SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X ]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
OR
[ ]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the period from January 1, 2002 to December 31, 2002
Commission File Number 1-14161
KEYSPAN CORPORATION
(Exact name of registrant as specified in its charter)
NEW YORK 11-3431358
(State or other jurisdiction of (I.R.S. employer identification no.)
incorporation or organization)
One MetroTech Center, Brooklyn, New York 11201
175 East Old Country Road, Hicksville, New York 11801
(Address of principal executive offices) (Zip code)
(718) 403-1000 (Brooklyn)
(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, 2003, the aggregate market value of the common stock held by
non-affiliates (156,910,326 shares) of the registrant was $5,016,423,122.22
based on the closing price, on such date, of $31.97 per share.
As of March 1, 2003, there were 172,737,654 shares of common stock, $.01
par value, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Proxy Statement dated on or about March 31, 2003 is incorporated by reference
into Part III hereof.
KEYSPAN CORPORATION
INDEX TO FORM 10-K
Page
----
Part I
Item 1. Description of the Business.................................................................................1
Item 2. Properties.................................................................................................26
Item 3. Legal Proceedings..........................................................................................27
Item 4. Submission of Matters to a Vote of Security Holders........................................................27
Part II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters......................................27
Item 6. Selected Financial Data....................................................................................29
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.................................................................................30
Item 7A. Quantitative and Qualitative Disclosures About Market Risk ................................................73
Item 8. Financial Statements and Supplementary Data ...............................................................79
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure..................................................................................149
Part III
Item 10. Directors and Executive Officers of the Registrant.........................................................149
Item 11. Executive Compensation.....................................................................................149
Item 12. Security Ownership of Certain Beneficial Owners and Management.............................................149
Item 13. Certain Relationships and Related Transactions.............................................................150
Item 14. Controls and Procedures....................................................................................150
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K............................................150
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"), now known as KeySpan New England, LLC ("KNE"), a
Massachusetts limited liability company[1], which primarily owns Boston Gas
Company ("Boston Gas"), Colonial Gas Company ("Colonial Gas") and Essex Gas
Company ("Essex Gas"), gas utilities operating in Massachusetts, 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 four 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 manage 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 4,200 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 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 three lines of business: (i) home energy services; (ii)
business solutions; and (iii) fiber optic services.
The Energy Investments segment includes: (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. Following the acquisition of Eastern and EnergyNorth in November 2000,
KeySpan became the largest gas distribution company in the Northeast and the
fifth largest in the United States. KeySpan's increased size and scope is
enabling us to provide enhanced cost-effective customer service; to offer our
existing customers other services and products by 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 also continue to explore
the monetization of some or all of our non-core assets in the Energy Investments
segment.
- --------
1 Pursuant to an application on Form U-1 filed with the Securities and Exchange
Commission on May 28, 2002, Eastern Enterprises, a Massachusetts business trust,
was reorganized as KNE. The transaction involved the formation of KNE as well as
another new subsidiary named KSNE, LLC ("KSNE"), a Delaware limited liability
company, that is a wholly-owned subsidiary of KeySpan. KNE is 99% owned by
KeySpan and 1% owned by KSNE.
1
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:
- volatility of energy prices of fuel used to generate electricity;
- fluctuations in weather and in gas and electric prices;
- general economic conditions, especially in the Northeast United
States;
- our ability to successfully reduce our cost structure and operate
efficiently;
- our ability to successfully contract for natural gas supplies required
to meet the needs of our firm customers;
- implementation of new accounting standards;
- inflationary trends and interest rates;
- the ability of KeySpan to identify and make complementary
acquisitions, as well as the successful integration of recent and
future acquisitions;
- available sources and cost of fuel;
- creditworthiness of counter-parties to derivative instruments and
commodity contracts;
- retention of key personnel;
- federal and state regulatory initiatives that increase competition,
threaten cost and investment recovery, and place limits on the type
and manner in which we invest in new businesses;
- the impact of federal and state utility regulatory policies and orders
on our regulated and unregulated businesses;
- potential write-down of our investment in natural gas properties when
natural gas prices are depressed or if we have significant downward
revisions in our estimated proved gas reserves;
- competition in general facing our unregulated Energy Services
businesses, including but not limited to competition from other
mechanical, plumbing, heating, ventilation and air conditioning, and
engineering companies, as well as, other utilities and utility holding
companies that are permitted to engage in such activities;
- the degree to which we develop unregulated business ventures, as well
as federal and state regulatory policies affecting our ability to
retain and operate such business ventures profitably; and
2
- 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. Description of Business," "Item 2.
Properties," "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). KeySpan makes available free of charge on or through its website,
http://www.keyspanenergy.com (Investor Relations section), its annual report on
Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all
amendments to those reports as soon as reasonably practicable after such
material is electronically filed with or furnished to the SEC.
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 provides gas distribution services
in eastern and central Massachusetts; Colonial Gas provides gas distribution
services on Cape Cod and in eastern Massachusetts; and Essex Gas provides gas
distribution services in eastern Massachusetts. In New Hampshire, EnergyNorth
provides gas distribution services 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 Gas' and ranges from 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 six
major gas storage facilities.
Natural 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 tariffed 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
fixed costs by increasing the amount of gas purchased at points within or in
close proximity to our market area, which allow us to contract for firm
short-haul transportation capacity from these points rather than long-haul
transportation capacity from production areas. We also engage in the use of
derivative financial instruments from time to time to reduce the cash flow
volatility associated with the purchase price for a portion of future natural
gas purchases.
3
Natural 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 and
are otherwise not participants of a mandatory capacity assignment program.
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, as well as on the spot market, and utilizes its
firm transportation contracts to transport the gas. KeySpan also contracts for
firm capacity in natural gas underground storage facilities, in addition to
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 interruptible on-system sales are
refunded, for most of our subsidiaries, to firm customers subject to certain
sharing provisions.
Our gas operations can be significantly affected by seasonal weather conditions.
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 utility tariffs that contain a weather
normalization adjustment that significantly offsets variations in firm net
revenues due to fluctuations in 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.
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 firm long-term contracts for the purchase of transportation
and underground storage services. Gas supplies are purchased under long and
short-term firm 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 on the coldest days
of the winter season.
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 2,025 MDTH of gas for a peak-day during the 2002/03 winter season
and that the gas available to us on such a peak-day amounts to approximately
2,026 MDTH. For the 2003/04 winter season, we estimate the peak-day requirements
will amount to 2,088 MDTH and that the gas supplies available to us on such a
peak-day will amount to approximately 2,001 MDTH; we have plans for additional
purchases to offset the peak-day supply deficit. The 2002/03 winter peak-day
throughput to our New York customers was 1,754 MDTH, which occurred on January
23, 2003 at an average temperature of 14 degrees F, representing 87% of our peak
day capability. Our New York firm gas peak-day capability is summarized in the
following table:
4
Source MDTH per day % of Total
- --------------------------------------------------------------- --------------------- ---------------------
Pipeline 744 37%
Underground Storage 778 38%
Peaking Supplies 504 25%
--- ---
Total 2,026 100%
===================== =====================
Pipelines. Our New York based gas distribution utilities purchase natural gas
for sale 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
2002/03 winter, approximately 75% of our New York natural gas supply was
available from domestic sources and 25% from Canadian sources. We have available
under firm contract 744 MDTH per day of year-round and seasonal pipeline
transportation capacity. 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 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 and 778 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: (i) two liquefied
natural gas ("LNG") plants; and (ii) peaking supply contracts with five dual
fuel power producers located in our franchise areas. For the 2002/03 winter
season, we had the capability to provide a maximum peak-day supply of 504 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.
We have an agreement with Coral Resources, L.P. ("Coral"), a subsidiary of Shell
Oil Company, under which Coral assists in the origination, structuring,
valuation and execution of energy-related transactions on behalf of KEDNY and
KEDLI. The agreement with Coral expires on March 31, 2003. In anticipation of
the expiration of the existing agreement, a request for proposal was sent to
various portfolio managers. Upon evaluation of the bids, KeySpan will negotiate
an agreement for its gas distribution subsidiaries. It is anticipated that such
agreement will become effective April 1, 2003.
Gas Costs. Fluctuations in gas costs have little direct impact on the financial
results of KEDNY and KEDLI, since the current gas rate structure of each of
these companies includes a gas adjustment clause pursuant to which variations
between actual gas costs incurred and gas costs billed are deferred and
subsequently refunded to or collected from customers.
5
Deregulation. Regulatory actions, economic factors and changes in customers and
their preferences continue to reshape our gas operations. A number of 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. As of February 1, 2003, approximately 119,776 gas
customers have opted to purchase their gas from marketers.
New England Gas Distribution Systems
Supply and Storage
KEDNE has firm long-term contracts for the purchase of transportation and
underground storage services. Gas supplies are purchased under long and
short-term firm contracts, as well as on the spot market. Gas supplies are
transported by interstate pipelines from domestic and Canadian supply basins. In
addition, peaking supplies, principally liquefied natural gas ("LNG"), are
available to meet system requirements during the winter season.
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 1,231 MDTH of gas for a peak-day during the 2002/2003 winter
season and that the gas available to KEDNE on such a peak-day amounts to
approximately 1,347 MDTH. For the 2003/2004 winter season, KEDNE estimates that
the peak-day requirements will amount to 1,266 MDTH and that the gas supplies
available on such a peak-day will amount to approximately 1,412 MDTH.
As of March 1, 2003, the highest daily throughput to our New England customers
was 1,203 MDTH, which occurred on January 22, 2003 at an average temperature of
9'F. KEDNE has sufficient gas available to meet the requirements of their
firm gas customers for the 2002/2003 winter gas season. The firm gas peak day
capability of KEDNE is summarized in the following table:
Source MDTH per day % of Total
- --------------------------------------------------------------------- --------------------- ----------------------
Pipeline 412 31
Underground Storage 270 20
Peaking Supplies 665 49
Total 1347 100
===================== ======================
Pipelines. Our New England based gas distribution utilities purchase natural gas
for sale 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. Major providers of
interstate pipeline capacity and related services to the KEDNE companies
include: Tetco, Iroquois, Maritimes and Northeast Pipelines, Tennessee,
Algonquin Gas Transmission Company and Portland Natural Gas Transmission System.
Underground Storage. KEDNE has available under firm contract 682 MDTH per day of
year-round and seasonal transportation and underground storage capacity to their
facilities in New England. KEDNE has long-term contracts with Tetco, Tennessee,
Dominion, National Fuel Gas Supply Corporation and Honeoye for underground
storage capacity of 23,279 MDTH and 270 MDTH per day of maximum deliverability.
6
Peaking Supplies. The KEDNE gas supply portfolio is supplemented with peaking
supplies that are available on the coldest days throughout the winter season 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 located in
Providence, Rhode Island and Everett, MA. For the 2002/2003 winter season, on a
peak-day, KEDNE has access to 665 MDTH of peaking supplies, 49% of peak-day
supply.
Gas Supply Management. From November 1, 1999 through October 31, 2002, the New
England based gas distribution subsidiaries operated under a portfolio
management contract with El Paso Merchant Energy ("El Paso"). El Paso provided
the majority of the city gate supply requirements to the four New England gas
distribution companies (Boston Gas, Colonial Gas, Essex Gas and EnergyNorth) at
market prices and managed upstream capacity, underground storage and term supply
contracts. We negotiated a new agreement with Entergy-Koch that replaced the
expired El Paso agreement. The new agreement with Entergy-Koch commenced on
November 1, 2002 and extends through March 31, 2003. In anticipation of the
expiration of the existing agreement, a request for proposal was sent to various
portfolio managers. Upon evaluation of the bids, KeySpan will negotiate an
agreement for its gas distribution subsidiaries. It is anticipated that such
agreement will become effective April 1, 2003.
Gas Costs. Fluctuations in gas costs have little impact on the operating results
of the KEDNE companies since the current gas rate structure for each of the
companies include gas adjustment clauses pursuant to which variations between
actual gas costs incurred and gas costs billed 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. To
lessen to some extent the effect of flucuations in normal weather patterns on
KEDNE's results of operations and cash flows, weather derivatives are in place
for the 2002/2003 winter heating season.
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 5 large generating plants and 8 smaller facilities
which are comprised of 57 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 and significant administrative services
relating to the Long Island electric transmission and distribution ("T&D")
system through a management services agreement (the "MSA"); (ii) supply LIPA
with generating capacity, 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
our 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."
7
Generating Facility Operations
In June 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 variable interest entity through which we lease the Ravenswood
facility. Under the arrangement, the variable interest 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 variable interest
entity not been utilized and conventional debt financing been employed. Further,
we would have recorded an asset in the same amount. Monthly lease payments 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. We believe that the fair market value of the
Ravenswood facility, including the leased facilities, is in excess of its
acquisition cost (see discussion concerning the Financial Accounting Standards
Board issued Interpretation No. 46 in "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations").
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 requirements and is a strategic asset that is
available to serve residents and businesses in New York City. Reliability
improvement investments at our Ravenswood facility reduced the forced outage
rate for that facility from 35% in 1999 to under 6% in 2000, 2001 and 2002.
Decreasing the amount of time our generating units are offline for repair allows
us to increase sales. We are also in the process of expanding our Ravenswood
facility by adding a 250-megawatt state-of-the-art gas-fired combined-cycle
unit. 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. Further, two 79.9 megawatt generating facilities
located on Long Island were placed into service in June and July 2002. The
capacity of and energy from these facilities are dedicated to LIPA under 25 year
contracts.
The competitive wholesale market for capacity, energy and ancillary services
administered by the NYISO 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 7. Management's
Discussion and Analysis of Financial Condition and Results of
Operation-Regulatory Issues and Competitive Environment" for a further
discussion of these matters.
Natural gas or oil can be used to power 45 of our 77 generating units. 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.
8
The following table indicates the 2003 summer capacity of all 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* 4 1,520
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* 16 471
Throughout L.I. GT Units Oil 30 1,093
TOTAL 77 6,407
============================================================================================================================
*Dual - Oil (#2 oil, #6 residual oil) or kerosene, and natural gas
In addition to the 250 MW expansion of the Ravenswood facility, 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, and in February 2003, the Presiding Examiners issued a Recommended
Decision recommending that the Siting Board issue a Certificate of Environmental
Capability and Public Need for the project. Action by the Siting Board is
expected in March 2003. In addition, as part of our growth strategy, we
continually evaluate the possible acquisition of additional generating
facilities in the Northeast. However, we are unable to predict when or if such
facilities will be acquired and the effect any such acquired facilities will
have on our financial condition, results of operations or cash flows.
LIPA Agreements
LIPA is a corporate municipal instrumentality and a political subdivision of the
State of New York. On May 28, 1998, certain of LILCO's business units were
merged with KeySpan and LILCO's common stock and remaining assets were acquired
by LIPA. At the time of this transaction, three major long-term service
agreements were also executed between KeySpan and LIPA that provide for KeySpan
to provide 4,037 MW of power generation capacity and energy conversion services;
operation, maintenance and capital improvement services for LIPA's transmission
and distribution system; and the performance of energy management services.
Power Supply Agreement. A KeySpan subsidiary sells to LIPA all of the capacity
and, to the extent requested, energy conversion services from our existing Long
Island based oil and gas-fired generating plants. Sales of capacity and energy
conversion services are made under rates approved by the FERC. Under the terms
of the PSA, rates will be reestablished for the contract year commencing January
1, 2004 by recalculating the revenue requirement underlying those rates. We
anticipate submitting to the FERC a rate filing reflecting the recalculated
revenue requirement in the Fall of 2003. We are unable to predict the outcome of
that proceeding at this time. 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 conversion services from us and is able to purchase energy or
energy conversion services on a least-cost basis from all available sources
consistent with existing interconnection limitations of the T&D system. The PSA
provides incentives and penalties that can total $4 million annually for the
maintenance of the output capability and the efficiency of the generating
facilities. In 2002, we earned $4 million in incentives under the PSA.
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The PSA runs for a term of fifteen years. The PSA is renewable for an additional
15 years on similar terms at LIPA's option. 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 seven through ten 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 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 for our budgeted
costs and entitled to earn an annual management fee of $10 million and may also
earn certain cost-based incentives, or be responsible for certain cost-based
penalties. The incentives provide for us to retain 100% of the first $5 million
of budget underruns and 50% of any additional budget underruns up to 15% of the
total cost budget. Thereafter, all savings accrue to LIPA. The penalties require
us 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 performance-based 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 2002, we earned $7 million in
non-cost performance incentives.
The MSA was originally set to expire on May 28, 2006, but was extended through
December 31, 2008. The MSA was extended in exchange for an extension of the
option period under the Generation Purchase Rights Agreement as more fully
described in 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 our Long Island generating facilities
acquired from LILCO in 1998, (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 fuel supply service provided in (i) above is fifteen years, expiring May 28,
2013, and the term for the off-system purchases and sales services provided in
(ii) and (iii) above is eight years, expiring May 28, 2006.
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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 and disincentives up to $5 million annually for
control of the cost of fuel and electricity purchased on behalf of LIPA. In
2002, we earned EMA incentives in an aggregate of $5 million.
Generation Purchase Rights Agreement. Under the Generation Purchase Rights
Agreement ("GPRA"), LIPA had the right for a one-year period, beginning May 28,
2001, to acquire all of our Long Island based generating assets formerly owned
by LILCO at fair market value at the time of the exercise of such right. By
agreement dated March 29, 2002, LIPA and KeySpan amended the GPRA to provide for
a new six-month option period ending on May 28, 2005. The other terms of the
option reflected in the GPRA remain unchanged.
The GPRA and MSA extensions were the result of an 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 also
allows both LIPA and us to explore alternatives to the GPRA including 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 of land 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 an 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) generally not to commence any tax
certiorari case (until termination of the PSA) challenging certain property tax
assessments relating to the former LILCO 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 former
LILCO 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.
Other. In late 2002, LIPA announced, and we acknowledged, that during 2001 and
2002 we had made an error in reporting LIPA's electric system requirements,
resulting in an overestimation of LIPA's unbilled revenue. LIPA and KeySpan have
continued to review and audit the reporting electric system requirements for
2002 and earlier periods, and have determined that, in addition to the 2001 and
2002 overestimation, unbilled revenues for prior periods back to May 1998 were
slightly underestimated. Based on the review, the total overestimation in
unbilled revenue was approximately $65 million. The LIPA revenue estimation
error did not have an impact on LIPA's electric rates charged to its customers
or to its cash balances. We do not believe that the LIPA revenue estimation
error will have any material adverse impact on the various agreements with LIPA
or on our financial or operating performance.
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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 New York, New Jersey, Massachusetts, New Hampshire, Rhode Island and
Pennsylvania through various subsidiaries which operate under the following
three 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); and (iii) 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 and 200,000 service
contracts, and is the number one oil to gas conversion contractor in New York
and New England.
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 and local distribution companies.
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.
In 2001, we discontinued the general contracting activities related to the
former Roy Kay companies with the exception of work to be completed on existing
contracts, based upon our view that the general contracting business was not a
core competency of these companies. As a result of our evaluation of the Energy
Services business undertaken during 2001, we decided to set certain limitations
on the types of new general contracting activities in which our contracting
subsidiaries may engage. We also installed senior management personnel whom,
among other things, have reviewed and continue to review and focus on our
overall strategy of these businesses. We are currently engaged in litigation
concerning the Roy Kay companies. For further information, See Note 10 to the
Consolidated Financial Statements, "Roy Kay Operations" and Note 7 "Contractual
Obligations and Contingencies - Legal Matters for a further discussion.
Although the Roy Kay companies are exiting the non-energy related general
contracting business, KeySpan Services, Inc. ("KSI"), through its subsidiaries,
may engage in general contracting where such activities involve contracts for
construction activities that management is satisfied such subsidiary, either by
itself or through one or more contracts with other KSI subsidiaries and/or third
parties, has the necessary resources to perform and which are primarily energy
related as determined by SEC rule or precedent under PUHCA (e.g., involving
projects such as the construction of HVAC, thermal, chilled water and other HVAC
12
facilities, renewable energy, cogeneration and other types of power production
facilities and waste water treatment facilities). KSI and its subsidiaries will
not, however, enter into new contracts to provide general contracting services
involving the construction of primarily non-energy related facilities, as
determined by SEC rule or precedent under PUHCA.
In its order approving the acquisition by KeySpan of Eastern, the SEC reserved
jurisdiction on its determination of whether the Energy Services companies were
retainable and required KeySpan to file a post-effective amendment regarding the
retention of these Energy Services companies. On June 27, 2001, we filed such a
post-effective amendment. The SEC has not made a determination, but we believe
that the SEC may find ample bases to approve of KeySpan's continued operations
in the Energy Services business, especially in light of the fact that other
registered holding companies 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 and Production
KeySpan is engaged in the exploration and production of domestic natural gas and
oil through our 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." On
February 26, 2003, Houston Exploration issued 3 million shares of its common
stock, the net proceeds of which were used to repurchase 3 million shares of
common stock owned by us. As a result of the repurchase, our ownership interest
in Houston Exploration was reduced from approximately 66% to approximately 56%.
Additionally, there is an over-allotment option for 300,000 shares, which if
exercised would further reduce our ownership in Houston Exploration to 55%. At
March 1, 2003, Houston Exploration's aggregate market capitalization was
approximately $842.2 million (based upon the closing price on the New York Stock
Exchange on February 28, 2003 of $27.20). At March 1, 2003, Houston Exploration
had approximately 30,961,618 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
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 exploration
prospects.
In line with our stated strategy of exploring the monetization or divestiture of
certain non-core assets, in October 2002, we sold a portion of our assets in the
joint venture drilling program to Houston Exploration. We received $26.5 million
in cash for our working interests in producing properties with an estimated 18.6
Bcfe of proved and provable reserves.
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
13
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. Our interests in offshore properties are located in the
shallow waters of the Outer Continental Shelf of the Gulf of Mexico. Our
interests in key producing properties are located in the western and central
Gulf of Mexico and include the Mustang Island, High Island, East Cameron,
Vermilion and South Timbalier areas. We hold interests in 86 blocks in federal
and state waters, of which 42 are developed. Through our subsidiaries, we
operate 29 of our developed blocks, which accounted for approximately 75% of our
interests in offshore production during 2002. We have a total of 37 platforms
and production cassions of which we operate 27. Since its inception in 1999, the
joint venture participated in 28 wells, 23 of which were successful-- 17
exploratory and six development. During 2002, we drilled ten offshore wells,
nine of which were successful, representing a success rate of 90%. Of the
successful wells drilled, six were exploratory and three were development. The
joint venture participated in four of the 2002 wells, two exploratory and two
development, all of which were successful.
Onshore Properties. Our interests in South Texas properties are concentrated in
the Charco, Haynes and South Trevino Fields of Zapata County; the Alexander,
Hubbard and South Laredo Fields of Webb County; and the North East Thompsonville
Field in Jim Hogg County. We own interests in 562 producing wells, 450 of which
are operated by our subsidiaries. Our interests in Arkoma Basin properties are
located in two primary areas: the Chismville/Massard Field located in Logan and
Sebastian Counties of Arkansas and the Wilburton and Panola Fields located in
Latimer County, Oklahoma. We own working interests in 252 producing natural gas
wells, of which we operate 131. Other Onshore properties are concentrated in
three areas: South Louisiana, West Virginia and East Texas. On a combined basis,
we own working interests in 708 producing wells, 653 of which we operate. During
2002, we drilled 87 onshore wells, 75 of which were successful, representing a
success rate of 86%. Of the successful wells drilled, 54 were drilled in South
Texas and 21 were drilled in the Arkoma Basin. Of the 75 successful wells
drilled, 73 were development and two were exploratory.
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 Gas Transmission System LP,
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.
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 involves the construction, ownership and operation of a 50 mile
natural gas pipeline that will transport 260 MDTH of gas supply daily from Nova
Scotia, Canada to growing markets in Connecticut, New York City and Long Island,
New York. 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. The project received a
certificate of public convenience and necessity from the FERC authorizing the
construction, operation and maintenance of the interstate natural gas pipeline
facilities in Connecticut and Long Island, N.Y. Islander East has obtained all
required permits in New York State for the construction of the facility.
However, the State of Connecticut has issued a moratorium on the issuance of
permits relating to the construction of energy projects until June 2003.
Islander East has therefore been unable to obtain the necessary permits from the
State of Connecticut at this time. Islander East has also appealed a denial by
the State of Connecticut of the coastal zone management permit to the U.S.
Department of Commerce and such appeal is currently pending. Islander East is
projected to be in service by year end 2004.
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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 that provides up to 6.2 billion cubic feet of storage service to New
Jersey and Massachusetts.
On December 12, 2002, we acquired Algonquin LNG, LP, the owner and operator of a
600,000 barrel liquefied natural gas ("LNG") storage and receiving facility
located in Providence, Rhode Island, from Duke Energy for approximately $28
million. Boston Gas Company is the facility's largest customer and contracts for
more than half of its storage. The facility, renamed KeySpan LNG, LP, is
regulated by the FERC.
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 provide associated natural gas liquids fractionation.
Additionally, KeySpan owns an approximate 20% interest in Taylor NGL LP which
owns and operates two extraction plants, one located in British Columbia, and
one in Alberta, 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 Transmission Limited 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 non-core and is
evaluating the possible divestiture or monetization 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 was divested and its operations
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 July 2, 2002, we announced that
we closed the sale of Midland to a subsidiary of Ingram Industries Inc.
("Ingram") and we received net proceeds of approximately $175 million from the
sale. See Note 9 "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.
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Except as set forth below, or in Note 7 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 investigation 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. 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. We are required to be in
compliance with the Phase III reduction requirements of the OTC memorandum
effective May 1, 2003. We expect to achieve such emission reductions in a
cost-effective manner through the completion of low NOx combustion control
systems, the use of natural gas fuel and the purchases of allowances when
necessary. Expenditures for combustion control systems and natural gas fuel
capability additions to address NOx emission reductions begun in 2002 and ending
in 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.
We are currently monitoring impacts of our discharges on aquatic resources, in
consultation with the DEC. Until our monitoring obligations are completed and
proposed changes to the Environmental Protection Agency regulations under
Section 316 of the Clean Water Act are finalized, 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 7
to the Consolidated Financial Statements, "Contractual Obligations and
Contingencies - Environmental Matters."
16
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 7. Management's Discussion and Analysis of
Financial Condition and Results of Operation-Regulatory Issues and Competitive
Environment."
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 New York Public Service
Commission ("NYPSC"), the Massachusetts Department of Telecommunications and
Energy ("DTE") and the New Hampshire Public Utilities Commission ("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 that 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
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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 7. Management's Discussion and
Analysis of Financial Condition and Results of Operation-Regulatory Issues and
Competitive Environment."
The 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, Steuben and Algonquin LNG 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.
Risks Related To Our Business
We are a Holding Company, and We and Our Subsidiaries are Subject to Federal
and/or State Regulation Which Limits Our Financial Activities, Including the
Ability of Our Subsidiaries to Pay Dividends and Make Distributions to Us
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We are a holding company registered under PUHCA with no business operations or
sources of income of our own. We conduct all of our operations through our
subsidiaries and 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 and to pay dividends on our common stock.
Because we are a registered holding company, our corporate and financial
activities and those of our subsidiaries, including their ability to pay
dividends to us from unearned surplus, are subject to PUHCA and regulation by
the SEC.
In addition, a substantial portion of our consolidated assets, earnings and cash
flow is derived from the operation of our regulated utility subsidiaries, whose
legal authority to pay dividends or make other distributions to us is subject to
regulation by the utility regulatory commissions of New York, Massachusetts and
New Hampshire. Pursuant to New York Public Service Commission orders, the
ability of KeySpan Energy Delivery New York, or KEDNY, and KeySpan Energy
Delivery Long Island, or KEDLI, to pay dividends to us is conditioned upon their
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 a customer service performance program.
At the end of KEDNY's and KEDLI's rate years (September 30, 2002 and November
30, 2002, respectively), their ratios of debt to total utility capitalization
were in compliance with the ratios set forth above.
PUHCA Also Limits Our Business Operations and Our Ability to Affiliate with
Other Utilities
PUHCA, in addition to limiting our financial activities, also limits our
operations to a single integrated utility system, plus additional energy related
businesses, regulates transactions between us and our subsidiaries and requires
SEC approval for specified utility mergers and acquisitions. In its order
approving our acquisition of Eastern Enterprises and EnergyNorth, Inc., the SEC
reserved jurisdiction on its determination of whether the companies that
comprise our energy services business can be classified as 'energy-related
companies' and therefore retainable under existing SEC precedent. We are unable
to predict whether the SEC will authorize the retention of all or some of these
companies or the impact its determination will have on our financial condition
or results of operations.
The SEC is currently conducting a routine audit of our operations to determine
compliance with PUHCA, and while no issues have been brought to our attention
that we believe to be material, we can provide no assurances as to the ultimate
findings of the audit or their potential impact on our operations.
Our Gas Distribution and Electric Services Businesses May Be Adversely Affected
by Changes in Federal and State Regulation
The regulatory environment applicable to our gas distribution and our electric
services businesses has undergone substantial changes in recent years, on both
the federal and state levels. These changes have significantly affected the
nature of the gas and electric utility and power industries and the manner in
which their participants conduct their businesses. Moreover, existing statutes
and regulations may be revised or reinterpreted, new laws and regulations may be
adopted or become applicable to us or our facilities, and future changes in laws
and regulations may affect our gas distribution and our electric services
businesses in ways that we cannot predict.
In addition, our operations are subject to extensive government regulation and
require numerous permits, approvals and certificates from various federal, state
and local governmental agencies. Some of our revenues in our Gas Distribution
and Electric Services segments are directly dependent on rates established by
federal or state regulatory authorities, and any change in these rates and
regulatory structure could significantly impact our financial results. Increases
in utility costs other than gas, not otherwise offset by increases in revenues
or reductions in other expenses, could have an adverse effect on earnings due to
the time lag associated with obtaining regulatory approval to recover such
increased costs and expenses, and the uncertainty of whether regulatory
commissions will allow full recovery of and return on such increased costs and
expenses.
Proposals to re-regulate the wholesale power market have been made at the
federal level. These proposals, and legislative and other attention to the
electric power industry could have a material adverse effect on our strategies
and results of operations for our electric services business and our financial
condition. In particular, we sell power and energy from our Ravenswood
generating facility into the New York Independent System Operator, or NYISO,
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energy market at market based rates, subject to mitigation measures approved by
the Federal Energy Regulatory Commission, or FERC. The pricing for both energy
sales and services to the NYISO energy market is still evolving and some of the
FERC's price mitigation measures are subject to rehearing and possible judicial
review.
Our Risk Mitigation Techniques Such as Hedging and Purchase of Insurance May Not
Adequately Provide Protection
To lower our financial exposure related to commodity price fluctuations, our
marketing, trading and risk management operations routinely enter into contracts
to hedge a portion of our purchase and sale commitments, weather fluctuations,
electricity sales, natural gas supply and other commodities. However, we do not
always cover the entire exposure of our assets or our positions to market price
volatility and the coverage will vary over time. To the extent we have unhedged
positions or our hedging procedures do not work as planned, fluctuating
commodity prices could cause our sales and net income to be volatile.
Our business is subject to many hazards from which our insurance may not
adequately provide coverage. Therefore it is possible that our insurance may not
be adequate to cover all losses or liabilities that we might incur in our
operations. Unexpected outage of Ravenswood, especially in the significant
summer period, could materially impact our financial results. Damage to
pipelines, equipment, properties and people caused by natural disasters,
accidents, terrorism or other damage by third parties could exceed our insurance
coverage. Although we do have insurance to protect against many of these
contingent liabilities, this insurance is capped at certain levels, has
self-insured retentions and does not provide coverage for all liabilities.
SEC Rules for Exploration and Production Companies May Require Us to Recognize a
Non-Cash Impairment Charge at the End of Our Reporting Periods
We use the full cost method of accounting for our investments in natural gas and
oil properties. These investments consist of our approximately 56% equity
interest in The Houston Exploration Company, 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 these 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, those
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, an impairment of gas properties is not reversible at a later date,
even if gas prices increase.
You May Not Be Able to Seek Remedies Against Arthur Andersen LLP, Our Former
Independent Accountant, with Respect to Our Financial Statements that were
Audited by Arthur Andersen
On June 15, 2002, Arthur Andersen LLP, our former independent certified public
accountant, was convicted of federal obstruction of justice arising from the
government's investigation of Enron Corp. On April 5, 2002, we dismissed Arthur
Andersen and appointed Deloitte & Touche LLP to serve as our independent
certified public accountant for fiscal year 2002. Arthur Andersen had audited
our financial statements for the fiscal years ended December 31, 2000 and
December 31, 2001. Holders of our common stock may have no effective remedy
against Arthur Andersen in connection with a material misstatement or omission
in those financial statements, particularly in the event that Arthur Andersen
ceases to exist or becomes insolvent as a result of the conviction or other
proceedings against it.
Our Operating Results May Fluctuate on a Seasonal and Quarterly Basis
Our gas distribution business is a seasonal business and is subject to weather
conditions. We receive most of our gas distribution revenues in the first and
fourth quarters when demand for natural gas usually increases due to colder
weather conditions. As a result, we are subject to seasonal variations in
working capital because we purchase most of our natural gas supplies in the
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second and third quarters and must increase our borrowings in these periods to
finance these purchases. Accordingly, our results of operations in the future
will fluctuate substantially on a seasonal basis. In addition, our New
England-based gas distribution subsidiaries do not benefit from weather
normalization tariffs, and results from our Ravenswood generating facility are
directly correlated to the weather as the demand and price for the electricity
it generates increases during the summer. As a result, fluctuations in weather
between years may have a significant effect on our results of operations for
these subsidiaries.
We Cannot Predict Whether LIPA will Exercise its Option to Purchase Our Long
Island Generating Assets and the Effect of that Purchase on Us
Under a Generation Purchase Right Agreement, as amended, entered into with the
Long Island Power Authority, LIPA has the right to purchase, at fair market
value, during the six month period beginning November 29, 2004, all of our Long
Island based generating assets that had been previously owned by the Long Island
Lighting Company. At this point in time, we cannot predict whether LIPA will
exercise its right to purchase the assets, nor can we estimate the effect on our
financial condition or results of operations if LIPA were to exercise its
option.
A Substantial Portion of Our Revenues are Derived from Our Agreements with LIPA,
and No Assurances Can Be Made that These Arrangements Will Not Be Discontinued
at Some Point in the Future
We derive a substantial portion of our revenues in our electric services segment
from a series of agreements with LIPA pursuant to which we manage LIPA's
transmission and distribution system and supply the majority of LIPA's
customers' electricity needs. The agreements terminate at various dates between
May 28, 2006 and May 28, 2013 and at this time we can provide no assurance that
any of the agreements will be renewed or extended or, if they were to be renewed
or extended, as to the terms and conditions thereof.
We Own Approximately 56% of The Houston Exploration Company, and Our Results of
Operation are Therefore Subject to the Risks Affecting its Business
We own approximately 56% of The Houston Exploration Company, an independent
natural gas and oil producer. Therefore, our results of operations in our energy
investments segment are subject to the same risks and uncertainties that affect
the operations of Houston Exploration. In addition to the risks set forth under
the caption ' -- SEC rules for exploration and production companies may require
us to recognize a non-cash impairment charge at the end of our reporting
periods,' these risks and uncertainties include:
The volatility of natural gas and oil prices. If natural gas and oil
prices decline, the amount of natural gas and oil Houston Exploration can
economically produce may be reduced, which may result in a material decline
in its revenue.
The potential inability of Houston Exploration to meet its capital
requirements. If Houston Exploration is unable to meet its capital
requirements to fund, develop, acquire and produce natural gas and oil
reserves, its oil and gas reserves will decline.
Substantial indebtedness. Houston Exploration's outstanding
indebtedness under its bank credit facility and the indenture governing its
senior subordinated notes contain covenants that require a substantial
portion of its cash flow from operations to be dedicated to its debt
service obligations and impose other restrictions that limit its ability to
borrow additional funds or dispose of assets. These restrictions may affect
its flexibility in planning for, and reacting to, changes in business
conditions.
Estimates of proved reserves and future net revenue may change. Any
significant variance from the assumptions used to estimate proved reserves
or natural gas could result in the actual quantity of Houston Exploration's
reserves and future net cash flow being materially different from the
estimates in its reserve report.
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A Decline or an Otherwise Negative Change in the Ratings or Outlook on Our
Securities Could Have a Materially Adverse Impact on Our Ability to Secure
Additional Financing on Favorable Terms
The rating agencies that rate our securities regularly review our financial
condition and results of operations. We can provide no assurances that the
ratings or outlook on our securities will not be reduced or otherwise negatively
changed. A negative change in the ratings or outlook on our securities could
have a materially adverse impact on our ability to secure additional financing
on favorable terms.
Our Costs of Compliance with Environmental Laws are Significant, and the Cost of
Compliance with Future Environmental Laws Could Adversely Affect Us
Our operations are subject to extensive federal, state and local environmental
laws and regulations relating to air quality, water quality, waste management,
natural resources and the health and safety of our employees. These
environmental laws and regulations expose us to costs and liabilities relating
to our operations and our current and formerly owned properties. Compliance with
these legal requirements requires us to commit significant capital toward
environmental monitoring, installation of pollution control equipment and
permits at our facilities. Costs of compliance with environmental regulations,
and in particular emission regulations, could have a material impact on our
electric services business and our results of operations and financial position,
especially if emission limits are tightened, more extensive permitting
requirements are imposed, additional substances become regulated or the number
and type of electric generating plants we operate increase.
In addition, we are responsible for the clean-up of contamination at certain
manufactured gas plant ('MGP') sites and at other sites and are aware of
additional MGP sites where we may have responsibility for clean up costs. While
our gas rate plans generally allow for the full recovery of the costs of
investigation and remediation of MGP sites, these rate recovery mechanisms may
change in the future. To the extent rate recovery mechanisms change in the
future, or if additional environmental matters arise in the future at our
currently or historically owned facilities, at sites we may acquire in the
future or at third party waste disposal sites, costs associated with
investigating and remediating these sites could have a material adverse effect
on our results of operations and financial condition.
Our Businesses are Subject to Competition and General Economic Conditions
Impacting Demand for Services
Ravenswood, our merchant generation plant, in our Electric Services segment, is
subject to competition that could adversely impact the market price for the
electricity it produces. Construction of new transmission facilities could also
cause significant changes to the market. If generation and/or transmission
facilities are constructed, and/or the availability of our Ravenswood facility
deteriorates, then the capacity and energy sales volumes could be adversely
affected. We cannot predict, however, when or if new power plants or
transmission facilities will be built or the nature of the future New York City
energy requirements.
Competition facing our unregulated Energy Services businesses, including but not
limited to competition from other mechanical, plumbing, heating, ventilation and
air conditioning, and engineering companies, as well as, other utilities and
utility holding companies that are permitted to engage in such activities, could
adversely impact our financial results and the value of those businesses,
resulting in decreased earnings as well as writedowns of the carrying value of
those businesses. In addition, competition in the fiber optics business could
negatively impact the value of this business.
Our Gas Distribution segment faces competition with distributors of alternative
fuels and forms of energy, including fuel oil and propane. Our ability to
continue to add new gas distribution customers may significantly impact
financial results. The gas distribution industry has experienced a decrease in
consumption per customer over time partially due to increased efficiency of
customers' appliances. Our Gas Distribution segment is dependent upon the
ability to add new customers to our system in a cost-effective manner. While our
Long Island and New England utilities have significant growth potential, we
cannot be sure new customers will continue to offset the decrease in consumption
of our existing customer base. There are a number of factors outside of our
control that impact whether a potential customer converts from an alternative
fuel to gas, including general economic factors impacting customers willingness
to invest in new gas equipment.
22
Employee Matters
As of December 31, 2002, KeySpan and its wholly owned subsidiaries had
approximately 13,000 employees. Of that total, approximately 5,850 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 66, 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 49, was elected President, KeySpan Energy Assets and Supply Group
in January 2003. Mr. Fani joined KEDNY in 1976, and held a variety of management
positions in distribution, engineering, planning, marketing, and business
development. He was elected Vice President in 1992. In 1997, Mr. Fani was
promoted to Senior Vice President of Marketing and Sales for KEDNY. 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 was promoted to Executive Vice President in February 2000 and then President
of Energy Services and Supply until assuming his current position in February
2003.
Wallace P. Parker Jr.
Mr. Parker, age 53, was elected President, Energy Delivery and Customer
Relations Group, in January 2003. He had previously served as President, KeySpan
Energy Delivery, since June 2001, and before that served as Executive Vice
President of Gas Operations from February 2000. 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.
John A. Caroselli
Mr. Caroselli, age 48, 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 and served at that time as Executive Vice
President of Corporate Development. Before joining KeySpan, Mr. Caroselli held
the position of Executive Vice President of Corporate Development at AXA
Financial. 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.
23
Gerald Luterman
Mr. Luterman, age 59 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. 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 has served on the Board of Directors of
The Houston Exploration Company since May 2000.
Anthony Nozzolillo
Mr. Nozzolillo, age 54, 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 49, was elected Executive Vice President of Client Services in
June 2000. She previously served as Senior Vice President of Customer Relations
for KEDNY from May 1994 to May 1998, and for KeySpan from May 1998 to January
2000. She joined KEDNY in 1974 and worked in management 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. Ms. Puleo was promoted to Senior Vice President of
KEDNY's Customer Relations in 1994.
Nickolas Stavropoulos
Mr. Stavropoulos, age 44, was elected Executive Vice President, KeySpan
Corporation, and President, KeySpan Energy Delivery New England, in April 2002;
prior to this he was Senior Vice President of sales and marketing in New England
since 2000. Prior to joining KeySpan, Mr. Stavropoulos was Senior Vice President
of marketing and gas resources for Boston Gas. Before joining Boston Gas, he was
Executive Vice President and Chief Financial Officer for Colonial Gas. In 1995,
Mr. Stavropoulos was elected Executive Vice President - Finance, Marketing and
CFO, and assumed responsibility for all of Colonial's financial, marketing,
information technology and customer service functions.
Steven L. Zelkowitz
Mr. Zelkowitz, age 53, Executive Vice President, was named Chief Administrative
Officer, with responsibility for the offices of General Counsel, Human
Resources, Regulatory Affairs, Enterprise Risk Management, and administratively
for Internal Auditing, in January 2003. Prior to that he served as Executive
Vice President-Administration and Compliance since November 2002, and Executive
Vice President and General Counsel of KeySpan since July 2001. 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 the Company, Mr. Zelkowitz practiced law with Cullen and Dykman in
Brooklyn, New York specializing in energy and utlity law and had been a partner
since 1984. He served on the firm's Executive Committee and was head of its
Corporate/Energy Department.
24
John J. Bishar, Jr.
Mr. Bishar, age 52, became Senior Vice President and General Counsel on November
1, 2002, with responsibility for the Legal Services Business Unit and the
Corporate Secretary's Office. Before joining KeySpan, Mr. Bishar practiced law
with Cullen and Dykman LLP. He was the Managing Partner from 1993 through 2002
and was a member of the firm's Executive Committee. From 1980 to 1987, Mr.
Bishar was Vice President, General Counsel and Corporate Secretary of LITCO
Bancorporation of New York, Inc. In 1987, Mr. Bishar returned to Cullen and
Dykman LLP as a partner responsible for the firm's commercial lending and
commercial real estate lending activities for a variety of financial
institutions.
Joseph F. Bodanza
Mr. Bodanza, age 55, was elected Senior Vice President of Finance Operations and
Regulatory Affairs in August 2001, and Chief Accounting Officer effective April
1, 2003. Prior to his appointment he was Senior Vice President and Chief
Financial Officer of KEDNE. Mr. Bodanza previously served as Senior Vice
President of Finance and Management Information Systems and Treasurer of Eastern
Enterprise'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.
John F. Haran
Mr. Haran, age 52, was elected Senior Vice President of gas operations for KEDNY
and KEDLI in April 2002. Mr. Haran joined The Brooklyn Union Gas Company in 1972
and has held management positions in operations, engineering, and marketing and
sales. He was named Vice President of KEDNY gas operations in 1996 and in 2000
moved to the position of Vice President of KEDLI gas operations.
David J. Manning
Mr. Manning, age 52, 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 65, was elected Senior Vice President of KeySpan's Corporate
Development and Asset Management division in March 1999. He also serves as
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 as agent for 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.
Colin P. Watson
Mr. Watson, age 51, 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.
25
Elaine Weinstein
Ms. Weinstein, age 56, 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.
Kamal Dua
Mr. Dua, age 43, was elected Vice President and General Auditor in June 2002.
Prior to joining KeySpan, he was Assistant Corporate Controller for AT&T
Corporation responsible for providing Decision Support services to the Corporate
Functions and the CFO for the Shared Services. Prior to joining AT&T, Mr. Dua
held executive level positions in the Finance and Internal Audit Department of
Verizon Corporation (formerly Bell Atlantic). Mr. Dua has also held Senior
Manager and Manager level positions with PriceWaterhouseCoopers LLP, Chartered
Accountants, BDO Seidman LLP, CPAs and Mitchell Titus & Co LLP, CPAs.
Ronald S. Jendras
Mr. Jendras, age 55, 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 and serves as a member of its Board of Directors.
Richard A. Rapp, Jr.
Mr. Rapp, age 44, serves as Vice President and Secretary of KeySpan Corporation,
a position he was appointed to in June 2000. On March 7, 2003, he was also
elected Senior Vice President of KeySpan Energy Supply, Inc. Prior to March 7,
2003, Mr Rapp also served as Deputy General Counsel since February 2000. He
joined LILCO in 1984 and has held various positions in the Legal Departments of
LILCO, and since 1998, KeySpan, including Assistant General Counsel.
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 a succession of positions
in Accounting, Customer Service, Corporate Planning, Budgeting and Forecasting,
Marketing and Sales, and Business Process Improvement. During the KeySpan/LILCO
merger, Mr. Taunton co-managed the day-to-day transition process of the merger
and then served on the Transition Team during the acquisition of Eastern
Enterprises (now known as KeySpan New England, LLC).
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 leases the executive headquarters located in Brooklyn,
New York. In addition, we lease other office and building space, office
equipment, vehicles and power operated equipment. Our properties are adequate
and suitable to meet our current and expected business requirements. Moreover,
their productive capacity and utilization meet our needs for the foreseeable
future. KeySpan continually examines its real property and other property for
its contribution and relevance to our businesses and when such properties are no
longer productive or suitable, they are disposed of as promptly as possible. 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.
26
Item 3. Legal Proceedings
See Note 7 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, 2002.
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, 2003, there
were approximately 70,213 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:
2002 High Low Dividends Per Share
First Quarter $36.72 $30.01 $0.445
Second Quarter $37.45 $34.35 $0.445
Third Quarter $38.19 $27.41 $0.445
Fourth Quarter $37.15 $30.75 $0.445
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
27
The following table sets forth securities authorized for issuance under equity
compensation plans for the year ended December 31, 2002:
Number of securities
Number of securities Remaining available for
to be issued Weighted-average future issuance under
upon exercise of exercise price of equity compensation plans
outstanding options, outstanding options, (excluding securities
Plan category warrants and rights warrants and rights, reflected in column (a))
- ------------- ------------------- -------------------- -------------------------
(a) (b) (c)
Equity compensation 9,549,039(1) $25.37 7,031,761
plans approved by
security holders.....
Equity compensation 44,293(2) N/A (3)
plans not approved
by security holders..
Total......... 9,593,332 $25.37 7,031,761
(1) Includes grants of options and restricted stock pursuant to KeySpan's
Long-Term Performance Incentive Compensation Plan, as amended, and options
granted pursuant to the Brooklyn Union Long-Term Performance Incentive
Compensation Plan and options granted pursuant to Eastern Enterprises
Long-Term Performance Incentive Compensation Plans, as well as 328,000
shares of Common Stock issued pursuant to the Stock Plan.
(2) Represents Deferred Stock Units issued pursuant to the Officers' Deferred
Stock Unit Plan.
(3) There is no set limit on the number of Deferred Stock Units issuable
pursuant to the Officers' Deferred Stock Unit Plan or the KeySpan Services
Inc. Officers' Deferred Stock Unit Plan.
Directors' Deferred Compensation Plan
The Directors' Deferred Compensation Plan provides all non-employee directors
with the opportunity to defer any portion of their cash compensation received as
directors, up to 100%, in exchange for Common Stock equivalents or cash
equivalents. Common Stock equivalents are valued by utilizing the average of the
high and low price per share of KeySpan common stock on the first trading day of
the month following the month in which contributions are received. Dividends are
paid on Common Stock equivalents in the same proportion as dividends paid on
Common Stock. Compensation not deferred and exchanged for Common Stock
equivalents, may be deferred into a cash account bearing interest at the prime
rate. Upon retirement, death or termination of service as a director, all
amounts in a director's Common Stock equivalent account and/or cash account
shall, at the director's election, (i) be paid in a lump sum in cash; (ii) be
deferred for up to five years; and/or (iii) be paid in the number of annual
installments, up to ten, specified by the director. The non-employee directors
are not entitled to benefits under any KeySpan retirement plan.
Officers' Deferred Stock Unit Plan
The Officers' Deferred Stock Unit Plan allows certain executives of the Company
and its wholly owned subsidiaries to elect to defer between 10% to 50% of their
annual cash bonus award and purchase deferred stock units ("DSUs"), which track
the performance of the Company's Common Stock but do not possess voting rights.
Executives also receive a 20% match by the Company on the amount deferred in
each year. The DSUs must be deferred until retirement or resignation and are
payable in Common Stock. The match on the deferral is also payable in Common
Stock upon retirement or in the event of an executive's disability, death or
upon change of control. The match is forfeited in the event of the executive's
resignation prior to retirement.
KeySpan Services Inc. Officers' Deferred Stock Unit Plan
The KeySpan Services Inc. Officers' Deferred Stock Unit Plan allows certain
officers of KeySpan Services Inc.and its wholly owned subsiadiries, to elect to
defer between 10% to 50% of their annual cash bonus award and purchase DSUs
which track the performance of the Company's Common Stock but do not possess
voting rights. Executives also receive a 20% match by the Company on the amount
deferred in each year. The DSUs must be deferred until retirement or resignation
and are payable in Common Stock. The match on the deferral is also payable in
Common Stock upon retirement or in the event of an executive's disability, death
or upon change of control. The match is forfeited in the event of the
executive's resignation prior to retirement.
28
Item 6. Selected Financial Data
- ------------------------------------------------------------------------------------------------------------------------------------
Nine Months
Year Ended December 31, December 31,
(In Thousands of Dollars, Except Per Share Amounts) 2002 2001 2000 1999 1998
--------------------------------------------------------------------------------
Income Summary
Revenues
Gas Distribution $ 3,163,761 $ 3,613,551 $ 2,555,785 $ 1,753,132 $ 856,172
Electric Services 1,421,043 1,421,079 1,444,711 861,582 408,305
Electric Distribution - - - - 330,011
Energy Services 938,761 1,100,167 770,110 186,529 63,064
Energy Investments and other 447,101 498,318 310,096 153,370 70,929
--------------------------------------------------------------------------------
Total revenues 5,970,666 6,633,115 5,080,702 2,954,613 1,728,481
Operating expenses
Purchased gas for resale 1,653,273 2,171,113 1,408,680 744,432 331,690
Fuel and purchased power 385,059 538,532 460,841 17,252 91,762
Operations and maintenance 2,101,897 2,114,759 1,659,736 1,091,166 777,678
Depreciation, depletion and amortization 514,613 559,138 330,922 253,440 254,859
Early retirement and severance charges - - 65,175 - 64,635
Operating taxes 410,651 448,924 421,936 366,154 257,124
--------------------------------------------------------------------------------
Operating income 905,173 800,649 733,412 482,169 (49,267)
Other income (deductions) (282,429) (346,264) (213,400) (87,196) (177,460)
--------------------------------------------------------------------------------
Income (loss) before income taxes 622,744 454,385 520,012 394,973 (226,727)
Income taxes (credits) 225,394 210,693 217,262 136,362 (59,794)
--------------------------------------------------------------------------------
Earnings (loss) from continuing operations 397,350 243,692 302,750 258,611 (166,933)
--------------------------------------------------------------------------------
Discontinued Operations
Income (loss) from operations, net of tax (3,356) 10,918 (1,943) - -
Loss on disposal, net of tax (16,306) (30,356) - - -
--------------------------------------------------------------------------------
Loss from discontinued operations (19,662) (19,438) (1,943) - -
--------------------------------------------------------------------------------
Net Income (Loss) 377,688 224,254 300,807 258,611 (166,933)
Preferred stock dividend requirements 5,753 5,904 18,113 34,752 28,604
--------------------------------------------------------------------------------
Earnings (loss) for Common Stock $ 371,935 $ 218,350 $ 282,694 $ 223,859 $ (195,537)
================================================================================
Financial Summary
Basic earnings (loss) per share ($) 2.63 1.58 2.10 1.62 (1.34)
Cash dividends declared per share ($) 1.78 1.78 1.78 1.78 1.19
Book value per share, year-end ($) 20.67 20.73 20.65 20.26 20.90
Market value per share, year-end ($) 35.24 34.65 42.38 23.19 31.00
Shareholders, year end 78,281 82,300 86,900 90,500 103,239
Capital expenditures ($) 1,161,456 1,059,759 925,257 725,670 676,563
Total assets ($) 12,614,306 11,789,606 11,307,465 6,730,691 6,895,102
Common shareholders' equity ($) 2,944,592 2,890,602 2,815,816 2,712,325 3,022,908
Redeemable preferred stock ($) - - - 363,000 363,000
Preferred stock ($) 83,849 84,077 84,205 84,339 447,973
Long-term debt ($) 5,224,081 4,697,649 4,116,441 1,682,702 1,619,067
Total capitalization ($) 8,252,522 7,672,328 7,016,462 4,479,366 5,089,948
- -----------------------------------------------------------------------------------------------------------------------------------
Utility Operating Statistics
Firm gas and transportation sales (MDTH) 348,454 347,659 271,543 244,659 87,179
Other sales (MDTH) 209,002 188,037 126,372 85,773 38,088
Total active gas meters 2,523,974 2,499,170 2,483,730 1,628,497 1,610,202
29
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
KeySpan Corporation (referred to herein as "KeySpan", "we", "us" and "our") is a
registered holding company under the Public Utility Holding Company Act of 1935,
as amended ("PUHCA"). KeySpan operates six regulated utilities that distribute
natural gas to approximately 2.5 million customers in New York City, Long
Island, Massachusetts and New Hampshire, making 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 and are the largest
investor owned generator in New York State. Under contractual arrangements, we
provide power, electric transmission and distribution services, billing and
other customer services for approximately one million electric customers of the
Long Island Power Authority ("LIPA"). KeySpan's other subsidiaries are involved
in gas and oil exploration and production; gas storage; wholesale and retail gas
and electric marketing; appliance service; plumbing, heating, ventilation, air
conditioning and other mechanical contracting services; large energy-system
ownership, installation and management; engineering and consulting services; and
fiber optic services. We also invest and participate in the development of
natural gas pipelines, natural gas processing plants, electric generation, and
other energy-related projects, domestically and internationally. (See Note 2
"Business Segments" for additional information on each operating segment.)
Consolidated Summary of Results
Consolidated earnings before interest and taxes ("EBIT") by segment, as well as
consolidated earnings available for common stock is set forth in the following
table for the periods indicated.
- -------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars, Except Per Share Amounts) 2002 2001 2000
- -------------------------------------------------------------------------------------------------
Gas Distribution $524,311 $492,362 $367,226
Electric Services 309,663 283,533 310,823
Energy Services (10,377) (143,492) 14,630
Energy Investments 128,265 141,477 131,686
Eliminations and other (27,614) 33,975 (103,039)
-------------------------------
Earnings Before Interest Charges
and Taxes 924,248 807,855 721,326
Interest charges 301,504 353,470 201,314
Income taxes 225,394 210,693 217,262
-------------------------------
Earnings from Continuing Operations 397,350 243,692 302,750
Discontinued operations (19,662) (19,438) (1,943)
-------------------------------
Net Income 377,688 224,254 300,807
Preferred stock dividends 5,753 5,904 18,113
-------------------------------
Earnings for Common Stock $371,935 $218,350 $282,694
================================
Basic Earnings per Share:
Continuing operations $ 2.77 $ 1.72 $ 2.12
Discontinued operations (0.14) (0.14) (0.02)
- -------------------------------------------------------------------------------------------------
$ 2.63 $ 1.58 $ 2.10
- -------------------------------------------------------------------------------------------------
30
As indicated in the above table, earnings from continuing operations less
preferred stock dividends for the year ended December 31, 2002 increased by
$153.8 million, or $1.05 per share compared to the same period in 2001. The
increase in earnings from continuing operations reflects the following
significant events which are discussed in more detail below: (i) the
discontinuance of goodwill amortization in 2002; (ii) the recording of special
items in 2001 which resulted in the recognition of certain gains and losses; and
(iii) a significant decrease in interest expense in 2002. These benefits to
comparative earnings were offset, in part, by a decrease in natural gas prices,
particularly during the first quarter, which reduced 2002 earnings associated
with gas exploration and production operations, as well as the impact of
extremely warm weather during the first quarter which adversely affected natural
gas consumption by gas distribution customers.
In January 2002, we adopted Statement of Financial Accounting Standard ("SFAS")
142 "Goodwill and Other Intangible Assets". The key requirements of this
Statement include the discontinuance of goodwill amortization, a revised
framework for testing goodwill impairment and new criteria for the
identification of intangible assets. Consolidated goodwill amortization for 2001
was $49.6 million, or $0.36 per share, and $19.7 million, or $0.15 per share for
2000.
During 2001, we recorded the effects of a number of events that impacted results
of operations for that year. These events are as follows: (1) we incurred losses
attributed to the former Roy Kay companies of $95.0 million after-tax, or $0.69
per share, primarily 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 10
to the Consolidated Financial Statements, "Roy Kay Operations" and Note 7
"Contractual Obligations, Financial Guarantees and Contingencies" - Legal
Matters, for a further discussion of these issues); (2) our gas exploration and
production subsidiaries recorded a non-cash impairment charge 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, or $0.19 per share. (See Note
1 to the Consolidated Financial Statements "Summary of Significant Accounting
Policies", Item F for further details); and (3) following a favorable appellate
court ruling, we reversed 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, or $0.15 per share. This adjustment has been reflected
as a $22.0 million reduction to Operations and Maintenance expense and a
reduction of $11.5 million to Interest Charges on the Consolidated Statement of
Income for the year ended December 31, 2001. (See Note 11 to the Consolidated
Financial Statements "Class Action Settlement" for a further discussion of this
issue.)
Interest expense decreased by $52.0 million ($33.8 million after-tax), or $0.24
per share in 2002 compared to 2001. The weighted average interest rate on
outstanding commercial paper for 2002 was approximately 2.0% compared to
approximately 4.5% for last year. Further, KeySpan had a number of interest rate
swap agreements which effectively converted fixed rate debt to floating rate
debt. The use of these derivative instruments reduced interest expense by $35.6
million in 2002. (See Note 8 to the Consolidated Financial Statements "Hedging,
Derivative Financial Instruments, and Fair Values" for a description of these
instruments.) Interest expense in 2001 also reflects the reversal of $11.5
million in accrued interest expense resulting from the RICO class action
settlement.
31
Net income from gas exploration and production operations decreased by $13.4
million, or $0.11 per share, in 2002 compared to 2001. These operations were
adversely impacted by significantly lower realized gas prices in 2002,
particularly in the first quarter. As previously mentioned, these operations
recorded a non-cash impairment charge in 2001; excluding this charge, the
comparative decrease in earnings was $39.6 million, or $0.30 per share.
Income tax expense generally reflects the level of pre-tax income for all
periods reported. Further, during the year we finalized the valuation study
related to the assets transferred to KeySpan resulting from the KeySpan/Long
Island Lighting Company ("LILCO") business combination completed in May 1998. As
a result, an adjustment to deferred taxes of $177.7 million was recorded to
reflect a decrease in the tax basis of the assets acquired. Concurrent with this
adjustment, KeySpan reduced current income taxes payable by $183.2 million,
resulting in a $5.5 million income tax benefit. Income tax expense also reflects
additional tax benefits of approximately $15 million resulting from the
finalization of amended tax returns and the reversal of certain tax reserves.
Average common shares outstanding in 2002 increased by 2% compared to 2001
reflecting the re-issuance of shares held in treasury pursuant to dividend
reinvestment and employee benefit plans. This increase in average common shares
outstanding reduced earnings per share in 2002 by $0.06 compared to 2001. In
January 2003, we received net proceeds of approximately $473 million from the
issuance of 13.9 million shares of common stock. See the discussion under the
caption "Capital Expenditures and Financing" for further information on this
equity offering.
Earnings before interest and taxes ("EBIT") increased by $116.4 million in 2002
compared to last year. Comparative EBIT results were impacted by the items
mentioned above, namely; (i) the discontinuation of goodwill amortization in
2002 of $49.6 million; (ii) EBIT losses of $137.8 million incurred by the Roy
Kay companies in 2001 compared to losses of $10.8 million incurred in 2002;
(iii) the recording of a non-cash pre-tax impairment charge of $42.0 million in
2001 to recognize the effect of lower wellhead prices; and (iv) the reversal, in
2001, of a previously recorded loss provision relating to the RICO class action
settlement of $22.0 million. Offsetting these benefits to comparative EBIT
results was a decrease in EBIT in 2002 from gas exploration and production
operations resulting from a significant decline in average realized gas prices.
(See "Review of Operating Segments" and Note 2 to the Consolidated Financial
Statements "Business Segments" for a detailed discussion of EBIT results for
each of our lines of business.)
Earnings from continuing operations less preferred stock dividends for the year
ended December 31, 2001 decreased by $46.9 million, or $0.40 per share, compared
to the same period in 2000. These comparative results were primarily driven by
the items recorded in 2001 that were previously discussed.
Further, 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, comparisons in consolidated earnings, revenues
and expenses between fiscal years 2001 and 2000 have been significantly affected
by the addition of these operations. (See Note 1 to the Consolidated Financial
Statements "Summary of Significant Accounting Policies".) As part of this
transaction, in 2000 we recorded a $65.2 million pre-tax charge associated with
early retirement and severance programs that were implemented upon the
completion of the acquisitions. The after-tax effect of this charge on
consolidated results was $41.1 million, or $0.31 per share.
32
Interest expense increased by $152.2 million, or 75% in 2001 compared to 2000,
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 KeySpan Canada, one of our
Canadian subsidiaries; as well as (v) higher commercial paper borrowings during
the year to satisfy seasonal working capital needs. As mentioned, we reversed
$11.5 million of previously recorded interest expense relating to the RICO class
action settlement during 2001, of which $9 million was recorded in 2000.
Income tax expense in 2001 generally reflects the lower level of pre-tax income
compared to 2000. (See Note 3 to the Consolidated Financial Statements, "Income
Taxes" for more information.) The decrease in preferred stock dividends in 2001
compared to 2000 resulted from the redemption, at maturity, of 14.5 million
shares of preferred stock in the second quarter of 2000.
Average common shares outstanding in 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 earnings per share in 2001 by $0.05 compared to 2000.
EBIT from continuing operations in 2001, after adjusting for the matters noted
above, were substantially higher than such earnings for 2000. Our gas
distribution operations benefited from the addition of the New England gas
utilities for the entire year in 2001 compared to only two months in 2000, as
well as from an increase in net margins due to continued gas sales growth, and
cost saving synergies. Further, our gas exploration and production activities
benefited 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 analysis of
comparative EBIT for each of our operating segments.)
On January 24, 2002, we announced that we had entered into an agreement to sell
Midland Enterprises, LLC ("Midland"), KeySpan's inland marine barge business
acquired in connection with the Eastern acquisition. In anticipation of this
divestiture, which was completed on July 2, 2002, Midland's operations have been
reported as discontinued for all periods. (See Note 9 to the Consolidated
Financial Statements "Discontinued Operations" for further disclosure on the
sale of Midland.) In the fourth quarter of 2001, an estimated loss on the sale
of Midland, as well as an estimate for Midland's results of operations for the
first six months of 2002 was recorded.
As a result of a change in the tax structure of this transaction, an additional
after-tax loss of $19.7 million was recorded in 2002, primarily reflecting a
provision for certain city and state taxes.
33
Financial Outlook for 2003
Consistent with our prior earnings guidance, and as reaffirmed in February 2003
following the announcement regarding the sale of a portion of our ownership in
The Houston Exploration Company ("Houston Exploration"), our gas exploration and
production subsidiary (as further discussed below), KeySpan's earnings for 2003
are forecasted to be approximately $2.45 to $2.60 per share, after giving effect
to the sale of 13.9 million shares of common stock previously noted. Earnings
from continuing core operations (defined for this purpose as all continuing
operations other than gas exploration and production, less preferred stock
dividends) are forecasted to be approximately $2.15 to $2.20 per share, while
earnings from gas exploration and production operations are forecasted to be
approximately $0.30 to $0.40 per share. The earnings forecast may vary
significantly during the year due to, among other things, changing energy market
and weather conditions. It should be noted that, starting in 2003, KeySpan will
expense stock options granted to its employees in order to reflect all
prospective compensation costs in earnings.
Consolidated earnings are seasonal in nature due to the significant contribution
to earnings of our gas distribution operations. As a result, we expect to earn
most of our annual earnings in the first and fourth quarters of our fiscal year
and breakeven or marginally profitable earnings are anticipated to be achieved
in the second and third quarters of our fiscal year.
Review of Operating Segments
- ----------------------------
The following discussion of financial results achieved by our operating segments
is presented on an EBIT basis. We use EBIT measures in our financial and
business planning process to provide a reasonable assurance that our financial
forecasts will provide, among other things, (i) shareholders with a competitive
return on their investment, (ii) adequate earnings and cash flow to service
debt; and (iii) adequate interest coverage to maintain or improve our credit
ratings. Information concerning EBIT is presented as a measure of those
financial results. EBIT should not be construed as an alternative to net income
or cash flow from operating activities as determined by Generally Accepted
Accounting Principles.
Gas Distribution
KeySpan Energy Delivery New York ("KEDNY") provides gas distribution service to
customers in the New York City Boroughs of Brooklyn, Staten Island and a portion
of Queens. 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.
34
The table below highlights certain significant financial data and operating
statistics for the Gas Distribution segment for the periods indicated.
- ------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
- ------------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars) 2002 2001 2000
- ------------------------------------------------------------------------------------------------------------------------
Revenues $ 3,163,761 $ 3,613,551 $ 2,555,785
Cost of gas 1,569,325 2,017,782 1,303,515
Revenue taxes 98,151 119,084 117,811
- ------------------------------------------------------------------------------------------------------------------------
Net Revenues 1,496,285 1,476,685 1,134,459
- ------------------------------------------------------------------------------------------------------------------------
Operating Expenses
Operations and maintenance 608,266 593,341 456,028
Early retirement and severance programs - - 41,790
Depreciation and amortization 237,186 253,523 143,335
Operating taxes 138,686 148,428 131,854
- ------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 984,138 995,292 773,007
- ------------------------------------------------------------------------------------------------------------------------
Operating Income 512,147 481,393 361,452
Other Income and (Deductions), net 12,164 10,969 5,774
- ------------------------------------------------------------------------------------------------------------------------
Earnings Before Interest Charges and Income Taxes $ 524,311 $ 492,362 $ 367,226
- ------------------------------------------------------------------------------------------------------------------------
Firm gas sales and transportation (MDTH) 284,281 283,081 221,689
Transportation - Electric
Generation (MDTH) 64,173 64,578 49,854
Other Sales (MDTH) 209,002 188,037 126,372
Warmer (Colder) than Normal - New York 7.0% 10.0% (2.1%)
Warmer (Colder) than Normal - New England 4.0% 4.6% (3.3%)
- ------------------------------------------------------------------------------------------------------------------------
A 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
Combined net gas revenues (revenues less the cost of gas sold and associated
revenue taxes) from our gas distribution operations increased by $19.6 million,
or 1.3%. Both the New York and New England based gas distribution operations
were adversely impacted by the significantly warmer than normal weather
experienced throughout the Northeastern United States during 2002, particularly
during the first quarter. Based on heating degree days, weather for the twelve
months ended December 31, 2002 was approximately 4%-7% warmer than normal and
approximately 1%-3% colder than last year in the New York and New England
service territories. However, weather during the heating season, January-March,
was approximately 16%-19% warmer than normal, across our service territories.
Our gas distribution operations historically earn approximately 60% of yearly
EBIT during the January-March period.
During 2002, KEDNY and KEDLI, together, added approximately $40 million in gross
gas load additions. The increased gas sales were generated from oil-to-gas space
heating conversions, as well as from new construction. These load additions,
however, were offset by declining usage per customer due to the extremely warm
first quarter weather and the use of more efficient gas heating equipment.
Additionally, the down-turn in the economy throughout the Northeastern United
States had an adverse impact on gas consumption in 2002. As a result of these
factors, net revenues from firm gas customers (residential, commercial and
industrial customers) in our New York service territory decreased by $1.5
million in 2002 compared to last year. Included in net revenues are regulatory
incentives that contributed a favorable $6.7 million to comparative net
revenues.
35
Net revenues from firm gas customers in the New England service territory
increased by $20.5 million in 2002 compared to last year, primarily as a result
of approximately $24 million in gross gas load additions. Also included in net
revenues are base rate adjustments totaling $10.0 million associated with Boston
Gas Company's Performance Based Rate Plan ("PBR"). The largest component of this
adjustment reflects the beneficial effect of a favorable ruling of the
Massachusetts Supreme Judicial Court relating to the "accumulated
inefficiencies" component of the productivity factor in the PBR. This ruling
resulted in a benefit to comparative net margins of $6.3 million. (See
"Regulation and Rate Matters" for a further discussion of this matter.)
Offsetting, to some extent, these benefits to revenues are the adverse effects
of declining usage per customer due to the extremely warm first quarter weather
and the use of more efficient gas heating equipment. Additionally, the down-turn
in the economy throughout the Northeastern United States had an adverse impact
on gas consumption in 2002.
KEDNY and KEDLI each operate under utility tariffs that contain a weather
normalization adjustment that significantly offsets variations in firm net
revenues due to fluctuations in weather. These weather normalization adjustments
resulted in an increase to net gas revenues of $22.3 million in 2002, but this
did not fully mitigate the impact of the loss in revenues due to the extremely
warm weather experienced during the first quarter. The New England-based gas
distribution subsidiaries do not have weather normalization adjustments. To
lessen, to some extent, the effect of fluctuations in normal weather patterns on
KEDNE's results of operations and cash flows, weather derivatives are in place
for the 2002/2003 winter heating season. Since weather during the fourth quarter
of 2002 was 7% colder than normal in the New England service territory, we
recorded a $3.3 million reduction to revenues to reflect the loss on these
derivative transactions. (See Note 8 to the Consolidated Financial Statements
"Hedging, Derivative Financial Instruments, and Fair Values" for further
information).
Firm gas distribution rates in 2002, excluding gas cost recoveries, have
remained substantially unchanged from last year in all of our service
territories.
Total net gas revenues 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 revenues from our firm gas 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 that added $13.3 million and $23.7
million, respectively, to the increase in firm net gas revenues in 2001. The
related property tax expense is being amortized through operating taxes and
therefore does not benefit EBIT.
36
In our large-volume heating and other interruptible (non-firm) markets, which
include large apartment houses, government buildings and schools, gas service is
provided under rates that are established to compete with prices of alternative
fuel, including No. 2 and No. 6 grade heating oil. Net margins realized from
these customers in 2002 are comparable to such margins realized last year. Net
revenues in these markets in 2001 were slightly lower than sales to this market
for 2000. The majority of these margins earned by KEDNE and KEDLI are returned
to firm customers as an offset to gas costs.
We are committed to our expansion strategies initiated during the past few
years. We believe that significant growth opportunities exist on Long Island and
in the New England service territories. We estimate that on Long Island
approximately 35% of the residential and multi-family markets, and approximately
55% of the commercial market currently use natural gas for space heating
purposes. Further, we estimate that in the New England service territories
approximately 50% of the residential and multi-family markets, and approximately
45% of the commercial market currently use natural gas for space heating
purposes. We will continue to seek growth in all of our market segments through
the expansion of the gas distribution system, as well as through the conversion
of residential homes from oil-to-gas for space heating purposes and the pursuit
of opportunities to grow multi-family, industrial and commercial markets.
Firm Sales, Transportation and Other Quantities
Total actual firm gas sales and transportation quantities remained consistent
with last year. In the New York service territory, actual and weather normalized
firm gas sales and transportation quantities decreased slightly in 2002 compared
to 2001. In the New England services territories, firm gas sales and
transportation quantities increased 4%, despite the warm first quarter weather,
due to load additions.
Firm gas sales and transportation quantities increased by 27% during 2001,
compared to 2000. The gas distribution operations of KEDNE, accounted for 73.9
MDTH, or 100% of the increase. Firm gas sales and transportation quantities from
our New York based gas distribution operations decreased by 7% compared to 2000
as a result of warmer than normal weather. Weather was approximately 10% warmer
than normal in 2001 and approximately 11% warmer than the prior year.
Weather normalized sales quantities in 2001 in our New York service territories
were flat compared to 2000 due primarily to the adverse effect on consumption of
extraordinarily high gas prices during the first quarter of 2001.
Net revenues are not affected by customers choosing to purchase their gas supply
from other sources, since delivery rates charged to transportation customers
generally are the same as the delivery component of rates charged to full sales
service customers. Transportation quantities related to electric generation
reflect the transportation of gas to KeySpan's electric generating facilities
located on Long Island. Net revenues from these services are not material.
37
Other sales quantities include on-system interruptible quantities, off-system
sales quantities (sales made to customers outside of our service territories)
and related transportation. We have an agreement with Coral Resources, L.P.
("Coral"), a subsidiary of Shell Oil Company, under which Coral assists in the
origination, structuring, valuation and execution of energy-related transactions
on behalf of KEDNY and KEDLI. We also had a portfolio management contract with
El Paso Energy Marketing, Inc. ("El Paso"), under which El Paso provided all of
the city gate supply requirements at market prices and managed certain upstream
capacity, underground storage and term supply contracts for KEDNE. Our agreement
with El Paso expired on October 31, 2002 and our agreement with Coral expires on
March 31, 2003. We have negotiated a new agreement with Entergy-Koch to replace
the expired El Paso agreement. The new agreement with Entergy-Koch began on
November 1, 2002 and extends through March 31, 2003. In anticipation of the
expiration of the existing agreements, a request for proposal was sent to
various portfolio managers. Upon evaluation of the bids, KeySpan will negotiate
agreements for all of its gas distribution subsidiaries. It is anticipated that
such agreements will become effective April 1, 2003.
Purchased Gas for Resale
The decrease in gas costs in 2002 compared to 2001 of $448.5 million, or 22%,
reflects a decrease of 26% in the price per dekatherm of gas purchased, and a
1.0% increase in the quantity of gas purchased. The increase in gas costs in
2001 compared to 2000 of $714.3 million, or 55% primarily reflects the addition
of KEDNE's operations for an entire year. KEDNE's operations accounted for
$666.1 million of the increase. Fluctuations in utility gas costs associated
with firm gas customers have no impact on operating results. The current gas
rate structure of each of our gas distribution utilities includes a gas
adjustment clause, pursuant to which variations between actual gas costs
incurred and gas costs billed are deferred and refunded to or collected from
customers in a subsequent period.
Operating Expenses
Operating expenses decreased by $11.2 million in 2002 compared to last year.
Comparative operating expenses were significantly impacted by the
discontinuation of goodwill amortization. As previously mentioned, in January
2002, we adopted Statement of Financial Accounting Standards ("SFAS") 142
"Goodwill and Other Intangible Assets," which required, among other things, the
discontinuation of goodwill amortization. Goodwill amortization in the gas
distribution segment for the twelve months ended December 31, 2001 was $35.6
million. Excluding the effects of this amortization, operating expenses
increased by $24.4 million, or 3%, in 2002 compared to last year.
The increase in operating expense in 2002 is attributable, in part, to higher
pension and other postretirement benefits which increased by approximately $25
million, net of amounts deferred and subject to regulatory true-ups, over the
level incurred in 2001. The cost of these benefits has risen primarily as a
result of lower actual returns on plan assets, as well as an increase in health
care costs. Further, depreciation and amortization expense, excluding the 2001
goodwill amortization, has also increased as a result of the continued expansion
of the gas distribution system.
38
Offsetting, to some extent, the increases in expenses noted above is a favorable
$7.4 million adjustment to operating taxes recorded in 2002 related to the
reversal of certain operating tax reserves established for the KeySpan/LILCO
transaction and subsequent re-organization in May 1998. Further, we are
realizing cost saving synergies as a result of early retirement and severance
programs implemented in the fourth quarter of 2000. The early retirement portion
of the program was completed in 2000, but the severance feature continued
through 2002.
Operating expenses increased by $222.3 million, or 29%, in 2001 compared to
2000, 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 2000, as a result of cost savings synergies
realized in 2001 and lower general and administrative costs being allocated to
our New York operations as a result of a change in 2001 of the allocation
methodology for these costs pursuant to the Securities and Exchange Commission's
("SEC") 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 in 2001 reflects $35.6 million for the
amortization of goodwill as previously noted, as well as continued property
additions, and the amortization of certain costs that were previously deferred
and were recovered through gas rates in 2001.
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. Gas sales growth and customer additions are critical to our
earnings in the future. However, the beneficial effect of our growth initiatives
may not be fully realized in the short-term since we will continue to make
incremental investments in our gas distribution network and expand our
promotional campaigns to optimize the long-term growth opportunities in our
service territories.
To take advantage of the anticipated gas sales growth opportunities in our New
York service territory, in 2000 we formed the Islander East Pipeline, LLC
("Islander East"), a limited liability company in which a KeySpan subsidiary and
a subsidiary of Duke Energy Corporation each own a 50% equity interest. During
2002, Islander East received a certificate of public convenience and necessity
from the Federal Energy Regulatory Commission ("FERC") to construct, own and
operate a natural gas pipeline facility consisting of approximately 50 miles of
interstate natural gas pipeline extending from Algonquin Gas Transmission
Company's facilities in Connecticut, across the Long Island Sound and connecting
with KEDLI's facilities on Long Island. Islander East has obtained all required
permits in New York State for the construction of the facility. However, the
State of Connecticut has issued a moratorium on the issuance of the permits
relating to the construction of energy projects until June 2003. Islander East
has therefore been unable to obtain the necessary permits from the State of
Connecticut at this time. Islander East has also appealed a denial by the State
of Connecticut of the coastal zone management permit to the U.S. Department of
39
Commerce and such appeal is currently pending. Assuming the timely receipt of
approvals from the State of Connecticut, the Islander East pipeline is expected
to begin operating by year-end 2004 and will transport 260,000 DTH daily to the
Long Island and New York City energy markets, enough fuel to heat 600,000 homes,
as well as allow us to further diversify the geographic sources of our gas
supply. We are currently evaluating various options for the financing of this
pipeline. (See the discussion under "Capital Expenditures and Financing" for
more information on our financing plans for 2003.)
On December 12, 2002, we acquired Algonquin LNG, LP, the owner and operator of a
600,000 barrel FERC-regulated liquefied natural gas ("LNG") storage and
receiving facility in Providence, Rhode Island, from Duke Energy for
approximately $28 million. Algonquin LNG was renamed KeySpan LNG, L.P. and its
largest customer is Boston Gas Company, which contracts for more than half of
the facility's storage capacity.
Electric Services
The Electric Services segment primarily consists of subsidiaries that own and
operate oil and gas fired electric generating plants in the borough of Queens
(the "Ravenswood facility") and the counties of Nassau and Suffolk on Long
Island. In addition, through long-term contracts of varying lengths, we manage
the electric transmission and distribution ("T&D") system, the fuel and electric
purchases, and the off-system electric sales for LIPA.
Selected financial data for the Electric Services segment is set forth in the
table below for the periods indicated.
- ------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2002 2001 2000
- ------------------------------------------------------------------------------------------------------------------------
Revenues $ 1,421,143 $ 1,421,179 $ 1,445,886
Purchased fuel 262,072 281,398 315,139
- ------------------------------------------------------------------------------------------------------------------------
Net Revenues 1,159,071 1,139,781 1,130,747
- ------------------------------------------------------------------------------------------------------------------------
Operating Expenses
Operations and maintenance 659,882 662,083 617,399
Depreciation 61,377 52,284 49,278
Operating taxes 150,495 155,693 158,886
- ------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 871,754 870,060 825,563
- ------------------------------------------------------------------------------------------------------------------------
Operating Income 287,317 269,721 305,184
Other Income and (Deductions), net 22,346 13,812 5,639
- ------------------------------------------------------------------------------------------------------------------------
Earnings Before Interest Charges and Income Taxes $ 309,663 $ 283,533 $ 310,823
- ------------------------------------------------------------------------------------------------------------------------
Electric sales (MWH)* 5,020,741 4,932,836 4,865,344
Capacity(MW)* 2,200 2,200 2,200
Cooling degree days 1,474 1,381 1,075
- ------------------------------------------------------------------------------------------------------------------------
*Reflects the operations of the Ravenswood facility only.
40
Net Revenues
Total electric net revenues increased by $19.3 million for the twelve months
ended December 31, 2002, compared to the same period in 2001. Net revenues in
2002 reflect net revenues of $17.3 million from our new Glenwood Landing and
Port Jefferson electric "peaking" facilities located on Long Island. The
Glenwood facility was placed in service on June 1, 2002, while the Port
Jefferson facility was placed in service on July 1, 2002. These facilities add a
combined 160 megawatts of generating capacity to KeySpan's electric generation
portfolio. The capacity of and energy produced by these facilities are dedicated
to LIPA under 25 year contracts.
Net revenues from the LIPA Agreements increased by $47.2 million or 6% in 2002,
compared to last year. Included in revenues for 2002, are billings to LIPA for
certain third party costs that were significantly higher than such billings last
year. These revenues have minimal impact on earnings since we record a similar
amount of costs in operating expense and we share any cost under-runs with LIPA.
Excluding these third party billings, revenues for 2002 associated with the LIPA
Agreements were comparable to such revenues last year. In addition, in 2002 we
earned $16.0 million associated with non-cost performance incentives provided
for under these agreements, compared to $16.2 million earned last year. (For a
description of the LIPA Agreements, see "LIPA Agreements".)
Net revenues from the Ravenswood facility were $45.2 million, or 13%, lower in
2002, compared to 2001. Net revenues from capacity sales decreased 19% compared
to last year, while margins associated with the sale of electric energy were
basically flat. Comparative energy sales benefited from a 2% increase in the
megawatt hours sold as a result of the hot summer weather offset, in part, by a
reduction in "spark-spread" (the selling price of electricity less cost of
fuel). Measured in cooling degree days, weather during the 2002 cooling season
was approximately 7% warmer than last year.
The decrease in net revenues from capacity sales in 2002, was due, in part, to
more competitive pricing by the electric generators that bid into the New York
Independent System Operator ("NYISO") energy market which lowered capacity
clearing prices by approximately 8% compared to last year. Further, the NYISO
revised its methodology employed to determine the available supply of and demand
for installed capacity that also had an adverse impact on the capacity market by
reducing the capacity required to be purchased by load serving entities such as
electric utilities. However, in September 2002, the NYISO recognized a flaw in
its revised methodology. Since this flaw resulted in insufficient capacity being
procured by the market, it was identified as a reliability concern. The NYISO
corrected its methodology prior to the recent 2002/2003 winter auction to ensure
sufficient capacity is procured. Elimination of the flaw ensures compliance with
New York State Reliability Rules. The Ravenswood facility and the NYISO energy
market should benefit from this correction since, as a result, load serving
entities should procure sufficient capacity to maintain reliability for
customers.
The rules and regulations for capacity, energy sales and the sale of certain
ancillary services to the NYISO energy markets continue to evolve and the FERC
has adopted several price mitigation measures that have adversely impacted
earnings from the Ravenswood facility. Certain of these mitigation measures are
still subject to rehearing and possible judicial review.
41
The final resolution of these issues and their effect on our financial position,
results of operations and cash flows cannot be fully determined at this time.
(See discussion under Market and Credit Risk Management Activities for a further
discussion of these matters.)
Total electric net revenues increased slightly in 2001 compared to 2000. 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 adversely impacted by an increase in available
capacity in New York City during 2001.
Revenues from the service agreements with LIPA increased by $22.7 million, or 3%
in 2001 compared to 2000. Included in revenues in 2001 were billings to LIPA for
certain third party capital costs that were significantly higher than such
billings in 2000 primarily due to the construction of an underground
transmission line to reinforce the electric system capacity on the South Fork of
Long Island. As noted previously, these revenues had a minimal impact on net
income. Excluding the third party billings, revenues in 2001 associated with the
LIPA Agreements were comparable to such revenues earned during the prior 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 in 2000.
Operating Expenses
Operating expenses in 2002 were consistent with the prior year. However,
included in comparative operating expenses is an increase in third party capital
costs that are fully recoverable from LIPA, as noted previously. Excluding the
increase in these costs, operating expenses have decreased by approximately $48
million in 2002 compared to 2001. In addition to third party capital costs, LIPA
reimburses KeySpan for costs directly incurred by KeySpan in providing service
to LIPA, subject to the sharing provisions in the LIPA Agreements. These
reimbursements are based on predetermined estimates of operating costs.
Variations between certain actual operating costs incurred (i.e. postretirement
costs and property taxes) and the predetermined estimates are deferred and
refunded to or collected from LIPA in subsequent periods. As a result of an
adjustment related to this "true-up", certain pension and other postretirement
costs were approximately $23 million lower in 2002 compared to 2001. Further,
during 2002, we settled certain outstanding issues with LIPA and the
Consolidated Edison Company of New York, Inc. ("Consolidated Edison") that
resulted in a $20.3 million decrease to comparative operating expenses. The
increase in depreciation and amortization expense, as indicated in the above
table, primarily reflects depreciation associated with the two new electric
peaking facilities.
Operating expenses increased by $44.5 million, or 5% in 2001, compared to 2000,
primarily as a result of the increase in third party costs previously noted and
higher allocated charges for corporate and administrative costs due to changes
in our allocation methodology as prescribed under PUHCA.
42
Other Income and Deductions
The increases in Other Income in 2002 and 2001 are due primarily to
inter-company interest income earned by subsidiaries within the Electric
Services segment. For the most part, the various subsidiaries of KeySpan do not
maintain separate cash balances. Rather, liquid assets are maintained in a money
pool, from and to which subsidiaries can either borrow or lend. Inter-company
interest expense is charged to "borrowers", while inter-company interest income
is earned by "lenders". In all years presented in the above table, the
subsidiaries within the Electric Services segment have been net "lenders" to the
money pool and, accordingly, have earned inter-company interest income. Interest
rates associated with money pool borrowings are generally the same as KeySpan's
short-term borrowing rate. All inter-company interest income and expense is
eliminated for consolidated financial reporting purposes.
Other Matters
As previously mentioned, both the Glenwood Landing and Port Jefferson electric
generating peaking facilities are fully operational. Short-term financing was
used for the construction of these facilities, but various financing options to
permanently finance these facilities are being explored. (See the discussion
under "Capital Expenditures and Financing" for more information on our financing
plans for 2003.) Further, construction has begun on a new 250 MW combined cycle
generating facility at the Ravenswood facility site. The new facility is
expected to commence operations in late 2003. The capacity and energy produced
from this plant are anticipated to be sold into the NYISO energy markets. We are
also progressing through the siting process before the New York State Board on
Electric Generation Siting and the Environment with a proposal to build a
similar 250 MW combined cycle electric generating facility on Long Island. On
February 4, 2003, an Examiners' Recommended Decision was issued recommending the
granting of a certificate of environmental capability and public need for this
proposed facility. In addition, as part of our growth strategy, we continually
evaluate the possible acquisition of additional generating facilities in the
Northeast. However, we are unable to predict when or if any such facilities will
be acquired and the effect any such acquired facilities will have on our
financial condition, results of operations or cash flows.
Under the Generation Purchase Right Agreement ("GPRA"), LIPA had the right for a
one-year period, beginning on May 28, 2001, to acquire all of our Long Island
based generating assets formerly owned by LILCO at fair market value at the time
of the exercise of such right. By agreement dated March 29, 2002, LIPA and
KeySpan amended the GPRA to provide for a new six-month option period ending on
May 28, 2005. The other terms of the option reflected in the GPRA remain
unchanged. See the discussion under the heading "Electric Services - Revenue
Mechanisms, Generation Purchase Right Agreement" for further details.
In late 2002, LIPA announced, and we acknowledged, that during 2001 and 2002 we
had made errors in reporting LIPA's electric system requirements, resulting in
an overestimation of LIPA's unbilled revenue. LIPA and KeySpan have continued to
review and audit the reporting of electric system requirements for 2002 and
earlier periods, and have determined that, in addition to the 2002 and 2001
overestimation, unbilled revenues for prior periods back to May 1998 were
slightly underestimated. Based upon the review, the total overestimation in
unbilled revenues amounted to approximately $65 million.
43
The LIPA revenue estimation error did not have an impact on LIPA's electric
rates charged to its customers nor to its cash balances. We do not believe that
the LIPA revenue estimation error will have any material adverse impact on the
various agreements with LIPA or on our financial or operating performance.
Energy Services
The Energy Services segment primarily includes companies that provide services
through three lines of business to clients located within the New York City
metropolitan area, including New Jersey and Connecticut, as well as in Rhode
Island, Pennsylvania, Massachusetts and New Hampshire. The lines of business
are: Home Energy Services; Business Solutions; and Fiber Optic Services.
The table below highlights selected financial information for the Energy
Services segment.
- ------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2002 2001 2000
- ------------------------------------------------------------------------------------------------------------------------
Revenues $ 938,761 $ 1,100,167 $ 770,110
Less: cost of gas and fuel 206,731 407,734 248,275
- ------------------------------------------------------------------------------------------------------------------------
Net Revenues 732,030 692,433 521,835
Other operating expenses 743,965 839,918 503,512
- ------------------------------------------------------------------------------------------------------------------------
Operating Income (Loss) (11,935) (147,485) 18,323
Other Income and (Deductions), net 1,558 3,993 (3,693)
- ------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) Before Interest Charges and Income Taxes $ (10,377) $ (143,492) $ 14,630
- ------------------------------------------------------------------------------------------------------------------------
Comparative EBIT results for 2002 compared to 2001 were significantly impacted
by losses incurred by one of our subsidiaries. In 2001, we discontinued the
general contracting activities related to the former Roy Kay companies, with the
exception of completion of work on then existing contracts, based upon our view
that the general contracting business is not a core competency of these
companies. (See Note 10 to the Consolidated Financial Statements "Roy Kay
Operations" for a more detailed discussion.) For the year-ended December 31,
2001, we incurred an EBIT loss of $137.8 million associated with the operations
of the former Roy Kay companies. The Roy Kay EBIT results reflect costs related
to the discontinuation of the general contracting activities of these companies,
costs to complete work on certain loss construction projects, and operating
losses. We are completing the contracts entered into by the former Roy Kay
companies and, for the twelve months ended December 31, 2002, we incurred EBIT
losses of $10.8 million reflecting increases in the estimates of and costs to
complete these contracts, and general and administrative expenses.
Excluding the results of the former Roy Kay companies, the Energy Services
segment reflected an increase in EBIT of $6.1 million in 2002 compared to last
year. Revenues, excluding the Roy Kay companies, decreased by $180.4 million in
2002, while the cost of fuel decreased by $201.0 million. These declines, which
for the most part offset each other, reflect the operations of our gas and
electric marketing subsidiary. In 2002, this subsidiary began to focus its
marketing efforts on higher net margin customers and as a result has
substantially decreased its customer base.
44
EBIT results for the Business Solutions group of companies, which provide
mechanical contracting, plumbing, engineering and consulting services to
commercial, institutional, and industrial customers, improved by $22.3 million
in 2002 compared to 2001. This increase reflects additional work being performed
on the backlog of projects existing at year-end last year and the absence of $6
million in losses incurred on four major projects in 2001. A backlog of
approximately $514 million presently exists, which is 20% below the December 31,
2001 level.
Offsetting the positive contribution to EBIT by the Business Solutions group of
companies, was a decrease of $15.4 million associated with the Home Energy
Services group of companies. These companies provide residential and small
commercial customers with service and maintenance of appliances, as well as the
retail marketing of natural gas and electricity. Contributing to the decrease in
EBIT from Home Energy Services were the following factors: (i) the continued
adverse impact of the down-turn in the economy; (ii) the non-renewal of
appliance service contracts due to the warm first quarter weather; (iii) costs
associated with the closing of a service center; and (iv) an increase in the
reserve for bad debts. Comparative EBIT results in 2002 benefited from the
elimination of goodwill amortization, which for 2001 amounted to $8.2 million.
We continue to re-align and/or combine a number of our service centers in this
segment in order to reduce operating and general and administrative costs,
realize synergy savings and improve profitability.
Excluding the operations of the Roy Kay companies, EBIT for this segment was
$19.0 million lower in 2001 compared to 2000, reflecting costs incurred to
complete certain loss construction contracts and higher corporate allocated
costs as a result of PUHCA requirements (See "Securities and Exchange Commission
Regulation" for further discussion.)
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.
At December 31, 2002, these investments consisted of our 66% ownership interest
in Houston Exploration, as well as our wholly-owned subsidiary, KeySpan
Exploration and Production, LLC. In line with our strategy of exploring the
monetization or divesture of certain non-core assets, in October 2002 we
monetized a portion of our assets in the joint venture drilling program with
Houston Exploration that was initiated in 1999. We received $26.5 million in
cash from Houston Exploration for 18.6 BCFe of estimated proved and probable
reserves. The proceeds were used to pay down short-term debt; there was no
earnings impact from this transaction. Further, in February 2003, we reduced our
ownership interest in Houston Exploration to approximately 56% through the
repurchase, by Houston Exploration, of 3 million shares of common stock owned by
KeySpan. The net proceeds of approximately $79 million received in connection
with this repurchase were used to pay down short-term debt.
45
This segment also consists of KeySpan Canada; our 20% interest in the Iroquois
Gas Transmission System LP ("Iroquois"); and our 50% interest in Premier
Transmission Limited and 24.5% interest in Phoenix Natural Gas Limited, both
located in Northern Ireland.
Selected financial data and operating statistics for our gas exploration and
production activities is set forth in the following table for the periods
indicated.
- ------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2002 2001 2000
- ------------------------------------------------------------------------------------------------------------------------
Revenues $ 357,451 $ 400,031 $ 274,209
Depletion and amortization expense 176,925 142,728 95,364
Full cost ceiling test write-down - 41,989 -
Other operating expenses 70,267 55,653 44,435
- ------------------------------------------------------------------------------------------------------------------------
Operating Income 110,259 159,661 134,410
Other Income and (Deductions), net* (14,765) (39,728) (22,738)
- ------------------------------------------------------------------------------------------------------------------------
Earnings Before Interest Charges and Income Taxes $ 95,494 $ 119,933 $ 111,672
- ------------------------------------------------------------------------------------------------------------------------
Natural gas and oil production (Mmcf) 106,044 93,968 80,415
Natural gas (per Mcf) realized $ 3.22 $ 4.24 $ 3.38
Natural gas (per Mcf) unhedged $ 3.06 $ 4.09 $ 3.97
- ------------------------------------------------------------------------------------------------------------------------
*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.
Earnings Before Interest and Taxes
The decrease in EBIT of $24.4 million in 2002 compared to last year, reflects a
24% reduction in average realized gas prices (average wellhead price received
for production including hedging gains and losses), which lowered comparative
revenues, as well as an increase in operating expenses associated with higher
levels of production and a higher depletion rate. The adverse effect on revenues
resulting from the decline in average realized gas prices was partially offset
by an increase of 13% in production volumes.
The average realized gas price for 2002 was 105% of the average unhedged natural
gas price, resulting in revenues that were $16.4 million higher than revenues
that would have been achieved if derivative financial instruments had not been
in place during 2002. Houston Exploration hedged approximately 64% of its 2002
production, principally through the use of costless collars. The average
realized gas price for 2001 was 104% of the average unhedged natural gas price,
resulting in revenues that were $12.9 million higher than revenues that would
have been achieved if derivative financial instruments had not been employed
during 2001. These derivative instruments are designed to provide Houston
Exploration with a more predictable cash flow, as well as to reduce its exposure
to fluctuations in natural gas prices. At December 31, 2002 Houston Exploration
46
had derivative positions in place to hedge approximately 67% of its estimated
2003 production and approximately 20% of its estimated 2004 production, again
principally through the use of costless collars. Depending upon market
conditions, Houston Exploration may enter into additional derivative positions
during 2003 to hedge a larger portion of its estimated 2004 production. (See
Note 8 to the Consolidated Financial Statements, "Hedging, Derivative Financial
Instruments, and Fair Value" for further information.)
The depreciation, depletion and amortization rate was $1.68 per Mcf for the
twelve months ended December 31, 2002, compared to $1.49 per Mcf for the same
period in 2001, reflecting higher finding and development costs together with
the addition of fewer new reserves.
In 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. Excluding this charge, the comparative decrease in EBIT
for 2002 compared to 2001 would have been greater. (See Note 1 to the
Consolidated Financial Statements "Summary of Significant Accounting Policies",
Item F for more information on this charge.)
The increase in EBIT for 2001 compared to 2000 reflects a significant increase
in gas exploration and production revenues, partially offset by an increase in
operating expenses associated with higher production volumes. Revenues for 2001
benefited from the combined effect of a 17% increase in production volumes and a
25% increase in average realized gas prices. As noted above, 2001 EBIT results
also reflect the recording of a non-cash impairment charge to recognize the
effect of lower wellhead prices on the valuation of proved gas reserves.
As previously mentioned, the average realized gas price in 2001 was 104% of the
average unhedged natural gas price, resulting in revenues that were $12.9
million higher than revenues that would have been achieved if derivative
financial instruments had not been employed during 2001. The average realized
gas price in 2000 was 85% of the average unhedged natural gas price, resulting
in revenues that were $46.3 million lower than revenues that would have been
achieved if derivative financial instruments had not been in place during 2000.
Natural gas prices continue to be volatile and the risk that we may be required
to record an impairment charge on 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.
The table below indicates the net proved reserves of our gas exploration and
production subsidiaries for the periods indicated.
- ---------------------------------------------------------------------------------------------------------------
Year Ended December 31,
2002 2001 2000
- ---------------------------------------------------------------------------------------------------------------
BCFe % BCFe % BCFe %
- ---------------------------------------------------------------------------------------------------------------
Houston Exploration 650 96.7% 608 94.0% 561 94.6%
KSE E&P 22 3.3% 39 6.0% 32 5.4%
- ---------------------------------------------------------------------------------------------------------------
Total 672 100.0% 647 100.0% 593 100.0%
- ---------------------------------------------------------------------------------------------------------------
47
Selected financial data for our other energy-related investments is set forth in
the following table for the periods indicated.
- ---------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2002 2001 2000
- ---------------------------------------------------------------------------------------------------------
Revenues $ 90,778 $ 98,287 $ 35,258
Operation and maintenance expense 57,161 71,411 31,551
Other operating expenses 17,623 20,883 9,988
- ---------------------------------------------------------------------------------------------------------
Operating Income 15,994 5,993 (6,281)
Other Income and (Deductions), net 16,777 15,551 26,295
- ---------------------------------------------------------------------------------------------------------
Earnings Before Interest Charges and Income Taxes $ 32,771 $ 21,544 $ 20,014
- ---------------------------------------------------------------------------------------------------------
The increase in EBIT in 2002 compared to last year primarily reflects lower
comparative losses associated with certain technology-related investments.
Further, higher EBIT from our Northern Ireland investments were, for the most
part, offset by lower EBIT realized by KeySpan Canada. KeySpan Canada
experienced lower per unit sales prices, as well as lower quantities of sales of
natural gas liquids in 2002, as a result of generally lower oil prices. The
pricing of natural gas liquids is directly related to oil prices.
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 have been fully consolidated since the additional
investment, whereas prior to this transaction, KeySpan Canada's results were
reported as equity income in Other Income and (Deductions).
We do not consider certain businesses contained in the Energy Investments
segment to be part of our core asset group. We have stated in the past that we
may sell or otherwise dispose of all or a portion of our non-core assets. Based
on current market conditions, we cannot 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, 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 the New York State Public Service Commission
requirements, we have service companies that provide: (i) traditional corporate
and administrative services; (ii) gas and electric transmission and distribution
systems planning, marketing, and gas supply planning and procurement; and (iii)
engineering and surveying services to subsidiaries. Revised allocation
methodologies, approved by the SEC, have been in use since 2001 to allocate
certain service company costs to affiliates.
48
These non-operating subsidiaries incurred certain costs in 2002 primarily
related to general corporate expenses that were not allocated to the various
operating subsidiaries. These expenses combined with inter-company money pool
eliminations (that were higher in 2002 compared to 2001) resulted in an EBIT
loss of $27.6 million in 2002. In 2001, these non-operating subsidiaries
realized EBIT of $34.0 million, primarily related to the $22.0 million benefit
associated with the favorable appellate court decision regarding the RICO class
action settlement, previously mentioned.
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 between the two years and are as follows: (i) a charge
of $10.0 million for a contribution to the KeySpan Foundation (a not-for-profit
philanthropic foundation that makes donations to local charitable community
organizations); (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
RICO class action settlement at our corporate holding company level, as
mentioned previously, 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.
Liquidity
Cash flow from operations decreased by $81.1 million, or 9%, in 2002 compared to
2001. Operating cash flow from gas exploration and production activities was
adversely impacted by significantly lower realized gas prices in 2002. Further,
cash flow from operations in 2002 reflects the funding of the minimum pension
obligation related to our New England subsidiaries of $80 million. These adverse
effects on cash flow were partially offset by the termination of two interest
rate swap agreements that resulted in a favorable operating cash flow benefit of
approximately $23.4 million, as well as lower income tax payments. State and
federal tax payments were lower in 2002, compared to last year, as KeySpan is
currently in a refund position with regard to such taxes. (See Note 8 to the
Consolidated Financial Statements, "Hedging, Derivative Financial Instruments,
and Fair Value" for an explanation of the interest rate hedges.)
49
Cash flow from operations for 2001 reflects strong results from gas distribution
and electric operations, as well as significant contributions from 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 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 prices 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 the prior year, resulting in lower cash
expenditures required to maintain natural gas inventory in storage. Also, as
stated earlier, gas exploration and production activities benefited 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.
A substantial portion of consolidated revenues are derived from the operations
of businesses within the Electric Services segment, that are largely dependent
upon two large customers - LIPA and the NYISO. Accordingly, our cash flows are
dependent upon the timely payment of amounts owed to us by these customers.
In 2002, KeySpan renewed its existing 364-day revolving credit agreement with a
commercial bank syndicate of 16 banks totaling $1.3 billion, a reduction from
the previous $1.4 billion facility. The credit facility is used to back up the
$1.3 billion commercial paper program. The fees for the facility are subject to
a ratings-based grid, with an annual fee of .075% on the total amount of the
revolving facility. The credit agreement allows for KeySpan to borrow using
several different types of loans; specifically, Eurodollar loans, Adjustable
Bank Rate ("ABR") loans, or competitively bid loans. Eurodollar loans are based
on the Eurodollar rate plus a margin of 42.5 basis points for loans up to 33% of
the facility, and an additional 12.5 basis points for loans over 33% of the
total facility. ABR loans are based on the greater of the Prime Rate, the base
CD rate plus 1%, or the Federal Funds Effective Rate plus 0.5%. Competitive bid
loans are based on bid results requested by KeySpan from the lenders. We do not
anticipate borrowing against this facility; however, if the credit rating on our
commercial paper program were to be downgraded, it may be necessary to do so.
The credit facility contains certain affirmative and negative operating
covenants, including restrictions on KeySpan's ability to mortgage, pledge,
encumber or otherwise subject its property to any lien, as well as certain
financial covenants that require us to, among other things, maintain a
consolidated indebtedness to consolidated capitalization ratio of no more than
66%, a decrease from the 68% ratio required under the previous credit facility.
Under the terms of the credit facility, KeySpan's debt-to-total capitalization
ratio reflects 80% equity treatment for the MEDS Equity Units issued in May
2002. In addition, the $425 million Ravenswood Master Lease is treated as debt.
At December 31, 2002, consolidated indebtedness, as calculated under the terms
50
of the credit facility, was 64.6% of consolidated capitalization. This ratio was
reduced to 59.8% by the sale of 13.9 million shares of common stock in January
2003 as discussed below. Violation of this covenant could result in the
termination of the credit facility and the required repayment of amounts
borrowed thereunder, as well as possible cross defaults under other debt
agreements. (See discussion under "Capital Expenditures and Financing" for an
explanation of the MEDS Equity Units and the Ravenswood Master Lease.)
The credit facility also requires that net cash proceeds from the sale of
significant subsidiaries be applied to reduce consolidated indebtedness.
Further, an acceleration of indebtedness of KeySpan or one of its subsidiaries
for borrowed money in excess of $25 million in the aggregate, if not annulled
within 30 days after written notice, would create an event of default under the
Indenture dated November 1, 2000, between KeySpan Corporation and the
JPMorganChase Bank as Trustee. At December 31, 2002, KeySpan was in compliance
with all covenants.
At December 31, 2002, we had cash and temporary cash investments of $170.6
million. During 2002, we repaid $132.8 million of commercial paper and, at
December 31, 2002, $915.7 million of commercial paper was outstanding at a
weighted average annualized interest rate of 1.52%. We had the ability to borrow
up to an additional $384.3 million at December 31, 2002 under the commercial
paper program.
During 2002, Houston Exploration entered into a new revolving credit facility
with a commercial banking syndicate that replaced the previous $250 million
revolving credit facility. The new facility provides Houston Exploration with an
initial commitment of $300 million, which can be increased at its option to a
maximum of $350 million with prior approval from the banking syndicate. The new
credit facility is subject to borrowing base limitations, initially set at $300
million and will be re-determined semi-annually. Up to $25 million of the
borrowing base is available for the issuance of letters of credit. The new
credit facility matures on July 15, 2005, is unsecured and ranks senior to all
existing debt of Houston Exploration.
Under the Houston Exploration credit facility, interest on base rate loans is
payable at a fluctuating rate, or base rate, equal to the sum of (a) the greater
of the federal funds rate plus 0.50% or the bank's prime rate plus (b) a
variable margin between 0% and 0.50%, depending on the amount of borrowings
outstanding under the credit facility. Interest on fixed loans is payable at a
fixed rate equal to the sum of (a) a quoted reserve adjusted LIBOR rate, plus
(b) a variable margin between 1.25% and 2.00%, depending on the amount of
borrowings outstanding under the credit facility.
Financial covenants require Houston Exploration to, among other things, (i)
maintain an interest coverage ratio of at least 3.00 to 1.00 of earnings before
interest, taxes and depreciation ("EBITDA") to cash interest; (ii) maintain a
total debt to EBITDA ratio of not more than 3.50 to 1.00; and (iii) hedge no
more than 70% of natural gas production during any 12-month period. At December
31, 2002, Houston Exploration was in compliance with all financial covenants.
During 2002, Houston Exploration borrowed $79 million under its credit facility
and repaid $71 million. At December 31, 2002, $152 million of borrowings
remained outstanding at a weighted average annualized interest rate of 3.42%.
51
Also, $0.4 million was committed under outstanding letters of credit
obligations. At December 31, 2002, $147.6 million of borrowing capacity was
available. KeySpan Canada has two revolving credit facilities with financial
institutions in Canada. Repayments under these agreements totaled approximately
US $26.1 million during 2002. At December 31, 2002, approximately US $150.9
million was outstanding at a weighted average annualized interest rate of 3.23%.
KeySpan Canada currently has available borrowings of approximately US $55.8
million. These revolving credit agreements have been extended through January
2004. An event of default would exist under these credit facilities if KeySpan,
as guarantor on the facilities, falls below investment grade rating or falls
below A3 or A- at a time when its consolidated indebtedness, as measured using
the same criteria employed under KeySpan's credit facility, is greater than 66%
of consolidated capitalization or its cash flow to interest expense is less than
2.25 to 1.00. At December 31, 2002, KeySpan and KeySpan Canada were in
compliance with all covenants.
On January 17, 2003, KeySpan sold 13.9 million shares of common stock to the
open market and realized net proceeds of approximately $473 million. All shares
were offered by KeySpan pursuant to the effective shelf registration statement
filed with the SEC. Net proceeds from the equity sale were used initially to pay
down commercial paper and reduced our debt to capitalization ratio by
approximately 480 basis points. Consolidated indebtedness at December 31, 2002,
as calculated under the terms of KeySpan's credit facility and, adjusted for
this equity offering was 59.8% of consolidated capitalization. In addition, as
previously noted, we used the net proceeds of approximately $79 million received
in February 2003 in connection with the partial monetization of Houston
Exploration to repay short-term debt. The anticipated impact of additional
common shares outstanding due to the equity offering offset by the expected
interest savings from the repayments of commercial paper is anticipated to
result in dilution of approximately 7% per share in 2003.
In connection with the KeySpan/LILCO transaction, KeySpan and certain of its
subsidiaries issued promissory notes to LIPA to support certain debt obligations
assumed by LIPA. At December 31, 2002 the remaining principal amount of
promissory notes issued to LIPA was approximately $600 million. In an effort to
mitigate the dilutive effect of the equity issuance, in February 2003, KeySpan
notified LIPA of its intention to redeem approximately $447 million aggregate
principal amount of such promissory notes at the applicable redemption prices
plus accrued and unpaid interest through the dates of redemption. It is
anticipated that such redemption will take place before the end of the first
quarter of 2003. Under these promissory notes, KeySpan is required to obtain
letters of credit to secure its payment obligations if its long-term debt is not
rated at least in the "A" range by at least two nationally recognized
statistical rating agencies.
The ratings on our long-term debt have remained unchanged since December 31,
2001. The following table represents the ratings of our long-term debt at
December 31, 2002. Currently, these ratings are all on stable outlook with the
exception of Standard & Poor's rating on KeySpan which is on negative outlook.
52
- ----------------------------------------------------------------------------------------------------------
Moody's Investor Services Standard and Poor's FitchRatings
- ----------------------------------------------------------------------------------------------------------
KeySpan Corporation A3 A A-
KEDNY A2 A+ A+
KEDLI A2 A+ A
Boston Gas A2 A2 NA
Colonial Gas A A NA
- ----------------------------------------------------------------------------------------------------------
We satisfy our seasonal working capital requirements primarily through
internally generated funds and the issuance of commercial paper. We believe that
these sources of funds are sufficient to meet our seasonal working capital
needs. In addition, we currently use treasury stock to satisfy the requirements
of our dividend reinvestment and employee benefit plans.
Capital Expenditures and Financing
Construction Expenditures
The table below sets forth our construction expenditures by operating segment
for the periods indicated:
- -------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2002 2001
- -------------------------------------------------------------------------------------------------
Gas Distribution $ 407,679 $ 384,323
Electric Services 371,885 211,816
Energy Investments 324,486 437,976
Energy Services 14,316 17,134
Corporate Unallocated 15,511 8,510
- -------------------------------------------------------------------------------------------------
$ 1,133,877 $ 1,059,759
- -------------------------------------------------------------------------------------------------
Construction expenditures related to the Gas Distribution segment are primarily
for the renewal and replacement of mains and services and for the expansion of
the gas distribution system. Construction expenditures for the Electric Services
segment reflect costs to: (i) maintain our generating facilities; (ii) expand
the Ravenswood facility; and (iii) construct the new Long Island generating
facilities as previously noted. Construction expenditures related to the Energy
Investments segment primarily reflect costs associated with gas exploration and
production activities. These costs are related to the exploration and
development of properties primarily in Southern Louisiana and in the Gulf of
Mexico. Expenditures also include development costs associated with the joint
venture with Houston Exploration, as well as costs related to KeySpan Canada's
gas processing facilities.
At December 31, 2002, total expenditures associated with the siting, permitting
and construction of the Ravenswood expansion project, the siting, permitting and
procurement of equipment for the Long Island 250MW combined cycle generation
plant, and the siting and permitting of the Islander East pipeline project were
$234.6 million.
53
Construction expenditures for 2003 are estimated to be $1.1 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
At December 31, 2001, KeySpan had authorization under PUHCA to issue up to $1
billion of securities and had an existing $1 billion shelf registration
statement on file with the SEC, with $500 million available for issuance. In
February 2002, we filed a new shelf registration statement for the issuance of
an additional $1.2 billion of securities, thereby giving us the ability to issue
up to $1.7 billion of debt, equity or various forms of preferred stock.
In May 2002, we issued $460 million of MEDS Equity Units at 8.75% consisting of
a three-year forward purchase contract for our common stock and a six-year note.
The purchase contract commits us three years from the date of issuance of the
MEDS Equity Units to issue and the investors to purchase a number of shares of
our common stock based on a formula tied to the market price of our common stock
at that time. The 8.75% coupon is composed of interest payments on the six-year
note of 4.9% and premium payments on the three-year equity forward contract of
3.85%. These instruments have been recorded as long-term debt on our
Consolidated Balance Sheet, but rating agencies, as well as our credit facility,
consider between 80% to 100% of the instruments as equity for purposes of
calculating debt-to-total capitalization ratios. (See Note 6 to the Consolidated
Financial Statements "Long-Term Debt" for further details on the MEDS Equity
Units.)
The issuance of the MEDS equity units utilized $920 million of our financing
authority under both the shelf registration and the PUHCA financing authority.
Both the $460 million six-year note and the $460 million forward equity contract
are considered current issuances for these purposes. On December 6, 2002 the SEC
issued an order increasing the available financing authority under PUHCA to an
aggregate $780 million. Following the recent common stock offering previously
mentioned and shares expected to be issued for employee benefit and dividend
reinvestment plans, we have approximately $40 million available for the issuance
of new securities under our current PUHCA authorization. However, the issuance
of securities in connection with the redemption of existing securities
(including the promissory notes discussed previously) is permitted under our
PUHCA authorization notwithstanding the foregoing limit. We intend to seek
authorization to issue additional securities in the near term.
In May 2002, Colonial Gas Company repaid $15 million of its 6.81% Series A First
Mortgage Medium -Term Notes. These Notes would have matured on May 19, 2027, but
the holder of the Notes elected to exercise a put option to redeem the Notes
early.
As previously noted, we issued commercial paper to finance the construction of
our two Long Island peaking-power plants, and we will continue to finance the
construction of the new 250MW combined cycle generating facility at the
Ravenswood facility site, as well as the Islander East Pipeline, through the
issuance of commercial paper.
54
During 2003, we intend to issue approximately $150 million of either taxable or
tax-exempt long-term debt securities, the proceeds of which, it is anticipated,
will be used to re-pay the outstanding commercial paper related to the
construction of our two Long Island peaking-power plants. We also may issue an
additional $200 to $300 million of medium-term or long-term debt in 2003 to
refinance existing indebtedness. We will continue to evaluate our capital
structure and financing strategy for 2003 and beyond. We believe that our
current sources of funding (i.e., internally generated funds, the issuance of
additional securities as noted above, and the availability of commercial paper),
together with the cash proceeds from the recent equity offering, are sufficient
to meet our anticipated working capital needs for the foreseeable future.
Off-Balance Sheet Arrangements
Guarantees
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 US
$130 million revolving credit agreement associated with KeySpan Canada. Both the
medium-term notes and outstanding borrowings under the credit agreement are
reflected on the Consolidated Balance Sheet.
Further, at December 31, 2002 KeySpan has guaranteed: (i) $153.9 million of
surety bonds associated with certain construction projects currently being
performed by subsidiaries within the Energy Services segment; (ii) certain
supply contracts, margin accounts and purchase orders for certain subsidiaries
in the aggregate amount of $65.7 million; (iii) the obligations of KeySpan
Ravenswood LLC, the lessee under the $425 million Master Lease Agreement
associated with the Ravenswood facility; and (iv) $64.4 million of subsidiary
letters of credit. KeySpan has also guaranteed $25 million associated with a
non-affiliated company's line of credit. These guarantees are not recorded on
the Consolidated Balance Sheet. The guarantee of the KEDLI medium-term notes
expires in 2010, while the other guarantees have terms that do not extend beyond
2005; however the Master Lease Agreement can be extended to 2009. At this time,
we have no reason to believe that our subsidiaries will default on their current
obligations. However, we cannot predict when or if any defaults may take place
or the impact such defaults may have on our consolidated results of operations,
financial condition or cash flows. (See Note 7 to the Consolidated Financial
Statements, "Contractual Obligations, Financial Guarantees and Contingencies"
for a description of the leasing arrangement associated with the Ravenswood
Master Lease Agreement and additional information regarding KeySpan's
guarantees.)
Variable Interest Entity
We have an arrangement with a variable interest entity through which we lease a
portion of the Ravenswood facility. We acquired the Ravenswood facility, in
part, through the variable interest entity from Consolidated Edison on June 18,
1999 for approximately $597 million. In order to reduce the initial cash
requirements, we entered into a lease agreement (the "Master Lease") with a
variable interest, unaffiliated financing entity that acquired a portion of the
facility, or three steam generating units, directly from Consolidated Edison and
leased it to a KeySpan subsidiary. The variable interest unaffiliated financing
55
entity acquired the property for $425 million, financed with debt of $412.3
million (97% of capitalization) and equity of $12.7 million (3% of
capitalization). Monthly lease payments equal the monthly interest expense on
the debt securities. The Master Lease currently qualifies as an operating lease
for financial reporting purposes while preserving our ownership of the facility
for federal and state income tax purposes.
The initial term of the Master Lease expires on June 20, 2004 and may be
extended until June 20, 2009. In June 2004, we have the right to either purchase
the facility at the original acquisition cost of $425 million plus the present
value of the lease payments that would otherwise have been paid through June 20,
2009, or terminate the Master Lease and dispose of the facility. If the Master
Lease is terminated, KeySpan has guaranteed an amount equal to 83% of the
original acquisition cost plus the present value of the lease payments that
would have otherwise been paid through June 20, 2009. In June 2009, when the
Master Lease terminates, we may purchase the facility in an amount equal to the
original acquisition cost, subject to adjustments, or surrender the facility to
the lessor. If we elect not to purchase the facility, the lessor will sell the
property; we have guaranteed the lessor 84% of the original acquisition cost.
In January 2003, The Financial Accounting Standards Board (the "Board") issued
Interpretation No. 46 ("FIN 46"), "Consolidation of Variable Interest Entities,
an Interpretation of ARB No. 51". This Interpretation would require us to, among
other things, consolidate this variable interest entity for the first interim
period ending after June 15, 2003, so long as the current variable interest
structure remains intact. This Interpretation will require us to classify the
Master Lease as debt on the Consolidated Balance Sheet at an amount generally
equal to fair market value. As previously mentioned, under the terms of our
credit facility the Master Lease is considered debt in the ratio of
debt-to-total capitalization and therefore, implementation of FIN 46 will have
no impact on our credit facility. Further, we will be required to record an
asset on the Consolidated Balance Sheet for an amount equal to the fair market
value of the leased assets. However, such amount cannot exceed the amount of
debt to be recorded for the variable interest entity. At this time, we believe
that the fair market value of the leased assets is in excess of the original
acquisition cost. The Interpretation contains certain other provisions that we
will be required to implement in 2003 and such provisions may impact future
earnings. (See Note 7 to the Consolidated Financial Statements "Contractual
Obligations, Financial Guarantees and Contingencies" for additional information
on the Master Lease and Interpretation No. 46 implementation issues.)
Contractual Obligations
KeySpan has certain contractual obligations related to its outstanding long-term
debt, outstanding credit facility borrowings, outstanding commercial paper
borrowings, operating and capital leases, and demand charges associated with
certain commodity purchases. KeySpan's outstanding short-term and long-term debt
issuances are explained in more detail in Note 6 to the Consolidated Financial
Statements "Long-Term Debt". KeySpan's operating and capital leases, as well as
its demand charges are more fully detailed in Note 7 to the Consolidated
Financial Statements "Contractual Obligations, Financial Guarantees and
Contingencies". The table below reflects maturity schedules for KeySpan's
contractual obligations at December 31, 2002:
56
- --------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
Contractual Obligations Total 1 - 3 Years 4 - 5 Years After 5 Years
- --------------------------------------------------------------------------------------------------------
Long-term Debt $ 5,229,855 $ 1,337,999 $ 512,666 $ 3,379,190
Capital Leases 13,884 3,157 2,064 8,663
Operating Leases 604,782 244,306 159,508 200,968
Demand Charges 462,297 462,297 - -
- --------------------------------------------------------------------------------------------------------
Total Contractual
Cash Obligations $ 6,310,818 $ 2,047,759 $ 674,238 $ 3,588,821
- --------------------------------------------------------------------------------------------------------
Commercial Paper $ 915,697 Revolving
- --------------------------------------------------------------------------------------------------------
Discussion of Critical Accounting Policies and Assumptions
In preparing our financial statements, the application of certain accounting
policies requires difficult, subjective and/or complex judgments. The
circumstances that make these judgments difficult, subjective and/or complex
have to do with the need to make estimates about the impact of matters that are
inherently uncertain. Actual effects on our financial position and results of
operations may vary significantly from expected results if the judgments and
assumptions underlying the estimates prove to be inaccurate. The critical
accounting policies requiring such subjectivity are discussed below.
Percentage-of-Completion
Percentage-of-completion accounting is the prescribed method of accounting for
long-term construction type contracts in accordance with Generally Accepted
Accounting Principles and, accordingly, the method used for revenue recognition
by the Energy Services segment. Percentage-of-completion is measured principally
by comparing the percentage of costs incurred 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 in which such losses are
determined. Application of percentage-of-completion accounting results in the
recognition of costs and estimated earnings in excess of billings on uncompleted
contracts (recorded within the Consolidated Balance Sheet) which arise when
revenues have been recognized but the amounts cannot be billed under the terms
of the contracts. Such amounts are recoverable from customers based on various
measures of performance, including achievement of certain milestones, completion
of specified units or completion of the contract. Due to uncertainties inherent
within estimates employed to apply percentage-of-completion accounting, it is
possible that estimates will be revised as project work progresses. Changes in
estimates resulting in additional future costs to complete projects can result
in reduced margins or loss contracts. Application of percentage-of-completion
accounting requires that the impact of those revised estimates be reported in
the consolidated financial statements prospectively.
57
Valuation of Goodwill
KeySpan records goodwill on purchase transactions, representing the excess of
acquisition cost over the fair value of net assets acquired. In testing for
goodwill impairment under SFAS 142, significant reliance is placed upon
estimated future cash flows requiring broad assumptions and significant judgment
by management. Cash flow estimates are determined based upon future commodity
prices, customer rates, customer demand, operating costs, rate relief from
regulators, customer growth and other items. A change in the fair value of our
investments could cause a significant change in the carrying value of goodwill.
While we believe that our assumptions are reasonable, actual results may differ
from our projections. The assumptions used to measure the fair value of our
investments are the same as those used by us to prepare yearly operating segment
and consolidated earnings and cash flow forecasts. In addition, these
assumptions are used to set yearly budgetary guidelines.
Under SFAS 142, goodwill is deemed impaired if the fair value of the reporting
unit's assets is less than the carrying value of those assets including
goodwill. It was determined that KeySpan's financial reporting segments are
virtually the same as the reporting unit levels as defined in SFAS 142.
For those segments with goodwill, the following amounts were evaluated using the
standards set forth by SFAS 142 through December 31, 2002.
- -------------------------------------------------------------------
(In Thousands of Dollars)
- -------------------------------------------------------------------
Reporting Unit
Gas Distribution $ 1,592,510
Energy Services 142,121
Energy Investments and other 55,120
- -------------------------------------------------------------------
Total Goodwill $ 1,789,751
- -------------------------------------------------------------------
The majority of the goodwill associated with the Gas Distribution unit resulted
from the November 2000 acquisition of Eastern and ENI. For purposes of
determining goodwill impairment, the fair value of the entire Gas Distribution
segment is evaluated against the carrying value of the entire unit. Some of the
major factors that were considered in determining the fair value of the Gas
Distribution unit included assumptions regarding the growth in revenues,
earnings before interest, taxes, depreciation and amortization, and the weighted
average cost of capital.
For the initial implementation of SFAS 142, the fair value of each of the
reporting units exceeded the carrying value and no impairment charge was
necessary. The fair value for the reporting units was evaluated based on the
present value of anticipated cash flows.
As permitted under SFAS 142, we can rely on our previous valuations for the
annual impairment testing provided that the following criteria for each
reporting unit are met: (a) the assets and liabilities that make up the
reporting unit have not changed significantly since the most recent fair value
determination; and (b) the most recent fair value determination resulted in an
amount that exceeded the carrying amount of the reporting unit by a substantial
margin.
58
In the case of the Gas Distribution and the Energy Investments segment, the
above criteria have been met and no further evaluation was required. In regard
to the Energy Services segment, criteria (b) was not met since the initial fair
value valuation did not exceed the carrying value by an amount deemed by us to
be substantial. However, our annual test was performed in the fourth quarter of
2002 which verified that no impairment charge was deemed necessary. KeySpan will
continue to monitor the goodwill associated with this reporting unit.
Accounting for the Effects of Rate Regulation on Gas Distribution Operations
The financial statements of the Gas Distribution segment reflect the ratemaking
policies and orders of the NYPSC, the New Hampshire Public Utilities Commission
("NHPUC"), and the Massachusetts Department of Telecommunications and Energy
("DTE").
Four of our six regulated gas utilities (KEDNY, KEDLI, Boston Gas Company and
EnergyNorth Natural Gas, Inc.) are subject to the provisions of SFAS 71,
"Accounting for the Effects of Certain Types of Regulation." This statement
recognizes the actions of regulators, through the ratemaking process, to create
future economic benefits and obligations affecting rate-regulated companies.
In separate merger-related orders issued by the DTE, the base rates charged by
Colonial Gas Company and Essex Gas Company have been frozen at their current
levels for a ten-year period ending 2009. Due to the length of these base rate
freezes, the Colonial and Essex Gas Companies had previously discontinued the
application of SFAS 71.
SFAS 71 allows for the deferral of expenses and income on the consolidated
balance sheet as regulatory assets and liabilities when it is probable that
those expenses and income will be allowed in the rate setting process in a
period different from the period in which they would have been reflected in the
consolidated statements of income of an unregulated company. These deferred
regulatory assets and liabilities are then recognized in the consolidated
statement of income in the period in which the amounts are reflected in rates.
Rate regulation is undergoing significant change as regulators and customers
seek lower prices for utility service and greater competition among energy
service providers. In the event that regulation significantly changes the
opportunity for us to recover costs in the future, all or a portion of our
regulated operations may no longer meet the criteria for the application of SFAS
71. In that event, a write-down of our existing regulatory assets and
liabilities could result. If we were unable to continue to apply the provisions
of SFAS 71 for any of our rate regulated subsidiaries, we would apply 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, 2002 could result in
a charge to net income of $230.1 million or $1.63 per share, which would be
classified as an extraordinary item. In management's opinion, our regulated
subsidiaries that currently are subject to the provisions of SFAS 71 will
continue to be subject to SFAS 71 for the foreseeable future.
59
As is further discussed under the caption "Regulation and Rate Matters", the
rate plans previously in effect for KEDNY, KEDLI and Boston Gas Company have all
expired. The continued application of SFAS 71 to record the activities of these
subsidiaries is contingent upon the actions of regulators with regard to future
rate plans. We anticipate filing a base rate case and a performance based rate
plan for Boston Gas Company in the second quarter of 2003. Further, we are
currently evaluating various options that may be available to us including, but
not limited to, proposing new plans for KEDNY and KEDLI. The ultimate resolution
of any future rate plans could have a significant impact on the application of
SFAS 71 to these entities and, accordingly, on our financial position, results
of operations and cash flows. However, management believes that currently
available facts support the continued application of SFAS 71 and that all
regulatory assets and liabilities are recoverable or refundable through the
regulatory environment.
Pension and Other Postretirement Benefits
As discussed in Note 4 of the Consolidated Financial Statements, "Postretirement
Benefits", KeySpan participates in both non-contributory defined benefit pension
plans, as well as other post-retirement benefit ("OPEB") plans (collectively
"postretirement plans"). KeySpan's reported costs of providing pension and OPEB
benefits are dependent upon numerous factors resulting from actual plan
experience and assumptions of future experience. Pension and OPEB costs
(collectively "postretirement costs") are impacted by actual employee
demographics, the level of contributions made to the plans, earnings on plan
assets, and health care cost trends. Changes made to the provisions of these
plans may also impact current and future postretirement costs. Postretirement
costs may also be significantly affected by changes in key actuarial
assumptions, including, anticipated rates of return on plan assets and the
discount rates used in determining the postretirement costs and benefit
obligations.
The discount rate used for our postretirement benefits at December 31, 2002 was
6.75%. Our discount rate assumption is based upon the current investment yield
associated with rating agency indices that have high quality long-term corporate
bonds.
For 2002, the assumed long-term return on our postretirement plans' assets was
8.5%. In selecting an assumed rate of return, we consider past performance and
economic forecasts for the types of investments held by the plans. The actual
10-year compound rate of return, net of all expenses, for the KeySpan
postretirement plans are greater than 8.5%. In addition, in eight of the last 10
years, actual returns have been greater than 8.5%. Our postretirement plans'
assets presently consist of approximately 65% equity, 33% fixed income/bonds and
2% cash. In an effort to maximize plan performance, actual asset allocation will
fluctuate from year to year depending on the then current economic environment.
Based upon the historical performance of equity investments over time, our asset
allocation, and our investment strategy, the assumed long-term rate of return
appears reasonable.
Our health care cost trend assumptions are developed based on historical cost
data, the near-term outlook and an assessment of likely long-term trends. The
salary growth assumptions reflect our long-term actual experience and future and
near-term outlook.
60
Actual results that differ from our assumptions are accumulated and amortized
over ten years.
Certain gas distribution subsidiaries are subject to SFAS 71, and, as a result,
changes in postretirement expenses are deferred for future recovery from or
refund to gas sales customers. Further, changes in postretirement expenses
associated with subsidiaries that service the LIPA Agreements are also deferred
for future recovery from or refund to LIPA. As a result of these deferrals, we
estimate that the actual impact of postretirement expense to KeySpan's
Consolidated Statement of Income is approximately 50% of the otherwise
actuarially determined expense.
The year-end December 31, 2002 assumed discount rate used to determine
postretirement obligations was 6.75%. A 25 basis point increase or decrease in
the assumed year-end discount rate would have had no impact on 2002 expense.
However, a 25 basis point decrease in the assumed year-end discount rate would
result in the recording of an additional minimum pension liability. Therefore, a
year-end discount rate of 6.50% would have required an additional $76.4 million
debit to Other Comprehensive Income ("OCI"), net of tax and deferrals noted
previously. A year-end discount rate of 7.00% would have reduced the charge to
OCI by a net $8.8 million.
At January 1, 2002, the assumed discount rate used to determine postretirement
obligations was 7.0%. A 25 basis point increase or decrease in the assumed
discount rate at the beginning of the year would have impacted 2002 expense by
approximately $4.2 million, net of tax and deferrals.
In 2002, the expected rate of return on plan assets was 8.50%. A 25 basis point
increase or decrease in the return on plan assets would have impacted 2002
expense by approximately $2.0 million, net of tax and deferrals.
Historically, we have funded our pension plans in excess of the amount required
to satisfy minimum ERISA funding requirements. At December 31, 2002, we had a
funding balance in excess of the ERISA minimum funding requirements and as a
result KeySpan will not be required to make any contribution to its pension
plans in 2003. However, although we have presently exceeded ERISA funding
requirements, our pension plans, on an actuarial basis, are currently
underfunded. Future funding requirements are heavily dependent on actual return
on plan assets. Therefore, if the actual return on plan assets continues to be
significantly below the expected returns, we may elect to fund the pension plans
in 2003.
Full Cost Accounting
Our gas exploration and production subsidiaries use the full cost method to
account for their natural gas and oil properties. Under full cost accounting,
all costs incurred in the acquisition, exploration, and development of natural
gas and oil reserves are capitalized into a "full cost pool". Capitalized costs
include costs of all unproved properties, internal costs directly related to
natural gas and oil activities, and capitalized interest.
Under full cost accounting rules, total capitalized costs are limited to a
ceiling equal to the present value of future net revenues, discounted at 10%,
plus the lower of cost or fair value of unproved properties less income tax
effects (the "ceiling limitation"). A quarterly ceiling test is performed to
61
evaluate whether the net book value of the full cost pool exceeds the ceiling
limitation. If capitalized costs (net of accumulated depreciation, depletion and
amortization) less deferred taxes are greater than the discounted future net
revenues or ceiling limitation, a write-down or impairment of the full cost pool
is required. A write-down of the carrying value of the full cost pool is a
non-cash charge that reduces earnings and impacts stockholders' equity in the
period of occurrence and typically results in lower depreciation, depletion and
amortization expense in future periods. Once incurred, a write-down is not
reversible at a later date.
The ceiling test is calculated using natural gas and oil prices in effect as of
the balance sheet date, held constant over the life of the reserves. Our gas
exploration and production subsidiaries use derivative financial instruments
that qualify for hedge accounting under SFAS 133 to hedge against the volatility
of natural gas prices. In accordance with current SEC guidelines, these
derivatives are included in the estimated future cash flows in the ceiling test
calculation. In calculating the ceiling test at December 31, 2002, our
subsidiaries estimated that a full cost ceiling "cushion" existed, whereby the
carrying value of the full cost pool was less that the ceiling limitation. No
writedown is required when a cushion exists. Natural gas prices continue to be
volatile and the risk that a write down to the full cost pool will be required
increases when natural gas prices are depressed or if there are significant
downward revisions in estimated proved reserves.
Natural gas and oil reserve quantities represent estimates only. Under full cost
accounting, reserve estimates are used to determine the full cost ceiling
limitation as well as the depletion rate. Houston Exploration estimates its
proved reserves and future net revenues using sales prices estimated to be in
effect as of the date it makes the reserve estimates. Natural gas prices, which
have fluctuated widely in recent years, affect estimated quantities of proved
reserves and future net revenues. Any estimates of natural gas and oil reserves
and their values are inherently uncertain, including many factors beyond our
control. The accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment. In
addition, estimates of reserves may be revised based upon actual production,
results of future development and exploration activities, prevailing natural gas
and oil prices, operating costs and other factors, which revision may be
material. Reserve estimates are highly dependent upon the accuracy of the
underlying assumptions. Actual future production may be materially different
from estimated reserve quantities and the differences could materially affect
future amortization of natural gas and oil properties.
Valuation of Derivative Instruments
We employ derivative instruments to hedge a portion of our exposure to commodity
price risk and interest rate risk, to partially hedge the cash flow variability
associated with our electric energy and capacity sales from the Ravenswood
facility, as well as to economically hedge certain other commodity exposures. In
addition, KeySpan Canada has used swap instruments to lock-in the purchase price
on the purchase of electricity needed to operate its gas processing plants.
62
All of our derivative instruments, except for certain weather derivatives, meet
the SFAS 133 definition of a derivative. For those derivative instruments
designated as cash flow hedges, changes in the market value of substantially all
of our derivatives are recorded in Other Comprehensive Income, (in line with
effectiveness measurements) and are not recorded through earnings until the
derivative positions are settled. Further, none of KeySpan's derivative
instruments qualify as "energy trading contracts" as defined by current
accounting literature.
When available, quoted market prices are used to record a contract's fair value.
However, market values for certain derivative contracts may not be readily
available or determinable. A number of our commodity related derivative
instruments are exchange traded and, accordingly, fair value measurements are
generally based on standard New York Mercantile Exchange ("NYMEX") quotes. We
use industry-published indices, NYISO location zone indices, as well as other
local published indices to value contracts for commodities that are not exchange
traded, such as No. 6 grade fuel oil and electricity. The fair value of our
electric capacity hedges is based on published NYISO capacity bidding prices.
Further, if no active market exists for a commodity, fair values may be based on
pricing models.
For collar transactions relating to natural gas sales associated with our gas
exploration and production subsidiaries, we use standard NYMEX quotes, and
published volatility with Black- Scholes valuations to calculate the fair value
of these instruments.
All fair value measurements, whether calculated using standard NYMEX quotes or
other valuation techniques, are subjective and subject to fluctuations in
commodity prices, interest rates and overall economic market conditions and, as
a result, our fair value measurements may not be precise and can fluctuate
significantly from period to period.
The table below summarizes the sources of fair value for cash-flow derivative
instruments that qualify for hedge accounting treatment at December 31, 2002.
- ---------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars) Fair Value of Contracts
- ---------------------------------------------------------------------------------------------------------------
Maturity Maturity Total
Source of Fair Value 2003 2004 Fair Value
- ---------------------------------------------------------------------------------------------------------------
Prices actively quoted $ (16,959) $ (91) $ (17,050)
Prices provided by external sources 124 - 124
Prices based on models and other valuation methods (10,743) (3,675) (14,418)
Local published indices (467) (817) (1,284)
- ---------------------------------------------------------------------------------------------------------------
$ (28,045) $ (4,583) $ (32,628)
- ---------------------------------------------------------------------------------------------------------------
During 2002, we also had interest rate swap agreements in which approximately
$1.3 billion of fixed rate debt was effectively converted to floating rate debt.
The fair values of these derivative instruments were provided to us by our
counter-parties and represent the present value of estimated future cash-flows
based on a forward interest rate curve for the life of the derivative
instrument.
63
Additionally, we use derivative financial instruments to reduce cash flow
variability associated with the purchase price for a portion of future natural
gas purchases for our regulated gas distribution activities. Since these
derivative instruments are employed to reduce variability of the purchase price
of natural gas to be sold to regulated firm gas sales customers, the accounting
for these derivative instruments is subject to SFAS 71. At December 31, 2002,
these instruments had a fair value of $4.8 million and were valued using,
primarily, standard NYMEX quotes. These derivative instruments will be settled
in 2003. Further, certain contracts for the physical purchase of natural gas for
our regulated firm gas sales customers can no longer be exempted as normal
purchases from the requirements of SFAS 133. At December 31, 2002, these
contracts had a fair value of $1.2 million. The fair value for these contracts
was determined using matrix-pricing models based on contracts with similar terms
and risks.
KeySpan also has a small number of derivative financial instruments that meet
the SFAS 133 definition of a derivative but do not qualify for hedge accounting
treatment. Further, these instruments do not qualify as "energy trading
contracts" as defined by current accounting literature. We use NYMEX futures to
economically hedge the cash flow variability associated with the purchase of
fuel for a portion of our fleet vehicles. KeySpan Canada has a portfolio of
financially-settled natural gas collars and natural gas liquid swap
transactions. Finally, our retail gas and electric marketing subsidiary has
bought options to economically hedge the cash flow variability associated with a
portion of expected future natural gas purchases. At December 31, 2002, these
instruments, all of which expire in 2003, had an unfavorable net mark-to-market
value of $0.4 million, which was recorded to earnings. We use standard NYMEX
quotes, local published commodity indices, and prices provided by external
sources to value these instruments.
See Note 8 to the Consolidated Financial Statements "Hedging, Derivative
Financial Instruments and Fair Values" for a further description of all our
derivative 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. Based on currently foreseeable market
conditions, we intend to maintain the dividend at the $1.78 level.
Pursuant to NYPSC orders, the ability of KEDNY and KEDLI to pay dividends to
KeySpan 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, 2002 and November 30, 2002, respectively), the ratio of debt to
total utility capitalization was 42% and 52%, respectively. Additionally, we
have met the requisite customer service performance standards. 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").
64
Regulation and Rate Matters
Gas Distribution
By orders dated February 5, 1998 and April 14, 1998, the NYPSC approved the
KeySpan/LILCO business combination 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 was 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 level for the rate year ended
September 30, 2002 was 13.25%. KEDNY slightly exceeded the threshold return on
equity for the rate year ended September 30, 2002. On September 30, 2002,
KEDNY's rate agreement with the NYPSC expired. Under the terms of the agreement,
the then current gas distribution rates and all other provisions, including the
earnings sharing provision (at the 13.25% threshold level), remain in effect
until changed by the NYPSC. At this time, we are currently evaluating various
options that may be available to us regarding KEDNY's rates, including but not
limited to, proposing a new rate plan.
The 1998 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, 2002. 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. At this time, we are currently evaluating
various options that may be available to us regarding KEDLI's rate plan,
including but not limited to, proposing a new rate plan.
We expect current gas distribution rates for KEDNY and KEDLI to remain in effect
through 2003.
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 DTE.
65
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 were
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. With respect to this appeal, on March
7, 2002, the Massachusetts Supreme Judicial Court ruled in favor of Boston Gas
Company and reduced the productivity factor from 1.0% to .5%. Further, the plan
contains 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. The Plan expired on October 31,
2002.
On March 27, 2002, we filed notice, as required, with the DTE that we may file a
base rate case and a performance based rate plan for the Boston Gas Company to
replace the plan that expired on October 31, 2002. On May 21, 2002, we filed
with the DTE a request to extend the existing performance based rate plan for an
additional term of one year. This request was denied by the DTE in early
September 2002. As a result, we anticipate filing a base rate case and a
performance based rate plan for the Boston Gas Company in the second quarter of
2003, to be effective in the fourth quarter of 2003.
In connection with the Eastern acquisition of Colonial Gas Company in 1999, the
DTE approved a merger and rate plan that resulted in a ten year freeze of base
rates to Colonial Gas Company's firm customers. 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.
EnergyNorth Natural Gas, Inc.'s base rates continue as set by the NHPUC in 1993.
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 as amended on December 6, 2002 and February 14, 2003,
provides us with, among other things, authorization to do the following through
December 31, 2003 (the "Authorization Period"): (a) subject to an aggregate
amount of $5.8 billion, (i) maintain existing financing agreements, (ii) issue
66
and sell up to $2.2 billion of additional securities in compliance with certain
defined parameters, (iii) issue additional guarantees and other forms of credit
support in an aggregate amount of $2.0 billion at any time in addition to any
such securities, guarantees and credit support outstanding or existing as of
November 8, 2000, and (iv) amend, renew, extend, supplement or replace any of
the foregoing; (b) issue shares of common stock or reissue shares of common
stock held in treasury under dividend reinvestment and stock-based management
incentive and employee benefit plans; (c) maintain existing and enter into
additional hedging transactions with respect to outstanding indebtedness in
order to manage and minimize interest rate costs; (d) invest up to $2.2 billion
in exempt wholesale generators; and (e) pay dividends out of capital and
unearned surplus as well as paid-in-capital with respect to certain
subsidiaries, subject to certain limitations.
In addition, we have committed that during the Authorization Period, our common
equity will be at least 30% of our consolidated capitalization and each of our
utility subsidiaries' common equity will be at least 30% of such entity's
capitalization. At December 31, 2002 our consolidated common equity was 33% of
our consolidated capitalization, including commercial paper, and each of our
utility subsidiaries common equity was at least 35% of its respective
capitalization.
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 a contract, which provides certain incentives and
imposes certain penalties based upon performance. We have reached an agreement
with LIPA to extend the MSA for 31 months through 2008, 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 budget underruns
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% on the
first $5 million in annual budget underruns, and (ii) retain 50% of additional
annual underruns up to 15% of the total cost budget, thereafter all savings
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.
67
Power Supply Agreement ("PSA")
A KeySpan subsidiary sells to LIPA all of the capacity and, to the extent
requested, energy conversion services from our existing Long Island based oil
and gas-fired generating plants. Sales of capacity and energy conversion
services are made under rates approved by the FERC. Under the terms of the PSA,
rates will be reestablished for the contract year commencing January 1, 2004 by
recalculating the revenue requirement underlying those rates. We anticipate
submitting to the FERC a rate filing reflecting the recalculated revenue
requirement in the Fall of 2003. We are unable to predict the outcome of that
proceeding at this time. 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 conversion services from us and is able to purchase energy
conversion services on a least-cost basis from all available sources consistent
with existing interconnection limitations of the T&D system. The PSA provides
incentives and penalties that can total $4 million annually for the maintenance
of the output capability and the efficiency of the generating facilities. The
PSA runs for a term of fifteen years, with LIPA having the option to renew the
PSA for an additional fifteen year term.
Energy Management Agreement ("EMA")
The EMA provides for a KeySpan subsidiary to procure and manage fuel supplies on
behalf of 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 to 2013 for the procurement of fuel supplies and eight years to 2006 for
off-system management services.
Under these 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 in the "A" range 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 formerly owned
by LILCO at fair market value at the time of the exercise of such right.
By agreement dated March 29, 2002, LIPA and KeySpan amended the GPRA to provide
for a new six month option period ending on May 28, 2005. The other terms of the
option reflected in the GPRA remained unchanged. In return for providing LIPA an
extension of the GPRA, KeySpan has been provided with a corresponding extension
of 31 months for the MSA to the end of 2008.
68
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 investor-owned entities.
KeySpan Glenwood and Port Jefferson Energy Centers
KeySpan Glenwood Energy Center LLC and KeySpan Port Jefferson Energy Center LLC
have entered into 25 year Power Purchase Agreements with LIPA (the "PPAs").
Under the terms of the PPAs, these subsidiaries sell capacity, energy conversion
services and ancillary services to LIPA. Both plants are designed to produce
79.9 megawatts. Under the PPAs, LIPA pays a monthly capacity fee, which
guarantees full recovery of each plant's construction costs, as well as an
appropriate rate of return on investment. The PPAs also obligate LIPA to pay for
each plant's costs of operation and maintenance. These costs are billed on a
monthly estimated basis and are subject to true-up for actual costs incurred.
Ravenswood Facility
We currently sell capacity, energy and ancillary services associated with the
Ravenswood facility through a bidding process into the NYISO energy markets on
both a day ahead and a real time basis. We also have the ability to enter into
bilateral transactions to sell all or a portion of the energy produced by the
Ravenswood facility to Load Serving Entities, i.e. entities that sell to
end-users or to brokers and marketers.
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 $192.9 million
and we have recorded a related liability for such amount. We have also recorded
an additional $39.2 million liability, representing the estimated environmental
cleanup costs related to a former coal tar processing facility. As of December
31, 2002, we have expended a total of $70.5 million on environmental
investigation and remediation activities. (See Note 7 to the Consolidated
Financial Statements, "Contractual Obligations, Guarantees and Contingencies"
for a further explanation of these matters.)
69
Market and Credit Risk Management Activities
Market Risk: We are exposed to market risk arising from potential changes in one
or more market variables, such as energy commodity price risk, interest rate
risk, foreign currency exchange rate risk, volumetric risk due to weather or
other variables. Such risk includes any or all changes in value whether caused
by commodity positions, asset ownership, business or contractual obligations,
debt covenants, exposure concentration, currency, weather, and other factors
regardless of accounting method. We manage our exposure to changes in market
prices using various risk management techniques for non-trading purposes,
including hedging through the use of derivative instruments, both
exchange-traded and over-the-counter contracts, purchase of insurance and
execution of other contractual arrangements. (See Item 7A. Quantitative and
Qualitative Disclosures About Market Risk and Note 8 to the Consolidated
Financial Statements "Hedging, Derivative Financial Instruments and Fair Values"
for a further explanation of derivative financial instruments.)
Credit Risk: We are exposed to credit risk arising from the potential that our
counter-parties fail to perform on their contractual obligations. Our credit
exposures are created primarily through the sale of gas and transportation
services to residential, commercial, electric generation, and industrial
customers and the provision of retail access services to gas marketers, by our
regulated gas businesses; the sale of commodities and services to LIPA and the
NYISO; the sale of gas power and services to our retail customers by our
unregulated energy service businesses; entering into financial and energy
derivative contracts with energy marketing companies and financial institutions;
and the sale of gas, natural gas liquids, oil and processing services to energy
marketing and oil and gas production companies.
We have regional concentration of credit risk due to receivables from
residential, commercial and industrial customers in New York, New Hampshire and
Massachusetts, although this credit risk is spread over a diversified base of
residential, commercial and industrial customers. Customers' payment records are
monitored and action is taken, when appropriate. Companies within the Energy
Services segment have a concentration of credit risk to large customers and to
the governmental and healthcare industries.
We also have concentrations of credit risk from LIPA, our largest customer, and
from other energy companies. Concentration of energy company counter-parties may
impact overall exposure to credit risk in that our counter-parties may be
similarly impacted by changes in economic, regulatory or other considerations.
We actively monitor the credit profile of our wholesale counter-parties in
derivative and other contractual arrangements, and manage our level of exposure
accordingly. Over the past year, the credit quality of certain energy companies
has declined. In instances where counter-parties' credit quality has declined,
we limit our credit exposure by restricting new transactions with the
counter-party, requiring additional collateral or credit support and negotiating
the early termination of certain agreements.
70
Regulatory Issues and Competitive Environment
We are subject to various other risk exposures and uncertainties associated with
our gas and electric operations. The most significant contingency involves the
evolution of the gas distribution and electric industries towards more
competitive and deregulated environments. Set forth below is a description of
these exposures.
The Gas Industry
Long Island and New York
The NYPSC 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.
On May 23, 2002, the NYPSC issued an Order Adopting Terms of Gas Restructuring
Joint Proposal Petition of KeySpan Energy Delivery New York and KeySpan Energy
Delivery Long Island for a Multi-Year Restructuring Agreement ("Joint
Proposal"). The Joint Proposal did not alter base rate levels, but established a
merchant function backout credit of $.21/dth and $.19/dth for KEDNY and KEDLI,
respectively. These credits are designed to lower transportation rates charged
to transportation only customers. These credits were based on established levels
of projected avoided costs and levels of customer migration to non-utility
commodity service. Lost revenues resulting from application of these credits
will be recovered from firm gas sales customers.
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.
On December 20, 2002, New York State Governor George Pataki signed into law the
"Energy Consumer Protection Act of 2002" ("Act"). The Act defines energy
services companies that provide gas or electric commodity service to customers
as utilities subject to the Home Energy Fair Practices Act provisions ("HEFPA")
of the New York Public Service Law. Under the Act, in certain circumstances
utilities such as KEDNY and KEDLI will be required to suspend distribution
service to customers whose commodity service has been terminated by an energy
services company. Generally, those energy services companies are required under
71
the Act to provide these customers with the same consumer protections prescribed
under HEFPA as are prescribed for full service sales customers of gas
distribution companies. Those consumer protections include a series of notices
warning of potential service termination, offering deferred payment agreements,
and special protections for elderly, blind and disabled customers. The Act
contemplates that the NYPSC will promulgate regulations implementing the Act,
but such regulations have not yet been promulgated. The Act becomes effective on
June 18, 2003. We cannot predict the impact of the Act on KeySpan's regulated or
unregulated operations at this time.
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 companies ("LDCs") 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.
Electric Industry
The Ravenswood Facility and our New York City Operations
The NYISO's New York City local reliability rules currently require that 80% of
the electric capacity needs of New York City be provided by "in-City"
generators. As additional, more efficient electric power plants are built in New
York City and the surrounding areas, the requirement that 80% of in-City load be
served by in-City generators could be modified. Construction of new transmission
facilities could also cause significant changes to the market. If generation
and/or transmission facilities are constructed, and/or the availability of our
Ravenswood facility deteriorates, then the capacity and energy sales volumes
could be adversely affected. We cannot predict, however, when or if new power
plants or transmission facilities will be built or the nature of future New York
City energy requirements or market design.
72
Regional Transmission Organizations and Standard Market Design
During 2001, the FERC issued several orders and began several proceedings
related to the development of Regional Transmission Organizations ("RTO") and
the design of the wholesale energy markets. The details of how RTOs will be
formed are currently evolving. On July 31, 2002, FERC issued a Notice of
Proposed Rulemaking ("NOPR") intended to establish a standardized national
market design and rules for competitive wholesale electric markets ("Standard
Market Design" or "SMD"). These rules would apply to transmission owners
("TOs"), independent system operators ("ISOs"), and RTOs. The SMD is intended to
create: (i) genuine wholesale competition; (ii) efficient transmission systems;
(iii) the right pricing signals for investment in transmission and generation
facilities; and (iv) more customer options. How the SMD will be implemented will
be based on FERC's final rules in this regard, as well as the subject of various
compliance filings by TOs, ISOs, and RTOs. We do not know how the markets will
develop nor how these proposed changes will impact the operations of the NYISO
or its market rules. Furthermore, we are unable to determine to what extent, if
any, this process will impact the Ravenswood facility's financial condition,
results of operations or cash flows.
New York Independent System Operator Matters
On May 31, 2002, FERC approved the NYISO's mitigation plan ("the Plan"). The
Plan retains existing mitigation measures such as $1,000/MWhr energy price caps,
non-spinning reserve bid caps, in-City capacity and energy mitigation measures,
the day ahead Automated Mitigation Procedure ("AMP"), and the NYISO's general
mitigation authority. In addition, the Plan implements a new in-City real time
automated mitigation procedure. Although prices for various energy products in
the NYISO markets have softened, it is not known to what extent each of these
proceedings and revised rules may impact the Ravenswood facility's financial
condition, results of operations or cash flows.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The market risks discussed below relate to our derivative financial instruments.
We have derivative financial instruments and derivative commodity contracts that
are exposed to potential losses due to adverse changes in interest rates,
commodity prices and weather. Interest rate risk generally is related to our
outstanding debt and financing activities. The majority of our commodity price
risk and volumetric risk due to weather relate to our Ravenswood merchant
electric operations, exploration and production operations and our gas
distribution operations. We use derivative contracts to manage price risk and
volumetric risk exposure from these activities.
73
Financially-Settled Commodity Derivative Instruments: From time to time KeySpan
has utilized derivative financial instruments, such as futures, options and
swaps, for the purpose of hedging exposure to commodity price risk and to hedge
the cash flow variability associated with a portion of peak electric energy
sales.
Houston Exploration has utilized collars, as well as over-the-counter ("OTC")
swaps to hedge the cash flow variability associated with forecasted sales of a
portion of its natural gas production. As of December 31, 2002, Houston
Exploration has hedged approximately 67% and 20% of its estimated 2003 and 2004
production, respectively. Further, Houston Exploration may enter into additional
derivative positions for 2003 and 2004. Houston Exploration used standard New
York Mercantile Exchange ("NYMEX") futures prices and published volatility in
its Black-Scholes calculation to value its outstanding derivatives. The maximum
length of time over which Houston Exploration has hedged such cash flow
variability is through December 2004.
The estimated amount of losses associated with such derivative instruments that
are reported in Other Comprehensive Income and that are expected to be
reclassified into earnings over the next twelve months is $34.9 million, or
$22.7 million after-tax.
With respect to price exposure associated with fuel purchases for the Ravenswood
facility, KeySpan employs standard NYMEX natural gas futures contracts and
over-the-counter financially settled natural gas basis swaps to hedge the cash
flow variability of a portion of forecasted purchases of natural gas. KeySpan
also employs the use of financially-settled oil swap contracts to hedge the cash
flow variability of a portion of forecasted purchases of fuel oil that will be
consumed at the Ravenswood facility. The maximum length of time over which we
have hedged cash flow variability associated with: (i) forecasted purchases of
natural gas is through December 2003; and (ii) forecasted purchases of fuel oil
is through April 2004. We used standard NYMEX futures prices to value the gas
futures contracts and industry published oil indices for number 6 grade fuel oil
to value the oil swap contracts. The estimated amount of gains associated with
all such derivative instruments that are reported in Other Comprehensive Income
and that are expected to be reclassified into earnings over the next twelve
months is $4.5 million, or $2.9 million after-tax.
Our retail gas and electric marketing subsidiary, our domestic gas distribution
operations and KeySpan Canada employed NYMEX natural gas futures contracts and
natural gas swaps to lock-in a price for expected future natural gas purchases.
As applicable, we used standard NYMEX futures prices and relevant natural gas
indices to value the outstanding contracts. The maximum length of time over
which we have hedged such cash flow variability is through December 2003. The
estimated amount of gains associated with such derivative instruments that are
reported in Other Comprehensive Income and that are expected to be reclassified
into earnings over the next twelve months is $4.9 million, or $3.2 million
after-tax.
74
We have also engaged in the use of cash-settled swap instruments to hedge the
cash flow variability associated with (i) a portion of forecasted peak electric
energy sales from the Ravenswood facility and (ii) forecasted sales of Unforced
Capacity ("UCAP") to the NYISO. The maximum length of time over which we have
hedged cash flow variability is through March 2004. We used NYISO-location zone
published indices as well as published NYISO bidding prices to value these
outstanding derivatives. The estimated amount of losses associated with such
derivative instruments that are reported in Other Comprehensive Income and that
are expected to be reclassified into earnings over the next twelve months is
$1.1 million, or $0.7 million after-tax.
KeySpan Canada also has employed electricity swap contracts to lock-in the
purchase price of electricity needed to operate its gas processing plants. These
contracts are not exchange-traded and local published indices were used to value
these outstanding swap agreements. The maximum length of time over which we have
hedged such cash flow variability is through December 2003. The estimated amount
of losses associated with such derivative instruments that are reported in Other
Comprehensive Income and that are expected to be reclassified into earnings over
the next twelve months is $1.5 million, or $1.0 million after-tax.
The following tables set forth selected financial data associated with these
derivative financial instruments noted above that were outstanding at December
31, 2002.
- ----------------------------------------------------------------------------------------------------------------------------
Type of Contract Year of Volumes Current Fair Value
Maturity mmcf Floor $ Ceiling $ Fixed Price $ Price $ ($000)
- ----------------------------------------------------------------------------------------------------------------------------
Gas
Collars 2003 54,300 3.48 4.92 - 4.43-4.99 (14,681)
2004 18,300 3.50 4.75 - 4.03-4.81 (3,767)
Swaps/Futures - Short Natural Gas 2003 14,751 - - 2.91-3.52 3.87-4.99 (20,694)
Swaps/Futures - Long Natural Gas 2003 10,580 - - 3.10-5.38 4.43-5.02 7,428
- ----------------------------------------------------------------------------------------------------------------------------
97,931 (31,714)
- ----------------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------
Fair
Type of Contract Year of Volumes Current Value
Maturity Barrel Fixed Price $ Price $ ($000)
- ---------------------------------------------------------------------------------------------------
Oil
Swaps - Short Fuel Oil 2003 90,000 28.50 28.14-31.00 (145)
Swaps - Long Fuel Oil 2003 320,815 20.05-27.20 23.72-33.81 2,633
2004 5,548 20.50-23.70 22.66-23.19 6
- ---------------------------------------------------------------------------------------------------
416,363 2,494
- ---------------------------------------------------------------------------------------------------
75
- ----------------------------------------------------------------------------------------------
Fair
Type of Contract Year of Fixed Margin/ Value
Maturity Capacity MWh Price $ Current Price $ ($000)
- ----------------------------------------------------------------------------------------------
Electricity
Swaps - Energy 2003 119,680 12.70-57.80 14.15-48.09 (1,889)
2004 68,800 14.00 22.25-22.34 (823)
Swaps - Capacity 2003 1,000 7.75 7.00-9.41 (696)
- ----------------------------------------------------------------------------------------------
1,000 188,480 (3,408)
- ----------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------
Change in Fair Value of Derivative Instruments 2002
($000)
- ------------------------------------------------------------------------------
Fair value of contracts at January 1, $ 55,097
(Gain) on contracts realized (26,204)
Fair value of new contracts when entered into during period -
(Decrease) in fair value of all open contracts (61,521)
- ------------------------------------------------------------------------------
Fair value of contracts outstanding at December 31, $ (32,628)
- ------------------------------------------------------------------------------
NYMEX futures are also used to economically hedge the cash flow variability
associated with the purchase of fuel for a portion of our fleet vehicles.
Further, KeySpan Canada has a portfolio of financially-settled natural gas
collars and natural gas liquid swap transactions. Such contracts are executed by
KeySpan Canada to: (i) synthetically fix the price that is paid or received by
KeySpan Canada for certain physical transactions involving natural gas and
natural gas liquids and (ii) transfer the price exposure of such instruments to
other trading partners. In addition, our retail gas and electric marketing
subsidiary has bought options to economically hedge the cash flow variability
associated with a portion of expected future natural gas purchases. These
derivative financial instruments do not qualify for hedge accounting under SFAS
133. At December 31, 2002, these instruments had a net fair market value of
($0.4) million, that was recorded on the Consolidated Balance Sheet. Based on
the non-hedge designation of these instruments, the loss was recognized in the
Consolidated Statement of Income.
Firm Gas Sales Derivative Instruments - Regulated Utilities: We also use
derivative financial instruments to reduce the cash flow variability associated
with the purchase price for a portion of future natural gas purchases. Our
strategy is to minimize fluctuations in firm gas sales prices to our regulated
firm gas sales customers in our New York and New Hampshire service territories.
Since these derivative instruments are employed to reduce the variability of the
purchase price of natural gas to be sold to regulated firm gas sales customers,
the accounting for these derivative instruments is subject to SFAS 71.
Therefore, changes in the market value of these derivatives have been recorded
as a Regulatory Asset or Regulatory Liability on the Consolidated Balance Sheet.
Gains or losses on the settlement of these contracts are initially deferred and
then refunded to or collected from our firm gas sales customers during the
appropriate winter heating season consistent with regulatory requirements.
76
The following table sets forth selected financial data associated with these
derivative financial instruments that were outstanding at December 31, 2002.
- -------------------------------------------------------------------------------------------------------
Fair
Type of Contract Year of Volumes Value
Maturity mmcf Fixed Price $ Current Price $ ($000)
- -------------------------------------------------------------------------------------------------------
Options 2003 5,560 3.90-4.50 4.27 3,250
Swaps 2003 2,080 3.85-4.50 4.79-4.95 1,586
- -------------------------------------------------------------------------------------------------------
7,640 4,836
- -------------------------------------------------------------------------------------------------------
Physically-Settled Commodity Derivative Instruments: On April 1, 2002 we
implemented Derivative Implementation Group ("DIG") Issue C15 and C16 of SFAS
133, "Accounting for Derivative Instruments and Hedging Activities", as amended
and interpreted, incorporating SFAS 137 and SFAS 138 and certain implementation
issues (collectively "SFAS 133"). Issue C15 establishes new criteria that must
be satisfied in order for option-type and forward contracts in electricity to be
exempted as normal purchases and sales, while Issue C16 relates to the exemption
(as normal purchases and normal sales) of contracts that combine a forward
contract and a purchased option contract. Based upon a review of our physical
commodity contracts, we determined that certain contracts for the physical
purchase of natural gas can no longer be exempted as normal purchases from the
requirements of SFAS 133. At December 31, 2002, the fair value of these
contracts was $1.2 million. Since these contracts are for the purchase of
natural gas sold to regulated firm gas sales customers, the accounting for these
contracts is subject to SFAS 71. Therefore, changes in the market value of these
contracts have been recorded as a Regulatory Asset or Regulatory Liability on
the Consolidated Balance Sheet.
Interest Rate Derivative Instruments: During most of 2002, we had interest rate
swap agreements in which approximately $1.3 billion of fixed rate debt had been
synthetically modified to floating rate debt. Under the terms of the agreements,
we received the fixed coupon rate associated with these bonds and paid the
counter-parties a variable interest rate that was reset on a quarterly basis.
These swaps were designated as fair-value hedges and qualified for "short-cut"
hedge accounting treatment under SFAS 133. Through the utilization of these
agreements, we reduced recorded interest expense by $35.6 million for the twelve
months ended December 31, 2002. In early November 2002, we terminated two
interest rate swap agreements with an aggregate notional amount of $1.0 billion
and received $80.9 million from our swap counter-parties, of which $23.4 million
represented accrued swap interest. The difference between the termination
settlement amount and the amount of accrued swap interest, $57.4 million, will
be amortized to earnings (as an adjustment to interest expense) on a level yield
basis over the remaining lives of the originally hedged debt obligations. The
remaining swap, which had a notional amount of $270.0 million, and a fair market
value of $15.6 million at December 31, 2002, was terminated on February 25,
2003. We received $18.4 million from our swap counter-parties, of which $8.1
million represents accrued swap interest. The difference between the termination
settlement amount and the amount of accrued interest, $10.3 million, will be
recorded to earnings in the first quarter of 2003. This swap was used to hedge a
portion of our outstanding promissory notes to LIPA. As discussed in Note 6 to
the Consolidated Financial Statements "Long-Term Debt", we intend to redeem a
portion of these promissory notes before the end of the first quarter of 2003.
77
Additionally, we also have an interest rate swap agreement that hedges the cash
flow variability associated with the forecasted issuance of a series of
commercial paper offerings. The maximum length of time over which we have hedged
such cash flow variability is through March 2003. The estimated amount of loss
associated with such derivative instruments that are reported in Other
Comprehensive Income and that are expected to be reclassified into earnings over
the next twelve months is $0.6 million, or $0.4 million after-tax.
Weather Derivatives: The utility tariffs associated with KEDNE's operations do
not contain weather normalization adjustments. As a result, fluctuations from
normal weather may have a significant positive or negative effect on the results
of these operations. To mitigate a substanial portion of the effect of
fluctuations from normal weather on our financial position and cash flows, we
sold heating degree-day call options and purchased heating degree-day put
options for the November 2002 - March 2003 winter season. With respect to sold
call options, KeySpan is required to make a payment of $40,000 per heating
degree day to its counter-parties when actual weather experienced during the
November 2002 - March 2003 time frame is above 4,470 heating degree days, which
equates to approximately 1% colder than normal weather. With respect to
purchased put options, KeySpan will receive a $20,000 per heating degree day
payment from its counter-parties when actual weather is below 4,150 heating
degree days, or is approximately 7% warmer than normal. Based on the terms of
such contracts, as discussed in Note 1 to the Consolidated Financial Statements
"Summary of Significant Accounting Policies", we account for such instruments
pursuant to the requirements of EITF 99-2, "Accounting for Weather Derivatives."
In this regard, we account for such instruments using the "intrinsic value
method" as set forth in such guidance. During the fourth quarter of 2002,
weather was 7% colder than normal and, as a result, $3.3 million has been
recorded as a reduction to revenues.
Derivative contracts are primarily used to manage exposure to market risk
arising from changes in commodity prices and interest rates. In the event of
nonperformance by a counter-party to a derivative contract, the desired impact
may not be achieved. The risk of a counter-party nonperformance is generally
considered credit risk and is actively managed by assessing each counter-party
credit profile and negotiating appropriate levels of collateral and credit
support.
Foreign Currency Fluctuations
We follow the principles of SFAS 52, "Foreign Currency Translation" for
recording our investments in foreign affiliates. Due to our continued activities
in Canada and Northern Ireland, our investment in foreign affiliates has been
growing. At December 31, 2002, the net assets of these affiliates was
approximately $374 million and at December 31, 2002, the accumulated after-tax
foreign currency translation included in Other Comprehensive Income was a debit
of $2.2 million. (See Note 1 to the Consolidated Financial Statements "Summary
of Significant Accounting Policies.")
78
Item 8. Financial Statements and Supplementary Data
CONSOLIDATED BALANCE SHEET
- --------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2002 2001
- --------------------------------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash and temporary cash investments $ 170,617 $ 159,252
Accounts receivable 1,122,022 1,009,166
Unbilled revenue 473,060 335,732
Allowance for uncollectible accounts (63,029) (72,299)
Gas in storage, at average cost 273,036 334,999
Material and supplies, at average cost 113,519 105,693
Other 127,224 125,944
---------------------- ---------------------
2,216,449 1,998,487
---------------------- ---------------------
Assets Held for Disposal - 191,055
Investments and Other 259,188 223,249
Property
Gas 6,124,281 5,704,857
Electric 1,974,352 1,629,768
Other 394,374 400,643
Accumulated depreciation (2,740,516) (2,533,466)
Gas exploration and production, at cost 2,438,998 2,200,851
Accumulated depletion (973,889) (796,722)
---------------------- ---------------------
7,217,600 6,605,931
---------------------- ---------------------
Deferred Charges
Regulatory assets 438,516 458,191
Goodwill, net of amortization 1,789,751 1,782,826
Other 692,802 529,867
---------------------- ---------------------
2,921,069 2,770,884
---------------------- ---------------------
Total Assets $ 12,614,306 $ 11,789,606
====================== =====================
See accompanying Notes to the Consolidated Financial Statements.
79
CONSOLIDATED BALANCE SHEET
- --------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2002 2001
- --------------------------------------------------------------------------------------------------------------------
LIABILITIES AND CAPITALIZATION
Current Liabilities
Current Redemption of long-term debt $ 11,413 $ 993
Accounts payable and other liabilities 1,061,649 1,091,430
Commercial paper 915,697 1,048,450
Dividends payable 64,714 63,442
Taxes accrued 51,276 50,281
Customer deposits 38,387 36,151
Interest accrued 77,092 93,962
---------------------- ---------------------
2,220,228 2,384,709
---------------------- ---------------------
Deferred Credits and Other Liabilities
Regulatory liabilities 84,479 39,442
Deferred income tax 877,013 598,072
Postretirement benefits and other reserves 759,731 694,680
Other 189,912 207,992
---------------------- ---------------------
1,911,135 1,540,186
---------------------- ---------------------
Commitments and Contingencies (See Note 7) - -
Capitalization
Common stock 3,005,354 2,995,797
Retained earnings 522,835 452,206
Other comprehensive income (108,423) 4,483
Treasury stock (475,174) (561,884)
---------------------- ---------------------
Total common shareholders' equity 2,944,592 2,890,602
Preferred stock 83,849 84,077
Long-term debt 5,224,081 4,697,649
---------------------- ---------------------
Total Capitalization 8,252,522 7,672,328
---------------------- ---------------------
Minority Interest in Subsidiary Companies 230,421 192,383
---------------------- ---------------------
Total Liabilities and Capitalization $ 12,614,306 $ 11,789,606
====================== =====================
See accompanying Notes to the Consolidated Financial Statements.
80
CONSOLIDATED STATEMENT OF INCOME
- ----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars, Except Per Share Amounts) 2002 2001 2000
- ----------------------------------------------------------------------------------------------------------------------------------
Revenues
Gas Distribution $ 3,163,761 $ 3,613,551 $ 2,555,785
Electric Services 1,421,043 1,421,079 1,444,711
Energy Services 938,761 1,100,167 770,110
Gas Exploration and Production 357,451 400,031 274,209
Energy Investments 89,650 98,287 35,887
------------------------------------------------------
Total Revenues 5,970,666 6,633,115 5,080,702
Operating Expenses
Purchased gas for resale 1,653,273 2,171,113 1,408,680
Fuel and purchased power 385,059 538,532 460,841
Operations and maintenance 2,101,897 2,114,759 1,659,736
Early retirement and severance charges - - 65,175
Depreciation, depletion and amortization 514,613 559,138 330,922
Operating taxes 410,651 448,924 421,936
------------------------------------------------------
Total Operating Expenses 5,065,493 5,832,466 4,347,290
------------------------------------------------------
Operating Income 905,173 800,649 733,412
------------------------------------------------------
Other Income and (Deductions)
Interest charges (301,504) (353,470) (201,314)
Income from equity investments 14,096 13,129 20,010
Minority interest (24,918) (40,847) (26,342)
Interest income 1,572 8,326 12,327
Other 28,325 26,598 (18,081)
------------------------------------------------------
Total Other Income and (Deductions) (282,429) (346,264) (213,400)
------------------------------------------------------
Earnings Before Income Taxes 622,744 454,385 520,012
Income Taxes
Current (48,487) 101,738 170,809
Deferred 273,881 108,955 46,453
------------------------------------------------------
Total Income Taxes 225,394 210,693 217,262
------------------------------------------------------
Earnings from Continuing Operations 397,350 243,692 302,750
------------------------------------------------------
Discontinued Operations
Income (loss) from operations, net of tax (3,356) 10,918 (1,943)
Loss on disposal, net of tax (16,306) (30,356) -
------------------------------------------------------
Loss from Discontinued Operations (19,662) (19,438) (1,943)
------------------------------------------------------
Net Income 377,688 224,254 300,807
Preferred stock dividend requirements 5,753 5,904 18,113
------------------------------------------------------
Earnings for Common Stock $ 371,935 $ 218,350 $ 282,694
======================================================
Basic Earnings Per Share:
Continuing Operations, less preferred stock dividends $ 2.77 $ 1.72 $ 2.12
Discontinued Operations (0.14) (0.14) (0.02)
------------------------------------------------------
Basic Earnings Per Share $ 2.63 $ 1.58 $ 2.10
======================================================
Diluted Earnings Per Share
Continuing Operations, less preferred stock dividends $ 2.75 $ 1.70 $ 2.11
Discontinued Operations (0.14) (0.14) (0.02)
------------------------------------------------------
Diluted Earnings Per Share $ 2.61 $ 1.56 $ 2.09
======================================================
Average Common Shares Outstanding (000) 141,263 138,214 134,357
Average Common Shares Outstanding - Diluted (000) 142,300 139,221 135,165
- ----------------------------------------------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
81
CONSOLIDATED STATEMENT OF CASH FLOWS
- -------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Earnings from continuing operations $ 397,350 $ 243,692 $ 302,750
Adjustments to reconcile net income to net
cash provided by (used in) operating activities
Depreciation, depletion and amortization 514,613 559,138 330,922
Early retirement and severance accruals - - 65,175
Deferred income tax (See Note 3) 90,724 108,955 46,453
Income from equity investments (14,096) (13,129) (20,010)
Dividends from equity investments 3,905 7,570 21,507
Gain from class action settlement - (33,510) -
Provision for losses on contracting business - 63,682 -
Changes in assets and liabilities
Accounts receivable (259,454) 401,976 (800,033)
Materials and supplies, fuel oil and gas in storage 54,174 (43,856) (36,952)
Accounts payable and other liabilities (19,745) (425,196) 452,076
Interest accrued 22,661 24,560 32,659
Other 18,945 (3,701) 44,179
-----------------------------------------------------
Net Cash Provided by Operating Activities 809,077 890,181 438,726
-----------------------------------------------------
Investing Activities
Construction expenditures (1,133,877) (1,059,759) (633,035)
Other investments (27,579) - (292,222)
Acquisition of Eastern Enterprise and EnergyNorth, Inc. - - (1,762,007)
Investment held for disposal - - (184,036)
Proceeds from sale of assets 175,110 18,458 -
Other - (6) (510)
-----------------------------------------------------
Net Cash (Used in) Investing Activities (986,346) (1,041,307) (2,871,810)
-----------------------------------------------------
Financing Activities
Treasury stock issued 86,710 88,786 72,289
Issuance of long-term debt 549,280 812,116 2,166,955
Payment of long-term debt (124,991) (183,410) (68,365)
Issuance (payment) of commercial paper (132,753) (251,787) 935,372
Payment of preferred stock - - (363,000)
Preferred stock dividends paid (5,753) (5,904) (20,261)
Common stock dividends paid (250,903) (245,598) (239,740)
Termination of interest rate swaps 57,415 - (59,490)
Other 9,629 12,846 (35,949)
-----------------------------------------------------
Net Cash Provided by Financing Activities 188,634 227,049 2,387,811
-----------------------------------------------------
Net (Decrease) or Increase in Cash and Cash Equivalents $ 11,365 $ 75,923 $ (45,273)
Cash and Cash Equivalents at Beginning of Period 159,252 83,329 128,602
-----------------------------------------------------
Cash and Cash Equivalents at End of Period $ 170,617 $ 159,252 $ 83,329
=====================================================
Interest Paid $ 318,374 $ 328,910 $ 165,020
Income Tax Paid $ 98,344 $ 128,558 $ 187,219
- -------------------------------------------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
82
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
- -------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Balance at Beginning of Period $ 452,206 $ 480,639 $ 456,882
Net Income for Period 377,688 224,254 300,807
- -------------------------------------------------------------------------------------------------------------------
829,894 704,893 757,689
Deductions:
Cash dividends declared on common stock 252,175 246,783 239,740
Cash dividends declared on preferred stock 5,753 5,904 20,298
MEDS Equity Units 49,131 - -
Other, primarily write-off of
capital stock expense - - 17,012
- -------------------------------------------------------------------------------------------------------------------
Balance at End of Period $ 522,835 $ 452,206 $ 480,639
- -------------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
- --------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2002 2001 2000
- --------------------------------------------------------------------------------------------------------------------------------
Net Income $ 377,688 $ 224,254 $ 300,807
- --------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax
Net gains on derivative instruments (17,033) (27,690) -
Reclassification adjustment for other gains reclassified to net income - (3,242) -
Foreign currency translation adjustments 9,759 (9,627) (7,320)
Unrealized gains (losses) on marketable securities (10,019) (5,464) 3,131
Accrued unfunded pension obligation (55,768) (13,262) -
Unrealized (losses) gains on derivative financial instruments (39,845) 62,943 -
- --------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax (112,906) 3,658 (4,189)
- --------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 264,782 $ 227,912 $ 296,618
- --------------------------------------------------------------------------------------------------------------------------------
Related tax (benefit) expense
Net gains on derivative instruments (9,172) $ (14,910) $ -
Reclassification adjustment for other gains reclassified to net income - (1,746) -
Foreign currency translation adjustments 5,255 (5,184) (3,941)
Unrealized gains (losses) on marketable securities (5,395) (2,942) 1,686
Accrued unfunded pension obligation (30,029) (7,140) -
Unrealized (losses) gains on derivative financial instruments (21,454) 33,892 -
- --------------------------------------------------------------------------------------------------------------------------------
Total Tax (Benefit) Expense $ (60,795) $ 1,970 $ (2,255)
- --------------------------------------------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
83
CONSOLIDATED STATEMENT OF CAPITALIZATION
- ------------------------------------------------------------------------------------------------------------------------------------
December 31,
(In Thousands of Dollars) 2002 2001 2002 2001
- ------------------------------------------------------------------------------------------------------------------------------------
Common Shareholders' Equity Shares Issued
Common stock, $0.01 par value 158,837,654 158,837,654 $ 1,588 $ 1,588
Premium on capital stock 3,003,766 2,994,209
Retained earnings 522,835 452,206
Other comprehensive income (108,423) 4,483
Treasury stock 16,412,880 19,407,905 (475,174) (561,884)
- ------------------------------------------------------------------------------------------------------------------------------------
Total Common Shareholders' Equity 142,424,774 139,429,749 2,944,592 2,890,602
- ------------------------------------------------------------------------------------------------------------------------------------
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 88,486 90,770 8,849 9,077
- ------------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - No Redemption Required 83,849 84,077
- ------------------------------------------------------------------------------------------------------------------------------------
Long - Term Debt Interest Rate Maturity
- ------------------------------------------------------------------------------------------------------------------------------------
Notes
Medium term notes 6.15% - 9.75% 2005 - 2030 2,885,000 2,885,000
Senior subordinated notes 8.63% 2008 100,000 100,000
- ------------------------------------------------------------------------------------------------------------------------------------
Total Notes 2,985,000 2,985,000
- ------------------------------------------------------------------------------------------------------------------------------------
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
- ------------------------------------------------------------------------------------------------------------------------------------
MEDS Equity Units 8.75% 2005 460,000 -
First Mortgage Bonds 5.50% - 10.10% 2003 - 2028 163,625 179,122
Authority Financing Notes Variable 2027 - 2028 66,005 66,005
Other Subsidiary Debt 304,298 330,293
Capital Leases 2005 - 2022 13,884 15,192
- ------------------------------------------------------------------------------------------------------------------------------------
Subtotal 5,243,739 4,826,539
Unamortized interest rate hedge and debt discount (75,265) (80,173)
Derivative impact on debt 67,020 (47,724)
Less: current maturities 11,413 993
- ------------------------------------------------------------------------------------------------------------------------------------
Total Long-Term Debt 5,224,081 4,697,649
- ------------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 8,252,522 $ 7,672,328
- ------------------------------------------------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
84
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, KeySpan 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, Staten Island and a portion of the borough of Queens 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, eastern 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 electric 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 1.1 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
85
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 Investments 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 companies. All significant intercompany transactions have
been eliminated.
As noted, on November 8, 2000, we completed the acquisitions of Eastern and ENI.
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 since the
acquisition date.
The preparation of financial statements in conformity with Generally Accepted
Accounting Principles ("GAAP") 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 ("NHPUC"), 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 GAAP 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 on the
Consolidated Balance Sheet, respectively.
86
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, 2002 and
December 31, 2001.
- -----------------------------------------------------------------------------------------------------
December 31,
(In Thousands of Dollars) 2002 2001
- -----------------------------------------------------------------------------------------------------
Regulatory Assets
Regulatory tax asset $ 53,401 $ 64,536
Property taxes 58,400 54,617
Environmental costs 182,163 183,716
Postretirement benefits other than pensions 82,563 84,238
Costs associated with the KeySpan/LILCO transaction 61,989 55,204
Derivative assets - 15,880
- ----------------------------------------------------------------------------------------------------
Total Regulatory Assets $ 438,516 $ 458,191
Regulatory Liabilities (84,479) (39,442)
- ----------------------------------------------------------------------------------------------------
Net Regulatory Assets $ 354,037 $ 418,749
- ----------------------------------------------------------------------------------------------------
The regulatory assets above are not included in rate base. However, we record
carrying charges on the property tax and costs associated with the KeySpan/LILCO
transaction cost 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 $61.8 million and $5.6 million at December 31, 2002 and December
31, 2001, respectively are reflected in Accounts Receivable on the Consolidated
Balance Sheet. Deferred gas costs are subject to current recovery from
customers.
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 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 apply
the provisions of SFAS 101, "Regulated Enterprises - Accounting for the
Discontinuation of Application of FASB Statement 71." We estimate that the
write-off of all regulatory assets at December 31, 2002 could result in a charge
to net income of $230.1 million or $1.63 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.
87
D. Revenues
Gas Distribution: 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 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. Revenues are adjusted each month the clause is
in effect and are generally included in rates in the following month. The New
England gas utility rate structures contain no weather normalization feature,
therefore their net revenues are subject to weather related demand fluctuations.
Electric Services: Electric revenues are derived from billings to 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 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. 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.
KeySpan Glenwood Energy Center LLC and KeySpan Port Jefferson Energy Center LLC
have entered into 25 year Power Purchase Agreements with LIPA (the "PPAs").
Under the terms of the PPAs, these subsidiaries sell capacity, energy conversion
services and ancillary services to LIPA. Both plants are designed to produce
79.9 megawatts ("MW"). Under the PPAs, LIPA pays a monthly capacity fee, which
guarantees full recovery of each plant's construction costs, as well as an
appropriate rate of return on investment. The PPAs also obligate LIPA to pay for
each plant's costs of operation and maintenance. These costs are billed on a
monthly estimated basis and are subject to true up for actual costs incurred.
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 7 "Contractual Obligations, Financial
Guarantees and Contingencies" for a description of the Ravenswood transaction.)
88
We realize revenues from our investment in the Ravenswood facility through the
sale, at wholesale, 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.
Energy Services: Revenues earned by our Energy Services segment for mechanical
and other contracting services 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 in which the revisions
are determined. The percentage of completion method of accounting may result in
situations where billings to customers are in excess of costs incurred to date.
These excess billings are not recognized in income until the related costs have
been incurred and the earnings process is complete. At December 31, 2002 and
December 31, 2001 we had billings in excess of costs of $27.2 million and $53.6
million, respectively. These balances are included in Accounts Payable and Other
Liabilities on the Consolidated Balance Sheet and are expected to be included in
income within one year.
Energy service and maintenance revenues are recognized as earned or over the
life of the service contract, as appropriate. Energy sales made by our electric
and gas marketing subsidiary are recorded upon delivery of the related
commodity. Fiber optic service revenue is recognized upon delivery of service
access. We have unearned revenue recorded in Deferred Credits and Other
Liabilities - Other on the Consolidated Balance Sheet totaling $19.2 million and
$18.0 million for the years ended December 31, 2002 and December 31, 2001,
respectively. These balances represent unearned revenues for service contracts
and leases on our fiber optic cables. The unearned revenues from the service
contracts are generally amortized to income within one year, while the lease
related unearned revenues are amortized over periods ranging from seven to 30
years.
Gas Exploration and Production: Natural gas and oil revenues earned by our gas
exploration and production activities is recognized using the entitlements
method of accounting. Under this method of accounting, income is recorded based
on the net revenue interest in production or nominated deliveries. Production
gas volume imbalances are incurred in the ordinary course of business. Net
deliveries in excess of entitled amounts are recorded as liabilities, while net
under deliveries are recorded as assets. Imbalances are reduced either by
subsequent recoupment of over and under deliveries or by cash settlement, as
required by applicable contracts. Production imbalances are marked-to-market at
the end of each month using the market price at the end of each period.
89
E. Utility and Other Property - Depreciation and Maintenance
Property, principally 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. The rates at which KeySpan
subsidiaries capitalized interest for years ended December 31, 2000 through 2002
ranged from 3.44% to 10.67%. Capitalized interest for 2002, 2001 and 2000 was
$19.7 million, $8.5 million and $2.7 million respectively.
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:
- ----------------------------------------------------------------------------
Year Ended December 31,
2002 2001 2000
- ----------------------------------------------------------------------------
Electric 3.88% 3.78% 3.68%
Gas 3.44% 3.40% 3.51%
- ----------------------------------------------------------------------------
We also had $394.4 million of other property at December 31, 2002, which is not
recovered under rate orders. This property consists of assets held primarily by
our Corporate Service subsidiary of $312.6 million and $81.8 million in Energy
Services assets. The Corporate Service assets consist largely of land,
buildings, office equipment and furniture, vehicles, computer and
telecommunications equipment and systems. These assets have depreciable lives
ranging from three to 40 years. Energy Service assets consist largely of
construction equipment and fiber optic cable and related electronics and have
service lives ranging from seven to 40 years.
KeySpan's repair and maintenance costs, including planned major maintenance in
the Electric Services segment for turbine and generator overhauls, are expensed
as incurred. Planned major maintenance cycles primarily range from seven to
eight years. Smaller periodic overhauls are performed approximately every 18
months.
F. Gas Exploration and Production Property - Depletion
At December 31, 2002, we had exploration and production property in the amount
of $2.4 billion related to our investments in natural gas and oil properties.
These assets are accounted for under the full cost method of accounting. Under
the full cost method, costs of acquisition, exploration and development of
natural gas and oil reserves are capitalized into a "full cost pool" as
incurred. Unproved properties and related costs are excluded from the
amortization base until a determination as to the existence of proved reserves.
Properties are depleted and charged to operations using the unit of production
method using proved reserve quantities.
These investments consist of our ownership interest in The Houston Exploration
Company ("Houston Exploration"), an independent natural gas and oil exploration
company, as well as KeySpan Exploration and Production, LLC, our wholly-owned
subsidiary engaged in a joint venture with Houston Exploration. On February 26,
2003, we reduced our ownership interest in Houston Exploration from 66% to
90
approximately 56% following the repurchase, by Houston Exploration, of 3 million
shares of stock owned by KeySpan. 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,
less deferred taxes, such excess costs are charged to operations. If an
impairment 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 the
volatility of natural gas prices. In accordance with current SEC guidelines, we
have included estimated future cash flows from our hedging program in the
ceiling test calculation. As of December 31, 2002, we estimated, using a
wellhead price of $4.99 per mcf, that our capitalized costs did not exceed the
ceiling test limitation.
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.
Houston Exploration capitalizes interest related to its unevaluated natural gas
and oil properties, as well as some properties under development which are not
currently being amoritized. For years ended December 31, 2002, 2001 and 2000,
capitalized interest was $8.0 million, $12.0 million and $13.7 million,
respectively.
G. Goodwill
At December 31, 2002 and 2001, the balance of goodwill was $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 transaction, and $176 million related to the acquisitions
of energy-related service 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.
On January 1, 2002, KeySpan adopted SFAS 142 "Goodwill and Other Intangible
Assets". Under SFAS 142, among other things, goodwill is no longer required to
be amortized and is to be tested for impairment at least annually. The initial
impairment test was to be performed within six months of adopting SFAS 142 using
a discounted cash flow method, compared to a undiscounted cash flow method
allowed under a previous standard. Any amounts impaired using data as of January
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1, 2002, was to be recorded as a "Cumulative Effect of an Accounting Change".
Any amounts impaired using data after the initial adoption date will be recorded
as an operating expense. During the second quarter of 2002, we completed our
initial impairment analysis for all the reporting units and determined that no
consolidated impairment existed. Also, in the fourth quarter of 2002, KeySpan
updated its review of the carrying value of goodwill compared to the fair value
of the assets by reporting unit and determined that no impairment existed.
As required by SFAS 142, below is a reconciliation of reported earnings
available for common stockholders for the years ended December 31, 2002, 2001
and 2000 and pro-forma net income, for the same periods, adjusted for the
discontinuance of goodwill amortization.
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Year Ended December 31,
(In Thousands of Dollars, Except for Per Share Amounts) 2002 2001 2000
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings for common stockholders $ 371,935 $ 218,350 $ 282,694
Add back: goodwill amortization* - 49,550 19,690
- ----------------------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 371,935 $ 267,900 $ 302,384
- ----------------------------------------------------------------------------------------------------------------------------------
Basic earnings per share 2.63 1.58 2.10
Add back: goodwill amortization - 0.36 0.15
- ----------------------------------------------------------------------------------------------------------------------------------
Adjusted basic earnings per share $ 2.63 $ 1.94 $ 2.25
- ----------------------------------------------------------------------------------------------------------------------------------
Diluted earnings per share $ 2.61 $ 1.56 2.09
Add back: goodwill amortization - 0.36 0.15
- ----------------------------------------------------------------------------------------------------------------------------------
Adjusted diluted earnings per share $ 2.61 $ 1.92 $ 2.24
- ----------------------------------------------------------------------------------------------------------------------------------
* Excludes the write-off of $12.4 million of goodwill in 2001 associated with
the Roy Kay Operations.
For the twelve months ended December 31, 2001 and 2000, respectively goodwill
amortization was recorded in each segment as follows: Gas Distribution $35.6 and
$5.9 million; Energy Services $8.2 and $7.6 million; and Energy Investments and
other $5.8 and $6.2 million. The increase in amortization expense in 2001 versus
2000 primarily reflects the acquisition of Eastern and ENI in November 2000.
Prior to implementation of SFAS 142, goodwill was reviewed for impairment under
SFAS 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of". Under SFAS 121, 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 10, "Roy Kay Operations" for
additional information.)
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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 hedge
cash flow variability associated with 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. Our derivative instruments do not qualify as energy
trading contracts as defined by current accounting literature.
Financially-Settled Commodity Derivative Instruments: We employ derivative
financial instruments, such as futures, options and swaps, for the purpose of
hedging the cash flow variability associated with forecasted purchases and sales
of various energy-forecasted commodities. All such derivative instruments are
accounted for pursuant to the requirements of SFAS 133 "Accounting for
Derivative Instruments and Hedging Activities", as amended by SFAS 138,
"Accounting for Certain Derivative Instruments and Hedging Activities"
(collectively, "SFAS 133"). With respect to those commodity derivative
instruments that are designated and accounted for as cash flow hedges, the
effective portion of periodic changes in the fair market value of cash flow
hedges is recorded as Other Comprehensive Income on the Consolidated Balance
Sheet, while the ineffective portion of such changes in fair value is recognized
in earnings. Gains and losses (on such cash flow hedges) that are recorded as
Other Comprehensive Income are subsequently reclassified into earnings
concurrent with when hedged transactions impact earnings. With respect to those
commodity derivative instruments that are not designated as hedging instruments,
such derivatives are accounted for on the Consolidated Balance Sheet at fair
value, with all changes in fair value reported in earnings.
Firm Gas Sales Derivatives Instruments - Regulated Utilities: We utilize
derivative financial instruments to reduce cash flow variability associated with
the purchase price for a portion of our future natural gas purchases. Our
strategy is to minimize fluctuations in firm gas sales prices to our regulated
firm gas sales customers in our New York and New Hampshire service territories.
Since these derivative instruments are 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
consistent with regulatory requirements.
Physically-Settled Commodity Derivative Instruments: Upon our implementation of
Derivative Implementation Group ("DIG") Issue C16 on April 1, 2002, certain of
our contracts for the physical purchase of natural gas were assessed as no
longer being exempt from the requirements of SFAS 133 as normal purchases. As
such, these contracts are recorded on the Consolidated Balance Sheet at fair
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market value. However, since such contracts were executed for the purchases of
natural gas that is sold to regulated firm gas sales customers, and pursuant to
the requirements of SFAS 71, changes in the fair market value of these contracts
are recorded as a Regulatory Asset or Regulatory Liability on the Consolidated
Balance Sheet.
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 derivative instruments from time to time. Based on the terms of
the contracts, we account for these instruments pursuant to the requirements of
EITF 99-2 "Accounting for Weather Derivatives." In this regard, we account for
weather derivatives using the "intrinsic value method" as set forth in such
guidance.
Interest Rate Derivative Instruments: We continually assess the cost
relationship between fixed and variable rate debt. Consistent 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 designated and accounted for as
fair-value hedges pursuant to the requirements of SFAS 133. 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. None of these
investments are publicly traded.
J. Income and Excise 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 generally
amortized as a reduction of income tax over the estimated lives of the related
property.
We report our collections and payments of excise taxes on a gross basis. Gas
distribution revenues include the collection of excise taxes, while operating
taxes include the related expense. For the years ended December 31, 2002, 2001
and 2000, excise taxes collected and paid were $98.2 million, $119.1 million and
$117.8 million, respectively.
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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, 2002, the foreign currency
translation adjustment was included in Other Comprehensive Income on the
Consolidated Balance Sheet. 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.
At December 31, 2002 we have approximately 2.1 million options outstanding to
purchase KeySpan common stock 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 KeySpan's common stock. Further, we have
88,486 shares of convertible preferred stock outstanding that can be converted
into 228,406 shares of common stock. These shares were not included in the
calculation of diluted EPS for the years ending December 31, 2001 and 2000,
since to do so would have been anti-dilutive.
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Under the requirements of SFAS 128, "Earnings Per Share" our basic and diluted
EPS are as follows:
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Year Ended December 31,
(In Thousands of Dollars, Except Per Share Amounts) 2002 2001 2000
- --------------------------------------------------------------------------------------------------------------------------------
Earnings for common stock $ 371,935 $ 218,350 $ 282,694
Houston Exploration dilution (471) (1,116) (725)
Preferred stock dividend 531 - -
- --------------------------------------------------------------------------------------------------------------------------------
Earnings for common stock - adjusted $ 371,995 $ 217,234 $ 281,969
- --------------------------------------------------------------------------------------------------------------------------------
Weighted average shares outstanding (000) 141,263 138,214 134,357
Add dilutive securities:
Options 809 1,007 808
Convertible preferred stock 228 - -
- --------------------------------------------------------------------------------------------------------------------------------
Total weighted average shares outstanding - assuming dilution 142,300 139,221 135,165
- --------------------------------------------------------------------------------------------------------------------------------
Basic earnings per share $ 2.63 $ 1.58 $ 2.10
- --------------------------------------------------------------------------------------------------------------------------------
Diluted earnings per share $ 2.61 $ 1.56 $ 2.09
- --------------------------------------------------------------------------------------------------------------------------------
N. Stock Options
We issue stock options to all KeySpan officers and certain other management
employees as approved by the Board of Directors. These options generally vest
over a three-to-five year period and have a ten-year exercise period. Up to
approximately 19.3 million shares have been authorized for the issuance of
options and approximately 6.7 million of these shares were remaining at December
31, 2002. Moreover, under a separate plan, Houston Exploration has issued
approximately 2.4 million stock options to key Houston Exploration employees.
During 2002, we announced our intention to record stock options as a
compensation expense beginning with those options granted in 2003. KeySpan and
Houston Exploration have adopted the prospective method of transition in
accordance with SFAS 148 "Accounting for Stock-Based Compensation - Transition
and Disclosure". Accordingly, compensation expense will be recognized by
employing the fair value recognition provisions of SFAS 123 "Accounting for
Stock-Based Compensation" for grants awarded after January 1, 2003.
KeySpan and Houston Exploration will continue to apply APB Opinion 25,
"Accounting for Stock Issued to Employees," and related Interpretations in
accounting for grants awarded prior to January 1, 2003. Accordingly, no
compensation cost has been recognized for these fixed stock option plans in the
Consolidated Financial Statements since the exercise prices and market values
were equal on the grant dates. Had compensation cost for these plans been
determined based on the fair value at the grant dates for awards under the plans
consistent with SFAS 123, our net income and earnings per share would have
decreased to the pro-forma amounts indicated below:
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- -----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars, Except Per Share Amounts) 2002 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
Earnings available for common stock:
As reported $ 371,935 $ 218,350 $ 282,694
Add: recorded stock-based compensation expense, net of tax 221 261 195
Deduct: total stock-based compensation expense, net of tax (7,547) (8,459) (6,835)
- -----------------------------------------------------------------------------------------------------------------------------------
Pro-forma earnings $ 364,609 $ 210,152 $ 276,054
- -----------------------------------------------------------------------------------------------------------------------------------
Earnings per share:
Basic - as reported $ 2.63 $ 1.58 $ 2.10
Basic - pro-forma $ 2.58 $ 1.52 $ 2.05
Diluted - as reported $ 2.61 $ 1.56 $ 2.09
Diluted - pro-forma $ 2.56 $ 1.50 $ 2.04
- -----------------------------------------------------------------------------------------------------------------------------------
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 December 31,
2002 2001 2000
- --------------------------------------------------------------------------------------------------------
Fair value of grants issued $ 3.42 $ 5.29 $ 2.87
Dividend yield 5.36% 4.91% 8.22%
Expected volatility 22.47% 29.04% 24.00%
Risk free rate 4.94% 5.13% 6.54%
Expected lives 10 years 10 years 6 years
Exercise price $ 32.66 $ 39.50 $ 22.69
- --------------------------------------------------------------------------------------------------------
A summary of the status of our fixed stock option plans and changes is presented
below for the periods indicated:
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
2002 2001 2000
- ----------------------------------------------------------------------------------------------------------------------------------
Weighted Weighted Weighted
Exercise Exercise Exercise
Fixed Options Shares Price Shares Price Shares Price
- ----------------------------------------------------------------------------------------------------------------------------------
Outstanding at beginning of period 7,796,162 $ 29.67 6,456,627 $ 25.61 4,968,398 $ 28.81
Granted during the year 2,796,310 $ 32.66 2,285,350 $ 39.50 3,165,822 $ 22.69
Exercised (506,794) $ 24.42 (809,983) $ 25.15 (1,577,259) $ 27.82
Forfeited (560,778) $ 30.99 (135,832) $ 29.19 (100,334) $ 26.04
- ----------------------------------------------------------------------------------------------------------------------------------
Outstanding at end of period 9,524,900 $ 30.74 7,796,162 $ 29.67 6,456,627 $ 25.61
- ----------------------------------------------------------------------------------------------------------------------------------
Exercisable at end of period 4,105,999 $ 27.69 2,996,771 $ 24.86 2,759,599 $ 29.57
- ----------------------------------------------------------------------------------------------------------------------------------
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- ------------------------------------------------------------------------------------------------------------------------------------
Options Weighted Options Weighted
Remaining Outstanding Average Exercisable at Average
Contractual December 31, Exercise Range of Exercise December 31, Exercise Range of Exercise
Life 2002 Price price 2002 Price price
- ------------------------------------------------------------------------------------------------------------------------------------
2 years 2,644 $ 13.76 $13.76 2,644 $ 13.76 $13.76
3 years 30,138 $ 25.98 $14.86 - 27.00 30,138 $ 25.98 $14.86 - 27.00
4 years 226,086 $ 30.43 $20.57 - 32.63 226,086 $ 30.43 $20.57 - 32.63
5 years 304,410 $ 32.56 $19.15 - 32.63 304,410 $ 32.56 $19.15 - 32.63
6 years 1,457,104 $ 27.78 $24.73 - 29.38 1,457,104 $ 27.78 $24.73 - 29.38
7 years 717,314 $ 26.82 $21.99 - 27.06 717,314 $ 26.82 $21.99 - 27.06
8 years 2,048,335 $ 22.71 $22.50 - 32.76 1,019,117 $ 22.71 $22.50 - 32.76
9 years 2,068,928 $ 39.50 $39.50 349,186 $ 39.50 $39.50
10 years 2,669,941 $ 32.66 $32.66 - $ 32.66 $32.66
- ------------------------------------------------------------------------------------------------------------------------------------
9,524,900 4,105,999
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In early March 2003, KeySpan's Board of Directors approved a modification to the
Long-Term Incentive Compensation Plan and its application to officers of
KeySpan. During 2003, long-term incentive compensation for officers will consist
of 50% stock options and 50% performance shares. Performance shares will be
awarded based upon the attainment of overall corporate performance goals and
will better align incentive compensation with overall corporate performance.
During 2002, and in prior years, the majority of long-term incentive
compensation awards were stock option grants with a limited amount of restricted
stock award grants.
O. Recent Accounting Pronouncements
On January 1, 2002, we adopted SFAS 141, "Business Combinations", and SFAS 142
"Goodwill and Other Intangible Assets". The key concepts from the two
interrelated Statements include mandatory use of the purchase method when
accounting for business combinations, discontinuance of goodwill amortization, a
revised framework for testing goodwill impairment at a "reporting unit" level
and new criteria for the identification and potential amortization of other
intangible assets. Other changes to existing accounting standards involve the
amount of goodwill to be used in determining the gain or loss on the disposal of
assets and a requirement to test goodwill for impairment at least annually. See
Item G "Goodwill" for a discussion of goodwill impairment testing.
In July 2001, the Financial Accounting Standards Board ("FASB") issued SFAS 143,
"Accounting for Asset Retirement Obligations." SFAS 143 requires an entity to
record a liability and corresponding asset representing the present value of
legal obligations associated with the retirement of tangible, long-lived assets.
SFAS 143 was effective for fiscal years beginning after June 2002.
KeySpan has completed its assessment of SFAS 143. At December 31, 2002, we
estimate that the present value of our future Asset Retirement Obligation
("ARO") is approximately $57 million, primarily related to our investment in
Houston Exploration. We estimate that the cumulative effect of SFAS 143 and the
change in accounting principle will be a benefit to net income of $49.5 million,
or $32.2 million, after-tax. KeySpan's largest asset base is its gas
98
transmission and distribution system. A legal obligation may be construed to
exist due to certain safety requirements at final abandonment. In addition, a
legal obligation may be construed to exist with respect to KeySpan's liquefied
natural gas ("LNG") storage tanks due to clean up responsibilities upon
cessation of use. However, mass assets such as storage, transmission and
distribution assets are believed to operate in perpetuity and, therefore, have
indeterminate cash flow estimates. Since that exposure is in perpetuity and
cannot be measured, no liability will be recorded. KeySpan's ARO will be
re-evaluated in future periods until sufficient information exists to determine
a reasonable estimate of fair value.
SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", was
effective January 1, 2002, and addresses accounting and reporting for the
impairment or disposal of long-lived assets. SFAS 144 supersedes SFAS 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. For 2002, implementation of this Statement did not have a
significant effect on our results of operations and financial position.
In June of 2002, the FASB issued SFAS 146, "Accounting for Costs Associated with
Exit or Disposal Activities". This Statement addresses financial accounting and
reporting for costs associated with exit or disposal activities and nullifies
EITF 94-3, "Liability Recognition for Certain Employee Termination Benefits and
Other Costs to Exit an Activity". This Statement is effective for exit or
disposal activities initiated after December 31, 2002, with early application
encouraged.
In December of 2002, the FASB issued SFAS 148, "Accounting for Stock-Based
Compensation-Transition and Disclosure", which amends SFAS 123, "Accounting for
Stock-Based Compensation". This Statement provides alternative methods of
transition for a voluntary change to the fair value based method of accounting
for stock-based employee compensation. In addition, SFAS 148 amends the
disclosure requirements of SFAS 123 to require more prominent and more frequent
disclosures in financial statements about the effects of stock-based
compensation. See Item N "Stock Options" for these disclosures. The transition
guidance and annual disclosure provisions of SFAS 148 are effective for fiscal
years ending after December 15, 2002, with earlier application permitted in
certain circumstances. The interim disclosure provisions are effective for
financial reports containing financial statements for interim periods beginning
after December 15, 2002.
99
The recognition provisions of this Statement allow for three alternative methods
of recognizing stock-based employee compensation expense. KeySpan has elected to
follow the prospective method of recognizing an expense for all employee awards
granted or modified after January 1, 2003. The expense associated with
implementation of this method is not expected to be material in 2003.
In November 2002, the FASB issued FASB Interpretation No. 45 ("FIN 45"),
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others." FIN 45 requires the guarantor to
recognize a liability for the non-contingent component of a guarantee; that is,
the obligation to stand ready to perform in the event that specified triggering
events or conditions occur. The initial measurement of this liability is the
fair value of the guarantee at inception. The recognition of the liability is
required even if it is not probable that payments will be required under the
guarantee or if the guarantee was issued with a premium payment or as part of a
transaction with multiple elements. FIN 45 also requires additional disclosures
related to guarantees (See Note 7 "Contractual Obligations, Financial Guarantees
and Contingencies" for a description of KeySpan's outstanding guarantees). The
disclosure requirements are effective for interim and annual financial
statements for periods ending after December 15, 2002. The recognition and
measurement provisions of FIN 45 are effective for all guarantees entered into
or modified after December 31, 2002. We currently do not anticipate that
implementation of this Statement will have a significant effect on our results
of operations and financial condition.
In January 2003, the FASB issued FASB Interpretation No. 46 ("FIN 46"),
"Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51."
FIN 46 requires certain variable interest entities to be consolidated by the
primary beneficiary of the entity if the equity investors in the entity do not
have the characteristics of a controlling financial interest or do not have
sufficient equity at risk for the entity to finance its activities without
additional subordinated financial support from other parties. FIN 46 is
effective for all new variable interest entities created or acquired after
January 31, 2003. For variable interest entities created or acquired prior to
February 1, 2003, the provisions of FIN 46 must be applied for the first interim
or annual period beginning after June 15, 2003. We currently have an arrangement
with a variable interest entity through which we lease a portion of the
Ravenswood facility (See Note 7 "Contractual Obligations, Financial Guarantees
and Contingencies" for a description of the Ravenswood transaction).
100
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.
KEDNY provides gas distribution services to customers in the New York City
boroughs of Brooklyn, Staten Island and a portion of the borough of Queens.
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, collectively doing business as KEDNE,
provide gas distribution service to customers in Massachusetts and New
Hampshire.
The Electric Services segment consists of subsidiaries that: operate the
electric transmission and distribution system owned by LIPA; own and provide
capacity to and produce energy for LIPA from our generating facilities located
on Long Island; and manage fuel supplies for LIPA to fuel our Long Island
generating facilities. These services are provided in accordance with long-term
service contracts having remaining terms that range from four to twelve years.
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. All of the energy, capacity and ancillary services related to
the Ravenswood facility is sold to the NYISO energy markets. Further, two 79.9
megawatt generating facilities located on Long Island were placed into service
in June and July 2002. The capacity of and energy from these facilities are
dedicated to LIPA under 25 year contracts.
The Energy Services segment includes companies that provide energy-related
services to customers primarily located within the New York City metropolitan
area including New Jersey and Connecticut, as well as Rhode Island,
Pennsylvania, Massachusetts and New Hampshire, through the following three lines
of business: (i) Home Energy Services, which provides residential customers with
service and maintenance of energy systems and appliances, as well as the retail
marketing of natural gas and electricity to residential and small commercial
customers; (ii) Business Solutions, which provides plumbing, heating,
ventilation, air conditioning and mechanical contracting services, as well as
operation and maintenance, design, engineering and consulting services to
commercial, institutional and industrial customers; and (iii) Fiber Optic
Services, which provides various services to carriers of voice and data
transmission on Long Island and in New York City.
The Energy Investments segment consists of our gas exploration and production
investments, as well as certain other domestic and international energy-related
investments. Our gas exploration and production subsidiaries are engaged in gas
and oil exploration and production, and the development and acquisition of
domestic natural gas and oil properties. These investments consist of our
ownership 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. As
previously mentioned, on February 26, 2003, we reduced our ownership interest in
Houston Exploration from 66% to approximately 56% following the repurchase, by
Houston Exploration, of 3 million shares of stock owned by KeySpan. We realized
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$79 million in connection with this repurchase. Additionally, there is an
over-allotment option for 300,000 shares, which if exercised, would further
reduce our ownership in Houston Exploration to 55%. 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 an earnings before interest and taxes ("EBIT") basis. To reflect a
complete picture of the electric operations, we reclassified, for all periods
presented, KeySpan Energy Supply from the Energy Services segment to the
Electric Services segment. This subsidiary provides commodity management and
procurement services for fuel supply and management of energy sales, primarily
for and from the Ravenswood facility. Due to the July 2002 sale of Midland
Enterprises LLC, an inland marine barge business, this subsidiary is reported as
discontinued operations for all periods presented. (See Note 9 "Discontinued
Operations" for more information on the sale of Midland).
The reportable segment information below is shown excluding the operations of
Midland:
- ------------------------------------------------------------------------------------------------------------------------------------
Gas
Exploration
Gas Electric Energy and Other
(In Thousands of Dollars) Distribution Services Services Production Investments Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2002
Unaffiliated revenue 3,163,761 1,421,043 938,761 357,451 89,650 - 5,970,666
Intersegment revenue - 100 - - 1,128 (1,228) -
Depreciation, depletion and
amortization 237,186 61,377 9,522 176,925 14,573 15,030 514,613
Income from equity investments - - - - 13,992 104 14,096
Interest income 2,020 1,834 1,248 - 238 (3,768) 1,572
Earnings before interest and
income taxes 524,311 309,663 (10,377) 95,494 32,771 (27,614) 924,248
Interest charges 215,140 57,589 19,386 7,303 6,858 (4,772) 301,504
Total assets 7,452,583 1,739,928 497,269 1,187,425 974,409 762,692 12,614,306
Equity method investments - - - - 130,815 - 130,815
Construction expenditures 407,679 371,885 14,316 275,524 48,962 15,511 1,133,877
- ------------------------------------------------------------------------------------------------------------------------------------
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, 2002, represents approximately 24% of our consolidated
revenues during that period.
102
- ------------------------------------------------------------------------------------------------------------------------------------
Gas
Exploration
Gas Electric Energy and Other
(In Thousands of Dollars) Distribution Services Services 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 - 100 - - - (100) -
Depreciation, depletion and
amortization 253,523 52,284 33,636 184,717 15,737 19,241 559,138
Income from equity investments - - - - 13,129 - 13,129
Interest income 3,879 433 3,185 - 334 495 8,326
Earnings before interest and
income taxes 492,362 283,533 (143,492) 119,933 21,544 33,975 807,855
Interest charges 219,307 46,842 21,106 2,993 9,772 53,450 353,470
Total assets 6,994,140 1,677,710 550,891 951,135 797,294 818,436 11,789,606
Equity method investments - - - - 107,069 - 107,069
Construction expenditures 384,323 211,816 17,134 385,463 52,513 8,510 1,059,759
- ------------------------------------------------------------------------------------------------------------------------------------
Eliminating items include intercompany interest income and expense and 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.
- ------------------------------------------------------------------------------------------------------------------------------------
Gas
Exploration
Gas Electric Energy and Other
(In Thousands of Dollars) Distribution Services Services 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 - 1,175 - - - (1,175) -
Depreciation, depletion and
amortization 143,335 49,278 10,347 95,364 6,586 26,012 330,922
Income from equity investments - - - - 20,010 - 20,010
Interest income 3,951 2,180 - - 6,134 62 12,327
Earnings before interest and
income taxes 367,226 310,823 14,630 111,672 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 1,871,323 755,506 830,170 683,399 (119,071) 11,307,465
Equity method investments - - - - 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 and 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.
103
Note 3. Income Tax
We file a consolidated federal income tax return. 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. The subsidiaries record income tax payable or receivable
from KeySpan resulting from the inclusion of their taxable income or loss in the
consolidated return.
Income tax expense is reflected as follows in the Consolidated Statement of
Income:
- ---------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2002 2001 2000
- ---------------------------------------------------------------------------------------------------
Current income tax $(48,487) $101,738 $170,809
Deferred income tax 273,881 108,955 46,453
- ---------------------------------------------------------------------------------------------------
Total income tax $225,394 $210,693 $217,262
- ---------------------------------------------------------------------------------------------------
The components of deferred tax assets and (liabilities) reflected in the
Consolidated Balance Sheet are as follows:
- -------------------------------------------------------------------------------------------------
December 31,
(In Thousands of Dollars) 2002 2001
- -------------------------------------------------------------------------------------------------
Reserves not currently deductible $ 38,275 $ 55,372
Benefits of tax loss carry forwards (13,997) 6,346
Property related differences (818,116) (498,726)
Regulatory tax asset (18,690) (22,588)
Property taxes (52,339) (61,126)
Discontinued operations - (74,936)
Other items - net (12,146) (2,414)
- -------------------------------------------------------------------------------------------------
Net deferred tax liability $ (877,013) $ (598,072)
- -------------------------------------------------------------------------------------------------
During the year ended December 31, 2002, an adjustment to deferred income taxes
of $177.7 million was recorded to reflect a decrease in the tax basis of the
assets acquired at the time of the KeySpan/LILCO combination. This adjustment
resulted from a revised valuation study and the preparation of amended tax
returns. Concurrent with this deferred tax adjustment, KeySpan reduced current
income taxes payable by $183.2 million, resulting in a net $5.5 million income
tax benefit. Currently, the Internal Revenue Service is auditing KeySpan's tax
returns pertaining to the KeySpan/LILCO combination, as well as other return
years. At this time, we cannot predict the outcome of the ongoing audit.
104
The following is a reconciliation between the effective tax rate and the federal
income tax rate of 35%:
- --------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2002 2001 2000
- --------------------------------------------------------------------------------------------------------------------------------
Computed at the statutory rate $ 217,960 $ 159,035 $ 182,004
Adjustments related to:
Tax credits (1,026) (1,100) (1,181)
Removal costs (4,787) (1,470) (2,788)
Accrual to return adjustment (9,539) 2,354 (508)
Goodwill amortization - 21,126 4,123
Minority interest in Houston Exploration 9,490 13,862 8,768
State income tax 30,370 26,418 30,384
Other items - net (17,074) (9,532) (3,540)
- --------------------------------------------------------------------------------------------------------------------------------
Total income tax $ 225,394 $ 210,693 $ 217,262
- --------------------------------------------------------------------------------------------------------------------------------
Effective income tax (1) 36% 46% 42%
- --------------------------------------------------------------------------------------------------------------------------------
(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.
KEDLI is subject to certain deferral accounting requirements mandated by the
NYPSC for pension costs and other postretirement benefit costs.
Boston Gas Company is also subject to deferral accounting requirements, as
previously ordered by the DTE, for other postretirement benefit costs. In
addition, by DTE approval dated January 28, 2003, Boston Gas Company will defer
for the year 2003, and record as either a regulatory asset or regulatory
liability, the difference between the level of pension expense that is included
in rates charged to gas customers and the actuarial determined amounts.
Information pertaining to discontinued operations has been excluded from this
presentation.
The calculation of net periodic pension cost is as follows:
- ----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2002 2001 2000
- ----------------------------------------------------------------------------------------------------------------------------------
Service cost, benefits earned during the period $ 42,423 $ 41,162 $ 35,541
Interest cost on projected benefit obligation 132,424 128,481 109,231
Expected return on plan assets (157,958) (180,757) (166,744)
Special termination charge (1) - - 45,838
Settlement Gain (2) - - (20,196)
Net amortization and deferral (4,247) (39,772) (54,881)
- ----------------------------------------------------------------------------------------------------------------------------------
Total pension (benefit) cost $ 12,642 $ (50,886) $ (51,211)
- ----------------------------------------------------------------------------------------------------------------------------------
(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 since November 8, 2000.
105
The following table sets forth the pension plans' funded status at December 31,
2002 and December 31, 2001. Plan assets are principally common stock and fixed
income securities.
- ----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2002 2001
- ----------------------------------------------------------------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation at beginning of period $ (1,915,154) $ (1,914,885)
Service cost (42,423) (41,162)
Interest cost (132,424) (128,481)
Amendments (2,932) (8,679)
Actuarial gain (loss) (103,988) 61,718
Benefits paid 116,728 116,335
- ----------------------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period (2,080,193) (1,915,154)
- ----------------------------------------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of period 1,899,256 2,170,093
Actual return on plan assets (347,270) (197,632)
Employer contribution 109,260 43,130
Benefits paid (116,728) (116,335)
- ----------------------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period 1,544,518 1,899,256
- ----------------------------------------------------------------------------------------------------------------------------------
Funded status (535,675) (15,898)
Unrecognized net loss from past experience different
from that assumed and from changes in assumptions 627,199 8,207
Unrecognized prior service cost 71,126 84,036
Unrecognized transition obligation 237 1,212
- ----------------------------------------------------------------------------------------------------------------------------------
Net prepaid pension cost reflected on
consolidated balance sheet $ 162,887 $ 77,557
- ----------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
2002 2001 2000
- ------------------------------------------------------------------------------------------------------------------------------
Assumptions:
Obligation discount 6.75% 7.00% 7.00%
Asset return 8.50% 8.50% 8.50%
Average annual increase in compensation 4.00% 4.00% 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. At
December 31, 2002, the accumulated benefit obligations were re-measured which
106
resulted in a revised minimum liability of $286.3 million. As permitted 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 in Other Comprehensive
Income.
Therefore, at year-end, we have recorded a long-term asset in Deferred Charges
Other of $61.5 million. We also recorded a $118.6 million contractual receivable
in Deferred Charges Other, representing the amount that would be recovered from
LIPA in accordance with our service agreements if the underlying assumptions
giving rise to this minimum liability were realized and recorded as pension
expense. The remaining charge to equity of $106.2 million, or $69.0 million
after-tax, has been recorded as a debit to Other Comprehensive Income. At
December 31, 2002 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, $948.0 million and $621.0 million,
respectively. At the end of each year, 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.
Net periodic other postretirement benefit cost included the following
components:
- ----------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2002 2001 2000
- ----------------------------------------------------------------------------------------------------
Service cost, benefits earned during the period $16,566 $20,339 $14,771
Interest cost on accumulated
postretirement benefit obligation 65,486 64,649 47,412
Expected return on plan assets (36,839) (42,822) (42,890)
Special termination charge (1) - - 5,590
Net amortization and deferral 17,527 11,664 (9,290)
- ----------------------------------------------------------------------------------------------------
Other postretirement benefit cost $62,740 $53,830 $15,593
- ----------------------------------------------------------------------------------------------------
(1) See discussion of early retirement program at end of note.
Other postretirement benefit costs include expense and income for KEDNE since
November 8, 2000.
107
The following table sets forth the plans' funded status at December 31, 2002 and
December 31, 2001. Plan assets are principally common stock and fixed income
securities.
- ------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2002 2001
- ------------------------------------------------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation at beginning of period $ (969,692) $ (873,421)
Service cost (16,566) (20,339)
Interest cost (65,486) (64,649)
Plan participants' contributions (1,587) (1,439)
Amendments 57,984 52
Actuarial (loss) (115,563) (57,670)
Benefits paid 53,966 47,774
- ------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period (1,056,944) (969,692)
- ------------------------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of period 476,146 554,866
Actual return on plan assets (82,950) (39,703)
Employer contribution 20,349 7,318
Plan participants' contributions 1,587 1,439
Benefits paid (53,966) (47,774)
- ------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period 361,166 476,146
- ------------------------------------------------------------------------------------------------------------------
Funded status (695,778) (493,546)
Unrecognized net loss from past experience different from
that assumed and from change in assumptions 464,269 251,198
Unrecognized prior service cost (60,104) (8,392)
- ------------------------------------------------------------------------------------------------------------------
Accrued benefit cost reflected on consolidated balance sheet $ (291,613) $ (250,740)
- ------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------
Year Ended December 31,
2002 2001 2000
- -------------------------------------------------------------------------------------------------------
Assumptions:
Obligation discount 6.75% 7.00% 7.00%
Asset return 8.50% 8.50% 8.50%
Average annual increase in compensation 4.00% 4.00% 5.00%
- -------------------------------------------------------------------------------------------------------
The measurement of plan liabilities also assumes a health care cost trend rate
of 9% 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, 2002 by $118.4 million and
the net periodic health care expense by $11.0 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, 2002 by $104.6 million and
the net periodic health care expense by $9.4 million.
108
At December 31, 2002, KeySpan had a contractual receivable from LIPA of $238
million representing the postretirement benefits associated with the electric
business unit employees recorded in Deferred Charges Other in the Consolidated
Balance Sheet. LIPA has been reimbursing us for costs related to the
postretirement benefits of the electric business unit employees in accordance
with the LIPA Agreements.
Early Retirement Program: In December 2000, we completed an early retirement
program for certain management and union employees. 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.
Defined Contribution Plan: KeySpan also offers both its union and management
employees a defined contribution plan. Both the KeySpan Energy 401(k) Plan for
Management Employees and the KeySpan Energy 401(k) Plan for Union Employees are
available to all eligible employees. These Plans are defined contribution plans
subject to Title I of the Employee Retirement Income Security Act of 1974
("ERISA"). All eligible employees contributing to the Plan receive a certain
employer matching contribution based on a percentage of the employee
contribution, as well as a 10% discount on the KeySpan Common Stock Fund
anywhere from three to twelve months after their date of hire depending upon the
Plan. The matching contributions are in KeySpan's common stock. The match and
discount amounts may be transferred out of common stock immediately. For the
years ended December 31, 2002, 2001 and 2000, we recorded an expense equal to
$11.2 million, $11.0 million and $6.7 million respectively.
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, 2002, we had 16.4 million
shares, or approximately $475 million of Treasury Stock outstanding. We
completed this repurchase plan in 1999 and now utilize Treasury Stock to satisfy
our common stock plans. During 2002, we issued 3 million shares out of treasury
for the dividend reinvestment feature of our Investor Program, the Employee
Stock Discount Purchase Plan and the 401(k) Plan.
On January 17, 2003, KeySpan sold 13.9 million shares of common stock in a
public offering that generated net proceeds of approximately $473 million. All
shares were offered by KeySpan pursuant to the effective shelf registration
statement filed with the SEC. Net proceeds from the equity sale were used
initially to pay down commercial paper.
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.
109
At December 31, 2002 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 88,486 shares outstanding of 6% Preferred Stock
Series A par value $100, in the aggregate totaling $83.8 million.
Boston Gas Company has 562,700 shares of 6.421% non-voting preferred stock par
value $25 per share outstanding at December 31, 2002. This issue of preferred
stock has a 5% annual sinking fund requirement and $1.5 million was paid on
September 1, 2002 to satisfy this 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. 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,
2002, 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 1.00% to 1.68% through December 31, 2002, at which time the rate
was 1.28%.
Authority Financing Notes: One of our electric generation subsidiaries can issue
tax-exempt bonds through the New York State Energy Research and Development
Authority. At December 31, 2002, $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 1.00% to 1.68%, through December 31,
2002, at which time the rate was 1.20%.
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 .95% to 1.90% through December 31, 2002 at which
time the rate was 1.60%.
Promissory Notes: In connection with the KeySpan/LILCO transaction, KeySpan and
certain of its subsidiaries issued promissory notes to LIPA to support certain
debt obligations assumed by LIPA. The remaining principal amount of promissory
notes issued to LIPA was approximately $600 million at December 31, 2002. In
February 2003, KeySpan notified LIPA of its intention to redeem approximately
$447 million aggregate principal amount of such promissory notes at the
applicable redemption prices plus accrued and unpaid interest through the dates
of redemption. It is anticipated that such redemption will take place before the
end of the first quarter of 2003. Under these promissory notes, KeySpan is
required to obtain letters of credit to secure its payment obligations if its
long-term debt is not rated at least in the "A" range by at least two nationally
recognized statistical rating agencies.
110
Notes Payable: KEDLI had $125 million of Medium-Term Notes at 6.90% due January
15, 2008, and $400 million of 7.875% Medium-Term Notes due February 1, 2010,
outstanding at December 31, 2002 each of which is guaranteed by KeySpan.
Further, KeySpan had $2.36 billion of Medium-Term Notes outstanding at December
31, 2002 of which $1.65 billion of these notes are associated with the
acquisition of Eastern and ENI. These 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. The remaining Medium-Term Notes of $710
million have interest rates ranging from 6.15% to 9.75% and mature in 2005-2025.
In May 2002, we issued $460 million of MEDS Equity Units at 8.75% consisting of
a three-year forward purchase contract for our common stock and a six-year note.
The purchase contract commits us, three years from the date of issuance of the
MEDS Equity Units, to issue and the investors to purchase, a number of shares of
our common stock based on a formula tied to the market price of our common stock
at that time. The 8.75% coupon is composed of interest payments on the six-year
note of 4.9% and premium payments on the three-year equity forward contract of
3.85%. These instruments have been recorded as long-term debt on the
Consolidated Balance Sheet. Further, upon issuance of the MEDS Equity Units, we
recorded a direct charge to Retained Earnings of $49.1 million, which represents
the present value of the forward contract's premium payments.
These securities are currently not considered convertible instruments for
purposes of applying SFAS 128 "Earnings Per Share" calculations, unless or until
such time as the market value of our common stock reaches a threshold
appreciation price ($42.36 per share) that is higher than the current per share
market value. Interest payments do, however, reduce net income and earnings per
share.
The Emerging Issues Task Force of the FASB is considering proposals related to
accounting for certain securities and financial instruments, including
securities such as the Equity Units. The current proposals being considered
include the method of accounting discussed above. Alternatively, other proposals
being considered could result in the common shares issuable pursuant to the
purchase contract to be deemed outstanding and included in the calculation of
diluted earnings per share, and could result in periodic "mark to market" of the
purchase contracts, causing periodic charges or credits to income. If this
latter approach were adopted, our basic and diluted earnings per share could
increase and decrease from quarter to quarter to reflect the lesser and greater
number of shares issuable upon satisfaction of the contract, as well as charges
or credits to income.
At December 31, 2001, KeySpan had authorization under PUHCA to issue up to $1
billion of securities and had an effective $1 billion shelf registration
statement on file with the SEC, with $500 million available for issuance. In
February 2002, we updated the shelf registration for the issuance of an
additional $1.2 billion of securities, thereby giving KeySpan the ability to
111
issue up to $1.7 billion of debt, equity or various forms of preferred stock.
The issuance of the MEDS Equity Units utilized $920 million of KeySpan's
financing authority under both the shelf registration and the PUHCA financing
authority. Both the $460 million six-year note and the $460 million forward
equity contract are considered current issuances under these arrangements. On
December 6, 2002, the SEC issued an order increasing the available authorization
amount of financing under PUHCA to an aggregate of $780 million. Following the
recent common stock offering mentioned in Note 5 "Capital Stock" and shares
expected to be issued for employee benefit and dividend reinvestment plans, we
have approximately $40 million available for the issuance of new securities
under our current PUHCA authorization. However, the issuance of securities in
connection with the redemption of existing securities (including the promissory
notes discussed previously) is permitted under our PUHCA authorization
notwithstanding the foregoing limit. We intend to seek authorization to issue
additional securities in the near term.
At December 31, 2002, 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: Colonial Gas Company, Essex Gas Company, ENI and their
respective subsidiaries, have issued and outstanding approximately $163.6
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.
In May 2002, Colonial Gas Company repaid $15 million of its 6.81% Series A First
Mortgage Medium-Term Notes. These Notes would have matured on May 19, 2027, but
the holder of the Notes elected to exercise a put option to redeem the Notes
early.
Commercial Paper and Revolving Credit Agreements: In 2002, KeySpan renewed its
existing 364-day revolving credit agreement with a commercial bank syndicate of
16 banks totaling $1.3 billion, a reduction from the previous $1.4 billion
facility. The credit facility is used to back up the $1.3 billion commercial
paper program. The fees for the facility are subject to a ratings-based grid,
with an annual fee of .075% on the total amount of the revolving facility. The
credit agreement allows for KeySpan to borrow using several different types of
loans; specifically, Eurodollar loans, Adjustable Bank Rate ("ABR") loans, or
competitively bid loans. Eurodollar loans are based on the Eurodollar rate plus
a margin of 42.5 basis points for loans up to 33% of the facility, and an
additional 12.5 basis points for loans over 33% of the total facility. ABR loans
are based on the greater of the Prime Rate, the base CD rate plus 1%, or the
Federal Funds Effective Rate plus 0.5%. Competitive bid loans are based on bid
results requested by KeySpan from the lenders. We do not anticipate borrowing
against this facility; however, if the credit rating on our commercial paper
program were to be downgraded, it may be necessary to borrow on the credit
facility.
112
The credit facility contains certain affirmative and negative operating
covenants, including restrictions on KeySpan's ability to mortgage, pledge,
encumber or otherwise subject its property to any lien and certain financial
covenants that require us to, among other things, maintain a consolidated
indebtedness to consolidated capitalization ratio of no more than 66%, a
decrease from the 68% ratio required under the previous credit facility.
Under the terms of the credit facility, the calculation of KeySpan's
debt-to-total capitalization ratio reflects 80% equity treatment for the MEDS
Equity Units issued in May 2002. Further the $425 million Ravenswood master
lease ("Master Lease") is treated as debt. (See Note 7 "Contractual Obligations,
Financial Guarantees and Contingencies" for a discussion of the Ravenswood
Master Lease.) At December 31, 2002, consolidated indebtedness, as calculated
under the terms of the credit facility, was 64.6% of consolidated
capitalization. As a result of the common stock offering previously mentioned,
this ratio has been reduced to 59.8%. Violation of this covenant could result in
the termination of the credit facility and the required repayment of amounts
borrowed thereunder, as well as possible cross defaults under other debt
agreements.
The credit facility also requires that net cash proceeds from the sale of
subsidiaries be applied to reduce consolidated indebtedness. Further, an
acceleration of indebtedness of KeySpan or one of its subsidiaries for borrowed
money in excess of $25 million in the aggregate, if not annulled within 30 days
after written notice, would create an event of default under the Indenture,
dated as of November 1, 2000, between KeySpan Corporation and the Chase
Manhattan Bank, as Trustee. At December 31, 2002, KeySpan was in compliance with
all covenants.
At December 31, 2002, we had cash and temporary cash investments of $170.6
million. During, 2002, we repaid $132.8 million of commercial paper and, at
December 31, 2002, $915.7 million of commercial paper was outstanding at a
weighted average annualized interest rate of 1.52%. We had the ability to borrow
up to an additional $384.3 million at December 31, 2002 under the commercial
paper program.
During 2002, Houston Exploration entered into a new revolving credit facility
with a commercial banking syndicate that replaced the existing $250 million
revolving credit facility. The new facility provides Houston Exploration with an
initial commitment of $300 million, which can be increased, at its option to a
maximum of $350 million with prior approval from the banking syndicate. The new
credit facility is subject to borrowing base limitations, initially set at $300
million and will be re-determined semi-annually. Up to $25 million of the
borrowing base is available for the issuance of letters of credit. The new
credit facility matures July 15, 2005, is unsecured and ranks senior to all
existing debt.
Under the Houston Exploration credit facility, interest on base rate loans is
payable at a fluctuating rate, or base rate, equal to the sum of (a) the greater
of the federal funds rate plus 0.50% or the bank's prime rate plus (b) a
variable margin between 0% and 0.50%, depending on the amount of borrowings
outstanding under the credit facility. Interest on fixed loans is payable at a
fixed rate equal to the sum of (a) a quoted reserve adjusted LIBOR rate plus (b)
a variable margin between 1.25% and 2.00%, depending on the amount of borrowings
outstanding under the credit facility.
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Financial covenants require Houston Exploration to, among other things, (i)
maintain an interest coverage ratio of at least 3.00 to 1.00 of earnings before
interest, taxes and depreciation ("EBITDA") to cash interest; (ii) maintain a
total debt to EBITDA ratio of not more than 3.50 to 1.00; and (iii) hedge no
more than 70% of natural gas production during any 12-month period. At December
31, 2002, Houston Exploration was in compliance with all financial covenants.
During 2002, Houston Exploration borrowed $79.0 million under its credit
facility and repaid $71.0 million. At December 31, 2002, $152 million of
borrowings remained outstanding at a weighted average annualized interest rate
of 3.42%. Also, $0.4 million was committed under outstanding letters of credit
obligations. At December 31, 2002, $147.6 million of borrowing capacity was
available.
KeySpan Canada has two revolving credit facilities with financial institutions
in Canada. Repayments under these agreements totaled approximately US $26.1
million during 2002. At December 31, 2002, approximately US $150.9 million was
outstanding at a weighted average annualized interest rate of 3.23%. KeySpan
Canada currently has available borrowings of approximately US $55.8 million.
These revolving credit agreements have been extended through January 2004. An
event of default would exist under these credit facilities if KeySpan, as
guarantor on the facilities, falls below investment grade rating or falls below
A3 or A- at a time when its consolidated indebtedness is greater than 66% of
consolidated capitalization or its cash flow to interest expense is less than
2.25 to 1.00. At December 31, 2002, KeySpan and KeySpan Canada were in
compliance with all covenants.
Capital Leases: Our subsidiaries lease certain facilities and equipment under
long-term leases, which expire on various dates through 2022. The weighted
average interest rate on these obligations was 6.25%.
Debt Maturity: The following table reflects the maturity schedule for our debt
repayment requirements, including capitalized leases and related maturities, at
December 31, 2002:
- ---------------------------------------------------------------------------
Long-Term Capital
(In Thousands of Dollars) Debt Leases Total
- ---------------------------------------------------------------------------
Repayments:
Year 1 $ 10,333 $ 1,080 $ 11,413
Year 2 333 1,033 1,366
Year 3 1,327,333 1,044 1,328,377
Year 4 512,333 1,003 513,336
Year 5 333 1,061 1,394
Thereafter 3,379,190 8,663 3,387,853
- ---------------------------------------------------------------------------
$ 5,229,855 $ 13,884 $ 5,243,739
- ---------------------------------------------------------------------------
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Note 7. Contractual Obligations, Financial Guarantees and Contingencies
Lease Obligations: Lease costs included in operation expense were $71.1 million
in 2002 reflecting, primarily, the Master Lease and the lease of our Brooklyn
headquarters of $29.1 million and $14.3 million, respectively. Lease costs also
include leases for other buildings, office equipment, vehicles and power
operated equipment. Lease costs for the year ended December 31, 2001 and 2000
were $75.8 million and $69.3 million, respectively. The future minimum lease
payments under various leases, all of which are operating leases, are $80.8
million per year over the next five years and $200.9 million, in the aggregate,
for all years thereafter, including future minimum lease payments for the Master
Lease of $30.8 million per year over the next five years and $61.7 million for
all years thereafter (See discussion below for further information regarding the
Master Lease.)
Variable Interest Entity: KeySpan has an arrangement with a variable interest
entity through which we lease a portion of the Ravenswood facility. We acquired
the Ravenswood facility, in part, through the variable interest entity from
Consolidated Edison on June 18, 1999 for approximately $597 million. In order to
reduce the initial cash requirements, we entered into the Master Lease with a
variable interest, unaffiliated financing entity that acquired a portion of the
facility, or three steam generating units, directly from Consolidated Edison and
leased it to our subsidiary. The variable interest unaffiliated financing entity
acquired the property for $425 million, financed with debt of $412.3 million
(97% of capitalization) and equity of $12.7 million (3% of capitalization).
KeySpan has no ownership interests in the units or the variable interest entity.
KeySpan has guaranteed all payment and performance obligations of our subsidiary
under the Master Lease. The Master Lease represents approximately $425 million
of the acquisition cost of the facility, which is the amount of debt that would
have been recorded on our Consolidated Balance Sheet had the variable interest
entity not been utilized and conventional debt financing been employed. Further,
we would have recorded an asset in the same amount. Monthly lease payments equal
the monthly interest expense on such debt securities. The Master Lease currently
qualifies as an operating lease for financial reporting purposes.
The initial term of the Master Lease expires on June 20, 2004 and may be
extended until June 20, 2009. In June 2004, we have the right to: (i) either
purchase the facility for the original acquisition cost of $425 million, plus
the present value of the lease payments that would otherwise have been paid
through June 2009; (ii) terminate the Master Lease and dispose of the facility;
or (iii) otherwise extend the Master Lease to 2009. If the Master Lease is
terminated in 2004, KeySpan has guaranteed an amount generally equal to 83% of
the residual value of the original cost of the property, plus the present value
of the lease payments that would have otherwise been paid through June 20, 2009.
In June 2009, when the Master Lease terminates, we may purchase the facility in
an amount equal to the original acquisition cost, subject to adjustment, or
surrender the facility to the lessor. If we elect not to purchase the property,
the Ravenswood facility will be sold by the lessor. We have guaranteed to the
lessor 84% of the residual value of the original cost of the property.
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In January 2003, the FASB issued FIN 46, "Consolidation of Variable Interest
Entities, an Interpretation of ARB No. 51." FIN 46 requires KeySpan, based upon
its current status as the primary beneficiary, to consolidate this variable
interest entity for the first interim period ending after June 15, 2003. It also
requires that assets, liabilities and non-controlling interests of the variable
interest entity be consolidated at fair value, except to the extent that to do
so would result in a gain to KeySpan. KeySpan believes that the fair market
value of the Ravenswood facility exceeds the fair market value of the lease
obligation.
Prospectively, KeySpan will have a $425 million asset that will be amortized
over the economic life of the leased property. However, upon implementation,
there will be a cumulative catch-up adjustment for a change in accounting policy
as if the asset had been owned from inception, or June 20, 1999. Therefore, at
July 1, 2003, assuming a 35 year economic life, KeySpan will be deemed to have
owned the asset for approximately 4 years and it is anticipated that we will
record a $31.6 million after-tax charge, or $0.20 per share, change in
accounting principle on the Consolidated Statement of Income. Upon
implementation of FIN 46, therefore, we anticipate recording an asset of
approximately $376 million and debt of $425 million.
Based upon expected average outstanding shares, we anticipate the incremental
impact of the additional depreciation expense for the remaining six months of
2003 to be approximately $0.02 per share. In addition, KeySpan is also
conducting a study to determine the fair value of the Ravenswood facility.
Although considered unlikely, to the extent the fair value of the Ravenswood
facility was less than the value of the lease obligation, then a loss would be
recognized upon consolidation.
If our subsidiary that leases the Ravenswood facility was not able to fulfill
its payment obligations with respect to the Master Lease payments, then the
maximum amount KeySpan would be exposed to under its current guarantees would be
$425 million plus the present value of the remaining lease payments through June
20, 2009.
KeySpan is currently exploring various options associated with the Master Lease,
including but not limited to, restructuring the current leasing arrangement. At
this time, we cannot predict the future structure of the leasing arrangement nor
the impact on our financial position, results of operations or cash flows.
Financial Guarantees: KeySpan has issued financial guarantees in the normal
course of business, primarily on behalf of its subsidiaries, to various third
party creditors. At December 31, 2002, the following amounts would have to be
paid by KeySpan in the event of non-payment by the primary obligor at the time
payment is due:
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- -----------------------------------------------------------------------------------------------------------
Amount of Expiration
Nature of Guarantee (In Thousands of Dollars) Exposure Dates
- -----------------------------------------------------------------------------------------------------------
Guarantees for Subsidiaries
Medium-Term Notes - KEDLI (i) $ 525,000 2008-2010
Master Lease - Ravenswood (ii) 425,000 2004
Revolving Credit Agreement - KeySpan Canada (iii) 130,000 2004
Surety Bonds (iv) 153,900 Revolving
Commodity Guarantees and Other (v) 65,700 2005
Letters of Credit (vi) 64,400 2003
- -----------------------------------------------------------------------------------------------------------
Guarantees for Non-Affiliates
Third Party Line of Credit (vii) 25,000 2004
- -----------------------------------------------------------------------------------------------------------
$ 1,389,000
- -----------------------------------------------------------------------------------------------------------
The following is a description of KeySpan's outstanding subsidiary guarantees:
(i) KeySpan has fully and unconditionally guaranteed $525 million to holders of
Medium-Term Notes issued by KEDLI. These notes are due to be repaid on
January 15, 2008 and February 1, 2010. KEDLI is required to comply with
certain financial covenants under the debt agreements. Currently, KEDLI is
in compliance with all covenants and management does not anticipate that
KEDLI will have any difficulty maintaining such compliance. The face value
of these notes are included in Long-Term Debt on the Consolidated Balance
Sheet.
(ii) KeySpan has guaranteed all payment and performance obligations of KeySpan
Ravenswood, LLC, the lessee under the $425 million Master Lease associated
with the lease of the Ravenswood facility. The initial term of the lease
expires on June 20, 2004 and may be extended until June 20, 2009. For
further information, see Variable Interest Entity above.
(iii)KeySpan has fully and unconditionally guaranteed a US $130 million
revolving credit agreement associated with KeySpan Canada. The term of the
agreement expires July 1, 2004.
(iv) KeySpan has purchased various surety and performance bonds associated with
certain construction projects currently being performed by subsidiaries
within the Energy Services segment. In the event that the operating
companies in the Energy Services segment fail to perform their obligation
under contract, the injured party may demand that the surety make payments
or provide services under the bond. KeySpan would then be obligated to
reimburse the surety for any expenses or cash outlays it incurs.
(v) KeySpan has guaranteed commodity-related payments for subsidiaries within
the Energy Services segment, as well as KeySpan Ravenswood, LLC. These
guarantees are provided to third parties to facilitate physical and
financial transactions involved in the purchase of natural gas, oil and
other petroleum products for electric production and marketing activities.
The guarantees cover actual purchases by these subsidiaries that are still
outstanding as of December 31, 2002.
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(vi) KeySpan has issued stand-by letters of credit in the amount of $64.4
million to third parties that have extended credit to certain subsidiaries.
Certain vendors require us to post letters of credit to guarantee
subsidiary performance under our contracts and to ensure payment to our
subsidiary subcontractors and vendors under those contracts. Certain of our
vendors also require letters of credit to ensure reimbursement for amounts
they are disbursing on behalf of our subsidiaries, such as to beneficiaries
under our self-funded insurance programs. Such letters of credit are
generally issued by a bank or similar financial institution. The letters of
credit commit the issuer to pay specified amounts to the holder of the
letter of credit if the holder demonstrates that we have failed to perform
specified actions. If this were to occur, KeySpan would be required to
reimburse the issuer of the letter of credit.
To date, KeySpan has not had a claim made against it for any of the above
guarantees and we have no reason to believe that our subsidiaries will default
on their current obligations. However, we cannot predict when or if any defaults
may take place or the impact such details may have on our consolidated results
of operations, financial condition or cash flows.
The following is a description of KeySpan's outstanding guarantees to
non-affiliates:
(vii)KeySpan has agreed to support a line of credit up to $25 million on behalf
of Hawkeye Construction ("Hawkeye"), a non-affiliated company. It also
assisted Hawkeye in obtaining performance bonds. The guarantees related to
their line of credit extend through 2004. To the extent Hawkeye does not
meet its obligations, KeySpan could be liable for the amount of the
outstanding guarantees. At December 31, 2002, the amount guaranteed was $25
million.
If Hawkeye fails to perform under a contract or to pay subcontractors and
vendors, the counter-party that requested the performance bond may demand
that the surety make payments or provide services under the bond. KeySpan
would then have to reimburse the surety for any expenses or outlays the
surety incurs. To date, we have not had a claim made against either the
guarantee associated with the line of credit or the performance bonds.
KeySpan is presently engaged in a legal action with Hawkeye as discussed
further in "Legal Matters" below.
Fixed Charges Under Firm Contracts: Our utility subsidiaries and the Ravenswood
facility 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 $462.3 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.
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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 or cash flows.
KeySpan has been cooperating in preliminary inquiries regarding trading in
KeySpan Corporation stock by individual officers of KeySpan prior to the July
17, 2001 announcement that KeySpan was taking a special charge in its Energy
Services business and otherwise reducing its 2001 earnings forecast. These
inquiries are being conducted by the U.S. Attorney's Office, Southern District
of New York and the SEC.
As previously reported, as part of its continuing inquiry, on March 5, 2002, the
SEC issued a formal order of investigation, pursuant to which it will review the
trading activity of certain company insiders from May 1, 2001 to the present, as
well as KeySpan's compliance with its reporting rules and regulations, generally
during the period following the acquisition of the Roy Kay companies through the
July 17th announcement.
Furthermore, KeySpan and certain of its officers and directors are defendants in
a number of class action lawsuits filed in the United States District Court for
the Eastern District of New York after the July 17th announcement. These
lawsuits allege, among other things, violations of Sections 10(b) and 20(a) of
the Securities Exchange Act of 1934, as amended ("Exchange Act"), in connection
with disclosures relating to or following the acquisition of the Roy Kay
companies by KeySpan Services, Inc., a KeySpan subsidiary and the announcement
of the agreement to acquire Eastern and ENI. Finally, in October 2001, a
shareholder's derivative action was commenced in the same court against certain
officers and directors of KeySpan, alleging, among other things, breaches of
fiduciary duty, violations of the New York Business Corporation Law and
violations of Section 20(a) of the Exchange Act. In addition, a second
derivative action has been commenced asserting similar allegations. Each of the
proceedings seek monetary damages in an unspecified amount. We have filed a
motion to dismiss the class action lawsuits which is currently pending. 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 June 2002, Hawkeye Electric, LLC et al. ("Hawkeye") commenced an action in
New York State Supreme Court, Suffolk County against KeySpan and certain of its
subsidiaries alleging, among other things, that KeySpan and its subsidiaries
breached certain contractual obligations to Hawkeye with respect to the
provision of certain gas, electric and telecommunications construction services
offered by Hawkeye. Hawkeye is seeking damages in excess of $90 million and
KeySpan has alleged a number of counterclaims seeking damages in excess of $4
million. At this time, we are unable to determine the outcome of this proceeding
and what effect, if any, such outcome will have on our financial position,
results of operations or cash flows.
KeySpan subsidiaries, along with several other parties, have been named as
defendants in numerous proceedings filed by plaintiffs claiming various degrees
of injury from asbestos exposure. Most of these proceedings have been commenced
in the New York State Supreme Court for New York County by alleged present or
former employees of various contractors, allegedly as a result of exposure to
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asbestos in connection with the construction and maintenance of our electric
generating facilities. Certain subsidiaries have also been named as defendants
in proceedings involving facilities not owned by KeySpan. At the present time,
KeySpan is unable to determine the outcome of these proceedings, but does not
believe that such outcome, if adverse, will have a material effect on its
financial condition, results of operations or 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 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.
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.
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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") or Voluntary Cleanup Agreements have
been executed with the DEC to address the investigation and remediation
activities associated with three 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 $81.1 million, which amount has been accrued
by us. Expenditures incurred to date by us with respect to MGP-related
activities total $26.8 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 have performed preliminary site assessments at
five other sites, which were formerly owned by KEDLI. For one of these sites,
the DEC has advised us that no further action is required. At another site, the
DEC has indicated that a remedial investigation will be required. For the
remaining three sites, KeySpan awaits the DEC's comments.
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 $61.1 million,
which amount has been accrued by us. Expenditures incurred to date by us with
respect to KEDLI MGP-related activities total $22.3 million.
We presently estimate the remaining cost of our New York/Long Island MGP-related
environmental cleanup activities will be $142.2 million, which amount has been
accrued by us as a reasonable estimate of probable cost for known sites.
Expenditures incurred to date by us with respect to these MGP-related activities
total $49.1 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 amounts due to
ratepayers against its estimated environmental cleanup costs for MGP sites. At
December 31, 2002, we have reflected a regulatory asset of $123.7 million for
our New York/Long Island MGP sites.
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We are also responsible for environmental obligations associated with the
Ravenswood 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. We are not responsible for
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. We presently estimate the remaining environmental clean up
activities for this site will be $3.6 million, which amount has been accrued by
us. Expenditures incurred to date total $1.4 million.
New England Sites: Within the Commonwealth of Massachusetts and the State of New
Hampshire, we are aware of 76 former MGP sites and related facilities within the
existing or former service territories of KEDNE.
Boston Gas Company, Colonial Gas Company and Essex Gas Company may have or share
responsibility under applicable environmental laws for the remediation of 66 MGP
sites and related facilities. A subsidiary of National Grid USA ("National
Grid"), formerly New England Electric System, has assumed responsibility for
remediating 11 of these sites, subject to a limited contribution from Boston Gas
Company, and has provided full indemnification to Boston Gas Company with
respect to eight other sites. At this time, there is substantial uncertainty as
to whether Boston Gas Company, Colonial Gas Company or Essex Gas Company have or
share responsibility for remediating any of these other sites. No notice of
responsibility has been issued to us for any of these sites from any
governmental environmental authority.
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 Massachusetts KEDNE
MGP-related environmental cleanup activities will be $32.4 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 $10.7 million.
We may have or share responsibility under applicable environmental laws for the
remediation of 10 MGP sites and related facilities associated with the
historical 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.
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With respect to the Laconia and Nashua sites, EnergyNorth has entered into
separate cost sharing agreements with Public Service of New Hampshire ("PSNH").
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 $14.7 million, which amount has been
accrued by us as a reasonable estimate of probable cost for known sites.
Expenditures incurred since November 8, 2000, with respect to these MGP-related
activities total $5.3 million.
By rate orders, the DTE and the NHPUC provide for the recovery of site
investigation and remediation costs and, accordingly, at December 31, 2002, we
have reflected a regulatory asset of $58.7 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 asset.
However, rate plans currently in effect for these subsidiaries provide for the
recovery of investigation and remediation costs.
KeySpan New England LLC Sites: We are aware of three non-utility sites
associated with the historic operations of KeySpan New England, LLC, a successor
company to Eastern Enterprises for which we may have or share environmental
remediation responsibility or ongoing maintenance: the former Philadelphia Coke
site located in Pennsylvania; the former Connecticut Coke site located in New
Haven, Connecticut; and the former Everett Coal Tar Processing Facility (the
"Everett Facility") located in Massachusetts. Honeywell International, Inc. and
Beazer East, Inc. (both former owners and operators of the Everett Facility)
together with KeySpan, have entered into an ACO with the Massachusetts
Department of Environmental Protection for the investigation and development of
a remedial response plan for the site.
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. In
2002, Beazer East commenced an action with the U.S. District Court for the
Southern District of New York which seeks a judicial determination on the
allocation of liability for the Everett Facility. The outcome of this proceeding
cannot yet be determined.
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KeySpan also is recovering certain legal defense costs and may be entitled to
recover remediation costs from its insurers. We presently estimate the remaining
cost of our environmental cleanup activities for the three non-utility sites
will be approximately $39.2 million, which amount has been accrued by us as a
reasonable estimate of probable costs for known sites. Expenditures incurred
since November 8, 2000, with respect to these sites total $4.0 million.
We believe that in the aggregate, the accrued liability for investigation and
remediation of sites and related facilities identified above are reasonable
estimates of likely cost within a range of reasonable, foreseeable costs. We may
be required to investigate and, if necessary, remediate each of these, or other
currently unknown former sites and related facility sites, the cost of which is
not presently determinable but may be material to our financial position,
results of operations or cash flows. Remediation costs for each site may be
materially higher than noted, depending upon remediation experience, selected
end use for each site, and actual environmental conditions encountered.
Note 8. Hedging, Derivative Financial Instruments and Fair Values
Financially-Settled Commodity Derivative Instruments: From time to time KeySpan
has utilized derivative financial instruments, such as futures, options and
swaps, for the purpose of hedging exposure to commodity price risk and to hedge
the cash flow variability associated with a portion of peak electric energy
sales.
Houston Exploration has utilized collars, as well as over-the-counter ("OTC")
swaps to hedge the cash flow variability associated with forecasted sales of a
portion of its natural gas production. As of December 31, 2002, Houston
Exploration has hedged approximately 67% and 20% of its estimated 2003 and 2004
production, respectively. Further, Houston Exploration may enter into additional
derivative positions for 2003 and 2004. Houston Exploration used standard New
York Mercantile Exchange ("NYMEX") futures prices and published volatility in
its Black-Scholes calculation to value its outstanding derivatives. The maximum
length of time over which Houston Exploration has hedged such cash flow
variability is through December 2004. The estimated amount of losses associated
with such derivative instruments that are reported in Other Comprehensive Income
and that are expected to be reclassified into earnings over the next twelve
months is $34.9 million, or $22.7 million after-tax.
With respect to price exposure associated with fuel purchases for the Ravenswood
facility, KeySpan employs standard NYMEX natural gas futures contracts and
over-the-counter financially settled natural gas basis swaps to hedge the cash
flow variability of a portion of forecasted purchases of natural gas. KeySpan
also employs the use of financially-settled oil swap contracts to hedge the cash
flow variability of a portion of forecasted purchases of fuel oil that will be
124
consumed at the Ravenswood facility. The maximum length of time over which we
have hedged cash flow variability associated with: (i) forecasted purchases of
natural gas is through December 2003; and (ii) forecasted purchases of fuel oil
is through April 2004. We used standard NYMEX futures prices to value the gas
futures contracts and industry published oil indices for number 6 grade fuel oil
to value the oil swap contracts. The estimated amount of gains associated with
all such derivative instruments that are reported in Other Comprehensive Income
and that are expected to be reclassified into earnings over the next twelve
months is $4.5 million, or $2.9 million after-tax.
Our retail gas and electric marketing subsidiary, our domestic gas distribution
operations and KeySpan Canada employed NYMEX natural gas futures contracts and
natural gas swaps to lock-in a price for expected future natural gas purchases.
As applicable, we used standard NYMEX futures prices and relevant natural gas
indices to value the outstanding contracts. The maximum length of time over
which we have hedged such cash flow variability is through December 2003. The
estimated amount of gains associated with such derivative instruments that are
reported in Other Comprehensive Income and that are expected to be reclassified
into earnings over the next twelve months is $4.9 million, or $3.2 million
after-tax.
We have also engaged in the use of cash-settled swap instruments to hedge the
cash flow variability associated with (i) a portion of forecasted peak electric
energy sales from the Ravenswood facility and (ii) forecasted sales of Unforced
Capacity ("UCAP") to the NYISO. The maximum length of time over which we have
hedged cash flow variability is through March 2004. We used NYISO-location zone
published indices as well as published NYISO bidding prices to value these
outstanding derivatives. The estimated amount of losses associated with such
derivative instruments that are reported in Other Comprehensive Income and that
are expected to be reclassified into earnings over the next twelve months is
$1.1 million, or $0.7 million after-tax.
KeySpan Canada also has employed electricity swap contracts to lock-in the
purchase price of electricity needed to operate its gas processing plants. These
contracts are not exchange-traded and local published indices were used to value
these outstanding swap agreements. The maximum length of time over which we have
hedged such cash flow variability is through December 2003. The estimated amount
of losses associated with such derivative instruments that are reported in Other
Comprehensive Income and that are expected to be reclassified into earnings over
the next twelve months is $1.5 million, or $1.0 million after-tax.
125
The following tables set forth selected financial data associated with these
derivative financial instruments noted above that were outstanding at December
31, 2002.
- ----------------------------------------------------------------------------------------------------------------------------
Year of Volumes Fixed Current Fair Value
Type of Contract Maturity mmcf Floor $ Ceiling $ Price $ Price ($000)
- ----------------------------------------------------------------------------------------------------------------------------
Gas
Collars 2003 54,300 3.48 4.92 - 4.43-4.99 (14,681)
2004 18,300 3.50 4.75 - 4.03-4.81 (3,767)
Swaps/Futures - Short Natural Gas 2003 14,751 - - 2.91-3.52 3.87-4.99 (20,694)
Swaps/Futures - Long Natural Gas 2003 10,580 - - 3.10-5.38 4.43-5.02 7,428
- ----------------------------------------------------------------------------------------------------------------------------
97,931 (31,714)
- ----------------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------
Fair
Year of Volumes Value
Type of Contract Maturity Barrels Fixed Price $ Current Price $ ($000)
- ---------------------------------------------------------------------------------------------------
Oil
Swaps - Short Fuel Oil 2003 90,000 28.50 28.14-31.00 (145)
Swaps - Long Fuel Oil 2003 320,815 20.05-27.20 23.72-33.81 2,633
2004 5,548 20.50-23.70 22.66-23.19 6
- ---------------------------------------------------------------------------------------------------
416,363 2,494
- ---------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------
Fair
Year of Fixed Margin/ Value
Type of Contract Maturity Capacity MWh Price $ Current Price $ ($000)
- --------------------------------------------------------------------------------------------------------------
Electricity
Swaps - Energy 2003 119,680 12.70-57.80 14.15-48.09 (1,889)
2004 68,800 14.00 22.25-22.34 (823)
Swaps - Capacity 2003 1,000 7.75 7.00-9.41 (696)
- --------------------------------------------------------------------------------------------------------------
1,000 188,480 (3,408)
- --------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------
Change in Fair Value of Derivative Instruments 2002
($000)
- ------------------------------------------------------------------------------
Fair value of contracts at January 1, $ 55,097
(Gain) on contracts realized (26,204)
Fair value of new contracts when entered into during period -
(Decrease) in fair value of all open contracts (61,521)
- ------------------------------------------------------------------------------
Fair value of contracts outstanding at December 31, $ (32,628)
- ------------------------------------------------------------------------------
126
NYMEX futures are also used to economically hedge the cash flow variability
associated with the purchase of fuel for a portion of our fleet vehicles.
Further, KeySpan Canada has a portfolio of financially-settled natural gas
collars and natural gas liquid swap transactions. Such contracts are executed by
KeySpan Canada to: (i) synthetically fix the price that is paid or received by
KeySpan Canada for certain physical transactions involving natural gas and
natural gas liquids and (ii) transfer the price exposure of such instruments to
other trading partners. In addition, our retail gas and electric marketing
subsidiary has bought options to economically hedge the cash flow variability
associated with a portion of expected future natural gas purchases. These
derivative financial instruments do not qualify for hedge accounting under SFAS
133. At December 31, 2002, these instruments had a net fair market value of
($0.4) million, that was recorded on the Consolidated Balance Sheet. Based on
the non-hedge designation of these instruments, the loss was recognized in the
Consolidated Statement of Income.
Firm Gas Sales Derivative Instruments - Regulated Utilities: We also use
derivative financial instruments to reduce the cash flow variability associated
with the purchase price for a portion of future natural gas purchases. Our
strategy is to minimize fluctuations in firm gas sales prices to our regulated
firm gas sales customers in our New York and New Hampshire service territories.
Since these derivative instruments are employed to reduce the variability of the
purchase price of natural gas to be sold to regulated firm gas sales customers,
the accounting for these derivative instruments is subject to SFAS 71.
Therefore, changes in the market value of these derivatives have been recorded
as a Regulatory Asset or Regulatory Liability on the Consolidated Balance Sheet.
Gains or losses on the settlement of these contracts are initially deferred and
then refunded to or collected from our firm gas sales customers during the
appropriate winter heating season consistent with regulatory requirements.
The following table sets forth selected financial data associated with these
derivative financial instruments that were outstanding at December 31, 2002.
- -------------------------------------------------------------------------------------------------
Fair
Year of Volumes Value
Type of Contract Maturity mmcf Fixed Price $ Current Price $ ($000)
- -------------------------------------------------------------------------------------------------
Options 2003 5,560 3.90-4.50 4.27 3,250
Swaps 2003 2,080 3.85-4.50 4.79-4.95 1,586
- -------------------------------------------------------------------------------------------------
7,640 4,836
- -------------------------------------------------------------------------------------------------
Physically-Settled Commodity Derivative Instruments: On April 1, 2002 we
implemented Derivative Implementation Group ("DIG") Issue C15 and C16 of
Statement of Financial Accounting Standard 133, "Accounting for Derivative
Instruments and Hedging Activities", as amended and interpreted, incorporating
SFAS 137 and SFAS 138 and certain implementation issues (collectively "SFAS
133"). Issue C15 establishes new criteria that must be satisfied in order for
option-type and forward contracts in electricity to be exempted as normal
purchases and sales, while Issue C16 relates to the exemption (as normal
purchases and normal sales) of contracts that combine a forward contract and a
purchased option contract. Based upon a review of our physical commodity
contracts, we determined that certain contracts for the physical purchase of
natural gas can no longer be exempted as normal purchases from the requirements
of SFAS 133. At December 31, 2002, the fair value of these contracts was $1.2
million. Since these contracts are for the purchase of natural gas sold to
regulated firm gas sales customers, the accounting for these contracts is
subject to SFAS 71. Therefore, changes in the market value of these contracts
have been recorded as a Regulatory Asset or Regulatory Liability on the
Consolidated Balance Sheet.
127
Interest Rate Derivative Instruments: During most of 2002, we had interest rate
swap agreements in which approximately $1.3 billion of fixed rate debt had been
synthetically modified to floating rate debt. Under the terms of the agreements,
we received the fixed coupon rate associated with these bonds and paid the
counter-parties a variable interest rate that was reset on a quarterly basis.
These swaps were designated as fair-value hedges and qualified for "short-cut"
hedge accounting treatment under SFAS 133. Through the utilization of these
agreements, we reduced recorded interest expense by $35.6 million for the twelve
months ended December 31, 2002.
In early November 2002, we terminated two interest rate swap agreements with an
aggregate notional amount of $1.0 billion and received $80.9 million from our
swap counter-parties, of which $23.4 million represented accrued swap interest.
The difference between the termination settlement amount and the amount of
accrued swap interest, $57.4 million, will be amortized to earnings (as an
adjustment to interest expense) on a level yield basis over the remaining lives
of the originally hedged debt obligations. The remaining swap, which had a
notional amount of $270.0 million, and a fair market value of $15.6 million at
December 31, 2002, was terminated on February 25, 2003. We received $18.4
million from our swap counter-parties, of which $8.1 million represents accrued
swap interest. The difference between the termination settlement amount and the
amount of accrued interest, $10.3 million, will be recorded to earnings in the
first quarter of 2003. This swap was used to hedge a portion of our outstanding
promissory notes to LIPA. As discussed in Note 6 "Long-Term Debt", we intend to
redeem a portion of these promissory notes before the end of the first quarter
of 2003.
Additionally, we also have an interest rate swap agreement that hedges the cash
flow variability associated with the forecasted issuance of a series of
commercial paper offerings. The maximum length of time over which we have hedged
such cash flow variability is through March 2003. The estimated amount of loss
associated with such derivative instruments that are reported in Other
Comprehensive Income and that are expected to be reclassified into earnings over
the next twelve months is $0.6 million, or $0.4 million after-tax.
Weather Derivatives: The utility tariffs associated with the KEDNE's operations
do not contain weather normalization adjustments. As a result, fluctuations from
normal weather may have a significant positive or negative effect on the results
of these operations. To mitigate a substantial portion of the effect of
fluctuations from normal weather on our financial position and cash flows, we
sold heating degree-day call options and purchased heating degree-day put
options for the November 2002 - March 2003 winter season. With respect to sold
call options, KeySpan is required to make a payment of $40,000 per heating
degree-day to its counter-parties when actual weather experienced during the
November 2002 - March 2003 time frame is above 4,470 heating degree days, which
equates to approximately 1% colder than normal weather. With respect to
purchased put options, KeySpan will receive a $20,000 per heating degree day
payment from its counter-parties when actual weather is below 4,150 heating
degree days, or is approximately 7% warmer than normal. Based on the terms of
128
such contracts, as discussed in Note 1 "Summary of Significant Accounting
Policies", we account for such instruments pursuant to the requirements of EITF
99-2, "Accounting for Weather Derivatives." In this regard, we account for such
instruments using the "intrinsic value method" as set forth in such guidance.
During the fourth quarter of 2002, weather was 7% colder than normal and, as a
result, $3.3 million has been recorded as a reduction to revenues.
Derivative contracts are primarily used to manage exposure to market risk
arising from changes in commodity prices and interest rates. In the event of
nonperformance by a counter-party to a derivative contract, the desired impact
may not be achieved. The risk of a counter-party nonperformance is generally
considered credit risk and is actively managed by assessing each counter-party
credit profile and negotiating appropriate levels of collateral and credit
support.
Fair Values of Long-Term Debt
- ---------------------------------------------------------------------------
December 31,
(In Thousands of Dollars) 2002 2001
- ---------------------------------------------------------------------------
First Mortgage Bonds $ 180,666 $ 182,666
Notes 3,441,619 3,076,455
Gas Facilities Revenue Bonds 674,828 630,845
Authority Financing Notes 66,005 66,005
Promissory Notes 616,240 617,933
MEDS Equity Units 525,918 -
- ---------------------------------------------------------------------------
$ 5,505,276 $ 4,573,904
- ---------------------------------------------------------------------------
Carrying Values of Long-Term Debt
- -----------------------------------------------------------------------------
December 31,
(In Thousands of Dollars) 2002 2001
- -----------------------------------------------------------------------------
First Mortgage Bonds $ 163,625 $ 179,122
Notes 2,985,000 2,985,000
Gas Facilities Revenue Bonds 648,500 648,500
Authority Financing Notes 66,005 66,005
Promissory Notes 602,427 602,427
MEDS Equity Units 460,000 -
- -----------------------------------------------------------------------------
$ 4,925,557 $ 4,481,054
- -----------------------------------------------------------------------------
Our subsidiary debt is carried at an amount approximating fair value because
interest rates are based on current market rates. All other financial
instruments included in the Consolidated Balance Sheet such as cash, commercial
paper, accounts receivable and accounts payable, are also stated at amounts that
approximate fair value.
Note 9. Discontinued Operations
On November 8, 2000, KeySpan acquired Midland Enterprises LLC ("Midland"), an
inland marine transportation subsidiary, as part of the Eastern acquisition. In
its order approving the acquisition, the SEC required KeySpan to sell this
subsidiary by November 8, 2003 because Midland's operations were not
functionally related to KeySpan's core utility operations. On July 2, 2002, the
sale of Midland to Ingram Industries Inc. was completed and net proceeds of
$175.1 million were received from the sale.
129
Discontinued operations for the year ended December 31, 2001 included an
anticipated after-tax loss on disposal of $30.4 million. As a result of a change
in the tax structuring strategy related to the sale of Midland, in the second
quarter of 2002 we recorded an additional provision for city and state taxes and
made adjustments to the estimates used in the December 31, 2001 loss provision.
These changes resulted in an additional after tax loss on disposal of $19.7
million.
The following is selected financial information for Midland for the period
January 1, 2002 through July 2, 2002 and the year ended December 31, 2001 and
for the period November 8, 2000 through December 31, 2000:
- --------------------------------------------------------------------------------------------
(In Thousands of Dollars) 2002 2001 2000
- --------------------------------------------------------------------------------------------
Revenues $ 116,149 $ 266,792 $ 40,788
Pre-tax income (loss) (4,624) 18,489 (2,970)
Income tax (expense) benefit 1,268 (7,571) 1,027
- --------------------------------------------------------------------------------------------
Income (loss) from discontinued operations (3,356) 10,918 (1,943)
- --------------------------------------------------------------------------------------------
Estimated book gain on disposal 5,980 44,580 -
Tax expense associated with disposal (22,286) (74,936) -
- --------------------------------------------------------------------------------------------
Estimated loss on disposal (16,306) (30,356) -
- --------------------------------------------------------------------------------------------
Loss from discontinued operations $ (19,662) $ (19,438) $ (1,943)
- --------------------------------------------------------------------------------------------
Assets and liabilities of the discontinued operations are as follows:
- ------------------------------------------------------------------------
(In Thousands of Dollars) 2001
- ------------------------------------------------------------------------
Current assets $ 139,522
Property, plant and equipment, net 316,626
Long-term assets 35,233
Current liabilities (58,835)
Long-term liabilitites (241,491)
- ------------------------------------------------------------------------
Assets held for disposal $ 191,055
- ------------------------------------------------------------------------
Note 10. 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 have been integrated with those
of other KeySpan energy-related businesses. During 2002, substantially all of
the remaining field work on outstanding construction projects was completed. We
are now engaged in the finalization of claims and collections and, as a result,
their operations will continue to be consolidated in our Consolidated Financial
Statements until such time as this process is complete.
130
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 account and retainage receivables; and (iv) operating losses. For
the years ended December 31, 2002, 2001 and 2000 the Roy Kay companies recorded
EBIT losses of $10.8 million, $137.8 million and EBIT 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 7
"Contractual Obligations and Contingencies" - Legal Matters.)
Note 11. 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
Operations and Maintenance expense and a reduction of $11.5 million to Interest
Expense on the Consolidated Statement of Income.
Note 12. 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 the parent, KeySpan
Corporation. On February 1, 2000, KEDLI issued $400 million of 7.875%
Medium-Term Notes due 2010. In January 2001, KEDLI issued an additional $125
million of Medium-Term Notes at 6.9% due January, 2008. The following condensed
financial statements are required to be disclosed by SEC regulations and set
forth those of KEDLI, KeySpan Corporation as guarantor of the Medium- Term Notes
and our other subsidiaries on a combined basis. The December 31, 2001 and 2000
disclosures have been revised to separately present our other subsidiaries.
131
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Income
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2002
(In Thousands of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- -----------------------------------------------------------------------------------------------------------------------------------
Revenues $ 463 $ 810,601 $ 5,160,065 $ (463) $ 5,970,666
Operating Expenses
Purchased gas - 379,742 1,273,531 - 1,653,273
Fuel and purchased power - - 385,059 - 385,059
Operations and maintenance 13,325 45,357 2,043,215 - 2,101,897
Intercompany expense 2,772 79,826 (79,826) (2,772) -
Depreciation and amortization (44) 65,911 448,746 - 514,613
Operating taxes (2,149) 85,614 327,186 - 410,651
------------------------------------------------------------------------------------------
Total Operating Expenses 13,904 656,450 4,397,911 (2,772) 5,065,493
------------------------------------------------------------------------------------------
Operating Income (Loss) (13,441) 154,151 762,154 2,309 905,173
Interest charges (200,920) (62,520) (295,209) 257,145 (301,504)
Other income and (deductions) 565,366 8,152 78,625 (633,068) 19,075
------------------------------------------------------------------------------------------
Total Other Income and (Deductions) 364,446 (54,368) (216,584) (375,923) (282,429)
Income (Loss) Before Income Taxes 351,005 99,783 545,570 (373,614) 622,744
Income Taxes (Benefit) (26,683) 31,188 220,889 - 225,394
------------------------------------------------------------------------------------------
Earnings from Continuing Operations $ 377,688 $ 68,595 $ 324,681 $ (373,614) $ 397,350
Discontinued Operations - - (19,662) - (19,662)
------------------------------------------------------------------------------------------
Net Income $ 377,688 $ 68,595 $ 305,019 $ (373,614) $ 377,688
==========================================================================================
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Income
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2001
(In Thousands of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Revenues $ 504 $ 889,693 $ 5,743,422 $ (504) $ 6,633,115
Operating Expenses
Purchased gas - 464,780 1,706,333 - 2,171,113
Fuel and purchased power - - 538,532 - 538,532
Operations and maintenance (24,537) 45,106 2,094,190 - 2,114,759
Intercompany expense 278 87,738 (87,738) (278) -
Depreciation and amortization 4,273 56,274 498,591 - 559,138
Operating taxes 1,094 91,204 356,626 - 448,924
---------------------------------------------------------------------------------------
Total Operating Expenses (18,892) 745,102 5,106,534 (278) 5,832,466
---------------------------------------------------------------------------------------
Operating Income (Loss) 19,396 144,591 636,888 (226) 800,649
Interest charges (230,618) (65,206) (264,286) 206,640 (353,470)
Other income and (deductions) 426,346 9,721 18,455 (447,316) 7,206
---------------------------------------------------------------------------------------
Total Other Income and (Deductions) 195,728 (55,485) (245,831) (240,676) (346,264)
Income (Loss) Before Income Taxes 215,124 89,106 391,057 (240,902) 454,385
Income Taxes (Benefit) (9,130) 28,319 191,504 - 210,693
---------------------------------------------------------------------------------------
Earnings from Continuing Operations $ 224,254 $ 60,787 $ 199,553 $ (240,902) $ 243,692
Discontinued Operations - - (19,438) - (19,438)
---------------------------------------------------------------------------------------
Net Income $ 224,254 $ 60,787 $ 180,115 $ (240,902) $ 224,254
=======================================================================================
132
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Income
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2000
(In Thousands of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- ----------------------------------------------------------------------------------------------------------------------------------
Revenues $ 1,799 $ 794,965 $ 4,285,737 $ (1,799) $ 5,080,702
Operating Expenses
Purchased gas - 408,087 1,000,593 - 1,408,680
Fuel and purchased power - - 460,841 - 460,841
Operations and maintenance 61,520 127,780 1,535,611 - 1,724,911
Intercompany expense 1,799 10,718 (10,718) (1,799) -
Depreciation and amortization 4,273 46,017 280,632 - 330,922
Operating taxes (8,172) 92,684 337,424 - 421,936
-----------------------------------------------------------------------------------
Total Operating Expenses 59,420 685,286 3,604,383 (1,799) 4,347,290
-----------------------------------------------------------------------------------
Operating Income (Loss) (57,621) 109,679 681,354 - 733,412
Interest charges (97,007) (53,656) (118,044) 67,393 (201,314)
Other income and (deductions) 417,411 (707) (67,606) (361,184) (12,086)
-----------------------------------------------------------------------------------
Total Other Income and (Deductions) 320,404 (54,363) (185,650) (293,791) (213,400)
Income (Loss) Before Income Taxes 262,783 55,316 495,704 (293,791) 520,012
Income Taxes (Benefit) (38,024) 18,362 236,924 - 217,262
-----------------------------------------------------------------------------------
Earnings from Continuing Operations $ 300,807 $ 36,954 $ 258,780 $ (293,791) $ 302,750
Discontinued Operations - - (1,943) - (1,943)
-----------------------------------------------------------------------------------
Net Income $ 300,807 $ 36,954 $ 256,837 $ (293,791) $ 300,807
===================================================================================
133
- ------------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
- ------------------------------------------------------------------------------------------------------------------------------------
December 31, 2002
Other
Guarantor KEDLI Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash and temporary cash investments $ 88,308 $ 6,472 $ 75,837 $ - $ 170,617
Accounts receivable, net 23,982 208,512 1,299,559 - 1,532,053
Other current assets 1,757 79,206 432,816 - 513,779
-----------------------------------------------------------------------------------------
114,047 294,190 1,808,212 - 2,216,449
-----------------------------------------------------------------------------------------
Equity Investments 3,797,964 - 792,050 (4,330,826) 259,188
-----------------------------------------------------------------------------------------
Property
Gas - 1,771,780 4,352,501 - 6,124,281
Other - - 4,807,724 - 4,807,724
Accumulated depreciation and depletion - (322,236) (3,392,169) - (3,714,405)
-----------------------------------------------------------------------------------------
- 1,449,544 5,768,056 - 7,217,600
-----------------------------------------------------------------------------------------
Intercompany Accounts Receivable 3,619,515 54,549 354,747 (4,028,811) -
Deferred Charges 339,443 195,369 2,386,257 - 2,921,069
-----------------------------------------------------------------------------------------
Total Assets $ 7,870,969 $ 1,993,652 $ 11,109,322 $ (8,359,637) $ 12,614,306
=========================================================================================
LIABILITIES AND CAPITALIZATION
Current Liabilities
Accounts payable $ 240,571 $ 68,772 $ 752,306 $ - $ 1,061,649
Commercial paper 915,697 - - - 915,697
Other current liabilities - 104,975 137,907 - 242,882
----------------------------------------------------------------------------------------
1,156,268 173,747 890,213 - 2,220,228
----------------------------------------------------------------------------------------
Intercompany Accounts Payable - 233,392 1,714,035 (1,947,427) -
----------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax (43,110) 139,715 780,408 - 877,013
Other deferred credits and liabilities 481,964 98,805 453,353 - 1,034,122
----------------------------------------------------------------------------------------
438,854 238,520 1,233,761 - 1,911,135
-----------------------------------------------------------------------------------------
Capitalization
Common shareholders' equity 2,983,214 647,089 3,645,115 (4,330,826) 2,944,592
Preferred stock 83,849 - - - 83,849
Long-term debt 3,208,784 700,904 3,395,777 (2,081,384) 5,224,081
-----------------------------------------------------------------------------------------
Total Capitalization 6,275,847 1,347,993 7,040,892 (6,412,210) 8,252,522
-----------------------------------------------------------------------------------------
Minority Interest in Subsidiary Companies - - 230,421 - 230,421
-----------------------------------------------------------------------------------------
Total Liabilities and Capitalization $ 7,870,969 $ 1,993,652 $ 11,109,322 $ (8,359,637) $ 12,614,306
=========================================================================================
134
- ------------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
- ------------------------------------------------------------------------------------------------------------------------------------
December 31, 2001
Other
Guarantor KEDLI Subsidiaries Eliminations Consolidated
-------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash and temporary cash investments $ - $ - $ 159,252 $ - $ 159,252
Accounts receivable, net 25,037 178,464 1,069,098 - 1,272,599
Other current assets 658 112,317 453,661 - 566,636
-------------------------------------------------------------------------------------
25,695 290,781 1,682,011 - 1,998,487
-------------------------------------------------------------------------------------
Assets Held for Disposal - - 191,055 - 191,055
Equity Investments 3,539,546 - 756,111 (4,072,408) 223,249
-------------------------------------------------------------------------------------
Property
Gas - 1,629,963 4,074,894 - 5,704,857
Other - - 4,231,262 - 4,231,262
Accumulated depreciation and depletion - (294,400) (3,035,788) - (3,330,188)
-------------------------------------------------------------------------------------
- 1,335,563 5,270,368 - 6,605,931
-------------------------------------------------------------------------------------
Intercompany Accounts Receivable 3,578,204 54,549 445,947 (4,078,700) -
Deferred Charges 156,001 199,855 2,415,028 - 2,770,884
-------------------------------------------------------------------------------------
Total Assets $ 7,299,446 $ 1,880,748 $10,760,520 $ (8,151,108) $ 11,789,606
=====================================================================================
LIABILITIES AND CAPITALIZATION
Current Liabilities
Accounts payable $ 455,947 $ 115,557 $ 519,926 $ - $ 1,091,430
Commercial paper 1,048,450 - - - 1,048,450
Other current liabilities (255) 23,844 221,240 - 244,829
-------------------------------------------------------------------------------------
1,504,142 139,401 741,166 - 2,384,709
-------------------------------------------------------------------------------------
Intercompany Accounts Payable - 324,592 1,667,846 (1,992,438) -
-------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax (60,261) 4,772 653,561 - 598,072
Other deferred credits and liabilities 320,510 100,452 521,152 - 942,114
-------------------------------------------------------------------------------------
260,249 105,224 1,174,713 - 1,540,186
-------------------------------------------------------------------------------------
Capitalization
Common shareholders' equity 2,823,177 610,627 3,529,206 (4,072,408) 2,890,602
Preferred stock 84,077 - - - 84,077
Long-term debt 2,627,801 700,904 3,455,206 (2,086,262) 4,697,649
-------------------------------------------------------------------------------------
Total Capitalization 5,535,055 1,311,531 6,984,412 (6,158,670) 7,672,328
-------------------------------------------------------------------------------------
Minority Interest in Subsidiary Companies - - 192,383 - 192,383
-------------------------------------------------------------------------------------
Total Liabilities and Capitalization $ 7,299,446 $ 1,880,748 $10,760,520 $ (8,151,108) $ 11,789,606
=====================================================================================
135
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2002
------------------------------------------------------------------
Other
Guarantor KEDLI Subsidiaries Consolidated
------------------------------------------------------------------
Operating Activities
Net Cash (Used in) Provided by Operating Activities $ (97,981) $ 191,826 $ 715,232 $ 809,077
------------------------------------------------------------------
Investing Activities
Capital expenditures - (148,418) (985,459) (1,133,877)
Other - - 147,531 147,531
------------------------------------------------------------------
Net Cash (Used in) Investing Activities - (148,418) (837,928) (986,346)
------------------------------------------------------------------
Financing Activities
Treasury stock issued 86,710 - - 86,710
Issuance (payment) of debt, net 327,247 - (35,711) 291,536
Common and preferred stock dividends paid (256,656) - - (256,656)
Termination of interest rate swaps and other 70,299 - (3,255) 67,044
Net intercompany accounts (41,311) (36,936) 78,247 -
------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities 186,289 (36,936) 39,281 188,634
------------------------------------------------------------------
Net (Decrease) Increase in Cash and Cash Equivalents $ 88,308 $ 6,472 $ (83,415) $ 11,365
Cash and Cash Equivalents at Beginning of Period - - 159,252 159,252
------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 88,308 $ 6,472 $ 75,837 $ 170,617
==================================================================
- -----------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
- -----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2001
--------------------------------------------------------------------
Other
Guarantor KEDLI Subsidiaries Consolidated
--------------------------------------------------------------------
Operating Activities
Net Cash Provided by Operating Activities $ 121,028 $ 64,294 $ 704,859 $ 890,181
--------------------------------------------------------------------
Investing Activities
Capital expenditures - (131,568) (928,191) (1,059,759)
Other - - 18,452 18,452
--------------------------------------------------------------------
Net Cash (Used in) Investing Activities - (131,568) (909,739) (1,041,307)
--------------------------------------------------------------------
Financing Activities
Treasury stock issued 88,786 - - 88,786
Issuance (payment) of debt, net 248,213 125,000 3,706 376,919
Common and preferred stock dividends paid (251,502) - - (251,502)
Other 10,582 - 2,264 12,846
Net intercompany accounts (217,107) (57,726) 274,833 -
--------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities (121,028) 67,274 280,803 227,049
--------------------------------------------------------------------
Net Increase in Cash and Cash Equivalents $ - $ - $ 75,923 $ 75,923
Cash and Cash Equivalents at Beginning of Period - - 83,329 83,329
--------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ - $ - $ 159,252 $ 159,252
====================================================================
136
- -----------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
- -----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2000
---------------------------------------------------------------------
Other
Guarantor KEDLI Subsidiaries Consolidated
---------------------------------------------------------------------
Operating Activities
Net Cash Provided by Operating Activities $ 245,497 $ 112,738 $ 80,491 $ 438,726
---------------------------------------------------------------------
Investing Activities
Capital expenditures - (114,977) (518,058) (633,035)
Other (1,946,043) - (292,732) (2,238,775)
---------------------------------------------------------------------
Net Cash (Used in) Investing Activities (1,946,043) (114,977) (810,790) (2,871,810)
---------------------------------------------------------------------
Financing Activities
Treasury stock issued 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 2,741,937 400,000 (107,975) 3,033,962
Debt received (paid) 397,000 (397,000) - -
Common and preferred stock dividends paid (260,001) - - (260,001)
Termination of interest rate swaps and other (41,799) - (53,640) (95,439)
Net intercompany accounts (845,880) 124,239 721,641 -
---------------------------------------------------------------------
Net Cash Provided by Financing Activities 1,700,546 2,239 685,026 2,387,811
---------------------------------------------------------------------
Net (Decrease) in Cash and Cash Equivalents $ - $ - $ (45,273) $ (45,273)
Cash and Cash Equivalents at Beginning of Period - - 128,602 128,602
---------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ - $ - $ 83,329 $ 83,329
=====================================================================
137
Note 13. 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. Itemization of the purchase price is as follows:
- --------------------------------------------------------------
(In Thousands of Dollars)
- --------------------------------------------------------------
Eastern Enterprises Common Stock $ 1,754,400
EnergyNorth Common Stock 204,200
Transaction costs 10,200
Other 2,000
- --------------------------------------------------------------
Total Consideration $ 1,970,800
- --------------------------------------------------------------
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 allocation of the purchase price
to the assets and liabilities acquired from Eastern and ENI was as follows:
- --------------------------------------------------------------------------------------------------------
(In Thousands of Dollars) Eastern ENI Total
- --------------------------------------------------------------------------------------------------------
Gas Plant $ 599,900 $ 124,800 $ 724,700
Other Plant (non - regulated) 704,600 - 704,600
Investments and regulatory assets 82,100 - 82,100
Current assets 322,500 40,200 362,700
Other deferred charges 63,300 14,700 78,000
Current liabilities (333,400) (77,000) (410,400)
Other liabilities (498,000) (23,600) (521,600)
Long-term debt (502,100) (45,200) (547,300)
- --------------------------------------------------------------------------------------------------------
Net assets acquired* $ 438,900 $ 33,900 $ 472,800
Goodwill 1,325,600 172,400 1,498,000
- --------------------------------------------------------------------------------------------------------
Total purchase price $ 1,764,500 $ 206,300 $ 1,970,800
- --------------------------------------------------------------------------------------------------------
* Certain non-regulated long-term assets of Eastern were increased by
approximately $25 million to reflect the fair value of such assets at the date
of acquisition. Further, no intangible assets were acquired as part of this
transaction.
138
The following is the comparative unaudited proforma condensed financial
information for the year ended December 31, 2000. The proforma disclosures
reflect the results of the operations of Eastern and ENI as if our acquisitions
were consummated on January 1, 2000.
- --------------------------------------------------------------------------------
Year Ended
(In Thousands of Dollars, Except Per Share Amounts) December 31, 2000
- --------------------------------------------------------------------------------
Revenues $ 6,130,158
Operating Income $ 671,081
Net Income $ 114,393
Earnings Per Share $ 0.71
- --------------------------------------------------------------------------------
Included in the 2000 pro-forma 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, pro-forma earnings were
$1.27 per share for the year ended December 31, 2000. These pro-forma results
may not be indicative of future results. Further, the consolidated pro-forma
results for 2000 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 14. Workforce Reduction Programs
As a result of the Eastern and ENI acquisitions, we implemented early retirement
and severance programs in an effort to reduce our workforce. The early
retirement program was completed in December 2000, at which time KeySpan
recorded a charge of $51.4 million to reflect termination benefits related to
employees who voluntarily elected early retirement. In addition, KeySpan
recorded a $13.8 million liability associated with severance programs; Eastern
and ENI had previously recorded an additional liability of $8.9 million. The
combined liability, therefore, was $22.7 million. 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. During 2002, we paid $3.5 million for the program and, in total, $13.6
million was distributed to employees during the past two years. The remaining
liability of $5.0 million was reversed and recorded to earnings in 2002.
Note 15. 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.
139
Note 16. Subsequent Events
Subsequent to December 31, 2002, the following events ocurred:
On January 17, 2003, KeySpan sold 13.9 million shares of common stock in a
public offering. The offering generated net proceeds of approximately $473
million. All shares were offered by KeySpan pursuant to the effective shelf
registration statement filed with the SEC. Net proceeds from the sale were used
initially to pay down commercial paper.
On February 25, 2003 we terminated an interest rate swap agreement that had a
notional amount of $270 million and received $18.4 million from our swap
counter-parties of which $8.1 million represents accrued swap interest. The
difference between the termination settlement amount and the amount of accrued
swap interest, $10.3 million, will be recorded through earnings in the first
quarter of 2003. This swap was used to hedge a portion of our outstanding
promissory notes to LIPA. As discussed in Note 6 "Long-Term Debt", we intend to
redeem a portion of these promissory notes before the end of the first quarter
of 2003.
On February 26, 2003, we reduced our ownership interest in Houston Exploration
from 66% to approximately 56% following the repurchase, by Houston Exploration,
of 3 million shares of stock owned by KeySpan. The net proceeds of approximately
$79 million received in connection with this repurchase were used to pay down
commercial paper. Additionally there is an over-allotment option for 300,000
shares, which if exercised would further reduce our ownership in Houston
Exploration to 55%.
In connection with the class action lawsuit discussed in Note 7, regarding among
other things, alleged violations of Sections 10(b) and 20(a) of the Exchange
Act, on March 18, 2003 the court granted our motion to dismiss the complaint.
The court's order dismissed certain class allegations with prejudice but
provided the plaintiffs a final opportunity to file an amended complaint
concerning the remaining allegations. (Unaudited)
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, 2002. Shareholders
other than KeySpan had a minority interest of approximately 34% in Houston
Exploration at December 31, 2002, 33% in 2001 and 30% in 2000. Gas and oil
operations, and reserves, were located in the United States in all years.
140
Capitalized Costs Relating to Gas and Oil Producing Activities
- ---------------------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- ---------------------------------------------------------------------------------------------------------------------------------
At December 31, 2002 2001 2000
- ---------------------------------------------------------------------------------------------------------------------------------
Unproved properties not being amortized $ 110,623 $ 195,478 $ 166,479
Properties being amortized - productive and nonproductive 1,917,287 1,590,014 1,235,436
- ---------------------------------------------------------------------------------------------------------------------------------
Total capitalized costs 2,027,910 1,785,492 1,401,915
Accumulated depletion (968,713) (791,194) (617,628)
- ---------------------------------------------------------------------------------------------------------------------------------
Net capitalized costs $ 1,059,197 $ 994,298 $ 784,287
- ---------------------------------------------------------------------------------------------------------------------------------
Costs Incurred in Property Acquisition, Exploration and Development Activities
- -------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------------
At December 31, 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Acquisition of properties -
Unproved properties $ 14,600 $ 31,718 $ 7,992
Proved properties 90,004 85,435 40,960
Exploration 28,343 74,497 70,511
Development 139,108 191,927 111,078
- -------------------------------------------------------------------------------------------------------------------
Total costs incurred $ 272,055 $ 383,577 $ 230,541
- -------------------------------------------------------------------------------------------------------------------
Costs included in development costs to develop proved undeveloped reserves for
the years ended December 31, 2002, 2001 and 2000 were $11.0 million, $19.9
million and $9.7 million, respectively.
Results of Operations from Gas and Oil Producing Activities*
- --------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- --------------------------------------------------------------------------------------------------
At December 31, 2002 2001 2000
- --------------------------------------------------------------------------------------------------
Revenues $ 356,233 $ 396,734 $ 274,209
Production and lifting costs 44,822 37,574 33,508
Depletion 177,519 173,566 90,280
- --------------------------------------------------------------------------------------------------
Total expenses 222,341 211,140 123,788
- --------------------------------------------------------------------------------------------------
Income before taxes 133,892 185,594 150,421
Income taxes 45,836 64,118 51,767
- --------------------------------------------------------------------------------------------------
Results of operations $ 88,056 $ 121,476 $ 98,654
- --------------------------------------------------------------------------------------------------
* (Excluding corporate overhead and interest costs)
141
Summary of Production and Lifting Costs
- -----------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- -----------------------------------------------------------------------------------------------------
At December 31, 2002 2001 2000
- -----------------------------------------------------------------------------------------------------
Pumping, gauging and other labor $ 7,846 $ 5,342 $ 6,199
Compressors and other rental equipment 4,135 3,023 1,990
Property taxes and insurance 6,801 3,640 2,195
Transportation 2,131 3,162 3,430
Processing fees 3,078 2,267 622
Workover and well stimulation 2,348 1,478 3,310
Repairs, maintenance and supplies 2,972 2,204 2,177
Fuel and chemicals 2,582 1,424 818
Environmental, regulatory and other 3,307 3,639 3,010
Severance taxes 9,622 11,395 9,757
- -----------------------------------------------------------------------------------------------------
Total production and lifting costs $ 44,822 $ 37,574 $ 33,508
- -----------------------------------------------------------------------------------------------------
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 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, 2002 2001 2000
- ----------------------------------------------------------------------------------------------
Proved Reserves
Beginning of year 585,659 545,858 534,306
Revisions of previous estimates (15,324) (39,994) 4,479
Extensions and discoveries 105,798 86,401 77,645
Production (2,669) (90,754) (78,493)
Purchases of reserves in place 48,777 84,148 7,921
Sales of reserves in place (107,507) - -
- ----------------------------------------------------------------------------------------------
Proved reserves - End of year (1) 614,734 585,659 545,858
Proved developed reserves
Beginning of year 448,921 431,536 399,482
End of Year (2) 435,629 448,921 431,536
- ----------------------------------------------------------------------------------------------
(1) Includes minority interest of 208,516, 188,077, and 167,730 in 2002, 2001,
and 2000, respectively.
(2) Includes minority interest of 148,811, 148,593 and 133,271in 2002, 2001,
and 2000, respectively.
142
Crude Oil, Condensate and Natural Gas Liquids (MBbls)
- --------------------------------------------------------------------------------------------------
At December 31, 2002 2001 2000
- --------------------------------------------------------------------------------------------------
Proved reserves
Beginning of Year 10,234 7,912 3,136
Revisions of previous estimates 21 (289) 108
Extension and discoveries - 3,061 4,326
Production (166) (536) (320)
Purchases of reserves in place - 115 662
Sales of reserves in place (469) (29) -
- --------------------------------------------------------------------------------------------------
Proved reserves - End of year (1) 9,620 10,234 7,912
Proved developed reserves
Beginning of year 2,479 2,126 2,059
End of year (2) 2,413 2,479 2,126
- --------------------------------------------------------------------------------------------------
(1) Includes minority interest of 2,256, 2,186 and 1,695 in 2002, 2001, and
2000, respectively. (2) Includes minority interest of 824, 821 and 573 in 2002,
2001, and 2000, 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
- -----------------------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- -----------------------------------------------------------------------------------------------------------------------------------
At December 31, 2002 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
Future cash flows $ 2,951,622 $ 1,580,077 $ 5,415,587
Future costs-
Production (495,097) (316,421) (558,384)
Development (263,926) (227,158) (182,242)
- -----------------------------------------------------------------------------------------------------------------------------------
Future net inflows before income tax 2,192,599 1,036,498 4,674,961
Future income taxes (559,853) (221,324) (1,299,965)
- -----------------------------------------------------------------------------------------------------------------------------------
Future net cash flows 1,632,746 815,174 3,374,996
10% discount factor (528,829) (228,988) (1,209,237)
- -----------------------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows (1) $ 1,103,917 $ 586,186 $ 2,165,759
- -----------------------------------------------------------------------------------------------------------------------------------
(1) Includes minority interest of 361,435, 182,555 and 653,046 in 2002, 2001 and
2000, respectively
Costs included in future development costs related to proved undeveloped
reserves for the years ending December 31, 2003, 2004 and 2005 are $155.6
million, $38.2 million and $7.0 million, respectively.
143
Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserve Quantities
- -------------------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------------------------
At December 31, 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------------------
Standardized measure - beginning of year $ 586,186 $ 2,165,759 $ 480,632
Sales and transfers, net of production costs (285,603) (359,163) (240,702)
Net change in sales and transfer prices, net
of production costs 589,632 (2,250,252) 2,142,932
Extensions and discoveries and improved
recovery, net of related costs 242,055 117,326 472,658
Changes in estimated future development costs (6,453) (23,395) (38,839)
Development costs incurred during the period
that reduced future development costs 42,075 75,652 77,197
Revisions of quantity estimates (36,368) (52,928) 24,650
Accretion of discount 68,986 293,581 54,460
Net change in income taxes (215,369) 666,373 (706,074)
Net purchases of reserves in place 99,741 51,674 23,118
Sales of reserves in place (31,488) (133) -
Changes in production rates (timing) and other 50,523 (98,308) (124,273)
- -------------------------------------------------------------------------------------------------------------------------------
Standardized measure - end of year $ 1,103,917 $ 586,186 $ 2,165,759
- -------------------------------------------------------------------------------------------------------------------------------
Average Sales Prices and Production Costs Per Unit
- ---------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2002 2001 2000
- ---------------------------------------------------------------------------------------------------------------------
Average Sales Price*
Natural gas ($/Mcf) 3.16 4.09 3.97
Oil, condensate and natural gas liquid ($/Bbl) 24.06 23.09 27.29
Production cost per equivalent Mcf ($) 0.42 0.4 0.42
- ---------------------------------------------------------------------------------------------------------------------
*Represents the cash price received which excludes the effect of any hedging
transactions.
Acreage
- -------------------------------------------------------------------------------
At December 31, 2002 Gross Net
- -------------------------------------------------------------------------------
Producing 396,988 262,659
Undeveloped 267,666 228,428
- -------------------------------------------------------------------------------
Number of Producing Wells
- ------------------------------------------------------------------------------
At December 31, 2002 Gross Net
- ------------------------------------------------------------------------------
Gas wells 1,593.0 861.3
Oil wells 10.0 6.1
- ------------------------------------------------------------------------------
Drilling Activity (Net)
- --------------------------------------------------------------------------------------------------------------------------
At December 31, 2002 2001 2000
- --------------------------------------------------------------------------------------------------------------------------
Producing Dry Total Producing Dry Total Producing Dry Total
-------------------------------------------------------------------------------------------
Net developmental wells 65.1 9.4 74.5 51.9 10.2 62.1 40.4 4.4 44.8
Net exploratory wells 4.0 2.2 6.2 5.3 4.3 9.6 5.1 1.7 6.8
- --------------------------------------------------------------------------------------------------------------------------
144
Wells in Process
- --------------------------------------------------------------------------------
At December 31, 2002 Gross Net
- --------------------------------------------------------------------------------
Exploratory 5.0 2.8
Developmental 7.0 6.2
- --------------------------------------------------------------------------------
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, 2002.
Quarter Ended
- --------------------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars, Except Per Share Amounts) 3/31/02 6/30/02 9/30/02 12/31/02
- --------------------------------------------------------------------------------------------------------------------------------
Operating revenues 1,871,366 1,215,911 1,076,066 1,807,323
Earnings before interest charges and income taxes 406,063 112,272 86,230 319,683
Earnings from continuing operations 214,631 29,174 4,964 148,581
Loss from discountinued operations - (19,662) - -
Earnings for common stock 213,155 8,036 3,629 147,115
Basic earnings per common share from continuing operations
less preferred stock dividends (a) 1.52 0.20 0.03 1.03
Basic earnings per common share from discountinued
operations (a) - (0.14) - -
Basic earnings per common share (a) 1.52 0.06 0.03 1.03
Diluted earnings per common share (a) 1.51 0.06 0.02 1.03
Dividends declared 0.445 0.445 0.445 0.445
- --------------------------------------------------------------------------------------------------------------------------------
(a) Quarterly earnings per share are based on the average number of shares
outstanding during each quarter. Because of the changing number of common shares
outstanding in each quarter, the sum of quarterly earnings per share does not
necessarily 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, 2001.
Quarter Ended
- -----------------------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars, Except Per Share Amounts) 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 charges and income taxes 462,104 85,224 49,792 210,735
Earnings (loss) from continuing operations 224,114 (10,417) (37,427) 67,422
Earnings (loss) from discountinued 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 share from continuing operations
less preferred stock dividneds (d) 1.63 (0.09) (0.28) 0.48
Basic earnings per common share from discountinued operations (d) - 0.03 0.02 (0.19)
Basic earnings per common share (d) 1.63 (0.06) (0.26) 0.29
Diluted earnings per common share (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 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 each quarter. Because of the changing number of common shares
outstanding in each quarter, the sum of quarterly earnings per share does not
necessarily equal earnings per share for the year.
145
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors of KeySpan Corporation:
We have audited the accompanying Consolidated Balance Sheet of KeySpan
Corporation and subsidiaries (the Company) as of December 31, 2002, and the
related Consolidated Statements of Income, Retained Earnings, Comprehensive
Income, Capitalization, and Cash Flows for the year then ended. Our audit also
included the consolidated financial statement schedule, for the year ended
December 31, 2002, listed in the Index at Item 14 (a). These consolidated
financial statements and the consolidated financial statement schedule are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements and the consolidated
financial schedule based on our audit. The consolidated financial statements of
KeySpan Corporation for the years ended December 31, 2001 and 2000 were audited
by other auditors who have ceased operations. Their report, dated February 4,
2002, expressed an unqualified opinion on those statements.
We conducted our audit in accordance with auditing standards generally accepted
in the United States of America. 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 audit provides a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of the KeySpan Corporation and
subsidiaries as of December 31, 2002, and the results of their operations and
their cash flows for the year then ended in conformity with accounting
principles generally accepted in the United States of America. Also in our
opinion, such consolidated financial statement schedule, when considered in
relation to the basic consolidated financial statements taken as a whole,
presents fairly in all material respects, the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, on January 1,
2002, the Company adopted Statement of Financial Accounting Standards No. 142
"Goodwill and Other Intangible Assets," (SFAS No. 142) to change its method of
accounting for goodwill and other intangible assets.
146
As discussed above, the consolidated financial statements of the Company as of
December 31, 2001, and for the two years in the period then ended were audited
by other auditors who have ceased operations. The notes related to these
consolidated financial statements have been revised to include the transitional
disclosures required by SFAS No. 142, which was adopted by the Company as of
January 1, 2002. Our audit procedures with respect to the disclosures in Note 1
G for 2001 and 2000 included (i) agreeing the previously reported earnings for
common stockholders to the previously issued consolidated financial statements
and the adjustments to earnings for common stockholders representing
amortization expense recognized in those periods related to goodwill to the
Company's underlying records obtained from management, and (ii) testing the
mathematical accuracy of the reconciliation of adjusted net income to reported
earnings for common shareholders, and the related earnings-per-share amounts. In
addition, Note 12 has also been revised. Our auditing procedures with respect to
the disclosures in Note 12 for 2001 and 2000 included (i) agreeing the amounts
in the guarantor and other subsidiaries columns to underlying consolidating
records obtained from management, (ii) comparing the sum of these columns to the
previously issued consolidated financial statements, and (iii) testing the
mathematical accuracy of the schedule. In our opinion, the adjustments in Notes
1G and 12 are appropriate and have been properly applied. However, we were not
engaged to audit, review, or apply any procedures to the 2001 and 2000 financial
statements of the Company other than with respect to such adjustments and,
accordingly, we do not express an opinion or any other form of assurance on the
2001 and 2000 financial statements taken as a whole.
DELOITTE & TOUCHE LLP
February 10, 2003
(February 26, 2003, as to Note 16)
New York, New York
147
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
Readers of these consolidated financial statements should be aware that this
report is a copy of a previously issued Arthur Andersen LLP report and that this
report has not been reissued by Arthur Andersen LLP. Furthermore, this report
has not been updated since February 4, 2002 and Arthur Anersen LLP completed its
last post-audit review of the December 31, 2001, consolidated financial
information on April 29, 2002.
148
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
Arthur Andersen LLP ("Arthur Andersen") served as KeySpan's independent public
accountants since May 1998. On March 29, 2002, KeySpan's Board of Directors,
upon recommendation of the Audit Committee, determined not to renew the
engagement of Arthur Andersen and appointed Deloitte & Touche LLP ("Deloitte &
Touche") as independent public accountants. During the past two fiscal years
through March 29, 2002, there was no report on the financial statements of the
Company by either Deloitte & Touche or Arthur Andersen that contained an adverse
opinion or a disclaimer of opinion, or was qualified or modified as to
uncertainty, audit scope, or accounting principles. During the past two fiscal
years through March 29, 2002, there were no disagreements with either Deloitte &
Touche or Arthur Andersen on any matter of accounting principles or practices,
financial statement disclosure or auditing scope or procedure which, if not
resolved to the satisfaction of either Deloitte & Touche or Arthur Andersen,
would have caused the firm to make reference to the subject matter of such
disagreements in connection with their respective reports.
Part III
Item 10. Directors and Executive Officers of the Registrant
A definitive proxy statement will be filed with the SEC on or about March 26,
2003 (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 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.
149
Item 13. Certain Relationships and Related Transactions
The information required by this item is set forth under the caption "Agreements
with Executives," "Transactions with Management and Others" and "Involvement in
Certain Proceedings" in the Proxy Statement, which information is incorporated
by reference thereto.
Item 14. Controls and Procedures
(a) Evaluation of Disclosure Controls and Procedures
Within the 90 days prior to the date of this report, KeySpan carried out an
evaluation, under the supervision and with the participation of KeySpan's
management, including KeySpan's Chief Executive Officer and Chief Financial
Officer, of the effectiveness of the design and operation of KeySpan's
disclosure controls and procedures. KeySpan's disclosure controls and procedures
are designed to ensure that information required to be disclosed by KeySpan in
its periodic SEC filings is recorded, processed and reported within the time
periods specified in the SEC's rules and forms. Based upon that evaluation, the
Chief Executive Officer and Chief Financial Officer concluded that KeySpan's
disclosure controls and procedures are effective in timely alerting them to
material information relating to KeySpan (including its consolidated
subsidiaries) required to be included in KeySpan's periodic SEC filings.
(b) Changes In Internal Controls
There were no significant changes in KeySpan's internal controls or in other
factors that could significantly affect these controls subsequent to the date of
their evaluation.
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)
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:
o Consolidated Statement of Income for the year ended December 31, 2002, the
year ended December 31, 2001, and the year ended December 31, 2000
o Consolidated Statement of Retained Earnings for the year ended December 31,
2002, the year ended December 31, 2001, and the year ended December 31,
2000
o Consolidated Balance Sheet at December 31, 2002 and December 31, 2001 o
Consolidated Statement of Capitalization at December 31, 2002 and December
31, 2001
o Consolidated Statement of Cash Flows for the year ended December 31, 2002,
the year ended December 31, 2001, and the year ended December 31, 2000
o Consolidated Statement of Comprehensive Income for the Year ended December
31, 2002, the year ended December 31, 2001 and the year ended December 31,
2000
o Notes to Consolidated Financial Statements
o Report of Independent Public Accountants
2. Financial Statement Schedules
Consolidated Schedule of Valuation and Qualifying Accounts for the year ended
December 31, 2002, the year ended December 31, 2001, and the year ended December
31, 2000.
All other schedules are omitted because they are not applicable or the required
information is shown in the financial statements or notes thereto.
150
SCHEDULE OF VALUATION AND QUALIFYING ACCOUNTS
- -----------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
- -----------------------------------------------------------------------------------------------------------------------
Balance Charged to Balance at
at Beginning costs and Net End of
Decription Period expenses Acquisitions Deductions Period
- -----------------------------------------------------------------------------------------------------------------------
Twelve Months Ended December 31, 2002
- -----------------------------------------------
Deducted from asset accounts: $ 72,299 $ 58,939 $ - $ 68,209 $ 63,029
Allowance for doubtful accounts
Additions to liability accounts:
Reserve for injury and damages $ 20,880 $ 11,984 $ - $ 7,084 $ 25,780
Reserves for environmental expenditures $ 257,649 $ - $ - $ 25,503 $ 232,146
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 injury 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 injury and damages $ 36,385 $ 20,074 $ 3,362 $ 19,121 $ 40,700
Reserves for environmental expenditures $ 128,011 $ - $ 42,637 $ 13,141 $ 157,507
- -----------------------------------------------------------------------------------------------------------------------
151
(b) Reports on Form 8-K
In our report on Form 8-K dated October 24, 2002, we disclosed that we had
issued a press release concerning, among other things, our earnings for the
third quarter ended September 30, 2002.
In our report on Form 8-K dated December 12, 2002, we disclosed that we had
issued a press release concerning, among other things, 2003 earnings guidance.
In our report on Form 8-K dated January 13, 2003, we disclosed that we had
issued a press release announcing our proposed issuance of approximately
14,000,000 shares of common stock.
In our report on Form 8-K dated January 14, 2003, we disclosed that we had
issued a press release discussing the anticipated net proceeds from the offering
of common stock announced on January 13, 2003.
In our report on Form 8-K dated January 15, 2003, we disclosed that we had
issued a press release announcing that our proposed issuance of approximately
14,000,000 shares of common stock announced on January 13, 2003, would be
offered at variable prices.
In our report on Form 8-K dated January 28, 2003, we disclosed that we had
issued a press release concerning, among other things, our consolidated earnings
for the year ended December 31, 2002.
In our report on Form 8-K dated February 21, 2003, we disclosed that we had
issued a press release concerning, among other things, a proposed sale of a
portion of our ownership interest in The Houston Exploration Company.
(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 (filed as Exhibit 2 to the Company's Form 10-K for the
year ended December 31, 2001)
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 April 25, 2002, as amended (filed as
Exhibit 3.1 to the Company's Form 10-Q for the quarterly period ended March
31, 2002)
* Filed herewith
** Management Contract or Compensation Plan
152
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
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
KeySpan Gas East Corporation 7 7/8% notes issued 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
KeySpan Gas East Corporation 6.9% notes issued 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)
* Filed herewith
** Management Contract or Compensation Plan
153
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 Brooklyn Union Gas 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 Brooklyn Union Gas Company's Form 10-K for the year
ended September 30, 1997)
* Filed herewith
** Management Contract or Compensation Plan
154
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)
* Filed herewith
** Management Contract or Compensation Plan
155
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 June 1, 1986 between Essex Gas 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).
4.27 Twelfth Supplemental Indenture dated as of December 1, 1990, between
Essex Gas Company and Centerre Trust Company of St. Louis, Trustee,
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).
4.28 Fifteenth Supplemental Indenture dated as of December 1, 1996, between
Essex Gas Company and Centerre Trust Company of St. Louis, Trustee,
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).
4.29 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).
4.30-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).
4.30-b* Extension Agreement, dated as of November 20, 2002 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
* Filed herewith
** Management Contract or Compensation Plan
156
4.31 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))
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 Agreement of Lease between Forest City Jay Street Associates and The
Brooklyn Union Gas Company 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)
10.4-a 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)
10.4-b* Amendment dated as of March 29, 2002 to Management Services Agreement
between Long Island Lighting Company d/b/a LIPA and KeySpan Electric
Services LLC dated as of June 26, 1997
10.5 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)
10.6-a 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)
10.6-b* Amendment dated as of March 29, 2002 to Energy Management Agreement
between Long Island Lighting Company d/b/a LIPA and KeySpan Energy
Trading Services LLC dated as of June 26, 1997
10.7-a Generation Purchase Rights Agreement between Long Island Lighting
Company and Long Island Power Authority dated as of June 26, 1997
(filed as Exhibit 10.17 to the Company's Annual Report on Form 10-K
for the year ended December 31, 2001)
10.7-b Amendment dated as of March 29, 2002 to Generation Purchase Right
Agreement by and between KeySpan Corporation as Seller, and Long
Island Lighting Company d/b/a LIPA as Buyer, dated as of June 26, 1997
(filed as Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q
for the quarterly period ended March 31, 2002)
10.8** Employment Agreement dated September 10, 1998, between KeySpan and
Robert B. Catell (filed as Exhibit (10)(b) to the Company's Quarterly
Report on Form 10-Q for the quarterly period ended September 30, 1998)
10.9** First 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 Annual Report on
Form 10-K for the year ended December 31, 2000)
* Filed herewith
** Management Contract or Compensation Plan
157
10.10** Second Amendment dated as of June 26, 2002, to the Employment
Agreement dated September 10, 1998, between KeySpan and Robert B.
Catell (filed as Exhibit 10.1 to the Company's Quarterly Report on
Form 10-Q for the quarterly period ended September 30, 2002)
10.11* Supplemental Retirement Agreement dated January 1, 2002 between
KeySpan and Gerald Luterman
10.12* Supplemental Retirement Agreement dated January 1, 2002 between
KeySpan and Steven L. Zelkowitz
10.13* Supplemental Retirement Agreement dated January 1, 2002 between
KeySpan and David J. Manning
10.14* Supplemental Retirement Agreement dated January 1, 2002 between
KeySpan and Neil Nichols
10.15* Supplemental Retirement Agreement dated January 1, 2002 between
KeySpan and Elaine Weinstein
10.16** Amended Directors' Deferred Compensation Plan (filed as Exhibit 10.27
to the Company's Form 10-K for the year ended December 31, 2001)
10.17** * Officers' Deferred Stock Unit Plan of KeySpan Corporation
10.18** * Officers' Deferred Stock Unit Plan KeySpan Services, Inc.
10.19** 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)
10.20** 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)
10.21** KeySpan's Amended Long Term Performance Incentive Compensation Plan
(filed as Exhibit A to the Company's 2001 Proxy Statement on March 23,
2001)
10.22 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)
10.23 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)
10.24 Lease Agreement dated June 9, 1999, between KeySpan-Ravenswood, LLC
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)
10.25* First Amendment to the Lease between KeySpan-Ravenswood, LLC and LIC
Funding, Limited Partnership, dated as of June 27, 2002
10.26 Guaranty dated June 9, 1999, from 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)
10.27* Purchase Agreement by and among Duke Energy Gas Transmission
Corporation, Algonquin Energy, Inc., KeySpan LNG GP, LLC and KeySpan
LNG LP, dated as of December 12, 2002
* Filed herewith
** Management Contract or Compensation Plan
158
10.28 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)
10.29 Revolving Credit Facility between The Houston Exploration Company and
Wachovia Bank, National Association, as issuing bank and
administrative agent, Bank of Nova Scotia and Fleet National Bank as
co-syndication agents and BNP Paribas as documentation agent dated
July 15, 2002 (filed as Exhibit 10.1 to The Houston Exploration
Company's Quarterly Report on Form 10-Q for the quarter ended June 30,
2002, File No. 001-11899)
10.30-a Credit Agreement among KeySpan Energy Development Co. several Lenders
and the Royal Bank of Canada, as Agent, for $125,000,000 (Canadian)
Credit Facility, dated as of October 13, 2000 (filed as Exhibit 10.10
to the Company's Annual Report on Form 10-K for the year ended
December 31, 2001)
10.30-b Consent, Waiver and Amending Agreement among KeySpan Energy
Development Co., several Lenders and the Royal Bank of Canada, as
Agent, for the $125,000,000 (Canadian) Credit Facility, dated as of
December 22, 2000 (filed as Exhibit 10.11 to the Company's Annual
Report on Form 10-K for the year ended December 31, 2001)
10.30-c Second Amending Agreement among KeySpan Energy Development Co.,
several Lenders and the Royal Bank of Canada, as Agent, for the
$125,000,000 (Canadian) Credit Facility, dated as of October 12, 2001
(filed as Exhibit 10.12 to the Company's Annual Report on Form 10-K
for the year ended December 31, 2001)
10.30-d* Extendible Revolving Credit Facility Amended and Restated Credit
Agreement among KeySpan Energy Development Co., National Bank
Financial, ATB Financial and Certain Financial Institutions with
National Bank of Canada, dated as of January 24, 2003
10.31-a Credit Agreement among KeySpan Energy Development Co., Borrower, the
Several Lenders' and Royal Bank of Canada, Administrative Agent, dated
July 29, 1999 (filed as Exhibit 10.37-a to the Company's Annual Report
on Form 10-K for the year ended December 31, 2001)
10.31-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 (filed as Exhibit 10.37-b to the Company's Annual Report on Form
10-K for the year ended December 31, 2001)
10.31-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 (filed as Exhibit 10.37-c to the Company's Annual Report on Form
10-K for the year ended December 31, 2001)
10.31-d* Third Amending Agreement dated as of December 20, 2002 to the Credit
Agreement among KeySpan Energy Development Co., Borrower, the Several
Lenders' and Royal Bank of Canada, Administrative Agent dated July 29,
1999
10.32 Guarantee Agreement by KeySpan Corporation in favor of the Several
Lenders to KeySpan Energy Development Co. dated as of July 29, 1999
(filed as Exhibit 10.38 to the Company's Annual Report on Form 10-K
for the year ended December 31, 2001)
* Filed herewith
** Management Contract or Compensation Plan
159
10.33 Credit Agreement among KeySpan Corporation, the several Lenders, ABN
AMRO Bank, N.V. and Citibank, N.A., as Co-Syndication Agents, The Bank
of New York and The Royal Bank of Scotland PLC, as Co-Documentation
Agents, and J.P. Morgan Chase Bank, as Administrative Agent for $1.3
billion, dated as of July 9, 2002 (filed as Exhibit 4.1 to the
Company's Form 10-Q for the quarterly period ended June 30, 2002)
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 Deloitte & Touche 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 on March 6, 2003
24.2* Power of Attorney executed by Andrea S. Christensen on March 6, 2003
24.3* Power of Attorney executed by Donald H. Elliott on March 6, 2003
24.4* Power of Attorney executed by Alan H. Fishman on March 6, 2003
24.5* Power of Attorney executed by J. Atwood Ives on March 6, 2003
24.6* Power of Attorney executed by James R. Jones on March 6, 2003
24.7* Power of Attorney executed by James L. Larocca on March 6, 2003
24.8* Power of Attorney executed by Stephen W. McKessy on March 6, 2003
24.9* Power of Attorney executed by Edward D. Miller on March 6, 2003
24.10* Power of Attorney executed by Edward Travaglianti on March 6, 2003
24.11* Certified copy of the Resolution of the Board of Directors authorizing
signatures pursuant to power of attorney
* Filed herewith
** Management Contract or Compensation Plan
160
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
KEYSPAN CORPORATION
By:/s/ Robert B. Catell
--------------------
Robert B. Catell
Chairman of the Board of Directors and
Chief Executive Officer
By:/s/ Gerald Luterman
-------------------
Gerald Luterman
Executive Vice President and
Chief Financial Officer
161
CHIEF EXECUTIVE OFFICER'S CERTIFICATION
I, Robert B Catell, certify that:
1. I have reviewed this annual report on Form 10-K of KeySpan Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Securities Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
the registrant's board of directors (or persons performing the equivalent
function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officer and I have indicated in this annual
report whether there were significant changes in internal controls or in other
factors that could significantly affect internal controls subsequent to the date
of our most recent evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
Date: March 6, 2003 /s/ Robert B. Catell
------------------------------
Robert B. Catell
Chairman of the Board of Directors
and Chief Executive Officer
162
CHIEF FINANCIAL OFFICER'S CERTIFICATION
I, Gerald Luterman, certify that:
1. I have reviewed this annual report on Form 10-K of KeySpan Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Securities Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
the registrant's board of directors (or persons performing the equivalent
function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officer and I have indicated in this annual
report whether there were significant changes in internal controls or in other
factors that could significantly affect internal controls subsequent to the date
of our most recent evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
Date: March 6, 2003 /s/ Gerald Luterman
-----------------------------
Gerald Luterman
Executive Vice President
and Chief Financial Officer
163
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended,
this report has been signed by the following persons on behalf of the registrant
and in the capacities indicated.
*
- --------------------
Andrea S. Christensen Director
*
- --------------------
Donald H. Elliott Director
*
- --------------------
Alan H. Fishman Director
*
- --------------------
J. Atwood Ives Director
*
- --------------------
James R. Jones Director
*
- --------------------
James L. Larocca Director
*
- --------------------
Stephen W. McKessy Director
*
- --------------------
Edward D. Miller Director
*
- --------------------
Edward Travaglianti 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.
164