3
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
Form 10-Q
(Mark One)
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
- --- ACT OF 1934
For the quarterly period ended June 30, 2002
-------------------------------------------------
OR
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 (I.R.S. Employer Identification No.)
incorporation or organization)
One MetroTech Center, Brooklyn, New York 11201
175 East Old Country Road, Hicksville, New York 11801
----------------------------------------------------------
(Address of principal executive offices) (Zip Code)
(718) 403-1000 (Brooklyn)
(631) 755-6650 (Hicksville)
--- ----------------------------
(Registrant's telephone number, including area code)
(Former name, former address and former fiscal year, if changed since last
report)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
APPLICABLE ONLY TO CORPORATE ISSUERS:
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class of Common Stock Outstanding at July 31, 2002
- --------------------------- -----------------------------
$.01 par value 141,407,660
KEYSPAN CORPORATION AND SUBSIDIARIES
INDEX
Part I. FINANCIAL INFORMATION Page No.
--------
Item 1. Financial Statements
Consolidated Balance Sheet -
June 30, 2002 and December 31, 2001 3
Consolidated Statement of Income -
Three and Six Months Ended June 30, 2002 and 2001
5
Consolidated Statement of Cash Flows -
Six Months Ended June 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 26
Item 3. Quantitative and Qualitative Disclosures
About Market Risk 52
Part II. OTHER INFORMATION
Item 1. Legal Proceedings 58
Item 4. Submission of Matters to a Vote of Security Holders 59
Item 6. Exhibits and Reports on Form 8-K 60
Signatures 61
CONSOLIDATED BALANCE SHEET
(Unaudited)
(In Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------------------------
June 30, 2002 December 31, 2001
-------------------------------- --------------------------------
ASSETS
Current Assets
Cash and cash equivalents $ 137,599 $ 159,252
Accounts receivable 1,236,016 1,344,898
Allowance for uncollectible accounts (88,432) (72,299)
Gas in storage, at average cost 239,403 334,999
Materials and supplies, at average cost 106,652 105,693
Other 220,320 125,944
-------------------------------- --------------------------------
1,851,558 1,998,487
-------------------------------- --------------------------------
Net Assets Held for Disposal 190,135 191,055
-------------------------------- --------------------------------
Equity Investments and Other 241,342 223,249
-------------------------------- --------------------------------
Property
Gas 5,877,621 5,704,857
Electric 1,840,067 1,629,768
Other 418,675 400,643
Accumulated depreciation (2,647,591) (2,533,466)
Gas exploration and production, at cost 2,348,391 2,200,851
Accumulated depletion (882,721) (796,722)
-------------------------------- --------------------------------
6,954,442 6,605,931
-------------------------------- --------------------------------
Deferred Charges
Regulatory assets 429,077 458,191
Goodwill, net of amortization 1,786,561 1,782,826
Other 496,415 529,867
-------------------------------- --------------------------------
2,712,053 2,770,884
-------------------------------- --------------------------------
Total Assets $ 11,949,530 $ 11,789,606
================================ ================================
See accompanying Notes to the Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEET
(Unaudited)
(In Thousands of Dollars)
- ----------------------------------------------------------------------------------------------------------------------------------
June 30, 2002 December 31, 2001
-------------------------------- ------------------------------
LIABILITIES AND CAPITALIZATION
Current Liabilities
Current redemption of long term debt $ 1,480 $ 993
Accounts payable and accrued expenses 1,006,073 1,091,430
Commercial paper 570,655 1,048,450
Dividends payable 64,273 63,442
Taxes accrued 11,068 50,281
Customer deposits 36,402 36,151
Interest accrued 85,169 93,962
-------------------------------- ------------------------------
1,775,120 2,384,709
-------------------------------- ------------------------------
Deferred Credits and Other Liabilities
Regulatory liabilities 68,790 39,442
Deferred income tax 811,349 598,072
Postretirement benefits and other reserves 708,320 694,680
Other 149,857 207,992
-------------------------------- ------------------------------
1,738,316 1,540,186
-------------------------------- ------------------------------
Capitalization
Common stock, $.01 par value, authorized 450,000,000
shares; outstanding 140,570,579 and 2,995,501 2,995,797
137,251,386 shares stated at
Retained earnings 498,751 452,206
Other comprehensive income (27,997) 4,483
Treasury stock purchased (509,988) (561,884)
-------------------------------- ------------------------------
Total common shareholders equity 2,956,267 2,890,602
Preferred stock 84,077 84,077
Long-term debt 5,192,217 4,697,649
-------------------------------- ------------------------------
Total Capitalization 8,232,561 7,672,328
-------------------------------- ------------------------------
Minority Interest in Subsidiary Companies 203,533 192,383
-------------------------------- ------------------------------
Total Liabilities and Capitalization $ 11,949,530 $ 11,789,606
================================ ==============================
See accompanying Notes to the Consolidated Financial Statements
CONSOLIDATED STATEMENT OF INCOME
(Unaudited)
(In Thousands of Dollars, Except Per Share Amounts)
- ------------------------------------------------------------------------------------------------------------------------------------
Three Months Three Months Six Months Six Months
Ended Ended Ended Ended
June 30, 2002 June 30, 2001 June 30, 2002 June 30, 2001
- ------------------------------------------------------------------------------------------------------------------------------------
Revenues
Gas Distribution $ 521,822 $ 620,685 $ 1,744,791 $ 2,374,329
Electric Services 354,756 357,904 669,440 701,275
Energy Services 229,311 232,771 470,870 551,864
Gas Exploration 88,274 103,720 162,988 235,731
Energy Investments 21,942 24,222 39,575 51,191
------------------ -------------------- ------------------ ------------------
Total Revenues 1,216,105 1,339,302 3,087,664 3,914,390
------------------ -------------------- ------------------ ------------------
Operating Expenses
Purchased gas for resale 249,942 348,349 899,299 1,545,698
Fuel and purchased power 93,292 146,357 177,664 289,657
Operations and maintenance 548,094 533,803 1,041,660 1,037,686
Depreciation, depletion and amortization 127,463 121,578 253,460 252,742
Operating taxes 87,388 100,835 207,781 242,825
------------------ -------------------- ------------------ ------------------
Total Operating Expenses 1,106,179 1,250,922 2,579,864 3,368,608
------------------ -------------------- ------------------ ------------------
Operating Income 109,926 88,380 507,800 545,782
------------------ -------------------- ------------------ ------------------
Other Income and (Deductions)
Minority interest (6,138) (11,869) (10,569) (27,280)
Other income 8,484 8,713 21,102 28,826
------------------ -------------------- ------------------ ------------------
Total Other Income 2,346 (3,156) 10,533 1,546
------------------ -------------------- ------------------ ------------------
Income Before Interest Charges 112,272 85,224 518,333 547,328
and Income Taxes ------------------ -------------------- ------------------ ------------------
Interest Charges 70,054 91,927 142,661 185,230
------------------ -------------------- ------------------ ------------------
Income Taxes
Current 5,587 (24,825) (78,031) 88,574
Deferred 7,457 28,539 209,898 59,827
------------------ -------------------- ------------------ ------------------
Total Income Taxes 13,044 3,714 131,867 148,401
------------------ -------------------- ------------------ ------------------
Preferred stock dividend requirements 1,476 1,476 2,952 2,952
------------------ -------------------- ------------------ ------------------
Earnings (Loss) from Continuing Operations 27,698 (11,893) 240,853 210,745
------------------ -------------------- ------------------ ------------------
Discontinued Operations
Income from operations, net of tax - 3,892 - 4,553
Loss on Disposal, net of tax of $13,050 (19,662) - (19,662) -
------------------ -------------------- ------------------ ------------------
Loss from Discontinued Operations (19,662) 3,892 (19,662) 4,553
------------------ -------------------- ------------------ ------------------
Earnings (Loss) for Common Stock $ 8,036 $ (8,001) $ 221,191 $ 215,298
================== ==================== ================== ==================
Basic Earnings (Loss) Per Share from
Continuing Operations 0.20 (0.09) 1.71 1.54
Basic Earnings (Loss) Per Share from
Discontinued Operations (0.14) 0.03 (0.14) 0.03
------------------ -------------------- ------------------ ------------------
Basic Earnings (Loss) Per Share $ 0.06 $ (0.06) $ 1.57 $ 1.57
================== ==================== ================== ==================
Diluted Earnings (Loss) Per Share from
Continuing Operations 0.20 (0.09) 1.70 1.52
Diluted Earnings (Loss) Per Share from
Discontinued Operations (0.14) 0.03 (0.14) 0.03
================== ==================== ================== ==================
Diluted Earnings (Loss) Per Share $ 0.06 $ (0.06) $ 1.56 $ 1.55
================== ==================== ================== ==================
Average Common Shares Outstanding (000) 141,063 137,916 140,551 137,438
Average Common Shares Outstanding Diluted (000) 142,156 139,361 141,706 138,872
See accompanying Notes to the Consolidated Financial Statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
(In Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------------------------------
Six Months Six Months
Ended Ended
June 30, 2002 June 30, 2001
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Earnings from continuing operations $ 243,805 $ 213,697
Adjustments to reconcile net income to net cash
Depreciation, depletion and amortization 253,460 252,742
Deferred income tax 26,741* 59,827
Income from equity investments (7,409) (6,294)
Dividends from equity investments 120 -
Provision for loss on contracting business - 28,012
Changes in assets and liabilities
Accounts receivable 125,015 321,673
Materials and supplies, fuel oil and gas in storage 94,637 24,518
Accounts payable and accrued expenses (48,213) (425,263)
Interest accrued (8,793) 52,252
Other 4,394* 33,706
---------------------------- --------------------------------
Net Cash Provided by Operating Activities 683,757 554,870
---------------------------- --------------------------------
Investing Activities
Capital expenditures (595,503) (424,807)
Proceeds from sale of assets - 18,458
Other - (7,822)
---------------------------- --------------------------------
Net Cash Used in Investing Activities (595,503) (414,171)
---------------------------- --------------------------------
Financing Activities
Issuance of treasury stock 51,896 64,107
Issuance of long-term debt 507,754 708,000
Payment of long-term debt (54,590) (152,000)
Payment of commercial paper (477,795) (497,033)
Preferred stock dividends paid (2,952) (2,952)
Common stock dividends paid (124,684) (121,937)
Other (9,536) 5,102
---------------------------- --------------------------------
Net Cash (Used in) Provided By Financing Activities (109,907) 3,287
---------------------------- --------------------------------
Net (decrease) increase in Cash and Cash Equivalents $ (21,653) $ 143,986
============================ ================================
Cash and cash equivalents at beginning of period $ 159,252 $ 83,329
Net (decrease) increase in cash and cash equivalents (21,653) 143,986
---------------------------- --------------------------------
Cash and Cash Equivalents at End of Period $ 137,599 $ 227,315
============================ ================================
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"). We operate six
regulated utilities that distribute natural gas to approximately 2.5 million
customers in New York City, Long Island, Massachusetts and New Hampshire, making
us the fifth largest gas distribution company in the United States and the
largest in the Northeast. We also own and operate electric generating plants in
Nassau and Suffolk Counties on Long Island and in Queens County in New York
City. Under contractual arrangements, we provide power, electric transmission
and distribution services, billing and other customer services for approximately
one million electric customers of the Long Island Power Authority ("LIPA"). Our
other subsidiaries are involved in gas and oil exploration and production; gas
storage; wholesale and retail gas and electric marketing; appliance service;
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
June 30, 2002, and the results of our operations for the three and six months
ended June 30, 2002 and June 30, 2001, as well as cash flows for the six months
ended June 30, 2002 and June 30, 2001. The accompanying financial statements
should be read in conjunction with the consolidated financial statements and
notes included in our Annual Report on Form 10-K for the year ended December 31,
2001, as amended, as well as our March 31, 2002 10Q. 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 options outstanding at June 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 84,077 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 months ended
June 30, 2002 since to do so would have been anti-dilutive.
Under the requirements of Statement of Financial Accounting Standards ("SFAS")
No. 128, "Earnings Per Share", our basic and diluted EPS are as follows:
(In Thousands of Dollars, Except Per Share)
- ------------------------------------------------------------- ------------------- --------------------------------------------------
Three Months Ended Three Months Ended Six Months Ended Six Months Ended
June 30, 2002 June 30, 2001 June 30, 2002 June 30, 2001
- ------------------------------------------------------------- ------------------ ---------------- --------------- --------------
Earnings (loss) from Continuing Operations $ 27,698 $ (11,893) $ 240,853 $ 210,745
Interest savings on convertible preferred stock - 142 284 284
Houston Exploration dilution (options) (129) (310) (225) (859)
- ------------------------------------------------------------- ------------------ ---------------- --------------- --------------
Earnings (loss) for common stock - adjusted 27,569 (12,061) 240,912 210,170
- ------------------------------------------------------------- ------------------ ---------------- --------------- --------------
Weighted average shares outstanding (000) 141,063 137,916 140,551 137,438
Add dilutive securities:
Options 1,093 1,201 911 1,190
Convertible preferred stock - 244 244 244
- ------------------------------------------------------------- ------------------ ---------------- --------------- --------------
Total weighted average shares outstanding - assuming dilution 142,156 139,361 141,706 138,872
- ------------------------------------------------------------- ------------------ ---------------- --------------- --------------
Basic Earnings (Loss) Per Share from Continuing Operations $ 0.20 $ (0.09) $ 1.71 $ 1.54
- ------------------------------------------------------------- ------------------ ---------------- --------------- --------------
Diluted Earnings (Loss) Per Share from Continuing Operations $ 0.20 $ (0.09) $ 1.70 $ 1.52
- ------------------------------------------------------------- ------------------ ---------------- --------------- --------------
2. BUSINESS SEGMENTS
We have four reportable segments: Gas Distribution, Electric Services, Energy
Services and Energy Investments.
The Gas Distribution segment consists of our six 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. We sell all of the energy, capacity and
ancillary services related to the Ravenswood facility to the New York
Independent System Operator ("NYISO") energy markets. Further, we recently
placed two 79 megawatt generating facilities into service, (one in June 2002 and
the other in July 2002) located on Long Island. Currently, our primary electric
generation customers are LIPA and the NYISO energy markets. 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, 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.
Subsidiaries in this segment also hold a 20% equity interest in the Iroquois Gas
Transmission System LP, a pipeline that transports Canadian gas supply to
markets in the Northeastern United States; a 50% interest in the Premier
Transmission Pipeline and a 24.5% interest in Phoenix Natural Gas, both in
Northern Ireland; and investments in certain midstream natural gas assets in
Western Canada through KeySpan Canada. With the exception of KeySpan Canada,
which is consolidated in our financial statements, these subsidiaries are
accounted for under the equity method. Accordingly, equity income from these
investments is reflected in Other Income and (Deductions) in the Consolidated
Statement of Income.
The accounting policies of the segments are the same as those used for the
preparation of the Consolidated Financial Statements. Our segments are strategic
business units that are managed separately because of their different operating
and regulatory environments. Operating results of our segments are evaluated by
management on an earnings before interest and taxes ("EBIT") basis. At June 30,
2002, the total assets of each reportable segment have not changed materially
from December 31, 2001. To reflect a complete picture of our 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, our 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
June 30, 2002
Unaffiliated Revenue 521,822 354,756 229,311 88,274 21,942 - 1,216,105
Intersegment Revenue - 25 - - - (25) -
Earnings Before Interest
and Taxes 29,243 64,719 (10,252) 23,595 1,266 3,701 112,272
Three Months Ended
June 30, 2001
Unaffiliated Revenue 620,685 357,904 232,771 103,720 24,222 - 1,339,302
Intersegment Revenue - 25 - - - (25) -
Earnings Before Interest
and Taxes 18,924 67,725 (57,040) 43,957 7,148 4,510 85,224
- ------------------------- --------------- ------------ ------------ ------------------ ------------- --------------- ---------------
Eliminating items include intercompany interest income and expense, the
elimination of certain intercompany accounts, as well as activities of our
corporate and administrative areas.
Because of the nature of our Electric Services business, electric revenues are
derived from two large customers - the NYISO and LIPA. Electric Services
revenues from these customers of $354.8 million and $357.9 million for the three
months ended June 30, 2002 and 2001 represent approximately 29% and 27% 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
- ------------------------- ---------------- ------------ ----------- --------------- ------------- ----------------- ----------------
Six Months Ended
June 30, 2002
Unaffiliated Revenue 1,744,791 669,440 470,870 162,988 39,575 - 3,087,664
Intersegment Revenue - 49 - - - (49) -
Earnings Before Interest
and Taxes 358,899 130,364 (19,449) 39,267 6,159 3,093 518,333
Six Months Ended
June 30, 2001
Unaffiliated Revenue 2,374,329 701,275 551,864 235,731 51,191 - 3,914,390
Intersegment Revenue - 50 - - - (50) -
Earnings Before Interest
and Taxes 349,605 133,306 (63,419) 109,473 16,401 1,962 547,328
- ------------------------- ---------------- ------------ ---------- ---------------- ------------- ----------------- ----------------
Eliminating items include intercompany interest income and expense, the
elimination of certain intercompany accounts, as well as activities of our
corporate and administrative areas.
Because of the nature of our Electric Services business, electric revenues are
derived from two large customers - the NYISO and LIPA. Electric Services
revenues from these customers of $669.4 million and $701.3 million for the six
months ended June 30, 2002 and 2001 represent approximately 22% and 18% of our
consolidated revenues, respectively.
3. COMPREHENSIVE INCOME
The table below indicates the components of comprehensive income.
(In Thousands of Dollars)
- ------------------------------------------------------ ----------------------------------------------------------- -----------------
Three Months Ended Three Months Ended Six Months Ended Six Months Ended
June 30, 2002 June 30, 2001 June 30, 2002 June 30, 2001
- ------------------------------------------------------ ------------------ ---------------- ----------------- --------------------
Earnings (Loss) for Common Stock $ 8,036 $ (8,001) $ 221,191 $ 215,298
- ------------------------------------------------------ ------------------ ---------------- ----------------- --------------------
Other comprehensive income (loss), net of tax
Reclassification adjustment for gains
realized in net income (2,998) (212) (10,285) (3,454)
Foreign currency translation adjustments 10,829 1,554 9,116 (8,128)
Unrealized losses on marketable securities (3,195) (4,765) (4,236) (2,148)
Accrued unfunded pension obligation - - (1,132) -
Unrealized (losses) gains on derivative financial
instruments (2,159) 20,124 (25,944) 21,075
- ------------------------------------------------------ ------------------ ---------------- ----------------- --------------------
Other comprehensive income (loss) 2,477 16,701 (32,481) 7,345
- ------------------------------------------------------ ------------------ ---------------- ----------------- --------------------
Comprehensive income $ 10,513 $ 8,700 $ 188,710 $ 222,643
- ------------------------------------------------------ ------------------ ---------------- ----------------- --------------------
Related tax expense (benefit)
Reclassification adjustment for gains
realized in net income (1,614) (114) (5,538) (1,860)
Foreign currency translation adjustments 5,831 837 4,908 (4,376)
Unrealized losses on marketable securities (1,721) (2,566) (2,281) (1,157)
Accrued unfunded pension obligation - - (610) -
Unrealized (losses) gains on derivative financial
instruments (1,163) 10,836 (13,970) 11,348
- -------------------------------------------------------- ----------------- ----------------- ----------------- --------------------
Total tax expense (benefit) $ 1,333 $ 8,993 $ (17,491) $ 3,955
- -------------------------------------------------------- ----------------- ----------------- ----------------- --------------------
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 we purchased the Ravenswood facility 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 $150.3 million, which amount has been accrued by us
as a reasonable estimate of probable cost for known sites. Expenditures incurred
to date by us with respect to these MGP-related sites total $41.0 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. At
June 30, 2002, we have reflected a regulatory asset of $123.9 million for our
New York/Long Island MGP sites.
We are also responsible for environmental obligations associated with the
Ravenswood electric generating facility. The extent of our liability does not
include liabilities arising from the disposal of waste at off-site locations
prior to the acquisition and any monetary fines arising from Consolidated
Edison's pre-closing conduct. Based on information currently available for
environmental contingencies related to the Ravenswood facility acquisition, we
have accrued a $5.0 million liability.
New England Sites. Within the Commonwealth of Massachusetts and the State of New
Hampshire, we are aware of 76 former MGP sites and related facilities within the
existing or former service territories of KEDNE 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 66 MPG
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 $51.7 million, which amount has been
accrued by us as a reasonable estimate of probable cost for known sites.
Expenditures incurred since November 8, 2000 with respect to these MGP-related
activities total $11.5 million.
The Massachusetts Department of Telecommunications and Energy and the New
Hampshire Public Utilities Commission have issued rate orders that provide for
the recovery of site investigation and remediation costs in rates charged to gas
distribution customers. Accordingly, at June 30, 2002, we have reflected a
regulatory asset of $60.0 million for the KEDNE MGP sites. Colonial Gas Company
and Essex Gas Company are not subject to the provisions of Statement of
Financial Accounting Standards ("SFAS") 71 "Accounting for the Effects of
Certain Types of Regulation" and therefore have recorded no regulatory 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 $41.8 million, which
amount has been accrued by us a reasonable estimate of probable costs for known
sites. Expenditures incurred since November 8, 2000 with respect to these sites
total $1.5 million. Additionally, 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 the New York and New England sites and related facilities
identified above are reasonable estimates of likely cost within a range of
reasonable, foreseeable costs. We may be required to investigate and, if
necessary, remediate each of these, or other currently unknown former sites and
related facility sites, the cost of which is not presently determinable but may
be material to our financial position, results of operations or liquidity.
Remediation costs for each site may be materially higher than noted, depending
upon remediation experience, selected end use for each site, and actual
environmental conditions encountered.
See our Annual Report on Form 10-K for the year ended December 31, 2001 Note 8
to those Consolidated Financial Statements "Contractual Obligations and
Contingencies" for further information on environmental matters.
5. LONG-TERM DEBT
At December 31, 2001, we had an existing $1 billion shelf registration statement
on file with the Securities and Exchange Commission ("SEC"), with $500 million
available for issuance. In February 2002, we updated our shelf registration for
the issuance of an additional $1.2 billion of securities, thereby giving us the
ability to issue up to $1.7 billion of debt, equity or various forms of
preferred stock. 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 our 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 our financing
authority under both the shelf registration and our 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 an application with the SEC
under PUHCA to increase our financing authority by $700 million, thereby
matching our shelf availability. We anticipate action by the SEC on this
application this year.
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 which will be higher than our current per share market value.
Interest payments will, however, reduce net income and earnings per share.
The Emerging Issues Task Force of the Financial Accounting Standards Board is
considering proposals related to accounting for certain securities and financial
instruments, including securities such as the Equity Units. The current
proposals being considered include the method of accounting discussed above.
Alternatively, other proposals being considered could result in the common
shares issuable pursuant to the purchase contract to be deemed outstanding and
included in the calculation of diluted earnings per share, and could result in
periodic "marking to market" of the purchase contracts, causing periodic charges
or credits to income. If this latter approach were adopted, our diluted earnings
per share could increase and decrease from quarter to quarter to reflect the
lesser and greater number of shares issuable upon satisfaction of the contract.
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 Contracts and Electric Derivative Instruments: From time to time we
have 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 our peak electric energy
sales. Our 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 June 30, 2002, Houston Exploration
has hedged approximately 64% of its estimated 2002 yearly production and
approximately 40% of its estimated 2003 yearly 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 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 $3.8
million. The measured amount of hedge ineffectiveness was immaterial.
We have also employed standard NYMEX gas futures contracts, as well as oil swap
derivative contracts, to fix the purchase price for a portion of the fuel used
at the Ravenswood facility. The maximum length of time over which we have hedged
such cash flow variability is through February 2004. We used standard NYMEX
futures prices to value the gas futures contracts and industry published oil
indices for number 6 grade fuel oil to value the oil swap contracts. The
estimated amount of gains 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 $1.7
million. The measured amount of hedge ineffectiveness was immaterial.
Our gas and electric marketing subsidiary, as well as our gas distribution
operations, have fixed rate gas sales contracts and utilized standard NYMEX
futures contracts to lock-in a price for future natural gas purchases. We used
standard NYMEX futures prices to value the outstanding contracts. The maximum
length of time over which we have hedged such cash flow variability is through
February 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 $0.8 million. The measured amount of hedge ineffectiveness was
immaterial.
We have also engaged in the use of derivative swap instruments to hedge the cash
flow variability associated with a portion of our forecasted 2002 summer and
winter peak electric energy sales from the Ravenswood facility. We currently
have hedge positions for approximately 50% of our estimated 2002 summer peak
electric sales from the Ravenswood facility. We used NYISO-location zone
published indices and standard NYMEX prices to value these outstanding
derivatives. The maximum length of time over which we have hedged such cash flow
variability is through December 2002. 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 $1.6 million. The measured amount of
hedge ineffectiveness was immaterial.
KeySpan Canada has also employed electric swap contracts to lock-in the purchase
price on the purchase of electricity needed to operate its gas processing
plants. These contracts are not exchange- traded and we used local published
indices 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 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 $2.2 million. The measured amount of hedge ineffectiveness was
immaterial.
The following tables set forth selected financial data associated with these
derivative financial instruments noted above that were outstanding at June 30,
2002.
- ------------------------------------------------------------------------------------------------------------------------------------
Year of Volumes Fixed Price $ Current Price $ Fair Value
Type of Contract Maturity mmcf Floor $ Ceiling $ ($000)
- ----------------------------- ---------- ------------- ------------ ------------- ----------------- ----------------- --------------
Gas
Collars 2002 29,440 3.56 5.14 - 3.25 - 3.88 9,149
2003 25,550 3.34 4.97 - 3.72 - 4.24 1,937
Swaps -Short Natural Gas 2002 5,520 - - 3.01 3.25 - 3.88 (2,321)
2003 14,600 - - 3.19 3.72 - 4.24 (9,954)
Swaps - Long Natural Gas 2002 3,920 - - 2.44 - 3.91 3.25 - 3.95 947
2003 2,110 - - 3.10 - 4.00 3.72 - 4.04 1,017
- ----------------------------- ---------- ------------- ------------ ------------- ----------------- ----------------- --------------
81,140 775
- ----------------------------- ---------- ------------- ------------ ------------- ----------------- ----------------- --------------
- ------------------------------------------------------------------------------------------------------------------------------------
Type of Contract Year of Maturity Volumes Fair Value
Barrels Fixed Price $ Current Price $ ($000)
- --------------------------- -------------------- ----------------- --------------------- ------------------------- -----------------
Oil
Swaps - Long Fuel Oil 2002 163,474 19.75 - 24.49 24.58 - 24.93 486
2003 346,892 20.10 - 26.72 22.19 - 23.94 405
2004 3,894 23.50 - 23.70 23.23 - 23.32 7
- --------------------------- -------------------- ----------------- --------------------- ------------------------- -----------------
514,260 898
- --------------------------- -------------------- ----------------- --------------------- ------------------------- -----------------
- ------------------------------------------------------------------------------------------------------------------------------------
Type of Contract Year of Current Price Estimated Profit $ Fair Value
Maturity MWh Fixed Profit /Price $ $ ($000)
- ------------------------ --------------- ------------ ------------------------- --------------- ------------------- ----------------
Electricity
Tolling Arrangements 2002 732,800 26.00 - 56.50 - 4.07 - 49.07 1,635
Swaps - Long 2002 35,328 58.70 - 60.01 26.02 - (1,121)
2003 70,080 58.70 - 60.01 28.25 - (2,067)
- ------------------------ --------------- ------------ ------------------------- --------------- ------------------- ----------------
838,208 (1,553)
- ------------------------ --------------- ------------ ------------------------- --------------- ------------------- ----------------
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 used natural gas swap contracts, with offsetting positions in oil
swap contracts of equivalent energy value, to hedge the cash-flow variability of
specified portions of gas purchases and sales. All positions that were
outstanding at December 31, 2001 settled during the first quarter of 2002. We
intend to enter into additional derivative instruments of this nature during
2002 if market conditions so warrant.
Firm Gas Sales Derivative Instruments - Regulated Utilities: We have also
utilized derivative financial instruments to reduce the cash flow variability
associated with the purchase price for a portion of our future natural gas
purchases. Our strategy is to minimize fluctuations in firm gas sales prices to
our regulated firm gas sales customers in our New York and New Hampshire service
territories. Since these derivative instruments are employed to support our gas
sales prices 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 tables set forth selected financial data associated with these
derivative financial instruments that were outstanding at June 30, 2002.
- ------------------------------------------------------------------------------------------------------------------------------------
Type of Contract Year of Maturity Volumes Fair Value
Mmcf Fixed Price $ Current Price $ ($000)
- -------------------------- -------------------- ----------------- ----------------------- ------------------------- ----------------
Gas
Call Options 2002 1,280 4.20 - 4.50 3.69 - 3.95 17
2003 1,960 4.20 - 4.50 3.88 - 4.04 253
- -------------------------- -------------------- ----------------- ----------------------- ------------------------- ----------------
3,240 270
- -------------------------- -------------------- ----------------- ----------------------- ------------------------- ----------------
Contract Review
On April 1, 2002 we implemented Implementation 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 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. As a result, and effective April 1, 2002, such contracts are
required to be recorded on the Consolidated Balance Sheet at fair value and had
a calculated fair value at that date of $7.8 million. At June 30, 2002 the fair
value of these contracts was $5.0 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 will be recorded as a Regulatory Asset or
Regulatory Liability on the Consolidated Balance Sheet.
Interest Rate Swaps: We also have interest rate swap agreements in which
approximately $1.3 billion of fixed rate debt has been synthetically modified to
floating rate debt. For the term of the agreements, we will receive the fixed
coupon rate associated with these bonds and pay the counter parties a variable
interest rate that is reset on a quarterly basis. These swaps are fair- value
hedges and qualify for "short-cut" hedge accounting treatment under SFAS 133.
Through the utilization of our interest rate swap agreements, we reduced
recorded interest expense by $22.7 million for the six months ended June 30,
2002. The fair values of these derivative instruments are provided to us by
third party appraisers and represent the present value of future cash-flows
based on a forward interest rate curve for the life of the derivative
instrument.
During the quarter ended June 30, 2002, the swap arrangement associated with a
$90 million Gas Facilities Revenue Bond was terminated by our counter party. At
that time we had an immaterial derivative asset recorded. As provided for under
the terms of the swap agreement, our counter party had the right to terminate
the swap arrangement at their discretion without a fee or penalty. Since neither
a fee nor penalty was imposed on the counter-party, the termination of this swap
arrangement had no earnings impact.
The table below summarizes selected financial data associated with these
derivative financial instruments that were outstanding at June 30, 2002.
- ------------------------------------------------------------------------------------------------------------------------------------
Average Variable Rate
Maturity Date of Notional Amount Fixed Rate Paid Fair Value
Bond Swaps ($000) Received Year to Date ($000)
- --------------------------- ---------------------- ----------------------- ---------------- ----------------------- ---------------
Medium Term Notes 2010 500,000 7.625% 4.290% 3,022
Medium Term Notes 2006 500,000 6.150% 3.320% 4,581
Medium Term Notes 2023 270,000 8.200% 3.620% (309)
- --------------------------- ---------------------- ----------------------- ---------------- ----------------------- ---------------
1,270,000 7,294
- --------------------------- ---------------------- ----------------------- ---------------- ----------------------- ---------------
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. The
measured amount of hedge ineffectiveness was immaterial. We estimate that a 1%
increase in current interest rates would result in a $10.3 million increase to
interest expense.
Derivative contracts are primarily used to manage our exposure to market risk
arising from changes in commodity prices and interest rates. In the event of
nonperformance by a counter party to 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 our derivative contracts are with investment
grade companies. (See Item 3. Quantitative and Qualitative Disclosures About
Market Risk for a discussion on credit risk.)
7. WORKFORCE REDUCTION PROGRAMS
As a result of the Eastern acquisition, we implemented early retirement and
severance programs in an effort to reduce our workforce. In 2000, we recorded a
$22.7 million liability associated with these programs. This severance program
is targeted to reduce the workforce by 500 employees and will continue through
2002. In 2001, we reduced this liability by $4.1 million as a result of lower
than anticipated costs per employee. As of June 30, 2002, we had paid $12.3
million for these programs and had a remaining liability of $6.3 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 is to be performed within six months of adopting SFAS 142
with any resulting impairment reflected as either a change in accounting
principle, or a charge to operations in the financial statements. We have
completed our analysis for all of our reporting units and determined that no
consolidated impairment exists.
For the three and six months ended June 30, 2001 respectively, goodwill
amortization was recorded in each segment as follows: Gas Distribution $8.9 and
$17.8 million; Energy Services $2.1 and $4.2 million; and Energy Investments and
other $1.6 and $3.1 million. As required by SFAS 142, below is a reconciliation
of reported net income for the three and six months ended June 30, 2001 and
pro-forma net income, for the same period, adjusted for the discontinuance of
goodwill amortization.
- -----------------------------------------------------------------------------------------------------------------------------------
Three Months Ended Three Months Ended Six Months Ended Six Months Ended
June 30, 2002 June 30, 2001 June 30, 2002 June 30, 2001
- -------------------------------------------- --------------------- -------------------- --------------------- ---------------------
Earnings (loss) available for common stock $ 8,036 $ (8,001) $ 221,191 $ 215,298
Add back: goodwill amortization - 12,594 - 25,145
- -------------------------------------------- --------------------- -------------------- --------------------- ---------------------
Adjusted net income 8,036 4,593 221,191 240,443
- -------------------------------------------- --------------------- -------------------- --------------------- ---------------------
Basic earnings (loss) per share 0.06 (0.06) 1.57 1.57
Add back: goodwill amortization - 0.09 - 0.18
- -------------------------------------------- --------------------- -------------------- --------------------- ---------------------
Adjusted basic earnings per share $ 0.06 $ 0.03 $ 1.57 $ 1.75
- -------------------------------------------- --------------------- -------------------- --------------------- ---------------------
Diluted earnings (loss) per share 0.06 (0.06) 1.56 1.55
Add back: goodwill amortization - 0.09 - 0.18
- -------------------------------------------- --------------------- -------------------- --------------------- ---------------------
Adjusted diluted earnings per share $ 0.06 $ 0.03 $ 1.56 $ 1.73
- -------------------------------------------- --------------------- -------------------- --------------------- ---------------------
In July of 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations". The Standard requires entities to record the fair value of a
liability for an asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity will capitalize a
cost by increasing the carrying amount of the related long-lived asset. Over
time, the liability is accreted to its then present value, and the capitalized
cost is depreciated over the useful life of the related asset. Upon settlement
of the liability, an entity either settles the obligation for its recorded
amount or incurs a gain or loss upon settlement. The standard is effective for
fiscal years beginning after June 15, 2002, with earlier application encouraged.
We are currently evaluating the impact, if any, that this Statement may have on
our results of operations and financial position.
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets",
was effective January 1, 2002, and addresses accounting and reporting for the
impairment or disposal of long-lived assets. SFAS No. 144 supersedes SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of" and APB Opinion No. 30, "Reporting the Results of
Operations-Reporting the Effects of Disposal of a Segment of a Business". SFAS
No. 144 retains the fundamental provisions of SFAS No. 121 and expands the
reporting of discontinued operations to include all components of an entity with
operations that can be distinguished from the rest of the entity and that will
be eliminated from the ongoing operations of the entity in a disposal
transaction. As of June 30, 2002, implementation of this Statement did not have
a significant effect on our results of operations and financial position.
9. DISCONTINUED OPERATIONS
On November 8, 2000, we acquired Midland Enterprises LLC ("Midland"), a marine
transportation subsidiary, as part of the Eastern acquisition. In its order
issued under PUCHA approving the acquisition, the SEC required us to sell this
subsidiary by November 8, 2003 because its operations were not functionally
related to our core utility operations. On July 2, 2002 we completed the sale of
Midland to Ingram Industries Inc.
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 our tax structuring strategy related to the sale of Midland, during the
quarter ended June 30, 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
six months ended June 30, 2002 and June 30, 2001:
(In Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------------------------------
Three Months Three Months Six Months Six Months
Ended Ended Ended Ended
June 30, 2002 June 30, 2001 June 30, 2002 June 30, 2001
- ------------------------------------------------------------------------------------------------------------------------------------
Revenues $ 60,260 $ 67,776 $ 116,149 $ 135,364
Pretax income (loss) (888) 6,368 (4,624) 7,857
Income tax (expense) benefit 235 (2,476) 1,268 (3,304)
- ------------------------------------------------------------------------------------------------------------------------------------
Income (loss) from discontinued operations (653) 3,892 (3,356) 4,553
- ------------------------------------------------------------------------------------------------------------------------------------
Loss on disposal (19,009) - (16,306) -
- ------------------------------------------------------------------------------------------------------------------------------------
Loss from discontinued operations $ (19,662) $ 3,892 $ (19,662) $ 4,553
- ------------------------------------------------------------------------------------------------------------------------------------
Assets and liabilities of the discontinued operations are as follows:
(In Thousands of Dollars)
--------------------------------------------------------------------------------------------------------------
June 30, 2002 December 31, 2001
--------------------------------------------------------------------------------------------------------------
Current assets $ 136,193 $ 139,522
Property, plant and equipment, net 308,707 316,626
Long-term assets 33,703 35,233
Current liabilities (49,750) (58,835)
Long-term liabilities (238,718) (241,491)
--------------------------------------------------------------------------------------------------------------
Net assets held for disposal $ 190,135 $ 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. 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.
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.
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 of Dollars)
- ------------------------------------------------------------------------------------------------------------------------------------
Three Months Ended June 30, 2002 Three Months Ended June 30, 2001
- ------------------------------------------------------------------------------------------------------------------------------------
Guarantor KEDLI Eliminations Consolidated Guarantor KEDLI Eliminations Consolidated
Revenues $1,078,169 $ 137,936 $ 1,216,105 $ 1,182,782 $ 156,520 $1,339,302
Operating Expenses
Purchased Gas 187,369 62,573 249,942 273,680 74,669 348,349
Fuel and purchased power 93,292 - 93,292 146,357 - 146,357
Operations and maintenance 535,027 13,067 548,094 517,176 16,627 533,803
Intercompany expense (20,034) 20,034 - (21,216) 21,216 -
Depreciation and
amortization 112,124 15,339 127,463 108,156 13,422 121,578
Operating Taxes 68,080 19,308 87,388 81,214 19,621 100,835
----------- ------------ ------------- -------------- ------------- ---------- ------------ -------------
Total Operating
Expenses 975,858 130,321 1,106,179 1,105,367 145,555 1,250,922
----------- ------------ ------------- -------------- ------------- ---------- ------------ -------------
Operating Income 102,311 7,615 109,926 77,415 10,965 88,380
Other Income and
(Deductions) 6,023 2,192 (5,869) 2,346 (1,137) 3,588 (5,607) (3,156)
----------- ------------ ------------- -------------- ------------- ---------- ------------ -------------
Income Before Interest
Charges and Income Taxes 108,334 9,807 (5,869) 112,272 76,278 14,553 (5,607) 85,224
Interest Expense 60,023 15,900 (5,869) 70,054 81,896 15,638 (5,607) 91,927
Income Taxes 15,768 (2,724) 13,044 4,520 (806) 3,714
Preferred stock dividends 1,476 - - 1,476 1,476 - - 1,476
----------- ------------ ------------- -------------- ------------- ---------- ------------ -------------
Earnings (Loss) From
Continuing Operations $ 31,067 $ (3,369) $ - $ 27,698 $ (11,614) $ (279) $ - $ (11,893)
=========== ============ ============= ============== ============= ========== ============ =============
Statement of Income
(In Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------------------------------
Six Months Ended June 30, 2002 Six Months Ended June 30, 2001
- ------------------------------------------------------------------------------------------------------------------------------------
Guarantor KEDLI Eliminations Consolidated Guarantor KEDLI Eliminations Consolidated
Revenues $ 2,630,780 $ 456,884 $ 3,087,664 $ 3,327,372 $ 587,018 $ 3,914,390
Operating Expenses
Purchased Gas 693,859 205,440 899,299 1,212,899 332,799 1,545,698
Fuel and purchased power 177,664 - 177,664 289,657 - 289,657
Operations and maintenance 1,016,593 25,067 1,041,660 1,005,915 31,771 1,037,686
Intercompany expense (38,242) 38,242 - (42,760) 42,760 -
Depreciation and
amortization 217,879 35,581 253,460 220,290 32,452 252,742
Operating Taxes 163,087 44,694 207,781 193,218 49,607 242,825
------------- ------------ --------------- ------------- ------------- ----------- ----------- -----------
Total Operating
Expenses 2,230,840 394,024 2,579,864 2,879,219 489,389 3,368,608
------------- ------------ --------------- ------------- ------------- ----------- ----------- -----------
Operating Income 399,940 107,860 507,800 448,153 97,629 545,782
Other Income and
(Deductions) 16,478 5,095 (11,040) 10,533 8,142 6,579 (13,175) 1,546
------------- ------------ --------------- ------------- ------------- ----------- ----------- -----------
Income Before Interest
Charges and Income Taxes 416,418 112,955 (11,040) 518,333 456,295 104,208 (13,175) 547,328
Interest Expense 122,599 31,102 (11,040) 142,661 165,527 32,878 (13,175) 185,230
Income Taxes 97,507 34,360 131,867 124,156 24,245 148,401
Preferred stock dividends 2,952 - - 2,952 2,952 - - 2,952
------------- ------------ --------------- ------------- ------------- ----------- ----------- -----------
Earnings (Loss) from
Continuing Operations $ 193,360 $ 47,493 $ - $ 240,853 $ 163,660 $ 47,085 $ - $ 210,745
============= ============ =============== ============= ============= =========== =========== ===========
Balance Sheet (In Thousands of Dollars)
- ---------------------------------------- -------------------------------------------------------------------------------------------
June 30, 2002 December 31, 2001
- ---------------------------------------- ----------------------------------------------------- -------------------------------------
ASSETS Guarantor KEDLI Eliminations Consolidated Guarantor KEDLI Eliminations Consolidated
Current Assets
Cash and temporary
cash investments $ 137,599 $ - $ - $ 137,599 $ 159,252 $ - $ - $ 159,252
Accounts Receivable, net 1,226,822 166,472 (245,710) 1,147,584 1,540,082 233,013 (500,496) 1,272,599
Other current assets 441,735 124,640 - 566,375 454,319 112,317 - 566,636
------------ -------------------------------------------------------------------------------------------
1,806,156 291,112 (245,710) 1,851,558 2,153,653 345,330 (500,496) 1,998,487
------------ -------------------------------------------------------------------------------------------
Assets Held for Disposal 190,135 - - 190,135 191,055 - - 191,055
Equity Investments 774,204 - (532,862) 241,342 756,111 - (532,862) 223,249
------------ -------------------------------------------------------------------------------------------
Property
Gas 4,187,083 1,690,538 - 5,877,621 4,074,894 1,629,963 - 5,704,857
Other 4,607,133 - - 4,607,133 4,231,262 - - 4,231,262
Accumulated depreciation
and depletion (3,219,722) (310,590) - (3,530,312) (3,035,788) (294,400) - (3,330,188)
------------ -------------------------------------------------------------------------------------------
5,574,494 1,379,948 - 6,954,442 5,270,368 1,335,563 - 6,605,931
------------ -------------------------------------------------------------------------------------------
Deferred Charges 2,528,605 183,448 - 2,712,053 2,571,029 199,855 - 2,770,884
--------------------------------------------------------------------------------------------------------
Total Assets $10,873,594 $1,854,508 $ (778,572) $11,949,530 $10,942,216 $1,880,748 $(1,033,358) $ 11,789,606
========================================================================================================
LIABILITIES
AND CAPITALIZATION
Current Liabilities
Accounts Payable
and accrued expenses $ 928,221 $ 77,852 $ - $ 1,006,073 $ 975,873 $ 115,557 $ - $ 1,091,430
Commercial Paper 570,655 - - 570,655 1,048,450 - - 1,048,450
Other current
liabilities 118,469 79,923 - 198,392 220,985 23,844 - 244,829
--------------------------------------------------------------------------------------------------------
1,617,345 157,775 - 1,775,120 2,245,308 139,401 - 2,384,709
--------------------------------------------------------------------------------------------------------
Intercompany
Accounts Payable - 69,806 (69,806) - - 324,592 (324,592) -
--------------------------------------------------------------------------------------------------------
Deferred Credits
and Other Liabilities
Deferred Income Tax 636,863 174,486 - 811,349 593,300 4,772 - 598,072
Other deferred credits
and liabilities 833,550 93,417 - 926,967 841,662 100,452 - 942,114
--------------------------------------------------- ----------------------------------------------------
1,470,413 267,903 - 1,738,316 1,434,962 105,224 - 1,540,186
--------------------------------------------------- ----------------------------------------------------
Capitalization
Common shareholders'
equity 2,831,009 658,120 (532,862) 2,956,267 2,812,837 610,627 (532,862) 2,890,602
Preferred stock 84,077 - - 84,077 84,077 - - 84,077
Long-term debt 4,667,217 700,904 (175,904) 5,192,217 4,172,649 700,904 (175,904) 4,697,649
--------------------------------------------------------------------------------------------------------
Total Capitalization 7,582,303 1,359,024 (708,766) 8,232,561 7,069,563 1,311,531 (708,766) 7,672,328
--------------------------------------------------------------------------------------------------------
Minority Interest
in Subsidiary Companies 203,533 - - 203,533 192,383 - - 192,383
--------------------------------------------------------------------------------------------------------
Total Liabilities
and Capitalization $10,873,594 $ 1,854,508 $(778,572) $11,949,530 $10,942,216 $ 1,880,748 $(1,033,358) $ 11,789,606
========================================================================================================
Statement of Cash Flows (In Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------------------------------
Six Months Ended June 30, 2002 Six Months Ended June 30, 2001
- ------------------------------------------------------------------------------------ -----------------------------------------------
Guarantor KEDLI Consolidated Guarantor KEDLI Consolidated
- ------------------------------------------------ -------------- ------------------ --------------- ---------------- ----------------
Operating Activities
Net Cash Provided by
Operating Activities $ 395,573 $ 288,184 $ 683,757 $ 473,124 $ 81,746 $ 554,870
----------------- -------------- ------------------ --------------- ---------------- ----------------
Investing Activities
Capital expenditures (534,831) (60,672) (595,503) (396,786) (28,021) (424,807)
Sale of Assets - - - 18,458 - 18,458
Other - - - (7,822) - (7,822)
----------------- -------------- ------------------ --------------- ---------------- ----------------
Net Cash Used in
Investing Activities (534,831) (60,672) (595,503) (386,150) (28,021) (414,171)
----------------- -------------- ------------------ --------------- ---------------- ----------------
Financing Activities
Issuance of Treasury Stock 51,896 - 51,896 64,107 - 64,107
Issuance of long-term debt 507,754 - 507,754 583,000 125,000 708,000
Payment of long-term debt (54,590) - (54,590) (152,000) - (152,000)
Payment of commercial paper (477,795) - (477,795) (497,033) - (497,033)
Preferred stock dividends paid (2,952) - (2,952) (2,952) - (2,952)
Common stock dividends paid (124,684) - (124,684) (121,937) - (121,937)
Net intercompany accounts
payable 227,512 (227,512) - 178,725 (178,725) -
Other (9,536) - (9,536) 5,102 - 5,102
----------------- -------------- ------------------ --------------- ---------------- ----------------
Net Cash Provided by
(Used in) Financing
Activities $ 117,605 $ (227,512) $ (109,907) $ 57,012 $ (53,725) $ 3,287
----------------- -------------- ------------------ --------------- ---------------- ----------------
Net Increase in Cash and
Cash Equivalents $ (21,653) $ - $ (21,653) $ 143,986 $ - $ 143,986
================= ============== ================== =============== ================ ================
Cash and Cash Equivalents at
Beginning of Period $ 159,252 $ - $ 159,252 $ 83,329 - $ 83,329
----------------- -------------- ------------------ --------------- ---------------- ----------------
Cash and Cash Equivalents at
End of Period $ 137,599 $ - $ 137,599 $ 227,315 $ - $ 227,315
=================== ============== ================ =============== ================ ================
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Consolidated Review of Results
- ------------------------------
The following is a summary of transactions affecting comparative earnings and a
discussion of material changes in revenues and expenses during the three and six
months ended June 30, 2002, compared to the three and six months ended June 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 and six months
ended June 30, 2002 were $27.7 million, or $0.20 per share and $240.9 million,
or $1.71 per share, respectively. Consolidated results from continuing
operations for the three months ended June 30, 2001 reflected a loss of $11.9
million, or $0.09 per share. Consolidated earnings from continuing operations
for the six months ended June 30, 2001 were $210.7 million, or $1.54 per share.
Earnings available for common stock, which includes discontinued operations as
discussed below, were $8.0 million, or $0.06 per share and $221.2 million, or
$1.57 per share for the three and six months ended June 30, 2002, respectively.
Earnings available for common stock for the three months ended June 30, 2001
reflected a loss of $8.0 million, or $0.06 per share. For the six months ended
June 30, 2001 earnings available for common stock were $215.3 million, or $1.57
per share. Diluted earnings per share were $1.56 and $1.55 for the six months
ended June 30, 2002 and 2001, respectively. Basic and diluted earnings per share
were the same for the three months ended June 30, 2002 and 2001, respectively.
Average common shares outstanding for the six months ended June 30, 2002
increased by 2.3% 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 six months ended June 30, 2002 by $0.04
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"), our marine barge business. In anticipation
of this divestiture, which closed on July 2, 2002, we have reported Midland's
operations as discontinued for 2002 and 2001. (See our Annual Report on Form 10K
for the year ended December 31, 2001 Item 7 "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, we recorded an estimated loss on the sale of Midland as
well as an estimate for Midland's results of operations for the first six months
of 2002. During the three months ended June 30, 2002, we recorded an additional
after-tax loss of $19.7 million, primarily reflecting a provision for certain
city and state taxes that resulted from a change in our tax structuring
strategy. (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 continuing operations for the
quarter and six months ended June 30, 2002 verses the comparable periods last
year were principally impacted by the following four factors: (i) losses
incurred in 2001 by one of our unregulated subsidiaries; (ii) the
discontinuation of goodwill amortization in 2002; (iii) a significant decrease
in interest expense; and (iv) a significant decrease in natural gas prices,
which reduced comparative earnings associated with the operations of our gas
exploration and production activities.
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 six months ended June 30, 2001 were $30.1 million
after-tax, or $0.22 per share and $35.6 million after-tax, or $0.26 per share,
respectively. (See our 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 10 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 six months ended June 30, 2002, we incurred after-tax losses of
$1.5 million and $2.8 million, respectively, reflecting overhead, and
administrative and general expenses. These costs could not be accrued in 2001.
In January 2002, we adopted Statement of 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 six
months ended June 30, 2001 was $12.6 million, or $0.09 per share, and $25.2
million, or $0.18 per share, respectively.
Interest expense decreased by $21.9 million ($14.2 after-tax), or $0.10 per
share and $42.6 million ($27.7 million after-tax) or $0.20 per share, for the
three and six months ended June 30, 2002, respectively. The weighted average
interest rate on outstanding commercial paper during the six months ended June
30, 2002 was approximately 2.08% compared to approximately 5.51% for the
corresponding period last year, a decrease of approximately 340 basis points.
Further, we have a number of interest rate swap agreements in which we have
effectively changed fixed rate debt to floating rate debt. Our use of these
derivative instruments has reduced interest expense by $22.7 million during the
six months ended June 30, 2002. (See Note 6 to the Consolidated Financial
Statements "Derivative Financial Instruments" for a description of these
instruments.)
For the three and six months ended June 30, 2002, net income from our gas
exploration and production operations decreased by $12.0 million, or $0.09 per
share and by $38.8 million, or $0.29 per share, respectively compared to the
corresponding periods last year. Our gas exploration and production subsidiaries
were adversely impacted by significantly lower realized gas prices during the
six months ended June 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 $6.4 million
and $11.9 million recognized in the three and six months ended June 30, 2002,
respectively, resulting from the favorable resolution of certain outstanding tax
issues related to the KeySpan / Long Island Lighting Company ("LILCO") merger
completed in May 1998. Further, during the first quarter of 2002, we recorded an
adjustment to deferred income taxes of $177.7 million reflecting a decrease in
the tax basis of the assets acquired at the time of the KeySpan / LILCO merger.
This adjustment was the result of a revised valuation study and the preparation
of an amended tax return. Concurrent with the deferred tax adjustment, we
reduced current income taxes payable by $183.2 million, resulting in a net $5.5
million income tax benefit.
Earnings before interest and taxes ("EBIT") increased by $27.1 million, or 32%,
for the second quarter of 2002 compared to the corresponding quarter last year,
but decreased by $29.0 million, or 5% for the six months ended June 30, 2002
compared to the same period last year. Comparative EBIT results were impacted by
the items mentioned above, namely (i) EBIT losses of $53.3 million and $61.2
million incurred by the Roy Kay companies for the three and six months ended
June 30, 2001, respectively; (ii) the discontinuation of goodwill amortization
in 2002 of $12.6 million and $25.2 million for the three and six months ended
June 30, 2001, respectively; and (iii) decreases in comparative EBIT results
associated with our gas exploration and production subsidiaries of $20.4 million
and $70.2 million for the three and six months ended June 30, 2002,
respectively. The remaining decrease in EBIT from core operations for the three
and six months ended June 30, 2002 compared to last year, primarily reflects
lower EBIT from our unregulated affiliates. 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 maintaining our earnings guidance that was issued in December 2001. We
forecast that KeySpan's 2002 earnings from continuing core operations (defined
for this purpose as all continuing operations other than gas exploration and
production) will be in the range of $2.40 to $2.45 per share. Earnings from
continuing core operations were $0.11 per share and $1.56 per share for the
three and six months ended June 30, 2002, respectively. KeySpan's 2002 earnings
forecast for its gas exploration and production operations is in the range of
$0.20 - $0.30 per share. Earnings from our gas exploration and production
operations were $0.09 per share and $0.15 per share for the three and six months
ended June 30, 2002, respectively. 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.
Consolidated earnings are seasonal in nature due to the significant contribution
to earnings of our gas distribution operations. As a result, we expect to earn
approximately 60%, and 30% to 35% of our yearly earnings in the first and fourth
quarters 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 operating 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 of Dollars)
- -------------------------------------------- --------------------- --------------------- ----------------------- -------------------
Three Months Ended Three Months Ended Six Months Ended Six Months Ended
June 30, 2002 June 30, 2001 June 30, 2002 June 30, 2001
- -------------------------------------------- --------------------- --------------------- --------------------- ---------------------
Revenues $ 521,822 $ 620,685 $ 1,744,791 $ 2,374,329
Cost of gas 236,357 328,487 849,939 1,433,795
Revenue taxes 18,163 21,163 56,458 77,642
- -------------------------------------------- --------------------- --------------------- --------------------- ---------------------
Net Revenues 267,302 271,035 838,394 862,892
- -------------------------------------------- --------------------- --------------------- --------------------- ---------------------
Operating expenses
Operations and maintenance 152,767 158,356 298,305 317,228
Depreciation and amortization 58,118 62,753 121,138 131,336
Operating taxes 29,647 36,162 67,648 74,138
- -------------------------------------------- --------------------- --------------------- --------------------- ---------------------
Total Operating Expenses 240,532 257,271 487,091 522,702
- -------------------------------------------- --------------------- --------------------- --------------------- ---------------------
Operating Income 26,770 13,764 351,303 340,190
Other Income and (Deductions) 2,473 5,160 7,596 9,415
- -------------------------------------------- --------------------- --------------------- --------------------- ---------------------
Earnings Before Interest and Taxes $ 29,243 $ 18,924 $ 358,899 349,605
- -------------------------------------------- --------------------- --------------------- --------------------- ---------------------
Firm gas sales (MDTH) 41,391 36,516 148,665 163,332
Firm transportation (MDTH) 13,497 22,248 43,495 56,488
Transportation - Electric
Generation (MDTH) 13,182 11,754 26,541 16,132
Other sales (MDTH) 23,513 23,319 61,414 48,834
Warmer than normal - New York - 7.4% 15.0% 2.0%
Warmer (Colder) than normal - New England 13.6% (3.3%) 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 and associated revenue taxes)
associated with both our New York and New England based gas distribution
operations were adversely impacted by the significantly warmer than normal
weather experienced throughout the Northeastern United States during the past
winter heating season. Based on heating degree days, weather for the first six
months of 2002 was the warmest in the past 30 years ( approximately 10% - 15%
warmer than normal), and approximately 14% warmer than last year in our New York
and New England service territories. The significantly warmer than normal
weather resulted in a decrease of $24.5 million, or 3%, in net gas revenues for
the six months ended June 30, 2002, compared to the corresponding period last
year.
KEDNY and KEDLI each operate under a utility tariff that contains a weather
normalization adjustment that largely offsets variations in firm net revenues
due to fluctuations in weather. These weather normalization adjustments resulted
in a $33.4 million benefit to net gas revenues during the first six months of
2002. Nevertheless, net revenues from firm gas customers (residential,
commercial and industrial customers) in our New York service territory decreased
by $17.9 million for the six months ended June 30, 2002 compared to the same
period last year, primarily as a result of lower customer consumption due to the
extremely warm weather, offset, in part, by the benefits from conversions to
natural gas.
Net revenues from firm gas customers in our New England service territory
decreased by $4.6 million for the first half of 2002, compared to the same
period last year, also due to the extremely warm weather. Our New England based
gas distribution subsidiaries do not have a weather normalization adjustment.
Included in net revenues for the six months ended June 30, 2002 is the
beneficial effect of a favorable ruling of the Massachusetts Supreme Judicial
Court relating to the appeal by Boston Gas Company of a decision of the
Massachusetts Department of Telecommunications and Energy ("DTE") on Boston Gas
Company's Performance Based Rate Plan ("PBR"). The court found that the
"accumulated inefficiencies" component of the productivity factor in the PBR,
imposed by the Massachusetts Department of Telecommunications and Energy, was
not supportable. This ruling resulted in a benefit to comparative net margins of
$5.3 million. (See our 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 the first quarter of 2002, other than for the
recovery of gas costs, have remained substantially unchanged from rates charged
last year in all of our service territories. To mitigate the effect of
fluctuations in normal weather patterns on our financial position and cash
flows, we are currently evaluating the appropriateness of employing weather
derivatives for the 2002/2003 winter heating season.
In our large-volume heating markets and other interruptible (non-firm) markets,
which include large apartment houses, government buildings and schools, gas
service is provided under rates that are established to compete with prices of
alternative fuel, including No. 2 and No. 6 grade heating oil. As a result of
the extremely warm weather, net margins decreased $2.0 million during the six
months ended June 30, 2002, compared to same period last year. The majority of
interruptible profits earned are returned to firm customers as an offset to gas
costs.
We are committed to our expansion strategies initiated during the past few
years. We believe that significant growth opportunities exist on Long Island and
in our New England service territories. We estimate that on Long Island
approximately 35% of the residential and multi-family markets, and approximately
55% of the commercial market currently use natural gas for space heating.
Further, we estimate that in our New England service territories approximately
50% of the residential and multi-family markets, and approximately 45% of the
commercial market currently use natural gas for space heating purposes. We will
continue to seek growth in all our market segments, through the expansion of our
gas distribution system, as well as through the conversion of residential homes
from oil-to-gas for space heating purposes and the pursuit of opportunities to
grow multi-family, industrial and commercial markets.
Sales, Transportation and Other Quantities
Firm gas sales and transportation quantities decreased by 13% during the six
months ended June 30, 2002, compared to the same period in 2001 due to the
extremely warm weather 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 our electric generating facilities located on Long
Island. Net revenues from these services are not material.
Other sales quantities include on-system interruptible quantities, off-system
sales quantities (sales made to customers outside of our service territories)
and related transportation. We have an agreement with Coral Resources, L.P.
("Coral"), a subsidiary of Shell Oil Company, under which Coral assists in the
origination, structuring, valuation and execution of energy-related transactions
on behalf of KEDNY and KEDLI. We also have a portfolio management contract with
El Paso Energy Marketing, Inc. ("El Paso"), under which El Paso provides all of
the city gate supply requirements at market prices and manages certain upstream
capacity, underground storage and term supply contracts for KEDNE. Our agreement
with El Paso expires on October 31, 2002 and our agreement with Coral expires on
March 31, 2003. We are currently considering extending the El Paso agreement to
March 31, 2003.
Purchased Gas for Resale
The decrease in gas costs for the six months ended June 30, 2002 of $583.9
million reflects a decrease of 35% in the price per decatherm of gas purchased,
and an 11% reduction in the quantity of gas purchased, as a result of the
extremely warm winter. Fluctuations in utility gas costs 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 decreased by $16.7 million, or 7%, and by $35.6 million, or
7%, for three and six months ended June 30, 2002, respectively, compared to the
corresponding periods last year. The decrease in operating expenses is due to
the discontinuance of goodwill amortization, lower operating taxes, cost saving
synergies, the effects of warmer than normal weather and the timing of certain
operations and maintenance expenses.
In January 2002, we adopted Statement of Accounting Standard ("SFAS") 142
"Goodwill and Other Intangible Assets"). The key requirements of this Statement
include discontinuance of goodwill amortization, a revised framework for testing
goodwill impairment and new criteria for the identification of intangible
assets. Goodwill amortization in the gas distribution segment for the three and
six months ended June 30, 2001 was $8.9 million and $17.8 million. Goodwill
amortization for the twelve months ended December 31, 2001 was $35.6 million.
During the three months ended June 30, 2002, we recorded a favorable $7.4
million adjustment to operating taxes related to the reversal of excess tax
reserves established for the KeySpan / LILCO merger and subsequent
re-organization in May 1998.
Further contributing to the reduction in comparative operating expenses are cost
saving synergies currently being realized primarily as a result of early
retirement and severance programs implemented in the fourth quarter of 2000
designed to reduce our workforce by approximately 500 employees. The early
retirement portion of the program was completed in 2000, but the severance
feature is expected to continue through 2002. Further, the warmer than normal
weather experienced in the first quarter of 2002 resulted in less repair and
maintenance work needed on our gas distribution infrastructure.
Other Matters
To take advantage of the anticipated gas sales growth opportunities in the New
York City metropolitan area, in 2000 we formed the Islander East Pipeline, LLC,
a limited liability company in which a KeySpan subsidiary and a subsidiary of
Duke Energy Corporation each own a 50% equity interest. Islander East Pipeline,
LLC has received a positive preliminary determination from the Federal Energy
Regulatory Commission ("FERC") to construct, own and operate a natural gas
pipeline facility consisting of approximately 50 miles of interstate natural gas
pipeline extending from Algonquin Gas Transmission Company's facilities in
Connecticut, across the Long Island Sound and connecting with KEDLI's facilities
on Long Island. Subsequent to the timely receipt of required regulatory
approvals, the Islander East Pipeline is expected to begin operating in 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 2002.)
Electric Services
The Electric Services segment primarily consists of subsidiaries that own and
operate oil and gas fired electric generating plants in Queens and Long Island
and, through long-term contracts, manage the electric transmission and
distribution ("T&D") system, the fuel and electric purchases, and the off-system
electric sales for the Long Island Power Authority ("LIPA").
Selected financial data for the Electric Services segment is set forth in the
table below for the periods indicated.
(In Thousands of Dollars)
- ----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Three Months Ended Three Months Ended Six Months Ended Six Months Ended
June 30, 2002 June 30, 2001 June 30, 2002 June 30, 2001
- ----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Revenues $ 354,781 $ 357,929 $ 669,489 $ 701,325
Purchased fuel 61,146 74,327 115,139 153,654
- ----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Net Revenues 293,635 283,602 554,350 547,671
- ----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Operating expenses
Operations and maintenance 183,936 167,132 332,056 311,906
Depreciation 13,928 12,716 27,661 25,290
Operating taxes 36,270 38,365 73,642 81,669
- ----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Total Operating Expenses 234,134 218,213 433,359 418,865
- ----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Operating Income 59,501 65,389 120,991 128,806
Other Income and (Deductions) 5,218 2,336 9,373 4,500
- ----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Earnings Before Interest and Taxes $ 64,719 $ 67,725 $ 130,364 $ 133,306
- ----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Electric sales (MWH)* 1,125,735 1,292,980 2,216,978 2,315,620
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 slightly for the three and six months
ended June 30, 2002, compared to the similar periods of 2001. Higher comparative
net revenues from the LIPA service agreements were mostly offset by lower
comparative net revenues from the Ravenswood facility. Revenues from the LIPA
service agreements increased by $19.2 million, or 10%, and by $32.1 million or
9% for the quarter and six months ended June 30, 2002 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 generally have no impact on net income since we record a
similar amount of costs in operating expense. Excluding these third party
billings, revenues for the quarter and six months ended June 30, 2002 associated
with the LIPA service agreements were comparable to such revenues earned during
the same period last year.
Net revenues from the Ravenswood facility were $10.5 million, or 12% lower
during the three months ended June 30, 2002 compared to the same period in 2001,
primarily due to lower net revenues from capacity sales. Net revenues were $26.7
million, or 15% lower during the six months ended June 30, 2002, compared to the
same period in 2001. Net revenues from capacity sales were 12% lower compared to
the same period last year, while margins associated with the sale of electric
energy were 22% lower than last year. Comparative energy sales were adversely
impacted by a reduction in "spark-spread" combined with a decrease in electric
sales quantities as a result of a slight decrease in cooling degree days.
The decrease in comparative net revenues from capacity sales for both the
quarter and six months ended June 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.
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 our
Annual Report on Form 10K, Item 7A. Quantitative and Qualitative Disclosures
About Market Risk for a further discussion of these matters.)
The increase in net revenues also reflects $1.2 million of revenues from our
recently constructed 79 megawatt Glenwood generating facility that went into
operation on June 1, 2002. The capacity of and energy produced by the Glenwood
facility is dedicated to LIPA under long-term contract.
Operating Expenses
Operating expenses increased by $15.9 million, or 7% and by $14.5 million or 3%,
for the three and six months ended June 30, 2002, respectively, compared to the
comparable periods last year. The increase in operating expenses is due
primarily to an increase in third party costs. We expect to incur additional
third party costs for the remainder of the year. As previously mentioned, these
costs are fully recovered from LIPA.
Other Income and Deductions
The increase of $2.8 million and $4.9 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
"central account", or 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 six
months ended June 30, 2002, the subsidiaries within the Electric Services
segment have been net "lenders" into 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
During the quarter, we also completed the construction of the 79 MW Port
Jefferson electric generating facility on Long Island and placed this facility
in service on July 1, 2002. This facility is under a 25 year capacity and energy
contract with LIPA. We used short-term financing for the construction of the
Glenwood and Port Jefferson generating facilities, but we are currently
exploring various financing options to permanently finance these facilities.
(See the discussion under "Capital Expenditures and Financing" for more
information on our financing plans for 2002.) Further, in June 2002, we began
construction of 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 our 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 remained
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 approval of the New York State Public Authorities Control Board and
the State Controller.
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 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 of Dollars)
- ----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Three Months Ended Three Months Ended Six Months Ended Six Months Ended
June 30, 2002 June 30, 2001 June 30, 2002 June 30, 2001
- ----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Revenues $ 229,311 $ 232,771 $ 470,870 $ 551,864
Less: cost of gas and fuel 45,731 91,892 111,885 245,175
- ----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Net revenues 183,580 140,879 358,985 306,689
Other operating expenses 194,447 198,237 379,209 370,859
- ----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Operating Loss (10,867) (57,358) (20,224) (64,170)
Other Income and (Deductions) 615 318 775 751
- ----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Loss Before Interest and Taxes $ (10,252) $ (57,040) $ (19,449) $ (63,419)
- ----------------------------------- ----------------------- ----------------------- ----------------------- -----------------------
Comparative EBIT results for the three and six months ended June 30, 2002 verses
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 existing contracts, based upon our view that the general
contracting business is not a core competency of these companies. (See our
Annual Report on Form 10K for the year ended December 31, 2001 Item 7
"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 six months ended June 30, 2001, we
incurred EBIT losses of $53.3 million and $61.2 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 six months ended June 30, 2002, we incurred EBIT losses of $1.8
million and $3.3 million, respectively reflecting overhead, and administrative
and general expenses. These costs could not be accrued in 2001.
Excluding the results of the former Roy Kay companies, the Energy Services
segment reflected a decrease in EBIT of $4.6 million and $13.9 million for the
three and six months ended June 30, 2002, respectively compared to the
corresponding periods last year. Revenues, excluding the Roy Kay companies,
decreased by $45.7 million and $144.1 million for the three and six months ended
June 30, 2002, respectively, while the cost of fuel decreased by $46.2 million
and $133.3 million during the same time periods. These decreases, which for the
most part offset each other, reflect the operations of our gas and electric
marketing company. Beginning in 2002, we focused our marketing efforts on higher
net margin customers and as a result we have decreased our customer base.
EBIT results have been adversely impacted in 2002 by the general "down-turn" in
the New York metropolitan economy. In addition, the extremely warm weather
during the winter heating season has reduced the number of service calls and
repair orders received. Further, during the quarter ended June 30, 2002 we
increased our reserve for bad debts. 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, as well as to realize synergy savings.
Comparative EBIT results for the three and six months ended June 30, 2002
benefited from the elimination of goodwill amortization, which for the three and
six months ended June 30, 2001 amounted to $2.1 million and $4.2 million,
respectively.
Energy Investments
The Energy Investment segment consists of our gas exploration and production
operations as well as certain other domestic and international energy-related
investments. Our gas exploration and production subsidiaries are engaged in gas
and oil exploration and production and the development and acquisition of
domestic natural gas and oil properties. These investments consist of our 67%
equity interest in Houston Exploration, as well as our wholly-owned subsidiary,
KeySpan Exploration and Production, LLC.
This segment also consists of KeySpan Canada; our 20% interest in the Iroquois
Gas Transmission System LP ("Iroquois"); and our 50% interest in the Premier
Transmission Pipeline and 24.5% interest in Phoenix Natural Gas.
Selected financial data and operating statistics for our gas exploration and
production activities are set forth in the following table for the periods
indicated.
(In Thousands of Dollars)
- ----------------------------------------- --------------------- --------------------- ----------------------- ----------------------
Three Months Ended Three Months Ended Six Months Ended Six Months Ended
June 30, 2002 June 30, 2001 June 30, 2002 June 30, 2001
- ----------------------------------------- --------------------- --------------------- ---------------------- -----------------------
Revenues $ 88,274 $ 103,720 $ 162,988 $ 235,731
Depletion and amortization expense 44,440 33,419 85,885 67,052
Other operating expenses 14,379 13,282 27,823 32,444
- ----------------------------------------- --------------------- --------------------- ---------------------- -----------------------
Operating Income 29,455 57,019 49,280 136,235
Other Income and (Deductions)* (5,860) (13,062) (10,013) (26,762)
- ----------------------------------------- --------------------- --------------------- ---------------------- -----------------------
Earnings Before Interest and Taxes* $ 23,595 $ 43,957 $ 39,267 $ 109,473
- ----------------------------------------- --------------------- --------------------- ---------------------- -----------------------
Natural gas and oil production (Mmcf) 26,251 22,904 51,921 46,681
Natural gas price (per Mcf) realized $3.19 $4.54 $3.04 $5.05
Natural gas price (per Mcf) unhedged $3.19 $4.49 $2.70 $5.69
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. Gas reserves and
production are stated in BCFe and Mmcfe, which includes equivalent oil reserves.
Earnings Before Interest and Taxes
The decreases in EBIT of $20.4 million, or 46% and $70.2 million, or 64% for the
three and six months ended June 30, 2002, respectively, compared to the
corresponding periods last year, reflects a significant decrease in revenues
and, to a lesser degree, an increase in operating expenses associated with
higher production volumes. Revenues for the quarter and six months ended June
30, 2002, compared to the same periods in 2001, were adversely impacted by the
significant decline in average realized gas prices (average wellhead price
received for production including realized hedging gains and losses). Average
realized gas prices decreased 30% and 40% for the quarter and six months ended
June 30, 2002, respectively, compared to the corresponding periods last year.
The adverse effect on revenues resulting from the decline in average realized
gas prices was partially offset by increases of 15% and 11% in production
volumes during the quarter and six months ended June 30, 2002, respectively,
compared to the same periods last year. The depreciation, depletion and
amortization rate was $1.65 per mcf for the six months ended June 30, 2002
compared to $1.47 for the same period in 2001, as a result of higher finding and
development costs together with the addition of fewer new reserves.
The average realized gas price in the second quarter of 2002 was the same as the
average unhedged natural gas price and was 113% of the average unhedged natural
gas price for the six months ended June 30, 2002. The average realized gas price
in the second quarter of 2001 was 101% of the average unhedged natural gas price
and was 89% of the average unhedged natural gas price for the six months ended
June 30, 2001. Houston Exploration entered into derivative financial positions
in 2001 to hedge a substantial portion of its anticipated 2002 production. These
derivative instruments are designed to provide Houston Exploration with a more
predictable cash flow, as well as to reduce its exposure to fluctuations in
natural gas prices. The settlement of derivative instruments during the six
months ended June 30, 2002 resulted in a benefit to revenues of $17.0 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 we have significant downward
revisions in our estimated proved reserves.
At December 31, 2001, our gas exploration and production subsidiaries had 647
BCFe of net proved reserves of natural gas, of which approximately 72% were
classified as proved developed.
Selected financial data and operating statistics for our other energy-related
investments are set forth in the following table for the periods indicated.
(In Thousands of Dollars)
- ------------------------------------- ----------------------- ----------------------- ----------------------- ----------------------
Three Months Ended Three Months Ended Six Months Ended Six Months Ended
June 30, 2002 June 30, 2001 June 30, 2002 June 30, 2001
- ------------------------------------- ----------------------- ----------------------- ----------------------- ----------------------
Revenues $ 21,942 $ 24,222 $ 39,575 $ 51,191
Operation and maintenance expense 19,768 15,871 33,826 33,136
Other operating expenses 5,545 4,019 8,572 7,782
- ------------------------------------- ----------------------- ----------------------- ----------------------- ----------------------
Operating Income (Loss) (3,371) 4,332 (2,823) 10,273
Other Income and (Deductions) 4,637 2,816 8,982 6,128
- ------------------------------------- ----------------------- ----------------------- ----------------------- ----------------------
Earnings Before Interest and Taxes $ 1,266 $ 7,148 $ 6,159 $ 16,401
- ------------------------------------- ----------------------- ----------------------- ----------------------- ----------------------
Decreases in EBIT of $5.9 million, or 82%, and $10.2 million, or 62% for the
three and six months ended June 30, 2002 are primarily due to the operations of
KeySpan Canada, losses incurred by certain technology-related investments 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 both periods of 2002, compared to
the same periods in 2001, 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 for both the three and six months ended
June 30, 2002 compared to the same periods last year, as a result of lower
demand for LNG due to the extremely warm weather.
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 six months ended June 30,
2002, compared to the corresponding period last year, is primarily attributable
to lower interest and income tax payments. As previously mentioned, interest
payments have decreased due to the use of derivative financial instruments to
hedge a portion of our exposure to interest rate risk, as well as to lower
interest rates on outstanding commercial paper. Further, in terms of cash flow,
state and federal tax payments were lower for the first six months of 2002
compared to the same period last year, since we are currently in a refund
position with regards to such taxes. Operating cash flow from our gas
exploration and production activities, however, was adversely impacted by
significantly lower realized gas prices for the first six months of 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 our consolidated revenues are
derived from the operations of businesses within the Electric Services Segment,
that are dependent upon two large customers - LIPA and the NYISO. According, our
cash flows are dependent upon the timely payment of amounts owed to us by these
customers.
In July 2002, we renewed our 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 our
current $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 June 30, 2002, we had cash and temporary cash investments of $137.6 million.
During the six months ended June 30, 2002, we repaid $477.8 million of
commercial paper and, at June 30, 2002, $570.7 million of commercial paper was
outstanding at a weighted average annualized interest rate of 1.93%. We had the
ability to borrow up to an additional $829.3 million at June 30, 2002 under our
commercial paper program.
Under the terms of the credit facility, our debt-to-total capitalization ratio
will reflect 80% equity treatment for the MEDS Equity Units issued in May 2002;
further the $425 million Ravenswood Master Lease will be 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 June 30, 2002, our consolidated indebtedness, as
calculated under the terms of the new credit facility, was 63.1% of our
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.)
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.
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,
maintain: (i) an interest coverage ratio of at least 3.00 to 1.00 of earnings
before interest, taxes and depreciation to cash interest (EBITDA); (ii) a total
debt to EBITDA of not more than a ratio of 3.50 to 1.00; and (iii) sets a
maximum limit of 70% on the amount of natural gas production that may be hedged
during any 12-month period.
During the six months ended June 30, 2002, Houston Exploration borrowed $46.0
million under its prior credit facility and repaid $10.0 million. At June 30,
2002, $180 million of borrowings remained outstanding at a weighted average
annualized interest rate of 3.23%; $70.0 million of borrowing capacity was
available. Also, KeySpan Canada has two revolving loan agreements with financial
institutions in Canada. Repayments under these agreements totaled approximately
$26.4 million for the six months ended June 30, 2002. At June 30, 2002,
approximately $157 million was outstanding at a weighted average annualized
interest rate of 3.05%. KeySpan Canada currently has available borrowings of
approximately $57 million.
KeySpan has fully and unconditionally guaranteed $525 million of medium- term
notes issued by KEDLI under KEDLI's current shelf registration, as well as a
$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) $160.8 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
$85.3 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) $59.7 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 $174.5 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 of Dollars)
- ------------------------------- ----------------------- -----------------------
Six Months Ended Six Months Ended
June 30, 2002 June 30, 2001
- ------------------------------- ----------------------- -----------------------
Gas Distribution $ 183,588 $ 120,874
Electric Services 225,051 99,196
Energy Investments 176,755 198,612
Energy Services 10,109 6,125
- ------------------------------- ----------------------- -----------------------
$ 595,503 $ 424,807
- ------------------------------- ----------------------- -----------------------
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 our 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 our joint venture
with Houston Exploration, as well as costs related to Canadian affiliates.
At June 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
$162.6 million.
The amount of future construction expenditures is reviewed on an ongoing basis
and can be affected by timing, scope and changes in investment opportunities.
Financing
At December 31, 2001, we had an existing $1 billion shelf registration statement
on file with the Securities and Exchange Commission ("SEC"), with $500 million
available for issuance. In February 2002, we updated our shelf registration for
the issuance of an additional $1.2 billion of securities, thereby giving us the
ability to issue up to $1.7 billion of debt, equity or various forms of
preferred stock. 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 our financing authority under PUCHA by $700 million,
thereby matching our shelf availability. We anticipate action on this request by
the SEC this year.
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.
By the end of 2002, we intend to issue approximately $150 to $200 million of
either taxable or tax-exempt debt securities, the proceeds of which, it is
anticipated, will be used to re-pay the outstanding commercial paper related to
the construction of our two Long Island peaking-power plants. We also may issue
additional medium-term or long-term debt towards the latter part of 2002 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 have several interest rate swap agreements on a portion of our existing
fixed rate medium-term and long-term debt that effectively change the debt to
floating rate debt. These swap agreements qualify for hedge accounting and were
completed with several major financial institutions in order to reduce credit
risk. (See Note 6 to the Consolidated Financial Statements "Derivative Financial
Instruments" for additional information on these swap agreements.)
We also have an arrangement with a special purpose financing entity through
which we lease a portion of the Ravenswood facility. We acquired the Ravenswood
facility from Consolidated Edison on June 18, 1999 for approximately $597
million. In order to reduce our initial cash requirements, we entered into a
lease agreement with a special purpose, unaffiliated financing entity that
acquired a portion of the facility directly from Consolidated Edison and leased
it to our subsidiary. We have guaranteed all payment and performance obligations
of our subsidiary under the lease. The lease represents approximately $425
million of the acquisition cost of the facility, which is the amount of debt
that would have been recorded on our Consolidated Balance Sheet had the special
purpose financing entity not been utilized and conventional debt financing been
employed. Further, we would have recorded an asset in the same amount. Monthly
lease payments represent interest only. The lease qualifies as an operating
lease for financial reporting purposes while preserving our ownership of the
facility for federal and state income tax purposes.
The initial term of the lease expires on June 20, 2004 and may be extended until
June 20, 2009. In June 2004, we have the right to either purchase the facility
or terminate the lease and dispose of the facility for an amount generally equal
to the original acquisition cost, $425 million, plus the present value of the
lease payments that would have otherwise been paid through June 20, 2009. In
June 2009, when the lease terminates, we may purchase the facility in an amount
generally equal to the original acquisition cost or surrender the facility to
the lessor. At this time, we believe that the fair market value of the leased
assets is in excess of the original acquisition cost.
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 2002, and be effective
January 1, 2003. It is possible that we may be required to classify the lease
under which we operate the Ravenswood facility as approximately $425 million of
indebtedness
and reflect such amount on our Consolidated Balance Sheet. As previously
mentioned, under the terms of our new credit facility the Ravenswood Master
Lease is currently considered as debt in the ratio of debt-to-total
capitalization. At this time, however, we are unable to determine what the
requirements will be under the final guidance, if and when an accounting
Standard is issued, as well as the actual impact on our results of operations
and financial position.
The ratings on our long-term debt have remained unchanged from December 31,
2001. Moody's Investor Services rated: (i) KeySpan's long-term debt at A3; and
(ii) KEDNY's, KEDLI's, Boston Gas Company's and Colonial Gas Company's long-term
debt at A2. Standard and Poor's rating agency rated: (i) the long-term debt of
KeySpan, KeySpan Generation, Boston Gas Company and Colonial Gas Company at A;
and (ii) KEDNY's and KEDLI's long-term debt at A+.
Our contractual cash obligations and associated maturities have 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 June 30, 2002:
(In Thousands of Dollars)
- ---------------------------------------- ------------------- --------------------- ----------------------- -------------------------
Contractual Obligations Total 1-3 Years 4-5 Years After 5 Years
- ---------------------------------------- ------------------- --------------------- ----------------------- -------------------------
Long-Term Debt $ 5,263,490 $ 486,184 $ 1,212,333 $ 3,564,973
Capital Lease Obligations 14,969 2,826 2,163 9,980
Operating Leases 633,313 261,953 165,441 205,919
- ---------------------------------------- ------------------- --------------------- ----------------------- -------------------------
Total Contractual
Cash Obligations $ 5,911,772 $ 750,963 $ 1,379,937 $ 3,780,872
- ---------------------------------------- ------------------- --------------------- ----------------------- -------------------------
Commercial Paper $ 570,655 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 our 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 by subsidiaries in our Energy Services
segment. This accounting method measures the percentage of costs incurred and
accrued to date for each contract to the estimated total costs for each contract
at completion. These estimates are based upon available information at the time
of review, and changes in estimates resulting in additional future costs to
complete projects can result in reduced margins or loss contracts. Provisions
for estimated losses on uncompleted contracts are made in the period such losses
are determined. Changes in job performance, job conditions and estimated
profitability are recognized in the period that the revisions are determined.
Valuation of Goodwill
On January 1, 2002, we adopted SFAS 141, "Business Combinations", and SFAS 142
"Goodwill and Other Intangible Assets". The key concepts from the two
interrelated Statements include mandatory use of the purchase method when
accounting for business combinations, discontinuance of goodwill amortization, a
revised framework for testing goodwill impairment at a "reporting unit" level,
and new criteria for the identification and potential amortization of other
intangible assets.
Other changes to existing accounting standards involve a requirement to test
goodwill for impairment at least annually. The initial impairment test is to be
performed within six months of adopting SFAS 142 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 will 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.
We record goodwill on purchase transactions, representing the excess of
acquisition cost over the fair value of net assets acquired. In testing for
goodwill impairment under SFAS 142, significant reliance is placed upon
estimated future cash flows 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
will likely differ from our projections.
We have completed our analysis for all of our 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. In the future, we will
conduct an annual review 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 have interest rate swap agreements in which approximately $1.3
billion of fixed rate debt has been effectively converted to floating rate debt.
The fair value of these derivative instruments is 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 our
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") No. 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 June 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 we
will be required to write down the full cost pool 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 our 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 Utility
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 Statement of Financial Accounting Standards ("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 currently in effect for KEDNY, KEDLI and Boston Gas Company will all
have expired by October 31, 2002. The continued application of SFAS 71 to record
the activities of these subsidiaries is contingent upon the actions of
regulators with regards 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 Massachusetts
Department of Telecommunications and Energy ("DTE") that we may file a base rate
case and a performance based rate plan for the Boston Gas Company to replace the
current plan that expires 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. The Massachusetts Attorney General has submitted a
letter to the DTE stating his opposition to our request. Our request is
currently pending before the DTE.
The rate agreement for KEDLI expired in November 2001 and the rate agreement for
KEDNY expires September 30, 2002. The New Hampshire Public Utility Commission
has indicated that they may examine the cost structure of EnergyNorth Natural
Gas during 2002. At this time, 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 rate plans.
For additional discussion of our current gas distribution rate agreements, see
our Annual Report on Form 10-K for the year ended December 31, 2001, Item 7
"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, 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 June 30, 2002 our consolidated common equity was 34% 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 $207.0 million
and we have recorded a related liability for such amount. We have also recorded
an additional $41.8 million liability, representing the estimated environmental
cleanup costs related to a former coal tar processing facility. Further, as of
June 30, 2002, we have expended a total of $54.0 million. (See Note 4 to the
Consolidated Financial Statements, "Environmental Matters").
Cautionary Statement Regarding Forward-Looking Statements
Certain statements contained in this Quarterly Report on Form 10-Q concerning
expectations, beliefs, plans, objectives, goals, strategies, future events or
performance and underlying assumptions and other statements that are other than
statements of historical facts, are "forward-looking statements" within the
meaning of Section 21E of the Securities Exchange Act of 1934, as amended.
Without limiting the foregoing, all statements under the captions "Item 2.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Item 3. Quantitative and Qualitative Disclosures About Market
Risk" relating to our future outlook, anticipated capital expenditures, future
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;
- - 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
We are subject to various risks and uncertainties associated with our
operations. The most significant of which involves the evolution of the gas
distribution and electric industries towards a more competitive and deregulated
environment. In addition, we are exposed to commodity price risk, interest rate
risk and, to much less degree, foreign currency translation risk. Below is an
update of the various risks associated with our operations. Additionally, see
our 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 $1000/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 we have 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
our peak electric energy sales. Our 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 June 30, 2002, Houston Exploration
has hedged approximately 64% of its estimated 2002 yearly production and
approximately 40% of its estimated 2003 yearly 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 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 $3.8
million. The measured amount of hedge ineffectiveness was immaterial.
We have also employed standard NYMEX gas futures contracts, as well as oil swap
derivative contracts, to fix the purchase price for a portion of the fuel used
at the Ravenswood facility. The maximum length of time over which we have hedged
such cash flow variability is through February 2004. We used standard NYMEX
futures prices to value the gas futures contracts and industry published oil
indices for number 6 grade fuel oil to value the oil swap contracts. The
estimated amount of gains 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 $1.7
million. The measured amount of hedge ineffectiveness was immaterial.
Our gas and electric marketing subsidiary, as well as our gas distribution
operations, have fixed rate gas sales contracts and utilized standard NYMEX
futures contracts to lock-in a price for future natural gas purchases. We used
standard NYMEX futures prices to value the outstanding contracts. The maximum
length of time over which we have hedged such cash flow variability is through
February 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 $0.8 million. The measured amount of hedge ineffectiveness was
immaterial.
We have also engaged in the use of derivative swap instruments to hedge the cash
flow variability associated with a portion of our forecasted 2002 summer and
winter peak electric energy sales from the Ravenswood facility. We currently
have hedge positions for approximately 50% of our estimated 2002 summer peak
electric sales from the Ravenswood facility. We used NYISO-location zone
published indices and standard NYMEX prices to value these outstanding
derivatives. The maximum length of time over which we have hedged such cash flow
variability is through December 2002. 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 $1.6 million. The measured amount of
hedge ineffectiveness was immaterial.
KeySpan Canada has also employed electric swap contracts to lock-in the purchase
price on the purchase of electricity needed to operate its gas processing
plants. These contracts are not exchange- traded and we used local published
indices 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 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 $2.2 million. The measured amount of hedge ineffectiveness was
immaterial.
The following tables set forth selected financial data associated with these
derivative financial instruments noted above that were outstanding at June 30,
2002.
- --------------------------- ------------ --------------- ------------ ------------- ----------------- ----------------- ------------
Year of Volumes Fixed Price $ Current Price $ Fair Value
Type of Contract Maturity mmcf Floor $ Ceiling $ ($000)
- --------------------------- ------------ --------------- ------------ ------------- ----------------- ----------------- ------------
Gas
Collars 2002 29,440 3.56 5.14 - 3.25 - 3.88 9,149
2003 25,550 3.34 4.97 - 3.72 - 4.24 1,937
Swaps -Short Natural Gas 2002 5,520 - - 3.01 3.25 - 3.88 (2,321)
2003 14,600 - - 3.19 3.72 - 4.24 (9,954)
Swaps - Long Natural Gas 2002 3,920 - - 2.44 - 3.91 3.25 - 3.95 947
2003 2,110 - - 3.10 - 4.00 3.72 - 4.04 1,017
- --------------------------- ------------ --------------- ------------ ------------- ----------------- ----------------- ------------
81,140 775
- --------------------------- ------------ --------------- ------------ ------------- ----------------- ----------------- ------------
Type of Contract Year of Maturity Volumes Fair Value
Barrels Fixed Price $ Current Price $ ($000)
- ----------------------------- -------------------- ----------------- --------------------- ----------------------- -----------------
Oil
- ----------------------------- -------------------- ----------------- --------------------- ----------------------- -----------------
Swaps - Long Fuel Oil 2002 163,474 19.75 - 24.49 24.58 - 24.93 486
2003 346,892 20.10 - 26.72 22.19 - 23.94 405
2004 3,894 23.50 - 23.70 23.23 - 23.32 7
- ----------------------------- -------------------- ----------------- --------------------- ----------------------- -----------------
514,260 898
- ----------------------------- -------------------- ----------------- --------------------- ----------------------- -----------------
Type of Contract Year of Current Price Estimated Profit $ Fair Value
Maturity MWh Fixed Profit /Price $ $ ($000)
- ------------------------- -------------- ------------ ----------------------- --------------- ------------------- -----------------
Electricity
Tolling Arrangements 2002 732,800 26.00 - 56.50 - 4.07 - 49.07 1,635
Swaps - Long 2002 35,328 58.70 - 60.01 26.02 - (1,121)
2003 70,080 58.70 - 60.01 28.25 - (2,067)
- ------------------------- -------------- ------------ ----------------------- --------------- ------------------- -----------------
838,208 (1,553)
- ------------------------- -------------- ------------ ----------------------- --------------- ------------------- -----------------
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 used natural gas swap contracts, with offsetting positions in oil
swap contracts of equivalent energy value, to hedge the cash-flow variability of
specified portions of gas purchases and sales. All positions that were
outstanding at December 31, 2001 settled during the first quarter of 2002. We
intend to enter into additional derivative instruments of this nature during
2002 if market conditions so warrant.
Firm Gas Sales Derivative Instruments - Regulated Utilities: We have also
utilized derivative financial instruments to reduce the cash flow variability
associated with the purchase price for a portion of our future natural gas
purchases. Our strategy is to minimize fluctuations in firm gas sales prices to
our regulated firm gas sales customers in our New York and New Hampshire service
territories. Since these derivative instruments are employed to support our gas
sales prices 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 tables set forth selected financial data associated with these
derivative financial instruments that were outstanding at June 30, 2002.
- ----------------------------- -------------------- ------------------ ---------------------- --------------------- -----------------
Type of Contract Year of Maturity Volumes Fair Value
Mmcf Fixed Price $ Current Price $ ($000)
- ----------------------------- -------------------- ------------------ ---------------------- --------------------- -----------------
Gas
Call Options 2002 1,280 4.20 - 4.50 3.69 - 3.95 17
2003 1,960 4.20 - 4.50 3.88 - 4.04 253
- ----------------------------- -------------------- ------------------ ---------------------- --------------------- -----------------
3,240 270
- ----------------------------- -------------------- ------------------ ---------------------- --------------------- -----------------
Contract Review
On April 1, 2002 we implemented Implementation 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 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 as normal purchase. As a result, and effective April 1, 2002, such
contracts are required to be recorded on the Consolidated Balance Sheet at fair
value and had a calculated fair value on that date of $7.8 million. At June 30,
2002,the fair value of these contracts was $5.0 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 will be recorded as a Regulatory Asset or
Regulatory Liability on the Consolidated Balance Sheet.
Interest Rate Swaps: We also have interest rate swap agreements in which
approximately $1.3 billion of fixed rate debt has been synthetically modified to
floating rate debt. For the term of the agreements, we will receive the fixed
coupon rate associated with these bonds and pay the counter parties a variable
interest rate that is reset on a quarterly basis. These swaps are fair- value
hedges and qualify for "short-cut" hedge accounting treatment under SFAS 133.
Through the utilization of our interest rate swap agreements, we reduced
recorded interest expense by $22.7 million for the six months ended June 30,
2002. The fair values of these derivative instruments are provided to us by
third party appraisers and represent the present value of future cash-flows
based on a forward interest rate curve for the life of the derivative
instrument.
During the quarter ended June 30, 2002, the swap arrangement associated with a
$90 million Gas Facilities Revenue Bond was terminated by our counter party. At
that time we had an immaterial derivative asset recorded. As provided for under
the terms of the swap agreement, our counter party had the right to terminate
the swap arrangement at their discretion without a fee or penalty. Since neither
a fee nor penalty was imposed on the counter-party, the termination of this swap
arrangement had no earnings impact.
The table below summarizes selected financial data associated with these
derivative financial instruments that were outstanding at June 30, 2002.
- --------------------------- ---------------------- ------------------------- -------------- ----------------------- ----------------
Average Variable
Maturity Date of Notional Amount Fixed Rate Rate Paid Year to Date Fair Value
Bond Swaps ($000) Received ($000)
- --------------------------- ---------------------- ------------------------- -------------- ----------------------- ----------------
Medium Term Notes 2010 500,000 7.625% 4.290% 3,022
Medium Term Notes 2006 500,000 6.150% 3.320% 4,581
Medium Term Notes 2023 270,000 8.200% 3.620% (309)
- --------------------------- ---------------------- ------------------------- -------------- ----------------------- ----------------
1,270,000 7,294
- --------------------------- ---------------------- ------------------------- -------------- ----------------------- ----------------
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. The
measured amount of hedge ineffectiveness was immaterial. We estimate that a 1%
increase in current interest rates would result in a $10.3 million increase to
interest expense.
Derivative contracts are primarily used to manage our exposure to market risk
arising from changes in commodity prices and interest rates. In the event of
nonperformance by a counter party to 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 our derivative contracts are with investment
grade companies. (See Item 3. Quantitative and Qualitative Disclosures About
Market Risk for a discussion on credit risk.)
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 and industrial customers 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.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
See Note 10 to the Financial Statements "Legal Matters"
Item 4. Submission of Matters to a Vote of Security Holders
We held our annual meeting of shareholders on May 9, 2002, at 10:00 a.m. Eastern
Time, at the Tilles Center for the Performing Arts, Long Island University, C.
W. Post Campus, 720 Northern Boulevard, Greenvale, New York, to consider and
take action on the following items:
1. Election of ten directors
The names of the persons who received a plurality of the votes cast by the
holders of shares entitled to vote thereon, and who were accordingly elected
Directors of KeySpan for one year or until their successors are duly elected or
chosen and qualified are as follows:
DIRECTOR VOTES VOTES TOTAL
FOR WITHHELD VOTES
Robert B. Catell 115,384,212 2,249,325 117,633,537
Andrea S. Christensen 115,387,150 2,246,387 117,633,537
Howard R. Curd 115,441,910 2,191,627 117,633,537
Donald H. Elliott 115,358,103 2,275,434 117,633,537
Alan H. Fishman 115,411,326 2,222,211 117,633,537
J. Atwood Ives 115,383,174 2,250,363 117,633,537
James R. Jones 115,400,216 2,233,321 117,633,537
James L. Larocca 115,435,440 2,198,097 117,633,537
Stephen W. McKessy 114,782,537 2,851,000 117,633,537
Edward D. Miller 115,419,908 2,213,629 117,633,537
2. Ratification of Deloitte & Touche LLP, as independent public accountants
for the Company for the year ending December 31, 2002
Deloitte & Touche LLP received a majority of the votes cast by the holders of
shares entitled to vote thereon, and was accordingly ratified Independent Public
Accountants of KeySpan for the fiscal year ending December 31, 2002.
DELOITTE & TOUCHE LLP VOTES CAST
FOR 111,704,204
AGAINST 4,689,073
ABSTAIN 1,240,428
TOTAL 117,633,705
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
4.1* Credit Agreement among KeySpan Corporation, the several Lenders, ABN AMRO
Bank, N.V. and Citibank, N.A., as Co-Syndication Agents, The Bank of New
York and The Royal Bank of Scotland PLC, as Co-Documentation Agents, and
J.P. Morgan Chase Bank, as Administrative Agent for $1.3 billion, dated as
of July 9, 2002
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 our report on Form 8-K dated April 5, 2002, we reported that on March 29,
2002, KeySpan's Board of Directors, upon recommendation of the Audit Committee,
determined not to renew the engagement of its independent public accountant
Arthur Andersen LLP and appointed Deloitte & Touche as its independent public
accountants.
In our report on Form 8-K dated April 25, 2002, we reported that we had issued a
press release concerning, among other things, our earnings for the quarter ended
March 31, 2002.
In our report on Form 8-K dated May 6, 2002, we reported that we had completed
the issuance of 8,000,000 MEDS Equity Units initially consisting of 8,000,000
Corporate MEDS on May 6, 2002.
In our 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
July 2, 2002.
In our 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, its earnings for
the quarter ended June 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: August 12, 2002 /s/ Gerald Luterman
-----------------------------
Gerald Luterman
Executive Vice President and
Chief Financial Officer
Date: August 12, 2002 /s/ Ronald S. Jendras
------------------------------
Ronald S. Jendras
Vice President, Controller and
Chief Accounting Officer