Canada. Repayments under these agreements totaled approximately US $20.5 million
for the nine months ended September 30, 2002. At September 30, 2002,
approximately US $155.0 million was outstanding at a weighted average annualized
interest rate of 3.15%. KeySpan Canada currently has available borrowings of
approximately US $49.8 million. These revolving credit agreements have been
extended without modification through December 31, 2002.
KeySpan has fully and unconditionally guaranteed $525 million of medium- term
notes issued by KEDLI under KEDLI's current shelf registration, as well as a
$130 million revolving credit agreement associated with its Canadian
subsidiaries. Both the medium-term notes and borrowings under the credit
agreement are reflected on the Consolidated Balance Sheet.
Further, KeySpan has guaranteed: (i) $127.2 million of surety bonds associated
with certain construction projects currently being performed by subsidiaries
within the Energy Services segment; (ii) certain supply contracts, margin
accounts and purchase orders for certain subsidiaries in the aggregate amount of
$95.0 million; (iii) the obligations of KeySpan Ravenswood LLC, the lessee under
the $425 million Master Lease Agreement associated with the lease of the
Ravenswood facility; and (iv) $63.2 million of subsidiary letter of credits.
These guarantees are not recorded on the Consolidated Balance Sheet. The
guarantee of the KEDLI medium- term notes expires in 2010, while the other
guarantees have terms that do not extend beyond 2005; however the Master Lease
Agreement can be extended to 2009. At this point in time, we have no reason to
believe that our subsidiaries will default on their current obligations.
However, we can not predict when or if any defaults may take place or the impact
such defaults may have on our consolidated results of operations, financial
condition or cash flows. See the discussion of the Ravenswood lease under the
heading "Capital Expenditures and Financing" for a description of the leasing
arrangement.
We satisfy our seasonal working capital requirements primarily through
internally generated funds and the issuance of commercial paper. In addition, we
realized $173.9 million in proceeds from the sale of Midland. 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 employee common stock, dividend reinvestment and benefit plans.
Capital Expenditures and Financing
Construction Expenditures
The table below sets forth our construction expenditures by operating segment
for the periods indicated:
(In Thousands)
- ---------------------------------------- -------------------- ------------------
Nine Months Ended Nine Months Ended
September 30, 2002 September 30, 2001
- ---------------------------------------- -------------------- ------------------
Gas Distribution $ 294,774 $ 219,137
Electric Services 290,790 138,272
Energy Investments 242,097 301,974
Energy Services 8,319 9,111
- ---------------------------------------- -------------------- ------------------
$ 835,980 $ 668,494
- ---------------------------------------- -------------------- ------------------
Construction expenditures related to the Gas Distribution segment are primarily
for the renewal and replacement of mains and services and for the expansion of
the gas distribution system. Construction expenditures for the Electric Services
segment reflect costs to: (i) maintain our generating facilities; (ii) expand
the Ravenswood facility; and (iii) construct the new Long Island generating
facilities as previously noted. Construction expenditures related to the Energy
Investments segment primarily reflect costs associated with gas exploration and
production activities. These costs are related to the 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 Canadian affiliates.
At September 30, 2002, total expenditures associated with the siting, permitting
and construction of the Ravenswood expansion project, the siting, permitting and
procurement of equipment for the Long Island 250MW combined cycle generation
plant, and the siting and permitting of the Islander East pipeline project are
$183.0 million.
Construction expenditures are reviewed on an ongoing basis and can be affected
by timing, scope and changes in investment opportunities.
Financing
At December 31, 2001, KeySpan had an existing $1 billion shelf registration
statement on file with the Securities and Exchange Commission ("SEC"), with $500
million available for issuance. In February 2002, we updated the shelf
registration for the issuance of an additional $1.2 billion of securities,
thereby giving us the ability to issue up to $1.7 billion of debt, equity or
various forms of preferred stock. At December 31, 2001, we had authority under
the Public Utility Holding Company Act ("PUHCA") to issue up to $1 billion of
this amount.
On April 30, 2002, we issued $460 million of MEDS Equity Units at 8.75%
consisting of a three-year forward purchase contract for our common stock and a
six-year note. The purchase contract commits us three years from the date of
issuance of the MEDS Equity Units to issue and the investors to purchase a
number of shares of our common stock based on a formula tied to the market price
of our common stock at that time. The 8.75% coupon is composed of interest
payments on the six-year note of 4.9% and premium payments on the three-year
equity forward contract of 3.85%. These instruments have been recorded as
long-term debt on our Consolidated Balance Sheet, but rating agencies consider
between 80% to 100% of the instruments as equity for purposes of calculating
debt-to-total capitalization ratios. (See Note 5 to the Consolidated Financial
Statements "Long-Term Debt" for further details on the MEDS Equity Units.)
The issuance of the MEDS equity units utilized $920 million of our financing
authority under both the shelf registration and the PUHCA financing authority.
Both the $460 million six-year note and the $460 million forward equity contract
are considered current issuances for these purposes. Therefore, we have $780
million available for issuance under the shelf registration and $80 million
available under PUHCA. We have filed an amendment to our financing authorization
with the SEC to increase the financing authority under PUHCA by $700 million,
thereby matching the shelf availability. We anticipate a decision on this
request by the SEC by year-end.
In May 2002, Colonial Gas Company repaid $15 million of its 6.81% Series A First
Mortgage Medium -Term Notes. These Notes would have matured on May 19, 2027, but
the holder of the Notes elected to exercise a put option to redeem the Notes
early.
As previously noted, we issued commercial paper to finance the construction of
our two Long Island peaking-power plants, and we will continue to finance the
construction of the new 250MW combined cycle generating facility at the
Ravenswood facility site, as well as the Islander East Pipeline, through the
issuance of commercial paper.
During the first half of 2003, we intend to issue approximately $150 million of
either taxable or tax-exempt long-term debt securities, the proceeds of which,
it is anticipated, will be used to re-pay the outstanding commercial paper
related to the construction of our two Long Island peaking-power plants. We also
may issue an additional $200 to $300 million of medium-term debt in the fourth
quarter of 2002 or early 2003 to replace outstanding commercial paper, if market
conditions are favorable. We will continue to evaluate our capital structure and
financing strategy for 2002 and beyond. We believe that our current sources of
funding (i.e., internally generated funds, the issuance of additional securities
as noted above, and the availability of commercial paper), together with the
cash proceeds from the sale of Midland, are sufficient to meet our anticipated
working capital needs for the foreseeable future.
As noted, as part of our strategy to maintain an optimal level of floating rate
debt, we had several interest rate swap agreements on a portion of our existing
fixed rate medium-term and long-term debt that effectively changed the debt to
floating rate debt. These swap agreements qualified for hedge accounting and
were completed with several major financial institutions in order to reduce
credit risk. In early November 2002, we terminated two interest rate swap
agreements with an aggregate notional amount of $1.0 billion and received $81.0
milliom from our swap counter-parties. (See Note 6 to the Consolidated Financial
Statements "Derivative Financial Instruments" for additional information on
these swap agreements.)
We also have an arrangement with a special purpose financing entity through
which we lease a portion of the Ravenswood facility. We acquired the Ravenswood
facility from Consolidated Edison on June 18, 1999 for approximately $597
million. In order to reduce the initial cash requirements, we entered into a
lease agreement with a special purpose, unaffiliated financing entity that
acquired a portion of the facility directly from Consolidated Edison and leased
it to our subsidiary. KeySpan has guaranteed all payment and performance
obligations of our subsidiary under the lease. The lease represents
approximately $425 million of the acquisition cost of the facility, which is the
amount of debt that would have been recorded on our Consolidated Balance Sheet
had the special purpose financing entity not been utilized and conventional debt
financing been employed. Further, we would have recorded an asset in the same
amount. Monthly lease payments represent interest only. The lease qualifies as
an operating lease for financial reporting purposes while preserving our
ownership of the facility for federal and state income tax purposes.
The initial term of the lease expires on June 20, 2004 and may be extended until
June 20, 2009. In June 2004, we have the right to either purchase the facility
or terminate the lease and dispose of the facility for an amount generally equal
to the original acquisition cost, $425 million, plus the present value of the
lease payments that would have otherwise been paid through June 20, 2009. In
June 2009, when the lease terminates, we may purchase the facility in an amount
generally equal to the original acquisition cost or surrender the facility to
the lessor.
The Financial Accounting Standards Board (the "Board") is currently reviewing
issues related to special purpose entities and in May 2002 issued an Exposure
Draft regarding the accounting for, and disclosure of special purpose entities.
It is expected that the final guidance will be issued in late 2002, and be
effective April 1, 2003. It is possible that KeySpan may be required to classify
the lease under which the Ravenswood facility is operated as debt on the
Consolidated Balance Sheet at an amount generally equal to fair market value. As
previously mentioned, under the terms of our credit facility the Ravenswood
Master Lease is considered debt in the ratio of debt-to-total capitalization.
Further, we may be required to record an asset on the Consolidated Balance Sheet
for an amount generally equal to the fair market value of the leased assets. At
this time, we believe that the fair market value of the leased assets is in
excess of the original acquisition cost. At this time, however, we are unable to
determine what the requirements will be under the final guidance, if and when an
accounting Standard is issued, as well as the actual impact on our results of
operations and financial position.
The ratings on our long-term debt have remained unchanged from December 31,2001.
Moody's Investor Services, Standard and Poor's rating agency, and FitchRatings
have rated our long-term debt as follows: (i) KeySpan's long-term debt A3, A and
A-, respectively; (ii) KEDNY's long-term debt A2, A+ and A+, respectively; and
(iii) KEDLI's long-term debt A2, A+ and A, respectively. Moody's Investor
Services and Standard and Poor's rating agency rated Boston Gas Company's and
Colonial Gas Company's long-term debt A2 and A, respectively. Our contractual
cash obligations and associated maturities have increased from December 31,
2001, due to the issuance of the MEDS Equity Units previously discussed.
The table below reflects maturity schedules for our cash contractual obligations
at September 30, 2002:
(In Thousands)
---------------------------------- ---------------- ------------------ -------------------- ----------------------
Contractual Obligations Total 1-3 Years 4-5 Years After 5 Years
---------------------------------- ---------------- ------------------ -------------------- ----------------------
Long-Term Debt $ 5,228,070 $ 486,151 $ 1,212,333 $ 3,529,586
Capital Lease Obligations 13,912 2,327 2,031 9,554
Operating Leases 633,313 261,953 165,441 205,919
---------------------------------- ---------------- ------------------ -------------------- ----------------------
Total Contractual
Cash Obligations $ 5,875,295 $ 750,431 $ 1,379,805 $ 3,745,059
---------------------------------- ---------------- ------------------ -------------------- ----------------------
Commercial Paper $ 529,228 Revolving
---------------------------------- ---------------- ------------------ -------------------- ----------------------
Discussions of Critical Accounting Policies and Assumptions
In preparing our financial statements, the application of certain accounting
policies requires difficult, subjective and/or complex judgments. The
circumstances that make these judgements difficult, subjective and/or complex
have to do with the need to make estimates about the impact of matters that are
inherently uncertain. Actual effects on our financial position and results of
operations may vary significantly from expected results if the judgments and
assumptions underlying the estimates prove to be inaccurate. The critical
accounting policies requiring such subjectivity are discussed below.
Percentage of Completion Accounting
Significant reliance is placed upon estimates of future job costs in computing
revenue and subsequent net income under the percentage of completion method of
revenue recognition for the designing, building and installation of heating,
ventilation and air-conditioning systems and other construction services by
subsidiaries in the Energy Services segment. This accounting method measures the
percentage of costs incurred and accrued to date for each contract to the
estimated total costs for each contract at completion. These estimates are based
upon available information at the time of review, and changes in estimates
resulting in additional future costs to complete projects can result in reduced
margins or loss contracts. Provisions for estimated losses on uncompleted
contracts are made in the period such losses are determined. Changes in job
performance, job conditions and estimated profitability are recognized in the
period that the revisions are determined.
Valuation of Goodwill
On January 1, 2002, KeySpan adopted SFAS 141, "Business Combinations", and SFAS
142 "Goodwill and Other Intangible Assets". The key concepts from the two
interrelated Statements include mandatory use of the purchase method when
accounting for business combinations, discontinuance of goodwill amortization, a
revised framework for testing goodwill impairment at a "reporting unit" level,
and new criteria for the identification and potential amortization of other
intangible assets.
Other changes to existing accounting standards involve a requirement to test
goodwill for impairment at least annually. The initial impairment test was to be
performed within six months of adopting SFAS 142 using a discounted cash flow
method, compared to a undiscounted cash flow method allowed under a previous
standard. Any amounts impaired using data as of January 1, 2002, was to be
recorded as a "Cumulative Effect of an Accounting Change". Any amounts impaired
using data after the initial adoption date will be recorded as an operating
expense.
KeySpan records goodwill on purchase transactions, representing the excess of
acquisition cost over the fair value of net assets acquired. In testing for
goodwill impairment under SFAS 142, significant reliance is placed upon
estimated future cash flows requiring broad assumptions and significant judgment
by management. Cash flow estimates are determined based upon future commodity
prices, customer rates, customer demand, operating costs, rate relief from
regulators, customer growth and many 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.
During the second quarter of 2002, we completed our analysis for all the
reporting units and have determined that no consolidated impairment exists. This
determination of impairment was done at the reporting unit level, which we
considered to be virtually the same as our financial reporting segments. We will
conduct an annual review (in the fourth quarter) of our investments to determine
if events or circumstances warrant new appraisals to be conducted to support the
carrying value of our assets.
Valuation of Derivative Instruments
We employ derivative instruments to hedge a portion of our exposure to commodity
price risk and interest rate risk, as well as to hedge the cash flow variability
associated with a portion of our electric energy sales from the Ravenswood
facility. 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. However, the oil derivative
instruments we employ to hedge the purchase price on a portion of the oil used
to fuel the Ravenswood facility are not exchange traded. We use industry
published oil indices for No. 6 grade fuel oil to value these oil swap
contracts.
As mentioned, we also engage in the use of derivative instruments to hedge the
cash flow variability associated with a portion of our electric energy sales
from the Ravenswood facility. In addition, our Canadian subsidiary uses swap
instruments to lock-in the purchase price on the purchase of electricity needed
to operate its gas processing plants. These arrangements are also non-exchange
traded and we use NYISO-location zone and other local published indices to value
these outstanding derivatives. For collar transactions relating to natural gas
sales associated with our gas exploration and production subsidiaries, we use
standard NYMEX quotes, as well as Black- Scholes valuations to calculate the
fair value of these instruments.
Finally, we also had interest rate swap agreements in which approximately $1.3
billion of fixed rate debt was effectively converted to floating rate debt. The
fair value of these derivative instruments was provided to us by third party
appraisers and represents the present value of estimated future cash-flows based
on a forward interest rate curve for the life of the derivative instrument.
All fair value measurements, whether calculated using standard NYMEX quotes or
other valuation techniques, are subjective and subject to fluctuations in
commodity prices, interest rates and overall economic market conditions and, as
a result, our fair value measurements may not be precise and can fluctuate
significantly from period to period. (See Note 6 to the Consolidated Financial
Statements "Derivative Financial Instruments" for a further description of the
instruments.)
Full Cost Accounting
Our gas exploration and production subsidiaries use the full cost method to
account for their natural gas and oil properties. Under full cost accounting,
all costs incurred in the acquisition, exploration and development of natural
gas and oil reserves are capitalized into a "full cost pool". Capitalized costs
include costs of all unproved properties, internal costs directly related to
natural gas and oil activities and capitalized interest.
Under full cost accounting rules, total capitalized costs are limited to a
ceiling equal to the present value of future net revenues, discounted at 10%,
plus the lower of cost or fair value of unproved properties less income tax
effects (the "ceiling limitation"). A quarterly ceiling test is performed to
evaluate whether the net book value of the full cost pool exceeds the ceiling
limitation. If capitalized costs (net of accumulated depreciation, depletion and
amortization) less deferred taxes are greater than the discounted future net
revenues or ceiling limitation, a write-down or impairment of the full cost pool
is required. A write-down of the carrying value of the full cost pool is a
non-cash charge that reduces earnings and impacts stockholders' equity in the
period of occurrence and typically results in lower depreciation, depletion and
amortization expense in future periods. Once incurred, a write-down is not
reversible at a later date.
The ceiling test is calculated using natural gas and oil prices in effect as of
the balance sheet date, held constant over the life of the reserves. Our gas
exploration and production subsidiaries use derivative financial instruments
that qualify for hedge accounting under Statement of Financial Accounting
Standards ("SFAS") 133 to hedge against the volatility of natural gas prices. In
accordance with current SEC guidelines, these derivatives are included in the
estimated future cash flows in the ceiling test calculation. In calculating the
ceiling test at September 30, 2002, our subsidiaries estimated that a full cost
ceiling "cushion" existed, whereby the carrying value of the full cost pool was
less that the ceiling limitation. No writedown is required when a cushion
exists. Natural gas prices continue to be volatile and the risk that a write
down to the full cost pool will be required increases when natural gas prices
are depressed or if there are significant downward revisions in estimated proved
reserves.
Natural gas and oil reserve quantities represent estimates only. Any estimates
of natural gas and oil reserves and their values are inherently uncertain,
including many factors beyond our control. The accuracy of any reserve estimate
is a function of the quality of available data and of engineering and geological
interpretation and judgment. In addition, estimates of reserves may be revised
based upon actual production, results of future development and exploration
activities, prevailing natural gas and oil prices, operating costs and other
factors, which revision may be material. Reserve estimates are highly dependent
upon the accuracy of the underlying assumptions. Actual future production may be
materially different from estimated reserve quantities and the differences could
materially affect future amortization of natural gas and oil properties.
Accounting for the Effects of Rate Regulation on Gas Distribution Operations
The accounting records for KeySpan's six regulated gas utilities are maintained
in accordance with the Uniform System of Accounts prescribed by the Public
Service Commission of the State of New York ("NYPSC"), the New Hampshire Public
Utilities Commission, and the Massachusetts Department of Telecommunications and
Energy ("DTE").
Our financial statements reflect the ratemaking policies and orders of these
regulators in conformity with generally accepted accounting principles for
rate-regulated enterprises. Four of our six regulated gas utilities (KEDNY,
KEDLI, Boston Gas Company and EnergyNorth Natural Gas, Inc.) are subject to the
provisions of SFAS 71, "Accounting for the Effects of Certain Types of
Regulation." This statement recognizes the actions of regulators, through the
ratemaking process, to create future economic benefits and obligations affecting
rate-regulated companies.
In separate merger-related orders issued by the DTE, the base rates charged by
Colonial Gas Company and Essex Gas Company have been frozen at their current
levels for a ten-year period. Due to the length of these base rate freezes, the
Colonial and Essex Gas Companies had previously discontinued the application of
SFAS 71.
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 are currently evaluating various options that may be available to
us including but not limited, to extending the existing rate plans or proposing
new plans. 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.
Regulation and Rate Matters
Gas Matters
On March 27, 2002, we filed notice, as required, with the DTE that we may file a
base rate case and a performance based rate plan for the Boston Gas Company to
replace the plan that expired on October 31, 2002. On May 21, 2002, we filed
with the DTE a request to extend the existing performance based rate plan for an
additional term of one year. This request was denied by the DTE in early
September 2002.
The rate agreement for KEDLI expired in November 2000 and the rate agreement for
KEDNY expired September 30, 2002. Under the terms of these agreements, gas
distribution rates and all other provisions will remain in effect. At this time,
we are currently evaluating various options that may be available to us
regarding all of our gas distribution rate plans including but not limited to,
extending the existing rate plans or proposing new rate plans.
For additional discussion of our current gas distribution rate agreements, see
KeySpan's Annual Report on Form 10K for the year ended December 31, 2001, 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, provides us with, among other things, authorization to
do the following through December 31, 2003 (the "Authorization Period"): (a)
subject to an aggregate amount of $5.1 billion, (i) maintain existing financing
agreements, (ii) issue and sell up to $1.5 billion of additional securities in
compliance with certain defined parameters, (iii) issue additional guarantees
and other forms of credit support in an aggregate amount of $2.0 billion at any
time in addition to any such securities, guarantees and credit support
outstanding or existing as of November 8, 2000, and (iv) amend, review, extend,
supplement or replace any of the foregoing; (b) issue shares of common stock or
reissue shares of common stock held in treasury under dividend reinvestment and
stock-based management incentive and employee benefit plans; (c) maintain
existing and enter into additional hedging transactions with respect to
outstanding indebtedness in order to manage and minimize interest rate costs;
(d) invest up to 250% of our consolidated retained earnings in exempt wholesale
generators and foreign utility companies; and (e) pay dividends out of capital
and unearned surplus as well as paid-in-capital with respect to certain
subsidiaries, subject to certain limitations. As previously indicated, we have
filed an application with the SEC seeking authority to issue and sell up to an
aggregate $2.2 billion of additional securities (a $700 million increase above
the existing authorization), as well as authorization to invest up to an
aggregate $2.2 billion in exempt wholesale generators.
In addition, we have committed that during the Authorization Period, our common
equity will be at least 30% of our consolidated capitalization and each of our
utility subsidiaries' common equity will be at least 30% of such entity's
capitalization. At September 30, 2002 our consolidated common equity was 33% of
our consolidated capitalization, including commercial paper.
Environmental Matters
KeySpan is subject to various federal, state and local laws and regulatory
programs related to the environment. Ongoing environmental compliance
activities, which have not been material, are charged to operation and
maintenance activities. We estimate that the remaining cost of our manufactured
gas plant ("MGP") related environmental cleanup activities, including costs
associated with the Ravenswood facility, will be approximately $200.9 million
and we have recorded a related liability for such amount. We have also recorded
an additional $41.2 million liability, representing the estimated environmental
cleanup costs related to a former coal tar processing facility. Further, as of
September 30, 2002, we have expended a total of $60.8 million. (See Note 4 to
the Consolidated Financial Statements, "Environmental Matters").
Credit Risk
We are exposed to credit risk arising from the potential that our
counter-parties 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 gas production companies.
In addition to regional concentration of credit risk due to receivables from
residential, commercial and industrial customers in New York and New England, we
also have concentrations of credit risk from LIPA, our largest customer, and
from energy companies. Concentration of energy company counter-parties may
impact overall exposure to credit risk in that our counter-parties may be
similarly impacted by changes in economic, regulatory or other considerations.
We actively monitor the credit profile of our major counter-parties 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 limit our credit exposure by restricting new
transactions with the counter-party, requiring additional collateral or credit
support and negotiating the early termination of certain agreements.
Cautionary Statement Regarding Forward-Looking Statements
Certain statements contained in this Quarterly Report on Form 10-Q concerning
expectations, beliefs, plans, objectives, goals, strategies, future events or
performance and underlying assumptions and other statements that are other than
statements of historical facts, are "forward-looking statements" within the
meaning of Section 21E of the Securities Exchange Act of 1934, as amended.
Without limiting the foregoing, all statements under the captions "Item 2.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Item 3. Quantitative and Qualitative Disclosures About Market
Risk" relating to our future outlook, anticipated capital expenditures, future
cash flows and borrowings, pursuit of potential future acquisition opportunities
and sources of funding, are forward-looking statements. Such forward-looking
statements reflect numerous assumptions and involve a number of risks and
uncertainties and actual results may differ materially from those discussed in
such statements.
Among the factors that could cause actual results to differ materially are:
- volatility of energy prices, as well as natural gas and fuel prices
used to generate electricity;
- fluctuations in weather and in gas and electric prices;
- general economic conditions, especially in the Northeast United
States;
- our ability to successfully reduce our cost structure and operate
efficiently;
- 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;
- credit worthiness 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;
- 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
KeySpan is subject to various risks and uncertainties associated with its
operations. The most significant of which involves the evolution of the gas
distribution and electric industries towards a more competitive and deregulated
environment. In addition, KeySpan is exposed to commodity price risk, interest
rate risk and, to much less degree, foreign currency translation risk. Below is
an update of the various risks associated with KeySpan's operations.
Additionally, see KeySpan's Annual Report on Form 10K for the year ended
December 31, 2001 Item 7A "Quantitative and Qualitative Disclosures About Market
Risk".
Regulatory Issues and Competitive Environment
Gas Distribution
On May 23, 2002, the NYPSC issued an Order Adopting Terms of Gas Restructuring
Joint Proposal Petition of KeySpan Energy Delivery New York and KeySpan Energy
Delivery Long Island for a Multi-Year Restructuring Agreement ("Joint
Proposal"). The Joint Proposal did not alter base rate levels, but established a
merchant function backout credit of $.21/dth and $.19/dth for KeySpan Energy
Delivery New York and KeySpan Energy Delivery Long Island, respectively. These
credits are designed to lower transportation rates charged to transportation
only customers. These credits were based on established levels of projected
avoided costs and levels of customer migration to non-utility commodity service.
Lost revenues resulting from application of these credits will be recovered from
firm gas sales customers.
Electric Industry
The Ravenswood Facility and our New York City Operations
The NYISO's New York City local reliability rules currently require that 80% of
the electric capacity needs of New York City be provided by "in-City"
generators. As additional, more efficient electric power plants are built in New
York City and the surrounding areas, the requirement that 80% of in-City load be
served by in-City generators could be modified. Construction of new transmission
facilities could also cause significant changes to the market. If generation
and/or transmission facilities are constructed, and/or the availability of our
Ravenswood facility deteriorates, then the capacity and energy sales volumes
could be adversely affected. We cannot predict, however, when or if new power
plants or transmission facilities will be built or the nature of the future New
York City energy requirements or market design.
Regional Transmission Organizations and Standard Market Design
During 2001, the Federal Energy Regulatory Commission ("FERC") issued several
orders and began several proceedings related to the development of Regional
Transmission Organizations ("RTO") and the design of the wholesale energy
markets. The details of how RTOs will be formed are currently evolving. On July
31, 2002, FERC issued a Notice of Proposed Rulemaking ("NOPR") intended to
establish a standardized market design and rules for competitive wholesale
electric markets ("Standard Market Design" or "SMD"). These rules would apply to
transmission owners ("TOs"), independent system operators ("ISOs"), and RTOs.
The SMD is intended to create: (i) genuine wholesale competition; (ii) efficient
transmission systems; (iii) the right pricing signals for investment in
transmission and generation facilities; and (iv) more customer options. How the
SMD will be implemented will be based on FERC's final rules in this regard, as
well as the subject of various compliance filings by TOs, ISOs, and RTOs. We do
not know how the markets will develop nor how these proposed changes will impact
the operations of the NYISO or its market rules. Furthermore, we are unable to
determine to what extent, if any, this process will impact the Ravenswood
facility's financial condition, results of operations or cash flow.
New York Independent System Operator Matters
On May 31, 2002, FERC approved the NYISO's mitigation plan ("the Plan"). The
Plan retains existing mitigation measures such as $1,000/MWhr energy price caps,
non-spinning reserve bid caps, in-City capacity and energy mitigation measures,
the day ahead Automated Mitigation Procedure ("AMP"), and the NYISO's general
mitigation authority. In addition, the Plan implements a new in-City real time
automated mitigation procedure. Although prices for various energy products in
the NYISO markets have softened, it is not known to what extent each of these
proceedings and revised rules may impact the Ravenswood facility's financial
condition, results of operations or cash flows.
Commodity Contracts and Electric 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. Hedging objectives and strategies have remained
substantially unchanged from year-end.
Houston Exploration has utilized collars, as well as over- the- counter ("OTC")
swaps to hedge the cash flow variability associated with forecasted sales of a
portion of its natural gas production. As of October 31, 2002, Houston
Exploration has hedged approximately 65% of its estimated 2002 and 2003
production. Further, Houston Exploration may enter into additional derivative
positions for 2003 and 2004. Houston Exploration used standard New York
Mercantile Exchange ("NYMEX") futures prices and published volatility in its
Black-Scholes calculation to value its outstanding derivatives. The maximum
length of time over which Houston Exploration has hedged such cash flow
variability is through December 2003. The estimated amount of losses associated
with such derivative instruments that are reported in Accumulated Other
Comprehensive Income and that are expected to be reclassified into earnings over
the next twelve months is $14.6 million.
KeySpan has also employed standard NYMEX gas futures contracts, as well as oil
swap derivative contracts, to hedge the cash flow variability of a portion of
forecasted purchases of natural gas and fuel oil that will be consumed at the
Ravenswood facility. Natural gas basis swaps are also utilized to hedge
forecasted purchases of natural gas transportation. The maximum length of time
over which we have hedged cash flow variability associated with: (i) forecasted
purchases of natural gas is October 2003; (ii) forecasted purchases of fuel oil
is through April 2004; and (iii) forecasted purchases of natural gas
transportation is through December 2003. 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 Accumulated
Other Comprehensive Income and that are expected to be reclassified into
earnings over the next twelve months is $4.1 million.
Our retail gas and electric marketing subsidiary, our domestic gas distribution
operations and KeSpan 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 2003. The
estimated amount of gains associated with such derivative instruments that are
reported in Accumulated Other Comprehensive Income and that are expected to be
reclassified into earnings over the next twelve months is $2.5 million.
We have also engaged in the use of cash-settled swap instruments to hedge the
cash flow variability associated with a portion of 2002 peak electric energy
sales from the Ravenswood facility. All hedge positions for the summer of 2002
have been settled. We currently have a number of remaining derivatives that are
employed to hedge cash flow variability through December 2002. We used
NYISO-location zone published indices to value these outstanding derivatives.
The estimated amount of gains associated with such derivative instruments that
are reported in Accumulated Other Comprehensive Income and that are expected to
be reclassified into earnings over the next twelve months is $2.4 million.
KeySpan Canada also has employed electricity swap contracts to lock-in the
purchase price of electricity needed to operate its gas processing plants. These
contracts are not exchange- traded and local published indices were used to
value these outstanding swap agreements. The maximum length of time over which
we have hedged such cash flow variability is through December 2003. The
estimated amount of losses associated with such derivative instruments that are
reported in Accumulated Other Comprehensive Income and that are expected to be
reclassified into earnings over the next twelve months is $1.7 million.
The following tables set forth selected financial data associated with these
derivative financial instruments noted above that were outstanding at September
30, 2002.
- -------------------------------- ------------ ------------- ------------ ------------- --------------- -------------- --------------
Year of Volumes Fixed Price Current Fair Value
Type of Contract Maturity mmcf Floor $ Ceiling $ $ Price $ ($000)
- -------------------------------- ------------ ------------- ------------ ------------- --------------- -------------- --------------
Gas
Collars 2002 14,720 3.56 5.14 - 3.69 - 4.32 (1,141)
2003 32,350 3.34 4.97 - 3.90 - 4.40 (2,498)
Swaps / Futures-Short
Natural Gas 2002 3,191 - - 3.01 3.69 - 4.32 (2,662)
2003 15,208 - - 3.19 3.90 - 4.40 (12,394)
Swaps / Futures-Long
Natural Gas 2002 2,990 - - 2.68 - 4.24 3.90 - 4.32 1,227
2003 8,210 - - 3.10 - 4.35 3.90 - 4.40 2,359
- -------------------------------- ------------ ------------- ------------ ------------- --------------- -------------- --------------
76,669 (15,109)
- -------------------------------- ------------ ------------- ------------ ------------- --------------- -------------- --------------
- ------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
Type of Contract Year of Volumes Fair Value
Maturity Barrels Fixed Price $ Current Price $ ($000)
- ------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
Oil
Swaps - Long Fuel Oil 2002 146,994 19.75 - 26.40 28.65 - 29.00 1,024
2003 307,822 20.10 - 26.72 23.01 - 28.96 1,613
2004 5,404 20.50 - 23.70 22.84 - 23.33 7
- ------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
460,220 2,644
- ------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
- -------------------------- ------------- ----------------- ----------------------- -------------- --------------- ------------------
Type of Contract Year of Current Estimated Fair Value
Maturity MWh Fixed Profit /Price $ Price $ Profit $ ($000)
- -------------------------- ------------- ----------------- ----------------------- -------------- --------------- ------------------
Electricity
Tolling Arrangements 2002 102,400 26.00 - 1.61 - 3.85 2,383
Swaps - Long 2002 17,664 56.07 - 57.33 30.87 - (429)
2003 70,080 56.07 - 57.33 29.61 - (1,791)
- -------------------------- ------------- ----------------- ----------------------- -------------- --------------- ------------------
190,144 163
- -------------------------- ------------- ----------------- ----------------------- -------------- --------------- ------------------
NYMEX futures are also used to economically hedge the cash flow variability
associated with the purchase of fuel for a portion of our fleet vehicles.
Further, KeySpan Canada has a portfolio of financially-settled natural gas
collars and natural gas liquid swap transactions. Such contracts are executed by
KeySpan Canada to: (i) synthetically fix the price that is paid or received by
KeySpan Canada for certain physical transactions involving natural gas and
natural gas liquids and (ii) transfer the price exposure of such instruments to
other trading partners. These derivative financial instruments do not qualify
for hedge accounting under SFAS 133. At September 30, 2002, these instruments
had a favorable net mark-to-market value of $0.4 million, which was recorded on
the Consolidated Balance Sheet and recorded to earnings for the quarter and nine
months ended September 30, 2002.
Non-firm Gas Sales Derivative Instruments: Utility tariffs applicable to certain
large-volume customers permit gas to be sold at prices established monthly
within a specified range expressed as a percentage of prevailing alternate fuel
oil prices. We use natural gas swap contracts, with offsetting positions in fuel
oil swap contracts of equivalent energy value, to hedge the cash-flow
variability of specified portions of gas purchases and sales. Currently, no
derivative transactions outstanding correspond to this particular price risk
strategy, although we intend to enter into derivative instruments of this nature
during the fourth quarter of 2002 if market conditions warrant.
Firm Gas Sales Derivative Instruments - Regulated Utilities: We have also
utilized derivative financial instruments to reduce the cash flow variability
associated with the purchase price for a portion of future natural gas
purchases. Our strategy is to minimize fluctuations in firm gas sales prices to
our regulated firm gas sales customers in our New York and New Hampshire service
territories. Since these derivative instruments are employed to reduce the
variability of the purchase price of natural gas to be sold to regulated firm
gas sales customers, the accounting for these derivative instruments is subject
to SFAS 71. Therefore, changes in the market value of these derivatives have
been recorded as a Regulatory Asset or Regulatory Liability on the Consolidated
Balance Sheet. Gains or losses on the settlement of these contracts are
initially deferred and then refunded to or collected from our firm gas sales
customers during the appropriate winter heating season consistent with
regulatory requirements.
The following table sets forth selected financial data associated with these
derivative financial instruments that were outstanding at September 30, 2002.
- ------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
Type of Contract Year of Maturity Volumes Fair Value
Mmcf Fixed Price $ Current Price $ ($000)
- ------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
Gas
Options 2002 7,980 3.85 - 4.50 4.23 1,549
2003 12,960 3.85 - 4.50 4.27 2,946
Swaps - Long 2002 300 4.11 4.24 42
2003 600 4.11 4.21 59
- ------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
21,840 4,596
- ------------------------------- ----------------- ----------------- ----------------------- --------------------- ------------------
Other Commodity Derivative Instruments: On April 1, 2002 we implemented
Derivative Implementation Group (DIG) Issue C15 and C16 of Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" as amended and interpreted, incorporating SFAS 137 and
138 and certain implementation issues (collectively "SFAS 133"). Issue C15
establishes new criteria that must be satisfied in order for option-type and
forward contracts in electricity to be exempted as normal purchases and sales,
while Issue C16 relates to the exemption (as normal purchase and normal sales)
of contracts that combine a forward contract and a purchased option contract.
Based upon a review of our physical commodity contracts, we determined that
certain contracts for the physical purchase of natural gas can no longer be
exempted as normal purchases from the requirements of SFAS 133. At September 30,
2002, the fair value of these contracts was $2.0 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: At September 30, 2002, we had interest
rate swap agreements in which approximately $1.3 billion of fixed rate debt had
been synthetically modified to floating rate debt. Under the terms of the
agreements, we received the fixed coupon rate associated with these bonds and
paid the counter-parties a variable interest rate that was reset on a quarterly
basis. These swaps were designated as fair-value hedges and qualified for
"short-cut" hedge accounting treatment under SFAS 133. Through the utilization
of these agreements, we reduced recorded interest expense by $30.5 million for
the nine months ended September 30, 2002.
In early November 2002, we terminated two interest rate swap agreements with an
aggregate notional amount of $1.0 billion and received $81.0 million from our
swap counter-parties, of which $23.0 million represents accrued swap interest.
The difference between the termination settlement amount and the amount of
accrued swap interest, $58.0 million, will be amortized to earnings (as an
adjustment to interest expense) on a level yield basis over the remaining lives
of the originally hedged debt obligations. The remaining swap, which has a
notional amount of $270.0 million, will continue to be accounted for as a fair
value hedge.
The table below summarizes selected financial data associated with these
derivative financial instruments that were outstanding at September 30, 2002.
The fair values of these derivative instruments were provided to us by our swap
counter-parties and represent the present value of expected future cash-flows
associated with such transactions.
The table below summarizes selected financial data associated with these
derivative financial instruments that were outstanding at September 30, 2002.
- -------------------------------------- ------------------- --------------------- ---------------- -------------------- -------------
Average Variable
Maturity Date of Notional Amount Fixed Rate Rate Paid Fair Value
Bond Swaps ($000) Received Year to Date ($000)
- -------------------------------------- ------------------- --------------------- ---------------- -------------------- -------------
Medium Term Notes 2010 500,000 7.625% 4.250% 55,077
Medium Term Notes 2006 500,000 6.150% 3.590% 37,145
Long Term Notes 2023 270,000 8.200% 3.770% 6,843
- -------------------------------------- ------------------- --------------------- ---------------- -------------------- -------------
1,270,000 99,065
- -------------------------------------- ------------------- --------------------- ---------------- -------------------- -------------
Additionally, we also have an interest rate swap agreement that hedges the cash
flow variability associated with the forecasted issuance of a series of
commercial paper offerings. The maximum length of time over which we have hedged
such cash flow variability is through March 2003. The estimated amount of gains
or losses associated with such derivative instruments that are reported in
Accumulated Other Comprehensive Income and that are expected to be reclassified
into earnings over the next twelve months is a loss of $1.6 million.
Weather Derivatives: The utility tariffs associated with the New England gas
distribution operations do not contain a weather normalization adjustment. As a
result, fluctuations from normal weather may have a significant positive or
negative effect on the results of these operations. To mitigate the effect of
fluctuations from normal weather on our financial position and cash flows, we
entered into weather collars during the quarter ended September 30, 2002. These
derivatives will hedge approximately 60% of expected gas throughput of the New
England gas distribution companies during the November 2002 - March 2003 winter
season. The collars have been established with a ceiling that reflects 1% colder
than normal weather and a floor that reflects 7% warmer than normal weather.
KeySpan will be required to make payment to its counter-parties when actual
weather experienced during the November 2002 - March 2003 time frame is 1% or
more colder than normal, based on the 1975 - 1995 20 year avergae. In the event
that actual weather is 7% or more warmer than normal the counter-parties will be
required to make payment to KeySpan. These derivatives will be accounted for by
applying the "intrinsic value method" and are outside the scope of SFAS 133.
Derivative contracts are primarily used to manage exposure to market risk
arising from changes in commodity prices and interest rates. In the event of
nonperformance by a counter-party to a derivative contract, the desired impact
may not be achieved. The risk of a counter-party nonperformance is generally
considered credit risk and is actively managed by assessing each counter-party
credit profile and negotiating appropriate levels of collateral and credit
support. Currently the majority of KeySpan's derivative contracts are with
investment grade companies.
PART II. OTHER INFORMATION
- ---------------------------
Item 1. Legal Proceedings
See Note 10 to the Financial Statements "Legal Matters"
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Within the 90 days prior to the date of this report, KeySpan carried out an
evaluation, under the supervision and with the participation of KeySpan's
management, including KeySpan's Chief Executive Officer and Chief Financial
Officer, of the effectiveness of the design and operation of KeySpan's
disclosure controls and procedures. KeySpan's disclosure controls and procedures
are designed to ensure that information required to be disclosed by KeySpan in
its periodic SEC filings is recorded, processed and reported within the time
periods specific in the SEC's rules and forms. Based upon that evaluation, the
Chief Executive Officer and Chief Financial Officer concluded that KeySpan's
disclosure controls and procedures are effective in timely alerting them to
material information relating to KeySpan (including its consolidated
subsidiaries) required to be included in KeySpan's periodic SEC filings.
Changes In Internal Controls
There were no significant changes in KeySpan's internal controls or in other
factors that could significantly affect these controls subsequent to the date of
their evaluation.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
10.1*Second Amendment dated as of June 26, 2002, to the Employment Agreement
dated September 10, 1998, between KeySpan Corporation and Robert B. Catell
99.1*Certification pursuant to 18 U.S.C. 1350, as adopted pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.
99.2*Certification pursuant to 18 U.S.C. 1350, as adopted pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.
(b) Reports on Form 8-K
In KeySpan's report on Form 8-K dated July 9, 2002, we reported that we had
issued a press release concerning the completion of the sale of our subsidiary,
Midland Enterprises, LLC ("Midland"), a U.S. inland marine transportation
company on July2, 2002.
In KeySpan's report on Form 8-K dated July 25, 2002, we reported that we had
issued a press release on July 25, 2002, concerning, among other things, our
earnings for the quarter ended June 30, 2002.
In KeySpan's report on Form 8-K dated August 14, 2002, we reported that on
August 12, 2002, in accordance with SEC file No. 4-460 and pursuant to Section
21(a)(1) of the Securities Exchange Act of 1934, the Chief Executive Officer and
Chief Financial Officer of KeySpan executed sworn statements which had been
submitted to the Securities and Exchange Commission.
In KeySpan's report on Form 8-K dated October 24, 2002, we reported that we had
issued a press release on October 24, 2002, concerning, among other things, our
earnings for the quarter ended September 30, 2002.
- ----------------------
*Filed Herewith
KEYSPAN CORPORATION AND SUBSIDIARIES
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on behalf of the undersigned
there unto duly authorized.
KEYSPAN CORPORATION
-------------------
(Registrant)
Date: November 7, 2002 /s/ Gerald Luterman
---------------------------
Gerald Luterman
Executive Vice President and
Chief Financial Officer
Date: November 7, 2002 /s/ Ronald S. Jendras
---------------------------
Ronald S. Jendras
Vice President, Controller and
Chief Accounting Officer
Certification Pursuant to Rule 13a-14 and 15d-14 of the Securities and Exchange
Act of 1934
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 officers 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 officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not 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: November 7, 2002
/s/Robert B. Catell
-------------------
Robert B. Catell
Chairman of the Board of Directors
and Chief Executive Officer
Certification Pursuant to Rule 13a-14 and 15d-14 of
the Securities and Exchange Act of 1934
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 officers 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 officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not 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: November 7, 2002
/s/Gerald Luterman
------------------
Gerald Luterman
Executive Vice President and
Chief Financial Officer