SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
Amendment No. 1
[X ]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
[ ]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the period from January 1, 2001 to December 31, 2001
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 incorporation or organization) (I.R.S. employer identification no.)
One MetroTech Center, Brooklyn, New York 11201
175 East Old Country Road, Hicksville, New York 11801
(Address of principal executive offices) (Zip code)
(718) 403-1000 (Brooklyn)
(516) 755-6650 (Hicksville)
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of each class Name of each exchange on which registered
- ------------------- -----------------------------------------
Common Stock, $.01 par value New York Stock Exchange
Pacific Stock Exchange
Series AA Preferred Stock, $25 par value New York Stock Exchange
Pacific Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None
(Title of class)
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.
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. __
As of March 1, 2002, the aggregate market value of the common stock held
by non-affiliates (139,252,417 shares) of the registrant was $4,450,003,939
based on the closing price, on such date, of $32.66 per share.
As of March 1, 2002, there were 140,013,471 shares of common stock, $.01
par value, outstanding.
EXPLANATORY NOTE
KeySpan Corporation hereby amends its Form 10-K for the period from January 1,
2001 to December 2001 (the "Form 10-K"). This Form 10-K/A does not include any
changes to the Financial Statements.
KEYSPAN CORPORATION
INDEX TO FORM 10-K
Page
----
Part I
Item 1. Description of the Business................................................................................
Item 2. Properties.................................................................................................
Item 3. Legal Proceedings..........................................................................................
Item 4. Submission of Matters to a Vote of Security Holders........................................................
Part II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters......................................
Item 6. Selected Financial Data....................................................................................
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Item 7A Quantitative and Qualitative Disclosures About Market Risk ................................................
Item 8. Financial Statements and Supplementary Data ...............................................................
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure....................................................................
Part III
Item 10. Directors and Executive Officers of the Registrant
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management
Item 13. Certain Relationships and Related Transactions
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
PART I
Item 1. Description of the Business
Corporate Overview
KeySpan Corporation ("KeySpan"), a New York corporation, is a member of the
Standard and Poor's 500 Index and a registered holding company under the Public
Utility Holding Company Act of 1935, as amended ("PUHCA"). KeySpan was formed in
May 1998, as a result of the business combination of KeySpan Energy Corporation,
the parent of The Brooklyn Union Gas Company, and certain businesses of the Long
Island Lighting Company ("LILCO"). On November 8, 2000, we acquired Eastern
Enterprises ("Eastern"), a Massachusetts business trust, that primarily owns
three gas utilities operating in Massachusetts, Boston Gas Company ("Boston
Gas"), Colonial Gas Company ("Colonial Gas") and Essex Gas Company ("Essex
Gas"); as well as EnergyNorth Natural Gas, Inc. ("EnergyNorth"), a gas utility
operating principally in central New Hampshire. As used herein, "KeySpan," "we,"
"us" and "our" refers to KeySpan, its six principal gas distribution
subsidiaries, and its other regulated and unregulated subsidiaries, individually
and in the aggregate.
Under our holding company structure, we have no independent operations and
conduct substantially all of our operations through our subsidiaries. Our
subsidiaries operate in the following businesses: Gas Distribution, Electric
Services, Energy Services and Energy Investments.
The Gas Distribution segment consists of our six regulated gas distribution
subsidiaries, which operate in New York, Massachusetts and New Hampshire and
serve approximately 2.5 million customers.
The Electric Services segment consists of subsidiaries that operate the electric
transmission and distribution ("T&D") system owned by the Long Island Power
Authority ("LIPA"); provide energy conversion services for LIPA from our
generating facilities located on Long Island; and manage fuel supplies for LIPA
to fuel our approximate 4,000 megawatts of Long Island generating facilities.
The electric services segment also includes subsidiaries that own, lease and
operate the 2,200 megawatt Ravenswood electric generation facility (the
"Ravenswood facility"), located in Queens County in New York City.
The Energy Services segment primarily provides energy-related services to
customers primarily located within New York, New Jersey, Massachusetts, New
Hampshire, Rhode Island and Pennsylvania through various subsidiaries that
operate under the following principal four lines of business: (i) home energy
services; (ii) business solutions; (iii) commodity procurement; and (iv) fiber
optic services.
We are also engaged in Energy Investments which include: (i) gas exploration and
production activities; (ii) domestic pipelines and gas storage facilities; (iii)
midstream natural gas processing activities in Canada; and (iv) natural gas
distribution and pipeline activities in the United Kingdom.
KeySpan's vision is to be the premier energy company in the Northeastern United
States. To help us achieve that goal, we acquired the operations of Eastern and
EnergyNorth in November 2000, establishing KeySpan as the largest gas
distribution company in the Northeast and the fifth largest in the United
States. The increased size and scope of the Company should enable us to provide
enhanced cost-effective customer service; offer our existing customers other
services and products by implementing innovative marketing techniques and
building upon our existing customer relationships; and to capitalize on the
above-average growth opportunities for natural gas expansion in the Northeast by
expanding our infrastructure primarily on Long Island and in New England.
The key element of our business strategy is the continued focus and growth of
our Gas Distribution, Electric Services and Energy Services businesses. We are
also exploring the sale of some or all of our assets in the Energy Investments
segment. KeySpan's financial statements are prepared on the basis of reporting
our operations under the following four business segments: Gas Distribution,
Electric Services, Energy Services and Energy Investments. Additional
information about KeySpan's industry segments is contained in Note 2 to the
Consolidated Financial Statements, "Business Segments" included herein and
incorporated by reference thereto.
Certain statements contained in this Annual Report on Form 10-K 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 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Item 7A. 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:
- - general economic conditions, especially in the Northeast United States;
- - our ability to successfully reduce our cost structure;
- - implementation of new accounting standards;
- - inflationary trends and interest rates;
- - the ability of KeySpan to identify and make complementary acquisitions, as
well as the successful integration of such acquisitions;
- - available sources and cost of fuel;
- - federal and state regulatory initiatives that increase competition,
threaten cost and investment recovery, and impact the rate structures of
our regulated businesses;
- - the exercise by LIPA of its right to acquire our Long Island generation
operations and the possible deployment of the proceeds received in
connection therewith;
- - potential write-down of our investment in natural gas properties when
natural gas prices are depressed or if we have significant downward
revisions in our estimated proved gas reserves;
- - competition in general facing our unregulated Energy Services businesses,
including but not limited to competition from other mechanical, heating,
ventilation and air conditioning ("HVAC"), engineering companies and other
utilities which are permitted to engage in such activities;
- - the degree to which we develop unregulated business ventures, as well as
federal and state regulatory policies affecting our ability to retain and
operate such business ventures;
- - other risks detailed from time to time in other reports and other documents
filed by KeySpan with the Securities and Exchange Commission ("SEC").
For any of these statements, KeySpan claims the protection of the safe harbor
for forward-looking information contained in the Private Securities Litigation
Reform Act of 1995, as amended. For additional discussion on these risks,
uncertainties and assumptions, see "Item 1. Business," "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
"Item 7A. Quantitative and Qualitative Disclosures About Market Risk" contained
herein.
KeySpan's principal executive offices are located at One MetroTech
Center, Brooklyn, New York 11201 and 175 East Old Country Road, Hicksville, New
York 11801 and its telephone numbers are (718) 403-1000 (Brooklyn) and (516)
755-6650 (Hicksville). Financial and other information is also available through
the World Wide Web at http://www.keyspanenergy.com (Investor Relations section).
Gas Distribution Overview
Our gas distribution activities are conducted by our six regulated gas
distribution subsidiaries, which operate in three states in the Northeast - New
York, Massachusetts and New Hampshire. We are the fifth largest gas distribution
company in the United States and the largest in the Northeast, with
approximately 2.5 million customers served within an aggregate service area
covering 4,273 square miles. In New York, The Brooklyn Union Gas Company doing
business as KeySpan Energy Delivery New York ("KEDNY") provides gas distribution
services to customers in the New York City Boroughs of Brooklyn, Queens and
Staten Island; and KeySpan Gas East Corporation doing business as 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. In Massachusetts, Boston Gas distributes natural gas in eastern
and central Massachusetts; Colonial Gas distributes natural gas in Cape Cod and
eastern Massachusetts; and Essex Gas distributes natural gas in eastern
Massachusetts. In New Hampshire, EnergyNorth distributes gas to customers
principally located in central New Hampshire. Our New England gas companies all
do business as KeySpan Energy Delivery New England ("KEDNE").
In New York there are two separate, but contiguous service territories served by
KEDNY and KEDLI, comprising approximately 1,417 square miles, and 1.66 million
customers. In Massachusetts, Boston Gas, Colonial Gas and Essex Gas serve three
contiguous service territories consisting of 1,934 square miles and
approximately 768,000 customers. In New Hampshire, EnergyNorth has a service
territory that is contiguous to Colonial's and is within 30 to 85 miles of the
greater Boston area. EnergyNorth provides service to approximately 75,000
customers over a service area of approximately 922 square miles. Collectively,
KeySpan owns and operates gas distribution, transmission and storage systems
that consist of approximately 21,000 miles of gas mains and distribution
pipelines and 576 miles of transmission pipelines, as well as two major gas
storage facilities.
Gas is offered for sale to residential and small commercial customers on a
"firm" basis, and to most large commercial and industrial customers on a "firm"
or "interruptible" basis. "Firm" service is offered to customers under tariffed
schedules or contracts that anticipate no interruptions, whereas "interruptible"
service is offered to customers under schedules or contracts that anticipate and
permit interruption on short notice, generally in peak-load seasons or for
system reliability reasons. We have restructured our gas supply and capacity
contracts to reduce fixed costs and to minimize the risk of stranded costs. We
maintain sufficient gas supply and capacity contracts to serve our customers,
maintain system reliability and system operations, and to meet our obligation to
serve. Over the long term, we intend to minimize our costs by purchasing gas at
points within or in close proximity to our market area, which will only require
us to contract for firm short-haul rather than long-haul transportation
capacity.
Gas is available at any time of the year on an interruptible basis, if supply is
sufficient and the gas delivery system is operationally adequate. KeySpan
actively promotes a competitive retail gas market by making capacity available
to retail marketers that are unable to obtain their own capacity. KeySpan also
participates in interstate markets by releasing pipeline capacity or by bundling
gas supply and pipeline capacity for "off-system" sales. An "off-system"
customer consumes gas at facilities located outside of our service territories
by connecting to our facilities or another transporter's facilities at a point
of delivery agreed to by us and the customer.
KeySpan purchases natural gas for sale to customers under both long-and
short-term supply contracts, and on the spot market, under firm transportation
contracts. In addition, KeySpan contracts for firm capacity in natural gas
underground storage facilities and for winter peaking supplies.
KeySpan sells gas to firm gas customers at its cost for such gas, plus a charge
designed to recover the costs of distribution (including a return of and a
return on capital invested in our distribution facilities). We share with our
firm gas customers net revenues (operating revenues less the cost of gas) from
off-system sales and capacity release transactions. Further, net revenues from
tariff gas balancing services and certain on-system sales are refunded, for the
most part, to firm customers subject to certain sharing provisions.
Our gas operations can be significantly affected by seasonal weather conditions.
Traditionally, annual revenues are substantially realized during the heating
season as a result of higher sales of gas due to cold weather. Accordingly,
operating results historically are most favorable in the first and fourth
calendar quarters.
KEDNY and KEDLI each operate under a tariff that contains a weather
normalization adjustment that provides for recovery from or refund to firm
customers of material shortfalls or excesses of firm net revenues (revenues less
applicable gas costs) during a heating season due to variations from normal
weather. However, the tariffs for our four KEDNE gas distribution companies do
not contain such a weather normalization adjustment and, therefore, fluctuations
in seasonal weather conditions between years may have a significant effect on
results of operations and cash flows for these four subsidiaries. For additional
discussion, see "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations - Regulation and Rate Matters".
Gas sales and revenues for 2001 by class of customer are set forth below:
Sales Revenues Revenues
Customer (MDTH) (thousands of $) (% of Total)
- -------------------------------------------------- -------------------- ------------------------ ---------------------
Firm
Residential Heating 152,725 1,944,414 53.81
Residential Non-Heating 12,412 255,623 7.07
Temperature-Controlled heating 28,694 191,504 5.30
Commercial / Industrial 67,642 733,560 20.30
-------------------- ------------------------ ---------------------
Total Firm 261,473 3,125,101 86.48
-------------------- ------------------------ ---------------------
Firm Transportation 101,000 87,089 2.41
Transportation - Electric Generation 64,578 7,496 .21
-------------------- ------------------------ ---------------------
Total Firm Transportation 165,578 94,585 2.62
-------------------- ------------------------ ---------------------
Total Firm Gas Sales and Transportation 427,051 3,219,686 89.10
Interruptible 7,235 47,082 1.30
Off-System Sales 40,058 138,415 3.83
Transportation 59,507 154,905 4.29
-------------------- ------------------------ ---------------------
Total Gas Sales and Transportation 533,851 3,560,088 98.52
Other Retail Services - 53,463 1.48
-------------------- ------------------------ ---------------------
Total Sales and Revenues 533,851 3,613,551 100.00
==================== ======================== =====================
Further information and statistics regarding our Gas Distribution segment see
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations, "Gas Distribution."
New York Gas Distribution System - KEDNY and KEDLI
Supply and Storage
KEDNY and KEDLI have contracts for the purchase of firm long-term transportation
and underground storage services. Gas supplies are purchased under long and
short-term contracts, as well as on the spot market. Gas supplies are
transported by interstate pipelines from domestic and Canadian supply basins.
Peaking supplies are available to meet system requirements during winter
periods.
Peak-Day Capability. The design criteria for the New York gas system assumes an
average temperature of 0(0)F for peak-day demand. Under such criteria, we
estimate that the requirements to supply our firm gas customers would amount to
approximately 1,993 MDTH of gas for a peak-day during the 2001/02 winter season
and that the gas available to us on such a peak-day amounts to approximately
2,036 MDTH. For the 2002/03 winter season, we estimate the peak-day requirements
will amount to 1,996 MDTH and that the gas supplies available on such a peak-day
amount to approximately 2,046 MDTH . The 2001/02 winter peak-day throughput to
our New York customers was 1,411 MDTH, which occurred on December 31, 2001 at an
average temperature of 26 F, representing 69% of our per day capability
at that time. We plan to have sufficient gas available to meet the requirements
of firm gas customers for both the 2001/02 and 2002/03 winter seasons. Our New
York firm gas peak-day capability is summarized in the following table:
Source MDTH per % of Total
day
- --------------------- --- -------------------- ---- -------------------
Pipeline........... 752 37
Underground Storage 779 38
Peaking Supplies... 505 25
--- --
Total 2,036 100
- --------------------- --- ==================== ---- ===================
Pipelines. Our New York based gas distribution utilities purchase natural gas
for sale to their New York gas customers under contracts with suppliers with
natural gas located in domestic and Canadian supply basins and arrange for its
transportation to our facilities under firm long-term contracts with interstate
pipeline companies. For the 2001/02 winter, approximately 76% of our New York
natural gas supply was available from domestic sources and 24% from Canadian
sources. We have available under firm contract 752 MDTH per day of year-round
and seasonal pipeline transportation capacity to our facilities in the New York
City metropolitan area. Major providers of interstate pipeline capacity and
related services to us include: Transcontinental Gas Pipe Line Corporation
("Transco"), Texas Eastern Transmission Corporation ("Tetco"), Iroquois Gas
Transmission System ("Iroquois"), Tennessee Gas Pipeline Company ("Tennessee"),
Dominion Transmission Incorporated ("Dominion"), and Texas Gas Transmission
Company.
Underground Storage. In order to meet higher winter demand in our New York
service territories, we also have long-term contracts with Transco, Tetco,
Tennessee, Dominion, Equitrans, Inc., and Honeoye Storage Corporation
("Honeoye"), for underground storage capacity of 59,058 MDTH for the winter
season and 779 MDTH per day of maximum deliverability.
Peaking Supplies. In addition to the pipeline and underground storage supply, we
supplement our winter supply portfolio with peaking supplies that are available
on the coldest days of the year to economically meet the increased requirements
of our heating customers. Our peaking supplies include gas provided by: (i) two
liquefied natural gas ("LNG") plants; and (ii) peaking supply contracts with
four cogeneration facilities/independent power producers located in our
franchise areas, as well as with the New York Power Authority ("NYPA"). For the
2001/02 winter season, we had the capability to provide a maximum peak-day
supply of 505 MDTH on excessively cold days. The LNG plants have a storage
capacity of approximately 2,053 MDTH and peak-day throughput capacity of 394.5
MDTH, or 19% of peak-day supply. We also have contract rights with Trigen
Services Corporation, Brooklyn Navy Cogeneration Partners, LP, Nissequogue Cogen
Partners, TBG Cogen Partners, and NYPA to purchase peaking supplies with a
maximum daily capacity of 110 MDTH and total available peaking supplies during
the winter season of 3,349 MDTH.
Gas Supply Management.
In April 1, 2000, through a subsidiary, we entered into a two-year agreement
with Coral Energy, LLC, ("Coral") in which Coral was contracted to assist with
the New York gas distribution energy supply management services and our
energy-management services undertaken on behalf of LIPA. The agreement was
scheduled to expire on March 31, 2002, and both parties have agreed to come to
terms on a one year extension through March 31, 2003.
Gas Costs. Fluctuations in utility gas costs have little impact on the operating
results of KEDNY and KEDLI, since the current gas rate structure of each of
these companies includes a gas adjustment clause whereby variations between
actual gas costs and gas cost recoveries are deferred and subsequently refunded
to or collected from customers.
Deregulation. Regulatory actions, economic factors and changes in customers and
their preferences continue to reshape our gas operations. A number of
multi-family, commercial and industrial customers and residential customers
currently purchase their gas supplies from natural gas marketers and then
contract with us for local transportation, balancing and other unbundled
services. In addition, our New York gas distribution companies release firm
capacity on our interstate pipeline transportation contracts to natural gas
marketers to ensure the marketers' gas supply is delivered on a firm basis and
in a reliable manner to their customers. Since 1996, when New York State
regulators implemented policies designed to encourage customers to purchase
their gas from suppliers other than the traditional gas utilities, approximately
136,000 gas customers have opted to purchase their gas from marketers instead of
KEDNY or KEDLI. This trend has slowed somewhat in recent months as policies
towards additional deregulation are being reevaluated by utility regulators
nationwide.
New England Gas Distribution Systems
Supply and Storage
KEDNE has contracts for the purchase of firm long-term transportation and
underground storage services. Gas supplies are purchased under long and
short-term contracts, as well as on the spot market. Gas supplies are
transported by interstate pipelines from domestic and Canadian supply basins.
Peaking supplies are available to meet system requirements during winter
periods.
Peak-Day Capability. The design criteria for our New England gas systems assumes
an average temperature of -6(0)F for peak-day demand. Under such criteria, KEDNE
estimates that the requirements to supply their firm gas customers would amount
to approximately 1,245 MDTH of gas for a peak-day during the 2001/2002 winter
season and that the gas available to KEDNE on such a peak-day would amount to
approximately 1,317 MDTH. For the 2002/2003 winter season, KEDNE estimates that
the peak-day requirements will amount to 1,294 MDTH and that the gas supplies
available on such a peak-day will amount to approximately 1,317 MDTH.
During 2001, the highest daily throughput to our New England customers was 947
MDTH, which occurred on February 11, 2001 at an average temperature of
17 F, representing 72% of KEDNE's capability at that time. KEDNE has
sufficient gas available to meet the requirements of their firm gas customers
for the 2001/2002 winter gas season and anticipate that they will have
sufficient quantities for the 2002/2003 winter season. The firm gas peak day
capability of KEDNE is summarized in the following table:
Source MDTH per % of Total
day
- ------------------------------ --- ------------------- --- --------------------
Pipeline................... 436 33
Underground Storage........ 270 21
Peaking Supplies........... 611 46
--- --
Total 1,317 100
- ------------------------------ --- =================== --- ====================
Pipelines. Our New England based gas distribution utilities purchase natural gas
for sale to their gas customers under contracts with suppliers with natural gas
located in domestic and Canadian supply basins and arrange for transportation to
their facilities under firm long-term contracts with interstate pipeline
companies. During the 2001/2002 winter season, approximately 77% of KEDNE's
natural gas supply was available from domestic sources and 23% from Canadian
sources.
Underground Storage. KEDNE has available under firm contract 706 MDTH per day of
year-round and seasonal transportation and underground storage capacity to their
facilities in New England. Major providers of interstate pipeline capacity and
related services to the KEDNE companies include: Tetco, Iroquois, Maritimes and
Northeast Pipeline, Tennessee, Algonquin Gas Transmission Company and Portland
Natural Gas Transmission System. Moreover, KEDNE has long-term contracts with
Tetco, Tennessee, Dominion, National Fuel Gas Supply Corporation and Honeoye for
underground storage capacity of 23,205 MDTH and 270 MDTH per day of maximum
deliverability.
Peaking Supplies. The KEDNE gas supply portfolio is supplemented with peaking
supplies that are available on the coldest days of the year in order to
economically meet the increased requirements of our heating customers. Peaking
supplies include gas provided by both LNG and propane air plants located within
the distribution system, as well as two leased facilities outside of our
distribution systems located in Providence, Rhode Island and Everett, MA. For
the 2001/2002 winter season, KEDNE had the capability to provide a peak-day
supply of 611 MDTH on excessively cold days or 46% of peak-day supply.
Gas Supply Management. Since November 1, 1999, the Massachusetts based gas
distribution subsidiaries have been operating under a three-year portfolio
management contract with El Paso Energy Marketing, Inc. ("El Paso"). El Paso
provides the majority of the city gate supply requirements to the three
Massachusetts gas distribution companies (Boston Gas, Colonial Gas and Essex
Gas) at market prices and manages upstream capacity, underground storage and
term supply contracts. The Massachusetts Department of Telecommunications and
Energy ("DTE") approved this contract in October 1999. The annual fee paid by El
Paso to manage the Massachusetts KEDNE companies' portfolio is, for the most
part, returned to firm customers.
Gas Costs. Fluctuations in utility gas costs have little impact on the operating
results of the KEDNE companies, since their current gas rate structures include
gas adjustment clauses whereby variations between actual gas costs and gas cost
recoveries are deferred and subsequently refunded to or collected from
customers. The KEDNE companies do not have a weather normalization adjustment
clause and as a result, fluctuations from normal weather may have a positive or
negative impact on their results.
For additional information concerning the gas distribution segment, see the
discussion in"Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations - Gas Distribution" contained herein.
Electric Services Overview
We are the largest investor owned electric generator in New York State. Our
subsidiaries own and operate five large generating plants and 8 smaller
facilities which are comprised of 53 generating units in Nassau and Suffolk
Counties on Long Island and the Rockaway Peninsula in Queens. In addition, we
own, lease and operate a major generating facility in Queens County in New York
City, the Ravenswood facility which is comprised of 3 large steam-generating
units and 17 gas turbine generators.
As more fully described below: we (i) provide to LIPA all operation, maintenance
and construction services relating to the Long Island electric T&D system
through a management services agreement (the "MSA"); (ii) supply LIPA with
energy conversion and ancillary services through a power supply agreement (the
"PSA") to allow LIPA to provide electricity to its customers on Long Island; and
(iii) manage all aspects of the fuel supply for the Long Island generating
facilities, as well as all aspects of the capacity and energy owned by or under
contract to LIPA through an energy management agreement (the "EMA"). Each of the
MSA, PSA and EMA became effective on May 28, 1998 and are collectively referred
to herein as the "LIPA Agreements."
Generating Facility Operations
Ravenswood facility. On June 18, 1999, we acquired the 2,200 megawatt Ravenswood
facility located in New York City from Consolidated Edison Company of New York,
Inc. ("Consolidated Edison") for approximately $597 million. In order to reduce
our initial cash requirements to finance this acquisition, we entered into an
arrangement with an unaffiliated special purpose financing entity through which
we lease the Ravenswood facility. Under the arrangement, the special purpose
financing entity acquired a portion of the facility directly from Consolidated
Edison and leased it to our wholly owned subsidiary. We have guaranteed all
payment and performance obligations of our subsidiary under the lease. The lease
relates to 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 are for 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 balance of the funds needed to acquire the Ravenswood facility
were provided from cash on hand. We believe that the fair market value of the
Ravenswood facility, including the leased facilities, is well in excess of its
acquisition cost.
The Ravenswood facility sells capacity, energy and ancillary services into the
New York Independent System Operator ("NYISO") energy market at market-based
rates, subject to mitigation. The plant has the ability to provide approximately
25% of New York City's capacity and is a strategic asset that is available to
serve residents and businesses in New York City. We are also in the process of
constructing an expansion to our Ravenswood facility by adding a 250-megawatt
state-of-the-art gas- fired co-generation unit at the site. On September 5,
2001, we received approval for the expansion from New York State's Siting Board
on Electric Generation and the Environment ("Siting Board") and construction is
underway. We anticipate that the new unit will be operational in late 2003/early
2004.
The pricing for both energy sales and ancillary services to the NYISO energy
market is still evolving and the Federal Energy Regulatory Commission ("FERC")
has adopted several price mitigation measures which are subject to rehearing and
possible judicial review. See "Item 7A. Quantitative and Qualitative Disclosures
About Market Risk" for a further discussion of these matters.
Long Island Generation. Forty of our 73 generating units can be powered either
by natural gas or oil. In recent years, we have reconfigured several of our
facilities to enable them to burn either natural gas or oil, thus enabling us to
switch periodically between fuel alternatives based upon cost and seasonal
environmental requirements. Through other innovative technological approaches,
we increased installed capacity in our generating facilities by 80 megawatts,
and we instituted a program to reduce nitrogen oxides for improved environmental
performance. Reliability improvement investments at our Ravenswood facility
reduced the forced outage rate for that facility from 35% in 1999 to just 5% in
2000 and 2001. Decreasing the amount of time our generating units are offline
for repair allows us to increase sales.
The following table indicates the 2001 summer capacity of our steam generation
facilities and gas turbine ("GT") units as reported to the NYISO:
Location of Units Description Fuel Units MW
- -------------------------- --------------------------- --------------------- --------------------- ------------------
Long Island City Steam Turbine Dual* 3 1,755
Northport, L.I. Steam Turbine Dual* 3 1,150
Northport, L.I. Steam Turbine Oil 1 370
Port Jefferson, L.I. Steam Turbine Dual* 2 385
Glenwood, L.I. Steam Turbine Gas 2 229
Island Park, L.I. Steam Turbine Dual* 2 389
Far Rockaway, L.I. Steam Turbine Dual 1 110
Long Island City GT Units Dual* 17 455
Throughout L.I. GT Units Dual* 12 311
Throughout L.I. GT Units Oil 30 1,093
Total 73 6,247
========================== =========================== ===================== ===================== ==================
*Dual - Oil or natural gas
In addition to the 250 MW expansion of the Ravenswood facility, we have plans
for the development of three new generation projects on Long Island, New York.
We plan to construct another 250 MW combined cycle plant in Melville, Long
Island. In January 2002, we filed an application for approval with the Siting
Board for this project. This facility is expected to become operational in late
2004/early 2005. Additionally, we are constructing two peaking facilities, one
at Glenwood Landing and the other at Port Jefferson. Each facility will produce
approximately 79 MW of electricity which is enough power to supply 80,000
customers. We have entered into a long term power purchase agreement with LIPA
with respect to the Glenwood Landing facility and expect to enter into a similar
power purchase agreement with respect to the Port Jefferson facility. We
anticipate that these units will be operational by this summer to meet the peak
electric load season.
LIPA Agreements
Power Supply Agreement. The PSA provides for the sale to LIPA of all of the
capacity and, to the extent LIPA requests, energy conversion services from the
Long Island generating facilities. Capacity refers to the ability to generate
energy and, pursuant to NYISO requirements, must be maintained at specified
levels (including reserves) regardless of the source and amount of energy
consumption. By contrast, energy conversion services refers to the electricity
actually generated for consumption by consumers. Such sales of capacity and
energy conversion services from the Long Island generating facilities are made
at rates regulated by the FERC. These rates may be modified in the future in
accordance with the terms of the PSA for (i) agreed upon labor and expense
indices applied to the base year; (ii) a return of and on the capital invested
in the Long Island generating facilities; and (iii) reasonably incurred expenses
that are outside of our control.
The PSA provides incentives and penalties for us to maintain the output
capability of the Long Island generating facilities, as measured by annual
industry-standard tests of operating capability, and plant availability and
efficiency. These combined incentives and penalties may total as much as $4
million annually. In 2001, we earned approximately $3.8 million in incentives
under the PSA.
LIPA has no obligation to purchase energy conversion services from the Long
Island generating facilities and is able to purchase energy on a least-cost
basis from all available sources, consistent with existing transmission
interconnection limitations of the transmission and distribution system. Under
the terms of the PSA, LIPA is obligated to pay for capacity at rates which
reflect a large percentage of the overall fixed cost of maintaining and
operating the Long Island generating facilities. A variable maintenance charge
is imposed for each unit of energy actually generated by the Long Island
generating facilities. The PSA expires on May 28, 2013 and is renewable for an
additional 15 years on similar terms. However, the PSA provides LIPA the option
of electing to reduce or "ramp-down" the capacity it purchases from us in
accordance with agreed-upon schedules. In years 7 through 10 of the PSA, if LIPA
elects to ramp-down, we are entitled to receive payment for 100% of the present
value of the capacity charges otherwise payable over the remaining term of the
PSA. If LIPA ramps-down the generation capacity in years 11 through 15 of the
PSA, the capacity charges otherwise payable by LIPA will be reduced in
accordance with a formula established in the PSA. If LIPA exercises its
ramp-down option, KeySpan may use any capacity released by LIPA to bid on new
LIPA capacity requirements or to bid on LIPA's capacity requirements to replace
other ramped-down capacity. If we continue to operate the ramped-down capacity,
the PSA requires us to use reasonable efforts to market the capacity and energy
from the ramped-down capacity and to share any profits with LIPA. The PSA will
be terminated in the event that LIPA exercises its right to purchase, at fair
market value, all of the Long Island generating facilities pursuant to the
Generation Purchase Rights Agreement discussed in greater detail below.
We also have an inventory of sulfur dioxide ("SO2") and nitrogen oxide ("NOx")
emission allowances that may be sold to third party purchasers. The amount of
allowances varies from year to year relative to the level of emissions from the
Long Island generating facilities which is greatly dependent on the mix of
natural gas and fuel oil used for generation and the amount of purchased power
that is imported onto Long Island. In accordance with the PSA, 33% of emission
allowance sales revenues attributable to the Long Island generating facilities
is retained by KeySpan and the other 67% is credited to LIPA. LIPA also has a
right of first refusal on any potential emission allowance sales of the Long
Island generating facilities. Additionally, KeySpan voluntarily entered into a
memorandum of understanding with the New York State Department of Environmental
Conservation ("DEC"), which memorandum prohibits the sale of SO2 allowances into
certain states and requires the purchaser to be bound by the same restriction,
which may marginally affect the market value of the allowances.
Management Services Agreement. Under the MSA, we perform day-to-day operation
and maintenance services and capital improvements for LIPA's transmission and
distribution system including, among other functions, transmission and
distribution facility operations, customer service, billing and collection,
meter reading, planning, engineering, and construction, all in accordance with
policies and procedures adopted by LIPA. KeySpan furnishes such services as an
independent contractor and does not have any ownership or leasehold interest in
the transmission and distribution system.
In exchange for providing these services, we are reimbursed our budgeted costs
and entitled to earn an annual management fee of $10 million and may also earn
certain incentives, or be responsible for certain penalties, based upon our
performance. The incentives provide for us to retain 100% of the first $5
million of cost reductions and 50% of any additional cost reductions up to 15%
of the total cost budget. Thereafter, all savings accrue to LIPA and we are
required to absorb any total cost budget overruns up to a maximum of $15 million
in any contract year.
In addition to the foregoing cost-based incentives and penalties, we are
eligible for incentives for performance above certain threshold target levels
and subject to disincentives for performance below certain other threshold
levels, with an intermediate band of performance in which neither incentives nor
disincentives will apply, for system reliability, worker safety, and customer
satisfaction. In 2001, we earned $7.4 million in non-cost performance
incentives.
The MSA currently has an eight year term and expires on May 28, 2006. However,
we have reached an agreement in principle with LIPA to, among other things,
extend the MSA for an additional thirty months, until November 28, 2008. For a
further description of the agreement in principle, see the discussion on
"Generation Purchase Rights Agreement" below.
Energy Management Agreement. Pursuant to the EMA, KeySpan (i) procures and
manages fuel supplies for LIPA to fuel the Long Island generating facilities,
(ii) performs off-system capacity and energy purchases on a least-cost basis to
meet LIPA's needs, and (iii) makes off-system sales of output from the Long
Island generating facilities and other power supplies either owned or under
contract to LIPA. LIPA is entitled to two-thirds of the profit from any
off-system electricity sales arranged by us. The term for the service provided
in (i) above is fifteen years, and the term for the services provided in (ii)
and (iii) above is eight years.
In exchange for these services, we earn an annual fee of $1.5 million, plus an
allowance for certain costs incurred in performing services under the EMA. The
EMA further provides incentives for control of the cost of fuel and electricity
purchased on behalf of LIPA. Fuel and electricity purchase prices are compared
to regional price indices and we receive payment from LIPA, or are obligated to
make payment to LIPA, for fuel and/or purchased electricity costs that are below
or above, respectively, specified tolerance bands. The total fuel purchase
incentive or disincentive can be no greater than $5 million annually and the
electricity purchase incentive or disincentive can be no greater than $2 million
annually (subject to an overall cap including certain non-cost performance
incentives under the MSA). For the year ended December 31, 2001, we earned an
aggregate of $5 million in incentives under the EMA.
Generation Purchase Rights Agreement. Under a Generation Purchase Rights
Agreement ("GPRA"), LIPA has the right to purchase, at fair market value, all of
our currently existing Long Island based generating assets during the twelve
month period ending on May 28, 2002. On March 11, 2002, we entered into an
agreement in principle with LIPA, to among other thing, extend the GPRA for
three years. The agreement in principle establishes a new option window
commencing November 2004 and closing May 2005. Under the agreement, LIPA retains
the right to exercise the option to purchase our Long Island generation assets
under the terms of the original GPRA. In return for providing LIPA an extension
of the GPRA, we have been provided with a corresponding extension of 30 months
on the term of the MSA, as previously discussed.
The GPRA extension is the result of a new initiative established by LIPA to work
with KeySpan and others to review Long Island's long-term energy needs. We will
work with LIPA to 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 us to explore alternatives to the GPRA
including re-powering existing facilities, the sale of some, or all of our
currently existing Long Island generation plants to LIPA, or the sale of some or
all of these plants to other private operators.
Other Rights. Pursuant to other agreements between LIPA and us, certain future
rights have been granted to LIPA. Subject to certain conditions, these rights
include the right for 99 years to lease or purchase, at fair market value,
parcels of land and to acquire unlimited access to, as well as appropriate
easements at, the Long Island generating facilities for the purpose of
constructing new electric generating facilities to be owned by LIPA or its
designee. Subject to this right granted to LIPA, KeySpan has the right to sell
or lease property on or adjoining the Long Island generating facilities to third
parties. In addition, LIPA has acquired a parcel at the site of the former
Shoreham Nuclear Power Station site suitable as the terminus for a potential
transmission cable under Long Island Sound or the potential site of a new
gas-fired combined cycle generating facility.
We own the common plant (such as administrative office buildings and computer
systems) formerly owned by LILCO and recover LIPA's allocable share of the
carrying costs of such plant through the MSA. KeySpan has agreed to provide
LIPA, for a period of 99 years, the right to enter into leases at fair market
value for common plant or sub-contract for common services which it may assign
to a subsequent manager of the transmission and distribution system. We have
also agreed: (i) for a period of 99 years not to compete with LIPA as a provider
of transmission or distribution service on Long Island; (ii) that LIPA will
share in synergy (i.e., efficiency) savings over a 10-year period attributed to
the May 28, 1998 transaction which resulted in the formation of KeySpan
(estimated to be approximately $1 billion), which savings are incorporated into
the cost structure under the LIPA Agreements; and (iii) not to commence any tax
certiorari case (until termination of the PSA) challenging certain property tax
assessments relating to the Long Island generating facilities.
Guarantees and Indemnities. We have entered into agreements with LIPA to provide
for the guarantee of certain obligations, indemnification against certain
liabilities and allocation of responsibility and liability for certain
pre-existing obligations and liabilities. In general, liabilities associated
with the LILCO assets transferred to KeySpan, have been assumed by KeySpan; and
liabilities associated with the assets acquired by LIPA, are borne by LIPA,
subject to certain specified exceptions. We have assumed all liabilities arising
from all manufactured gas plant ("MGP") operations of LILCO and its
predecessors, and LIPA has assumed certain liabilities relating to the Long
Island generating facilities and all liabilities traceable to the business and
operations conducted by LIPA after completion of the 1998 KeySpan/LILCO
transaction. An agreement also provides for an allocation of liabilities which
relate to the assets that were common to the operations of LILCO and/or shared
services and are not traceable directly to either the business or operations
conducted by LIPA or KeySpan.
For additional information concerning the Electric services segment, see the
discussion in "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations - Electric Services" contained herein.
Energy Services Overview
Our Energy Services segment provides services to customers located primarily
within the New York, New Jersey, Massachusetts, New Hampshire, Rhode Island and
Pennsylvania through various subsidiaries which operate under the following four
principal lines of business: (i) home energy services, which provides
residential and small commercial customers with service and maintenance of
energy systems and appliances, as well as the competitive retail supply of
natural gas and electricity; (ii) business solutions, which provides
engineering, consulting and construction services, related to the design,
construction, installation, operation, maintenance and management of heating,
cooling and power production equipment and systems for commercial and industrial
customers, as well as the competitive retail supply of natural gas and
electricity to large commercial, institutional and industrial customers. Certain
subsidiaries within this line of business also engage or may engage in the
financing and ownership of cogeneration, small power production, thermal energy,
chilled water and related equipment and facilities; (iii) commodity procurement,
which provides management and procurement services for fuel supply and
management of energy sales, primarily for and from the Ravenswood facility, as
well as wholesale gas and electric purchasing and management services for home
energy services, retail gas and electricity business; and (iv) fiber optic
services in which we construct fiber optic systems and facilities and own and
lease fiber optic cable to local, long distance, and trans-Atlantic carriers, as
well as internet service providers.
The Energy Services segment has more than 3,000 employees, 100,000 natural gas
and electric commodity customers, 200,000 service contracts and is the number
one oil to gas conversion contractor in New York.
KeySpan's Energy Services subsidiaries compete with local, regional and national
mechanical contracting, HVAC, plumbing, engineering, wholesale fiber optics
carriers, and independent energy companies, in addition to electric utilities,
independent power producers, local distribution companies and various energy
brokers. As a result of the continuing efforts to deregulate both the natural
gas and electric industries, the relative energy cost differences among
different forms of energy are expected to be reduced in the future. Competition
is based largely upon pricing, availability and reliability of supply, technical
and financial capabilities, regional presence experience and customer service.
With our strong market presence in the Northeast centered on our Gas
Distribution and Electric Services operations and the long-term trend towards
further deregulation, we believe that we are well positioned to provide our
customers with an expanded array of energy products and services through our
unregulated energy service companies.
During 2001, we undertook a complete evaluation of our Energy Services
operations, operating controls and the organizational structure of our
subsidiaries, as a result of circumstances surrounding certain charges and
losses incurred in 2001 relating to the general contracting activities of the
Roy Kay companies. We are currently engaged in litigation concerning the Roy Kay
companies. For further information, See Note 11 to the Consolidated Financial
Statements, "Roy Kay Operations" and Note 8 "Contractual Obligations and
Contingencies - Legal Matters for a further discussion.
As a result of our evaluation of the Energy Services business, we decided that
our contracting subsidiaries would no longer engage in new general contracting
activities. We also installed new senior management personnel who, among other
things, will be reviewing and focusing on our overall strategy of these
businesses.
In its order approving the acquisition by KeySpan of Eastern and EnergyNorth,
the SEC reserved jurisdiction on its determination of whether the Energy
Services companies are retainable under existing SEC precedent. We are working
with the SEC in providing them with additional and supplemental information to
assist them in their evaluation of these subsidiaries as to whether their
operations are functionally related to our core utility operations as required
by PUHCA. We are hopeful that the SEC will approve of KeySpan's continued
operations in the Energy Services business, as other companies that have
registered as holding companies under PUHCA have been permitted to retain their
energy-service operations.
For additional information concerning the Energy Services segment, see the
discussion in "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations - Energy Services" contained herein.
Energy Investments Overview
We are also engaged in Energy Investments which include: (i) gas exploration and
production activities; (ii) domestic pipelines and gas storage facilities; (iii)
midstream natural gas processing activities in Canada; (iv) natural gas
distribution and pipeline activities in the United Kingdom; and (v) certain
other domestic energy-related investments, such as providing meter reading
equipment and services to municipal utilities, the transportation by truck of
liquid natural gas, new fuel cell technologies and certain internet related
activities.
Gas Exploration & Production
KeySpan is engaged in the exploration and production of domestic natural gas and
oil through our 67% equity interest in The Houston Exploration Company ("Houston
Exploration") and through our wholly owned subsidiary, KeySpan Exploration and
Production, LLC ("KeySpan Exploration"). Houston Exploration was organized by
KEDNY in 1985 to conduct natural gas and oil exploration and production
activities. It completed an initial public offering in 1996 and its shares are
currently traded on the New York Stock Exchange under the symbol "THX." At March
1, 2002, its aggregate market capitalization was approximately $943,597,720
(based upon the closing price on the New York Stock Exchange on that date of
$30.95). At March 1, 2002, Houston Exploration had approximately 30,487,810
shares of common stock, $.01 par value, outstanding.
KeySpan Exploration is engaged in a joint venture with Houston Exploration to
explore for natural gas and oil. Houston Exploration contributed all of its then
undeveloped offshore leases to the joint venture for a 55% working interest and
KeySpan Exploration, acquired a 45% working interest in all prospects to be
drilled by the joint venture. Effective 2001, the joint venture was modified to
reflect that KeySpan Exploration would only participate in the development of
wells that had previously been drilled and not participate in future prospects.
KeySpan Exploration expended approximately $17.2 million and has agreed to
commit approximately $15 million for 2002 for the continued development of
prospects successfully drilled by the joint venture.
Our gas exploration and production subsidiaries focus their operations offshore
in the Gulf of Mexico and onshore in South Texas, South Louisiana, the Arkoma
Basin, East Texas and West Virginia. The geographic focus of these operations
enables our subsidiaries to manage a comparatively large asset base with
relatively few employees and to add and operate production at relatively low
incremental costs. Our gas exploration and production subsidiaries seek to
balance their offshore and onshore activities so that the lower risk and more
stable production typically associated with onshore properties complement the
high potential exploratory projects in the Gulf of Mexico by balancing risk and
reducing volatility. Houston Exploration's business strategy is to seek to
continue to increase reserves, production and cash flow by pursuing internally
generated prospects, primarily in the Gulf of Mexico, by conducting development
and exploratory drilling on our offshore and onshore properties and by making
selective opportune acquisitions.
Offshore Properties. We hold interests in 101 lease blocks, representing 496,995
gross (412,335 net) acres, in federal and state waters in the Gulf of Mexico, of
which 38 have current operations. Houston Exploration operates 24 of these
blocks, accounting for approximately 75% of our offshore production. Over the
past five years, we have drilled 29 successful exploratory wells and 22
successful development wells in the Gulf of Mexico, representing a historical
success rate of 70%. During 2001, Houston Exploration drilled 7 successful
exploratory wells and 6 successful development wells on its Gulf of Mexico
properties. The joint venture participated in 3 of the successful wells, all 2
exploratory wells and 1 of the development wells.
Onshore Properties. We also own onshore natural gas and oil properties
representing interests in 1,481 gross (1041 net) wells, approximately 86% of
which Houston Exploration is the operator of record, and 198,781 gross (126,448
net) acres. Over the past five years, we have drilled or participated in the
drilling of 191 successful development wells and 7 successful exploratory wells
onshore, representing a historical success rate of 84%, through our interest in
Houston Exploration. During 2001, Houston Exploration participated in the
drilling of 60 successful development wells and 1 successful exploratory well on
its onshore properties. During the same period, Houston Exploration drilled or
participated in the drilling of 4 development and 12 development wells that were
not successful.
On January 1, 2002, Houston Exploration acquired 159 producing wells located in
South Texas, representing 85 BCF of total proved reserves from Conoco, Inc. for
$69 million.
For additional information concerning the gas exploration and production
segment, see the discussion on "Gas Exploration and Production" in "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" and for information with respect to net proved reserves, production,
productive wells and acreage, undeveloped acreage, drilling activities, present
activities and drilling commitments see "Note 17 to the Consolidated Financial
Statements, Supplemental Gas and Oil Disclosures," included herein.
Domestic Pipelines and Gas Storage Facilities
We also own an approximate 20% interest in Iroquois, the partnership that owns a
375-mile pipeline that currently transports 946 MDTH of Canadian gas supply
daily from the New York-Canadian border to markets in the Northeastern United
States. KeySpan is also a shipper on Iroquois and currently transports up to 137
MDTH of gas per day on the pipeline.
We are also participating in the Islander East Pipeline Company LLC ("Islander
East"), an interstate pipeline joint venture with Duke Energy Corporation. The
joint venture plans to construct, own and operate a 50 mile natural gas pipeline
that will transport 260 MDTH of gas from Nova Scotia, Canada to growing markets
in Connecticut, New York City and Long Island, New York. The project received a
positive preliminary determination from the FERC to construct the pipeline.
Increasing gas transmission capacity is necessary to meet the increased demand
for natural gas in the Northeast which coincides with the growth strategy of our
Gas Distribution business. Islander East is projected to be in service by 2003.
We also have equity investments in two gas storage facilities in the State of
New York. Honeoye Storage Corporation and Steuben Gas Storage Company. We own a
52% interest in Honeoye, an underground gas storage facility which provides up
to 4.8 billion cubic feet of storage service to New York and New England.
Additionally, we own 34% of a partnership that has a 50% interest in the Steuben
facility storage which provides up to 6.2 billion cubic feet of storage service
to New Jersey and Massachusetts.
Our investments in domestic pipelines and gas storage facilities are
complimentary to our Gas Distribution and Electric Services businesses in that
they provide energy infrastructure to support the growth of these businesses. To
the extent that opportunities become available for expanding our investments in
these types of Energy Investments, KeySpan will continue to consider such
investments as strategic.
Midstream Natural Gas Processing Activities in Canada
We also own 100% of KeySpan Canada, a company with natural gas processing plants
and gathering facilities located in Western Canada. In October 2000, we
purchased the remaining 50% interest in KeySpan Canada from our former partner,
Gulf Canada Resources Limited. The assets include interests in 14 processing
plants and associated gathering systems that can process approximately 1.5 BCFe
of natural gas daily, and associated natural gas liquids fractionation.
Additionally, KeySpan owns an approximate 75% interest in the Paddle River
processing plant in Western Canada and an interest in the Younger NGL Extraction
plant in British Columbia, Canada. We also consider our Canadian operations to
be non-core assets and are also evaluating strategies to divest or monetize
these assets.
Natural Gas Distribution and Pipeline Activities in the United Kingdom
We own a 50% interest in Premier Transco Pipeline and a 24.5% interest in
Phoenix Natural Gas Limited both in Northern Ireland. Premier is an 84-mile
pipeline to Northern Ireland from southwest Scotland that has planned
transportation capacity of approximately 300 MDTH of gas supply daily to markets
in Northern Ireland. Phoenix is a gas distribution system serving the City of
Belfast, Northern Ireland. KeySpan also considers these assets as non-core
assets and is currently evaluating the possible divestiture of these assets.
Marine Transportation Activities - Discontinued Operations
Our marine transportation subsidiary, Midland Enterprises, Inc. ("Midland") that
was acquired as part of the Eastern acquisition is being divested and its
operations are being discontinued. We were required by the SEC to divest this
subsidiary by November 8, 2003, as its operations were determined not to be
functionally related to our core utility operations as required by PUHCA. On
January 24, 2002, we announced that we had entered into a definitive agreement
with Ingram Industries for the sale of Midland for approximately $230 million.
Ingram Industries will also assume debt of approximately $135 million. The sale
is subject to certain regulatory approvals and is expected to close during the
second quarter of 2002. See Note 10 "Discontinued Operations," for further
information on the sale of our marine transportation business.
For additional information concerning the Energy Investments segment, see the
discussion on "Energy Investments" in "Item 7, Management's Discussion and
Analysis of Financial Condition and Results of Operations" contained herein.
Environmental Matters Overview
KeySpan's ordinary business operations subject it to regulation in accordance
with various federal, state and local laws, rules and regulations dealing with
the environment, including air, water, and hazardous substances. These
requirements govern both our normal, ongoing operations and the remediation of
impacted properties historically used in utility operations. Potential liability
associated with our historical operations may be imposed without regard to
fault, even if the activities were lawful at the time they occurred.
Except as set forth below, or in Note 8 to the Consolidated Financial Statements
"Contractual Obligations and Contingencies - Environmental Matters," no material
proceedings relating to environmental matters have been commenced or, to our
knowledge, are contemplated by any federal, state or local agency against
KeySpan, and we are not a defendant in any material litigation with respect to
any matter relating to the protection of the environment. We believe that our
operations are in substantial compliance with environmental laws and that
requirements imposed by environmental laws are not likely to have a material
adverse impact upon us. We are also pursuing claims against insurance carriers
and potentially responsible parties which seek the recovery of certain
environmental costs associated with the investigation and remediation of
contaminated properties. We believe that all investigator and remediation costs
prudently incurred at facilities associated with utility operations, not
recoverable through insurance or some other means, will be recoverable from our
customers.
Air. The Federal Clean Air Act ("CAA") provides for the regulation of a variety
of air emissions from new and existing electric generating plants. We have
submitted timely applications for permits in accordance with the requirements of
Title V of the 1990 amendments to the CAA. Final permits have been issued for
all of our electric generating facilities, except for the Far Rockaway facility.
The permits allow our electric generating plants to continue to operate without
any additional significant expenditures, except as described below.
Our generating facilities are located within a CAA severe ozone non-attainment
area, and are subject to Phase I, II and III NOx reduction requirements
established under the Ozone Transportation Commission ("OTC") memorandum of
understanding. Our investments in boiler combustion modifications and the use of
natural gas firing systems at our steam electric generating stations have
enabled us to achieve the emission reductions required under Phase I and II of
the OTC memorandum in a cost-effective manner. With respect to Phase III of the
OTC memorandum, we are required to be in compliance with such reduction
requirements by May 1, 2003 and we fully expect to achieve such emission
reductions on time and in a cost-effective manner. Our expenditures to address
emission reduction requirements through the year 2003 are expected to be between
$10 million and $15 million.
Water. The Federal Clean Water Act provides for effluent limitations, to be
implemented by a permit system, to regulate the discharge of pollutants into
United States waters. We possess permits for our generating units which
authorize discharges from cooling water circulating systems and chemical
treatment systems. These permits are renewed from time to time, as required by
regulation. Additional capital expenditures associated with the renewal of the
surface water discharge permits for our power plants may be required by the DEC.
Until our monitoring obligations are completed and changes to the Environmental
Protection Agency regulations under Section 316 of the Clean Water Act are
promulgated, the need for and the cost of equipment upgrades, if any, cannot be
determined.
Land. The Federal Comprehensive Environmental Response, Compensation and
Liability Act of 1980 and certain similar state laws (collectively "Superfund")
impose liability, regardless of fault, upon generators of hazardous substances
for costs associated with remediating contaminated property. In the course of
our business operations, we generate materials which, after disposal, may become
subject to Superfund. From time to time, we have received notices under
Superfund concerning possible claims with respect to sites where hazardous
substances generated by KeySpan and other potentially responsible parties were
allegedly disposed. The cost of these claims is not presently determinable but,
if actually imposed on us, may be material to our financial condition, results
of operations or cash flows.
KeySpan has identified certain manufactured gas plant ("MGP") sites which were
historically owned or operated by its subsidiaries (or such companies
predecessors). Operations at these sites between the mid 1800s to mid 1900s may
have resulted in the release of hazardous substances.
For a discussion on our MGP sites and further information concerning
environmental matters, see Note 8 to the Consolidated Financial Statements,
"Contractual Obligations and Contingencies - Environmental Matters."
Competition, Regulation and Rate Matters
Competition
Over the last several years the natural gas and electric sectors of the
regulated energy industry have undergone significant change as market forces
moved towards replacing or supplementing rate regulation through the
introduction of competition. A significant number of natural gas and electric
utilities reacted to the changing structure of the energy industry by entering
into business combinations, with the goal of reducing common costs, gaining size
to better withstand competitive pressures and business cycles, and attaining
synergies from the combination of operations. We engaged in two such
combinations, the KeySpan/LILCO transaction in1998 and our November 2000
acquisition of Eastern and EnergyNorth. For further information regarding the
gas and electric industry, see "Item 7A. Quantitative and Qualitative Disclosure
about Market Risk."
Additionally, our non-utility subsidiaries engaged in the Energy Services
business compete with other mechanical, HVAC, and engineering companies, and in
New Jersey are faced with competition from the regulated utilities that are
still able to offer appliance repair and protection services.
Regulation
Public utility holding companies, like KeySpan, are regulated by the SEC under
PUHCA and to some extent by state utility commissions through the regulation of
corporate, financial and affiliate activities of public utilities. Our utility
subsidiaries are subject to extensive federal and state regulation by state
utility commissions, FERC and the SEC. Our gas and electric public utility
companies are subject to either or both state and federal regulation. In
general, state public utility commissions, such as the NYPSC, DTE and NHPUC
regulate the provision of retail services, including the distribution and sale
of natural gas and electricity to consumers. The FERC regulates interstate
natural gas transportation and electric transmission, and has jurisdiction over
certain wholesale natural gas sales and wholesale electric sales.
In addition, our non-utility subsidiaries are subject to a wide variety of
federal, state and local laws, rules and regulations with respect to their
business activities, including but not limited to those affecting public sector
projects, environmental and labor laws and regulations, state licensing
requirements, as well as state laws and regulations concerning the competitive
retail commodity supply.
State Utility Commissions Our regulated utility subsidiaries are subject to
regulation by the NYPSC, DTE and NHPUC. The NYPSC regulates KEDNY and KEDLI, and
indirectly KeySpan itself, through conditions, which were included in the NYPSC
order authorizing the 1998 KeySpan/LILCO transaction. Those conditions address
the manner in which KeySpan, its service company subsidiaries and its
unregulated subsidiaries may interact with KEDNY and KEDLI. The NYPSC also
regulates the safety, reliability and certain financial transactions of our Long
Island generating facilities and our Ravenswood generating facility under a
lightened regulatory standard. Our KEDNE subsidiaries are subject to regulation
by the DTE and NHPUC. Our Energy Services subsidiaries which engage in the
retail sale of gas and electricity are also subject to regulation by the NYPSC
and the New Jersey Board of Public Utilities. For further information regarding
the state regulatory commissions, see the discussion in "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Regulation and Rate Matters."
Federal Energy Regulatory Commission
The FERC regulates the sale of electricity at wholesale and the transmission of
electricity in interstate commerce as well as certain corporate and financial
activities of companies that are engaged in such activities. The Long Island
generating facilities and the Ravenswood facility are subject to FERC regulation
based on their wholesale energy transactions. In 1998, LIPA, KeySpan and the
Staff of FERC stipulated to a five-year rate plan for the Long Island generating
facilities with agreed-upon yearly adjustments, which have been approved by
FERC. Our Ravenswood facility's rates are based on a market-based rate
application approved by FERC. The rates that our Ravenswood facility may charge
are subject to mitigation measures due to market power concerns of FERC. The
mitigation measures are administered by the NYISO. FERC retains the ability in
future proceedings, either on its own motion or upon a complaint filed with
FERC, to modify the Ravenswood facility's rates, as well as the mitigation
measures, if FERC concludes that it is in the public interest to do so.
KeySpan currently bids and sells the energy capacity and ancillary services from
the Ravenswood facility through the energy market operated by the NYISO. For
information concerning the NYISO, see Item 7A. Quantitative and Qualitative
Disclosures About Market Risk.
FERC also has jurisdiction to regulate certain natural gas sales for resale in
interstate commerce, the transportation of natural gas in interstate commerce,
and, unless an exemption applies, companies engaged in such activities. The
natural gas distribution activities of KEDNY, KEDLI, KEDNE and certain related
intrastate gas transportation functions are not subject to FERC jurisdiction.
However, to the extent that KEDNY, KEDLI or KEDNE purchase or sell gas for
resale in interstate commerce, such transactions are subject to FERC
jurisdiction and have been authorized by the FERC. Our interests in Iroquois,
Honeoye and Steuben are also fully regulated by FERC as natural gas companies.
Securities and Exchange Commission
As a result of the acquisition of Eastern and EnergyNorth, we became a
registered holding company under PUHCA. Therefore, our corporate and financial
activities and those of our subsidiaries, including their ability to pay
dividends to us, are subject to regulation by the SEC. Under our holding company
structure, we have no independent operations or source of income of our own and
conduct substantially all of our operations through our subsidiaries and, as a
result, we depend on the earnings and cash flow of, and dividends or
distributions from, our subsidiaries to provide the funds necessary to meet our
debt and contractual obligations. Furthermore, a substantial portion of our
consolidated assets, earnings and cash flow is derived from the operations of
our regulated utility subsidiaries, whose legal authority to pay dividends or
make other distributions to us is subject to regulation by state regulatory
authorities. For additional information concerning regulation by the SEC under
PUHCA see the discussion under the heading "Securities and Exchange Commission
Regulation" contained in "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations" contained herein.
Foreign Regulation
KeySpan's foreign operations in Northern Ireland, conducted through Premier and
Phoenix, are subject to licensing by the Northern Ireland Department of Economic
Development and regulation by the U.K. Department of Trade and Industry (with
respect to the subsea and on-land portions of the Premier pipeline) and the
Northern Ireland Director General, Office for the Regulation of Electricity and
Gas (with respect to the Northern Ireland portion of the Premier pipeline and
Phoenix's operations generally). The licenses establish mechanisms for the
establishment of rates for the conveyance and transportation of natural gas, and
generally may not be revoked except upon long- term notice. Charges for the
supply of gas by Phoenix are largely unregulated unless a determination is made
of an absence of competition.
KeySpan's assets in Canada are subject to regulation by Canadian federal and
provincial authorities. Such regulatory authorities license various aspects of
the facilities and pipeline systems as well as regulate safety, operational and
environmental matters and certain changes in such facilities' and pipelines'
capacities and operations.
Employee Matters
As of December 31, 2001, KeySpan and its wholly owned subsidiaries had
approximately 13,000 employees. Of that total, approximately 5,922 employees in
our regulated companies are covered under collective bargaining agreements.
KeySpan has not experienced any work stoppage during the past five years and
considers its relationship with employees, including those covered by collective
bargaining agreements, to be good.
Executive Officers of the Company
Certain information regarding executive officers of KeySpan and certain of its
subsidiaries is set forth below:
Robert B. Catell
Mr. Catell, age 65, has been a Director of KeySpan since its creation in May
1998. He was elected Chairman of the Board and Chief Executive Officer in July
1998. He served as its President and Chief Operating Officer from May 1998
through July 1998. Mr. Catell joined KEDNY in 1958 and became an officer in
1974. He was elected Vice President in 1977, Senior Vice President in 1981 and
Executive Vice President in 1984. He was elected Chief Operating Officer in 1986
and President in 1990. Mr. Catell continued to serve as President and Chief
Executive Officer of KEDNY from 1991 through 1996, when he was elected Chairman
and Chief Executive Officer. In 1997, Mr. Catell was elected Chairman, President
and Chief Executive Officer of KEDNY and its parent KeySpan Energy Corporation.
Robert J. Fani
Mr. Fani, age 48, was elected President of KeySpan Energy Services and Supply in
July 2001. Mr. Fani joined KEDNY in 1976, and held a variety of management
positions in distribution, engineering, planning, marketing, and business
development. He was elected as a KEDNY Vice President in 1992. In 1997, Mr. Fani
was promoted to Senior Vice President of Marketing and Sales. In 1998, he
assumed the position of Senior Vice President of Marketing and Sales for
KeySpan. In September 1999, he became SENIOR Vice President for Gas Operations
and in February 2000 was promoted to Executive Vice President of Strategic
Services until assuming his current position in July 2001.
Wallace P. Parker Jr.
Mr. Parker, age 52, was elected President of KeySpan Energy Delivery in July
2001. He joined KEDNY in 1971 and served in a wide variety of management
positions. In 1987 he was named Assistant Vice President for marketing and
advertising and was elected Vice President in 1990. In 1994, Mr. Parker was
promoted to SENIOR Vice President of Human Resources and in August 1998 was
promoted to SENIOR Vice President of Human Resources of KeySpan. He also served
as Executive Vice President of Gas Operations from February 2000 until his
promotion in July 2001.
John A. Caroselli
Mr. Caroselli, age 47, was elected Executive Vice President of Strategic
Services in October 2001 and is responsible for Brand Management, Strategic
Marketing, Strategic Planning, Strategic Performance, and E-business. Mr.
Caroselli came to KeySpan in 2001 from AXA Financial where he was Executive Vice
President of Corporate Development. Prior to that, he held senior officer
positions with Chase Manhattan, Chemical Bank and Manufacturers Hanover Trust.
He has extensive experience in brand management, marketing, communications,
human resources, facilities management, e-business and change management.
Gerald Luterman
Mr. Luterman, age 58 was elected Executive Vice President and Chief Financial
Officer in February 2002. He previously served as SENIOR Vice President and
Chief Financial Officer since joining KeySpan in July 1999. He formerly served
as Chief Financial Officer of barnesandnoble.com and SENIOR Vice President and
Chief Financial Officer of Arrow Electronics, Inc., a distributor of electronic
components and computer products. Prior to that, from 1985 through 1996, he held
executive positions with American Express, including Executive Vice President
and Chief Financial Officer of the Consumer Card Division from 1991-1996. Mr.
Luterman serves on the Board of Directors of The Houston Exploration Company.
Chester R. Messer
Mr. Messer, age 60, was elected Executive Vice President of KeySpan and
President of KEDNE in November 2000, upon the acquisition of Eastern. He also
serves as President of each of our New England gas utilities, Boston Gas
Company, Colonial Gas Company, Essex Gas Company and EnergyNorth Natural Gas,
Inc. Mr. Messer joined Boston Gas Company in 1963 and rose through a succession
of positions until he was elected President in November 1988.
Anthony Nozzolillo
Mr. Nozzolillo, age 53, was elected Executive Vice President of Electric
Operations in February 2000. He previously served as SENIOR Vice President of
KeySpan's Electric Business Unit from December 1998 to January 2000. He joined
LILCO in 1972 and held various positions, including Manager of Financial
Planning and Manager of Systems Planning. Mr. Nozzolillo served as LILCO's
Treasurer from 1992 to 1994 and as SENIOR Vice President of Finance and Chief
Financial Officer from 1994 to 1998.
Lenore F. Puleo
Ms. Puleo, age 48, was elected Executive Vice President of Shared Services in
February 2000. She previously served as SENIOR Vice President of Customer
Relations for KEDNY from May 1994 to January 2000. She joined KEDNY in 1974 and
held various positions in KEDNY's Accounting, Treasury, Corporate Planning, and
Human Resources areas. She was given responsibility for the Human Resources
Department in 1987 and was named a Vice President in 1990.
Steven L. Zelkowitz
Mr. Zelkowitz, age 52, was elected to Executive Vice President and General
Counsel in July 2001, with responsibility for legal services, human resources,
regulatory affairs, enterprise-wide risk management and administration of the
internal auditing area. He joined KeySpan as SENIOR Vice President and Deputy
General Counsel in October 1998, and was elected SENIOR Vice President and
General Counsel in February 2000. Before joining KeySpan, Mr. Zelkowitz
practiced law with Cullen and Dykman in Brooklyn, New York and had been a
partner since 1984. He served on the firm's Executive Committee and was head of
its Corporate/Energy Department.
Joseph A. Bodanza
Mr. Bodanza, age 54, was elected SENIOR Vice President of Finance Operations and
Regulatory Affairs in July 2001. He continues to serve as Chief Financial
Officer of KEDNE, a position he was appointed to in November 2000, upon the
acquisition of Eastern. Mr. Bodanza previously served as SENIOR Vice President
of Finance and Management Information Systems and Treasurer of Eastern's Gas
Distribution Operations. Mr. Bodanza joined Boston Gas in 1972 and held a
variety of positions in the financial and regulatory areas before becoming
Treasurer in 1984. He was elected Vice President and Treasurer in 1988.
David J. Manning
Mr. Manning, age 51, was elected SENIOR Vice President of KeySpan's Corporate
Affairs group in April 1999. Before joining KeySpan, Mr. Manning had been
President of the Canadian Association of Petroleum Producers since 1995. From
1993 to 1995, he was Deputy Minister of Energy for the Province of Alberta,
Canada. From 1988 to 1993, he was SENIOR International Trade Counsel for the
Government of Alberta, based in New York City. Previously he was in the private
practice of law in Canada.
H. Neil Nichols
Mr. Nichols, age 64, was elected President of KeySpan Energy Development
Corporation ("KEDC"), a position to which he was elected in March 1998. KEDC is
a wholly owned subsidiary of KeySpan responsible for our Energy Investments
segment. Since February 1999, Mr. Nichols also has responsibility for KeySpan
Energy Trading Services, LLC, which provides fuel-procurement management and
energy-trading services for KEDNY, KEDLI and LIPA. Mr. Nichols joined KeySpan in
1997 as a broad-based negotiator and business strategist with comprehensive
finance and treasury experience in domestic and international markets. Prior to
joining KeySpan, Mr. Nichols was an owner and president of Corrosion
Interventions, Ltd. in Toronto, Canada. He also served as Chief Financial
Officer and Executive Vice President with TransCanada PipeLines.
Cheryl T. Smith
Ms. Smith, age 50, joined KeySpan in November 1998. She serves as SENIOR Vice
President and Chief Information Officer of KeySpan's Information technology
division. She came to KeySpan from Verizon (Bell Atlantic) where she served as
Vice President of Strategic Systems and Corporate Systems from 1995 through
1998. Prior to Bell Atlantic, she worked at Honeywell Federated Systems Inc. as
the Director of Management Information Services for Honeywell Federal Systems,
Inc.
Colin P. Watson
Mr. Watson, age 50, was named SENIOR Vice President of KeySpan's Strategic
Marketing and E- Business division effective March 1, 2000. He previously served
as Vice President of Strategic Marketing from May 1998 until his promotion to
SENIOR Vice President. Mr. Watson joined KEDNY in 1997 as Vice President of
Strategic Marketing. From 1973 to 1997, he held several positions at NYNEX,
including Vice President of General Business Sales and Managing Director of
worldwide operations.
Elaine Weinstein
Ms. Weinstein, age 55, was named SENIOR Vice President of KeySpan's Human
Resources division in November 2000. She previously served as Vice President of
Staffing and Organizational Development since September 1998. Prior to that
time, Ms. Weinstein was General Manager of Employee Development since joining
KeySpan in 1995. Prior to 1995, Ms. Weinstein was Vice President of Training and
Organizational Development at Merrill Lynch.
Lawrence S. Dryer
Mr. Dryer, age 42, was named SENIOR Vice President and Chief Financial Officer
of KeySpan Services, Inc. effective March 1, 2002. He had been Acting Chief
Financial Officer since August 2001. He also serves as our Internal Auditor, a
position he has held since he was elected Vice President, Internal Audit in
September 1998. Prior to such positions, Mr. Dryer had been with LILCO from 1992
to 1998 as Director of Internal Audit. Prior to joining LILCO, Mr. Dryer was an
Audit Manager with Coopers & Lybrand.
Ronald S. Jendras
Mr. Jendras, age 54, was named Vice President, Controller and Chief Accounting
Officer of KeySpan in August 1998. He joined KEDNY in 1969 and held a variety of
positions in the Accounting Department before being named budget director in
1973. In 1983, Mr. Jendras was promoted to manager of KEDNY's Rate and
Regulatory Affairs area, and in 1997, was named general manager of the
Accounting Division. Mr. Jendras has been Treasurer of KeySpan Foundation since
1998 as well as a member of its Board of Directors.
Richard A. Rapp, Jr.
Mr. Rapp, age 43, was elected Vice President and Deputy General Counsel in
February 2000 and in June 2000, he assumed the additional responsibility of
corporate Secretary. He joined LILCO in 1984 and has held various positions in
the Legal Department including several Assistant General Counsel positions.
Michael J. Taunton
Mr. Taunton, age 46, has been KeySpan's Vice President and Treasurer since June
2000. Prior to that time, he served as Vice President of Investor Relations
since September 1998. He joined KEDNY in 1975 and held positions in Accounting,
Customer Service, Corporate Planning, Budgeting and Forecasting, Marketing and
Sales and Business Process Improvement.
Item 2. Properties
Information with respect to KeySpan's material properties used in the conduct of
its business is set forth in, or incorporated by reference in, Item 1 hereof.
Except where otherwise specified, all such properties are owned or, in the case
of certain rights of way used in the conduct of its gas distribution business,
held pursuant to municipal consents, easements or long-term leases, and in the
case of gas and oil properties, held under long-term mineral leases. In addition
to the information set forth therein with respect to properties utilized by each
business segment, KeySpan owns or leases a variety of office space used for its
administrative operations. In the case of leased office space, we anticipate no
significant difficulty in leasing alternative space at reasonable rates in the
event of the expiration, cancellation or termination of a lease.
Item 3. Legal Proceedings
See Note 8 to the Consolidated Financial Statements, "Contractual
Obligations and Contingencies - Legal Matters."
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of the security holders during the last
quarter of the 12 months ended December 31, 2001.
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
KeySpan's common stock is listed and traded on the New York Stock Exchange and
the Pacific Stock Exchange under the symbol "KSE." As of March 1, 2002, there
were approximately 82,321 registered record holders of KeySpan's common stock.
The following table sets forth, for the quarters indicated, the high and low
sales prices and dividends declared per share for the periods indicated:
2001 High Low Dividends Per Share
- -------------------- -----------------------------------------------------------
First Quarter $41.94 $34.20 $0.445
Second Quarter $41.10 $35.75 $0.445
Third Quarter $37.20 $29.10 $0.445
Fourth Quarter $35.35 $31.53 $0.445
2000 High Low Dividends Per Share
- -------------------- -----------------------------------------------------------
First Quarter $27.875 $20.188 $0.445
Second Quarter $32.688 $26.000 $0.445
Third Quarter $40.125 $30.938 $0.445
Fourth Quarter $43.625 $33.500 $0.445
Item 6. Selected Financial Data
(In Thousands of Dollars, Except Per Share Amounts)
- ------------------------------------------------------------------------------------------------------------------------------------
Nine Months
Year Ended Year Ended Year Ended Ended Year Ended
December 31, 2001 December 31, 2000 December 31, 1999 December 31, 1998 March 31, 1998
- ------------------------------------------------------------------------------------------------------------------------------------
Income Summary
Revenues
Gas Distribution $ 3,613,551 $ 2,555,785 $ 1,753,132 $ 856,172 $ 645,659
Electric Services 1,421,079 1,444,711 861,582 408,305 -
Electric Distribution - - - 330,011 2,478,435
Gas Exploration and Production 400,031 274,209 150,581 70,812 -
Energy Services and Other 1,198,454 805,997 189,318 63,181 -
- ------------------------------------------------------------------------------------------------------------------------------------
Total revenues 6,633,115 5,080,702 2,954,613 1,728,481 3,124,094
Operating expenses
Purchased gas for resale 2,171,113 1,408,680 744,432 331,690 299,469
Fuel and purchased power 538,532 460,841 17,252 91,762 658,338
Operation and maintenance 2,114,759 1,659,736 1,091,166 777,678 511,165
Depreciation, depletion and
amortization 559,138 330,922 253,440 254,859 183,129
Early retirement and
severance charges - 65,175 - 64,635 -
Operating taxes 448,924 421,936 366,154 257,124 466,326
- ------------------------------------------------------------------------------------------------------------------------------------
Operating income 800,649 733,412 482,169 (49,267) 1,005,667
Other income (deductions) 7,206 (12,086) 46,555 (36,727) (6,301)
- ------------------------------------------------------------------------------------------------------------------------------------
Income (loss) before interest
charges and income taxes 807,855 721,326 528,724 (85,994) 999,366
Interest charges 353,470 201,314 133,751 140,733 404,473
Income taxes (credits) 210,693 217,262 136,362 (59,794) 232,653
- ------------------------------------------------------------------------------------------------------------------------------------
Net income (loss) 243,692 302,750 258,611 (166,933) 362,240
Preferred stock dividends 5,904 18,113 34,752 28,604 51,813
- ------------------------------------------------------------------------------------------------------------------------------------
Earnings (loss) from
Continuing Operations $ 237,788 $ 284,637 $ 223,859 $ (195,537) $ 310,427
- ----------------------------------------------------------------------------------------------------------------------------------
Discontinued Operations
Income from Operations, net of tax 10,918 (1,943) - - -
Loss on Disposal, net of tax (30,356) - - - -
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings (loss) from
Discontinued Operations (19,438) (1,943) - - -
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings for Common Stock $ 218,350 $ 282,694 $ 223,859 $ (195,537) $ 310,427
- ----------------------------------------------------------------------------------------------------------------------------------
Financial Summary
Basic earnings (loss) per share ($) 1.58 2.10 1.62 (1.34) 2.56
Cash dividends declared per share ($) 1.78 1.78 1.78 1.19 1.78
Book value per share, year-end ($) 21.33 20.65 20.26 20.90 21.88
Market value per share, year-end ($) 34.65 42.38 23.19 31.00 31.50
Shareholders 82,300 86,900 90,500 103,239 78,314
Capital expenditures ($) 1,059,759 925,257 725,670 676,563 297,230
Total assets ($) 11,789,606 11,307,465 6,730,691 6,895,102 11,900,725
Common equity ($) 2,890,602 2,815,816 2,712,325 3,022,908 2,662,447
Redeemable preferred stock ($) - - 363,000 363,000 562,600
Preferred stock ($) 84,077 84,205 84,339 447,973 -
Long term debt ($) 4,697,649 4,116,441 1,682,702 1,619,067 4,381,949
Total capitalization ($) 7,672,328 7,016,462 4,479,366 5,089,948 7,606,996
- ----------------------------------------------------------------------------------------------------------------------------------
Utility Operating Statistics
Firm gas and transportation
sales (MDTH) 427,051 306,509 275,771 87,179 58,304
Other sales (MDTH) 106,800 91,406 54,661 38,088 21,025
Total active gas meters 2,499,170 2,483,730 1,628,497 1,610,202 464,563
Gas heating customers 1,267,000 1,260,000 677,000 665,000 295,000
- ----------------------------------------------------------------------------------------------------------------------------------
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
KeySpan Corporation (referred to in this Management's Discussion and Analysis of
Financial Condition and Results of Operations as "KeySpan", "we", "us", and
"our") is a registered holding company under the Public Utility Holding Company
Act of 1935, as amended ("PUHCA"). We operate six utilities that distribute
natural gas to approximately 2.5 million customers in New York City, Long
Island, Massachusetts and New Hampshire making us the fifth largest gas
distribution company in the United States and the largest in the Northeast. We
also own and operate electric generating plants in Nassau and Suffolk Counties
on Long Island and in Queens County in New York City. Under contractual
arrangements, of varying lengths and duration, we provide power, electric
transmission and distribution services, billing and other customer services for
approximately one million electric customers of the Long Island Power Authority
("LIPA"). Our other subsidiaries are involved in gas and oil exploration and
production; gas storage; wholesale and retail gas and electric marketing;
appliance service; heating, ventilation and air conditioning installation and
services; large energy-system ownership, installation and management;
engineering services; and fiber optic services. We also invest in, and
participate in the development of, pipelines and other energy-related projects,
domestically and internationally. (See Note 2 to the Consolidated Financial
Statements, "Business Segments" for additional information on each operating
segment.)
Consolidated Summary of Results
- -------------------------------
The following is a discussion of transactions affecting comparative earnings for
the years ended December 31, 2001, 2000 and 1999. As mentioned in Note 1 to the
Consolidated Financial Statements "Summary of Significant Accounting Policies",
on November 8, 2000 we acquired all of the common stock of Eastern Enterprises
("Eastern") and EnergyNorth Inc. ("ENI") in a transaction accounted for as a
purchase. As a result, consolidated comparisons in earnings, revenues and
expenses between reporting periods have been significantly affected by the
addition of these operations. 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.
Consolidated earnings from continuing operations for 2001 were $237.8 million,
or $1.72 per share compared to $284.6 million, or $2.12 per share for 2000 and
$223.9 million, or $1.62 per share for 1999. Average common shares outstanding
for 2001 increased by 3% compared to 2000 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 2001 earnings per
share by $0.05 compared to 2000.
On January 24, 2002, we announced that we have entered into an agreement to sell
Midland Enterprises Inc. ("Midland"), our marine barge business. In anticipation
of this divestiture, which we expect to close in the second quarter of 2002, we
have reported Midland's operations as discontinued for 2001 as well as for 2000.
For 2001, we reflected a loss of $19.4 million, or $0.14 per share, which
included both Midland's 2001 operating results as well as an estimate for our
loss on the sale. At the time of our acquisition of Eastern, we were ordered by
the Securities and Exchange Commission ("SEC") to divest this subsidiary by
November 8, 2003 since its operations are not functionally related to our core
utility operations. (See Note 10 to the Consolidated Financial Statements
"Discontinued Operations" for further information.) In 2000, Midland's results
of operations reflected a loss of $1.9 million, or $0.02 per share. There were
no discontinued operations in 1999, since we acquired Midland as part of the our
acquisition of Eastern on November 8, 2000.
Consolidated earnings available for common stock, which includes both results of
operations from continuing as well as discontinued operations, were $218.4
million or $1.58 per share in 2001, compared to $282.7 million or $2.10 per
share in 2000 and $223.9 million or $1.62 per share in 1999. Diluted earnings
per share were $1.56 in 2001 and $2.09 in 2000. Basic and diluted earnings per
share were the same in 1999.
During 2001, we recorded the effects of a number of events that significantly
affected results of operations as follows: (1) A non-cash impairment charge
recorded by our gas exploration and production subsidiaries to recognize the
effect of lower wellhead prices on their valuation of proved gas reserves. Our
share of this charge was $26.2 million after-tax ($40.7 million pre-tax) or
$0.19 per share. (See Note 1 to the Consolidated Financial Statements "Summary
of Significant Accounting Policies", Item F for further details.); (2) The
reversal of a previously recorded loss provision regarding certain pending rate
refund issues relating to the 1989 RICO class action settlement of $20.1 million
after-tax ($33.5 million pre-tax), or $0.15 per share. (See Note 12 to the
Consolidated Financial Statements "Class Action Settlement" for a further
discussion of this issue.); and (3) Losses incurred by the Roy Kay companies of
$95.0 million after-tax ($137.8 million pre- tax) or $0.69 per share reflecting
costs related to the discontinuance of the general contracting activities of
these companies, costs to complete work on certain loss construction projects,
and operating losses incurred. (See Note 11 to the Consolidated Financial
Statements, "Roy Kay Operations" and Note 8 "Contractual Obligations and
Contingencies " - legal matters, for a further discussion of these issues.)
In 2000, we recorded a $65.2 million pre-tax charge associated with early
retirement and severance programs that were implemented upon the acquisition of
Eastern and ENI. The after-tax effect of this charge on consolidated results
from continuing operations was $41.1 million, or $0.31 per share. There were no
significant items to note in 1999.
Interest expense increased by $152.2 million, or 75% in 2001, reflecting higher
levels of debt outstanding, primarily related to: (i) $1.65 billion of long-term
debt and $308.6 million of commercial paper issued to finance the acquisition of
Eastern and ENI; (ii) debt assumed in the Eastern and ENI acquisition; (iii)
$625 million of notes issued during the year, primarily used to repay short-
term debt; (iv) debt incurred by our Canadian subsidiary; as well as (v) higher
commercial paper borrowings during the year to satisfy seasonal working capital
needs. As part of the RICO class settlement adjustment noted above, we reversed
$11.5 million of previously recorded carrying charges during 2001; of which $9
million ($5.9 million after-tax) was recorded in 2000.
Earnings before interest and taxes ("EBIT") from continuing operations in 2001,
after adjusting for the matters noted above, were substanially higher than such
earnings for 2000. Our gas distribution operations benefitted from the addition
of the New England gas utilities for an entire year as compared to only two
months in the prior year's results, as well as an increase in net margins due to
continued gas sales growth, and cost saving synergies. Further, our gas
exploration and production activities benefitted from the combined effect of
higher realized gas prices, primarily during the first quarter of 2001, and
improved production volumes throughout the year. These benefits to EBIT from
continuing operations were almost entirely offset by higher interest expense. In
addition, during 2000 certain charges were incurred by our corporate and
administrative areas that were not incurred in 2001, which resulted in a
significant increase to comparative earnings. (See the discussion under the
heading "Review of Operating Segments" for an analyses of comparative EBIT for
each of our operating segments.)
The increase in earnings for 2000 over 1999, resulted from solid performance
across all of our business segments. Further, our average common shares
outstanding were approximately 3% lower for 2000 compared to 1999 due to a stock
repurchase program in 1999. The lower shares outstanding had a favorable affect
on earnings per share from continuing operations of $0.07. Our gas distribution
operations benefitted from gas sales growth, favorable gas prices compared to
oil prices for most of 2000 and earnings from the acquisition of the New England
gas distribution companies.
Earnings growth in 2000 was also due to the operation of our investment in the
Ravenswood electric generation facility, ("Ravenswood facility") located in
Queens, New York. The Ravenswood facility was acquired in June 1999 and
therefore, earnings for 2000 reflected a full year of operations, while 1999
reflected less than seven full months of operations. In addition, consolidated
earnings from continuing operations were further enhanced through improved
performance from our gas exploration and production operations which benefitted
from significantly higher realized gas prices and increased production volumes
in 2000. In addition, on March 31, 2000 we increased our ownership in our gas
and oil exploration and production subsidiary The Houston Exploration Company
("Houston Exploration") from 64% to 70% at that time. Offsetting, to some
extent, these enhancements to earnings in 2000, were expenses incurred by our
corporate and administrative areas that were not allocated to our various
business segments and were not incurred in 1999, as well as an increase to
interest expense reflecting higher levels of debt outstanding due primarily to
the acquisition of Eastern and ENI as previously noted.
Income tax expense generally reflects the lower level of pre-tax income in 2001
compared to last year. For 2000, income tax expense reflects the higher level of
pre-tax income compared to 1999. Further, during the last quarter of 2000, the
basis for computing certain local income taxes was changed which increased
income tax expense in 2001 and 2000. (See Note 3 to the Consolidated Financial
Statements, "Income Taxes" for more information.) Preferred stock dividends have
decreased in all periods as a result of a redemption, at maturity, of 14.5
million shares of preferred stock in the second quarter of 2000.
Financial Outlook for 2002
Consistent with the guidance issued in December 2001, KeySpan's 2002 earnings
from core operations (defined for this purpose as all operations other than gas
exploration and production operations) are forecasted to be approximately $2.40
to $2.45 per share. KeySpan's 2002 earnings forecast for its gas exploration and
production operations is approximately $0.20-$0.30 per share, based on the most
recent guidance issued by Houston Exploration. Houston Exploration's earnings
forecasts may vary significantly during the year due to, among other things,
changing energy market conditions.
Pursuant to SEC rules for exploration and production companies which use the
"full cost" accounting method, such as Houston Exploration and KeySpan
Exploration and Production LLC, a quarterly "ceiling test" calculation is
required using commodity prices as of the end of the reporting period. As a
result, depending on prevailing commodity prices, our gas exploration and
production subsidiaries may be required to recognize a non-cash impairment
charge at the end of any future reporting period.
Review of Operating Segments
- ----------------------------
Gas Distribution
KeySpan Energy Delivery New York ("KEDNY") provides gas distribution service to
customers in the New York City Boroughs of Brooklyn, Queens and Staten Island.
KeySpan Energy Delivery Long Island ("KEDLI") provides gas distribution service
to customers in the Long Island Counties of Nassau and Suffolk and the Rockaway
Peninsula of Queens County. Four natural gas distribution companies - Boston Gas
Company, Essex Gas Company, Colonial 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. Since the New England entities were acquired on November 8, 2000,
results of operations for periods prior to such date do not reflect the
operating results of these entities.
The table below highlights certain significant financial data and operating
statistics for the Gas Distribution segment for the periods indicated.
(In Thousands of Dollars)
-------------------------
Year Ended Year Ended Year Ended
December 31, 2001 December 31, 2000 December 31, 1999
- ----------------------------------------------------- --------------------------- ---------------------------- ------------------
Revenues $ 3,613,551 $ 2,555,785 $ 1,753,132
Cost of gas 2,017,782 1,303,515 702,044
Revenue taxes 119,084 117,811 108,488
- ----------------------------------------------------- --------------------------- ---------------------------- ------------------
Net Revenues 1,476,685 1,134,459 942,600
- ----------------------------------------------------- --------------------------- ---------------------------- ------------------
Operating expenses
Operations and maintenance 593,341 456,028 415,888
Early retirement and severance programs - 41,790 -
Depreciation and amortization 253,523 143,335 102,997
Operating taxes 148,428 131,854 115,305
- ----------------------------------------------------- --------------------------- ---------------------------- ------------------
Total Operating Expenses 995,292 773,007 634,190
- ----------------------------------------------------- --------------------------- ---------------------------- ------------------
Operating Income 481,393 361,452 308,410
Other Income and (Deductions), Net 10,969 5,774 9,835
- ----------------------------------------------------- --------------------------- ---------------------------- ------------------
Earnings Before Interest and Taxes $ 492,362 $ 367,226 $ 318,245
- ----------------------------------------------------- --------------------------- ---------------------------- ------------------
Firm gas sales (MDTH) 261,473 216,000 172,019
Firm transportation (MDTH) 101,000 40,655 21,249
Transportation - Electric
Generation (MDTH) 64,578 49,854 82,503
Other sales (MDTH) 106,800 91,406 54,661
Warmer (Colder) than normal - New York 10.0% (2.1)% 10.0%
Warmer (Colder) than normal - New England 4.6% (4.0)% N/A
- ----------------------------------------------------- --------------------------- ---------------------------- ------------------
An MDTH is 10,000 therms 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)
increased by $342.2 million or 30% in 2001 compared to 2000. The gas
distribution operations of KEDNE added $296.8 million to this increase, while
our New York based gas distribution operations accounted for the remaining $45.4
million increase. Net gas revenues increased by $191.9 million or 20% in 2000
compared to 1999. The gas distribution operations of KEDNE contributed $126.6
million to the increase in net gas revenues, while our New York based gas
distribution operations added the remaining $65.3 million to the increase.
Net revenues from our firm gas customers (residential, commercial and industrial
customers) increased by $343.1 million in 2001 compared to 2000. This increase
was largely driven by the addition of KEDNE's gas distribution operations which
accounted for $296.8 million of the increase. Our New York based gas
distribution operations added $9.2 million to firm net revenues in 2001 through
the addition of new gas customers and through our continuing efforts to convert
residential and commercial customers from oil-to-gas for space heating purposes,
primarily on Long Island. In addition, the comparative increase in firm net
revenues in 2001 was favorably affected by the recovery of previously deferred
property taxes, as well as regulatory incentives which added $13.3 million and
$23.7 million, respectively to firm net gas revenues in 2001. The property taxes
are being amortized through operating taxes and therefore do not benefit net
income.
Firm net gas revenues grew approximately $163.9 million in 2000 over 1999. The
gas distribution operations of Eastern and ENI added $126.6 million, while our
New York based gas distribution operations added $41.8 million through the
addition of new gas customers and oil-to-gas conversions, primarily in the Long
Island market, as well as from the benefits of colder weather. Partially
offsetting these benefits were regulatory customer refunds that reduced net
margins by $4.5 million.
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. Net revenues in
these markets in 2001 were slightly lower than sales to this market for 2000.
Sales in these markets increased by $28.0 million in 2000 compared to 1999,
through aggressive unit pricing and the addition of two large commercial and
industrial customers. The majority of interruptible profits earned by KEDNE and
KEDLI are returned to firm customers through the gas adjustment clause.
We believe that significant growth opportunities exist on Long Island and in our
New England service territories. We estimate that on Long Island approximately
35% of the residential and multi-family markets, and approximately 55% of the
commercial market currently use natural gas for space heating. Further, we
estimate that in our New England service territories approximately 45% of the
residential and multi-family markets, and approximately 30% of the commercial
market currently use natural gas for space heating and other purposes. In all
our market segments we will continue to seek growth 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.
KEDNY and KEDLI each operate under a utility tariff that contains a weather
normalization adjustment that largely offsets shortfalls or excesses of firm net
revenues during a heating season due to variations from normal weather. The gas
distribution operations of our New England based subsidiaries do not have a
weather normalization adjustment and, as a result, fluctuations from normal
weather may have a significant positive or negative effect on the results of
these operations. To a small extent, we mitigated the effect of fluctuations in
normal weather patterns on our New England based subsidiaries' cash flows, by
employing a derivative hedging instrument in 2001 for a limited sales quantity.
(See Note 9 to the Consolidated Financial Statements "Hedging, Derivative
Financial Instruments and Fair Values" for further information.)
Sales, Transportation and Other Quantities
Firm gas sales and transportation quantities increased by 41% during 2001,
compared to last year. The gas distribution operations of KEDNE, accounted for
122.1 Mdth or 100% of the increase. Firm gas sales and transportation quantities
from our New York based gas distribution operations decreased by 8% compared to
last year as a result of warmer than normal weather. Weather was approximately
10% warmer than normal in 2001 and approximately 11% warmer than last year. Firm
gas sales and transportation quantities increased by 33% in 2000 compared to
1999 reflecting firm gas sales from KEDNE which accounted for 41.0 Mdth, or 65%
of the increase, as well as from the addition of new gas customers and the
benefits derived from colder weather.
Weather normalized sales quantities in 2001 in our New York service territories
were flat compared to 2000 due primarily to the effect on consumption of
extraordinarily high gas prices during the first quarter of 2001 when the
majority of our yearly gas distribution earnings are usually realized. Weather
normalized sales quantities increased by approximately 5% in 2000 compared to
1999 in our New York service territories.
Firm gas transportation quantities increased in all periods, due to our
continued natural gas unbundling initiatives and the addition of the New England
gas distribution operations. At December 31, 2001, approximately 141,000
residential, commercial and industrial customers throughout our service
territories purchased their gas supply from third party suppliers compared to
approximately 130,500 customers in 2000 and 46,000 customers in 1999. Net
revenues are not affected by customers opting to purchase their gas supply from
other sources, since delivery rates charged to transportation customers
generally are the same as delivery rates charged to full sales service
customers.
Transportation quantities related to electric generation reflect the
transportation of gas to our electric generating facilities located on Long
Island. Net revenues from these services are deducted from the cost of gas
charged to firm customers.
Other sales quantities include on-system interruptible quantities, off-system
sales quantities (sales made to customers outside of our service territories)
and related transportation. Effective April 1, 2000, we entered into an
agreement with Coral Resources, L.P. ("Coral"), a subsidiary of Shell Oil
Company. Coral assists in the origination, structuring, valuation and execution
of energy-related transactions on behalf of KEDNY and KEDLI. Effective November
1, 1999, our Massachusetts based gas distribution subsidiaries entered into a
three-year portfolio management contract with El Paso Energy Marketing, Inc. El
Paso provides all of the city gate supply requirements at market prices and
manages certain upstream capacity, underground storage and term supply
contracts.
Operating Expenses
Operating expenses increased by $222.3 million, or 29%, in 2001 compared to last
year, due to the addition of the New England gas distribution operations, which
added $289.1 million to operating expenses in 2001. This amount includes
operations and maintenance costs of $170.6 million, depreciation and
amortization charges of $91.0 million and general taxes of $27.5 million.
Operating expenses related to our New York based gas distribution operations
decreased in 2001 compared to last year, as a result of cost savings synergies
realized this year and lower general and administrative costs being allocated to
our New York operations as a result of a change in our allocation methodology
pursuant to the SEC's requirements under PUHCA. Further, in 2000 we recorded a
charge of $41.8 million associated with early retirement and severance programs
implemented upon the acquisition of Eastern and ENI.
Depreciation and amortization expense for this segment reflects the amortization
of goodwill ($35.6 million in 2001), that was assigned to gas distribution
operations, as well as continued property additions, and the amortization of
certain costs previously deferred and now being recovered through rates. During
2001, the Financial Accounting Standards Board ("FASB") issued Statement of
Financial Accounting Standard ("SFAS") 142 "Goodwill and Other Intangible
Assets". As required by SFAS 142, goodwill will no longer be subject to
amortization, but rather, will be tested for impairment at least annually. SFAS
142 is effective January 1, 2002. (See Note 1 "Summary of Significant Accounting
Policies" - item G for further information.)
Operating expenses increased by $138.8 million, or 22%, in 2000 compared to 1999
primarily due to the addition of the KEDNE gas distribution operations. KEDNE
added $69.8 million to operating expenses in 2000. This amount includes
operations and maintenance costs of $42.0 million, depreciation and amortization
charges of $21.9 million and general taxes of $5.9 million. Further, operating
expenses in 2000 include $41.8 million of early retirement and severance program
charges. Included in the depreciation and amortization charge, is an expense of
$6.2 million primarily representing two months amortization of goodwill that was
assigned to gas distribution operations. The remaining increase in depreciation
and amortization expense reflects continued property additions, and the
amortization of certain costs previously deferred and now being recovered
through revenue recovery mechanisms. Further, operating taxes, which include
state and local taxes on property have increased as the applicable property base
and tax rates generally have increased.
Other Matters
As previously mentioned, there remain significant growth opportunities in our
Long Island and New England gas distribution service areas. The Northeast region
represents a significant portion of the country's population and energy
consumption. As our gas distribution operations evolve within the new
deregulated gas environment, gas sales growth will remain a critical core
strategy. Customer additions are and will remain critical to our earnings in the
future. The beneficial effect of these initiatives, however, may not be fully
realized in the short-term since we will make incremental investments in our gas
distribution network and expand our promotional campaigns to optimize the
long-term growth opportunities in our territories.
To take advantage of the anticipated gas sales growth opportunities in the New
York City metropolitan area, in 2000 we announced the formation of 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 connect with KEDLI's
facilities on Long Island. A companion proposal filed by Algonquin Gas
Transmission Company also received preliminary approval for increasing
throughput on more than 13 miles of existing pipeline and constructing a new
compressor station in Connecticut. The Islander East Pipeline which is expected
to begin operating in 2003, will transport 260,000 dth daily to the Long Island
and New York City energy markets, enough fuel to cool and heat 600,000 homes, as
well as allow us to further diversify the geographic sources of our gas supply.
We are currently evaluating various options for the financing of this pipeline.
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 of varying lengths, manage the electric
transmission and distribution ("T&D") system, the fuel and electric purchases,
and the off-system electric sales for LIPA.
Selected financial data for the Electric Services segment is set forth in the
table below for the periods indicated.
(In Thousands of Dollars)
-------------------------
Year Ended Year Ended Year Ended
December 31, 2001 December 31, 2000 December 31, 1999
- -------------------------------------------- ---------------------------- ----------------------------- -------------------------
Revenues $ 1,421,079 $ 1,444,711 $ 861,582
Purchased fuel 281,398 315,139 17,252
- -------------------------------------------- ---------------------------- ----------------------------- -------------------------
Net Revenues 1,139,681 1,129,572 844,330
- -------------------------------------------- ---------------------------- ----------------------------- -------------------------
Operating expenses
Operations and maintenance 699,169 675,393 527,729
Depreciation 52,247 49,278 44,334
Operating taxes 155,697 158,886 132,327
- -------------------------------------------- ---------------------------- ----------------------------- -------------------------
Total Operating Expenses 907,113 883,557 704,390
- -------------------------------------------- ---------------------------- ----------------------------- -------------------------
Operating Income 232,568 246,015 139,940
Other Income and (Deductions), Net 13,523 4,673 1,257
- -------------------------------------------- ---------------------------- ----------------------------- -------------------------
Earnings Before Interest and Taxes $ 246,091 $ 250,688 $ 141,197
- -------------------------------------------- ---------------------------- ----------------------------- -------------------------
Electric sales (MWH)* 4,930,129 4,893,451 2,995,970
Capacity (MW)* 2,200 2,200 2,168
Cooling degree days 1,381 1,075 1,312
- -------------------------------------------- ---------------------------- ----------------------------- -------------------------
*Reflects the operations of the Ravenswood facility only.
Net Revenues
Total electric net revenues increased slightly in 2001 compared to last year.
Net revenues from the Ravenswood facility decreased by $12.6 million, or 3%,
reflecting lower realized energy prices and lower ancillary service revenues
offset, in part, by effective hedging strategies. (Ancillary services include
primarily spinning reserves and non-spinning reserves available to replace
energy that is unable to be delivered due to the unexpected loss of a major
energy source.) Further, capacity and energy sales quantities, as well as
realized energy prices were impacted by an increase in available capacity in New
York City during 2001.
The pricing for both energy sales and the sale of certain ancillary services to
the New York Independent System Operator ("NYISO") energy markets is still
evolving and the FERC has adopted several price mitigation measures which are
subject to rehearing and possible judicial review. The final resolution of these
issues and their effect on our financial position, results of operations and
cash flows can not be determined at this time. (See Item 7A. Quantitative and
Qualitative Disclosures About Market Risk for a further discussion of these
matters.)
Revenues from the service agreements with LIPA increased by $22.7 million, or 3%
in 2001 compared to last year. Included in revenues in 2001, are billings to
LIPA for certain third party construction costs that were significantly higher
than such billings last year. These revenues have minimal impact on net income
since the costs associated with these construction projects are included in
operating expenses and we share any cost under-runs with LIPA. Further,
reflected in 2000, are revenues earned from the construction of an underground
transmission line to reinforce the electric system capacity on the southfork of
Long Island. These revenues also have minimal impact on net income. Excluding
both the third party construction billings and revenues associated with the
construction of the underground transmission line, revenues in 2001 associated
with the LIPA service agreements were comparable to such revenues earned last
year. In addition, in 2001 we earned $16.2 million associated with non-cost
performance incentives provided for under these agreements, compared to $15.4
million earned last year. (For a description of the LIPA service agreements, see
"LIPA Agreements.")
Net revenues increased by $285.2 million, or 34%, in 2000 compared to 1999 due
primarily to a full year of operations of the Ravenswood facility. Revenues from
the Ravenswood facility benefitted both from the sale of energy, capacity and
ancillary services to the NYISO at competitive market prices, as well as from
effective hedging strategies. Prior to the start of operations of the NYISO on
November 19, 1999, all of the energy and capacity from the Ravenswood facility
was sold to the Consolidated Edison Company of New York, Inc. ("Consolidated
Edison") on a cost recovery and fixed fee basis. Further, there were no sales of
ancillary services in 1999.
Revenues from our service agreements with LIPA were $50.2 million higher in 2000
compared to 1999. The increase is largely due to the construction of the
underground transmission line described previously. Further, revenues in 2000
include $16.5 million related to our share of off-system sales from the Long
Island electric generation units. Under the terms of the energy management
agreement, we are entitled to one-third of the profit from any off-system
electricity sales arranged by us on LIPA's behalf. In addition, in 2000 we
earned $15.4 million associated with non-cost performance incentives provided
for under these agreements, compared to $15.8 million earned in 1999.
Operating Expenses
Operating expenses increased by $23.6 million, or 3% in 2001, compared to 2000,
primarily as a result of the increase in third party construction costs
previously noted and higher allocated charges for corporate and administrative
costs due to changes in our allocation methodology as prescribed under PUHCA.
Operating expenses in 2000 increased by $179.2 million or 25% compared to 1999,
primarily reflecting the operations of the Ravenswood facility for a full year.
Operating expenses associated with the Ravenswood facility increased by $143.7
million in 2000 compared to 1999. Included in operating expenses for the
Ravenswood facility are charges of $63.9 million for fuel management services
provided by one of our subsidiaries within the Energy Services segment. There
were no comparable charges in 1999. Operating expenses incurred under LIPA
service agreements increased by $35.5 million in 2000 compared to 1999 due
primarily to costs incurred to install the new electric transmission line
discussed earlier.
Other Matters
On September 5, 2001, the New York State Board on Electric Generation Siting and
the Environment ("Siting Board") approved our application to build a new 250 MW
generation facility at the Ravenswood facility site. The new facility is
expected to commence operations in late 2003 or early 2004. The capacity and
energy produced from this plant is anticipated to be sold into the NYISO energy
markets. We have also filed an application with the Siting Board for approval of
our proposal to build a similar 250 MW combined cycle electric generating
facility on Long Island. This facility is anticipated to commence operation in
late 2004 or early 2005. We anticipate that 50% of the plant's capacity will be
under a long-term contract to LIPA. Further, we are in the process of
constructing two 79 MW electric generating facilities on Long Island that will
serve LIPA in the summer of 2002. We are currently evaluating various options
for the financing of these facilities.
Under a Generation Purchase Rights Agreement ("GPRA"), LIPA had the right to
purchase, at fair market value, all existing Long Island based generating assets
during the twelve month period beginning on May 28, 2001. On March 11, 2002,
LIPA and KeySpan announced that they had reached an agreement in principle to,
among other things, extend the GPRA for three years. See the discussion under
the heading "Electric Services - Revenue Mechanisms, Generation Purchase Rights
Agreement" for further details.
Energy Services
The Energy Services segment primarily includes companies that provide services
through four lines of business to clients located within the New York City
metropolitan area, Rhode Island, Pennsylvania, Massachusetts and New Hampshire.
The lines of business are: Home Energy Services; Business Solutions; Energy
Commodity Procurement; and Fiber Optic Services.
The table below highlights selected financial information for the Energy
Services segment.
(In Thousands of Dollars)
-------------------------
Year Ended Year Ended Year Ended
December 31, 2001 December 31, 2000 December 31, 1999
- --------------------------------------------------------- ------------------------ ------------------------- --------------------
Unaffiliated revenues $ 1,100,167 $ 770,110 $ 186,529
Intersegment revenues 46,718 63,296 -
Less: cost of gas and fuel 407,734 248,275 42,388
- --------------------------------------------------------- ------------------------ ------------------------- --------------------
Net revenues 739,151 585,131 144,141
Other operating expenses 849,483 507,639 148,784
- --------------------------------------------------------- ------------------------ ------------------------- --------------------
Operating Income (Loss) (110,332) 77,492 (4,643)
Other Income and (Deductions), Net 4,282 (2,727) 708
- --------------------------------------------------------- ------------------------ ------------------------- --------------------
Earnings (Loss) Before Interest and Taxes $ (106,050) $ 74,765 $ (3,935)
- --------------------------------------------------------- ------------------------ ------------------------- --------------------
The decrease in EBIT in 2001 is primarily the result of the operations of the
former Roy Kay companies, which incurred EBIT losses of $137.8 million in 2001.
We have decided to discontinue the general contracting activities of these
companies based upon our view that the general contracting business is not a
core competency of these companies. Certain remaining activities engaged in by
the former Roy Kay companies will be integrated with those of other KeySpan
energy-related businesses. (See Note 11 to the Consolidated Financial Statements
"Roy Kay Operations" for further information.) EBIT associated with these
companies in 2000 was $1.3 million.
Excluding the operations of the Roy Kay companies, EBIT for this segment was
$31.7 million in 2001 compared to $73.4 million in 2000. EBIT also includes
earnings from fuel-management services provided to the Ravenswood facility. A
subsidiary within this segment, KeySpan Energy Supply Inc., provides the
Ravenswood facility with energy procurement advisory services and acts as an
energy broker for the sale of energy and ancillary services. For these services,
KeySpan Energy Supply Inc. receives a management fee and shares in the operating
profit generated by the Ravenswood facility on the sale of energy and ancillary
services. Inter-company EBIT associated with these services in 2001 was $37.4
million compared to $60.1 million in 2000. The remaining companies in this
segment reflected a decrease in EBIT of $19.0 million in 2001 compared to 2000.
The comparative decrease in EBIT is attributed to costs incurred to complete
certain loss construction contracts and higher corporate allocated costs as
result of PUHCA requirements.
The increase in earnings of the Energy Services segment in 2000 compared to
1999, reflects primarily fuel-management services provided to the Ravenswood
facility, which for 2000, resulted in inter-company EBIT of $60.1 million. There
were no energy procurement and fuel-management advisory services between KeySpan
Energy Supply and the Ravenswood facility in 1999. This segment also realized
significantly greater gross profit margins in 2000, compared to 1999, for each
of its other lines of business. These gross profit margin enhancements resulted
from acquisitions of companies providing energy-related services and through
customer additions related to energy sales. These benefits to gross profit
margins were partially offset by increases in general and administrative
expenses associated primarily with the operations of the acquired companies.
At December 31, 2001, affiliates in this segment had net customer accounts
receivable of $332.7 million, which is consistent with the prior year balance.
This balance reflects, for the most part, receivables associated with the
design, building, and installation of large heating, ventilation and air-
conditioning ("HVAC") systems. Revenues, as well as receivables, are generally
recognized by the percentage of completion method. A number of these
construction projects are for the installation of HVAC systems for governmental
agencies and hospitals. Traditionally, the collection cycle for outstanding
accounts receivables associated with these customers is generally longer than
with other customers. It has been our experience that, for the most part, these
accounts receivable are fully collectible. In addition, included in the net
customer accounts receivable balance are receivables associated with our gas and
electric marketing activities, which balances are also consistent with prior
years.
Energy Investments
The Energy Investment segment consists of our gas exploration and production
operations, certain other domestic and international energy-related investments,
as well as certain technology related investments. Our gas exploration and
production subsidiaries 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"), 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, both located in
Northern Ireland.
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)
-------------------------
Year Ended Year Ended Year Ended
December 31, 2001 December 31, 2000 December 31,1999
- ---------------------------------------------------- ---------------------------- ------------------------- ---------------------
Revenues $ 400,031 $ 274,209 $ 150,581
Depletion and amortization expense 142,728 95,364 74,051
Full cost ceiling test write-down 41,989 - -
Other operating expenses 55,653 44,435 28,000
- ---------------------------------------------------- ---------------------------- ------------------------- ---------------------
Operating Income 159,661 134,410 48,530
Other Income and (Deductions), Net* (39,728) (22,738) (7,695)
- ---------------------------------------------------- ---------------------------- ------------------------- ---------------------
Earnings Before Interest and Taxes* $ 119,933 $ 111,672 $ 40,835
- ---------------------------------------------------- ---------------------------- ------------------------- ---------------------
Natural gas and oil production (Mmcf) 93,968 80,415 71,227
Natural gas (per Mcf) realized $ 4.24 $ 3.38 $ 2.10
Natural gas (per Mcf) unhedged $ 4.09 $ 3.97 $ 2.14
Proved reserves at year-end (BCFe) 647 593 553
- ---------------------------------------------------- ---------------------------- ------------------------- ---------------------
*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 increase in EBIT for 2001 compared to 2000 reflects a significant increase
in gas exploration and production revenues, partially offset by increases in
operating expenses associated with higher production volumes. Revenues for 2001
benefitted from the combined effect of a 17% increase in production volumes and
a 25% increase in average realized gas prices (average wellhead price received
for production including hedging gains and losses). The average realized gas
price in 2001 was 103% of the average unhedged natural gas price.
In the fourth quarter of 2001, our gas exploration and production subsidiaries
recorded a non-cash impairment charge of $42.0 million to recognize the effect
of lower wellhead prices on their valuation of proved gas reserves. Our share of
this charge, which includes our joint venture ownership interest and minority
interest, was $26.2 million after-tax. (See Note 1 to the Consolidated Financial
Statements "Summary of Significant Accounting Policies", Item F for more
information on this charge.)
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 predicable
cash flow, as well as to reduce its exposure to adverse price fluctuations in
natural gas. (See Note 9 to the Consolidated Financial Statements, "Hedging,
Derivative Financial Instruments and Fair Values" for further information.)
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.
EBIT increased by $70.8 million in 2000 compared to 1999, reflecting a
significant increase in revenues, partially offset by increases in operating
expenses. Revenues benefitted from the combined effect of a 13% increase in
production volumes and a 61% increase in average realized gas prices. The
average realized gas price in 2000 was 85% of the average unhedged natural gas
price. Further, on March 31, 2000, we increased our ownership in Houston
Exploration from 64% to 70% at that time. The increase in operating expenses
reflects the significant increase in production volumes.
Natural gas prices continue to be volatile and the risk that we may be required
to write-down our full cost pool again in the future increases when natural gas
prices are depressed or if we have significant downward revisions in our
estimated proved reserves.
Selected financial data for our other energy-related investments are set forth
in the following table for the periods indicated.
(In Thousands of Dollars)
-------------------------
Year Ended Year Ended Year Ended
December 31, 2001 December 31, 2000 December 31, 1999
- -------------------------------------------- ------------------------------ --------------------------- -------------------------
Revenues $ 98,287 $ 35,258 $ 2,789
Operation and maintenance expense 71,411 31,551 8,257
Other operating expenses 20,883 9,988 1,316
- -------------------------------------------- ------------------------------ --------------------------- -------------------------
Operating Income (Loss) 5,993 (6,281) (6,784)
Other Income and (Deductions), Net 15,551 26,295 20,557
- -------------------------------------------- ------------------------------ --------------------------- -------------------------
Earnings Before Interest and Taxes $ 21,544 $ 20,014 $ 13,773
- -------------------------------------------- ------------------------------ --------------------------- -------------------------
Overall, EBIT from these operations and investments in 2001 remained relatively
constant compared to 2000. EBIT growth from our investments in KeySpan Canada,
Northern Ireland and certain operations purchased as part of our acquisition of
Eastern were offset, in part, by losses incurred from certain technology-related
investments. Further, in the fourth quarter of 2000, we acquired the remaining
50% interest in KeySpan Canada, making us the sole owner. Results of operations
associated with KeySpan Canada are now fully consolidated, whereas prior to this
transaction, KeySpan Canada's results were reported as equity income in Other
Income and (Deductions).
EBIT from this segment increased by $6.2 million in 2000, compared to 1999,
reflecting earnings growth from our Canadian investments. Results of operations
from Canadian gas and oil operations were enhanced through the acquisition, in
the fourth quarter of 1999, of the Paddle River Gas Plant and certain oil
producing properties in Alberta, Canada, more efficient operations of KeySpan
Canada and the additional ownership interest in that company. Further, in the
fourth quarter of 2000, we sold our interest in the oil producing properties in
Alberta, Canada and recognized an after-tax gain of approximately $1.3 million
from the sale. In addition, Iroquois realized higher transportation sales
quantities and revenues from its interruptible customers in 2000 compared to
1999. Earnings from our investments in Northern Ireland in 2000 were essentially
the same as earnings for 1999. For much of 2000 and 1999, the subsidiaries in
this segment were primarily accounted for under the equity method since our
ownership interests were 50% or less. Accordingly, income from these investments
was reflected primarily in Other Income and (Deductions) in the Consolidated
Statement of Income.
We do not consider the businesses contained in the Energy Investments segment to
be part of our core asset group. We have stated in the past that we may sell or
otherwise dispose of all or a portion of our non-core assets. Except for the
sale of Midland Enterprises as previously discussed, we can not predict when, or
if, any such sale or disposition may take place, or the effect that any such
sale or disposition may have on our financial position, results of operations or
cash flows.
Allocated Costs
As previously mentioned, due to the acquisition of Eastern and ENI, we are
subject to the jurisdiction of the SEC under PUHCA. As part of the regulatory
provisions of PUHCA, the SEC regulates various transactions among affiliates
within a holding company system. In accordance with the regulations of PUHCA and
New York State Public Service Commission requirements, we have established
service companies that provide: (i) traditional corporate and administrative
services; (ii) gas and electric transmission and distribution systems planning,
marketing, and gas supply planning and procurement; and (iii) engineering and
surveying services to subsidiaries. Revised allocation methodologies, approved
by the SEC, have been used in 2001 to allocate service company costs to
affiliates. During 2000, certain costs were incurred by our corporate and
administrative subsidiaries that were not allocated to other operating segments,
and were not incurred in 2001. These unallocated costs had a significant effect
on comparative EBIT results and are as follows:(i) a charge of $10.0 million for
a contribution to the KeySpan Foundation; (ii) an impairment charge of $23.2
million associated with our equity investment in certain technology-related
activities; (iii) branding expenses and other costs related to the integration
of the Eastern and ENI companies of $24.6 million; and (iv) early retirement and
severance charges of $23.1 million. Item (i) is reflected in "Other Income and
Deductions" and all other items are reflected in "Operations and Maintenance
expense" in the Consolidated Statement of Income for 2000. Further, during 2001
we: (i) recorded the benefit associated with the favorable appellate court
decision regarding the class action settlement at our corporate holding company
level which increased EBIT by $22.0 million; and (ii) settled certain
outstanding issues associated with LIPA and reallocated certain administrative
costs which combined added $15.8 million to EBIT. The net result of the
preceding items contributed to the increase in EBIT of $137.0 million in 2001
associated with our non-operating subsidiaries. The 2000 charges described above
are also the major contributing factor to the $121.6 million decrease in EBIT
from these operations in 2000 compared to 1999.
Liquidity
Cash flow from operations continues to reflect strong results from our core
operations - gas distribution operations and electric operations, as well as
significant contributions from our gas exploration and production activities.
Further, the decrease in natural gas prices in the second half of 2001 also had
a positive impact on cash flow from operations. As a result of the seasonal
nature of our gas distribution operations, we incur significant cash
expenditures during the summer and early fall to purchase and inject gas into
our storage facilities. We recover these costs in subsequent periods as the gas
is removed from storage and delivered to our customers, primarily during the
winter, for space heating purposes. Significant cash flows are generated during
the first two quarters of the subsequent fiscal year as we receive payment from
customers for such heating season use. Due to the significant increase in gas
costs during the summer and early fall of 2000, gas cost recoveries for the
first two quarters of 2001 were greater than such recoveries for the same period
in 2000. Further, gas prices during the third and fourth quarters of 2001 were
lower than this time last year, resulting in lower cash expenditures required to
maintain natural gas inventory in storage. Also, as stated earlier, our gas
exploration and production activities benefitted from higher gas prices during
the first two quarters of 2001 compared to 2000. These enhancements to cash flow
were partially offset by an increase in interest payments due to higher levels
of outstanding debt.
The decrease in cash flow from operations in 2000 compared to 1999 reflects
working capital requirements primarily as a result of the rising price of
natural gas in the latter part of 2000, as previously mentioned. Cash flow from
operations also reflects a decrease in interest income, and an increase in
interest payments due to increased levels of outstanding debt. Further, in 1999
cash flow from operations reflects the cash utilization of a $57.4 million net
operating loss carryforward on income tax payments in 1999.
At December 31, 2001, we had cash and temporary cash investments of $159.3
million. During the year, we replaced two existing revolving credit facilities
of $700 million each, with one new credit facility which will continue to
support our $1.4 billion commercial paper program. Under this facility, our
consolidated indebtedness may not exceed 68% of our consolidated capitalization
at the end of any fiscal quarter. As of December 31, 2001, our consolidated
indebtedness was 66% of our consolidated capitalization. Violation of this
covenant could result in the termination of the credit facilities. At December
31, 2001, $1.0 billion of commercial paper was outstanding at a weighted average
annualized interest rate of 2.23% compared to $1.3 billion outstanding at
December 31, 2000. We had the ability to borrow up to an additional of $351.6
million at December 31, 2001 under the terms of our credit facility.
Houston Exploration has an unsecured line of credit with a commercial bank that
provides for a maximum commitment of $250 million, subject to a borrowing base
limitation of $250 million. During 2001, Houston Exploration borrowed $172
million under this facility and repaid $173 million; at December 31, 2001, $144
million remained outstanding at a weighted average annualized interest rate of
6.22%. At December 31, 2001, Houston Exploration had available borrowings of
$106 million.
Also, KeySpan Canada has two revolving loan agreements with financial
institutions in Canada. Borrowings under these agreements totaled $13.6 million
and repayments totaled $9.4 million in 2001. At December 31, 2001, approximately
$175 million was outstanding at a weighted average annualized interest rate of
5.03%. KeySpan Canada currently has available borrowings of approximately $29
million.
KeySpan has fully and unconditionally guaranteed $525 million of medium- term
notes issued by KEDLI under KEDLI's current shelf registration, as well as a
$125 million revolving credit agreement associated with its Canadian
subsidiaries. Both the medium- term notes and credit agreement are reflected on
the Consolidated Balance Sheet.
Further, KeySpan has: (i) guaranteed $191.0 million of surety bonds associated
with certain construction projects currently being performed by subsidiaries
within the Energy Services segment; (ii) guaranteed certain supply contracts,
hedging margin accounts and purchase orders for certain subsidiaries in the
aggregate amount of $83.2 million; and (iii) guaranteed the $425 million Master
Lease Agreement associated with the lease of the Ravenswood facility. These
guarantees are not on the Consolidated Balance Sheet. The guarantee on the
medium- term notes expires in 2010, while the other guarantees have terms that
do not extend beyond 2005; however the Master Lease Agreement can be extended to
2009. At this point in time, we have no reason to believe that our subsidiaries
will default on their current obligations. However, we can not predict when or
if any defaults may take place or the impact such defaults may have on our
consolidated results of operations, financial condition or cash flows. See Note
7 to the Consolidated Financial Statements "Long-Term Debt" for an explanation
of KEDLI's medium- term notes and the Canadian revolving credit facility. Also,
see the discussion of the Ravenswood lease under the heading "Financing".
We satisfy our seasonal working capital requirements primarily through
internally generated funds and the issuance of commercial paper. In addition, we
anticipate realizing approximately $165 million in proceeds from the sale of
Midland in 2002. We believe that these sources of funds are sufficient to meet
our seasonal working capital needs. Further, we use treasury stock to satisfy
the requirements of our employee common stock, dividend reinvestment and benefit
plans.
Capital Expenditures and Financing
Construction Expenditures
The table below sets forth our construction expenditures by operating segment
for the periods indicated:
(In Thousands of Dollars)
-------------------------
Year Ended Year Ended
December 31, 2001 December 31, 2000
- --------------------------------------------- ------------------------------ ------------------------------
Gas Distribution $ 384,323 $ 274,941
Electric Services 211,658 69,921
Energy Investments 437,976 270,187
Energy Services 17,292 17,362
Corporate Unallocated 8,510 624
- --------------------------------------------- ------------------------------ ------------------------------
$ 1,059,759 $ 633,035
- --------------------------------------------- ------------------------------ ------------------------------
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 on Long Island and in New England. Construction
expenditures for the Electric Services segment reflect primarily costs to
maintain our electric generating facilities as well as costs to expand the
Ravenswood facility and construct the new electric generating facilities as
previously noted. Construction expenditures related to the Energy Investments
segment primarily reflect costs associated with our gas exploration and
production activities. These costs are related to the development of properties
in Southern Louisiana and in the Gulf of Mexico. Expenditures also include
development costs associated with our joint venture with Houston Exploration, as
well as costs related to Canadian affiliates.
Construction expenditures for 2002 are estimated to be $1.2 billion, including
estimated expenditures for the construction of the new electric generating
facilities. 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
During 2001, we issued $500 million 6.15% Notes due June 1, 2006 under an
existing shelf registration statement, leaving $500 million available for
issuance at December 31, 2001. The proceeds from the issuance of these notes was
used to repay a portion of outstanding commercial paper. In February 2002, we
updated our shelf registration for the issuance of up to $1.2 billion of
additional securities, thereby giving us the ability to issue up to $1.7 billion
of debt, equity or various forms of preferred stock. Currently, we have the
authority under PUHCA to issue up to $1.0 billion of this amount. We have filed
an application with the SEC for additional authorization.
KEDLI also has an effective shelf registration statement on file with the SEC
for the issuance of up to $600 million of debt securities. During 2001, KEDLI
issued $125 million of medium term notes at 6.9% due January 15, 2008 and at
December 31, 2001 has $525 million outstanding under this shelf registration
statement, with $75 million available for issuance. The medium term notes issued
by KEDLI are fully and unconditionally guaranteed by KeySpan.
We will continue to evaluate our capital structure and financing strategy for
2002 and beyond. In order to take advantage of low cost debt opportunities
currently available and to finance the construction of our new electric power
plants and the Islander East pipeline, we are analyzing the feasibility of
engaging in various forms of financing transactions during 2002. Depending upon,
among other things, market conditions and the timing of our receipt of the
proceeds from the sale of Midland, our strategy may include the issuance of
traditional and/or alternative forms of debt or equity securities during 2002.
In any event, we believe that our current sources of funding (i.e., internally
generated funds 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 part of our strategy to increase the level of floating rate debt, in 2001 we
entered into several interest rate swap agreements on $1.3 billion of existing
fixed rate medium-term and long-term debt and effectively converted it to
floating rate debt. These swap agreements qualify for hedge accounting and were
completed with several major financial institutions to reduce credit risk.
Additionally, we entered into a swap agreement that effectively converts $270
million of outstanding commercial paper with fixed rate debt and also qualifies
for hedge accounting. (See Note 9 to the Consolidated Financial Statements
"Hedging, Derivative Financial Instruments, and Fair Values" for additional
information on these swap agreements.)
At December 31, 2001 our debt, including commercial paper, to total
capitalization was approximately 66%. As a registered holding company, we are
subject to certain financing restrictions. See the discussion under the heading
"Securities and Exchange Commission Regulation" for additional information on
these restrictions.
We also have an arrangement with a special purpose financing entity through
which we lease 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 relates to 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 are for
interest only. The lease qualifies as an operating lease for financial reporting
purposes while preserving our ownership of the facility for federal and state
income tax purposes.
The initial term of the lease expires on June 20, 2004 and may be extended until
June 20, 2009. In June 2004 , we have the right to either purchase the facility
or terminate the lease and dispose of the facility for an amount generally equal
to the original acquisition cost, $425 million, plus the present value of the
lease payments that would have otherwise been paid through June 20, 2009. In
June 2009, when the lease terminates, we may purchase the facility in an amount
generally equal to the original acquisition cost or surrender the facility to
the lessor. At this time, we believe that the fair market value of the leased
assets is well in excess of the original acquisition cost.
The Financial Accounting Standards Board (the "Board") is currently reviewing
issues related to special purpose entities. We anticipate that in April 2002,
the Board will issue for public comment interpretive guidance regarding
accounting for and disclosure of special purpose entities. We expect the final
guidance to be issued in the summer of 2002, and be effective January 1, 2003.
At this time, we are unable to determine the impact the final interpretive
guidance will have on our results of operations and financial position. (See
Note 8 to the Consolidated Financial Statements "Contractual Obligations and
Contingencies" for further details.)
The ratings on our long-term debt have remained unchanged from last year.
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+.
The table below reflects the maturity schedules for our contractual obligations:
(In Thousands of Dollars)
-------------------------
Contractual Less than 1
Obligations Total Year 1-3 Years 4-5 Years After 5 Years
- --------------------------- --------------------- ----------------- ------------------- ------------------ --------------------
Long-Term Debt $ 4,811,347 $ 339 $ 10,810 $ 1,227,333 $ 3,572,865
Capital Lease
Obligations 15,192 654 2,382 2,176 9,980
Operating Leases 633,313 - 261,953 165,441 205,919
- --------------------------- --------------------- ----------------- ------------------- ------------------- --------------------
Total Contractual
Cash Obligations $ 5,459,852 $ 993 $ 275,145 $ 1,394,950 $ 3,788,764
- --------------------------- --------------------- ----------------- ------------------- ------------------ --------------------
Commercial Paper (1) $ 1,048,450 Revolving - - -
- --------------------------- --------------------- ----------------- ------------------- ------------------ --------------------
(1) We have a $1.4 billion revolving credit facility that supports our
commercial paper program. This facility will expire in September 2002.
Traditionally we replace expired credit facilities with new facilities of
similar terms.
Discussions of Critical Accounting Policies and Assumptions
In preparing our financial statements, the application of certain accounting
policies requires difficult, subjective and/or complex judgements. The
circumstances that make these judgements difficult, subjective and/or complex
have to do with the need to make estimates about the impact of matters that are
inherently uncertain. Actual effects on our financial position and results of
operations may vary significantly from expected results if the judgements and
assumptions underlying our estimates prove to be inaccurate. The critical
accounting policies requiring such subjectivity are discussed below.
Percentage of Completion
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 design, building and installation of heating,
ventilation and air-conditioning systems by subsidiaries in our Energy Services
segment. This 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 made on 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. These changes in job performance, job conditions and estimated
profitability are recognized in the period the revisions are determined.
Valuation of Goodwill
We record goodwill on purchase transactions, representing the excess of
acquisition cost over the fair value of net assets acquired. In accordance with
the provisions of SFAS 121 "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed Of", the carrying value of goodwill is
to be reviewed if the facts and circumstances, such as significant declines in
sales, earnings or cash flows, or material adverse changes in the business
climate suggest that such goodwill might be impaired. If this review indicates
that goodwill is not recoverable, as determined based upon the estimated
undiscounted cash flows of the entity acquired, impairment would be measured by
comparing the carrying value of the investment in such entity to its fair value.
Fair value would be determined based on quoted market values, appraisals, or
discounted cash flows. For the year ended December 31, 2001, we reviewed the
facts and circumstances for the entities carrying goodwill and as a result of
the above procedures, wrote off $12.4 million associated with the Roy Kay
Companies upon determination that the asset was not recoverable. (See Note 11 to
the Consolidated Financial Statements "Roy Kay Operations" for more
information.)
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 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, as appropriate.
In testing for goodwill impairment under both SFAS 121 and SFAS 142, significant
reliance is placed upon estimated future cash flows. Cash flow estimates are
determined based upon our projected market conditions and demand for our
products and services. We are currently in the process of testing goodwill under
the revised discounted cash flow methodology prescribed by SFAS 142. A change in
the fair value measurement of our investments could cause a significant change
in the carrying value of goodwill. The results of this analysis is not complete
at this time, and we are unable to determine the impact this analysis may have
on our results of operations or financial condition.
Valuation of Derivative Instruments
From time to time, we employ derivative instruments to hedge a portion of our
exposure to commodity price risk and interest rate risk, as well as to fix the
selling price on a portion of our electric energy sales from the Ravenswood
facility. A number of our derivative instruments are exchange traded and,
accordingly, fair value measurements are generally based on standard New York
Mercantile Exchange ("NYMEX") quotes. However, the oil derivative instruments we
employ to hedge the purchase price on a portion of the oil used to fuel the
Ravenswood facility are not exchange traded. We use industry published oil
indices for No. 6 grade fuel oil to value these oil swap contracts. We have also
engaged in the use of derivative swap instruments to fix the selling price on a
portion of our electric energy sales from the Ravenswood facility. Further, we
have tolling arrangements under which we have "locked-in" a profit margin on a
portion of electric sales. These arrangements are also non-exchange traded and
we use NYISO-location zone published indices to value these outstanding
derivatives. For collar transactions relating to natural gas sales associated
with our gas exploration and production subsidiaries, we use standard NYMEX
quotes, as well as Black- Scholes valuations to calculate the fair value of
these instruments.
Finally, we also have interest rate swap agreements in which approximately $1.4
billion of fixed rate debt have been effectively converted to floating rate
debt. The fair values of these derivative instruments are provided to us by
third party appraisers and represent the present value of 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 can fluctuate significantly from period
to period. Except for derivative instruments related to firm gas sales to our
regulated gas sales customers and derivative instruments associated with gas
sales to certain large-volume gas sales customers, our current derivative
instruments qualify for hedge accounting under SFAS 133 "Accounting for
Derivative Instruments and Hedging Activities". (See Note 9 to the Consolidated
Financial Statements "Hedging, Derivative Financial Instruments and Fair Values"
for a further description of the instruments.)
Dividends
We are currently paying a dividend at an annual rate of $1.78 per common share.
Our dividend policy is reviewed annually by the Board of Directors. The amount
and timing of all dividend payments is subject to the discretion of the Board of
Directors and will depend upon business conditions, results of operations,
financial conditions and other factors. However, based on currently foreseeable
market conditions it is our intent to maintain the dividend at the $1.78 level.
Pursuant to New York Public Service Commission's ("NYPSC") orders, the ability
of KEDNY and KEDLI to pay dividends to the parent company is conditioned upon
maintenance of a utility capital structure with debt not exceeding 55% and 58%,
respectively, of total utility capitalization. In addition, the level of
dividends paid by both utilities may not be increased from current levels if a
40 basis point penalty is incurred under the customer service performance
program. At the end of KEDNY's and KEDLI's rate years (September 30, 2001 and
November 30, 2001, respectively), the ratio of debt to total utility
capitalization was 44% and 54%, respectively. Our corporate and financial
activities and those of each of our subsidiaries (including their ability to pay
dividends to us) are also subject to regulation by the SEC. For additional
information, see the discussion under the heading "Securities and Exchange
Commission Regulation" .
Regulation and Rate Matters
Gas Distribution
By orders dated February 5, 1998 and April 14, 1998 the NYPSC approved the
KeySpan / LILCO merger and established gas rates for both KEDNY and KEDLI.
Pursuant to the orders, $1 billion of efficiency savings, excluding gas costs,
attributable to operating synergies that are expected to be realized over the
ten-year period following the combination, were allocated to customers net of
transaction costs.
Effective May 29, 1998, KEDNY's base rates to core customers were reduced by
$23.9 million annually. In addition, KEDNY is subject to an earnings sharing
provision pursuant to which it will be required to credit core customers with
60% of any utility earnings up to 100 basis points above certain threshold
return on equity levels over the term of the rate plan (other than any earnings
associated with discrete incentives) and 50% of any utility earnings in excess
of 100 basis points above such threshold levels. The threshold levels are 13.50%
and 13.25% for the rate years ended September 30, 2001 and 2002, respectively.
KEDNY slightly exceeded the threshold return on equity for the rate year ended
September 30, 2001. On September 30, 2002, KEDNY's rate agreement with the NYPSC
will expire. Under the terms of the agreement, the then current gas distribution
rates and all other provisions, including the earnings sharing provision, will
remain in effect until changed by the NYPSC.
The orders also required KEDLI to reduce base rates to its customers by $12.2
million annually effective February 5, 1998 and by an additional $6.3 million
annually effective May 29, 1998. KEDLI is subject to an earnings sharing
provision pursuant to which it is required to credit to firm customers 60% of
any utility earnings in any rate year up to 100 basis points above a return on
equity of 11.10% and 50% of any utility earnings in excess of a return on equity
of 12.10%. KEDLI did not earn above its threshold return level in its rate year
ended November 30, 2001. On November 30, 2000, KEDLI's rate agreement with the
NYPSC expired. Under the terms of the agreement, the gas distribution rates and
all other provisions, including the earnings sharing provision, will remain in
effect until changed by the NYPSC. We expect current gas distribution rates for
our New York and Long Island based gas distribution utilities to remain in
effect through 2002.
Boston Gas Company, Colonial Gas Company, and Essex Gas Company operations are
subject to Massachusetts's statutes applicable to gas utilities. Rates for gas
sales and transportation service, distribution safety practices, issuance of
securities and affiliate transactions are regulated by the Massachusetts
Department of Telecommunications and Energy ("DTE"). Rates for transportation
service and gas sales are subject to approval by and are on file with the DTE.
Boston Gas Company's gas rates for local distribution service are governed by a
five-year performance- based rate plan approved by the DTE in 1996 (the "Plan").
Under the Plan, Boston Gas Company's rates for local distribution are
recalculated annually to reflect inflation for the previous 12 months, and
reduced by a productivity factor of 1%. The productivity factor has been the
subject of a remand proceeding at the DTE as discussed below. The Plan also
calls for penalties if Boston Gas Company fails to meet specified service
quality measures, with a maximum potential expense of $1 million, which has also
been a subject in the DTE's remand proceeding. There is a margin sharing
mechanism, whereby 25% of earnings in excess of a 15% return on equity are
passed back to customers. Similarly, ratepayers absorb 25% of any shortfall
below a 7% return on equity. Gas rates under the Plan are set to expire on
October 31, 2002. We have represented to the DTE that by April 1, 2002 we will
propose a new rate plan or an extension of the existing Plan.
With respect to the appeal by Boston Gas Company of the Plan, the Massachusetts
Supreme Judicial Court issued an order vacating: (i) the "accumulated
inefficiencies" component of the productivity factor, thereby reducing the
productivity factor from 1.50% to .50%; and (ii) the expansion of the service
quality penalty beyond $1 million, and remanded these matters to the DTE for
further proceedings, which actions were requested by the DTE in its motion for
discharge of report and remand.
On January 16, 2001, the DTE issued an order in the remand proceeding. The order
imposes a 0.5% accumulated inefficiencies factor, thereby increasing the
productivity factor from 0.5% to 1% and sets the maximum service quality
adjustment at $1 million. The order requires the accumulated inefficiencies
factor be implemented retroactively as of November 1, 1999. On January 30, 2001,
Boston Gas Company filed a Petition for Appeal and Motion for a Stay with the
Massachusetts Supreme Judicial Court, and on February 16, 2001, the court
granted the stay pending the appeal. On March 7, 2002, the Supreme Judicial
Court ruled in favor of Boston Gas Company and eliminated the accumulated
inefficiencies factor of 0.5%. During, the first quarter of 2002, we will
reverse a previously recorded loss provision of approximately $4.0 million
because of this favorable ruling.
In connection with Eastern Enterprises' acquisition of Colonial Gas Company in
1999, the DTE approved a merger and rate plan that resulted in a 2.2% reduction
in firm gas sales rates to Colonial Gas Company's firm customers for the first
full year following the merger. Also a ten-year freeze of base rates was also
ordered at that time. The base rate freeze is subject only to certain exogenous
factors, such as changes in tax laws, accounting changes, or regulatory,
judicial, or legislative changes. The Office of the Attorney General appealed
the DTE's order to the Supreme Judicial Court, which appeal is still pending.
Due to the length of the base rate freeze, Colonial Gas Company discontinued its
application of SFAS 71 "Accounting for the Effects of Certain Types of
Regulation".
Essex Gas Company is also under a ten-year base rate freeze and has also
discontinued its application of SFAS 71.
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 and ENI, provides us with, among other things, authorization to do
the following through December 31, 2003 (the "Authorization Period"): (a)
subject to an aggregate amount of $5.1 billion, (i) maintain existing financing
agreements, (ii) issue and sell up to $1.5 billion of additional securities in
compliance with certain defined parameters, (iii) issue additional guarantees
and other forms of credit support in an aggregate amount of $2.0 billion at any
time in addition to any such securities, guarantees and credit support
outstanding or existing as of November 8, 2000, and (iv) amend, review, extend,
supplement or replace any of the foregoing; (b) issue shares of common stock or
reissue shares of common stock held in treasury under dividend reinvestment and
stock-based management incentive and employee benefit plans; (c) maintain
existing and enter into additional hedging transactions with respect to
outstanding indebtedness in order to manage and minimize interest rate costs;
(d) invest up to 250% of our consolidated retained earnings in exempt wholesale
generators and foreign utility companies; and (e) pay dividends out of capital
and unearned surplus as well as paid-in-capital with respect to certain
subsidiaries, subject to certain limitations.
In addition, we have committed that during the Authorization Period, our common
equity will be at least 30% of our consolidated capitalization and each of our
utility subsidiaries' common equity will be at least 30% of such entity's
capitalization. At December 31, 2001 our consolidated common equity was 34% of
our consolidated capitalization, including commercial paper.
Electric Services - Revenue Mechanisms
LIPA Agreements
KeySpan, through certain of its subsidiaries, provides services to LIPA under
the following agreements:
Management Services Agreement ("MSA")
A KeySpan subsidiary manages the day-to-day operations, maintenance and capital
improvements of the T&D system. LIPA exercises control over the performance of
the T&D system through specific standards for performance and incentives. In
exchange for providing the services, we earn a $10 million annual management fee
and are operating under an eight-year contract which provides certain incentives
and imposes certain penalties based upon performance. We have reached an
agreement in principle with LIPA to extended the MSA for 30 months, as discussed
under the heading "Generation Purchase Right Agreement" below. Annual service
incentives or penalties exist under the MSA if certain targets are achieved or
not achieved. In addition, we can earn certain incentives for cost reductions
associated with the day-to-day operations, maintenance and capital improvements
of LIPA's T&D system. These incentives provide for us to (i) retain 100% of cost
reductions on the first $5 million in reductions, and (ii) retain 50% of
additional cost reductions up to 15% of the total cost budget, thereafter all
savings will accrue to LIPA. With respect to cost overruns, we will absorb the
first $15 million of overruns, with a sharing of overruns above $15 million.
There are certain limitations on the amount of cost sharing of overruns. To
date, we have performed our obligations under the MSA within the agreed upon
budget guidelines and we are committed to providing on-going services to LIPA
within the established cost structure. However, no assurances can be given as to
future operating results under this agreement.
Power Supply Agreement ("PSA")
A KeySpan subsidiary sells to LIPA all of the capacity and, to the extent
requested, energy from our existing Long Island based oil and gas-fired
generating plants. Sales of capacity and energy are made under rates approved by
the FERC. The rates may be modified in the future in accordance with the terms
of the PSA for (i) agreed upon labor and expense indices applied to the base
year, (ii) a return of and on net capital additions required for the generating
facilities, and (iii) reasonably incurred expenses that are outside our control.
Rates charged to LIPA include a fixed and variable component. The variable
component is billed to LIPA on a monthly basis and is dependent on the number of
megawatt hours dispatched. LIPA has no obligation to purchase energy from us and
is able to purchase energy on a least-cost basis from all available sources
consistent with existing interconnection limitations of the T&D system. We must,
therefore, operate our generating facilities in a manner such that we can remain
competitive with other producers of energy. To date, we have dispatched to LIPA
and LIPA has accepted the level of energy generated at the agreed to price per
megawatt hour. However, no assurances can be given as to the level and price of
energy to be dispatched to LIPA in the future. The PSA provides incentives and
penalties that can total $4 million annually for the maintenance of the output
capability of the generating facilities. The PSA runs for a term of fifteen
years.
Energy Management Agreement ("EMA")
The EMA provides for a KeySpan subsidiary to procure and manage fuel supplies
for LIPA to fuel the generating facilities under contract to it and perform
off-system capacity and energy purchases on a least-cost basis to meet LIPA's
needs. In exchange for these services we earn an annual fee of $1.5 million. In
addition, we arrange for off-system sales on behalf of LIPA of excess output
from the generating facilities and other power supplies either owned or under
contract to LIPA. LIPA is entitled to two-thirds of the profit from any
off-system energy sales. In addition, the EMA provides incentives and penalties
that can total $7 million annually for performance related to fuel purchases and
off-system power purchases. The EMA covers a period of fifteen years for the
procurement of fuel supplies and eight years for off-system management services.
Under the agreements, we are required to obtain a letter of credit in the
aggregate amount of $60 million supporting our obligations to provide the
various services if our long-term debt is not rated investment grade by a
nationally recognized rating agency.
Generation Purchase Right Agreement ("GPRA")
Under the 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 at fair market
value at the time of the exercise of such right. On March 11, 2002, LIPA and
KeySpan announced that they had reached an agreement in principle to extend
LIPA's option under the GPRA for three years.
The agreement in principle establishes a new option window commencing November
2004 and closing May 2005. Under the agreement, LIPA retains the right to
exercise the option to purchase KeySpan's on-island generation assets under the
terms of the original GPRA. In return for providing LIPA an extension of the
GPRA, KeySpan has been provided with a corresponding extension of 30 months for
the MSA.
The extension is the result of a new initiative established by LIPA to work with
KeySpan and others to review Long Island's long-term energy needs. LIPA and
KeySpan will jointly analyze new energy supply options including re-powering
existing plants, renewable energy technologies, distributed generation,
conservation initiatives and retail competition.
The extension allows both LIPA and KeySpan to explore alternatives to the GPRA
including re- powering existing facilities, the sale of some or all of KeySpan's
plants to LIPA, or the sale of some or all of these plants to other private
operators.
Ravenswood Facility
At the time of our purchase of the Ravenswood facility, KeySpan and Consolidated
Edison entered into transition energy and capacity contracts. The energy
contract provided Consolidated Edison with 100% of the energy produced by the
Ravenswood facility and covered a period of time from the date of closing, June
18, 1999, through November 18, 1999. With the start-up of the NYISO, the
electricity market in New York City began a transition to a competitive market
for capacity, energy and ancillary services. Starting on November 18, 1999, we
began selling the energy produced by the Ravenswood facility through bidding
into the NYISO energy markets on a day ahead or real time basis. We also have
the option to enter into bilateral transactions to sell all or a portion of the
energy produced by the Ravenswood facility to Load Serving Entities ("LSE"),
i.e. entities that sell to end-users or to brokers and marketers. At this point
in time, we have sold energy exclusively through the NYISO. The capacity
contract, which provided Consolidated Edison with 100% of the available capacity
of the Ravenswood facility expired on April 30, 2000. Since that date, the
available capacity of the Ravenswood facility has been bid into the auction
process conducted by the NYISO.
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 $215.1 million and
we have recorded a related liability for such amount. We have also recorded an
additional $42.5 million liability representing the estimated environmental
cleanup costs related to a coal tar processing facility formerly owned by
Eastern. As of December 31, 2001, we have expended a total of $44.5 million
associated with environmental clean-up activities. During 2001, we performed an
analysis of our potential environmental liabilities and accordingly adjusted our
liabilities for the remaining cost on a number of our environmental sites. The
adjustments associated with our New York based gas distribution operations were
deferred, pursuant to current NYPSC orders, while the increases associated with
our New England operations were either recorded as an adjustment to goodwill or
were deferred as appropriate for each company. (See Note 8 to the Consolidated
Financial Statements, "Contractual Obligations and Contingencies" for a further
explanation of these matters.)
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are subject to various risk exposures and uncertainties associated with our
operations. The most significant contingency involves the evolution of the gas
distribution and electric industries towards more competitive and deregulated
environments. In addition, we are exposed to commodity price risk, interest rate
risk and, to less of a degree, foreign currency risk. Set forth below is a
description of these exposures and an explanation as to how we have managed and,
to the extent possible, sought to reduce these risks.
Regulatory Issues and the Competitive Environment
The Gas Industry
Long Island and New York
The NYPSC's December 26, 2000 Order Establishing Interim Rate Plan (the "Interim
Agreement") provided, among other things, that marketers receive an incentive
payment equal to 8% of the delivery charges they incurred to serve firm
customers to encourage marketers to provide gas commodity sales to customers.
The Interim Agreement and incentive payment expired on June 30, 2001. The
Interim Agreement also provided that the parties resume negotiations on issues
that were not resolved, including daily balancing, a migration program for
cooking-only customers, a low income customer aggregation program, and a back
out credit to be applied to rates charged to customers who migrate to a
non-utility energy supplier. We continue to discuss these remaining issues with
a number of interested parties.
The NYPSC also continues to conduct collaborative proceedings on ways to develop
the competitive energy market in New York. On July 13, 2001, the presiding
officers in the case issued their recommended decision ("RD"). The RD recommends
that the NYPSC adopt an end state vision that includes removing the utilities
from the provision of the energy (gas and electric) commodity. The RD also
recommends that utilities exit the commodity function only where there is a
workably competitive market. The RD states that the only market that is
currently workably competitive is the commodity market for non-residential
large- use gas customers. Parties filed briefs on and opposing exceptions to the
RD. An order in this proceeding is pending.
In a separate phase of this case, the parties have discussed preparation of
embedded cost of service studies by all gas and electric utilities in New York.
The NYPSC has ordered the utilities to prepare abbreviated embedded cost of
service studies and to file unbundled rates reflecting the results of those
studies. KEDNY's and KEDLI's studies must be filed by May 15, 2002. Tariffs
implementing unbundled rates must be filed by June 1, 2002 to be effective
August 30, 2002.
We are unable, at this time, to predict the outcome of these proceedings or what
effect, if any, they will have on our financial condition, results of operations
or cash flows. Moreover, as a result of circumstances in 2001, including the
California energy crisis and the bankruptcy of Enron Corp., state regulators
around the country are reassessing the pace of movement toward deregulation. We
are unable to predict the outcome or pace of this trend or its ultimate effect
on our results of operation, financial condition or cash flows.
New England
In July 1997, the DTE directed Massachusetts gas distribution companies to
undertake a collaborative process with other stakeholders to develop common
principles under which comprehensive gas service unbundling might proceed. A
settlement agreement by the Local Distribution Company's ("LDC's") and the
marketer group regarding model terms and conditions for unbundled transportation
service was approved by the DTE in November 1998. In February 1999, the DTE
issued its order on how unbundling of natural gas service will proceed. For a
five year transition period, the DTE determined that LDC contractual commitments
to upstream capacity will be assigned on a mandatory, pro rata basis to
marketers selling gas supply to the LDC's customers. The approved mandatory
assignment method eliminates the possibility that the costs of upstream capacity
purchased by the LDCs to serve firm customers will be absorbed by the LDC or
other customers through the transition period. The DTE also found that, through
the transition period, LDCs will retain primary responsibility for upstream
capacity planning and procurement to assure that adequate capacity is available
to support customer requirements and growth. The DTE approved the LDCs Terms and
Conditions of Distribution Service that conform to the settled upon model terms
and conditions. Since November 1, 2000, all Massachusetts gas customers have the
option to purchase their gas supplies from third party sources other than the
LDCs. Further, the New Hampshire Public Utility Commission required gas
utilities to offer transportation services to all commercial and residential
customers starting November 1, 2001.
We believe that the actions described above strike a balance among competing
stakeholder interests in order to most effectively make available the benefits
of the unbundled gas supply market to all customers.
The Electric Industry - Long Island and New York City
As previously mentioned, our electric operations on Long Island are generally
governed by service agreements with LIPA. The agreements have varying terms and
generally provide for recovery of virtually all costs of production, operation
and maintenance. Although additional generating capacity and transmission
interconnections for Long Island are in various stages of development, at this
time, we face minimal competitive pressures associated with our electric
operations on Long Island.
With our investment in the Ravenswood facility, we also have electric operations
in New York City. We currently sell the energy produced by the Ravenswood
facility, as well as its capacity and ancillary services, through bidding into
the NYISO energy markets. 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. We expect that the current local reliability rules will
remain in effect at least through October 31, 2002. A total of over 500 MW of
additional generating capacity was either placed in service or attained through
improved generating facility operations over the past year. The majority of this
additional capacity was placed in service by the New York Power Authority. At
this time, we anticipate that we can continue to sell a significant portion of
the capacity of the Ravenswood facility. However, should new, more efficient
electric power plants be built in New York City, the requirement that 80% of
in-city load be served by in-city generators be modified, and/or the
availability of the Ravenswood facility deteriorate, then capacity and energy
sales volumes could be adversely affected. We cannot predict, however, when or
if new power plants will be built or the nature of future New York City
requirements.
Regional Transmission Organizations and Market Design
During 2001, FERC issued several orders and began several proceedings related to
the development of the Regional Transmission Organizations ("RTO") and the
design of the wholesale energy markets. The details of how the RTO will be
formed and how the markets would develop are not yet known. We do not know 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 flows.
New York Independent System Operator Matters
The Ravenswood facility currently sells its capacity, energy and ancillary
services through bidding into the NYISO energy markets at FERC approved market
based rates. Capacity is the capability to generate electrical power and is
measured in megawatts (MW). Energy is a quantity of electricity that is produced
over a period of time and is measured in megawatt hours (MWh). Ancillary
services include 10-minute spinning and non-spinning reserves available to
replace energy that is unable to be delivered due to the unexpected loss of a
major energy source.
As a condition of FERC's approval of the Ravenswood facility's market based rate
authority, it is subject to certain mitigation measures associated with the sale
of its capacity, energy and ancillary services. There have been various filings
at FERC concerning the various market mitigation measures.
One of the most significant mitigation measures has been with regard to in-city
local mitigation measures that impose a bid and price cap on the Ravenswood
facility's capacity sales and the day ahead energy bid cap. FERC has ordered the
NYISO to make a comprehensive filing proposing a coordinated set of mitigation
measures to be effective May 1, 2002. The NYISO is in the process of developing
mitigation measures to be applied to the real-time market, as well as the day
ahead market. Mitigation measures are also being developed to apply to all
existing and planned New York City generation.
Based on availability data for a 12-month period, the bid and price cap for
in-city unforced capacity was set at $112.95 per kW-year. Ravenswood and other
in-city generation owners requested rehearing of FERC's order claiming that the
translation of the bid and price cap based solely on a brief 12-month time
period was inaccurate. The rehearing request was denied on February 13, 2002.
There have also been proceedings regarding mitigation measures concerning
ancillary services. On November 8, 2001, FERC denied various rehearing requests
related to the sale of 10 minute non-spinning reserves during the months from
January through March 2000 and held that refunds related to these reserves would
not be required during this period. On December 10, 2001, the NYISO filed a
rehearing request with FERC related to its November 8th decision, claiming that:
(i) FERC's decision was based on new grounds that were not included in FERC's
May 31, 2000 Order on Tariff Filing and Complaints; and (ii) that FERC had
erroneously concluded that the NYISO had raised a new issue when it proposed a
means for determining just and reasonable rates.
Additionally, the NYISO, Consolidated Edison, Rochester Gas and Electric
Corporation ("RGEC") and Niagara Mohawk Power Corporation ("NMPC") each appealed
the November 8th FERC order to the United States Court of Appeals for the
District of Columbia. Consolidated Edison, RGEC and the NMPC appeals were
consolidated. We requested that the NYISO appeals and the consolidated appeal be
dismissed, or in the alternative, that the appeals be held in abeyance until
FERC acts upon the NYISO's December 10th request for rehearing. A decision on
these matters is still pending.
It is not known to what extent these proceedings may impact the Ravenswood
facility's financial condition, results of operations or cash flows.
Derivative Financial Instruments
Commodity Contracts and Electric Derivative Instruments: From time to time we
utilize derivative financial instruments, such as futures, options and swaps,
for the purpose of hedging exposure to commodity price risk and to fix the
selling price on a portion of our peak electric energy sales.
Houston Exploration utilizes collars, as well as, over- the- counter ("OTC")
swaps to hedge future sales prices on a portion of its natural gas production to
achieve a more predictable cash flow and reduce its exposure to adverse price
fluctuations of natural gas. For any particular collar transaction, the counter
party is required to make a payment to Houston Exploration if the settlement
price for any settlement period is below the floor price for such transaction,
and Houston Exploration is required to make payment to the counter party if the
settlement price for any settlement period is above the ceiling price for such
transaction. In the swap instruments, Houston Exploration will pay the amount by
which the floating variable price (settlement price) exceeds the fixed price and
receive the amount by which the settlement price is below the fixed price. As of
December 31, 2001, Houston Exploration has hedged approximately 59% of its
estimated 2002 yearly production and 14% of its estimated 2003 yearly
production. Houston Exploration uses standard New York Mercantile Exchange
("NYMEX") futures prices and published volatility in its Black-Scholes
calculation to value its outstanding derivatives. Houston Exploration recorded a
benefit of $12.9 million in Revenues for derivative instruments that settled
during 2001.
We also employ standard NYMEX gas futures contracts, as well as oil swap
derivative contracts to fix the purchase price for a portion of the fuel used at
the Ravenswood facility. For these instruments, we will pay the amount by which
the floating variable price (settlement price) is below the fixed price and
receive the amount by which the settlement price exceeds the fixed price. We use
standard NYMEX futures prices to value the gas futures contracts and industry
published oil indices for number 6 grade fuel oil to value the oil swap
contracts. These contracts extend through 2003. During 2001, we realized a gain
of $5.9 million on the settlement of derivative instruments and recorded this
gain as a decrease to Fuel and Purchased Power expense.
Our gas and electric marketing subsidiary has fixed rate gas sales contracts and
utilizes standard NYMEX futures contracts to lock-in a price for future natural
gas purchases. For these contracts, we pay the amount by which the floating
variable price (settlement price) is below the fixed price and receive the
amount by which the settlement price exceeds the fixed price. This subsidiary
uses standard NYMEX futures prices to value its outstanding contracts. During
2001, we realized a gain of $10.2 million on derivatives that settled during
2001 and recorded this gain as a reduction to Purchased Gas for Resale.
We have also engaged in the use of derivative swap instruments to fix the
selling price on a portion of our estimated 2002 summer and winter peak electric
energy sales from the Ravenswood facility to protect against a potential
degradation in market prices. Under these swap agreements, we will receive
from a counter party a fixed price per megawatt hour of electricity sold during
certain peak hours and pay the counter party the then current floating market
price for peak electric supply. We will receive the then current floating market
price of peak electric energy when the Ravenswood facility sells electric energy
to the NYISO. We also have tolling arrangements with two counter parties under
which we have "locked-in" a profit margin on a portion of 2002 summer and winter
season sales. Under these arrangements, we will receive from counter parties a
fixed margin and will then pay the counter party, on a monthly basis, a variable
profit margin from the sale of electric energy. As a result of these hedging
arrangements, we have hedged approximately 13% of our estimated 2002 yearly
electric sales. We have a stated hedging policy that we will not hedge more than
50% of our daily peak sales. We use NYISO-location zone published indices and
standard NYMEX prices to value these outstanding derivatives. During 2001, we
realized a gain of $13.6 million on the settlement of certain swap derivative
instruments and recorded this gain in Revenues.
We adopted SFAS 133 "Accounting for Derivative Instruments and Hedging
Activities" on January 1, 2001. All of our commodity contracts and electric
derivative instruments detailed above are cash- flow hedges and qualify for
hedge accounting. Periodic changes in market value of derivatives which meet the
definition of a cash-flow hedge are recorded as comprehensive income, subject to
effectiveness, and then included in net income to match the underlying hedged
transactions. The adoption of SFAS 133, and the associated effectiveness
testing, did not have a significant effect on the results of operations for
2001.
The following tables set forth selected financial data associated with these
derivative financial instruments noted above that were outstanding at December
31, 2001.
Year of Volumes Fixed Current Fair Value
Type of Contract Maturity mmcf Floor $ Ceiling $ Price $ Price $ ($000)
- --------------------------- ------------- ----------- ----------- ------------ ---------------- ---------------- ------------
Gas
Collars 2002 51,100 3.64 5.36 - 2.56 - 3.22 50,731
Swaps -Short Natural Gas 2002 10,950 - - 3.01 2.56 - 3.22 2,926
2003 14,600 - - 3.19 3.18 113
Swaps - Long Natural Gas 2002 8,880 - - 2.96 - 3.93 2.56 - 3.22 (5,733)
2003 1,570 - - 3.36 - 3.64 3.12 - 3.41 (350)
- --------------------------- ------------- ----------- ----------- ------------ ---------------- ---------------- ------------
87,100 47,687
- --------------------------- ------------- ----------- ----------- ------------ ---------------- ---------------- ------------
Year of Volumes Fair Value
Type of Contract Maturity Barrels Fixed Price $ Current Price $ ($000)
- ----------------------------- --------------- ----------------- ------------------- ------------------------ ------------------
Oil
Swaps - Long Fuel Oil 2002 384,043 20.09 - 29.38 21.22 - 22.72 (776)
2003 225,686 21.01 - 26.72 21.32 -21.81 (274)
- ----------------------------- --------------- ----------------- ------------------- ------------------------ ------------------
609,729 (1,050)
- ----------------------------- --------------- ----------------- ------------------- ------------------------ ------------------
Year of Current Estimated Fair Value
Type of Contract Maturity MWh Fixed Margin /Price $ Price $ Margin $ ($000)
- ----------------------- ---------------- ------------- ------------------------ ------------- ---------------- ---------------
Electricity
Tolling Arrangements 2002 576,000 10.00 - 26.00 - 3.94 - 10.13 7,640
Swaps 2002 67,200 54.50 42.35 - 820
- ----------------------- ---------------- ------------- ------------------------ ------------- ---------------- ---------------
643,200 8,460
- ----------------------- ---------------- ------------- ------------------------ ------------- ---------------- ---------------
Non-firm Gas Sales Derivative Instruments: Utility tariffs applicable to certain
large-volume customers permit gas to be sold at prices established monthly
within a specified range expressed as a percentage of prevailing alternate fuel
oil prices. We use gas swap contracts, with offsetting positions in oil swap
contracts of equivalent energy value, with third parties to fix profit margins
on specified portions of gas sales to our large-volume market. These derivatives
instruments, at this time, do not meet the "effectiveness standards" as
prescribed by SFAS 133 and accordingly do not qualify for hedge accounting.
Therefore, changes in the market value of these derivatives are included in
income currently. During 2001, we realized gains of $3.0 million on the
settlement of certain contracts, as well as, $1.9 million in mark-to-market
gains, and recorded these gains as a reduction to Purchased Gas for Resale. We
use standard NYMEX futures prices to value both the gas and No. 2 grade heating
oil swap contracts.
The following table sets forth selected financial data associated with these
derivative financial instruments that were outstanding at December 31, 2001.
Year of Volumes Volumes Fair Value
Type of Contract Maturity mmcf Barrels Fixed Price $ Current Price $ ($000)
- ------------------------------ ------------ -------------- -------------- ---------------- ------------------- ---------------
Swaps - Long Natural Gas 2002 770 - 3.11 - 3.81 2.56 - 2.57 (1,535)
Swaps - Short Heating Oil 2002 - 448,000 29.42 - 33.15 23.18 - 23.24 3,505
- ------------------------------ ------------ -------------- -------------- ---------------- ------------------- ---------------
770 448,000 1,970
- ------------------------------ ------------ -------------- -------------- ---------------- ------------------- ---------------
Firm Gas Sales Derivative Instruments - Regulated Utilities: We utilize
derivative financial instruments to "lock-in" the purchase price for a portion
of our future natural gas purchases. Our strategy is to minimize fluctuations in
firm gas sales prices to our regulated firm gas sales customers in our New York
service territory. During 2001, we entered into a number of derivative
instruments such as, collars, purchased calls, transformer calls and variable
premium contracts. Since these derivative instruments have not been designed as
hedges and are being 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 are
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. We use standard NYMEX futures prices to value these
instruments.
The following table sets forth selected financial data associated with these
derivative financial instruments that were outstanding at December 31, 2001.
Year of Volumes Fair Value
Type of Contract Maturity mmcf Floor $ Ceiling $ Fixed Price $ Current Price $ ($000)
- ----------------------- ------------- ----------- ------------- -------------- ---------------- ----------------- -----------
Gas
Collars 2002 1,800 4.55 - 5.43 5.70 - 6.20 - 2.56 - 2.57 (4,370)
Call Options 2002 3,900 - - 4.00 - 5.60 2.56 - 2.57 (3,878)
Variable Premiums 2002 2,400 - - 3.90 - 6.00 2.56 - 2.57 (2,604)
- ----------------------- ------------- ----------- ------------- -------------- ---------------- ----------------- -----------
8,100 (10,852)
- ----------------------- ------------- ----------- ------------- -------------- ---------------- ----------------- -----------
Interest Rate Swaps: We also have interest rate swap agreements in which
approximately $1.4 billion of fixed rate debt have effectively been changed to
floating rate debt. These swaps extend through 2023, but can be terminated
earlier based on certain market and contract conditions. We have entered into
these derivative instruments with a number of major financial institutions to
reduce credit risk. For the term of the agreements, we will receive the fixed
coupon rate associated with these bonds and pay the counter parties a variable
interest rate that is reset on a weekly and/or quarterly basis as appropriate.
These bonds are fair- value hedges and qualify for hedge accounting. The swap
agreements associated with the Medium Term Notes, as displayed in the table
below, qualify for "short-cut" hedge accounting treatment under SFAS 133. Under
this method, changes in the fair values of the swap instruments are recorded
directly against the hedged bonds and have no impact on earnings. These swaps
were entered into in October 2001. The fair-value hedge associated with a Gas
Facilities Revenue Bond, which was entered into in 1999, does not qualify for
"short-cut" accounting treatment. As a result, the fair values of both the bond
and swap instrument are measured at least quarterly and the net change in the
fair values from period to period are recorded in income. Through the
utilization of our interest rate swap agreements, we reduced recorded interest
expense by $9.5 million in 2001. Further, we recorded, a benefit of $0.5 million
as a result of the fair value measurements. The fair values of these derivative
instruments are provided to us by third party appraisers and represent the
present value of future cash- flows based on a forward interest rate curve for
the life of the derivative instrument. The fair values at December 31, 2001, as
indicated in the table below, reflects an assumption of higher interest rates in
the future.
The table below summarizes selected financial data associated with these
derivative financial instruments that were outstanding at December 31, 2001.
Average
Maturity Date of Notional Amount Fixed Rate Variable Rate Fair Value
Bond Swaps ($000) Received Paid ($000)
- ------------------------------- ------------------ ------------------- ---------------- ------------------ -------------------
Gas Facilities Revenue Bonds 2024 90,000 5.540% 2.650% 136
Medium Term Notes 2010 500,000 7.625% 4.600% (21,921)
Medium Term Notes 2006 500,000 6.150% 3.900% (11,567)
Medium Term Notes 2023 270,000 8.200% 4.020% (13,794)
- ------------------------------- ------------------ ------------------- ---------------- ------------------ -------------------
1,360,000 (47,146)
- ------------------------------- ------------------ ------------------- ---------------- ------------------ -------------------
Additionally, in November 2001, we entered into a swap agreement that
effectively converted $270 million of outstanding commercial paper with
fixed-rate debt. This swap is a cash-flow hedge and qualifies for hedge
accounting under SFAS 133. Periodic changes in the market value of this swap are
recorded as comprehensive income, subject to effectiveness, and then included in
net income to match the underlying hedged transactions. We recorded additional
interest expense associated with this swap of $0.3 million during 2001 and there
was no impact on earnings from ineffectiveness. At December 31, 2001, the fair
value of this swap, which was reflected as a liability, was $0.4 million.
Weather Derivative: The utility tariffs associated with our New England gas
distribution operations do not contain a weather normalization adjustment. As a
result, fluctuations from normal weather may have a significant positive or
negative effect on the results of these operations. To mitigate the effect of
fluctuations from normal weather on our financial position and cash flows, we
entered into a weather swap in October 2001. This derivative hedged
approximately 15% of our weather related risk for the November 2001 - March 2002
winter season. Since weather in New England was warmer than normal in the fourth
quarter of 2001, we recorded a gain of $1.4 million in Other Income in 2001.
Although weather derivatives are outside the scope of SFAS 133, these
derivatives are essentially marked to market, at least quarterly, with changes
in fair valve included in earnings currently. In January 2002, we settled all
our remaining weather derivatives and recorded a gain of $0.3 million in Other
Income.
We are exposed to credit risk in the event of nonperformance by counter parties
to derivative contracts, as well as nonperformance by the counter parties of the
transactions hedged against. We believe that the credit risk related to the
above noted contracts is no greater than that associated with the primary
contracts which they hedge, as these contracts are with major investment grade
financial institutions, and that elimination of the price risk lowers overall
business risk.
Foreign Currency Fluctuations
We follow the principles of SFAS 52, "Foreign Currency Translation" for
recording our investments in foreign affiliates. Due to our purchases of certain
Canadian interests and our continued activities in Northern Ireland, our
investment in foreign affiliates has been growing. At December 31, 2001, the net
assets of these affiliates was approximately $360.0 million and at December 31,
2001, the accumulated after-tax foreign currency translation included in
Accumulated Other Comprehensive Income was a debit of $9.6 million. (See Note 1
to the Consolidated Financial Statements, "Summary of Significant Accounting
Policies.")
Item 8. Financial Statements and Supplementary Data
CONSOLIDATED BALANCE SHEET
(In Thousands of Dollars)
December 31, 2001 December 31, 2000
- -----------------------------------------------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash and temporary cash investments $ 159,252 $ 83,329
Customer accounts receivable 1,344,898 1,759,628
Allowance for uncollectible accounts (72,299) (48,314)
Gas in storage, at average cost 334,999 282,654
Materials and supplies, at average cost 105,693 114,663
Other 125,944 139,185
-------------------------- --------------------------
1,998,487 2,331,145
-------------------------- --------------------------
Investment Held for Disposal 191,055 184,036
Equity Investments and Other 223,249 199,196
Property
Gas 5,704,857 5,346,799
Electric 1,629,768 1,412,839
Other 400,643 402,600
Accumulated depreciation (2,533,466) (2,297,842)
Gas exploration, production and refining 2,200,851 1,781,379
Accumulated depletion (796,722) (615,799)
-------------------------- --------------------------
6,605,931 6,029,976
-------------------------- --------------------------
Deferred Charges
Regulatory assets 458,191 385,116
Goodwill, net of amortization 1,782,826 1,829,070
Other 529,867 348,926
-------------------------- --------------------------
2,770,884 2,563,112
-------------------------- --------------------------
-------------------------- --------------------------
Total Assets $ 11,789,606 $ 11,307,465
========================== ==========================
See accompanying Notes to the Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEET
(In Thousands of Dollars)
December 31, 2001 December 31, 2000
- ------------------------------------------------------------------------------------------------------------------------------------
LIABILITIES AND CAPITALIZATION
Current Liabilities
Current redemption of long-term debt $ 993 $ 1,500
Accounts payable and accrued expenses 1,091,430 1,464,684
Commercial paper 1,048,450 1,300,237
Dividends payable 63,442 62,218
Taxes accrued 50,281 73,199
Customer deposits 36,151 32,855
Interest accrued 93,962 69,402
---------------------------- ------------------------
2,384,709 3,004,095
---------------------------- ------------------------
Deferred Credits and Other Liabilities
Regulatory liabilities 39,442 40,041
Deferred income tax 598,072 374,580
Postretirement benefits and other reserves 694,680 602,954
Other 207,992 127,393
---------------------------- ------------------------
1,540,186 1,144,968
---------------------------- ------------------------
Capitalization
Common stock 2,995,797 2,985,022
Retained earnings 452,206 480,639
Accumulated other comprehensive income 4,483 825
Treasury stock purchased (561,884) (650,670)
---------------------------- ------------------------
Total common shareholders' equity 2,890,602 2,815,816
Preferred stock 84,077 84,205
Long-term debt 4,697,649 4,116,441
---------------------------- ------------------------
Total Capitalization 7,672,328 7,016,462
---------------------------- ------------------------
Minority Interest in Subsidiary Companies 192,383 141,940
---------------------------- ------------------------
Total Liabilities and Capitalization $ 11,789,606 $ 11,307,465
============================ ========================
See accompanying Notes to the Consolidated Financial Statements.
CONSOLIDATED STATEMENT OF INCOME
(In Thousands of Dollars, Except Per Share Amounts)
---------------------------------------------------
Year Ended Year Ended Year Ended
December 31, 2001 December 31, 2000 December 31, 1999
- --------------------------------------------------------------------------------- ------------------------ -----------------------
Revenues
Gas Distribution $ 3,613,551 $ 2,555,785 $ 1,753,132
Electric Services 1,421,079 1,444,711 861,582
Energy Services 1,100,167 770,110 186,529
Gas Exploration and Production 400,031 274,209 150,581
Energy Investments 98,287 35,887 2,789
------------------ ------------------ -----------------
Total Revenues 6,633,115 5,080,702 2,954,613
------------------ ------------------ -----------------
Operating Expenses
Purchased gas for resale 2,171,113 1,408,680 744,432
Fuel and purchased power 538,532 460,841 17,252
Operations and maintenance 2,114,759 1,659,736 1,091,166
Early retirement and severance charges - 65,175 -
Depreciation, depletion and amortization 559,138 330,922 253,440
Operating taxes 448,924 421,936 366,154
------------------ ------------------ -----------------
Total Operating Expenses 5,832,466 4,347,290 2,472,444
------------------ ------------------ -----------------
Operating Income 800,649 733,412 482,169
------------------ ------------------ -----------------
Other Income and (Deductions)
Income from equity investments 13,129 20,010 15,347
Interest income 8,326 12,327 26,993
Minority interest (40,847) (26,342) (11,141)
Other 26,598 (18,081) 15,356
------------------ ------------------ -----------------
Total Other Income and (Deductions) 7,206 (12,086) 46,555
------------------ ------------------ -----------------
Income Before Interest Charges
and Income Taxes 807,855 721,326 528,724
------------------ ------------------ -----------------
Interest Charges 353,470 201,314 133,751
------------------ ------------------ -----------------
Income Taxes
Current 101,738 170,809 26,618
Deferred 108,955 46,453 109,744
------------------ ------------------ -----------------
Total Income Taxes 210,693 217,262 136,362
------------------ ------------------ -----------------
Net Income 243,692 302,750 258,611
Preferred Stock Dividend Requirements 5,904 18,113 34,752
------------------ ------------------ -----------------
Earnings from Continuing Operations 237,788 284,637 223,859
------------------ ------------------ -----------------
Discontinued Operations
Income from operations, net of tax 10,918 (1,943) -
Loss on disposal, net of tax (30,356) - -
------------------ ------------------ -----------------
Loss from Discontinued Operations (19,438) (1,943) -
------------------ ------------------ -----------------
Earnings for Common Stock $ 218,350 $ 282,694 $ 223,859
================== ================== =================
Basic Earnings Per Share from Continuing Operations 1.72 2.12 1.62
Basic Loss Per Share from Discontinued Operations (0.14) (0.02) -
------------------ ------------------ -----------------
Basic Earnings Per Share $ 1.58 $ 2.10 $ 1.62
================== ================== =================
Diluted Earnings Per Share $ 1.56 $ 2.09 $ 1.62
================== ================== =================
Average Common Shares Outstanding (000) 138,214 134,357 138,526
Average Common Shares Outstanding - Diluted (000) 139,221 135,165 138,552
See accompanying Notes to the Consolidated Financial Statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
(In Thousands of Dollars)
-------------------------
Year Ended Year Ended Year Ended
December 31, 2001 December 31, 2000 December 31, 1999
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income from continuing operations $ 243,692 $ 302,750 $ 258,611
Adjustments to reconcile net income to net
cash provided by (used in) operating activities
Depreciation, depletion and amortization 559,138 330,922 253,440
Early retirement and severance accruals - 65,175 -
Deferred income tax 108,955 46,453 109,744
Income from equity investments (13,129) (20,010) (15,347)
Dividends from equity investments 7,570 21,507 9,368
Gain from class action settlement (33,510) - -
Provision for losses on contracting business 63,682 - -
Changes in assets and liabilities
Accounts receivable 401,976 (800,033) (132,114)
Materials and supplies, fuel oil and gas in storage (43,856) (36,952) (9,789)
Accounts payable and accrued expenses (425,196) 452,076 83,493
Interest accrued 24,560 32,659 8,128
Other (3,701) 44,179 23,471
----------------- ----------------- ------------------
Net Cash Provided by Operating Activities 890,181 438,726 589,005
----------------- ----------------- ------------------
Investing Activities
Construction expenditures (1,059,759) (633,035) (671,845)
Other investments - (292,222) (53,825)
Acquisition of Eastern Enterprise and EnergyNorth, Inc. - (1,762,007) -
Investment held for disposal - (184,036) -
Proceeds from sale of assets 18,458 - -
Other (6) (510) 30,006
------------------ ---------------- ------------------
Net Cash (Used in) by Investing Activities (1,041,307) (2,871,810) (695,664)
----------------- ----------------- ------------------
Financing Activities
Treasury stock issued (purchased) 88,786 72,289 (299,243)
Issuance of long-term debt 812,116 2,166,955 102,648
Payment of long-term debt (183,410) (68,365) (442,475)
Issuance (payment) of commercial paper (251,787) 935,372 208,300
Payment of preferred stock - (363,000) -
Preferred stock dividends paid (5,904) (20,261) (34,760)
Common stock dividends paid (245,598) (239,740) (249,567)
Settlement on interest rate lock - (59,490) -
Other 12,846 (35,949) 7,582
----------------- ----------------- ------------------
Net Cash Provided by (Used in) Financing Activities 227,049 2,387,811 (707,515)
----------------- ----------------- ------------------
Net Increase or (Decrease) in Cash and Cash Equivalents $ 75,923 $ (45,273) $ (814,174)
================= ================= ==================
Cash and Cash Equivalents at Beginning of Period $ 83,329 $ 128,602 $ 942,776
Net Increase or (Decrease) in Cash and Cash Equivalents 75,923 (45,273) (814,174)
------------------ ----------------- ------------------
Cash and Cash Equivalents at End of Period $ 159,252 $ 83,329 $ 128,602
================= ================= ==================
Interest paid $ 328,910 $ 165,020 $ 109,614
Income tax paid $ 128,558 $ 187,219 $ 38,700
See accompanying Notes to the Consolidated Financial Statements.
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
(In Thousands of Dollars)
-------------------------
Year Ended Year Ended Year Ended
December 31, 2001 December 31, 2000 December 31, 1999
- ------------------------------------------------ -------------------------- ------------------------- ---------------------------
Balance at Beginning of Period $ 480,639 $ 456,882 $ 474,188
Net Income for period 224,254 300,807 258,611
- ------------------------------------------------ -------------------------- ------------------------- ---------------------------
704,893 757,689 732,799
Deductions:
Cash dividends declared on common stock 246,783 239,740 246,251
Cash dividends declared on preferred stock 5,904 20,298 34,752
Other, primarily write-off of
capital stock expense - 17,012 (5,086)
- ------------------------------------------------ -------------------------- ------------------------- ---------------------------
Balance at End of Period $ 452,206 $ 480,639 $ 456,882
- ------------------------------------------------ -------------------------- ------------------------- ---------------------------
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(In Thousands of Dollars)
-------------------------
Year Ended Year Ended Year Ended
December 31, 2001 December 31, 2000 December 31, 1999
- ---------------------------------------------------------- ------------------------- --------------------- ---------------------
Net Income $ 224,254 $ 300,807 $ 258,611
- ---------------------------------------------------------- ------------------------- --------------------- ---------------------
Other comprehensive income (loss), net of tax
Net gains on derivative instruments (27,690) - -
Reclassification adjustment for other gains
reclassified to net income (3,242) - -
Foreign currency translation adjustments (9,627) (7,320) 5,633
Unrealized gains (losses) on marketable securities (5,464) 3,131 -
Accrued unfunded pension obligation (13,262) - -
Unrealized gains on derivative
financial instruments 62,943 - -
- ---------------------------------------------------------- ------------------------- --------------------- ---------------------
Other comprehensive income (loss) 3,658 (4,189) 5,633
- ---------------------------------------------------------- ------------------------- --------------------- ---------------------
Comprehensive income $ 227,912 $ 296,618 $ 264,244
- ---------------------------------------------------------- ------------------------- --------------------- ---------------------
Related tax (benefit) expense
Net gains on derivative instruments $ (14,910) $ - $ -
Reclassification adjustment for other gains
reclassified to net income (1,746) - -
Foreign currency translation adjustments (5,184) (3,941) 3,033
Unrealized gains (losses) on marketable securities (2,942) 1,686 -
Accrued unfunded pension obligation (7,140) - -
Unrealized gains on derivative financial instruments 33,892 - -
- ---------------------------------------------------------- ------------------------- --------------------- ---------------------
Total tax expense (benefit) $ 1,970 $ (2,255) $ 3,033
- ---------------------------------------------------------- ------------------------- --------------------- ---------------------
See accompanying Notes to the Consolidated Financial Statements.
CONSOLIDATED STATEMENT OF CAPITALIZATION
- -----------------------------------------------------------------------------------------------------------------------------------
Shares Issued (In Thousands of Dollars)
- ------------------------------------------------ -----------------------------------------------------------------------------------
December 31, December 31, December 31, December 31,
2001 2000 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
Common Shareholders' Equity
Common stock, $0.01 par value 158,837,654 158,837,654 $ 1,588 $ 1,588
Premium on capital stock 2,994,209 2,983,434
Retained earnings 452,206 480,639
Other comprehensive income 4,483 825
Treasury stock 19,407,905 22,474,628 (561,884) (650,670)
- -----------------------------------------------------------------------------------------------------------------------------------
Total Common Shareholders' Equity 139,429,749 136,363,026 2,890,602 2,815,816
- -----------------------------------------------------------------------------------------------------------------------------------
Preferred Stock - No Redemption Required
Par Value $100 per share
7.07% Series B-private placement 553,000 553,000 55,300 55,300
7.17% Series C-private placement 197,000 197,000 19,700 19,700
6.00% Series A-private placement 90,770 92,050 9,077 9,205
- -----------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - No Redemption Required 84,077 84,205
- -----------------------------------------------------------------------------------------------------------------------------------
Long - Term Debt Interest Rate Maturity
- -----------------------------------------------------------------------------------------------------------------------------------
Notes
Medium term notes 6.15% - 9.75% 2005-2030 2,885,000 2,260,000
Senior subordinated notes 8.625% 2008 100,000 100,000
- -----------------------------------------------------------------------------------------------------------------------------------
Total Notes 2,985,000 2,360,000
- -----------------------------------------------------------------------------------------------------------------------------------
Gas Facilities Revenue Bonds Variable 2020 125,000 125,000
5.50% - 6.95% 2020-2026 523,500 523,500
- -----------------------------------------------------------------------------------------------------------------------------------
Total Gas Facilities Revenue Bonds 648,500 648,500
- -----------------------------------------------------------------------------------------------------------------------------------
Promissory Notes to LIPA
Debentures 8.20% 2023 270,000 270,000
Pollution control revenue bonds 5.15% 2016 108,022 108,022
Electric facilities revenue bonds 5.30% - 7.15% 2019-2025 224,405 224,405
- -----------------------------------------------------------------------------------------------------------------------------------
Total Promissory Notes to LIPA 602,427 602,427
- -----------------------------------------------------------------------------------------------------------------------------------
First Mortgage Bonds 5.50% - 10.10% 2002-2028 179,122 179,872
Authority Financing Notes Variable 2027-2028 66,005 66,005
Other Subsidiary Debt 330,293 328,227
Capital Leases 2004-2020 15,192 16,001
- -----------------------------------------------------------------------------------------------------------------------------------
Subtotal 4,826,539 4,201,032
Unamortized interest rate hedge and debt discount (80,173) (83,091)
Derivative impact on debt (47,724) -
Less current maturities 993 1,500
- -----------------------------------------------------------------------------------------------------------------------------------
Total Long Term Debt 4,697,649 4,116,441
- -----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 7,672,328 $ 7,016,462
- -----------------------------------------------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
Notes to the Consolidated Financial Statements
Note 1. Summary of Significant Accounting Policies
A. Organization of the Company
KeySpan Corporation, a New York corporation, was formed in May 1998, as a result
of the business combination of KeySpan Energy Corporation, the parent of The
Brooklyn Union Gas Company, and certain businesses of the Long Island Lighting
Company ("LILCO"). On November 8, 2000, we acquired Eastern Enterprises
("Eastern"), a Massachusetts business trust, and the parent of several gas
utilities operating in Massachusetts. Also on November 8, 2000, Eastern acquired
EnergyNorth, Inc. ("ENI"), the parent of a gas utility operating in central New
Hampshire. KeySpan Corporation will be referred to in these notes to the
Consolidated Financial Statements as "KeySpan", "we", "us" and "our."
Our core business is gas distribution, conducted by our six regulated gas
utility subsidiaries: The Brooklyn Union Gas Company d/b/a KeySpan Energy
Delivery New York ("KEDNY") and KeySpan Gas East Corporation d/b/a KeySpan
Energy Delivery Long Island ("KEDLI") distribute gas to customers in the
boroughs of Brooklyn, Queens and Staten Island in New York City, and the
counties of Nassau and Suffolk on Long Island and the Rockaway Peninsula in
Queens, respectively; Boston Gas Company, Colonial Gas Company and Essex Gas
Company, each doing business as KeySpan Energy Delivery New England ("KEDNE"),
distribute gas to customers in southern and central Massachusetts; and
EnergyNorth Natural Gas, Inc., d/b/a KeySpan Energy Delivery New England
distributes gas to customers in central New Hampshire. Together, these companies
distribute gas to approximately 2.5 million customers throughout the Northeast.
We also own, lease and operate generating plants on Long Island and in New York
City. Under contractual arrangements, we provide power, electric transmission
and distribution services, billing and other customer services for approximately
one million electric customers of the Long Island Power Authority ("LIPA").
Our other subsidiaries are involved in gas and oil exploration and production;
gas storage; wholesale and retail gas and electric marketing; appliance service;
heating, ventilation and air conditioning installation and services; large
energy-system ownership, installation and management; and fiber optic services.
We also invest in, and participate in the development of, pipelines and other
energy-related projects, domestically and internationally. (See Note 2,
"Business Segments" for additional information on each operating segment.)
We are a registered holding company under the Public Utility Holding Company Act
of 1935 ("PUHCA"), as amended. Therefore, our corporate and financial activities
and those of our subsidiaries, including their ability to pay dividends to us,
are subject to regulation by the Securities and Exchange Commission ("SEC").
Under our holding company structure, we have no independent operations or source
of income of our own and conduct all of our operations through our subsidiaries
and, as a result, we depend on the earnings and cash flow of, and dividends or
distributions from, our subsidiaries to provide the funds necessary to meet our
debt and contractual obligations. Furthermore, a substantial portion of our
consolidated assets, earnings and cash flow is derived from the operations of
our regulated utility subsidiaries, whose legal authority to pay dividends or
make other distributions to us is subject to regulation by state regulatory
authorities.
B. Basis of Presentation
The Consolidated Financial Statements presented herein reflect the accounts of
KeySpan and its subsidiaries. Most of our subsidiaries are fully consolidated in
the financial information presented, except for certain subsidiary investments
in the Energy Investment segment which are accounted for on the equity method as
we do not have a controlling voting interest or otherwise have control over the
management of such investee companies. All significant intercompany transactions
have been eliminated.
Certain reclassifications were made to conform prior period financial statements
with the current period financial statement presentation.
As noted, on November 8, 2000, we completed the acquisitions of Eastern
Enterprises and EnergyNorth Inc. The transactions have been accounted for using
the purchase method of accounting for business combinations and accordingly the
accompanying consolidated financial statements include the results of Eastern
and ENI for the period November 8, 2000 through December 31, 2001.
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
C. Accounting for the Effects of Rate Regulation
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 electric generation subsidiaries are not subject to state rate
regulation, but they are subject to Federal Energy Regulatory Commission
("FERC") regulation. Our financial statements reflect the ratemaking policies
and actions 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.) and our Long Island based electric generation
subsidiaries 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 ability of regulators, through the
ratemaking process, to create future economic benefits and obligations affecting
rate-regulated companies. Accordingly, we record these future economic benefits
and obligations as regulatory assets and regulatory liabilities, respectively.
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.
The following table presents our net regulatory assets at December 31, 2001 and
December 31, 2000.
(In Thousands of Dollars)
-------------------------
December 31, 2001 December 31, 2000
- ----------------------------------------------------------- ------------------------------- --------------------------------
Regulatory Assets
Regulatory tax asset $ 64,536 $ 61,071
Property taxes 54,617 51,948
Environmental costs 183,716 116,609
Postretirement benefits other than pensions 84,238 89,188
Costs associated with the KeySpan / LILCO merger 55,204 66,300
Derivative assets 15,880* -
- ----------------------------------------------------------- ------------------------------- --------------------------------
Total Regulatory Assets $ 458,191 $ 385,116
Regulatory Liabilities 39,442 40,041
- ----------------------------------------------------------- ------------------------------- --------------------------------
Net Regulatory Assets $ 418,749 $ 345,075
=========================================================== =============================== ================================
* Includes derivative instruments that settled in December 2001 for $5.0 million
associated with January 2002 gas purchases.
The regulatory assets above are not included in our rate base. However, we
record carrying charges on the property tax and costs associated with the
KeySpan / LILCO merger deferrals. We also record carrying charges on our
regulatory liabilities. The remaining regulatory assets represent, primarily,
costs for which expenditures have not yet been made, and therefore, carrying
charges are not recorded. We anticipate recovering these costs in our gas rates
concurrently with future cash expenditures. If recovery is not concurrent with
the cash expenditures, we will record the appropriate level of carrying charges.
Deferred gas costs of $5.6 million and $189.8 million at December 31, 2001 and
December 31, 2000, respectively are reflected in Accounts Receivable on the
Consolidated Balance Sheet.
We estimate that full recovery of our regulatory assets will not exceed 15
years, except for the regulatory tax asset which will be recovered over the
estimated lives of certain utility property.
Rate regulation is undergoing significant change as regulators and customers
seek lower prices for utility service and greater competition among energy
service providers. In the event that regulation significantly changes the
opportunity for us to recover costs in the future, all or a portion of our
regulated operations may no longer meet the criteria for the application of SFAS
71. In that event, a write-down of all or a portion of our existing regulatory
assets and liabilities could result. If we were unable to continue to apply the
provisions of SFAS 71 for any of our rate regulated subsidiaries, we would have
applied the provisions of SFAS 101 "Regulated Enterprises - Accounting for the
Discontinuation of Application of FASB Statement No. 71." We estimate that the
write-off of all our net regulatory assets at December 31, 2001 could result in
a charge to net income of $272.2 million or $1.97 per share, which would be
classified as an extraordinary item. In management's opinion, our regulated
subsidiaries that are currently subject to the provisions of SFAS 71 will
continue to be subject to SFAS 71 for the foreseeable future.
D. Revenues
Utility gas customers are billed monthly or bi-monthly on a cycle basis.
Revenues include unbilled amounts related to the estimated gas usage that
occurred from the most recent meter reading to the end of each month.
The cost of gas used is recovered when billed to firm customers through the
operation of gas adjustment clauses ("GAC") included in utility tariffs. The GAC
provision requires a periodic reconciliation of recoverable gas costs and GAC
revenues. Any difference is deferred pending recovery from or refund to firm
customers. Further, net revenues from tariff gas balancing services, off-system
sales and certain on-system interruptible sales are refunded, for the most part,
to firm customers subject to certain sharing provisions.
The New York and Long Island gas utility tariffs contain weather normalization
adjustments that largely offset shortfalls or excesses of firm net revenues
(revenues less gas costs and revenue taxes) during a heating season due to
variations from normal weather. The New England gas utility rate structures
contain no weather normalization feature, therefore their net revenues are
subject to weather related demand fluctuations.
Electric revenues are derived from billings to the Long Island Power Authority
("LIPA") for management of LIPA's transmission and distribution ("T&D") system,
electric generation, and procurement of fuel. The agreements with LIPA include
provisions for us to earn, in the aggregate, approximately $11.5 million per
year (plus up to an additional $5 million per year if certain cost savings are
achieved) in annual management service fees from LIPA for the management of the
LIPA T&D system and the management of all aspects of fuel and power supply.
Under a Management Service Agreement ("MSA") costs in excess of budgeted levels
are assumed by us up to $15 million, while cost reductions in excess of $5
million from budgeted levels are shared with LIPA. These agreements also contain
certain non-cost incentive and penalty provisions which could impact earnings.
Billings associated with generation capacity are based on pre-determined levels
of supply to be dispatched to LIPA on a yearly basis. Rates billed to LIPA on a
monthly basis include fixed and variable components. Billings related to
transmission, distribution and delivery services are based, in part, on
negotiated estimated levels.
In addition, electric revenues are derived from our investment in the 2,200
megawatt Ravenswood electric generation facility ("Ravenswood facility"), which
we acquired in June 1999. (See Note 8 "Contractual Obligations and
Contingencies" for a description of the Ravenswood transaction.)
We realize revenues from our investment in the Ravenswood facility through the
wholesale sale of energy, capacity, and ancillary services to the New York
Independent System Operator ("NYISO"). Energy and ancillary services are sold
through a bidding process into the NYISO energy markets on a day ahead or real
time basis.
Prior to the start of the NYISO on November 19, 1999, however, KeySpan and the
Consolidated Edison Company of New York, Inc. ("Consolidated Edison") entered
into transition energy and capacity contracts. The energy contract provided
Consolidated Edison with 100% of the energy produced by the Ravenswood facility
on a cost recovery basis. This contract expired on November 19, 1999. The
capacity contract provided Consolidated Edison with 100% of the available
capacity of the Ravenswood facility on a monthly fixed-fee basis. That contract
expired on April 30, 2000.
Revenues earned by our Energy Services segment for the design, building and
installation of heating, ventilation and air-conditioning systems are generally
recognized by the percentage of completion method. This method measures the
percentage of costs incurred and accrued to date for each contract to the
estimated total costs for each contract at completion. 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 may result in revisions to cost and income, which are recognized
in the period the revisions are determined. Service and maintenance revenues are
recognized as earned or over the life of the service contract, as appropriate.
Energy sales are recorded upon delivery of the related commodity and
telecommunications revenue is recognized upon delivery of service access.
E. Utility Property - Depreciation and Maintenance
Utility gas property is stated at original cost of construction, which includes
allocations of overheads, including taxes, and an allowance for funds used
during construction. Electric depreciation consists of depreciation of our
electric generating facilities, including the Ravenswood facility from June 19,
1999.
Depreciation is provided on a straight-line basis in amounts equivalent to
composite rates on average depreciable property. The cost of property retired,
plus the cost of removal less salvage, is charged to accumulated depreciation.
The cost of repair and minor replacement and renewal of property is charged to
maintenance expense. The composite rates on average depreciable property were as
follows:
Period Electric Gas
------ -------- ---
Year Ended December 31, 2001 3.78% 3.40%
Year Ended December 31, 2000 3.68% 3.51%
Year Ended December 31, 1999 3.56% 2.85%
F. Gas Exploration and Production Property - Depletion
The full cost method of accounting is used for our investments in natural gas
and oil properties. These investments consist of our 67% equity interest in The
Houston Exploration Company ("Houston Exploration"), an independent natural gas
and oil exploration company, as well as KeySpan Exploration and Production, LLC,
our wholly-owned subsidiary engaged in a joint venture with Houston Exploration.
Under the full cost method, all costs of acquisition, exploration and
development of natural gas and oil reserves are capitalized into a "full cost
pool" as incurred, and properties in the pool are depleted and charged to
operations using the unit-of-production method based on production and proved
reserve quantities. To the extent that such capitalized costs (net of
accumulated depletion) less deferred taxes exceed the present value (using a 10%
discount rate) of estimated future net cash flows from proved natural gas and
oil reserves and the lower of cost or fair value of unproved properties, such
excess costs are charged to operations. If a write-down is required, it would
result in a charge to earnings but would not have an impact on cash flows. Once
incurred, such impairment of gas properties is not reversible at a later date
even if gas prices increase.
The ceiling test is calculated using natural gas and oil prices in effect as of
the balance sheet date, held flat over the life of the reserves. We use
derivative financial instruments that qualify for hedge accounting under SFAS
133 "Accounting for Derivative Instruments and Hedging Activities", to hedge
against the volatility of natural gas prices. In accordance with current
Securities and Exchange Commission guidelines, we have included estimated future
cash flows from our hedging program in the ceiling test calculation. In
calculating the ceiling test at December 31, 2001, we estimated, using a
wellhead price of $2.38 per mcf, that our capitalized costs exceeded the ceiling
limitation. As a result, in the fourth quarter of 2001, we recorded a $42.0
million impairment charge to write-down our gas exploration and production
assets, and recorded this charge in Depreciation, Depletion and Amortization on
the Consolidated Statement of Income. Our share of the impairment charge was
$26.2 million after-tax, or $0.19 per share. Natural gas prices continue to be
volatile and the risk that we will be required to write-down our full cost pool
increases when, among other things, natural gas prices are depressed, we have
significant downward revisions in our estimated proved reserves or we have
unsuccessful drilling results.
G. Goodwill
At December 31, 2001, we had recorded goodwill in the amount of $1.8 billion,
representing the excess of acquisition cost over the fair value of net assets
acquired. Our recorded goodwill, net of accumulated amortization, consists of
$1.5 billion related to the Eastern and ENI acquisitions, $156 million related
to the KeySpan / LILCO merger, and $169 million related to the acquisitions of
energy- related services companies and to certain ownership interests of 50% or
less in energy-related investments in Northern Ireland which are accounted for
under the equity method. For the year ended December 31, 2001, goodwill
amortization was $62 million.
As prescribed by SFAS 121 "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed Of", the carrying value of goodwill is
reviewed if the facts and circumstances, such as significant declines in sales,
earnings or cash flows, or material adverse changes in the business climate
suggest it might be impaired. If this review indicates that goodwill is not
recoverable, as determined based upon the estimated undiscounted cash flows of
the entity acquired, impairment would be measured by comparing the carrying
value of the investment in such entity to its fair value. Fair value would be
determined based on quoted market values, appraisals, or discounted cash flows.
For the year ended December 31, 2001, we reviewed the facts and circumstances
for the entities carrying goodwill and as a result of the above procedures,
wrote off $12.4 million associated with the Roy Kay Companies upon determination
that the asset was not recoverable. (See note 11, "Roy Kay Operations" for
additional information.)
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. The results of
this analysis is not complete at this time, and we are unable to determine the
impact this analysis may have on our results of operations or financial
condition. However, a change in the measurement of the fair value of our
investments could result in a significant change in the carrying value of
goodwill.
H. Hedging and Derivative Financial Instruments
From time to time we employ derivative instruments to hedge a portion of our
exposure to commodity price risk and interest rate risk, as well as to fix the
selling price on a portion of our peak electric energy sales. Whenever hedge
positions are in effect, we are exposed to credit risk in the event of
nonperformance by counter parties to derivative contracts, as well as
nonperformance by the counter parties of the transactions against which they are
hedged. We believe that the credit risk related to the futures, options and swap
instruments is no greater than that associated with the primary commodity
contracts which they hedge. We have a stated policy that we enter into
derivative contracts only with major investment grade financial institutions,
and we believe that reduction of the exposure to price risk lowers our overall
business risk.
Commodity Contracts and Electric Derivatives: We employ derivative financial
instruments, such as futures, options and swaps, for the purpose of hedging
exposure to commodity price risk and to fix the selling price on a portion of
our peak electric energy sales. We also utilize derivative instruments to
"lock-in" profit margin on a number of fixed- rate gas sales contracts. These
derivative instruments are cash-flow hedges and qualify for hedge accounting
under SFAS 133. Under SFAS 133, periodic changes in market value of cash-flow
hedges are recorded as comprehensive income, subject to effectiveness, and
subsequently included in net income to match the underlying transactions.
Non-firm Gas Sales Derivatives: Further, we employ derivative instruments to fix
profit margins on specific portions of gas sales to our large-volume gas sales
market. These derivative instruments do not qualify for hedge accounting at this
time, since they do not meet the "effectiveness standards" prescribed by SFAS
133. Accordingly, changes in market value of these derivatives are included in
income currently.
Firm Gas Sales Derivatives: We utilize derivative financial instruments to
"lock-in" the purchase price for a portion of our future natural gas purchases.
Our strategy is to minimize fluctuations in firm gas sales prices to our
regulated firm gas sales customers in our New York service territory. Since
these derivative instruments are being 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 are recorded as a Regulatory Asset or Regulatory Liability on
our 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.
Weather Derivatives: The utility tariffs associated with our New England gas
distribution operations do not contain a weather normalization adjustment. As a
result, fluctuations from normal weather may have a significant positive or
negative effect on the results of these operations. To mitigate the effect of
fluctuations from normal weather on our financial position and cash flows, we
may enter into weather swaps from time to time. Although weather derivatives are
outside the scope of SFAS 133, such instruments are essentially marked to market
currently.
Interest Rate Derivatives: We continually assess the cost relationship between
fixed and variable rate debt. In line with our objective to minimize capital
costs, we periodically enter into hedging transactions that effectively convert
the terms of underlying debt obligations from fixed to variable or variable to
fixed. Payments made or received on these derivative contracts are recognized as
an adjustment to interest expense as incurred. Hedging transactions that
effectively convert the terms of underlying debt obligations from fixed to
variable are considered fair-value hedges. Hedging transactions that effectively
convert the terms of underlying debt obligations from variable to fixed are
considered cash-flow hedges.
I. Equity Investments
Certain subsidiaries own as their principal assets investments, including
goodwill, representing ownership interests of 50% or less in energy-related
businesses that are accounted for under the equity method.
J. Income Tax
In accordance with SFAS 109, "Accounting for Income Taxes" and applicable rate
regulation, certain of our regulated subsidiaries record a regulatory asset for
the net cumulative effect of providing deferred income taxes on all differences
between the financial statement carrying amounts of existing assets and
liabilities, and their respective tax basis. Investment tax credits, which were
available prior to the Tax Reform Act of 1986, were deferred and are generally
amortized as a reduction of income tax over the estimated lives of the related
property.
K. Subsidiary Common Stock Issuances to Third Parties
We follow an accounting policy of income statement recognition for parent
company gains or losses from issuances of common stock by subsidiaries to
unaffiliated third parties.
L. Foreign Currency Translation
We follow the principles of SFAS 52, "Foreign Currency Translation," for
recording our investments in foreign affiliates. Under this statement, all
elements of the financial statements are translated by using a current exchange
rate.
Translation adjustments result from changes in exchange rates from one reporting
period to another. At December 31, 2001, the foreign currency translation
adjustment was included in Accumulated Other Comprehensive Income as a separate
component of Shareholders' Equity. The functional currency for our foreign
affiliates is their local currency.
M. Earnings Per Share
Basic earnings per share ("EPS") is calculated by dividing earnings 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 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 2.2 million options outstanding at December 31, 2001 that
were not used in the calculation of diluted EPS since the exercise price
associated with these options was greater than the average per share market
price of our common stock. (See Note 6 "Stock Options", for further information
on outstanding options.) 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 also not included in the calculation of diluted EPS since to
do so would have been anti-dilutive.
Under the requirements of SFAS 128, "Earnings Per Share" our basic and diluted
EPS are as follows:
(In Thousands of Dollars, Except Per Share)
-------------------------------------------
Year Ended Year Ended Year Ended
December 31, December 31, December 31,
2001 2000 1999
- ------------------------------------------------------------------- ----------------- ----------------- -----------------------
Earnings for common stock $ 218,350 $ 282,694 $ 223,859
Houston Exploration dilution (options) (1,116) (725) (135)
- ------------------------------------------------------------------- ----------------- ----------------- -----------------------
Earnings for common stock - adjusted $ 217,234 $ 281,969 $ 223,724
- ------------------------------------------------------------------- ----------------- ----------------- -----------------------
Weighted average shares outstanding (000) 138,214 134,357 138,526
Add dilutive securities:
Options 1,007 808 26
- ------------------------------------------------------------------- ----------------- ----------------- -----------------------
Total weighted average shares outstanding - assuming dilution 139,221 135,165 138,552
- ------------------------------------------------------------------- ----------------- ----------------- -----------------------
Basic Earnings Per Share $ 1.58 $ 2.10 $ 1.62
- ------------------------------------------------------------------- ----------------- ----------------- -----------------------
Diluted Earnings Per Share $ 1.56 $ 2.09 $ 1.62
- ------------------------------------------------------------------- ----------------- ----------------- -----------------------
N. Recent Accounting Pronouncements
In June of 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
143, "Accounting for Asset Retirement Obligations". The Standard requires
entities to record the fair value of a liability for an asset retirement
obligation in the period in which it is incurred. When the liability is
initially recorded, the entity will capitalize a cost by increasing the carrying
amount of the related long-lived asset. Over time, the liability is accreted to
its then present value, and the capitalized cost is depreciated over the useful
life of the related asset.
Upon settlement of the liability, an entity either settles the obligation for
its recorded amount or incurs a gain or loss upon settlement. The standard is
effective for fiscal years beginning after June 15, 2002, with earlier
application encouraged. We are currently evaluating the impact, if any, that the
Statement may have on our results of operations and financial condition.
SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," is
effective January 1, 2002, and addresses accounting and reporting for the
impairment or disposal of long-lived assets. SFAS 144 supersedes SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long- Lived Assets
to Be Disposed Of" and APB Opinion No. 30, "Reporting the Results of Operations-
Reporting the Effects of Disposal of a Segment of a Business." SFAS 144 retains
the fundamental provisions of SFAS 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. We currently do not
anticipate that implementation of this Statement will have a significant effect
on our results of operations and financial condition.
Note 2. Business Segments
We have four reportable segments: Gas Distribution, Electric Services, Energy
Services and Energy Investments.
The Gas Distribution segment consists of our six gas distribution subsidiaries.
KeySpan Energy Delivery New York ("KEDNY") provides gas distribution services to
customers in the New York City Boroughs of Brooklyn, Queens and Staten Island.
KeySpan Energy Delivery Long Island ("KEDLI") provides gas distribution services
to customers in the Long Island Counties of Nassau and Suffolk and the Rockaway
Peninsula of Queens County. The remaining gas distribution subsidiaries, Boston
Gas Company, Colonial Gas Company, Essex Gas Company and EnergyNorth Natural
Gas, Inc., collectively referred to as KeySpan Energy Delivery New England
("KEDNE"), provide gas distribution service to customers in Massachusetts and
New Hampshire.
The Electric Services segment consists of subsidiaries that: operate the
electric transmission and distribution system owned by LIPA; own and provide
capacity to and produce energy for LIPA from our generating facilities located
on Long Island; and manage fuel supplies for LIPA to fuel our Long Island
generating facilities. These services are provided in accordance with long-term
service contracts having remaining terms that range from four to eleven years.
The Electric Services segment also includes subsidiaries that own, lease and
operate the 2,200 megawatt Ravenswood electric generation facility, located in
Queens, New York. Currently, our primary electric generation customers are LIPA
and the NYISO energy markets.
The Energy Services segment includes companies that provide energy-related
services to customers located within the New York City metropolitan area, as
well as, Rhode Island, Pennsylvania, Massachusetts and New Hampshire, through
the following four lines of business: (i) Home Energy Services, which provides
residential customers with service and maintenance of energy systems and
appliances, as well as the retail marketing of natural gas and electricity to
residential and small commercial customers; (ii) Business Solutions, which
provides professional engineering-consulting and design of energy systems for
commercial and industrial customers, including installation of plumbing,
heating, ventilation and air-conditioning equipment; (iii) Commodity
Procurement, which provides management and procurement services for fuel supply
and management of energy sales, primarily for and from the Ravenswood facility;
and (iv) 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 Houston Exploration, an independent natural gas and oil
exploration company, as well as KeySpan Exploration and Production, LLC, our
wholly owned subsidiary engaged in a joint venture with Houston Exploration.
Subsidiaries in this segment also hold a 20% equity interest in the Iroquois Gas
Transmission System LP, a pipeline that transports Canadian gas supply to
markets in the Northeastern United States; a 50% interest in the Premier
Transmission Pipeline and a 24.5% interest in Phoenix Natural Gas, both in
Northern Ireland; and investments in certain midstream natural gas assets in
Western Canada through KeySpan Canada. With the exception of our gas exploration
and production subsidiaries and KeySpan Canada, which are consolidated in our
financial statements, these subsidiaries are accounted for under the equity
method. Accordingly, equity income from these investments is reflected in Other
Income and (Deductions) in the Consolidated Statement of Income.
The accounting policies of the segments are the same as those used for the
preparation of the Consolidated Financial Statements. Our segments are strategic
business units that are managed separately because of their different operating
and regulatory environments. Operating results of our segments are evaluated by
management on a earnings before interest and taxes ("EBIT") basis. Due to the
anticipated sale of Midland Enterprises in 2002, this subsidiary is reported as
discontinued operations in 2001 and 2000. For more information on this
transaction, refer to Note 10, "Discontinued Operations".
The reportable segment information below is shown excluding the operations of
Midland:
(In Thousands of Dollars)
-------------------------
Energy Investments
------------------------------------
Gas Electric Energy Gas Exploration Other
Distribution Services Services and Production Investments Eliminations Consolidated
- -------------------------------- ---------------------------------------------------------------------------------------------------
Year Ended December 31, 2001
Unaffiliated revenue 3,613,551 1,421,079 1,100,167 400,031 98,287 - 6,633,115
Intersegment revenue - - 46,718 - - (46,718) -
Depreciation, depletion and
amortization 253,523 52,247 33,673 184,717 15,737 19,241 559,138
Income from equity
method subsidiaries - - - - 13,129 - 13,129
Interest income 3,879 147 3,471 - 334 495 8,326
Earnings before interest and
income taxes 492,362 246,091 (106,050) 119,933 21,544 33,975 807,855
Interest charges 219,307 47,124 20,824 2,993 9,772 53,450 353,470
Total assets 6,994,140 1,641,189 585,162 951,135 797,294 820,686 11,789,606
Investment in equity
method subsidiaries - - - - 107,069 - 107,069
Construction expenditures 384,323 211,658 17,292 385,463 52,513 8,510 1,059,759
- -------------------------------- ---------------------------------------------------------------------------------------------------
Eliminating items include intercompany interest income and expense, the
elimination of certain intercompany accounts, as well as activities of our
corporate and administrative subsidiaries.
Electric Services revenues from LIPA and the NYISO of $1.4 billion for the year
ended December 31, 2001 represents approximately 21% of our consolidated
revenues during that period.
(In Thousands of Dollars)
-------------------------
Energy Investments
---------------------------------
Gas Electric Energy Gas Exploration Other
Distribution Services Services and Production Investments Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2000
Unaffiliated revenue 2,555,785 1,444,711 770,110 274,209 35,258 629 5,080,702
Intersegment revenue - - 63,296 - - (63,296) -
Depreciation, depletion and
amortization 143,335 49,278 10,347 95,364 6,586 26,012 330,922
Income from equity
method subsidiaries - - - - 20,010 - 20,010
Interest income 3,951 1,214 966 - 6,134 62 12,327
Earnings before interest and
income taxes 367,226 250,688 74,765 111,672 20,014 (103,039) 721,326
Interest charges 111,176 24,254 125 11,360 7,636 46,763 201,314
Total assets 7,286,138 1,856,981 768,016 830,170 683,399 (117,239) 11,307,465
Investment in equity
method subsidiaries - - - - 109,751 3,387 113,138
Construction expenditures 274,941 69,921 17,362 243,799 26,388 624 633,035
- -----------------------------------------------------------------------------------------------------------------------------------
Eliminating items include intercompany interest income, expense and the
elimination of certain intercompany accounts as well as activities of our
corporate and administrative subsidiaries.
Electric Services revenues from LIPA, Consolidated Edison and the NYISO of $1.4
billion for the year ended December 31, 2000 represents approximately 28% of our
consolidated revenues during that period.
(In Thousands of Dollars)
-------------------------
Energy Investments
--------------------------------------
Gas Electric Energy Gas Exploration Other
Distribution Services Services and Production Investments Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1999
Unaffiliated revenue 1,753,132 861,582 186,529 150,581 2,789 - 2,954,613
Intersegment revenue - - - - - - -
Depreciation, depletion and
amortization 102,997 44,334 3,548 74,051 1,308 27,202 253,440
Income from equity
method subsidiaries - - - - 15,347 - 15,347
Interest income 3,942 - - - 5,016 18,035 26,993
Earnings before interest and
income taxes 318,245 141,197 (3,935) 40,835 13,773 18,609 528,724
Interest charges 88,370 22,380 - 13,307 3,726 5,968 133,751
Total assets 3,774,563 1,267,931 202,124 646,657 503,549 335,867 6,730,691
Investment in equity
method subsidiaries - - - - 341,874 4,016 345,890
Construction expenditures 213,845 245,177 6,179 183,322 10,028 13,294 671,845
- ------------------------------------------------------------------------------------------------------------------------------------
Eliminating items include intercompany interest income, expense and the
elimination of certain intercompany accounts as well as activities of our
corporate and administrative subsidiaries.
Electric Services revenues from LIPA, and Consolidated Edison of $859 million
for the year ended December 31, 1999 represents approximately 29% of our
consolidated revenues during that period.
Note 3. Income Tax
We file consolidated federal and state income tax returns. A tax sharing
agreement between our holding company and its subsidiaries provides for the
allocation of a realized tax liability or benefit based upon separate return
contributions of each subsidiary to the consolidated taxable income or loss in
the consolidated income tax returns.
Income tax expense in 1999 reflects an adjustment to deferred tax expense and
current tax expense for the utilization of previously deferred net operating
loss carryforwards recorded in 1998. In 1998, we recorded a deferred tax benefit
of $71.1 million for net operating loss carryforwards. We estimated that $57.4
million of the benefit from the net operating loss carryforwards from 1998 would
be realized in our consolidated 1999 federal and state income tax returns and,
accordingly, we applied the net operating loss benefit in our 1999 federal and
state tax provisions.
Income tax expense is reflected as follows in the Consolidated Statement of
Income:
(In Thousands of Dollars)
-------------------------
Year Ended Year Ended Year Ended
December 31, 2001 December 31, 2000 December 31, 1999
- ------------------------------------------------------------------------------------------------------------------------------------
Current income tax $ 101,738 $ 170,809 $ 26,618
Deferred income tax 108,955 46,453 109,744
- ------------------------------------------------------------------------------------------------------------------------------------
Total income tax $ 210,693 $ 217,262 $ 136,362
- ------------------------------------------------------------------------------------------------------------------------------------
The components of deferred tax assets and (liabilities) reflected in the
Consolidated Balance Sheet are as follows:
(In Thousands of Dollars)
-------------------------
December 31, 2001 December 31, 2000
- -------------------------------------------- -------------------------------- --------------------------------
Reserves not currently deductible $ 55,372 $ 63,635
Benefits of tax loss carryforwards 6,346 26,276
Property related differences (498,726) (403,224)
Regulatory tax asset (22,588) (21,375)
Property taxes (61,126) (54,794)
Discontinued operations (74,936) -
Other items - net (2,414) 14,902
- -------------------------------------------- -------------------------------- --------------------------------
Net deferred tax liability $ (598,072) $ (374,580)
- -------------------------------------------- -------------------------------- --------------------------------
The following is a reconciliation between the effective tax rate and the federal
income tax rate of 35%:
(In Thousands of Dollars)
-------------------------
Year Ended Year Ended Year Ended
December 31, December 31, December 31,
2001 2000 1999
- -------------------------------------------------------------------------------- --------------------- -------------------------
Computed at the statutory rate $ 159,035 $ 182,004 $ 138,241
Adjustments related to:
Tax credits (1,100) (1,181) (2,154)
Goodwill amortization 21,126 4,123 1,468
Minority interest in Houston Exploration 13,862 8,768 3,105
State income tax 26,418 30,384 4,635
Other items - net (8,648) (6,836) (8,933)
- -------------------------------------------------------------------------------- --------------------- -------------------------
$ Total income tax $ 210,693 $ 217,262 $ 136,362
- -------------------------------------------------------------------------------- --------------------- -------------------------
Effective income tax rate (1) 46% 42% 35%
- -------------------------------------------------------------------------------- --------------------- ------------------------
(1) Reflects both federal as well as state income taxes.
Note 4. Postretirement Benefits
Pension Plans: The following information represents the consolidated results for
our noncontributory defined benefit pension plans which cover substantially all
employees. Benefits are based on years of service and compensation. Funding for
pensions is in accordance with requirements of federal law and regulations. We
are currently integrating our plans and allocations to individual business
segments. KEDLI is subject to certain deferral accounting requirements mandated
by the NYPSC for pension costs and other postretirement benefit costs.
Information pertaining to discontinued operations has been excluded from this
presentation.
The calculation of net periodic pension cost is as follows:
(In Thousands of Dollars)
-------------------------
Year Ended Year Ended Year Ended
December 31, 2001 December 31, 2000 December 31, 1999
- --------------------------------------------- -------------------------------- ---------------------------- ---------------------
Service cost, benefits earned
during the period $ 41,162 $ 35,541 $ 38,372
Interest cost on projected
benefit obligation 128,481 109,231 106,888
Expected return on plan assets (180,757) (166,744) (138,436)
Special termination charge (1) - 45,838 -
Settlement Gain (2) - (20,196) -
Net amortization and deferral (39,772) (54,881) (8,869)
- --------------------------------------------- -------------------------------- ---------------------------- ---------------------
Total pension benefit $ (50,886) $ (51,211) $ (2,045)
- --------------------------------------------- -------------------------------- ---------------------------- ---------------------
(1) See discussion of early retirement program at end of note.
(2) See discussion of pension plan settlement.
Pension cost includes expense and income for KEDNE for the period November 8,
2000 through December 31, 2001.
The following table sets forth the pension plans' funded status at December 31,
2001 and December 31, 2000. Plan assets are principally common stock and fixed
income securities.
(In Thousands of Dollars)
-------------------------
December 31, 2001 December 31, 2000
- -------------------------------------------------------- ------------------------------ -----------------------------------
Change in benefit obligation:
Benefit obligation at beginning of period $ (1,914,885) $ (1,529,815)
Benefit obligation of acquisitions - (255,510)
Service cost (41,162) (35,541)
Interest cost (128,481) (109,231)
Amendments (8,679) (34,400)
Actuarial gain (loss) 61,718 (112,137)
Special termination benefits - (45,838)
Settlements - 110,000
Benefits paid 116,335 97,587
- -------------------------------------------------------- ------------------------------ -----------------------------------
Benefit obligation at end of period (1,915,154) (1,914,885)
- -------------------------------------------------------- ------------------------------ -----------------------------------
Change in plan assets:
Fair value of plan assets at beginning of period 2,170,093 2,048,325
Fair value of acquired plan assets - 240,665
Actual return on plan assets (197,632) 70,798
Employer contribution 43,130 18,302
Settlements - (110,410)
Benefits paid (116,335) (97,587)
- -------------------------------------------------------- ------------------------------ -----------------------------------
Fair value of plan assets at end of period 1,899,256 2,170,093
- -------------------------------------------------------- ------------------------------ -----------------------------------
Funded status (15,898) 255,208
Unrecognized net loss (gain) from past experience
different from that assumed and from
changes in assumptions 8,207 (342,730)
Unrecognized prior service cost 84,036 79,914
Unrecognized transition obligation 1,212 2,187
- -------------------------------------------------------- ------------------------------ -----------------------------------
Net prepaid (accrued) pension cost reflected
on consolidated balance sheet $ 77,557 $ (5,421)
- -------------------------------------------------------- ------------------------------ -----------------------------------
Year Ended Year Ended Year Ended
December 31, 2001 December 31, 2000 December 31, 1999
- ------------------------------------------------ ----------------------------- ----------------------------- --------------------
Assumptions:
Obligation discount 7.00% 7.00% 7.50%
Asset return 8.50% 8.50% 8.50%
Average annual increase in compensation 4.00% 5.00% 5.00%
- ------------------------------------------------ ----------------------------- ----------------------------- --------------------
Pension Plan Settlement
In 2000, we settled certain participating contracts covering retiree pension
plans with MetLife. As required under SFAS 88 "Employers' Accounting for
Settlements and Curtailments of Defined Benefit Pension Plans and for
Termination Benefits", a gain of $20.2 million was recognized as part of our
pension cost for the year ended December 31, 2000.
Unfunded Pension Obligation
At December 31, 2001 accumulated benefit obligations were in excess of pension
assets. As prescribed by SFAS 87 "Employers' Accounting for Pensions", we were
required to record an additional $68.9 million minimum liability for this
unfunded pension obligation. As allowed for under current accounting guidelines,
this accrual can be offset by a corresponding debit to a long-term asset up to
the amount of accumulated unrecognized prior service costs. Any remaining amount
is to be recorded as a direct charge to equity. Therefore, at year-end, we also
recorded a $48.5 million debit in Deferred Charges Other and a $20.4 million
debit in Accumulated Other Comprehensive Income. At December 31, 2001 the
projected benefit obligation, accumulated benefit obligation and value of assets
for plans with accumulated benefit obligations in excess of plan assets were
$1.1 billion, $1.0 billion and $929 million, respectively. In December 2002, we
will re- measure the accumulated benefit obligations and pension assets, and
adjust the accrual and deferrals as appropriate.
Other Postretirement Benefits: The following information represents the
consolidated results for our noncontributory defined benefit plans covering
certain health care and life insurance benefits for retired employees. We have
been funding a portion of future benefits over employees' active service lives
through Voluntary Employee Beneficiary Association ("VEBA") trusts.
Contributions to VEBA trusts are tax deductible, subject to limitations
contained in the Internal Revenue Code. We are currently integrating our plans
and allocations to individual business segments.
Net periodic other postretirement benefit cost included the following
components:
(In Thousands of Dollars)
Year Ended Year Ended Year Ended
December 31, 2001 December 31, 2000 December 31, 1999
- ------------------------------------------ ------------------------------ ----------------------------- -------------------------
Service cost, benefits earned
during the period $ 20,339 $ 14,771 $ 16,747
Interest cost on accumulated post-
retirement benefit obligation 64,649 47,412 42,616
Expected return on plan assets (42,822) (42,890) (36,842)
Special termination charge (1) - 5,590 -
Net amortization and deferral 11,664 (9,290) 3,429
- ------------------------------------------ ------------------------------ ----------------------------- -------------------------
Other postretirement benefit cost $ 53,830 $ 15,593 $ 25,950
- ------------------------------------------ ------------------------------ ----------------------------- -------------------------
(1) See discussion of early retirement program at end of note.
Other post-retirement benefit costs include expense and income for KEDNE for
November 8, 2000 through December 31, 2001.
The following table sets forth the plan's funded status at December 31, 2001 and
December 31, 2000. Plan assets are principally common stock and fixed income
securities.
(In Thousands of Dollars)
-------------------------
December 31, 2001 December 31, 2000
- ---------------------------------------------------------- ------------------------------ -------------------------------
Change in benefit obligation:
Benefit obligation at beginning of period $ (873,421) $ (602,053)
Benefit obligation of acquisitions - (103,630)
Service cost (20,339) (14,771)
Interest cost (64,649) (47,412)
Plan participants' contributions (1,439) (678)
Amendments 52 -
Actuarial (loss) (57,670) (137,756)
Special termination benefits - (5,590)
Benefits paid 47,774 38,469
- ---------------------------------------------------------- ------------------------------ -------------------------------
Benefit obligation at end of period (969,692) (873,421)
- ---------------------------------------------------------- ------------------------------ -------------------------------
Change in plan assets:
Fair value of plan assets at beginning of period 554,866 548,850
Fair value of acquired plan assets - 39,263
Actual return on plan assets (39,703) 816
Employer contribution 7,318 3,728
Plan participants' contribution 1,439 678
Benefits paid (47,774) (38,469)
- ---------------------------------------------------------- ------------------------------ -------------------------------
Fair value of plan assets at end of period 476,146 554,866
- ---------------------------------------------------------- ------------------------------ -------------------------------
Funded status (493,546) (318,555)
Unrecognized net loss from past experience
different from that assumed and from changes in
assumptions 251,198 123,251
Unrecognized prior service cost (8,392) (8,924)
- ---------------------------------------------------------- ------------------------------ -------------------------------
Accrued benefit cost reflected on
consolidated balance sheet $ (250,740) $ (204,228)
- ---------------------------------------------------------- ------------------------------ -------------------------------
Year Ended Year Ended Year Ended
December 31, 2001 December 31, 2000 December 31, 1999
- ------------------------------------------- ----------------------------- ------------------------------- --------------------------
Assumptions:
Obligation discount 7.00% 7.00% 7.50%
Asset return 8.50% 8.50% 8.50%
Average annual increase in compensation 4.00% 5.00% 5.00%
- ------------------------------------------- ----------------------------- ------------------------------- --------------------------
The measurement of plan liabilities also assumes a health care cost trend rate
of 10% grading down to 5% in 2009 and thereafter. A 1% increase in the health
care cost trend rate would have the effect of increasing the accumulated
postretirement benefit obligation as of December 31, 2001 by $110.8 million and
the net periodic health care expense by $12.9 million. A 1% decrease in the
health care cost trend rate would have the effect of decreasing the accumulated
postretirement benefit obligation as of December 31, 2001 by $97.3 million and
the net periodic health care expense by $10.8 million.
In 1993, LILCO adopted the provisions of SFAS 106, "Employer's Accounting for
Postretirement Benefits Other Than Pensions," and recorded an accumulated
postretirement benefit obligation and a corresponding regulatory asset of $376
million. LIPA has been reimbursing us for costs related to the postretirement
benefits of the electric business unit employees, therefore, we have
reclassified the regulatory asset for postretirement benefits associated with
electric business unit employees to Deferred Charges Other on the Consolidated
Balance Sheet.
Early Retirement Program
In December 2000, we completed an early retirement program for certain
management and union employees. The additional obligations for pensions and
other postretirement benefits are reflected at December 31, 2000. Included in
the pension and other postretirement benefits expense for the year ended
December 31, 2000 are charges of $45.8 million and $5.6 million, respectively
related to the early retirement program.
Note 5. Capital Stock
Common Stock: Currently we have 450,000,000 shares of authorized common stock.
In 1998, we initiated a program to repurchase a portion of our outstanding
common stock on the open market. At December 31, 2001 we had 19.4 million
shares, or approximately $562 million of Treasury Stock outstanding. We
completed this repurchase plan in 1999 and now utilize Treasury Stock to satisfy
our common stock plans. During 2001, we issued 3.1 million shares out of
treasury for the dividend reinvestment feature of our Investor Program, the
Employee Stock Discount Purchase Plan for Employees, and the Employee Savings
Plan.
Preferred Stock: We have the authority to issue 100,000,000 shares of preferred
stock with the following classifications: 16,000,000 shares of preferred stock,
par value $25 per share; 1,000,000 shares of preferred stock, par value $100 per
share; and 83,000,000 shares of preferred stock, par value $.01 per share.
At December 31, 2001 we had 553,000 shares outstanding of 7.07% Preferred Stock
Series B par value $100; 197,000 shares outstanding of 7.17% Preferred Stock
Series C par value $100; and 90,770 shares outstanding of 6% Preferred Stock
Series A par value $100, in the aggregate totaling $84.1 million.
Boston Gas Company has 622,700 shares of 6.421% non-voting preferred stock par
value $25 per share outstanding at December 31, 2001. This issue of preferred
stock has a 5% annual sinking fund requirement. We have the option of increasing
the sinking fund payment up to 10% per year. This issue is callable beginning in
2003 and is reflected in Minority Interest on the Consolidated Balance Sheet.
Note 6. Stock Options
We issue stock options to all KeySpan officers and certain other management
employees as approved by our Board of Directors. These options generally vest
over a three year period and have a ten-year exercise period. Approximately 19.3
million shares have been authorized to grant for options and approximately 9.0
million of these shares were remaining at December 31, 2001. Moreover, under a
separate plan, Houston Exploration has issued approximately 2.2 million stock
options to key Houston Exploration employees. KeySpan and Houston Exploration
apply APB Opinion 25, "Accounting for Stock Issued to Employees," and related
Interpretations in accounting for their plans. Accordingly, no compensation cost
has been recognized for these fixed stock option plans in the Consolidated
Financial Statements since the exercise prices and market values were equal on
the grant dates. Had compensation cost for these plans been determined based on
the fair value at the grant dates for awards under the plans consistent with
SFAS 123, "Accounting for Stock-Based Compensation," our net income and earnings
per share would have been decreased to the proforma amounts indicated below:
Year Ended Year Ended Year Ended
December 31, 2001 December 31,2000 December 31, 1999
- -----------------------------------------------------------------------------------------------------------------------------------
Income available for common stock (000):
As reported $218,350 $282,694 $223,859
Proforma $210,493 $276,167 $215,416
Earnings per share: As reported $1.58 $2.10 $1.62
Proforma $1.52 $2.06 $1.56
- -----------------------------------------------------------------------------------------------------------------------------------
All grants are estimated on the date of the grant using the Black-Scholes
option-pricing model. The following table presents the weighted average fair
value, exercise price and assumptions used for the periods indicated:
Year Ended Year Ended Year Ended
December 31, 2001 December 31, 2000 December 31, 1999
- ------------------------------- -------------------------------- ------------------------------- --------------------------------
Fair value of grants issued $5.29 $2.87 $3.65
Dividend yield 4.91% 8.22% 6.58%
Expected volatility 29.04% 24.00% 23.43%
Risk free rate 5.13% 6.54% 5.72%
Expected lives 10 years 6 years 6 years
Exercise price $36.25 $22.69 $27.58
- ------------------------------- -------------------------------- ------------------------------- --------------------------------
A summary of the status of our fixed stock option plans and changes is presented
below for the periods indicated:
Year Ended Year Ended Year Ended
December 31, 2001 December 31, 2000 December 31, 1999
- ----------------------------------- ------------------------------ --------------------------------- -------------------------------
Weighted Weighted Weighted
Average Average Average
Fixed Options: Shares Exercise Price Shares Exercise Price Shares Exercise Price
- ----------------------------------- ---------- ------------------- --------------------------------- -------------- ----------------
Outstanding at beginning of period 6,456,627 $25.61 4,968,398 $28.18 921,066 $30.80
Granted during the year 2,285,350 $39.50 3,165,822 $22.69 4,149,000 $27.58
Exercised (809,983) $25.15 (1,577,259) $27.82 (2,666) $27.75
Forfeited (135,832) $29.19 (100,334) $26.04 (99,002) $27.22
- ----------------------------------- ---------- ------------------- --------------------------------- -------------- ----------------
Outstanding at end of period 7,796,162 $29.67 6,456,627 $25.61 4,968,398 $28.18
- ----------------------------------- ---------- ------------------- --------------------------------- -------------- ----------------
Exercisable at end of period 2,996,771 $24.86 2,759,599 $29.57 3,638,448 $28.53
- ----------------------------------- ---------- ------------------- --------------------------------- -------------- ----------------
Options Outstanding Remaining Weighted Average Range of Options Exercisable Weighted Average Range of
at December 31, 2001 Contractual Life Exercise Price Exercise Price at December 31, 2001 Exercise Price Exercise Price
- --------------------- ----------------- ------------------ --------------- --------------------- ----------------- -----------------
61,400 4 years $27.00 $27.00 61,400 $27.00 $27.00
236,086 5 years $30.43 $20.57 - 30.50 236,086 $30.43 $20.57 - 30.50
304,410 6 years $32.56 $19.15 - 32.63 304,410 $32.56 $19.15 - 32.63
1,501,009 7 years $30.14 $24.73 - 30.63 1,501,009 $30.14 $24.73 - 30.63
919,649 8 years $26.82 $21.99 - 27.01 390,772 $26.86 $21.99 - 27.01
2,531,258 9 years $22.68 $13.76 - 32.76 503,094 $22.54 $13.76 - 32.76
2,242,350 10 years $39.50 $39.50 - - -
- --------------------- ----------------- ------------------ --------------- --------------------- ----------------- -----------------
7,796,162 2,996,771
- --------------------- ----------------- ------------------ --------------- --------------------- ----------------- -----------------
Note 7. Long-Term Debt
Gas Facilities Revenue Bonds: KEDNY can issue tax-exempt bonds through the New
York State Energy Research and Development Authority. Whenever bonds are issued
for new gas facilities projects, proceeds are deposited in trust and
subsequently withdrawn to finance qualified expenditures. There are no sinking
fund requirements on any of our Gas Facilities Revenue Bonds. At December 31,
2001, KEDNY had $648.5 million of Gas Facilities Revenue Bonds outstanding. The
interest rate on the variable rate series due December 1, 2020 is reset weekly
and ranged from 1.30% to 4.40% through December 31, 2001, at which time the rate
was 1.42%.
We have an interest rate swap agreement in which $90 million of our Gas Facility
Revenue Bonds, 6.75% Series A and B, were effectively converted to floating rate
debt. (See Note 9, "Hedging, Derivative Financial Instruments and Fair Values.")
Authority Financing Notes: Our electric generation subsidiary can also issue
tax-exempt bonds through the New York State Energy Research and Development
Authority. At December 31, 2001, $41.1 million of Authority Financing Notes 1999
Series A Pollution Control Revenue Bonds due October 1, 2028 were outstanding.
The interest rate on these notes is reset based on an auction procedure. The
interest rate during the year ranged from 1.20% to 4.45%, through December 31,
2001 at which time the rate was 1.40%.
We also have outstanding $24.9 million variable rate 1997 Series A Electric
Facilities Revenue Bonds due December 1, 2027. The interest rate on these bonds
is reset weekly and ranged from 1.00% to 4.85% through December 31, 2001 at
which time the rate was 1.65%.
Promissory Notes: At the time of the business combination between KeySpan and
LILCO, LIPA assumed all of the outstanding long-term debt of LILCO at May 28,
1998 except for the 1997 Series A Electric Facilities Revenue Bonds due December
1, 2027 which were assigned to us. In accordance with the LIPA agreement, we
issued promissory notes to LIPA which represented an amount equivalent to the
sum of: (i) the principal amount of 7.30% Series Debentures due July 15, 1999
and 8.20% Series Debentures due March 15, 2023 outstanding at May 28, 1998, and
(ii) an allocation of certain of the Authority Financing Notes. The promissory
notes contain identical terms as the debt referred to in items (i) and (ii)
above. During 1999, we extinguished our obligation in the amount of $442.5
million under certain promissory notes to LIPA.
Notes Payable: In January 2001 KEDLI issued $125 million of Medium-Term Notes at
6.9% due January 15, 2008. Additionally, KEDLI has outstanding $400 million of
7.875 % Medium-Term Notes due February 1, 2010.
In May 2001, we issued $500 million 6.15% Notes due June 1, 2006 under an
effective shelf registration, leaving $500 million available for issuance at
December 31, 2001. In February 2002, we updated our shelf registration for
issuance of up to $1.2 billion in additional securities, thereby providing us
with the ability to issue up to $1.7 billion of debt, equity or various forms of
preferred stock.
During the year ended December 31, 2000, we issued $1.65 billion of Medium-Term
Notes, associated with the acquisition of Eastern and ENI. The notes were issued
in three series as follows: $700 million, 7.25% Notes due 2005; $700 million,
7.625% Notes due 2010 and $250 million, 8.00% Notes due 2030. Additionally,
Boston Gas Company has outstanding $210 million of Medium-Term Notes. These
notes, which are not callable until maturity, have interest rates ranging from
6.80% - 9.75% and mature in 2005- 2025.
As part of our strategy to increase our level of floating rate debt, in 2001 we
entered into several interest rate swap agreements on $1.3 billion of existing
fixed rate medium and long-term debt and effectively converted it to floating
rate debt. These swap agreements qualify for hedge accounting and were completed
with several counter parties to reduce credit risk. (See Note 9 "Hedging,
Derivative Financial Instruments, and Fair Values" for additional information on
these swap agreements.)
At December 31, 2001, Houston Exploration had outstanding $100 million of 8.625%
Senior Subordinated Notes due 2008. These notes were issued in a private
placement in March 1998 and are subordinate to borrowings under Houston
Exploration's line of credit. These notes are redeemable at the option of
Houston Exploration after January 1, 2003.
First Mortgage Bonds: Eastern and ENI and their respective subsidiaries, have
issued and outstanding approximately $179 million of first mortgage bonds. These
bonds are secured by KEDNE gas utility property. The first mortgage bond
indentures include, among other provisions, limitations on: (i) the issuance of
long- term debt; (ii) engaging in additional lease obligations; and (iii) the
payment of dividends from retained earnings.
Commercial Paper and Revolving Credit Agreements: During 2001, we replaced two
existing revolving credit facilities of $700 million each, with one new credit
facility which will support our $1.4 billion commercial paper program. This
agreement is in place until September 2002.
Pricing under the facility is subject to a ratings-based grid with an annual fee
of .075% per annum on the balance of funds available. Borrowings will bear
interest at LIBOR plus 50 basis points. Borrowings in excess of more than 33% of
the total commitment will bear interest at LIBOR plus 62.5 basis points. At
December 31, 2001, $1.0 billion of commercial paper was outstanding at a
weighted average annualized interest rate of 2.23%; $351.6 million of commercial
paper was available for issuance.
In 2001 we entered into a swap agreement that effectively converted $270 million
of outstanding commercial paper with fixed rate debt that qualifies for hedge
accounting. (See Note 9 "Hedging, Derivative Financial Instruments, and Fair
Values" for additional information on these swap agreements.)
Houston Exploration has an unsecured available line of credit with a commercial
bank that provides for a maximum commitment of $250 million subject to borrowing
base limitations. This credit facility supports borrowings under a revolving
loan agreement, and at December 31, 2001, the borrowing base was $250 million.
Up to $2 million of this line is available for the issuance of letters of credit
to support performance guarantees. This credit facility matures on March 1, 2003
and is unsecured.
Houston Exploration borrowed $172 million under this facility during 2001 and
repaid $173 million, and at December 31, 2001, borrowings of $144 million were
outstanding and $0.4 million was committed under outstanding letter of credit
obligations. Borrowings under this facility bear interest, at rates indexed at a
premium to the Federal Funds rate or LIBOR, or based on the prime rate depending
on amounts outstanding under the credit facility. The weighted average interest
rate on this debt was 6.22% at December 31, 2001.
KeySpan Canada has two revolving loan agreements with Canadian banks. Under its
agreement with the Bank of Canada, KeySpan Canada repaid $9.4 million US dollars
in 2001. At December 31, 2001, total borrowings under this facility were $124.7
million US dollars. The weighted average interest rate on these borrowings at
December 31, 2001 was 4.97%. This credit facility has been fully utilized. The
second facility is with the Bank of Montreal. During the year, KeySpan Canada
borrowed $13.6 million US dollars. At December 31, 2001, total borrowings under
this facility were $50.6 million US dollars at a weighted average interest rate
of 5.20%. KeySpan Canada has $29 million US dollars available for future
borrowing under this facility.
Capital Leases: Our subsidiaries lease certain facilities and equipment under
long-term leases which expire on various dates through 2020. The weighted
average interest rate on these obligations was 6.69%.
Debt Maturity: Debt repayment requirements, including capitalized leases and
related maturities, are $1.0 million, $11.7 million, $1.5 million, $716.5
million, and $513.0 million for the years 2002 through 2006, respectively and
cumulatively $3.6 billion thereafter.
Note 8. Contractual Obligations and Contingencies
Lease Obligations: Lease costs included in operation expense were $89.8 million
in 2001 reflecting, primarily, the Ravenswood lease of $30.4 million and the
lease of our Brooklyn headquarters of $13.1 million. Lease costs also include
leases for other buildings, office equipment, vehicles and power operated
equipment. Lease costs for the year ended December 31, 2000 were $69.3 million.
Lease costs for the year ended December 31, 1999 were $47.1 million. The future
minimum lease payments under various leases, all of which are operating leases,
are $85.5 million per year over the next five years and $205.9 million, in the
aggregate, for all years thereafter, including future minimum lease payments for
the Ravenswood lease of $30.8 million per year over the next five years and
$92.5 million for all years thereafter.
We acquired the 2,200 megawatt Ravenswood facility located in Long Island City,
Queens, New York, 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. Another subsidiary provides all operating,
maintenance and construction services for the facility. The lease relates to
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 employed. Further, we would have recorded an asset in the same amount.
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 balance of the funds needed to acquire the facility were provided
from cash on hand. The initial term of the lease expires on June 20, 2004 and
may be extended until June 20, 2009.
Fixed Charges Under Firm Contracts: Our utility subsidiaries have entered into
various contracts for gas delivery, storage and supply services. The contracts
have remaining terms that cover from one to thirteen years. Certain of these
contracts require payment of annual demand charges in the aggregate amount of
approximately $500.9 million. We are liable for these payments regardless of the
level of service we require from third parties. Such charges are currently
recovered from utility customers through the gas adjustment clause.
Legal Matters: From time to time we are subject to various legal proceedings
arising out of the ordinary course of our business. Except as described below,
we do not consider any of such proceedings to be material to our business or
likely to result in a material adverse effect on our results of operations,
financial condition and cash flows.
KeySpan, through its subsidiary, formerly known as Roy Kay, Inc., has terminated
the employment of the former owners of the Roy Kay companies and commenced a
proceeding in the Chancery Division of the Superior Court, Monmouth County, New
Jersey (Docket No. Mon. C. 95-01) as a result of the alleged fraudulent acts of
the former owners, both before and after the acquisition of the Roy Kay
companies in January 2000. KeySpan believes the former owners misstated the
financial statements of the Roy Kay companies and certain underlying
work-in-progress schedules. KeySpan is seeking damages in excess of $76 million
as well as a judicial determination that KeySpan is not required to pay the
former owners any further amounts under the terms of the stock purchase
agreement entered into in connection with the acquisition of the Roy Kay
companies. The causes of action include breach of contract and fiduciary duty,
fraud, and violation of the New Jersey Securities Laws. The former owners have
filed counterclaims against KeySpan and certain of its subsidiaries, as well as
certain of their respective officers, to recover damages they claim to have
incurred as a result of, among other things, their alleged improper termination
and the alleged fraud on the part of KeySpan in failing to disclose the
limitations imposed upon the Roy Kay companies, with respect to the performance
of certain services, under the PUHCA . The fraud claims asserted by the former
owners include claims under the New Jersey Uniform Securities Law and RICO
statutes. We are unable to predict the outcome of these proceedings or what
effect, if any, such outcome will have on our financial condition, results of
operations or cash flows.
KeySpan 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 U.S. Securities and Exchange Commission. In addition,
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. Each of the proceedings seeks
monetary damages in an unspecified amount. We are unable to determine the
outcome of these proceedings and what effect, if any, such outcome will have on
our financial condition, results of operations or cash flows.
In October 1998, the County of Suffolk and the Towns of Huntington and Babylon
commenced an action against LIPA, KeySpan, the NYPSC and others in the United
States District Court for the Eastern District of New York (the "Huntington
Lawsuit"). The Huntington Lawsuit alleges, among other things, that LILCO
ratepayers (i) have a property right to receive or share in the alleged capital
gain that resulted from the transaction with LIPA (which gain is alleged to be
at least $1 billion); and (ii) that LILCO was required to refund to ratepayers
the amount of a Shoreham-related deferred tax reserve (alleged to be at least
$800 million) carried on the books of LILCO at the consummation of the LIPA
Transaction. In December 1998, and again in June 1999, the plaintiffs amended
their complaint. The amended complaint contains allegations relating to certain
payments LILCO had determined were payable in connection with the KeySpan /
LILCO merger to LILCO's Chairman and certain former officers and adds the
recipients of the payments as defendants. In June 1999, KeySpan was served with
the second amended complaint. On June 16, 2000, KeySpan filed a motion to
dismiss the second amended complaint. On August 14, 2000, the Court granted
KeySpan's motion and dismissed the plaintiffs' second amended complaint in its
entirety. The plaintiffs appealed that decision and on June 1, 2001 the United
States Court of Appeals in the Second Circuit denied plaintiff's appeal.
Environmental Matters
Air. With respect to NOx emissions reduction requirements for our existing power
plants, we are required to be in compliance with the Phase III reduction
requirements of the Ozone Transportation Commission memorandum by May 1, 2003
and we fully expect to achieve such emission reductions on time and in a
cost-effective manner. Our expenditures to address emission reduction
requirements through the year 2003 are expected to be between $10 million and
$15 million.
Water. Additional capital expenditures associated with the renewal of the
surface water discharge permits for our power plants may be required by the
Department of Environmental Conservation ("DEC"). Until our monitoring
obligations are completed and changes to the Environmental Protection Agency
regulations under Section 316 of the Clean Water Act are promulgated, the need
for and the cost of equipment upgrades cannot be determined.
Land. Manufactured Gas Plants and Related Facilities
New York Sites. Within the State of New York we have identified 28 manufactured
gas plant ("MGP") sites and related facilities which were historically owned or
operated by KeySpan subsidiaries or such companies' predecessors. These former
sites, some of which are no longer owned by us, have been identified to both the
DEC for inclusion on appropriate site inventories and listing with the NYPSC.
We have identified 18 sites associated with the historic operations of KEDNY.
Administrative Orders on Consent ("ACO") have been executed with the DEC to
address the investigation and remediation activities associated with two of
these sites. In 2001, KEDNY filed a complaint for the recovery of its
remediation costs in the New York State Supreme Court against the various
insurance companies that issued general comprehensive liability policies to
KEDNY. The outcome of this proceeding cannot yet be determined. We presently
estimate the remaining environmental cleanup activities of these sites will be
$88.6 million, which amount has been accrued by us. Expenditures incurred to
date by us with respect to MGP-related activities total $19.3 million.
We have identified nine sites associated with the historic operations of KEDLI,
six of which are the subject of two separate ACOs which we executed with the DEC
in 1999. Field investigations and, in some cases, interim remedial measures, are
underway or scheduled to occur at each of these sites under the supervision of
the DEC and the New York State Department of Health. Pursuant to a separate ACO
also entered into in 1999, we are performing preliminary site assessments at
five other sites which were formerly owned by KEDLI.
In January 1998, KEDLI filed a complaint for the recovery of its remediation
costs in the New York State Supreme Court against the various insurance
companies that issued general comprehensive liability policies to KEDLI. The
outcome of this proceeding cannot yet be determined. We presently estimate the
remaining environmental cleanup activities of these sites will be $68.3 million,
which amount has been accrued by us. Expenditures incurred to date by us with
respect to KEDLI MGP-related activities total $15.1 million.
We presently estimate the remaining cost of our New York/Long Island MGP-related
environmental cleanup activities will be $156.9 million, which amount has been
accrued by us as a reasonable estimate of probable cost for known sites.
Expenditures incurred to date by us with respect to these MGP-related activities
total $34.4 million.
With respect to remediation costs, the KEDNY rate plan provides, among other
things, that if the total cost of investigation and remediation varies from that
which is specifically estimated for a site under investigation and/or
remediation, then KEDNY will retain or absorb up to 10% of the variation. The
KEDLI rate plan also provides for the recovery of investigation and remediation
costs but with no consideration of the difference between estimated and actual
costs. Under prior rate orders, KEDNY has offset certain monies due to
ratepayers against its estimated environmental cleanup costs for MGP sites. At
December 31, 2001, we have reflected a regulatory asset of $124.1 million for
our New York/Long Island MGP sites.
We are also responsible for environmental obligations associated with the
Ravenswood electric generating facility, purchased from Consolidated Edison in
1999, including remediation activities associated with its historic operations
and those of the MGP facilities that formerly operated at the site. The extent
of our liability does not include liabilities arising from disposal of waste at
off-site locations prior to the acquisition closing and any monetary fines
arising from Consolidated Edison's pre-closing conduct. Based on information
currently available for environmental contingencies related to the Ravenswood
facility acquisition, we have accrued a $5 million liability.
New England Sites. Within the Commonwealth of Massachusetts and the State of New
Hampshire, we are aware of 76 former MGP sites and related facilities within the
existing or former service territories of KEDNE.
Boston Gas Company, Colonial Gas Company, and Essex Gas Company may have or
share responsibility under applicable environmental laws for the remediation of
66 MGP sites and related facilities. A subsidiary of National Grid USA
("National Grid") formerly New England Electric System has assumed
responsibility for remediating 11 of these sites, subject to a limited
contribution from Boston Gas Company and has provided full indemnification to
Boston Gas Company with respect to eight other sites. At this time, there is
substantial uncertainty as to whether Boston Gas Company, Colonial Gas Company
or Essex Gas Company have or share responsibility for remediating any of these
other sites. No notice of responsibility has been issued to us for any of these
sites from any governmental environmental authority.
In March 1999, Boston Gas Company and a subsidiary of National Grid filed a
complaint for the recovery of remediation costs in the Massachusetts Superior
Court against various insurance companies that issued comprehensive general
liability policies to National Grid and its predecessors with respect to, among
other things, the 11 sites for which Boston Gas Company has agreed to make a
limited contribution. The outcome of this proceeding cannot be determined at
this time.
We presently estimate the remaining cost of these KEDNE MGP-related
environmental cleanup activities will be $36.1 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 $7.2 million.
We may have or share responsibility under applicable environmental laws for the
remediation of 10 MGP sites and related facilities associated with the historic
operations of EnergyNorth. EnergyNorth has received notice of its potential
responsibility for contamination at two former MGP sites and, together with
other potentially responsible parties, has received notice of potential
responsibility for contamination associated with four other sites.
With respect to the Laconia and Nashua sites, EnergyNorth has entered into
separate cost sharing agreements with Public Service of New Hampshire ("PSNH")
for the Laconia and Nashua sites. Under the agreements PSNH is obligated to
indemnify EnergyNorth for future remediation costs, with limited exceptions, at
the Laconia site and PSNH will pay EnergyNorth up to $4.8 million toward the
costs of the investigation and remediation at the Nashua site. EnergyNorth also
has entered into an agreement with the United States Environmental Protection
Agency ("EPA") for the contamination from the Nashua site that was allegedly
commingled with asbestos at the so-called Nashua River Asbestos Site, adjacent
to the Nashua MGP site.
EnergyNorth has filed suit in both the New Hampshire Superior Court and the
United States District Court for the District of New Hampshire for recovery of
its remediation costs against the various insurance companies that issued
comprehensive general liability and excess liability insurance policies to
EnergyNorth and its predecessors. Settlements have been reached with some of the
carriers and one carrier was dismissed from a Superior Court action on summary
judgment. The outcome of the remaining proceedings cannot yet be determined.
EnergyNorth has also filed a contribution action in the United States District
Court for the District of New Hampshire against an entity it alleges shares
liability for the Manchester MGP study and remediation costs.
We presently estimate the remaining cost of EnergyNorth MGP-related
environmental cleanup activities will be $17.1 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 $2.9 million.
By a rate order issued in May 1990, the Massachusetts Department of
Telecommunications and Energy and the New Hampshire Public Utilities Commission
provide for the recovery of site investigation and remediation costs, and
accordingly, at December 31, 2001, we have reflected a regulatory asset of $59.6
million for the KEDNE MGP sites. As previously mentioned, Colonial Gas Company
and Essex Gas Company are not subject to the provisions of SFAS 71 and therefore
have recorded no regulatory assets. However, rate plans currently in effect for
these subsidiaries provide for the recovery of investigation and remediation
costs.
Eastern Enterprises Sites. We are aware of three non-utility sites located in
Pennsylvania, Connecticut and Massachusetts associated with former operations of
Eastern Enterprises, for which we may have or share environmental remediation
responsibility or ongoing maintenance, the principal of which is the former coal
tar processing facility in Everett, Massachusetts (the "Facility"). The Facility
was formerly owned by Eastern Enterprises and was operated by a predecessor of
Honeywell International, Inc. from the early 1900s until 1937 and then by a
predecessor of Beazer East, Inc. from 1937 until 1960 when it was shut down. The
Facility processed coal tar purchased from Eastern's adjacent by-product coke
plant, also shut down in 1960. Eastern, Beazer and Honeywell have entered into
an ACO with the Massachusetts Department of Environmental Protection ("DEP") for
the investigation and development of a remedial response plan for the Facility.
In addition, the Coast Guard has been working with the DEP since July 1998 to
bring about a remedial solution that would abate the continuing sheening problem
in the adjacent river. Eastern, Beazer and Honeywell have proposed a remedial
solution, a major element of which is the utilization of a containment structure
with limited dredging. As of yet, however, no agreement has been reached with
the regulators as to the appropriate remedial solution.
KeySpan, Honeywell and Beazer East have entered into a cost-sharing agreement
under which each company has agreed to pay one-third of the costs of compliance
with the consent order, while preserving any claims it may have against the
other companies. The companies have completed preliminary remedial measures,
including abatement of seepage of materials into the adjacent tidal river.
KeySpan also is recovering certain legal defense costs and may be entitled to
recover remediation costs from our insurers. We presently estimate the remaining
cost of our environmental cleanup activities for the three non-utility sites
will be approximately $42.5 million, which amount has been accrued by us a
reasonable estimate of probable costs for known sites; however the actual
remediation cost for these sites may be substantially higher.
We believe that in the aggregate, the accrued liability for investigation and
remediation of the New York and New England MGP sites and related facilities
identified above are reasonable estimates of likely cost within a range of
reasonable, foreseeable costs. We presently estimate the remaining cost of these
MGP- related environmental cleanup activities will be $257.6 million which
amount has been accrued by us as a reasonable estimate of probable cost for
known sites based upon available data, historical remediation costs of similarly
situated companies and management's experience in such matters. We may be
required to investigate and, if necessary, remediate each of these, or other
currently unknown, former MGP 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. As previously indicated, MGP-related costs
may be materially higher, depending upon remediation experience, selected end
use for each site, and actual environmental conditions encountered.
Note 9. Hedging, Derivative Financial Instruments, and Fair Values
Commodity Contracts and Electric Derivative Instruments: From time to time we
utilize derivative financial instruments, such as futures, options and swaps,
for the purpose of hedging exposure to commodity price risk and to fix the
selling price on a portion of our peak electric energy sales.
Houston Exploration utilizes collars, as well as, over- the- counter ("OTC")
swaps to hedge future sales prices on a portion of its natural gas production to
achieve a more predictable cash flow and reduce its exposure to adverse price
fluctuations of natural gas. For any particular collar transaction, the counter
party is required to make a payment to Houston Exploration if the settlement
price for any settlement period is below the floor price for such transaction,
and Houston Exploration is required to make payment to the counter party if the
settlement price for any settlement period is above the ceiling price for such
transaction. In the swap instruments, Houston Exploration will pay the amount by
which the floating variable price (settlement price) exceeds the fixed price and
receive the amount by which the settlement price is below the fixed price. As of
December 31, 2001, Houston Exploration has hedged approximately 59% of its
estimated 2002 yearly production and 14% of its estimated 2003 yearly
production. Houston Exploration uses standard New York Mercantile Exchange
("NYMEX") futures prices and published volatility in its Black-Scholes
calculation to value its outstanding derivatives. Houston Exploration recorded a
benefit of $12.9 million in Revenues for derivative instruments that settled
during 2001.
We also employ standard NYMEX gas futures contracts, as well as oil swap
derivative contracts to fix the purchase price for a portion of the fuel used at
the Ravenswood facility. For these instruments, we will pay the amount by which
the floating variable price (settlement price) is below the fixed price and
receive the amount by which the settlement price exceeds the fixed price. We use
standard NYMEX futures prices to value the gas futures contracts and industry
published oil indices for number 6 grade fuel oil to value the oil swap
contracts. These contracts extend through 2003. During 2001, we realized a gain
of $5.9 million on the settlement of derivative instruments and recorded this
gain as a decrease to Fuel and Purchased Power expense.
Our gas and electric marketing subsidiary has fixed rate gas sales contracts and
utilizes standard NYMEX futures contracts to lock-in a price for future natural
gas purchases. For these contracts, we pay the amount by which the floating
variable price (settlement price) is below the fixed price and receive the
amount by which the settlement price exceeds the fixed price. This subsidiary
uses standard NYMEX futures prices to value its outstanding contracts. During
2001, we realized a gain of $10.2 million on derivatives that settled during
2001 and recorded this gain as a reduction to Purchased Gas for Resale.
We have also engaged in the use of derivative swap instruments to fix the
selling price on a portion of our estimated 2002 summer and winter peak electric
energy sales from the Ravenswood facility to protect against a potential
degradation in market prices. Under these swap agreements, we will receive from
a counter party a fixed price per megawatt hour of electricity sold during
certain peak hours and pay the counter party the then current floating market
price for peak electric supply. We will receive the then current floating market
price of peak electric energy when the Ravenswood facility sells electric energy
to the NYISO. We also have tolling arrangements with two counter parties under
which we have "locked- in" a profit margin on a portion of 2002 summer and
winter season sales. Under these arrangements, we will receive from counter
parties a fixed margin and will then pay the counter party, on a monthly basis,
a variable profit margin from the sale of electric energy. As a result of these
hedging arrangements, we have hedged approximately 13% of our estimated 2002
yearly electric sales. We have a stated hedging policy that we will not hedge
more than 50% of our daily peak sales. We use NYISO-location zone published
indices and standard NYMEX prices to value these outstanding derivatives. During
2001, we realized a gain of $13.6 million on the settlement of certain swap
derivative instruments and recorded this gain in Revenues.
We adopted SFAS 133 "Accounting for Derivative Instruments and Hedging
Activities" on January 1, 2001. All of our commodity contracts and electric
derivative instruments detailed above are cash-flow hedges and qualify for hedge
accounting. Periodic changes in market value of derivatives which meet the
definition of a cash-flow hedge are recorded as comprehensive income, subject to
effectiveness, and then included in net income to match the underlying hedged
transactions. The adoption of SFAS 133, and the associated effectiveness
testing, did not have a significant effect on the results of operations for
2001.
The following tables set forth selected financial data associated with these
derivative financial instruments noted above that were outstanding at December
31, 2001.
Year of Volumes Fixed Current Fair Value
Type of Contract Maturity mmcf Floor $ Ceiling $ Price $ Price $ ($000)
- ---------------------------- ------------ ----------- --------- ----------- ------------- ------------- ------------------
Gas
Collars 2002 51,100 3.64 5.36 - 2.56 - 3.22 50,731
Swaps -Short Natural Gas 2002 10,950 - - 3.01 2.56 - 3.22 2,926
2003 14,600 - - 3.19 3.18 113
Swaps - Long Natural Gas 2002 8,880 - - 2.96 - 3.93 2.56 - 3.22 (5,733)
2003 1,570 - - 3.36 - 3.64 3.12 - 3.41 (350)
- ---------------------------- ------------ ----------- --------- ----------- ------------- ------------- ------------------
87,100 47,687
- ---------------------------- ------------ ----------- --------- ----------- ------------- ------------- ------------------
Year of Volumes Fair Value
Type of Contract Maturity Barrels Fixed Price $ Current Price $ ($000)
- ---------------------------- ----------- --------- ------------------- -------------------- -----------------
Oil
Swaps - Long Fuel Oil 2002 384,043 20.09 - 29.38 21.22 - 22.72 (776)
2003 225,686 21.01 - 26.72 21.32 -21.81 (274)
- ---------------------------- ----------- --------- ------------------- -------------------- -----------------
609,729 (1,050)
- ---------------------------- ----------- --------- ------------------- -------------------- -----------------
Year of Current Estimated Fair Value
Type of Contract Maturity MWh Fixed Margin /Price $ Price $ Margin $ ($000)
- ------------------------ ---------------- --------------- ----------------------- ---------- --------------- -----------------
Electricity
Tolling Arrangements 2002 576,000 10.00 - 26.00 - 3.94 - 10.13 7,640
Swaps 2002 67,200 54.50 42.35 - 820
- ------------------------ ---------------- --------------- ----------------------- ---------- --------------- -----------------
643,200 8,460
- ------------------------ ---------------- --------------- ----------------------- ---------- --------------- -----------------
Non-firm Gas Sales Derivative Instruments: Utility tariffs applicable to certain
large-volume customers permit gas to be sold at prices established monthly
within a specified range expressed as a percentage of prevailing alternate fuel
oil prices.
We use gas swap contracts, with offsetting positions in oil swap contracts of
equivalent energy value, with third parties to fix profit margins on specified
portions of gas sales to our large-volume market. These derivatives instruments,
at this time, do not meet the "effectiveness standards" as prescribed by SFAS
133 and accordingly do not qualify for hedge accounting. Therefore, changes in
the market value of these derivatives are included in income currently. During
2001, we realized gains of $3.0 million on the settlement of certain contracts,
as well as, $1.9 million in mark-to-market gains, and recorded these gains as a
reduction to Purchased Gas for Resale. We use standard NYMEX futures prices to
value both the gas and No. 2 grade heating oil swap contracts.
The following table sets forth selected financial data associated with these
derivative financial instruments that were outstanding at December 31, 2001.
Year of Volumes Volumes Fair Value
Type of Contract Maturity mmcf Barrels Fixed Price $ Current Price $ ($000)
- --------------------------- ---------------- ------------ ------------- --------------- ------------------ -------------------
Swaps - Long Natural Gas 2002 770 - 3.11 - 3.81 2.56 - 2.57 (1,535)
Swaps - Short Heating Oil 2002 - 448,000 29.42 - 33.15 23.18 - 23.24 3,505
- --------------------------- ---------------- ------------ ------------- --------------- ------------------ -------------------
770 448,000 1,970
- --------------------------- ---------------- ------------ ------------- --------------- ------------------ -------------------
Firm Gas Sales Derivative Instruments - Regulated Utilities: We utilize
derivative financial instruments to "lock-in" the purchase price for a portion
of our future natural gas purchases. Our strategy is to minimize fluctuations in
firm gas sales prices to our regulated firm gas sales customers in our New York
service territory. During 2001, we entered into a number of derivative
instruments such as, collars, purchased calls, transformer calls and variable
premium contracts. Since these derivative instruments have not been designed as
hedges and are being 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 are
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. We use standard NYMEX futures prices to value these
instruments.
The following table sets forth selected financial data associated with these
derivative financial instruments that were outstanding at December 31, 2001.
Year of Volumes Fair Value
Type of Contract Maturity mmcf Floor $ Ceiling $ Fixed Price $ Current Price $ ($000)
- ----------------------- ----------- --------- ------------- -------------- ---------------- ----------------- ----------------
Gas
Collars 2002 1,800 4.55 - 5.43 5.70 - 6.20 - 2.56 - 2.57 (4,370)
Call Options 2002 3,900 - - 4.00 - 5.60 2.56 - 2.57 (3,878)
Variable Premiums 2002 2,400 - - 3.90 - 6.00 2.56 - 2.57 (2,604)
- ----------------------- ----------- --------- ------------- -------------- ---------------- ----------------- ----------------
8,100 (10,852)
- ----------------------- ----------- --------- ------------- -------------- ---------------- ----------------- ----------------
Interest Rate Swaps: We also have interest rate swap agreements in which
approximately $1.4 billion of fixed rate debt have effectively been changed to
floating rate debt. These swaps extend through 2023, but can be terminated
earlier based on certain market and contract conditions. We have entered into
these derivative instruments with a number of major financial institutions to
reduce credit risk. For the term of the agreements, we will receive the fixed
coupon rate associated with these bonds and pay the counter parties a variable
interest rate that is reset on a weekly and/or quarterly basis as appropriate.
These bonds are fair- value hedges and qualify for hedge accounting. The swap
agreements associated with the Medium Term Notes, as displayed in the table
below, qualify for "short-cut" hedge accounting treatment under SFAS 133. Under
this method, changes in the fair values of the swap instruments are recorded
directly against the hedged bonds and have no impact on earnings. These swaps
were entered into in October 2001. The fair-value hedge associated with a Gas
Facilities Revenue Bond, which was entered into in 1999, does not qualify for
"short-cut" accounting treatment. As a result, the fair values of both the bond
and swap instrument are measured at least quarterly and the net change in the
fair values from period to period are recorded in income. Through the
utilization of our interest rate swap agreements, we reduced recorded interest
expense by $9.5 million in 2001. Further, we recorded, a benefit of $0.5 million
as a result of the fair value measurements. The fair values of these derivative
instruments are provided to us by third party appraisers and represent the
present value of future cash-flows based on a forward interest rate curve for
the life of the derivative instrument. The fair values at December 31, 2001, as
indicated in the table below, reflects an assumption of higher interest rates in
the future.
The table below summarizes selected financial data associated with these
derivative financial instruments that were outstanding at December 31, 2001.
Average
Maturity Date of Notional Amount Fixed Rate Variable Rate Fair Value
Bond Swaps ($000) Received Paid ($000)
- ------------------------------- ------------------- --------------------- ---------------- ----------------- ------------------
Gas Facilities Revenue Bonds 2024 90,000 5.540% 2.650% 136
Medium Term Notes 2010 500,000 7.625% 4.600% (21,921)
Medium Term Notes 2006 500,000 6.150% 3.900% (11,567)
Medium Term Notes 2023 270,000 8.200% 4.020% (13,794)
- ------------------------------- ------------------- --------------------- ---------------- ----------------- ------------------
1,360,000 (47,146)
- ------------------------------- ------------------- --------------------- ---------------- ----------------- ------------------
Additionally, in November 2001, we entered into a swap agreement that
effectively converted $270 million of outstanding commercial paper with
fixed-rate debt. This swap is a cash-flow hedge and qualifies for hedge
accounting under SFAS 133. Periodic changes in the market value of this swap are
recorded as comprehensive income, subject to effectiveness, and then included in
net income to match the underlying hedged transactions. We recorded additional
interest expense associated with this swap of $0.3 million during 2001 and there
was no impact on earnings from ineffectiveness. At December 31, 2001, the fair
value of this swap, which was reflected as a liability, was $0.4 million.
Weather Derivative: The utility tariffs associated with our New England gas
distribution operations do not contain a weather normalization adjustment. As a
result, fluctuations from normal weather may have a significant positive or
negative effect on the results of these operations. To mitigate the effect of
fluctuations from normal weather on our financial position and cash flows, we
entered into a weather swap in October 2001. This derivative hedged
approximately 15% of our weather related risk for the November 2001 - March 2002
winter season. Since weather in New England was warmer than normal in the fourth
quarter of 2001, we recorded a gain of $1.4 million in Other Income in 2001.
Although weather derivatives are outside the scope of SFAS 133, these
derivatives are essentially marked to market, at least quarterly, with changes
in fair valve included in earnings currently. In January 2002, we settled all
our remaining weather derivatives and recorded a gain of $0.3 million in Other
Income.
We are exposed to credit risk in the event of nonperformance by counter parties
to derivative contracts, as well as nonperformance by the counter parties of the
transactions hedged against. We believe that the credit risk related to the
above noted contracts is no greater than that associated with the primary
contracts which they hedge, as these contracts are with major investment grade
financial institutions, and that elimination of the price risk lowers overall
business risk.
Fair Values of Long-Term Debt
Fair Value (In Thousands of Dollars)
2001 2000
- ---------------------------------------------------- --------------------------- -------------------------
First Mortgage Bonds $ 182,666 $ 185,418
Notes 3,076,455 2,482,436
Gas Facilities Revenue Bonds 630,845 672,815
Authority Financing Notes 66,005 66,005
Promissory Notes 617,933 598,769
- ---------------------------------------------------- --------------------------- -------------------------
$ 4,573,904 $ 4,005,443
- ---------------------------------------------------- --------------------------- -------------------------
Carrying Amount (In Thousands of Dollars)
2001 2000
- ---------------------------------------------------- --------------------------- -------------------------
First Mortgage Bonds $ 179,122 $ 179,872
Notes 2,985,000 2,360,000
Gas Facilities Revenue Bonds 648,500 648,500
Authority Financing Notes 66,005 66,005
Promissory Notes 602,427 602,427
- ---------------------------------------------------- --------------------------- -------------------------
$ 4,481,054 $ 3,856,804
- ---------------------------------------------------- --------------------------- -------------------------
Our subsidiary debt is carried at an amount approximately fair value because
interest rates are based on current market rates. All other financial
instruments included in the Consolidated Balance Sheet are stated at amounts
that approximate fair values.
Note 10. Discontinued Operations
On November 8, 2000, we acquired Midland Enterprises ("Midland"), a marine
transportation subsidiary, as part of the Eastern transaction. We were ordered
by the SEC to sell this subsidiary by November 8, 2003 because its operations
are not functionally related to our core utility operations. On January 24,
2002, we announced an agreement to sell Midland to Ingram Industries Inc., which
is expected to close by the second quarter of 2002, subject to receipt of
applicable regulatory approvals. The sale of Midland represents the disposal of
a business segment pursuant to Accounting Principles Board ("APB") Opinion No.
30. Accordingly, the results of Midland have been classified as discontinued
operations, and prior periods have also been reclassified.
Discontinued operations for the year ended December 31, 2001 includes an
anticipated $30.4 million after-tax loss on the sale of Midland based on the
expected proceeds and estimated income for the first two quarters of 2002.
Proceeds from the transaction are subject to purchase price and post closing
adjustments, and may be used to pay-down a portion of outstanding debt.
The following is selected financial information for Midland Enterprises for the
year ended December 31, 2001 and for the period November 8, 2000 through
December 31, 2000 :
(In Thousands of Dollars)
-------------------------
2001 2000
- ------------------------------------------------------------------ ---------------------- -------------------------
Revenues $ 266,792 $ 40,788
Pretax income (loss) 18,489 (2,970)
Income tax (expense) benefit (7,571) 1,027
- ------------------------------------------------------------------ ---------------------- -------------------------
Income (loss) from discontinued operations 10,918 (1,943)
- ------------------------------------------------------------------ ---------------------- -------------------------
Estimated book gain on disposal 44,580 -
Tax expense associated with disposal (74,936) -
- ------------------------------------------------------------------ ---------------------- -------------------------
Estimated loss on disposal (30,356) -
- ------------------------------------------------------------------ ---------------------- -------------------------
Loss from discontinued operations $ (19,438) $ (1,943)
- ------------------------------------------------------------------ ---------------------- -------------------------
Assets and liabilities of the discontinued operations are as follows:
(In Thousands of Dollars)
-------------------------
2001 2000
- ------------------------------------------------------- --------------------------- ---------------------------
Current assets $ 139,522 $ 117,199
Property, plant and equipment, net 316,626 328,321
Long-term assets 35,233 34,516
Current liabilities (58,835) (54,084)
Long-term liabilities (241,491) (241,916)
- ------------------------------------------------------- --------------------------- ---------------------------
Net assets of discontinued operations $ 191,055 $ 184,036
- ------------------------------------------------------- --------------------------- ---------------------------
Note 11. Roy Kay Operations
During 2001 we undertook a complete evaluation of the strategy, operating
controls and organizational structure of the Roy Kay companies - plumbing,
mechanical, electrical and general contracting companies acquired by us in
January 2000. We decided to discontinue the general contracting business
conducted by these companies based upon our view that the general contracting
business is not a core competency of these companies. Certain remaining
activities engaged in by the Roy Kay companies will be integrated with those of
other KeySpan energy-related businesses. We will complete the construction
projects entered into by the former Roy Kay companies and, as a result, their
operations will continue to be consolidated in our Consolidated Financial
Statements until such time as those contracts have been completed. We currently
estimate that these contracts will be completed in 2002. For the year ended
December 31, 2001, the Roy Kay companies incurred an after-tax loss of $95.0
million ($137.8 million pre-tax) reflecting: (i) unanticipated costs to complete
work on certain construction projects; (ii) the impact of inaccuracies in the
books of these companies relating to their overall financial and operational
performance, (iii) discontinuance costs of the general contracting activities of
those companies, including the write-off of goodwill, and certain accounts and
retainage receivables; and (iv) operating losses. For the year ended December
31, 2001 and December 31, 2000, the Roy Kay companies recorded a pre-tax loss of
$137.8 million and pre-tax earnings of $1.3 million, respectively. KeySpan and
the former Roy Kay companies are currently engaged in litigation relating to the
termination of the former owners, as well as other matters relating to the
acquisition of the Roy Kay companies. (See Note 8 "Contractual Obligations and
Contingencies" - legal matters.)
Note 12. Class Action Settlement
During 2001, we reversed a previously recorded loss provision regarding certain
pending rate refund issues relating to the 1989 RICO class action settlement.
This adjustment resulted from a favorable United States Court of Appeals ruling
received on September 28, 2001, overturning a lower court decision, and resulted
in a positive pre-tax adjustment to earnings of $33.5 million, or $20.1 million
after-tax. This adjustment has been reflected as a $22.0 million reduction to
Operation and Maintenance expense and a reduction of $11.5 million to Interest
Expense on the Consolidated Statement of Income.
Note 13. KeySpan Gas East Corporation Summary Financial Data
KEDLI is a wholly owned subsidiary of KeySpan. KEDLI was formed on May 7, 1998
and on May 28, 1998 acquired substantially all of the assets related to the gas
distribution business of LILCO. KEDLI provides gas distribution services to
customers in the Long Island counties of Nassau and Suffolk and the Rockaway
peninsula of Queens county. KEDLI established a program for the issuance, from
time to time, of up to $600 million aggregate principal amount of Medium-Term
Notes, which will be fully and 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. These notes are also guaranteed by us. The following
condensed financial statements are required to be disclosed by SEC regulations
and represent those of KEDLI and KeySpan as guarantor of the Medium- Term Notes.
Statement of Income
(In Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2001 Year Ended December 31, 2000
- --------------------- -------------------------------------------------------------------------------------------------------------
Guarantor KEDLI Eliminations Consolidated Guarantor KEDLI Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Revenues $5,743,422 $ 889,693 $ - $ 6,633,115 $ 4,285,737 $ 794,965 $ - $ 5,080,702
---------- --------- -------------- ----------- ------------- ---------- -------------- --------------
Operating Expenses
Purchased gas 1,706,333 464,780 - 2,171,113 1,000,593 408,087 - 1,408,680
Fuel and purchased
power 538,532 - - 538,532 460,841 - - 460,841
Operations and
maintenance 2,069,653 45,106 - 2,114,759 1,597,131 127,780 - 1,724,911
Intercompany expense (87,738) 87,738 - - (10,718) 10,718 - -
Depreciation and
amortization 502,864 56,274 - 559,138 284,905 46,017 - 330,922
Operating taxes 357,720 91,204 - 448,924 329,252 92,684 - 421,936
---------- --------- -------------- ----------- ------------- ---------- -------------- --------------
Total Operating
Expenses 5,087,364 745,102 - 5,832,466 3,662,004 685,286 - 4,347,290
---------- --------- -------------- ----------- ------------- ---------- -------------- --------------
Operating Income 656,058 144,591 - 800,649 623,733 109,679 - 733,412
Other Income and
(Deductions) 22,566 9,721 (25,081) 7,206 13,388 (707) (24,767) (12,086)
---------- --------- -------------- ----------- ------------- ---------- -------------- --------------
Income (Loss) before
interest charges and
income taxes 678,624 154,312 (25,081) 807,855 637,121 108,972 (24,767) 721,326
Interest Expense 313,345 65,206 (25,081) 353,470 172,425 53,656 (24,767) 201,314
Income Taxes 182,374 28,319 - 210,693 198,900 18,362 - 217,262
---------- --------- -------------- ----------- ------------- ---------- -------------- --------------
Earnings from
Continuing Operations $182,905 $60,787 $ - $243,692 $265,796 $36,954 $ - $302,750
- -----------------------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- ----------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1999
- ------------------------------ --------------------------------------------------------------------------------
Guarantor KEDLI Eliminations Consolidated
- ------------------------------ ------------------ ------------------ ------------------ --------------------
Revenues $ 2,317,525 $ 637,088 $ - $ 2,954,613
------------------ ------------------ ------------------ --------------------
Operating Expenses
Purchased gas 459,508 284,924 - 744,432
Fuel and purchased power 17,252 - - 17,252
Operations and
maintenance 981,331 109,835 - 1,091,166
Intercompany expense (10,793) 10,793 - -
Depreciation and
amortization 220,639 32,801 - 253,440
Operating taxes 282,521 83,633 - 366,154
------------------ ------------------ ------------------ --------------------
Total Operating Expenses 1,950,458 521,986 - 2,472,444
------------------ ------------------ ------------------ --------------------
Operating Income 367,067 115,102 - 482,169
Other Income and
(Deductions) 96,884 159 (50,488) 46,555
------------------ ------------------ ------------------ --------------------
Income (Loss) before
interest charges and
income taxes 463,951 115,261 (50,488) 528,724
Interest Expense 133,751 50,488 (50,488) 133,751
Income Taxes 113,106 23,256 - 136,362
------------------ ------------------ ------------------ --------------------
Earnings From
Continuing Operations $ 217,094 $ 41,517 - $ 258,611
- ----------------------------------------------------------------------------------------------------------------
Balance Sheet (In Thousands of dollars)
December 31, 2001 December 31, 2000
- -----------------------------------------------------------------------------------------------------------------------------------
Guarantor KEDLI Eliminations Consolidated Guarantor KEDLI Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash and temporary cash
investments $ 159,252 $ - $ - $ 159,252 $ 83,329 $ - $ - $ 83,329
Accounts receivable, net 1,540,082 233,013 (500,496) 1,272,599 1,991,904 277,632 (558,222) 1,711,314
Other current assets 454,319 112,317 - 566,636 442,660 93,842 - 536,502
----------- ----------- ------------ ----------- ----------- ---------- ------------ -----------
2,153,653 345,330 (500,496) 1,998,487 2,517,893 371,474 (558,222) 2,331,145
----------- ----------- ------------ ----------- ----------- ---------- ------------ -----------
Investment Held for
Disposal 191,055 - - 191,055 184,036 - - 184,036
Equity Investments 756,111 - (532,862) 223,249 732,058 - (532,862) 199,196
----------- ----------- ------------ ----------- ----------- ---------- ------------ -----------
Property
Gas 4,074,894 1,629,963 - 5,704,857 3,845,803 1,500,996 - 5,346,799
Other 4,231,262 - - 4,231,262 3,596,818 - - 3,596,818
Accumulated depreciation
and depletion (3,035,788) (294,400) (3,330,188) (2,645,381) (268,260) (2,913,641)
----------- ----------- ------------ ----------- ----------- ---------- ------------ -----------
5,270,368 1,335,563 - 6,605,931 4,797,240 1,232,736 - 6,029,976
----------- ----------- ------------ ----------- ----------- ---------- ------------ -----------
Deferred Charges 2,571,029 199,855 - 2,770,884 2,355,985 207,127 - 2,563,112
----------- ----------- ------------ ----------- ----------- ---------- ------------ -----------
----------- ----------- ------------ ----------- ----------- ---------- ------------ -----------
Total Assets $10,942,216 $ 1,880,748 $(1,033,358) $11,789,606 $10,587,212 $1,811,337 $(1,091,084) $11,307,465
=========== =========== ============ =========== =========== ========== ============ ===========
LIABILITIES AND
CAPITALIZATION
Current Liabilities
Accounts payable and
accrued expenses $ 975,873 $ 115,557 $ - $ 1,091,430 $ 1,268,147 $ 196,537 $ - $ 1,464,684
Notes payable 1,048,450 - - 1,048,450 1,300,237 - - 1,300,237
Other current
liabilities 220,985 23,844 - 244,829 218,767 20,407 - 239,174
------------ ----------- ------------ ----------- ----------- ---------- ------------ -----------
2,245,308 139,401 - 2,384,709 2,787,151 216,944 - 3,004,095
------------ ----------- ------------ ----------- ----------- ---------- ------------ -----------
Intercompany Accounts
Payable - 324,592 (324,592) - - 382,318 (382,318) -
------------ ----------- ------------ ----------- ----------- ---------- ------------ -----------
Deferred Credits and Other
Liabilities
Deferred income tax 593,300 4,772 - 598,072 400,674 (26,094) - 374,580
Other deferred credits
and liabilities 841,662 100,452 - 942,114 658,149 112,239 - 770,388
------------ ----------- ------------ ----------- ----------- ---------- ------------ -----------
1,434,962 105,224 - 1,540,186 1,058,823 86,145 - 1,144,968
------------ ----------- ------------ ----------- ----------- ---------- ------------ -----------
Capitalization
Common shareholders'
equity 2,812,837 610,627 (532,862) 2,890,602 2,798,652 550,026 (532,862) 2,815,816
Preferred stock 84,077 - - 84,077 84,205 - - 84,205
Long-term debt 4,172,649 700,904 (175,904) 4,697,649 3,716,441 575,904 (175,904) 4,116,441
------------ ----------- ------------ ----------- ----------- ---------- ------------ -----------
Total Capitalization 7,069,563 1,311,531 (708,766) 7,672,328 6,599,298 1,125,930 (708,766) 7,016,462
------------ ----------- ------------ ----------- ----------- ---------- ------------ -----------
Minority Interest in
Subsidiary Companies 192,383 - - 192,383 141,940 - - 141,940
------------ ----------- ------------ ----------- ----------- ---------- ------------ -----------
Total Liabilities and
Capitalization $ 10,942,216 $ 1,880,748 $(1,033,358) $11,789,606 $10,587,212 $1,811,337 $(1,091,084) $11,307,465
============ =========== ============ =========== =========== ========== ============ ===========
Statement of Cash Flows
(In Thousands of dollars)
- ------------------------------------------ ---------------------------------------------- ----------------------------------------
Year Ended December 31, 2001 Year Ended December 31, 2000
----------------------------------------------------------------------------------------
Guarantor KEDLI Consolidated Guarantor KEDLI Consolidated
----------------------------------------------------------------------------------------
Operating Activities
Net Cash Provided by Operating Activities $ 825,887 $ 64,294 $ 890,181 $ 325,988 $ 112,738 $ 438,726
----------------------------------------------------------------------------------------
Investing Activities
Capital expenditures (928,191) (131,568) (1,059,759) (518,058) (114,977) (633,035)
Other 18,452 - 18,452 (2,238,775) - (2,238,775)
----------------------------------------------------------------------------------------
Net Cash (Used in) Investing Activities (909,739) (131,568) (1,041,307) (2,756,833) (114,977) (2,871,810)
----------------------------------------------------------------------------------------
Financing Activities
Treasury stock issued (purchased) 88,786 - 88,786 72,289 - 72,289
Receipt/payment of dividends - - - 125,000 (125,000) -
Redemption of preferred stock - - - (363,000) - (363,000)
Issuance (payment) of debt, net 251,919 125,000 376,919 2,633,962 400,000 3,033,962
Debt received (paid) - - - 397,000 (397,000) -
Common and preferred stock dividends paid (251,502) - (251,502) (260,001) - (260,001)
Settlement of interest rate lock and other 12,846 - 12,846 (95,439) - (95,439)
Net intercompany accounts payable 57,726 (57,726) - (124,239) 124,239 -
----------------------------------------------------------------------------------------
Net Cash Provided by
(Used in) Financing Activities 159,775 67,274 227,049 2,385,572 2,239 2,387,811
----------------------------------------------------------------------------------------
Net (Decrease) Increase
in Cash and Cash Equivalents $ 75,923 $ - $ 75,923 $ (45,273) $ - $ (45,273)
========================================================================================
Cash and Cash Equivalents
at Beginning of Period $ 83,329 $ - $ 83,329 $ 128,602 $ - $ 128,602
Net (Decrease) Increase
in Cash and Cash Equivalents $ 75,923 $ - $ 75,923 $ (45,273) $ - $ (45,273)
----------------------------------------------------------------------------------------
Cash and Cash Equivalents
at End of Period $ 159,252 $ - $ 159,252 $ 83,329 $ - $ 83,329
========================================================================================
(In Thousands of dollars)
--------------------------------------
Year Ended December 31, 1999
--------------------------------------
Guarantor KEDLI Consolidated
--------------------------------------
Operating Activities
Net Cash Provided by Operating Activities $ 564,109 $ 24,896 $ 589,005
---------------------------------------
Investing Activities
Capital expenditures (569,838) (102,007) (671,845)
Other (23,819) - (23,819)
---------------------------------------
Net Cash (Used in) Investing Activities (593,657) (102,007) (695,664)
---------------------------------------
Financing Activities
Treasury stock issued (purchased) (299,243) - (299,243)
Receipt/payment of dividends - - -
Redemption of preferred stock - - -
Issuance (payment) of debt, net (131,527) - (131,527)
Debt received (paid) - - -
Common and preferred stock dividends paid (284,327) - (284,327)
Settlement of interest rate lock and other 7,582 - 7,582
Net intercompany accounts payable (77,111) 77,111 -
---------------------------------------
Net Cash Provided by
(Used in) Financing Activities (784,626) 77,111 (707,515)
---------------------------------------
Net (Decrease) Increase
in Cash and Cash Equivalents $ (814,174) $ - $ (814,174)
=======================================
Cash and Cash Equivalents
at Beginning of Period $ 942,776 $ - $ 942,776
Net (Decrease) Increase
in Cash and Cash Equivalents $ (814,174 $ - $ (814,174)
---------------------------------------
Cash and Cash Equivalents
at End of Period $ 128,602 $ - $ 128,602
=======================================
Note 14. Eastern/EnergyNorth Acquisition
On November 8, 2000, we purchased all of the outstanding stock of Eastern for
$64.56 per share in cash and all of the outstanding common stock of ENI for
$61.46 per share in cash. The increased size of KeySpan should enable us to
provide enhanced cost-effective customer service and to capitalize on the
above-average growth opportunities for natural gas in the Northeast and provide
additional resources to our unregulated businesses.
The transactions have been accounted for using the purchase method of accounting
for business combinations. Accordingly, the accompanying Consolidated Statement
of Income includes Eastern and ENI results commencing November 8, 2000. The
purchase price was allocated to the net assets acquired based upon their fair
value. The historical cost basis of Eastern's and ENI's assets and liabilities,
with minor exceptions, was determined to represent the fair value due to the
existence of regulatory-approved rate plans based upon the recovery of
historical costs and a fair return thereon. The excess of the purchase price
over the fair value of the net assets acquired was approximately $1.5 billion
and was recorded as goodwill.
The following is the comparative unaudited proforma condensed financial
information for the years ended December 31, 2000 and 1999. The proforma
disclosures reflect the results of the operations of Eastern and ENI as if our
acquisitions were consummated on the first day of the reporting periods.
Year Ended Year Ended
December 31, 2000 December 31, 1999
- -------------------------------------------------------------------------
(In Thousands of Dollars, Except Per Share Amounts)
Revenues 6,130,158 4,058,178
Operating Income 671,081 568,754
Net Income 114,393 174,923
- -------------------------------------------------------------------------
Earnings Per Share $0.71 $1.01
- -------------------------------------------------------------------------
Included in the 2000 proforma earnings, are merger related costs of $76.0
million, after-tax, recorded by Eastern and ENI in connection with our
acquisition of these companies. Excluding these costs, proforma earnings per
share for the year ended December 31, 2000 were $1.27. These proforma results
may not be indicative of future results. Further, the consolidated proforma
results for 2000 and 1999 do not take into account: (i) continued gas sales
growth throughout our service territories, especially on Long Island and in New
England; (ii) earnings enhancement from our gas exploration and production
operations; and (iii) the continued successful integration of acquired companies
providing energy-related services within our Energy Services segment.
Note 15. 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. During the year ended
December 31, 2001 we reduced this liability by $4.1 million as a result of lower
than anticipated costs per employee and recorded a corresponding reduction to
Goodwill. This severance program is targeted to reduce the workforce by 500
employees and will continue through 2002. At December 31, 2001 we paid $10.1
million for these programs and had a remaining liability of $8.5 million.
Note 16. Shareholder Rights Plan
On March 30, 1999 our Board of Directors adopted a Shareholder Rights Plan (the
"Plan") designed to protect shareholders in the event of a proposed takeover.
The Plan creates a mechanism that would dilute the ownership interest of a
potential unauthorized acquirer. The Plan establishes one preferred stock
purchase "right" for each outstanding share of common stock to shareholders of
record on April 14, 1999. Each right, when exercisable, entitles the holder to
purchase 1/100th of a share of Series D Preferred Stock, at a price of $95.00.
The rights generally become exercisable following the acquisition of more than
20 percent of our common stock without the consent of the Board of Directors.
Prior to becoming exercisable, the rights are redeemable by the Board of
Directors for $0.01 per right. If not so redeemed, the rights will expire on
March 30, 2009.
Note 17. Supplemental Gas and Oil Disclosures (Unaudited)
This information includes amounts attributable to 100% of Houston Exploration
and KeySpan Exploration and Production, LLC at December 31, 2001. Shareholders
other than KeySpan had a minority interest of approximately 33% in Houston
Exploration at December 31, 2001 and a 30% minority interest in 2000. Gas and
oil operations, and reserves, were located in the United States in all years.
Capitalized Costs Relating To Gas and Oil Producing Activities
- ----------------------------------------------------------------------- ---------------------------- ---------------------------
At December 31, 2001 2000
- ----------------------------------------------------------------------- ---------------------------- ---------------------------
(In Thousands of Dollars)
Unproved properties not being amortized $ 195,478 $ 166,478
Properties being amortized - productive and nonproductive 1,575,131 1,235,438
- ----------------------------------------------------------------------- ---------------------------- ---------------------------
Total capitalized costs 1,770,609 1,401,916
Accumulated depletion (796,722) (577,240)
- ----------------------------------------------------------------------- ---------------------------- ---------------------------
Net capitalized costs $ 973,887 $ 824,676
- ----------------------------------------------------------------------- ---------------------------- ---------------------------
The following is a break-out of the costs which are excluded from the
amortization calculation as of December 31, 2001, by year of acquisition: 2001-
$75.5 million , 2000 - $33.2 million and prior years $86.7 million. We cannot
accurately predict when these costs will be included in the amortization base,
but it is expected that these costs will be evaluated within the next five
years.
Costs Incurred in Property Acquisition, Exploration and Development Activities
Year Ended December 31, 2001 2000 1999
- -------------------------------------- -------------------------- ------------------------- --------------------------
(In Thousands of Dollars)
Acquisition of properties-
Unproved properties $ 31,718 $ 7,992 $ 13,107
Proved properties 85,435 40,960 42,573
Exploration 74,497 70,511 39,649
Development 191,927 111,078 87,965
- -------------------------------------- -------------------------- ------------------------- --------------------------
Total costs incurred $ 383,577 $ 230,541 $ 183,294
- -------------------------------------- -------------------------- ------------------------- --------------------------
Results of Operations from Gas and Oil Producing Activities*
- ------------------------------------------------------------
Year Ended December 31, 2001 2000 1999
- -------------------------------------------------------- ---------------- ---------------------- ---------------------
(In Thousands of Dollars)
Revenues $ 398,089 $ 274,209 $ 150,581
- -------------------------------------------------------- ---------------- ---------------------- ---------------------
Production and lifting costs 26,179 36,929 23,851
Depletion 174,249 95,364 74,051
- -------------------------------------------------------- ---------------- ---------------------- ---------------------
Total expenses 200,428 132,293 97,902
- -------------------------------------------------------- ---------------- ---------------------- ---------------------
Income before taxes 197,661 141,916 52,679
Income taxes 68,081 48,790 17,477
- -------------------------------------------------------- ---------------- ---------------------- ---------------------
Results of operations $ 129,580 $ 93,126 $ 35,202
- -------------------------------------------------------- ---------------- ---------------------- ---------------------
*(excluding corporate overhead and interest costs)
The gas and oil reserves information is based on estimates of proved reserves
attributable to the interest of Houston Exploration and KeySpan Exploration and
Production, LLC as of December 31 for each of the years presented. These
estimates principally were prepared by Netherland, Sewell & Associates, Inc. and
Miller and Lents, Ltd., independent petroleum consultants. Proved reserves are
estimated quantities of natural gas and crude oil which geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions.
Reserve Quantity Information Natural Gas (MMcf)
- -----------------------------------------------
At December 31, 2001 2000 1999
- ---------------------------------------------- ------------------ -------------------------- -------------------------
Proved reserves
Beginning of year 545,858 534,306 470,447
Revisions of previous estimates (39,994) 4,479 45,510
Extensions and discoveries 86,401 77,645 70,741
Production (90,754) (78,493) (69,679)
Purchases of reserves in place 84,148 7,921 20,779
Sales of reserves in place - - (3,492)
- ---------------------------------------------- ------------------ -------------------------- -------------------------
Proved reserves-
End of year (1) 585,659 545,858 534,306
- ---------------------------------------------- ------------------ -------------------------- -------------------------
Proved developed reserves-
Beginning of year 431,536 399,482 369,931
- ---------------------------------------------- ------------------ -------------------------- -------------------------
End of year (2) 448,921 431,536 399,482
- ---------------------------------------------- ------------------ -------------------------- -------------------------
(1) Includes minority interest of 188,077; 167,730 and 189,427; in 2001, 2000,
and 1999, respectively.
(2) Includes minority interest of 148,593; 133,271; and 143,043; in 2001, 2000,
and 1999, respectively.
Crude Oil, Condensate and Natural Gas Liquids (MBbls)
- -----------------------------------------------------
At December 31, 2001 2000 1999
- ------------------------------------------- --------------------------- ------------------------- --------------------------
Proved reserves
Beginning of year 7,912 3,136 1,650
Revisions of previous estimates (289) 108 237
Extensions and discoveries 3,061 4,326 1,574
Production (536) (320) (258)
Purchases of reserves in place 115 662 2
Sales of reserves in place (29) - (69)
- ------------------------------------------- --------------------------- ------------------------- --------------------------
Proved reserves-
End of year (1) 10,234 7,912 3,136
- ------------------------------------------- --------------------------- ------------------------- --------------------------
Proved developed reserves-
Beginning of year 2,126 2,059 1,498
- ------------------------------------------- --------------------------- ------------------------- --------------------------
End of year (2) 2,479 2,126 2,059
- ------------------------------------------- --------------------------- ------------------------- --------------------------
(1) Includes minority interest of 2,186; 1,695; and 890; in 2001,2000, and 1999,
respectively.
(2) Includes minority interest of 821; 573; and 647 in 2001,2000, and 1999,
respectively.
The standardized measure of discounted future net cash flows was prepared by
applying year-end prices of gas and oil to the proved reserves. The standardized
measure does not purport, nor should it be interpreted, to present the fair
value of gas and oil reserves of Houston Exploration or KeySpan Exploration and
Production LLC. An estimate of fair value would also take into account, among
other things, the recovery of reserves not presently classified as proved,
anticipated future changes in prices and costs, and a discount factor more
representative of the time value of money and the risks inherent in reserve
estimates.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Gas and Oil Reserves
- ------------------------------------------------------------------------------------------------
At December 31, 2001 2000
- --------------------------------------------------------------------- ----------------------------- -------------------------
(In Thousands of Dollars)
Future cash flows $ 1,580,077 $ 5,415,587
Future costs -
Production (316,421) (558,384)
Development (227,158) (182,242)
- --------------------------------------------------------------------- ----------------------------- -------------------------
Future net inflows before income tax 1,036,498 4,674,961
Future income taxes (221,324) (1,299,965)
- --------------------------------------------------------------------- ----------------------------- -------------------------
Future net cash flows 815,174 3,374,996
10% discount factor (228,988) (1,209,237)
- --------------------------------------------------------------------- ----------------------------- -------------------------
Standardized measure of discounted future net cash flows (1) $ 586,186 $ 2,165,759
- --------------------------------------------------------------------- ----------------------------- -------------------------
(1) Includes minority interest of 182,555 and 653,046 in 2001 and 2000,
respectively.
Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserve Quantities
- --------------------------------------------------------------------------------------------------
Year Ended December 31, 2001 2000 1999
- ------------------------------------------------------- ----------------------- ----------------------- -------------------------
(In Thousands of Dollars)
Standardized measure -
beginning of year $ 2,165,759 $ 480,632 $ 396,060
Sales and transfers, net of production costs (359,163) (240,702) (126,730)
Net change in sales and transfer prices,
net of production costs (2,250,252) 2,142,932 47,330
Extensions and discoveries and improved
recovery, net of related costs 117,326 472,658 106,076
Changes in estimated future development costs (23,395) (38,839) (25,730)
Development costs incurred during the period
that reduced future development costs 75,652 77,197 40,563
Revisions of quantity estimates (52,928) 24,650 51,375
Accretion of discount 293,581 54,460 41,293
Net change in income taxes 666,373 (706,074) (47,097)
Net purchases of reserves in place 51,674 23,118 19,018
Sales of reserves in place (133) - -
Changes in production rates (timing) and other (98,308) (124,273) (21,526)
- ------------------------------------------------------ --------------------- ----------------------- --------------------------
Standardized measure -
end of year $ 586,186 $ 2,165,759 $ 480,632
- ------------------------------------------------------ --------------------- ----------------------- --------------------------
Average Sales Prices and Production Costs Per Unit
- --------------------------------------------------
Year Ended December 31, 2001 2000 1999
- --------------------------------------------------------------- ------------------------ -------------------- -------------------
Average sales price*
Natural gas ($/MCF) 4.09 3.97 2.14
Oil, condensate and natural gas liquid ($/Bbl) 23.09 27.29 16.41
Production cost per equivalent MCF ($) 0.28 0.55 0.26
- --------------------------------------------------------------- ------------------------ -------------------- -------------------
*Represents the cash price received which excludes the effect of any hedging
transactions.
Acreage
- -------
At December 31, 2001 Gross Net
- -------------------------------------- ------------------ -------------------
Producing 392,419 264,072
Undeveloped 303,357 274,711
- -------------------------------------- ------------------ -------------------
Number of Producing Wells
- -------------------------
At December 31, 2001 Gross Net
- ----------------------- ---------------------- -----------------------
Gas Wells 1,550 1,086.6
Oil Wells 6 4.9
- ----------------------- ---------------------- -----------------------
Drilling Activity (Net)
- -----------------------
Year Ended December 31, 2001 2000 1999
- ------------------------- ------------------------------- --------------------------------- -------------------------------------
Producing Dry Total Producing Dry Total Producing Dry Total
--------- --- ----- --------- --- ----- --------- --- -----
Net developmental wells 51.9 10.2 62.1 40.4 4.4 44.8 29.7 3.1 32.8
Net exploratory wells 5.3 4.3 9.6 5.1 1.7 6.8 2.9 1.0 3.9
Wells in Process
- ----------------
At December 31, 2001 Gross Net
- ------------------------ --------------------- -----------------------------
Exploratory - -
Developmental 6 4.3
- ------------------------ --------------------- -----------------------------
Note 18. Summary of Quarterly Information (Unaudited)
The following is a table of financial data for each quarter of KeySpan's year
ended December 31, 2001.
(In Thousands of Dollars, Except Per Share Amounts)
Quarter Ended Quarter Ended Quarter Ended Quarter Ended
3/31/01 6/30/01 (a) 9/30/01 (b) 12/31/01 (c)
- ------------------------------------------------------------------------------------------------------------------------------------
Operating revenues 2,575,088 1,339,302 1,102,439 1,616,286
Earnings before interest and taxes 462,104 85,224 49,792 210,735
Earnings (loss) from continuing operations 222,638 (11,893) (38,900) 65,943
Earnings (loss) from discontinued operations 661 3,892 2,253 (26,244)
Earnings (loss) for common stock 223,299 (8,001) (36,647) 39,699
Basic earnings per common stock from
continuing operations (d) 1.63 (0.09) (0.28) 0.48
Basic earnings per common stock from
discontinued operations (d) - 0.03 0.02 (0.19)
Basic earnings per common stock (d) 1.63 (0.06) (0.26) 0.29
Diluted earnings per common stock (d) 1.61 (0.06) (0.26) 0.28
- ------------------------------------------------------------------------------------------------------------------------------------
Dividends declared 0.445 0.445 0.445 0.445
- ------------------------------------------------------------------------------------------------------------------------------------
(a) Reflects costs to complete work on certain construction projects, as well
as, operating losses of the Roy Kay Companies of $35.6 million after-tax.
(b) Reflects the reversal of a previously recorded loss provision regarding
certain pending rate refund issues of $20.1 million after-tax. Also includes
losses incurred by the Roy Kay Companies of $56.6 million after-tax related to
the discontinuance of the general contracting activities of these companies.
(c)Reflects an after-tax non-cash impairment charge of $26.2 million to
recognize the effect of lower wellhead prices on the valuation of proved gas
reserves, as well as, after-tax operating losses of the Roy Kay Companies of
$2.8 million.
(d) Quarterly earnings per share are based on the average number of shares
outstanding during the quarter. Because of the changing number of common shares
outstanding in each quarter, the sum of quarterly earnings per share does not
equal earnings per share for the year.
The following is a table of financial data for each quarter of KeySpan's year
ended December 31, 2000.
(In Thousands of Dollars, Except Per Share Amounts)
Quarter Ended Quarter Ended Quarter Ended Quarter Ended
3/31/00 6/30/00 9/30/00 12/31/00 (a)
- ------------------------------------------------------------------------------------------------------------------------------------
Operating revenues 1,316,613 947,588 947,137 1,869,364
Earnings before interest and taxes 308,441 136,221 90,272 186,392
Earnings (loss) from continuing operations 163,553 47,080 13,154 60,850
Earnings (loss) from discontinued operations - - - (1,943)
Earnings for common stock 163,553 47,080 13,154 58,907
Basic earnings per common stock from
continuing operations (b) 1.22 0.35 0.10 0.46
Basic earnings per common stock from
discontinued operations (b) - - - (0.02)
Basic earnings per common stock (b) 1.22 0.35 0.10 0.44
Diluted earnings per common stock (b) 1.22 0.35 0.10 0.43
- ------------------------------------------------------------------------------------------------------------------------------------
Dividends declared 0.445 0.445 0.445 0.445
- ------------------------------------------------------------------------------------------------------------------------------------
(a) Reflects an after-tax charge of $41.1 million relating to an early
retirement and severance program.
(b) Quarterly earnings per share are based on the average number of shares
outstanding during the quarter. Because of the changing number of common shares
outstanding in each quarter, the sum of quarterly earnings per share does not
equal earnings per share for the year.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of KeySpan Corporation d/b/a/ KeySpan
Energy:
We have audited the accompanying Consolidated Balance Sheet and Consolidated
Statement of Capitalization of KeySpan Corporation (a New York corporation) and
subsidiaries as of December 31, 2001 and December 31, 2000 and the related
Consolidated Statements of Income, Retained Earnings, Comprehensive Income and
Cash Flows for each of the three years in the period ended December 31, 2001.
These financial statements are the responsibility of the KeySpan Corporation's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position and capitalization of KeySpan
Corporation and subsidiaries as of December 31, 2001 and December 31, 2000 and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule listed in Item 14 is the
responsibility of the KeySpan Corporation's management and is presented for the
purpose of complying with the Securities and Exchange Commission's rules and is
not part of the basic financial statements. This schedule has been subjected to
the auditing procedures applied in the audits of the basic financial statements
and, in our opinion, fairly states in all material respects the financial data
required to be set forth therein in relation to the basic financial statements
taken as a whole.
ARTHUR ANDERSEN LLP
February 4, 2002
New York, New York
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure
None.
Part III
Item 10. Directors and Executive Officers of the Registrant
A definitive proxy statement was filed with the SEC on or about April 4, 2002
(the "Proxy Statement"). The information required by this item is set forth
under the caption "Executive Officers of the Company" in Part I hereof and under
the captions "Proposal 1. Election Of Directors" and "Section 16(a) Beneficial
Ownership Reporting Compliance" contained in the Proxy Statement, which
information is incorporated herein by reference thereto.
Item 11. Executive Compensation
The information required by this item is set forth under the captions "Director
Compensation" and "Executive Compensation" in the Proxy Statement, which
information is incorporated herein by reference thereto.
Item 12. Security Ownership of Certain Beneficial Owners and Management The
information required by this item is set forth under the captions "Security
Ownership of Management" and "Security Ownership of Certain Beneficial Owners"
in the Proxy Statement, which information is incorporated herein by reference
thereto.
Item 13. Certain Relationships and Related Transactions
The information required by this item is set forth under the caption "Agreements
With Executives" and "Involvement in Certain Proceedings" in the Proxy
Statement, which information is incorporated herein by reference thereto.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) Required Documents
1. Financial Statements
The following consolidated financial statements of KeySpan and its subsidiaries
and report of independent accountants are included in Item 8 and are filed as
part of this Report:
Consolidated Statement of Income for the year ended December 31, 2001, the
year ended December 31, 2000 and the year ended December 31,1999.
Consolidated Statement of Retained Earnings for the year ended December 31,
2001, the year ended December 31, 2000 and the year ended December 31,
1999.
Consolidated Balance Sheet at December 31, 2001 and December 31, 2000.
Consolidated Statement of Capitalization at December 31, 2001 and December
31, 2000.
Consolidated Statement of Cash Flows for the year ended December 31, 2001,
the year ended December 31, 2000 and the year ended December 31,1999.
Notes to Consolidated Financial Statements
Report of Independent Accountants
2. Financial Statements Schedules
Consolidated Schedule of Valuation and Qualifying Accounts for the year ended
December 31, 2001, the year ended December 31, 2000 and the year ended December
31, 1999.
All other schedules are omitted because they are not applicable or the required
information is shown in the financial statements or notes thereto.
SCHEDULE OF VALUATION AND QUALIFYING ACCOUNTS
(In Thousands of Dollars)
Column A Column B Column C Column D Column E
- ----------------------------------------------- --------------- --------------------------------- -------------- ---------------
Additions
---------------------------------
Balance at Charged to Balance at
beginning costs and Net end of
Description of period expenses Acquisitions Deductions period
- ----------------------------------------------- --------------- --------------- ---------------- -------------- ---------------
Twelve months ended December 31, 2001
- -----------------------------------------------
Deducted from asset accounts:
Allowance for doubtful accounts $ 48,314 $ 66,500 - $ 42,515 $ 72,299
Additions to liability accounts:
Reserve for injuries and damages $ 40,700 $ 7,643 - $ 27,463 $ 20,880
Reserves for environmental expenditures $ 157,507 $ 115,942 - $ 15,800 $ 257,649
Twelve months ended December 31, 2000
- -----------------------------------------------
Deducted from asset accounts:
Allowance for doubtful accounts $ 20,294 $ 26,455 $ 19,208 $ 17,643 $ 48,314
Additions to liability accounts:
Reserve for injuries and damages $ 36,385 $ 20,074 $ 3,362 $ 19,121 $ 40,700
Reserves for environmental expenditures $ 128,011 - $ 42,637 $ 13,141 $ 157,507
Twelve months ended December 31, 1999
- -----------------------------------------------
Deducted from asset accounts:
Allowance for doubtful accounts $ 20,026 $ 15,793 - $ 15,525 $ 20,294
Additions to liability accounts:
Reserve for injuries and damages $ 29,075 $ 25,930 - $ 18,620 $ 36,385
Reserves for environmental expenditures $ 130,278 $ 5,000 - $ 7,267 $ 128,011
(b) Reports on Form 8-K
KeySpan filed Reports on Form 8-K on October 24, 2001, December 6, 2001, January
24, 2002 and February 26, 2002.
In our report on Form 8-K dated October 24, 2001, we disclosed that we had
issued a press release concerning, among other things, our earnings for the
third quarter ended September 30, 2001.
In our report on Form 8-K dated December 6, 2001, we disclosed that we had
issued a press release concerning, among other things, 2002 earnings guidance.
In our Report on Form 8-K, dated January 24, 2002, we disclosed our consolidated
earnings for the fiscal year ended December 31, 2001.
In our Report on Form 8-K, dated February 26, 2002, we disclosed an adjustment
to our earnings for the fiscal year ended December 31, 2001.
In our Report on Form 8-K, dated March 12, 2002, we disclosed that we had issued
a press release announcing, among other things, that we reached an agreement in
principle with the Long Island LIPA to extend LIPA's option to acquire our Long
Island power plants.
In our Report on Form 8-K, dated April 5, 2002, we disclosed that on March 29,
2002, our Board of Directors, upon recommendation of the Audit Committee,
determined not to renew the engagement of Arthur Andersen LLP as independent
public accountants and appointed Deloitte & Touche as our independent public
accountants.
(c) Exhibits
Exhibits listed below which have been filed with the SEC pursuant to the
Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as
amended, and which were filed as noted below, are hereby incorporated by
reference and made a part of this report with the same effect as if filed
herewith.
2* Purchase Agreement by and among Eastern Enterprises, Landgrove Corp. and
KeySpan Corporation for the acquisition of Midland Enterprises dated as of
January 23, 2002
3.1 Certificate of Incorporation of the Company effective April 16, 1998,
Amendment to Certificate of Incorporation of the Company effective May
26,1998, Amendment to Certificate of Incorporation of the Company effective
June 1, 1998, Amendment to the Certificate of Incorporation of the Company
effective April 7, 1999 and Amendment to the Certificate of Incorporation
of the Company effective May 20, 1999 (filed as Exhibit 3.1 to the
Company's Form 10-Q for the quarterly period ended June 30, 1999)
3.2 ByLaws of the Company in effect on September 10, 1998, as amended (filed as
Exhibit 3.1 to the Company's Form 8-K/A, Amendment No. 2, on September 29,
1998)
4.1-a Indenture, dated as of November 1, 2000, between KeySpan Corporation and
the Chase Manhattan Bank, as Trustee, with the respect to the issuance of
Debt Securities (filed as Exhibit 4-a to Amendment No. 1 to Form S-3
Registration Statement No. 333-43768 and filed as Exhibit 4-a to the
Company's Form 8-K on November 20, 2000)
4.1-b Form of Note issued in connection with the issuance of the 7.25% notes
issued on November 20, 2000 (filed as Exhibit 4-b to the Company's Form 8-K
on November 20, 2000)
4.1-c Form of Note issued in connection with the issuance of the 7.625% notes
issued on November 20, 2000 (filed as Exhibit 4-c to the Company's Form 8-K
on November 20, 2000)
4.1-d Form of Note issued in connection with the issuance of the 8.0% notes
issued on November 20, 2000 (filed as Exhibit 4-d to the Company's Form 8-K
on November 20, 2000)
4.1-e Form of Note issued in connection with the issuance of the 6.15% notes
issued on May 24, 2001 (filed as Exhibit 4 to the Company's Form 8-K on May
24, 2001)
4.2-a Indenture, dated December 1, 1999, between KeySpan and KeySpan Gas East
Corporation, the Registrants, and the Chase Manhattan Bank, as Trustee,
with respect to the issuance of Medium-Term Notes, Series A, (filed as
Exhibit 4-a to Amendment No. 1 to the Company's and KeySpan and KeySpan Gas
East Corporation's Form S-3 Registration Statement No. 333-92003)
4.2-b Form of Medium-Term Note issued in connection with the issuance of the 7
7/8% notes on February 1, 2000 (filed as Exhibit 4 to the Company's Form
8-K on February 1, 2000)
4.2-c Form of Medium-Term Note issued in connection with the issuance of the
6.9% notes on January 19, 2001 (filed as Exhibit 4.3 to the Company's Form
10-K for the year ended December 31, 2000)
4.3-a Participation Agreements dated as of February 1, 1989, between NYSERDA and
The Brooklyn Union Gas Company relating to the Adjustable Rate Gas
Facilities Revenue Bonds ("GFRBs") Series 1989A and Series 1989B (filed as
Exhibit 4 to The Brooklyn Union Gas Company's Form 10-K for the year ended
September 30, 1989)
4.3-b Indenture of Trust, dated February 1, 1989, between NYSERDA and
Manufacturers Hanover Trust Company, as Trustee, relating to the Adjustable
Rate GFRBs Series 1989A and 1989B (filed as Exhibit 4 to the Brooklyn Union
Gas Company's Form 10-K for the year ended September 30, 1989)
4.3-c First Supplemental Participation Agreement dated as of May 1, 1992 to
Participation Agreement dated February 1, 1989 between NYSERDA and The
Brooklyn Union Gas Company relating to Adjustable Rate GFRBs, Series 1989A
& B (filed as Exhibit 4 to The Brooklyn Union Gas Company's Form 10-K for
the year ended September 30, 1992)
4.3-d First Supplemental Trust Indenture dated as of May 1, 1992 to Trust
Indenture dated February 1, 1989 between NYSERDA and Manufacturers Hanover
Trust Company, as Trustee, relating to Adjustable Rate GFRBs, Series 1989A
& B (filed as Exhibit 4 to The Brooklyn Union Gas Company's Form 10-K for
the year ended September 30, 1992)
4.4-a Participation Agreement, dated as of July 1, 1991, between NYSERDA and The
Brooklyn Union Gas Company relating to the GFRBs Series 1991A and 1991B
(filed as Exhibit 4 to The Brooklyn Union Gas Company's Form 10-K for the
year ended September 30, 1991)
4.4-b Indenture of Trust, dated as of July 1, 1991, between NYSERDA and
Manufacturers Hanover Trust Company, as Trustee, relating to the GFRBs
Series 1991A and 1991B (filed as Exhibit 4 to The Brooklyn Union Gas
Company's Form 10-K for the year ended September 30, 1991)
4.5-a Participation Agreement, dated as of July 1, 1992, between NYSERDA and The
Brooklyn Union Gas Company relating to the GFRBs Series 1993A and 1993B
(filed as Exhibit 4 to The Brooklyn Union Gas Company's Form 10-K for the
year ended September 30, 1992)
4.5-b Indenture of Trust, dated as of July 1, 1992, between NYSERDA and Chemical
Bank, as Trustee, relating to the GFRBs Series 1993A and 1993B (filed as
Exhibit 4 to The Brooklyn Union Gas Company Form 10-K for the year ended
September 30, 1992)
4.6-a First Supplemental Participation Agreement dated as of July 1, 1993 to
Participation Agreement dated as of June 1, 1990, between NYSERDA and The
Brooklyn Union Gas Company relating to GFRBs Series C (filed as Exhibit 4
to The Brooklyn Union Gas Company's Form 10-K for the year ended September
30, 1993)
4.6-b First Supplemental Trust Indenture dated as of July 1, 1993 to Trust
Indenture dated as of June 1, 1990 between NYSERDA and Chemical Bank, as
Trustee, relating to GFRBs Series C (filed as Exhibit 4 to The Brooklyn
Union Gas Company's Form 10-K for the year ended September 30, 1993)
4.7-a Participation Agreement, dated July 15, 1993, between NYSERDA and Chemical
Bank as Trustee, relating to the GFRBs Series D-1 1993 and Series D-2 1993
(filed as Exhibit 4 to The Brooklyn Union Gas Company's Form S-8
Registration Statement No. 33-66182)
4.7-b Indenture of Trust, dated July 15, 1993, between NYSERDA and Chemical Bank
as Trustee, relating to the GFRBs Series D-1 1993 and D-2 1993 (filed as
Exhibit 4 to The Brooklyn Union Gas Company's Form S-8 Registration
Statement No. 33-66182)
4.8-a Participation Agreement, dated January 1, 1996, between NYSERDA and The
Brooklyn Union Gas Company relating to GFRBs Series 1996 (filed as Exhibit
4 to The Brooklyn Union Gas Company's Form 10-K for the year ended
September 30, 1996)
4.8-b Indenture of Trust, dated January 1, 1996, between NYSERDA and Chemical
Bank, as Trustee, relating to GFRBs Series 1996 (filed as Exhibit 4 to The
Brooklyn Union Gas Company's Form 10-K for the year ended September 30,
1996)
4.9-a Participation Agreement, dated as of January 1, 1997, between NYSERDA and
The Brooklyn Union Gas Company relating to GFRBs 1997 Series A (filed as
Exhibit 4 to the Company's Form 10-K for the year ended September 30, 1997)
4.9-b Indenture of Trust, dated January 1, 1997, between NYSERDA and Chase
Manhattan Bank, as Trustee, relating to GFRBs 1997 Series A (filed as
Exhibit 4 to the Company's Form 10-K for the year ended September 30, 1997)
4.9-c Supplemental Trust Indenture, dated as of January 1, 2000, by and between
New York State NYSERDA and The Chase Manhattan Bank, as Trustee, relating
to the GFRBs 1997 Series A (filed as Exhibit 4.11 to the Company's Form
10-K for the year ended December 31, 1999)
4.10-a Participation Agreement dated as of December 1, 1997 by and between
NYSERDA and Long Island Lighting Company relating to the 1997 EFRBs, Series
A (filed as Exhibit 10(a) to the Company's Form 10-Q for the quarterly
period ended September 30, 1998)
4.10-b Indenture of Trust dated as of December 1, 1997 by and between NYSERDA
and The Chase Manhattan Bank, as Trustee, relating to the 1997 Electric
Facilities Revenue Bonds (EFRBs), Series A (filed as Exhibit 10(a) to the
Company's Form 10-Q for the quarterly period ended September 30, 1998)
4.11-a Participation Agreement, dated as of October 1, 1999, by and between
NYSERDA and KeySpan Generation LLC relating to the 1999 Pollution Control
Refunding Revenue Bonds, Series A (filed as Exhibit 4.10 to the Company's
Form 10-K for the year ended December 31, 1999)
4.11-b Trust Indenture, dated as of October 1, 1999, by and between NYSERDA and
The Chase Manhattan Bank, as Trustee, relating to the 1999 Pollution
Control Refunding Revenue Bonds, Series A (filed as Exhibit 4.10 to the
Company's Form 10-K for the year ended December 31, 1999)
4.12 Indenture dated as of December 1, 1989 between Boston Gas Company and The
Bank of New York, Trustee (Filed as Exhibit 4.2 to Boston Gas Company's
Form S-3 (File No. 33-31869).
4.13 Agreement of Registration, Appointment and Acceptance dated as of November
18, 1992 among Boston Gas Company, The Bank of New York as Resigning
Trustee, and The First National Bank of Boston as Successor Trustee. (Filed
as an exhibit to Boston Gas Company's S-3 Registration S (File No.
33-31869))
4.14 Second Amended and Restated First Mortgage Indenture for Colonial Gas
Company dated as of June 1, 1992 (filed as Exhibit 4(b) to Colonial Gas
Company's Form 10-Q for the quarter ended June 30, 1992)
4.15 First Supplemental Indenture for Colonial Gas Company dated as of June 15,
1992 (filed as Exhibit 4(c) to Colonial Gas Company's Form 10-Q for the
quarter ended June 30, 1992)
4.16 Second Supplemental Indenture for Colonial Gas Company dated as of
September 27, 1995 (filed as Exhibit 4(c) to Colonial Gas Company's Form
10-K for the fiscal year ended December 31, 1995)
4.17 Amendment to Second Supplemental Indenture for Colonial Gas Company dated
as of October 12, 1995 (filed as Exhibit 4(d) to Colonial Gas Company's
Form 10-K for the fiscal year ended December 31, 1995)
4.18 Third Supplemental Indenture for Colonial Gas Company dated as of December
15, 1995 (filed as Exhibit 4(f) to Colonial Gas Company's Form S-3
Registration Statement dated January 5, 1998)
4.19 Fourth Supplemental Indenture for Colonial Gas Company dated as of March 1,
1998 (filed as Exhibit 4(l) to Colonial Gas Company's Form 10-Q for the
quarter ended March 31, 1998)
4.20 Trust Agreement dated as of June 22, 1990 between Colonial Gas Company (as
Trustor) and Shawmut Bank, N.A. (as Trustee) (filed as Exhibit 10(d) to
Colonial Gas Company's Form 10-Q for the period ended June 30, 1990)
4.21 Gas Service, Inc. General and Refunding Mortgage Indenture, dated as of
June 30, 1987, as amended and supplemented by a First Supplemental
Indenture, dated as of October 1, 1988, and by a Second Supplemental
Indenture, dated as of August 31, 1989 (filed as Exhibit 4.1 to
EnergyNorth, Inc.'s Form 10-K for the fiscal year ended September 30, 1989
(File No. 0-11035)
4.22 Third Supplemental Indenture, dated as of September 1, 1990, to Gas
Service, Inc. General and Refunding Mortgage Indenture, dated as of June
30, 1987 (filed as Exhibit 4.2 to EnergyNorth, Inc.'s Form 10-K for the
fiscal year ended September 30, 1990 (File No. 0-11035)
4.23 Fourth Supplemental Indenture, dated as of January 10, 1992, to Gas
Service, Inc. General and Refunding Mortgage Indenture, dated as of June
30, 1987 (filed as Exhibit 4.3 of EnergyNorth, Inc.'s Form 10-K for the
fiscal year ended September 30, 1992 (File No. 0-11035)
4.24 Fifth Supplemental Indenture, dated as of February 1, 1995, to Gas Service,
Inc. General and Refunding Mortgage Indenture, dated as of June 30, 1987
(filed as Exhibit 4.4 to EnergyNorth, Inc.'s Form 10-K for the fiscal year
ended September 30, 1996 (File No. 1-11441)
4.25 Sixth Supplemental Indenture, dated as of September 15, 1997, to Gas
Service, Inc. General and Refunding Mortgage Indenture, dated as of June
30, 1987 (filed as Exhibit 4.5 to EnergyNorth Natural Gas, Inc.'s Amendment
No. 1 to Registration Statement on Form S-1, No. 333-32949, dated September
10, 1997)
4.26 Indenture, dated as of March 2, 1998, between The Houston Exploration
Company and The Bank of New York, as Trustee, with respect to the 8 5/8%
SENIOR Subordinated Notes Due 2008 (including form of 8 5/8% SENIOR
Subordinated Note Due 2008) (filed as Exhibit 4.1 to The Houston
Exploration Company's Registration Statement on Form S-4 (No. 333-50235)
4.27 Indenture between Midland Enterprises and State Street Bank and Trust
Company dated as of April 2, 1990 (filed as Exhibit 2.2 to Midland
Enterprises Registration Statement No 333-21120)
4.28 Indenture between Midland Enterprises and The Chase Manhattan Bank dated as
of September 29, 1998 (filed as Exhibit 4.2 to Midland Enterprises
Registration Statement (File No. 333-61137))
4.29 Indenture dated as of June 1, 1986 between the Company and Centerre Trust
Company of St. Louis, Trustee. (Filed as an Exhibit to Essex Gas Company's
Registration Statement on Form S-2, filed June 19, 1986, File No. 33-6597).
4.30 Twelfth Supplemental Indenture dated as of December 1, 1990, providing for
a 10.10 percent Series due 2020. (Filed as Exhibit 4-14 to Essex Gas
Company's Form 10-Q for the quarter ended February 28, 1991).
4.31 Fifteenth Supplemental Indenture dated as of December 1, 1996 providing for
a 7.28 percent Series due 2017. (Filed as Exhibit 4.5 to the Essex Gas
Company's Form 10-Q for the quarter ended February 28, 1997).
4.32 Bond Purchase Agreement dated December 1, 1990, between Allstate Life
Insurance Company of New York, and Essex County Gas Company. (Filed as an
Exhibit to Company's Form 10-Q for the quarter ended February 28, 1991).
10.1 Amendment, Assignment and Assumption Agreement dated as of September 29,
1997 by and among The Brooklyn Union Gas Company, Long Island Lighting
Company and KeySpan Energy Corporation (filed as Exhibit 2.5 to Schedule
13D by Long Island Lighting Company on October 24, 1997)
10.2 Agreement and Plan of Merger dated as of June 26, 1997 by and among BL
Holding Corp., Long Island Lighting Company, Long Island Power Authority
and LIPA Acquisition Corp. (filed as Annex D to Registration Statement on
Form S-4, No. 333-30353 on June 30, 1997)
10.3* Credit Agreement among KeySpan Corporation, the several Lenders, Fleet
National Bank and Royal Bank of Scotland PLC, as Co-Documentation Agents,
ABN AMRO Bank, N.V. and Citibank, N.A., as Co-Syndication Agents and the
Chase Manhattan Bank, as Administrative Agent for $1,400.000.000, dated as
of September 19, 2001
10.4-a Letter of Credit and Reimbursement Agreement, dated as of December 1,
2000, by and between KeySpan Generation LLC and National Westminister Bank
PLC relating to the Electric Facilities Revenue Bonds ("EFRBs") Series
1997A (filed as Exhibit 4.10 to the Company's Form 10-K for the year ended
December 31, 2000). .
10.4-b* Extension Agreement, dated as of November 1, 2001 by and between KeySpan
Generation LLC and National Westmnister Bank PLC, relating to the Letter of
Credit and Reimbursement Agreement, dated as of December 1, 2000
10.5-a Amended and Restated Credit Agreement among The Houston Exploration
Company and Chase Bank of Texas, National Association, as agent, dated
March 30,1999, (filed as Exhibit 10.2 to The Houston Exploration Company's
Quarterly Report on Form 10-Q for the quarter ended March 31, 1999 (File
No. 001-11899) and incorporated by reference ).
10.5-b First Amendment and Supplement to Amended and Restated Credit Agreement
dated May 4, 1999 by and among The Houston Exploration Company and Chase
Bank of Texas, National Association, as agent, (filed as Exhibit 10.1 to
The Houston Exploration Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1999 (File No. 001-11899) and incorporated by
reference ).
10.5-c Second Amendment to Amended and Restated Credit Agreement between The
Houston Exploration Company and Chase Bank of Texas, National Association,
as agent, dated October 6, 1999, (filed as Exhibit 10.32 to The Houston
Exploration Company's Quarterly Report on Form 10-Q for the quarter ended
September 30, 1999 (File No. 001-11899)).
10.5-d Third Amendment and Supplement to Amended and Restated Credit Agreement
between The Houston Exploration Company and Chase Bank of Texas, National
Association, as agent, dated December 9, 1999 (filed as Exhibit 10.20 to
the Company's Form 10-K for the year ended December 31, 1999)
10.6 Subordinated Loan Agreement dated November 30, 1998 between The Houston
Exploration Company and MarketSpan Corporation (KeySpan Corporation) (filed
as Exhibit 10.30 to The Houston Exploration Company's Annual Report on Form
10-K for the year ended December 31, 1998).
10.7 Subordination Agreement dated November 25, 1998 entered into and among
MarketSpan Corporation (KeySpan Corporation), The Houston Exploration
Company and Chase Bank of Texas, National Association (filed as Exhibit
10.31 to The Houston Exploration Company's Annual Report on Form 10-K for
the year ended December 31, 1998 (File No. 001-11899)).
10.8 First Amendment to Subordinated Loan Agreement and Promissory Note between
KeySpan Corporation and The Houston Exploration Company dated effective as
of October 27, 1999 (filed as Exhibit 10.14 to the Company's Form 10-K for
the year ended December 31, 1999).
10.9 Amended and Restated Credit Agreement among The Houston Exploration Company
and Chase Bank of Texas, National Association, as agent, dated March
30,1999, (filed as Exhibit 10.2 to The Houston Exploration Company's
Quarterly Report on Form 10-Q for the quarter ended March 31, 1999 (File
No. 001-11899) and incorporated by reference).
10.10* Credit Agreement among KeySpan Energy Development Co., several Lenders
and the Royal Bank of Montreal, as Agent, for $125,000,000 (Canadian)
Credit Facility, dated as of October 13, 2000
10.11* Consent, Waiver and Amending Agreement among KeySpan Energy Development
Co., several Lenders and the Royal Bank of Montreal, as Agent, for the
$125,000,000 (Canadian) Credit Facility, dated as of December 22, 2000
10.12* Second Amending Agreement among KeySpan Energy Development Co., several
Lenders and the Royal Bank of Montreal, as Agent, for the $125,000,000
(Canadian) Credit Facility, dated as of October 12, 2001
10.13 Agreement of Lease between Forest City Jay Street Associates and The
Brooklyn Union Gas KeySpan dated September 15, 1988 (filed as an exhibit to
The Brooklyn Union Gas Company's Form 10-K for the year ended September 30,
1996)
10.14 Management Services Agreement between Long Island Power Authority and Long
Island Lighting Company dated as of June 26, 1997 (filed as Annex D to
Registration Statement on Form S-4, No. 333-30353, on June 30, 1997)
10.15 Power Supply Agreement between Long Island Lighting Company and Long
Island Power Authority dated as of June 26, 1997 (filed as Annex D to
Registration Statement on Form S-4, No. 333-30353, on June 30, 1997)
10.16 Energy Management Agreement between Long Island Lighting Company and Long
Island Power Authority dated as of June 26, 1997 (filed as Annex D to
Registration Statement on Form S-4, No. 333-30353, on June 30, 1997)
10.17* Generation Purchase Rights Agreement between Long Island Lighting Company
and Long Island Power Authority dated as of June 26, 1997
10.18* Letter Agreement between KeySpan and the Long Island Power Authority
Regarding Agreement In Principle for the Extension of the Generation
Purchase Right Agreement dated as of March 11, 2002
10.19** Employment Agreement dated September 10, 1998, between KeySpan and
Robert B. Catell (filed as Exhibit (10)(b) to the Company's Form 10-Q for
the quarterly period ended September 30, 1998)
10.20** Amendment dated as of February 24, 2000, to the Employment Agreement
dated September 10, 1998, between KeySpan and Robert B. Catell (filed as
Exhibit 10.12-a to the Company's Form 10-K for the year ended December 31,
2000)
10.21** Employment Agreement effective as of March 1, 2001, between KeySpan and
Craig G. Matthews (filed as Exhibit 10.13 to the Company's Form 10-K for
the year ended December 31, 2000)
10.22** Employment Agreement effective as of July 29, 1999, between KeySpan and
Gerald Luterman (filed as Exhibit 10.10 to the Company's Form 10-K for the
year ended December 31, 1999)
10.23** Employment Agreement dated as of November 8, 2000, between KeySpan and
Chester R. Messer (filed as Exhibit 10.15 to the Company's Form 10-K for
the year ended December 31, 2000)
10.24** Change of Control Agreement dated as of September 22, 1999, between
Eastern, Boston Gas Company and Chester R. Messer (filed as Exhibit 10.11.5
to Eastern's Form 10-Q for the quarterly period ended September 30, 1999,
File No. 1-2297).
10.25** Employment Agreement dated as of November 8, 2000 between KeySpan and
Joseph A. Bodanza (filed as Exhibit 10.17 to the Company's Form 10-K for
the year ended December 31, 2000)
10.26** Change of Control Agreement dated as of September 22, 1999, between
Eastern, Boston Gas Company and Joseph A. Bodanza (filed as Exhibit 10.18
to the Company's Form 10-K for the year ended December 31, 2000)
10.27* ** Amended Directors' Deferred Compensation Plan
10.28** Corporate Annual Incentive Compensation and Gainsharing Plan (filed as
Exhibit 10.20 to the Company's Form 10-K for the year ended December 31,
2000)
10.29** Senior Executive Change of Control Severance Plan effective as of
October 30, 1998 (filed as Exhibit 10.20 to the Company's Form 10-K for the
year ended December 31, 1998)
10.30** KeySpan's Amended Long Term Performance Incentive Compensation Plan
effective May 20, 1999 (filed as Exhibit A to the Company's 2001 Proxy
Statement on March 23, 2001)
10.31 Rights Agreement dated March 30, 1999, between the KeySpan and the Rights
Agent (filed as Exhibit 4 to the Company's Form 8-K, on March 30, 1999)
10.32 Generating Plant and Gas Turbine Asset Purchase and Sale Agreement for
Ravenswood for Ravenswood Generating Plants and Gas Turbines dated January
28, 1999, between the KeySpan and Consolidated Edison Company of New York,
Inc. (filed as Exhibit 10(a) to the Company's Form 10-Q for the quarterly
period ended March 31, 1999)
10.33 Lease Agreement dated June 9, 1999, between KeySpan-Ravenswood, Inc. and
LIC Funding, Limited Partnership (filed as Exhibit 10.2 to the Company's
Form 10-Q for the quarterly period ended June 30, 1999)
10.34 Guaranty dated June 9, 1999, from the KeySpan in favor of LIC Funding,
Limited Partnership (filed as Exhibit 10.1 to the Company's Form 10-Q for
the quarterly period ended June 30, 1999)
10.35 Redacted Gas Resource Portfolio Management and Gas Sales Agreement between
Boston Gas Company, Colonial Gas Company, Essex Gas Company (collectively,
KEDNE) and El Paso Energy Marketing Company dated as of September 14, 1999,
as amended (filed as Exhibit 10.1 to Eastern Enterprises Form 10-K for the
period ended December 31, 1999)
10.36-a Restated Exploration Agreement between The Houston Exploration Company
and KeySpan Exploration and Production, L.L.C., dated June 30, 2000, (filed
as Exhibit 10.1 to The Houston Exploration Company's Quarterly Report on
Form 10-Q for the quarter ended September 30, 2000, File No. 001-11899)
10.36-b Exploration Agreement between The Houston Exploration Company and
KeySpan Exploration and Production, L.L.C., dated March 15,1999, (filed as
Exhibit 10.1 to The Houston Exploration Company's Quarterly Report on Form
10-Q for the quarter ended March 31, 1999 (File No. 001-11899) and
incorporated by reference)
10.36-c First Amendment to the Exploration Agreement between The Houston
Exploration Company and KeySpan Exploration and Production, L.L.C. dated
November 3, 1999 (filed as Exhibit 10.19 to The Houston Exploration
Company's Annual Report on Form 10-K for the year ended December 31, 1999
(File No. 001-11899) and incorporated by reference )
10.37-a* Credit Agreement among KeySpan Energy Development Co., Borrower, the
Several Lenders' and Royal Bank of Canada, Administrative Agent, dated July
29, 1999
10.37-b* First Amending Agreement dated as of October 13, 2000 to the Credit
Agreement among KeySpan Energy Development Co., Borrower, the Several
Lenders' and Royal Bank of Canada, Administrative Agent dated July 29, 1999
10.37-c* Second Amending Agreement dated as of December 15, 2000 to the Credit
Agreement among KeySpan Energy Development Co., Borrower, the Several
Lenders' and Royal Bank of Canada, Administrative Agent dated July 29, 1999
10.38* Guarantee Agreement by KeySpan Corporation in favor of the Several
Lenders to KeySpan Energy Development Co. dated as of July 29, 1999
12* Computation in support of ratio of earnings to fixed charges and ratio of
combined fixed charges and dividends
21* Subsidiaries of the Registrant
23.1* Consent of Arthur Andersen LLP, Independent Auditors
23.2* Consent of Netherland, Sewell & Associates, Inc., Independent Petroleum
Consultants
23.3* Consent of Miller and Lents, Ltd., Independent Petroleum Consultants
24.1* Power of Attorney executed by Robert B. Catell, which is substantially the
same as Powers of Attorney made by Lilyan F. Affinito, Andrea S.
Christensen, Howard R. Curd, Donald H. Elliott, Alan H. Fishman, Vicki L.
Fuller, J. Atwood Ives, James R. Jones, James L. Larocca, Stephen W.
McKessy, Edward D. Miller and James Q. Riordan on March 7, 2002
24.2* Certified copy of the Resolution of the Board of Directors authorizing
signatures pursuant to power of attorney
99.* Letter pursuant to Temporary Note 3T to Article 3 of Regulation S-X
* Filed herewith
** Management Contract or Compensation Plan
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, as amended, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized.
KEYSPAN CORPORATION
March 27, 2001 By: /S/Gerald Luterman
----------------------
Gerald Luterman
Executive Vice President and
Chief Financial Officer
March 27, 2001 By: /S/Ronald S. Jendras
--------------------
Ronald S. Jendras
Vice President, Controller and
Chief Accounting Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated on March 27, 2001.
*
------------------------
Lilyan H. Affinito Director
*
------------------------
Andrea S. Christensen Director
*
------------------------
Howard R. Curd Director
*
------------------------
Donald H. Elliott Director
*
________________________ Director
Alan H. Fishman
*
________________________ Director
Vicki L. Fuller
*
________________________ Director
J. Atwood Ives
*
________________________ Director
James R. Jones
*
________________________ Director
James L. Larocca
*
________________________ Director
Stephen W. McKessy
*
________________________ Director
Edward D. Miller
*
------------------------
James Q. Riordan Director
By:/s/ Gerald Luterman
Attorney-in-Fact
* Such signature has been affixed pursuant to a Power of Attorney filed as an
exhibit hereto and incorporated herein by reference thereto.