UNITED STATES
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 fiscal year ended December 31, 2003
Commission File Number 1-14161
KEYSPAN CORPORATION
(Exact name of registrant as specified in its charter)
NEW YORK 11-3431358
(State or other jurisdiction (I.R.S. employer identification no.)
of 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. X Yes __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. X
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act) X Yes __No
As of June 30, 2003, the aggregate market value of the common stock held by
non-affiliates (157,824,519 shares) of the registrant was $5,594,879,198 based
on the closing price of the New York Stock Exchange on such date, of $35.45 per
share. For purposes of this computation, all officers and directors of the
registrant are deemed to be affiliates.
As of March 1, 2004, there were 159,844,530 shares of common stock, $.01 par
value, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Proxy Statement dated on or about March 25, 2004 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...............................................................................................33
Item 3. Legal Proceedings........................................................................................34
Item 4. Submission of Matters to a Vote of Security Holders......................................................34
PART II
-------
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters....................................34
Item 6. Selected Financial Data..................................................................................36
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations....................37
Item 7A. Quantitative and Qualitative Disclosures About Market Risk...............................................85
Item 8. Financial Statements and Supplementary Data..............................................................87
Notes to the Consolidated Financial Statements...............................................................................93
Note 1. Summary of Significant Accounting Policies...............................................................93
Note 2. Business Segments.......................................................................................111
Note 3. Income Tax..............................................................................................115
Note 4. Postretirement Benefits.................................................................................117
Note 5. Capital Stock...........................................................................................122
Note 6. Long-Term Debt..........................................................................................123
Note 7. Contractual Obligations, Financial Guarantees and Contingencies.........................................129
Note 8. Hedging, Derivative Financial Instruments and Fair Values...............................................139
Note 9. Discontinued Operations.................................................................................144
Note 10. Roy Kay Operations......................................................................................145
Note 11. Class Action Settlement.................................................................................146
Note 12. KeySpan Gas East Corporation Summary Financial Data.....................................................146
Note 13. Workforce Reduction Programs............................................................................152
Note 14. Shareholder Rights Plan.................................................................................152
Note 15. Subsequent Events.......................................................................................153
Note 16. Supplemental Gas and Oil Disclosures (Unaudited)........................................................153
Note 17. Summary of Quarterly Information (Unaudited)............................................................158
INDEPENDENT AUDITORS' REPORT................................................................................................159
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS....................................................................................161
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure....................162
Item 9A. Controls and Procedures.................................................................................162
PART III
Item 10. Directors and Executive Officers of the Registrant......................................................162
Item 11. Executive Compensation..................................................................................163
Item 12. Security Ownership of Certain Beneficial Owners and Management..........................................163
Item 13. Certain Relationships and Related Transactions..........................................................163
Item 14. Principal Accounting Fees and Services..................................................................163
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K.........................................163
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, 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 generating capacity and, to the extent required,
energy conversion services for LIPA from our approximately 4,200 megawatts of
generating facilities located on Long Island; and manage fuel supplies for LIPA
to fuel our 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, as well as the 250 megawatt expansion unit at
Ravenswood expected to be completed within the next few months.
The Energy Services segment provides energy-related services to customers
primarily located within New York, New Jersey, Connecticut, Massachusetts, New
Hampshire, Rhode Island and Pennsylvania through various subsidiaries that
operate under the following principal two lines of business: (i) home energy
services; and (ii) business solutions.
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 pipeline
activities in the United Kingdom.
1
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 core businesses.
We also continue to explore the monetization of some or all of our non-core
assets in the Energy Investments segment.
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 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;
- - the resolution of certain disputes with LIPA concerning each party's rights
and obligations under various agreements;
- - retention of key personnel;
2
- - 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 and conduct operations;
- - 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
- - 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 the 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.
KeySpan has adopted a Code of Ethics applicable to its Chief Executive Officer
and Senior Financial Officers, and has revised its Ethical Business Conduct
Statement applicable to all directors, officers and employees of the Company in
each case as required by recently adopted rules and regulations.
KeySpan's Code of Ethics, Ethical Business Conduct Statement, Corporate
Governance Guidelines and Committee Charters can each be found on the Investor
Relations section of KeySpan's website (http://www.keyspanenergy.com) and
provide information on the framework and high standards set by the Company
relating to its corporate governance and business practices. Additionally, these
documents are available in print to any shareholder requesting a copy. The Code
of Ethics, Ethical Business Conduct Statement, Corporate Governance Guidelines
and Committee Charters have all been approved by the Board of Directors and are
vital to securing the confidence of KeySpan's shareholders, customers,
employees, governmental authorities and the investment community.
3
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 23,000 miles of gas mains and
distribution pipelines.
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.
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.
4
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 and
associated revenue taxes) 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. We utilize weather derivatives for KEDNE to mitigate
variations in firm net revenues due to fluctuations in weather.
For 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.
5
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 2,053 MDTH (one MDTH equals 1,000 DTH or 1 billion British Thermal
Units) of gas for a peak-day during the 2003/04 winter season and that the gas
available to us on such a peak-day amounts to approximately 2,076 MDTH. As of
January 20, 2004, the 2003/04 winter peak-day throughput to our New York
customers was 1,804 MDTH, which occurred on January 15, 2004 at an average
temperature of 7 degrees F, representing 87% of our peak-day capability. Our New
York firm gas peak-day capability is summarized in the following table:
Source MDTH per day % of Total
- ------------------------------------------- ------------------------- ------------------------
Pipeline 794 38%
Underground Storage 778 38%
Peaking Supplies 504 24%
--- ---
Total 2,076 100%
========================= ========================
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
2003/04 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 794 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, L.P. ("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 provided us with peak day capacity of
394 MDTH and winter season availability of 2,053 MDTH. The peaking supply
contracts with the five duel fuel power producers provided us with peak day
capacity of 110 MDTH and winter season availability of 3,349 MDTH.
6
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 which expires on March 31, 2006.
Gas Costs. 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 firm customers.
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 January 1, 2004, approximately 105,429 gas customers
on the New York Gas Distribution System are purchasing their gas from marketers.
However, net gas revenues are not significantly affected by customers opting to
purchase their gas supply from other sources since delivery rates charged to
transportation customers generally are the same as delivery rates charged to
sales service customers.
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, are available to
meet system requirements during the winter season.
Peak-Day Capability. The design criteria for our New England gas systems assumes
a level of 78 effective degree days for peak-day demand. Under such criteria,
KEDNE estimates that the requirements to supply their firm gas customers would
amount to approximately 1,281 MDTH of gas for a peak-day during the 2003/2004
winter season. The gas available to KEDNE on such peak-day amounts to 1,402
MDTH. KEDNE estimates an additional 105 MDTH of on-system throughput on behalf
of its transportation-only customers for a total peak day throughput estimate of
1,386 MDTH.
The highest daily throughput, which includes both firm sales and firm
transportation, to our New England customers was 1,421 MDTH, which occurred on
January 15, 2004 at a level of 80 effective degree days. The total throughput of
1,421 MDTH exceeded the design day throughput estimate by two and one half
percent (2.5%). KEDNE has sufficient gas supply available to meet the
requirements of their firm gas customers for the 2003/2004 winter season. The
firm gas supply peak day capability of KEDNE for its firm customers is
summarized in the following table:
7
MDTH per
Source day % of Total
- -------------------------------------------- ------------------------- -------------------------
Pipeline 486 35
- -------------------------------------------- ------------------------- -------------------------
Underground Storage 261 19
- -------------------------------------------- ------------------------- -------------------------
Peaking Supplies 655 47
--- --
- -------------------------------------------- ------------------------- -------------------------
Total 1402 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 747 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 23,280 MDTH and 261 MDTH per day of maximum deliverability.
Peaking Supplies. The KEDNE gas supply portfolio is supplemented with peaking
supplies that are available on the coldest days 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 2003/2004 winter season, on a
peak-day, KEDNE has access to 655 MDTH of peaking supplies, 47% of peak-day
supply.
Gas Supply Management. Since April 1, 2003 the New England based gas
distribution subsidiaries have been operating under a portfolio management
contract with Entergy Koch Trading, LP ("EKT"). EKT provides the majority of the
city gate supply requirements to the four New England gas distribution companies
(Boston Gas, Colonial Gas, Essex Gas and Energy North) at market prices and
manages upstream capacity, underground storage and supply contracts.
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.
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.
8
Electric Services Overview
We are the largest electric generator in New York State. Our subsidiaries own
and operate 5 large generating plants and 10 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 the
Ravenswood Generating Station located in Queens County, which is the largest
generating facility in New York City. Ravenswood is comprised of 3 large
steam-generating units and 17 gas turbine generators. A 250MW expansion at our
Ravenswood facility has been qualified to participate in the capicity market
adminstered by the New York Independent System Operator as of April 1, 2004 (the
"Ravenswood Expansion Project") and we operate and maintain a 55 MW gas turbine
unit in Greenport, Long Island under an agreement with Global Commons Greenport.
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 from the Long
Island units through a power supply agreement (the "PSA") and other long-term
agreements to provide LIPA with approximately two thirds of its customers energy
needs; 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").
We also purchase energy, capacity and ancillary services in the open market on
LIPA's behalf under 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."
Additional electric capacity and energy are supplied under power purchase
agreements with LIPA from four gas turbine units installed in 2002 at our
Glenwood and Port Jefferson sites. See Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operation - "Electric Services -
Revenue Mechanisms" for a further discussion of these matters.
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 a portion of 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 ("Master
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 instead conventional debt financing been employed. 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
9
original cost of the property, plus the present value of the lease payments that
would have otherwise been paid through June 20, 2009. KeySpan intends to extend
the Master Lease for the forseeable future. (See discussion concerning the
Financial Accounting Standards Board issued Interpretation No. 46 in Note 7 to
the Consolidated Financial Statements, "Contractual Obligations, Financial
Guarantees and Contingencies."
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. In addition,
KeySpan intends to enter into a sale/leaseback transaction to finance a
significant portion of the costs related to the Ravenswood Expansion Project.
For further details on this proposed transaction, see Note 15 to the
Consolidated Financial Statements - "Subsequent Events."
The New York State 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.
Forty-five of our seventy-seven generating units are dual fuel 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 MW, and we instituted a program to reduce
nitrogen oxides for improved environmental performance.
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 1,765
Northport, L.I. Steam Turbine Dual* 4 1,529
Port Jefferson, L.I. Steam Turbine Dual* 2 388
Glenwood, L.I. Steam Turbine Gas 2 232
Island Park, L.I. Steam Turbine Dual* 2 391
Far Rockaway, L.I. Steam Turbine Dual* 1 110
Long Island City GT Units Dual* 17 454
Throughout L.I. GT Units Gas 4 160
Throughout L.I. GT Units Dual* 12 311
Throughout L.I. GT Units Oil 30 1,093
-- -----
TOTAL 77 6,433
=========================================================================================================
*Dual - Oil (#2 oil, #6 residual oil) or kerosene, and natural gas.
10
In January 2002, we filed an application for approval with the New York State
Siting Board on Electric Generation and Environment ("Siting Board") for a 250
MW combined cycle plant in Melville, NY. 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, and
on May 8, 2003 the Siting Board issued the certificate. In 2003, we formed a
joint venture with American National Power, Inc. ("ANP") for the purpose of
jointly submitting a proposal in repsonse to a request for proposals by LIPA
for additional generating resources. The response proposed the construction of
two 250 MW plants, one at the Melville site and another at a site in the town of
Brookhaven in Long Island which also received a certificate from the Siting
Board. If successful in negotiating a power purchase agreement with LIPA, the
ANP joint venture will commence construction of the plant. Otherwise, we may
seek other opportunities to enter into a long-term agreement for the sale of
capacity, energy and ancillary services. In addition, as part of our growth
strategy, we continually evaluate the possible acquisition or development of
additional generating facilities in the Northeast. However, we are unable to
predict when or if such facilities will be acquired or constructed 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 (collectively, the "LIPA
Agreements"). Under the agreements and subsequent Power Purchase Agreements,
KeySpan provides: 4,214 MW of power generation capacity and energy conversion
services; operation, maintenance and capital improvement services for LIPA's
transmission and distribution system; and 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 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. A rate
filing reflecting the recalculated revenue requirement was submitted to FERC on
October 31, 2003 and on December 30, 2003, FERC issued an order accepting, in
part, the rates subject to refund pending settlement discussions and hearings.
We are unable to predict the outcome of those proceedings 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 2003, we earned
$4 million in incentives under the PSA.
11
The PSA runs for a term of 15 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 7 through 10 of the PSA, if LIPA
elects to ramp-down, we are entitled to receive payment for 100% of the present
value of the capacity charges otherwise payable over the remaining term of the
PSA. If LIPA ramps-down the generation capacity in years 11 through 15 of the
PSA, the capacity charges otherwise payable by LIPA will be reduced in
accordance with a formula established in the PSA. If LIPA exercises its
ramp-down option, KeySpan may use any capacity released by LIPA to bid on new
LIPA capacity requirements or to 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 2003, we earned $7.2 million in
non-cost performance incentives.
12
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.
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
2003, 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 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 for the terminus of a transmission
cable under Long Island Sound and other generating facilities.
13
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 relates 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. In addition, costs incurred
by KeySpan for liabilities for asbestos exposure arising from the activities of
the generating facilities previously owned by LILCO are recoverable from LIPA
through the Power Supply Agreement between LIPA and KeySpan.
For additional information concerning the Electric Services segment, see the
discussion in Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations - "Electric Services" contained herein.
Energy Services Overview
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 two lines of
business: (i) Home Energy Services, which provides residential customers with
installation, service and maintenance of energy systems and appliances, as well
as the retail marketing of electricity to commercial customers; and (ii)
Business Solutions, which provides plumbing, heating, ventilation, air
conditioning and mechanical services, as well as operation and maintenance,
design, engineering and consulting services to commercial and industrial
customers. On May 1, 2003, KeySpan's gas and electric marketing subsidiary,
KeySpan Energy Services, assigned a substantial portion of its retail natural
gas customers, consisting mostly of residential and small commercial customers,
to ECONnergy Energy Co., Inc. ("ECONnergy"). ECONnergy is one of the largest
deregulated energy service companies in the Northeast. KeySpan Energy Services
is continuing its electric marketing activities.
14
The Energy Services segment has more than 2,700 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, 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.
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 who,
among other things, have reviewed and continue to review and focus on our
overall strategy of these businesses.
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 pipeline
activities in the United Kingdom; and (v) certain other domestic energy-related
investments, such as the transportation by truck of liquid natural gas and new
fuel cell technologies.
Gas Exploration and Production
KeySpan is engaged in the exploration for 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 the current level
of approximately 55%. This reduction in our ownership interest is in line with
our strategy of monetizing or divesting certain non-core assets, which include
investment in oil and gas exploration and production assets. At March 1, 2004,
Houston Exploration's aggregate market capitalization was approximately $1.224
billion (based upon the closing price on the New York Stock Exchange on March 1,
2004 of $38.75 per share). At March 1, 2004, Houston Exploration had
approximately 31,587,637 shares of common stock, $0.01 par value, outstanding.
15
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.
Our gas exploration and production subsidiaries focus their operations offshore
in the Gulf of Mexico and onshore in South Texas, South Louisiana, the Arkoma
Basin, East Texas and West Virginia. The geographic focus of these operations
enables our subsidiaries to manage a comparatively large asset base with
relatively few employees and to add and operate production at relatively low
incremental costs. Our gas exploration and production subsidiaries seek to
balance their offshore and onshore activities so that the lower risk and more
stable production typically associated with onshore properties complement the
high potential exploratory projects in the Gulf of Mexico by balancing risk and
reducing volatility. Houston Exploration's business strategy is to seek to
continue to increase reserves, production and cash flow by pursuing internally
generated prospects, primarily in the Gulf of Mexico, by conducting development
and exploratory drilling on our offshore and onshore properties and by making
selective opportune acquisitions.
Offshore Properties. 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 2003. We have a total of 37 platforms
and production caissons 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,
16
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 412-mile pipeline that currently transports 1236
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. Applications for all necessary
regulatory authorizations were filed in 2000 and 2001. To date, Islander East
has received a final certificate from the Federal Energy Regulatory Commission
("FERC") and all necessary permits from the State of New York. However, the
State of Connecticut has denied Islander East's application for a coastal zone
management permit and a permit under Section 401 of the Clean Water Act.
Islander East has reinstated its appeal of the State of Connecticut's
determination on the coastal zone management issue to the United States
Department of Commerce and is evaluating its legal and other options with
respect to the Section 401 issue. Once in service, the pipeline is expected to
transport up to 260,000 DTH daily to the Long Island and New York City energy
markets, enough natural gas to heat 600,000 homes. The pipeline will also allow
KeySpan to diversify the geographic sources of its gas supply. However, we are
unable to predict when or if all regulatory approvals required to construct this
pipeline will be obtained. Various options for the financing of pipeline
construction are currently being evaluated. At December 31, 2003, total
expenditures associated with the siting and permitting of the Islander East
pipeline were $14.9 million.
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. 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 FERC. In a joint initiative
with BG LNG Services, KeySpan plans to upgrade the KeySpan LNG facility to
accept marine deliverables and to triple vaporization (or regasification
capacity). Pending regulatory approvals, the facility could be ready to accept
marine deliverables by late 2005.
17
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
and, therefore, we will continue to pursue these opportunities.
Midstream Natural Gas Processing Activities in Canada
During the year, we sold 39.09% of our interest in KeySpan Canada, a company
with natural gas processing plants and gathering facilities located in Western
Canada. In February 2004, we entered into an agreement to sell an additional
35.91% of our interest in KeySpan Canada. Following the closing of this
additional sale of our interest, currently scheduled for early April 2004, we
will own 25% of KeySpan Canada. 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, we sold our 20% interest in Taylor NGL LP that owns and operates
two extraction plants also in Canada, one located in British Columbia, and one
in Alberta, Canada. We consider our Canadian operations to be non-core assets
and we continue to evaluate 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, 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. KeySpan considers this a non-core asset and is evaluating the possible
divestiture or monetization. In December, 2003, the company sold its interest in
Phoenix Natural Gas Limited, a gas distribution system serving the City of
Belfast, Northern Ireland.
For additional information concerning the Energy Investments segment, see the
discussion on "Energy Investments" in Item 7, Management's Discussion and
Analysis of Financial Condition and Results of Operations contained herein.
Environmental Matters Overview
KeySpan's ordinary business operations subject it to regulation in accordance
with various federal, state and local laws, rules and regulations dealing with
the environment, including air, water, and hazardous substances. These
requirements govern both our normal, ongoing operations and the remediation of
impacted properties historically used in utility operations. Potential liability
associated with our historical operations may be imposed without regard to
fault, even if the activities were lawful at the time they occurred.
Except as set forth below, or in Note 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 existing 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
18
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 in accordance with the terms of our rate recovery agreements for each
regulated subsidiary.
Air. The Federal Clean Air Act ("CAA") provides for the regulation of a variety
of air emissions from new and existing electric generating plants. Final permits
in accordance with the requirements of Title V of the 1990 amendments to the CAA
have been issued for all of our electric generating facilities, with the
exception of two 79 MW simple cycle gas turbine units which were constructed in
2002. These units currently are permitted under New York State Facility permits
and Title V permits have been timely applied for and are pending issuance by the
NYSDEC. Renewal applications have been submitted in a timely manner for 13
existing facilities whose initial permits will expire in 2004. The permits and
timely renewal applications 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 Transport 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, II, and
III of the OTC memorandum in a cost-effective manner. We have achieved and
expect to continue to achieve such emission reductions in a cost-effective
manner through the use of low NOX combustion control systems, the use of natural
gas fuel and/or the purchases of allowances when necessary. Capital expenditures
were incurred between $10 million and $15 million for combustion control systems
and natural gas fuel capability additions over the last several years enhance
compliance options.
In 2003, New York State promulgated regulations which will establish separate
NOX and SO2 emission reduction requirements on electric generating facilities in
New York State beginning in late 2004. KeySpan's facilities are expected to
comply with the NOX requirements without material additional expenditures
because of previously installed emissions control equipment. SO2 compliance is
expected to require a reduction in the sulfur content of the fuel oil used in
our Northport and Port Jefferson facilities. Based on current projections,
higher incremental fuel costs at these facilities will be approximately $10
million per year, and, contractually, are the obligation of LIPA in accordance
with the terms of the PPA.
In December 2003, the United States Environmental Protection Agency ("USEPA")
issued draft regulations that would require reductions of mercury and nickel as
well as further reductions of NOX and SO2 from electric generating facilities on
a national basis. The proposed mercury regulations would have no impact on
KeySpan facilities since their application is limited to coal-fired plants. The
proposed nickel, NOX and SO2 reduction requirements, if finalized as drafted,
could require additional expenditures for emission control systems or greater
use of natural gas in order to facilitate compliance. Until these regulations
are finalized, the nature and extent of the financial impact on KeySpan, if any,
cannot be determined.
19
In 2003, the Governor of New York initiated a Regional Greenhouse Gas Initiative
that seeks to establish a coordinated multistate plan to reduce greenhouse gas
emissions (primarily carbon dioxide) from electric generating emission sources
in the Northeast. Several congressional initiatives are also under consideration
that may also require greenhouse gas reductions from electric generating
facilities nationwide. At the present time, it is not possible to predict the
nature of the requirements, which ultimately will be imposed on KeySpan nor
what, if any, financial impact such requirements would have on KeySpan
facilities. However, our investments in emissions control technology and
conversions to natural gas capability have resulted in a 15% reduction in carbon
dioxide emissions over the last decade, while the electric generation industry
as a whole increased carbon dioxide emissions by 26%. The addition of the
efficient, combined cycle unit at Ravenswood will further reduce emission rates
when it commences commercial operations in 2004.
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 nature and cost of
equipment upgrades 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
even before Superfund was enacted 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 or its
predecessors and other potentially responsible parties were allegedly disposed.
Normally the costs associated with such claims are allocated among the
potentially responsible parties on a pro rata basis. The cost of these claims is
not presently determinable. Superfund does, however, provide for joint and
several liability against a single potentially responsible party. In the
unlikely event that Superfund claims were pursued against us on that basis, the
costs, 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."
20
Competition, Regulation and Rate Matters
Competition. Over the last several years, the natural gas and electric
industries 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 in 1998 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."
Ravenswood, the merchant plant in our Electric Services segment, is subject to
competitive and other risks that could adversely impact the market price for the
plant's output. Such risks include, but are not limited to, the construction of
new generation or transmission capacity serving the New York City market.
However, we cannot predict when or if new generation or transmission capacity
will be built.
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. Each of the federal and state
regulators also regulates certain transactions among our affiliates. 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.
21
State Utility Commissions. Our regulated utility subsidiaries are subject to
regulation by the NYPSC, DTE and NHPUC. The NYPSC regulates KEDNY and KEDLI.
Although KeySpan Corporation is not regulated by the NYPSC, it is impacted by
conditions that were included in the NYPSC order authorizing the 1998
KeySpan/LILCO transaction. Those conditions address, among other things, 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
electricity are also subject to regulation by the NYPSC. 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. 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. A rate filing reflecting a recalculated
revenue requirement was submitted to FERC on October 31, 2003. On December 30,
2003, FERC issued an order accepting, in part, the rates subject to refund
pending settlement discussions and hearings. We are unable to predict the
outcome of those proceedings at this time. Our Ravenswood facility's rates are
based on a market-based rate application approved by FERC. The rates that our
Ravenswood facility may charge are subject to mitigation measures due to market
power concerns of FERC. The mitigation measures are administered by the NYISO.
FERC retains the ability in future proceedings, either on its own motion or upon
a complaint filed with FERC, to modify the Ravenswood facility's rates, as well
as the mitigation measures, if FERC concludes that it is in the public interest
to do so.
KeySpan currently offers 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."
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 FERC. Our interests in Iroquois,
Honeoye, Steuben and KeySpan LNG are also fully regulated by FERC as natural gas
companies.
22
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 and to pay dividends to our
shareholders. 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.
In addition, in November 2000, KeySpan received authorization from the SEC to
operate three mutual service companies. Under this order, the SEC determined
that, in accordance with PUHCA, KeySpan Corporate Services LLC ("KCS"), KeySpan
Utility Services LLC ("KUS") and KeySpan Engineering & Survey, Inc. ("KENG") may
operate to provide various services to KeySpan subsidiaries, including regulated
utility companies, at cost fairly and equitably allocated among them.
Foreign Regulation. KeySpan's foreign operations in Northern Ireland, conducted
through Premier, 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).
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. 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
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 NYPSC
orders, the ability of KEDNY and 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
23
a customer service performance program. At the end of KEDNY's and KEDLI's
rate years (September 30, 2003 and November 30, 2003, respectively), their
ratios of debt to total utility capitalization were well in compliance with
the ratios set forth above.
PUHCA Also Limits Our Business Operations and Our Ability to Affiliate with
Other Utilities
In addition to limiting our financial activities, PUHCA 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 April 2003, the SEC determined that the companies that comprise our
Energy Services business are "energy-related companies" and therefore
retainable under existing SEC precedent. However, the SEC also required
that certain of those companies increase the percentage of their work that
is energy related.
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. A significant portion 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 in rates, and the uncertainty of whether regulatory
commissions will allow full recovery of and return on such increased costs
and expenses.
Various rulemaking proposals and market design revisions related to the
wholesale power market are being reviewed at the federal level. These
proposals, as well as 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, 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 FERC's price mitigation measures are subject to
rehearing and possible judicial review.
24
Our Risk Mitigation Techniques Such as Hedging and Purchase of Insurance May Not
Adequately Provide Protection
To mitigate our financial exposure related to commodity price fluctuations,
KeySpan routinely enters 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.
In addition, our business is subject to many hazards from which our
insurance may not adequately provide coverage. An 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 55%
equity interest in The Houston Exploration Company and our ownership of
KeySpan 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.
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 increases due to
colder weather conditions. As a result, we are subject to seasonal
variations in working capital because we purchase natural gas supplies for
storage in the second and third quarters and must 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
25
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 extreme temperature conditions. As a result,
fluctuations in weather between years may have a significant effect on our
results of operations for these subsidiaries. The construction activities
of our Energy Services subsidiaries are also affected by weather.
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 the GPRA, 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 (all Long Island units except for the 80MW facility
at Port Jefferson and the 80MW facility in Glenwood). 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 Assurance Can Be Made that These Arrangements Will Be Renewed at the End
of their Terms or that the Resolution of Certain Disputes Will Not Materially
Impact the Financial Condition of the Company
We derive a substantial portion of our revenues in our electric services
segment from a number 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, the terms and
conditions thereof. In addition, given the complexity of these
arrangements, disputes arise from time to time between the Company and LIPA
concerning the rights and obligations of each party to make and receive
payments as required pursuant to the terms of these agreements. As a
result, the Company is unable to determine what effect, if any, the
ultimate resolution of these disputes will have on its financial condition
or results of operations.
We Own Approximately 55% of Houston Exploration and Our Results of Operation are
Therefore Subject to the Risks Affecting its Business
We own approximately 55% of Houston Exploration. 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.
26
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.
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 credit rating agencies that rate our debt securities regularly review
our financial condition and results of operations. We can provide no
assurances that the ratings or outlook on our debt securities will not be
reduced or otherwise negatively changed. A negative change in the ratings
or outlook on our debt 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 utility subsidiaries' rate plans generally allow for
the full recovery of the costs of investigation and remediation of most of
27
our 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 quantities 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
write-downs of the carrying value of those businesses.
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.
Employee Matters
As of December 31, 2003, KeySpan and its wholly-owned subsidiaries had
approximately 11,300 employees. Of that total, approximately 5,800 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.
28
Prior to their expiration in February, KeySpan reached tentative agreements with
IBEW Locals 1049 and 1381 on new collective bargaining agreements. These Unions
represent KeySpan employees in physical and clerical positions respectively, and
serve our Long Island customers. The new four-year agreements are expected to be
ratified by each respective union before the end of March 2004.
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 67, 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.
Mr. Catell also serves on the Board of Directors for Houston Exploration.
Robert J. Fani
Mr. Fani, age 50, was elected President and Chief Operating Officer of KeySpan
in October 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 for Strategic Services in February
2000 and then to President of the KeySpan Energy Services and Supply Group in
2001. In January 2003, he was named President of KeySpan's Energy Assets and
Supply Group until assuming his current position in October 2003. Mr. Fani also
serves on the Board of Directors for Houston Exploration.
Wallace P. Parker Jr.
Mr. Parker, age 54, was elected President of the KeySpan Energy Delivery and
Customer Relations Group in January 2003. He also serves as Vice Chairman and
Chief Executive Officer of KeySpan Services, Inc. since October 2003. He had
previously served as President, KeySpan Energy Delivery, since June 2001, and
from February 2000 served as Executive Vice President of Gas Operations. 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.
29
Steven L. Zelkowitz
Mr. Zelkowitz, age 54, was elected President of KeySpan's Energy Assets and
Supply Group in October 2003. Prior to that, he served as Executive Vice
President & Chief Administrative Officer since January 2003. 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. In July
2001, Mr. Zelkowitz was promoted to Executive Vice President and General
Counsel, and in November 2002, he was named Executive Vice President,
Administration & Compliance, with responsibility for the offices of General
Counsel, Human Resources, Regulatory Affairs, Enterprise Risk Management and
administratively for Internal Auditing. Before joining the Company, Mr.
Zelkowitz practiced law with Cullen and Dykman LLP in Brooklyn, New York,
specializing in energy and utility law and had been a partner since 1984. He
served on the firm's Executive Committee and was head of its Corporate/Energy
Department.
John A. Caroselli
Mr. Caroselli, age 49, was elected Executive Vice President and Chief Strategy
Officer in January 2003. Mr. Caroselli is responsible for Brand Management,
Strategic Marketing, Strategic Planning, Strategic Performance, Human Resources,
and Information Technology. Mr. Caroselli came to KeySpan in 2001 and at that
time served as Executive Vice President of Strategic 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.
Gerald Luterman
Mr. Luterman, age 60, 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. Mr. Luterman
also serves on the Board of Directors for Houston Exploration.
Anthony Nozzolillo
Mr. Nozzolillo, age 55, 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.
30
Lenore F. Puleo
Ms. Puleo, age 50, was elected Executive Vice President of Shared Services in
March 2004. She previously served as Executive Vice President of Client Services
since February 2000. Prior to that she 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 45, was elected Executive Vice President, KeySpan
Corporation, and President, KeySpan Energy Delivery New England, in April 2002.
Prior to that, 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 Company. Before joining
Boston Gas, he was Executive Vice President and Chief Financial Officer for
Colonial Gas Company. 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. Mr. Stavropoulos was also a director of Colonial Gas Company.
John J. Bishar, Jr.
Mr. Bishar, age 54, became Senior Vice President, General Counsel and Secretary
on May 8, 2003, with responsibility for the Legal Services Business Unit and the
Corporate Secretary's Office. Prior to that, he joined KeySpan as Senior Vice
President and General Counsel on November 1, 2002. 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 56, was elected Senior Vice President, Regulatory Affairs and
Chief Accounting Officer on April 1, 2003. Prior to his appointment, he served
as Senior Vice President of Finance Operations and Regulatory Affairs since
August 2001 and 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 Company 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.
31
John F. Haran
Mr. Haran, age 53, was elected Senior Vice President of KeySpan Energy Delivery
and Chief Gas Engineer in March 2004. He had been Senior Vice President of gas
operations for KEDNY and KEDLI in since 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 53, was elected Senior Vice President for Corporate Affairs 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 66, 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. He is also a member of the Board or Directors for Houston
Exploration Company and KeySpan Facilities Income Fund. 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.
Michael J. Taunton
Mr. Taunton, age 48, was named Senior Vice President and Treasurer in March
2004. He had 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.
32
Colin P. Watson
Mr. Watson, age 52, 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. In support of New York City's bid to host the 2012 Olympic
games, KeySpan has provided NYC2012 with the expertise and guidance of Mr.
Watson on a full-time basis.
Elaine Weinstein
Ms. Weinstein, age 57, was named Senior Vice President and Chief Diversity
Officer in March 2004. She had served as Senior Vice President of KeySpan's
Human Resources division since November 2000. She previously served as Vice
President of Staffing and Organizational Development since September 1998. Prior
to that time, Ms. Weinstein was General Manager of Employee Development since
joining KeySpan in 1995. Prior to 1995, Ms. Weinstein was Vice President of
Training and Organizational Development at Merrill Lynch.
Lawrence S. Dryer
Mr. Dryer, 44, was elected Vice President and General Auditor in June 2003. He
previously served in this position from September 1998 to August 2001. In August
2001, he was named Senior Vice President and Chief Financial Officer of KeySpan
Services, Inc. Prior to such positions, Mr. Dryer had been with LILCO from 1992
to 1998 as Director of Internal Audit. Prior to joining LILCO, Mr. Dryer was an
Audit Manager with Coopers & Lybrand.
Theresa Balog
Ms. Balog, age 42, was named Vice President and Controller of KeySpan in April
2003. She joined KeySpan in 2002 as Assistant Controller. Prior to joining
KeySpan, Ms. Balog was Chief Accounting Officer for NiSource and held a variety
of positions with the Columbia Energy Group.
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
33
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.
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, 2003.
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, 2004, there
were approximately 75,070 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:
2003 High Low Dividends Per Share
-------------------------------------------------------------------------------------------------------
First Quarter $38.14 $31.02 $0.445
Second Quarter $37.51 $31.87 $0.445
Third Quarter $35.83 $32.30 $0.445
Fourth Quarter $37.09 $33.64 $0.445
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
34
EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth securities authorized for issuance under equity
compensation plans for the year ended December 31, 2003:
Number of securities
Number of securities remaining available for
to be issued upon Weighted-average future issuance under
exercise of outstanding exercise price of equity compensation plans
options, warrants and outstanding options, (excluding securities
Stock Plan category rights warrants and rights reflected in column (a))
- --------------------------------- --------------------------- ----------------------------------- ----------------------------------
(a) (b) (c)
Equity compensation plans
approved by security holders
Stock Options 10,320,743 $31.39 6,783,675
Restricted Stock 84,318 N/A
Performance Shares 186,708 N/A
Equity compensation plans
not approved by security
holders N/A N/A N/A
Total 10,591,769 $31.39 6,783,675(1)
(1) Includes grants of options, restricted stock, and performance shares
pursuant to KeySpan's Long-Term Incentive Compensation Plan, as amended,
and options granted pursuant to the Brooklyn Union Long-Term Incentive
Compensation Plan and options granted pursuant to the Eastern Enterprises
1995 Stock Option Plan and the Eastern Enterprises 1996 Non-Employee
Trustee's Stock Option Plan, as well as 328,000 shares of Common Stock
issued pursuant to the Stock Plan.
35
Item 6. Selected Financial Data
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars, Except Per Share Amounts) 2003 2002 2001 2000 1999
-------------------------------------------------------------------------------
Income Summary
Revenues
Gas Distribution $ 4,161,272 $ 3,163,761 $ 3,613,551 $ 2,555,785 $ 1,753,132
Electric Services 1,503,086 1,421,043 1,421,079 1,444,711 861,582
Energy Services 641,432 938,761 1,100,167 770,110 186,529
Energy Investments and other 609,371 447,101 498,318 310,096 153,370
-------------------------------------------------------------------------------
Total revenues 6,915,161 5,970,666 6,633,115 5,080,702 2,954,613
-------------------------------------------------------------------------------
Operating expenses
Purchased gas for resale 2,495,102 1,653,273 2,171,113 1,408,680 744,432
Fuel and purchased power 414,633 395,860 538,532 460,841 17,252
Operations and maintenance 2,005,796 2,101,897 2,114,759 1,659,736 1,091,166
Depreciation, depletion and amortization 574,074 514,613 559,138 330,922 253,440
Early retirement and severance charges - - 65,175 -
Operating taxes 418,236 381,767 448,924 421,936 366,154
-------------------------------------------------------------------------------
Total operating expenses 5,907,841 5,047,410 5,832,466 4,347,290 2,472,444
-------------------------------------------------------------------------------
Gain on sale of property 15,123 4,730 - - -
Income from equity investments 19,214 14,096 13,129 20,010 15,347
-------------------------------------------------------------------------------
Operating income 1,041,657 942,082 813,778 753,422 497,516
Other deductions (340,165) (301,253) (359,393) (233,410) (102,543)
Income taxes 277,311 243,479 210,693 217,262 136,362
-------------------------------------------------------------------------------
Earnings from continuing operations 424,181 397,350 243,692 302,750 258,611
-------------------------------------------------------------------------------
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) -
Cumulative change in accounting principles (37,451) - - - -
-------------------------------------------------------------------------------
Net income 386,730 377,688 224,254 300,807 258,611
Preferred stock dividend requirements 5,844 5,753 5,904 18,113 34,752
-------------------------------------------------------------------------------
Earnings for common stock $ 380,886 $ 371,935 $ 218,350 $ 282,694 $ 223,859
===============================================================================
Financial Summary
Earnings per share ($) 2.41 2.63 1.58 2.10 1.62
Cash dividends declared per share ($) 1.78 1.78 1.78 1.78 1.78
Book value per share, year-end ($) 22.94 20.67 20.73 20.65 20.26
Market value per share, year-end ($) 36.80 35.24 34.65 42.38 23.19
Shareholders, year-end 75,067 78,281 82,300 86,900 90,500
Capital expenditures ($) 1,011,716 1,061,022 1,059,759 925,257 725,670
Total assets ($) 14,626,784 12,980,050 11,789,606 11,307,465 6,730,691
Common shareholders' equity ($) 3,661,948 2,944,592 2,890,602 2,815,816 2,712,325
Redeemable preferred stock ($) - - - - 363,000
Preferred stock ($) 83,568 83,849 84,077 84,205 84,339
Long-term debt ($) 5,611,432 5,224,081 4,697,649 4,116,441 1,682,702
Total capitalization ($) 9,356,948 8,252,522 7,672,328 7,016,462 4,479,366
- -----------------------------------------------------------------------------------------------------------------------------------
36
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; underground gas storage; liquefied
natural gas storage; wholesale and retail electric marketing; appliance service;
plumbing, heating, ventilation, air conditioning and other mechanical services;
large energy-system ownership, installation and management; fiber optic
services; and engineering and consulting 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 to the Consolidated Financial Statements "Business
Segments" for additional information on each operating segment.)
Consolidated Summary of Results
Operating income 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) 2003 2002 2001
- -----------------------------------------------------------------------------------------------------------
Gas Distribution $ 574,254 $ 531,134 $ 481,393
Electric Services 268,977 288,796 269,721
Energy Services (38,066) (11,935) (147,485)
Energy Investments 238,554 142,594 178,783
Eliminations and other (2,062) (8,507) 31,366
-----------------------------------------------
Operating Income 1,041,657 942,082 813,778
Interest charges (307,694) (301,504) (353,470)
Other Income and (deductions) (32,471) 251 (5,923)
Income taxes (277,311) (243,479) (210,693)
-----------------------------------------------
Income from Continuing Operations 424,181 397,350 243,692
Cumulative change in accounting principles (37,451) - -
Loss from discontinued operations - (19,662) (19,438)
-----------------------------------------------
Net Income 386,730 377,688 224,254
Preferred stock dividend requirements 5,844 5,753 5,904
-----------------------------------------------
Earnings for Common Stock $ 380,886 $ 371,935 $ 218,350
===============================================
Basic Earnings per Share:
Continuing operations, less preferred stock dividends $ 2.64 $ 2.77 $ 1.72
Change in accounting principles (0.23) - -
Discontinued operations - (0.14) (0.14)
- --------------------------------------------------------------------------------------------------------
$ 2.41 $ 2.63 $ 1.58
- --------------------------------------------------------------------------------------------------------
37
Operating income in 2003 increased $99.6 million, or 11% compared to 2002. This
increase in operating income reflects higher earnings from the Energy
Investments and Gas Distribution segments, somewhat offset by decreases in
earnings from the Electric Services and Energy Services segments. The Energy
Investment segment benefited from higher earnings associated with gas
exploration and production activities as a result of significantly higher
realized gas prices and higher production volumes. The Gas Distribution segment
benefited from colder weather during the January through March 2003 heating
season compared to the same period last year, as well as from load growth.
Further, during 2003 we recorded $15.1 million in gains from property sales,
primarily 550 acres of real property located on Long Island. The Energy Services
group of companies were adversely impacted by the decline in construction
industry activity in the Northeastern United States during most of the year.
Lower results from the Electric Services segment were attributable to higher
operating costs, as well as lower revenues from our merchant generating
facility, due in part to cooler summer weather. (See the discussion under the
caption "Review of Operating Segments" for further details on each segment.)
Interest charges increased 2% in 2003, compared to last year, primarily as a
result of the termination of certain interest-rate derivative swap instruments
that were in effect in 2002. (See Note 8 to the Consolidated Financial
Statements "Hedging, Derivative Financial Instruments and Fair Values.")
Other income and (deductions) reflects a number of significant items that
impacted comparative results. During 2003, we monetized a portion of our
Canadian and Northern Ireland investments, as well as a portion of our ownership
interest in The Houston Exploration Company ("Houston Exploration"), our gas
exploration and production subsidiary. During the year, we sold 39.09% of our
interest in KeySpan Canada through an income trust fund. KeySpan Canada has
natural gas processing plants and gathering facilities in Western Canada.
Additionally, we sold our 20% interest in Taylor NGL LP that owns and operates
two extraction plants also located in Canada. We recorded a pre-tax loss of
$30.3 million ($34.1 million after-tax, or $0.22 per share) associated with
these sales. Further, in February 2004 we entered into an agreement to sell an
additional 36% of our interest in KeySpan Canada. (See Note 15 to the
Consolidated Financial Statements "Subsequent Events.") In the fourth quarter of
2003, we completed the sale of our 24.5% interest in Phoenix Natural Gas,
located in Northern Ireland, and recorded a pre-tax gain of $24.7 million, $16.0
million after-tax, or $0.10 per share.
Additionally in 2003, we reduced our ownership interest in Houston Exploration
from 66% to approximately 55% following the repurchase, by Houston Exploration,
of three million shares of common stock owned by KeySpan. We recorded a gain of
$19.0 million on this transaction. Income taxes were not provided on this
transaction since the transaction was structured as a return of capital.
In total, KeySpan recorded a pre-tax gain of $13.4 million from the monetization
of certain non-core assets. The after-tax gain from these three asset sales,
however, was minimal due to the different tax treatment associated with each
transaction.
38
Also in 2003, we called approximately $447 million of outstanding promissory
notes that were issued to LIPA in connection with the KeySpan/Long Island
Lighting Company ("LILCO") business combination completed in May 1998, and
recorded debt redemption charges of $18.2 million in other income and
(deductions). Further, Houston Exploration incurred costs of $5.9 million to
retire $100 million of 8.625% Notes due 2008.
Other income and (deductions) also reflects severance tax refunds totaling $21.6
million recorded by Houston Exploration for severance taxes paid in 2002 and
earlier periods, compared to $9.1 million recorded in 2002, as well as $6.5
million of realized foreign currency translation gains. Finally, other income
and (deductions) reflects minority interest adjustments related to Houston
Exploration and KeySpan Canada, as well as carrying charges on certain
regulatory assets.
The increase in income tax expense in 2003 compared to 2002 generally reflects a
higher level of pre-tax earnings. Further income tax expense for 2003 and 2002
includes a number of items impacting comparative results. During 2003, the
partial monetization of our Canadian investments resulted in tax expense of $3.8
million, reflecting certain United States partnership tax rules. In addition, we
recorded an adjustment to income tax expense of $6.1 million due to the state of
Massachusetts disallowing the carry forward of net operating losses incurred by
regulated utilities. Offsetting, to some extent, these increases to tax expense,
was a tax benefit recorded in 2003 of $9.0 million associated with certain New
York City general corporation tax issues. In addition, certain costs associated
with employee deferred compensation plans were deducted for federal income tax
purposes in 2003. These costs, however, are not expensed for "book" purposes
resulting in a beneficial permanent book-to-tax difference of $6.3 million.
Income tax expense for 2002 reflects a tax benefit of $15 million as a result of
the favorable resolution of certain outstanding tax issues related to the
KeySpan/LILCO merger. Additionally, we recorded an adjustment to deferred income
taxes of $177.7 million reflecting a decrease in the tax basis of the assets
acquired at the time of the merger. This adjustment was a result of a revised
valuation study. Concurrent with the deferred tax adjustment, we reduced current
income taxes payable by $183.2 million, resulting in a $5.5 million income tax
benefit. Also, it should be noted that pre-tax income in the Consolidated
Statement of Income reflects minority interest adjustments, whereas income taxes
reflect the full amount of subsidiary taxes.
In January 2002, KeySpan announced that it had entered into an agreement to sell
Midland Enterprises LLC ("Midland"), its marine barge business. During the
fourth quarter of 2001, in anticipation of this divestiture, which closed on
July 2, 2002, an estimated loss on the sale of Midland was recorded as
discontinued operations, as well as an estimate for Midland's results of
operations for the first nine months of 2002. In the second quarter of 2002, we
recorded an additional after-tax loss of $19.7 million, primarily reflecting a
provision for certain city and state taxes that resulted from a change in our
tax structuring strategy.
In January 2003, the Financial Accounting Standards Board ("FASB") issued
Financial Interpretation Number 46 ("FIN 46"), "Consolidation of Variable
Interest Entities, an Interpretation of ARB No. 51"; FIN 46 requires
consolidation of variable interest entities. KeySpan has an arrangement with a
variable interest entity through which we lease a portion of the 2,200-megawatt
Ravenswood electric generating facility ("Ravenswood facility"). Based upon
39
KeySpan's current status as the primary beneficiary, we were required to
consolidate the variable interest entity as of December 31, 2003. As a result of
implementing FIN 46, we recognized a non-cash, after-tax charge of $37.6
million, or $0.23 per share related to "catch-up" depreciation of the facility
since its acquisition in June 1999 and recorded the charge as a cumulative
change in accounting principle. (See Note 7 to the Consolidated Financial
Statements "Contractual Obligations, Financial Guarantees and Contingencies" for
an explanation of the leasing arrangement for the Ravenswood facility, as well
as an explanation of the implementation of FIN 46.)
As a result of the above mentioned items, income from continuing operations,
less preferred stock dividends, increased $26.7 million, or 7% in 2003 compared
to 2002. Earnings per share from continuing operations, however, decreased by
$0.13 per share, reflecting the issuance of 13.9 million shares of common stock
on January 17, 2003, as well as the re-issuance of shares held in treasury
pursuant to dividend reinvestment and employee benefit plans. The increase in
average common shares outstanding reduced 2003 earnings per share by $0.32
compared to 2002. Comparative earnings available for common stock, which
includes the cumulative change in accounting principle recorded in 2003, as well
as the loss on discontinued operations recorded in 2002, increased $9.0 million
in 2003 compared to 2002. Earnings per share, however, decreased by $0.22 per
share reflecting the higher level of common stock outstanding in 2003.
KeySpan's earnings for 2003 were forecasted to be approximately $2.45 to $2.60
per share, including the effect of the equity issuance in January 2003 and
excluding special items. Earnings from continuing core operations (defined for
this purpose as all continuing operations other than exploration and production,
less preferred stock dividends) were forecasted to be approximately $2.15 to
$2.20 per share, while earnings from exploration and production operations were
forecasted to be approximately $0.30 to $0.40 per share. Actual 2003 earnings
from continuing core operations, as defined, were $2.16 per share, while
earnings from exploration and production operations were $0.48 per share.
Operating income for the year ended December 31, 2002, increased $128.3 million
compared to the same period in 2001. The increase in operating income primarily
reflects the following two significant events that are discussed in more detail
below: (i) the discontinuance of goodwill amortization in 2002; and (ii) the
recording of special items in 2001 which resulted in the recognition of certain
gains and losses. These benefits to comparative operating income were offset, in
part, by a decrease in natural gas prices, particularly during the first quarter
of 2002, which reduced earnings associated with gas exploration and production
operations. Further, the impact of extremely warm weather during the first
quarter of 2002 adversely impacted natural gas consumption by gas distribution
customers and operating income in the Gas Distribution segment. (See "Review of
Operating Segments" for a detailed discussion of operating income for each of
KeySpan's lines of business.)
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.
40
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 $137.8
million in pre-tax operating losses attributed to the former Roy Kay companies
($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, as well
as 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, pre-tax 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 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 $52.0 million 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% in 2001. 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
reflects the reversal of $11.5 million in accrued interest expense resulting
from the RICO class action settlement, as noted previously.
Income tax expense generally reflects the level of pre-tax income in 2002 and
2001. However, as noted above, during 2002 we finalized the valuation study
related to the assets transferred to KeySpan resulting from the KeySpan/LILCO
business combination completed in May 1998. As a result of an adjustment to
deferred taxes and current income taxes payable, KeySpan recognized a $5.5
million income tax benefit. Income tax expense for 2002 also reflects additional
tax benefits of approximately $15 million resulting from the finalization of
amended tax returns and the reversal of certain tax reserves.
As a result of the above mentioned items, income from continuing operations,
less preferred stock dividends, increased $153.8 million in 2002 compared to
2001; earnings per share from continuing operations increased $1.05 per share.
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.
41
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.
Financial Outlook for 2004
KeySpan's consolidated earnings for 2004 are forecasted to be in the range of
$2.55 to $2.75 per share, excluding special items. Earnings from continuing core
operations (defined for this purpose as all continuing operations other than
exploration and production, less preferred stock dividends) are forecasted to be
in the range of $2.20 to $2.30 per share, while earnings from exploration and
production operations are forecasted to be in the range of $0.35 to $0.45 per
share.
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.
Review of Operating Segments
- ----------------------------
In response to new disclosure regulations adopted by the Securities and Exchange
Commission ("SEC") as part of its implementation of the Sarbanes-Oxley Act of
2002 - specifically Regulation G, which became effective March 2003 - we are
reporting all of KeySpan's segment results on an Operating Income basis for
2003, 2002 and 2001. Management believes that this generally accepted accounting
principle ("GAAP") based measure provides a reasonable indication of KeySpan's
underlying performance associated with its operations. The following is a
discussion of financial results achieved by KeySpan's operating segments
presented on an Operating Income basis.
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.
42
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) 2003 2002 2001
- ------------------------------------------------------------------------------------------------------------------------
Revenues $ 4,161,272 $ 3,163,761 $ 3,613,551
Cost of gas 2,444,485 1,569,325 2,017,782
Revenue taxes 90,456 83,066 119,084
- ------------------------------------------------------------------------------------------------------------------------
Net Gas Revenues 1,626,331 1,511,370 1,476,685
- ------------------------------------------------------------------------------------------------------------------------
Operating Expenses
Operations and maintenance 659,932 608,266 593,341
Depreciation and amortization 259,934 237,186 253,523
Operating taxes 147,334 135,687 148,428
- ------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 1,067,200 981,139 995,292
- ------------------------------------------------------------------------------------------------------------------------
Gain on the sale of property 15,123 903 -
Operating Income $ 574,254 $ 531,134 $ 481,393
- ------------------------------------------------------------------------------------------------------------------------
Firm gas sales and transportation (MDTH) 328,073 284,281 283,081
Transportation - Electric Generation (MDTH) 34,778 64,173 64,578
Other Sales (MDTH) 158,722 209,002 188,037
Warmer (Colder) than Normal - New York & Long Island (8.0%) 7.0% 10.0%
Warmer (Colder) than Normal - New England (10.0%) 4.0% 4.6%
- ------------------------------------------------------------------------------------------------------------------------
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
Net gas revenues (revenues less the cost of gas and associated revenue taxes)
from our gas distribution operations increased by $115.0 million, or 8%, for the
year ended December 31, 2003, compared to last year. Both our New York and New
England based gas distribution operations benefited from the significantly
colder than normal weather experienced throughout the Northeastern United
States, particularly during the primary winter heating months, January through
March, when our gas distribution operations realize over 60% of their yearly
operating income. As measured in heating degree-days, weather during the first
quarter of 2003 was approximately 10% colder than normal in our New York and New
England service territories. This contrasts with the extremely warm weather
experienced during the first quarter of 2002 when weather was approximately 16%
- - 18% warmer than normal. On a twelve month basis, weather was approximately 8%
- - 10% colder than normal in 2003 compared to 4% - 7% warmer than normal in 2002.
Net gas revenues from firm gas customers (residential, commercial and industrial
customers) in our New York service territories increased by $56.4 million, or
6%, for the twelve months ended December 31, 2003, compared to the same period
last year. Customer additions and oil-to-gas conversions, net of attrition and
conservation, added approximately $22 million to net revenues during 2003. The
effect of higher customer consumption in 2003 due primarily to colder than
43
normal weather, coupled with lower customer consumption in 2002 due to the
extremely warmer than normal weather resulted in a comparative increase to firm
net revenues of approximately $41.1 million in 2003 compared to 2002. However,
KEDNY and KEDLI each operate under a utility tariff that contains a weather
normalization adjustment that significantly offsets variations in firm net
revenues due to fluctuations from normal weather. These tariff provisions
resulted in a $20.4 million refund to firm gas customers during 2003. Also
included in net revenues are regulatory incentives that reduced comparative net
revenues by $2.1 million and recovery of certain taxes that added $15.8 million
to net revenues during 2003. The recovery of taxes through revenues, however,
does not impact net income since we expense a similar amount as amortization
charges and income taxes, as appropriate, on the Consolidated Statement of
Income.
Net gas revenues from firm gas customers in our New England service territories
increased $31.7 million, or 7%, for the year ended December 31, 2003, compared
to the same period last year. Customer additions and oil-to-gas conversions, net
of attrition and conservation, added approximately $13.5 million to net
revenues. As with our New York service territories, higher customer consumption
in 2003 due to the colder than normal weather, coupled with lower customer
consumption in 2002 due to the warmer than normal weather, resulted in an
increase in comparative net revenues for our New England based gas distribution
utilities of approximately $25.1 million in 2003 compared to 2002. The gas
distribution operations of our New England based subsidiaries do not have a
weather normalization adjustment. To mitigate the effect of fluctuations from
normal weather patterns on KEDNE's results of operations and cash flows, weather
derivatives were put in place for the 2002/2003 and 2003/2004 winter heating
seasons. Since weather during the first quarter of 2003 was 10% colder than
normal in the New England service territories, we recorded an $11.9 million
reduction to revenues to reflect the loss on these derivative transactions.
Similarly, in 2002 we recorded a $3.3 million reduction to revenues. As a result
of these transactions, comparative net revenues were adversely impacted by $8.6
million. Weather derivatives had only a marginal impact on net revenues during
the fourth quarter of 2003, since weather was approximately normal. (See Note 8
to the Consolidated Financial Statements "Hedging, Derivative Financial
Instruments and Fair Values" for further information).
Also included in net revenues for 2003 are $5.6 million of base-rate adjustments
resulting from Boston Gas Company's recently concluded rate case. Further,
included in net revenues for 2002, was a benefit of $3.9 million as a result of
a favorable ruling from the Massachusetts Supreme Judicial Court relating to the
appeal by Boston Gas Company of its Performance Based Rate Plan ("PBR"). The net
effect of these base-rate adjustments was a favorable impact to comparative net
revenues in 2003 of $1.7 million. (See "Regulation and Rate Matters" for a
further discussion of these matters.)
Firm gas distribution rates for KEDNY and KEDLI in 2003, other than for the
recovery of gas costs, have remained substantially unchanged from rates charged
last year. As noted, firm gas distribution rates for KEDNE reflect an increase
of $5.6 million resulting from The Boston Gas Company's rate order, which became
effective November 1, 2003.
44
In our large-volume heating and other interruptible (non-firm) markets, which
include large apartment houses, government buildings and schools, gas service is
provided under rates that are designed to compete with prices of alternative
fuel, including No. 2 and No. 6 grade heating oil. Net revenues from sales to
these markets increased by $26.8 million during the twelve months ended December
31, 2003, compared to the same period last year. The majority of interruptible
profits earned by KEDNE and KEDLI are returned to firm customers as an offset to
gas costs.
During 2002, combined net gas revenues from our gas distribution operations
increased by $34.7 million, or 2% compared to 2001. 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. Weather during
the primary heating seasons, January through March, was approximately 16%-18%
warmer than normal, across our service territories.
Net revenues from firm gas customers in our New York service territories
increased $13.6 million, or 1%, in 2002 compared to 2001. Included in net
revenues are regulatory incentives and recovery of certain taxes that added $1.8
million and $20.1 million to net revenues during 2002, respectively. As
mentioned previously, the recovery of taxes through revenues does not impact net
income. Excluding both the regulatory incentives and tax recoveries, comparative
net revenues decreased $8.3 million. During 2002, our New York based gas
distribution utilities added approximately $40 million in gross gas load
additions through oil-to-gas conversions, as well as from new construction.
Further, as mentioned, KEDNY and KEDLI each operate under utility tariffs that
contain a weather normalization adjustment. These tariff provisions resulted in
an increase to net gas revenues of $22.3 million in 2002. However the benefits
from load additions and the weather normalization adjustment 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 adversely impacted gas
consumption in 2002.
Net revenues from firm gas customers in the New England service territories
increased by $20.5 million, or 5%, in 2002 compared to 2001, primarily as a
result of approximately $24 million in gross load additions. Also included in
net revenues are base rate adjustments totaling $10.0 million associated with
Boston Gas Company's 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 were 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 adversely impacted gas consumption in 2002.
As mentioned previously, the New England-based gas distribution subsidiaries do
not have weather normalization adjustments. To lessen, to some extent, the
effect of fluctuations from normal weather patterns on KEDNE's results of
operations and cash flows, weather derivatives were in place for the 2002/2003
winter heating season. Since weather during the fourth quarter of 2002 was 7%
45
colder than normal in the New England service territories, 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, remained
substantially unchanged from 2001 in all of our service territories.
Net revenues from sales in the large-volume heating and other interruptible
(non-firm) markets were consistent between 2002 and 2001.
We are committed to our expansion strategy initiated during the past few years.
We believe that significant growth opportunities exist on Long Island and in our
New England service territories. We estimate that on Long Island approximately
36% of the residential and multi-family markets, and approximately 58% of the
commercial market currently use natural gas for space heating. Further, we
estimate that in our New England service territories approximately 53% of the
residential and multi-family markets, and approximately 63% of the commercial
market, currently use natural gas for space heating purposes. We will continue
to seek growth in all our market segments, through the economic expansion of our
gas distribution system, as well as through the conversion of residential homes
from oil-to-gas for space heating purposes and the pursuit of opportunities to
grow the multi-family, industrial and commercial markets.
Firm Sales, Transportation and Other Quantities
Total actual firm gas sales and transportation quantities increased by 15%
during the year ended December 31, 2003, compared to the same period in 2002. In
the New York service territories actual firm sales increased 17%, while firm
sales in the New England service territories increased 13%. Weather normalized
sales quantities increased 6% in the New York service territories and 3% in the
New England service territories. The increases in both actual and weather
normalized gas sale quantities reflect higher customer consumption as a result
of the significantly colder than normal weather in 2003, as well as from
customer additions and oil-to-gas conversions for space heating purposes.
Further, as mentioned previously, gas sales quantities in 2002 were adversely
impacted by the exceptionally warm weather.
In 2002, total actual firm gas sales and transportation quantities remained
consistent with 2001. In the New York service territories, actual and weather
normalized firm gas sales and transportation quantities decreased slightly in
2002 compared to 2001, due to the exceptionally warm 2002 weather. However, in
the New England services territories, firm gas sales and transportation
quantities increased 4%, despite the warm first quarter weather, due to load
additions.
Net revenues are not affected by customers opting to purchase their gas supply
from other sources, since delivery rates charged to transportation customers
generally are the same as delivery rates charged to sales service customers.
Transportation quantities related to electric generation reflect the
transportation of gas to our electric generating facilities located on Long
Island. Net revenues from these services are not material.
46
Other sales quantities include on-system interruptible quantities, off-system
sales quantities (sales made to customers outside of our service territories)
and related transportation. We have an agreement with Coral Resources, L.P.
("Coral"), a subsidiary of Shell Oil Company, under which Coral assists in the
origination, structuring, valuation and execution of energy-related transactions
on behalf of KEDNY and KEDLI. We also have a portfolio management contract with
Entergy Koch Trading, LP ("EKT"), under which EKT provides all of the city gate
supply requirements at market prices and manages certain upstream capacity,
underground storage and term supply contracts for KEDNE. These agreements expire
on March 31, 2006.
Purchased Gas for Resale
The increase in gas costs for the year ended December 31, 2003 compared to the
same period in 2002 of $875.2 million, or 56%, reflects an increase of 39% in
the price per dekatherm of gas purchased, and a 15% increase in the quantity of
gas purchased. 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, partially offset by a 1.0% increase in the quantity of gas purchased.
The current gas rate structure of each of our gas distribution utilities
includes a purchased gas adjustment clause, pursuant to which variations between
actual gas costs incurred for resale to firm sales customers and gas costs
billed to firm sales customers are deferred and refunded to or collected from
customers in a subsequent period.
Operating Expenses
Operating expenses in 2003 increased $86.1 million, or 9%, compared to last
year. This increase is primarily attributable to higher pension and other
postretirement benefit costs, which have increased (net of amounts deferred and
subject to regulatory true-ups) by $30.9 million during 2003. The cost of these
benefits has risen primarily as a result of lower actual returns on plan assets,
as well as increased health care costs. Further, the colder weather experienced
during 2003 resulted in a higher level of repair and maintenance work on our gas
distribution infrastructure which increased comparative operating expenses by
approximately $15 million.
Higher depreciation and amortization expense reflects the continued expansion of
the gas distribution system. Further, included in depreciation and amortization
expense is the amortization of certain property taxes previously deferred and
currently being recovered in revenues. Comparative operating taxes reflect a
favorable $9.9 million adjustment recorded during 2002 relating to the reversal
of excess tax reserves established for the KeySpan/LILCO combination in May
1998.
Operating expenses decreased by $14.2 million in 2002 compared to 2001.
Comparative operating expenses were significantly impacted by the
discontinuation of goodwill amortization. As mentioned earlier, in January 2002,
we adopted 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 $21.4 million, or 2%, in 2002 compared to 2001.
47
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. Further, depreciation and amortization expense,
excluding the 2001 goodwill amortization, increased as a result of the continued
expansion of the gas distribution system.
Offsetting, to some extent, these increases to operating expenses is the
favorable $9.9 million adjustment to operating taxes recorded in 2002 related to
the reversal of certain operating tax reserves established for the KeySpan/LILCO
combination as previously noted. Further, we realized 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.
Sale of Property
During 2003 we recorded $15.1 million in gains from property sales, primarily
550 acres of real property located on Long Island.
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. Cost efficient 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 to optimize the
long-term growth opportunities in our service territories.
In order to serve the anticipated market requirements in our New York service
territories, KeySpan and Duke Energy Corporation formed Islander East Pipeline
Company, LLC ("Islander East") in 2000. Islander East is owned 50% by KeySpan
and 50% by Duke Energy, and was created to pursue the authorization and
construction of an interstate pipeline from Connecticut, across Long Island
Sound, to a terminus near Northport, Long Island. Applications for all necessary
regulatory authorizations were filed in 2000 and 2001. To date, Islander East
has received a final certificate from the Federal Energy Regulatory Commission
("FERC") and all necessary permits from the State of New York. However, the
State of Connecticut has denied Islander East's application for a coastal zone
management permit and a permit under Section 401 of the Clean Water Act.
Islander East has reinstated its appeal of the State of Connecticut's
determination on the coastal zone management issue to the United States
Department of Commerce and is evaluating its legal and other options with
respect to the Section 401 issue. Once in service, the pipeline is expected to
transport up to 260,000 DTH daily to the Long Island and New York City energy
markets, enough natural gas to heat 600,000 homes. The pipeline will also allow
KeySpan to diversify the geographic sources of its gas supply. However, we are
unable to predict when or if all regulatory approvals required to construct this
pipeline will be obtained. Various options for the financing of pipeline
construction are currently being evaluated. At December 31, 2003, total
expenditures associated with the siting and permitting of the Islander East
pipeline were $14.9 million.
48
Electric Services
The Electric Services segment primarily consists of subsidiaries that own and
operate oil and gas fired electric generating plants in the New York City
Borough of Queens (the "Ravenswood facility") and the counties of Nassau and
Suffolk on Long Island and on the Rockaway Peninsula in Queens. 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) 2003 2002 2001
- --------------------------------------------------------------------------------------------------
Revenues $ 1,503,187 $ 1,421,143 $ 1,421,179
Purchased fuel 371,134 272,873 281,398
- --------------------------------------------------------------------------------------------------
Net Revenues 1,132,053 1,148,270 1,139,781
- --------------------------------------------------------------------------------------------------
Operating Expenses
Operations and maintenance 650,649 659,882 662,083
Depreciation 66,843 61,377 52,284
Operating taxes 145,584 139,694 155,693
- --------------------------------------------------------------------------------------------------
Total Operating Expenses 863,076 860,953 870,060
- --------------------------------------------------------------------------------------------------
Gain on the sale of property - 1,479 -
Operating Income $ 268,977 $ 288,796 $ 269,721
- --------------------------------------------------------------------------------------------------
Electric sales (MWH)* 4,743,029 4,998,111 4,932,836
Capacity(MW)* 2,200 2,200 2,200
Cooling degree days 1,010 1,384 1,381
- --------------------------------------------------------------------------------------------------
*Reflects the operations of the Ravenswood facility only.
Net Revenues
Total electric net revenues decreased $16.2 million, or 1% for the year ended
December 31, 2003 compared to the same period in 2002.
Net revenues from the Ravenswood facility were $3.1 million lower in 2003
compared to 2002. Comparative net revenues reflect higher capacity revenues of
$31.5 million, offset by a decrease in energy margins of $34.6 million. The
increase in capacity revenues reflects an increase in the level of capacity
sold, as well as an increase in the selling price of capacity. Such increases
are the result of two measures. First, in 2002, the New York Independent System
Operator ("NYISO") employed a revised methodology to assess the available supply
of and demand for installed capacity. This revised methodology resulted in
insufficient capacity being procured by the market, which caused a reliability
concern. Further, the revised methodology resulted in lower capacity volume sold
into the NYISO and depressed capacity pricing during the year ended December 31,
2002. The NYISO, however, recognized a calculation flaw in its revised
49
methodology, and prior to the 2002/2003 winter season capacity auction,
corrected the calculation methodology to ensure that sufficient capacity is
procured. Elimination of the flaw ensured compliance with New York State
reliability rules and resulted in higher capacity revenue realized at the
Ravenswood facility in 2003 compared to the prior year.
In addition, on May 20, 2003, the Federal Energy Regulatory Commission ("FERC")
approved the NYISO's revised capacity market procurement design with an
effective date of May 21, 2003. This revised capacity market procurement design
is based on a demand curve rather than relying on deficiency auctions to procure
necessary capacity. The deficiency auction with its associated fixed minimum
capacity requirements was replaced with a spot market auction that pays
gradually declining prices as additional capacity is offered and gradually
increasing prices as capacity offers decrease. This new market design recognizes
the value of capacity in excess of the minimum requirement and reduces price
spikes during periods of shortage. Essentially, the demand curve design
eliminates the high and low cycles inherent in the deficiency auction market
design. This new market design also established seasonal electric generator
specific price caps. Price caps establish the maximum price per megawatt ("MW")
that capacity can be sold into the NYISO by divested electric generators like
Ravenswood. Prior to this design change, one price cap was established for the
entire year and was effective for all electric generators. For the Ravenswood
facility, its 2003 summer price cap was higher than the yearly price cap
effective during the 2002 summer. As a result of these market design changes,
the Ravenswood facility realized higher capacity revenues during 2003 compared
to 2002. It should be noted, however, that Ravenswood's 2003/2004 structured
winter price cap will be lower than the yearly price cap effective during the
2002/2003 winter, which was prior to the implementation of the new demand curve
methodology.
The decrease in comparative energy margins in 2003 primarily reflects
significantly cooler weather during the summer of 2003 compared to the summer of
2002. Measured in cooling degree-days, weather for 2003 was 27% cooler than last
year. The cooler weather resulted in lower realized "spark-spreads" (the selling
price of electricity less cost of fuel, plus hedging gains or losses), as well
as a reduction in megawatt hours sold into the NYISO. Further, more competitive
behavior by market participants that bid into the NYISO, as well as certain
price mitigation measures imposed by the FERC (as discussed below) have resulted
in lower comparative realized "spark-spreads." Energy sales quantities during a
portion of 2003 were also adversely impacted by the scheduled major overhaul of
our largest generating unit.
We employ derivative financial hedging instruments to hedge the cash flow
variability for a portion of forecasted purchases of natural gas and fuel oil
consumed at the Ravenswood facility. Further, we have engaged in the use of
derivative financial hedging instruments to hedge the cash flow variability
associated with a portion of forecasted peak electric energy sales from the
Ravenswood facility. These derivative instruments resulted in hedging gains,
which are reflected in net electric margins, of $12.3 million for the year ended
December 31, 2003 compared to hedging gains of $17.4 million for the year ended
December 31, 2002. (See Note 8 to the Consolidated Financial Statements
"Hedging, Derivative Financial Instruments, and Fair Values" for further
information).
50
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. 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 the discussion
under the caption "Market and Credit Risk Management Activities" for more
information.)
Net revenues from the service agreements with LIPA decreased by $22.7 million
for the year ended December 31, 2003 compared to the same period last year.
Included in revenues are billings to LIPA for certain third party costs that
were lower than such billings last year. These revenues have minimal or no
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 in 2003 associated with these service agreements increased
approximately $7 million compared to last year. The increase reflects a higher
level of service fees charged to LIPA for the recovery of past operating costs.
In 2003 we earned $16.2 million associated with non-cost performance incentives
provided for under these agreements, compared to $16.0 million earned last year.
(For a description of the LIPA Agreements, see the discussion under the caption
"LIPA Agreements.")
Net revenues from the new electric "peaking" facilities located at Glenwood
Landing and Port Jefferson on Long Island were $9.6 million higher in 2003
compared to 2002, reflecting a full year of operation. 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 added 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.
Total electric net revenues increased by $8.5 million for the year ended
December 31, 2002, compared to the same period in 2001. Net revenues in 2002
reflect net revenues of $17.3 million from the Glenwood Landing and Port
Jefferson facilities.
Net revenues from the LIPA Agreements increased by $47.2 million in 2002,
compared to 2001. Included in revenues for 2002, are billings to LIPA for
certain third party costs that were significantly higher than such billings in
the prior year. As previously mentioned, these revenues have minimal impact on
earnings. Excluding these third party billings, revenues for 2002 associated
with the LIPA Agreements were comparable to such revenues in 2001. In 2002 we
earned $16.0 million associated with non-cost performance incentives provided
for under these agreements, compared to $16.2 million earned in 2001.
Net revenues from the Ravenswood facility were $56 million, or 16%, lower in
2002, compared to 2001. Net revenues from capacity sales decreased $45.3 million
compared to 2001, while margins associated with the sale of electric energy
decreased $10.7 million. During 2002 we changed our classification of certain
operating taxes that resulted in a comparative decrease in energy margins.
Further, comparative energy sales were adversely impacted by a reduction in
"spark-spread." Measured in cooling degree-days, weather during 2002 and 2001
was comparable.
51
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 NYISO
energy market which lowered capacity clearing prices by approximately 8%
compared to 2001. Further, as mentioned earlier, 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.
Derivative instruments resulted in hedging gains, which are reflected in net
electric margins, of $17.4 million for the year ended December 31, 2002 compared
to hedging gains of $16.7 million for the year ended December 31, 2001. (See
Note 8 to the Consolidated Financial Statements "Hedging, Derivative Financial
Instruments, and Fair Values" for further information).
Operating Expenses
Operating expenses increased $2.1 million for the year ended December 31, 2003,
compared to 2002. Included in comparative operating expenses is a decrease in
third party capital costs that are fully recoverable from LIPA, as noted
previously. Excluding the decrease in these costs, operating expenses increased
approximately $32 million. This increase resulted, in part, from higher pension
and other postretirement benefit costs. LIPA reimburses KeySpan for costs
directly incurred by KeySpan in providing service to LIPA, subject to certain
sharing provisions. Variations between pension and other postretirement costs
and the estimates used to bill LIPA are deferred and refunded to or collected
from LIPA in subsequent periods. As a result of an adjustment recorded in 2002
relating to this "true-up," comparative pension and other postretirement costs
were approximately $9.3 million higher in 2003 compared to 2002. In addition, in
2002 we settled certain outstanding issues with LIPA and The Consolidated Edison
Company of New York ("Consolidated Edison") that resulted in a $13.0 million
decrease to operating expenses in 2002. Operating taxes reflect an increase in
property tax rates associated with the Ravenswood facility. The increase in
depreciation expense is associated with the Glenwood and Port Jefferson
facilities.
Operating expenses were $9.1 million lower in 2002 compared to 2001. Excluding
the increase in third party capital costs, operating expenses decreased by
approximately $57 million in 2002 compared to 2001. As a result of an adjustment
recorded in 2002 relating to the pension and other postretirement benefit
"true-up" as previously mentioned, comparative 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 Consolidated
Edison, as previously noted, that resulted in a $20.3 million decrease to
comparative operating expenses. Also in 2002 we changed our method for recording
certain operating taxes that resulted in a comparative decrease in operating
taxes. The increase in depreciation and amortization expense primarily reflects
depreciation associated with the new peaking facilities.
52
Other Matters
During 2002, construction began on a new 250 MW combined cycle generating
facility at the Ravenswood facility site. The new facility was synchronized to
the electric grid in December 2003 and commenced operational testing in January
2004. In March, the facility completed full load dependable maximum net capacity
testing. The capacity and energy produced from this plant are anticipated to be
sold into the NYISO energy markets during the second quarter of 2004. KeySpan
intends to enter into an approximately $360 million sale/leaseback transaction
with third parties to finance the cost of this facility. (See Note 15 to the
Consolidated Financial Statements "Subsequent Events" for a further discussion
regarding this proposed transaction.)
In 2003, the New York State Board on Electric Generation Siting and the
Environment issued an opinion and order which granted a certificate of
environmental capability and public need for a 250 MW combined cycle electric
generating facility in Melville, Long Island, which is now final and
non-appealable. Also in 2003, LIPA issued a Request for Proposal ("RFP") seeking
bids from developers to either build and operate a Long Island generating
facility, and/or a new cable that will link Long Island to dedicated off-Long
Island power of between 250 to 600 MW of electricity by no later than the summer
of 2007. KeySpan and American National Power Inc. ("ANP") filed a joint proposal
in response to LIPA's RFP. Under the proposal, KeySpan and ANP will jointly own
and operate two 250 MW electric generating facilities to be located on Long
Island. It is anticipated that LIPA will respond to the joint proposal early in
2004. At December 31, 2003, total expenditures associated with the siting,
permitting and construction of the Ravenswood expansion project, and the siting,
permitting and procurement of equipment for the Long Island 250 MW combined
cycle electric generating facility were $387.7 million.
As part of our growth strategy, we continually evaluate the possible acquisition
and development 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.
Energy Services
The Energy Services segment includes companies that provide services to clients
located primarily within the Northeastern United States, with concentrations in
the New York City metropolitan area, including New Jersey and Connecticut, as
well as in Rhode Island, Pennsylvania, Massachusetts and New Hampshire. The
primary lines of business are: Business Solutions and Home Energy Services.
53
The table below highlights selected financial information for the Energy
Services segment.
- ------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2003 2002 2001
- ------------------------------------------------------------------------------------------------------------
Revenues $ 649,590 $ 938,761 $ 1,100,167
Less: cost of gas and fuel 93,674 206,731 407,734
- ------------------------------------------------------------------------------------------------------------
Net Revenues 555,916 732,030 692,433
Other operating expenses 593,982 743,965 839,918
- ------------------------------------------------------------------------------------------------------------
Operating (Loss) $ (38,066) $ (11,935) $ (147,485)
- ------------------------------------------------------------------------------------------------------------
Revenues decreased 31% for the year ended December 31, 2003 compared to the same
period last year, due in part to lower revenues realized by the Business
Solutions group of companies as a result of the softness in the construction
industry in the Northeastern United States, as well as from the discontinuation
of the general contracting business of one of our subsidiaries. The Business
Solutions group of companies provide mechanical, contracting, plumbing,
engineering, and consulting services to commercial, institutional, and
industrial customers. Further, comparative revenues, as well as gas and fuel
costs, were impacted by the assignment of retail natural gas customers,
consisting mostly of residential and small commercial customers, to ECONnergy
Energy Co., Inc. ("ECONnergy). KeySpan Energy Services will continue its
electric marketing activities.
Total operating losses for the Energy Services segment increased $26.1 million
in 2003 compared to 2002. Operating losses for the Business Solutions group of
companies increased by $32.2 million, reflecting revenue and significant gross
margin pressure from the softness in the construction industry, which has
delayed the start-up of certain engineering and construction projects, and has
generally increased competition for remaining opportunities. In addition,
margins were impacted by certain project-specific losses, resulting from costs
incurred in excess of cost recoveries, for which some recovery may be possible
pending successful claim resolution. Business Solutions' backlog held relatively
stable at approximately $537 million at December 31, 2003 (which includes
backlog of $33 million purchased in a recent acquisition as discussed below),
compared to $514 million at December 31, 2002.
Offsetting, in part, the results of the Business Solutions group of companies,
was a comparative increase in operating earnings of $6.1 million for the year
ended December 31, 2003 associated with the Home Energy Services group of
companies. These companies provide residential and small commercial customers
with service and maintenance contracts, as well as the retail marketing of
electricity. Comparative operating income reflects losses incurred during 2002,
resulting from the non-renewal of appliance service contracts due to the warm
first quarter 2002 weather, as well as from an increase in the provision for bad
debts.
Comparative operating income 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.
(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
operating loss of $137.8 million associated with the operations of the former
54
Roy Kay companies. The Roy Kay results reflect costs related to the
discontinuation of the general contracting activities of these companies, costs
to complete work on certain loss construction projects, as well as operating
losses. During 2002, in completing the contracts entered into by the former Roy
Kay companies we incurred operating losses of $10.8 million reflecting increases
in costs to complete construction contracts, and general and administrative
expenses. It should be noted that in 2003 we incurred $11.4 million in operating
losses which reflected provisions made for the resolution of outstanding claims
and change orders, as well as additional costs incurred in connection with the
collection of outstanding contract balances.
Excluding the results of the former Roy Kay companies, the Energy Services
segment reflected an increase in operating income of $8.7 million in 2002
compared to 2001. 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
substantially decreased its customer base by focusing its marketing efforts on
higher net margin customers and in 2003 assigned the majority of its retail
natural gas customers to ECONnergy, as previously discussed.
Operating income for the Business Solutions group of companies improved by $22.0
million in 2002 compared to 2001. This increase reflected additional work being
performed on the backlog of projects existing at the end of 2001 and the absence
of $6 million in losses incurred on four major projects in 2001. A backlog of
approximately $514 million existed at December 31, 2002, which was 20% below the
December 31, 2001 level.
Offsetting the positive contribution to operating income in 2002 by the Business
Solutions group of companies was a decrease of $13.3 million associated with the
Home Energy Services group of companies. Contributing to the decrease in
operating income from Home Energy Services were the following factors: (i) the
adverse impact of the downturn in the economy in 2002; (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 operating income in 2002 also benefited from
the elimination of goodwill amortization, which for 2001 amounted to $8.2
million.
Other Matters
During the third quarter of 2003, KeySpan Services, Inc., and its wholly-owned
subsidiary, Paulus, Sokolowski and Sartor, LLC., acquired Bard, Rao + Athanas
Consulting Engineers, Inc. (BR+A), a company engaged in the business of
providing engineering services relating to mechanical, electrical and plumbing
systems. The purchase price was $35 million, plus up to $14.7 million in
contingent consideration depending on the financial performance of BR+A over the
five-year period after the closing of the acquisition. We have recorded goodwill
of $26 million and intangible assets of $2 million associated with this
transaction. The intangible assets, which relate primarily to a portion of the
backlog purchased, as well as to non-compete agreements with all of the former
owners of BR+A, will be amortized over two and three years, respectively.
55
Energy Investments
The Energy Investment segment consists of our gas exploration and production
operations, certain other domestic and international energy-related investments,
as well as certain technology-related investments. Our gas exploration and
production subsidiaries, Houston Exploration and KeySpan Exploration and
Production, LLC ("KES E&P") are engaged in gas and oil exploration and
production, and the development and acquisition of domestic natural gas and oil
properties. In line with our strategy of monetizing or divesting certain
non-core assets, in 2002 we sold a portion of our assets in the joint venture
drilling program with Houston Exploration that was initiated in 1999. In 2003 we
reduced our ownership interest in Houston Exploration to approximately 55% (from
the previous level of 66%) through the repurchase, by Houston Exploration, of
three million shares of common stock owned by KeySpan. The net proceeds of
approximately $79 million received in connection with this repurchase were used
to pay down short-term debt. We realized a $19.0 million gain on this
transaction that was recorded in other income and (deductions) in the
Consolidated Statement of Income. Income taxes were not provided on this
transaction, since the transaction was structured as a return of capital.
In 2003, Houston Exploration acquired the entire Gulf of Mexico shallow-water
asset base of Transworld Exploration and Production, Inc. for $149 million. The
properties, which are 75% natural gas, have proven reserves of approximately 92
billion cubic feet of natural gas equivalent. Current production from 11 fields
is approximately 35 million cubic feet of natural gas equivalent per day.
Houston Exploration funded the transaction from its bank revolver and from cash
on hand at the time of closing.
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) 2003 2002 2001
- -------------------------------------------------------------------------------------------------------------------
Revenues $ 501,255 $ 357,451 $ 400,031
Depletion and amortization expense 204,102 176,925 142,728
Full cost ceiling test write-down - - 41,989
Other operating expenses 99,944 70,267 55,653
- -------------------------------------------------------------------------------------------------------------------
Operating Income $ 197,209 $ 110,259 $ 159,661
- -------------------------------------------------------------------------------------------------------------------
Natural gas and oil production (Mmcf) 109,211 106,044 93,968
Natural gas (per Mcf) realized $ 4.55 $ 3.32 $ 4.24
Natural gas (per Mcf) unhedged $ 5.23 $ 3.16 $ 4.09
- -------------------------------------------------------------------------------------------------------------------
*Operating income above represents 100% of our gas exploration and production
subsidiaries' results for the periods indicated. Gas reserves and production are
stated in BCFe and Mmcfe, which includes equivalent oil reserves
Operating Income
The increase in operating income of $87.0 million or 79% for the year ended
December 31, 2003, compared to the same period of 2002, reflects a significant
increase in revenues. The higher revenues were offset, to some extent, by an
increase in operating expenses associated with a higher depletion rate, as well
56
as higher lease operating expenses and severance taxes, as discussed below.
Revenues for the year ended 2003 benefited from the combination of a 37%
increase in average realized gas prices (average wellhead price received for
production including hedging gains and losses) and a 3% increase in production
volumes.
Derivative financial hedging instruments are employed by Houston Exploration to
provide more predictable cash flow, as well as to reduce its exposure to
fluctuations in natural gas prices. The average realized gas price for the year
ended 2003 was 87% of the average unhedged natural gas price, resulting in
revenues that were approximately $67 million lower than revenues that would have
been achieved if derivative financial instruments had not been in place during
2003. Houston Exploration hedged slightly less than 70% of its 2003 production,
principally through the use of costless collars, and has hedged a similar amount
of its estimated 2004 production. Further, at December 31, 2003, Houston
Exploration has derivative financial instruments in place for approximately 44%
of its estimated 2005 production. (See Note 8 to the Consolidated Financial
Statements, "Hedging, Derivative Financial Instruments, and Fair Values" for
further information.)
The depletion rate experienced in 2003 was $1.85 per Mcf, compared to $1.68 per
Mcf experienced in 2002. The increase in the depletion rate reflects downward
reserve revisions related to performance, the addition of more costs to Houston
Exploration's depreciation base with fewer additions for reserves, as well as an
increase in estimated future development costs at year end.
The increase in other operating expenses for the year ended December 31, 2003,
compared to the same period of 2002 was primarily due to increased lease
operating costs and severance taxes. Lease operating expenses increased $13.1
million in 2003 compared to 2002, as a result of the continued expansion of
operations both onshore and offshore. Severance tax, which is a function of
volume and revenues generated from onshore production, increased $6.5 million in
2003 compared to 2002 as a result of the increase in average wellhead prices for
natural gas. Overall operating expenses are increasing as new wells and
facilities are added and production from existing wells is maintained.
Operating income decreased $49.4 million or 31% in 2002 compared to 2001
primarily due to a 22% reduction in average realized gas prices, which lowered
comparative revenues. Further, operating expenses increased as a result of
higher levels of production and a higher depletion rate, as well as from an
increase in lease operating expenses. 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 approximately $16 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.
57
The depletion rate was $1.68 per Mcf for the year 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. (See Note 1 to the Consolidated Financial Statements
"Summary of Significant Accounting Policies," Item F for more information on
this charge.)
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,
2003 2002 2001
- -----------------------------------------------------------------------------------------------------
BCFe % BCFe % BCFe %
- -----------------------------------------------------------------------------------------------------
Houston Exploration 755 99.1% 650 96.7% 608 94.0%
KSE E&P 7 0.9% 22 3.3% 39 6.0%
- -----------------------------------------------------------------------------------------------------
Total 762 100.0% 672 100.0% 647 100.0%
- -----------------------------------------------------------------------------------------------------
This segment also consists of KeySpan Canada; our 20% interest in Iroquois Gas
Transmission System LP ("Iroquois"); our wholly owned 600,000 barrel liquefied
natural gas ("LNG") storage and receiving facility located in Rhode Island
("KeySpan LNG"); and our 50% interest in Premier Transmission Limited, and until
December 2003, our 24.5% interest in Phoenix Natural Gas Limited, both located
in Northern Ireland.
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) 2003 2002 2001
- ----------------------------------------------------------------------------------------------------
Revenues $ 113,124 $ 90,778 $ 98,287
Less: Operation and maintenance expense 68,568 57,161 71,411
Other operating expenses 22,317 17,622 20,883
Add: Equity earnings 19,106 13,992 13,129
Gain on sale of property - 2,348 -
- ----------------------------------------------------------------------------------------------------
Operating Income $ 41,345 $ 32,335 $ 19,122
- ----------------------------------------------------------------------------------------------------
* Operating income above reflects 100% of KeySpan's Canada's results.
58
The increase in operating income in 2003 compared to last year reflects, in
part, higher operating income associated with our Canadian investments,
primarily KeySpan Canada, as well as higher earnings from our Northern Ireland
investments. KeySpan Canada experienced higher unit sales, as well as higher
quantities of sales of natural gas liquids in 2003, as a result of increasing
oil prices. The pricing of natural gas liquids is directly related to oil
prices. The Northern Ireland investments realized higher gas sales quantities,
as well as favorable exchange rates during 2003. Operating income for 2003 also
reflects our investment in KeySpan LNG storage facility located in Rhode Island,
which we acquired in December 2002.
The increase in operating income in 2002 compared to 2001 reflects lower
comparative losses associated with certain technology-related investments.
Further, higher operating income from our Northern Ireland investments were, for
the most part, offset by lower earnings 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.
KeySpan has announced an initiative to upgrade the storage and receiving
terminal and enhance the vaporization capacity at the KeySpan LNG facility
located in Providence, Rhode Island. Pending approvals, the facility could be
ready to accept marine deliveries by 2005. We anticipate making an investment of
approximately $50 million to upgrade the facility.
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. As
previously indicated, in 2003 we monetized 39.09% of our interest in KeySpan
Canada, a company with natural gas processing plants and gathering facilities in
Western Canada. These assets include 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. We sold a portion of
our interest in KeySpan Canada through the establishment of an open-ended income
fund trust (the "Fund") organized under the laws of Alberta, Canada. The Fund
acquired the 39.09% ownership interest of KeySpan Canada through an indirect
subsidiary, and then issued 17 million trust units to the public through an
initial public offering. Each trust unit represents a beneficial interest in the
Fund and is registered on the Toronto Stock Exchange (KEY.UN). Additionally, we
sold our 20% interest in Taylor NGL LP that owns and operates two extraction
plants in Canada to AltaGas Services, Inc. We received cash proceeds of $119.4
million associated with these transactions and recorded a pre-tax loss of $30.3
million ($34.1 million after-tax). In February 2004, KeySpan entered into an
agreement to sell an additional 36% of its interest in KeySpan Canada. (See Note
15 to the Consolidated Financial Statements, "Subsequent Events.")
Further, in the fourth quarter of 2003, we completed the sale of our 24.5%
interest in Phoenix Natural Gas Limited. We received cash proceeds of $96
million and recorded a pre-tax gain of $24.7 million, $16.0 million after-tax,
or $0.10 per share.
59
Based on current market conditions we cannot predict when, or if, any other
sales or dispositions of our non-core assets may take place, or the effect that
any such sale or disposition may have on our financial position, results of
operations or cash flows.
Allocated Costs
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 non-operating 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.
The variation in operating income reflected in "eliminations and other" for
KeySpan's non-operating subsidiaries between 2003 and 2002 primarily reflects an
adjustment recorded in 2003 for environmental reserves associated with
non-utility environmental sites based on a recently concluded site investigation
study. (See Note 7 to the Consolidated Financial Statements "Contractual
Obligations, Financial Guarantees and Contingencies - Environmental Matters" for
additional information on environmental issues.) In 2001, these non-operating
subsidiaries realized operating income of $31.4 million, primarily related to
the $22.0 million benefit associated with the favorable appellate court decision
regarding the RICO class action settlement, previously mentioned.
Liquidity
Cash flow from operations for the year ended December 31, 2003 increased $453.2
million, or 62%, compared to the same period last year. During 2003, KeySpan
performed an analysis of costs capitalized for self-constructed property and
inventory for income tax purposes. KeySpan filed a change of accounting method
for income tax purposes resulting in a cumulative deduction for costs previously
capitalized. As a result of this tax method change, along with accelerated
deductions resulting from bonus depreciation, Keyspan received in October 2003,
a $192.3 million refund from the Internal Revenue Service associated with the
refund of prior year taxes, as well as an additional $85 million for tax
payments made in 2002. On a comparative basis, tax refunds received in 2003
coupled with tax payments made in 2002, resulted in a cash flow benefit in 2003,
compared to 2002, of approximately $ 310 million.
Comparative operating cash flow also reflects the collection of gas accounts
receivable associated with higher winter gas heating sales. As a result of load
additions, colder than normal winter weather during the first quarter, higher
natural gas prices, and higher accounts receivable at the end of 2002, cash
receipts from gas heating customers were higher in 2003 than in 2002. Further,
the higher natural gas prices resulted in an increase in operating cash flow
associated with the operations of Houston Exploration. These benefits to cash
flow were partially offset by significantly higher cash expenditures to re-fill
natural gas storage levels as a result of the higher natural gas prices.
60
Cash flow from operations decreased by $158.7 million, or 18%, 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 pension
obligations 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 2001, as KeySpan
was in a refund position with regard to such taxes. (See Note 8 to the
Consolidated Financial Statements, "Hedging, Derivative Financial Instruments,
and Fair Values" for an explanation of the interest rate hedges.)
At December 31, 2003, we had cash and temporary cash investments of $205.8
million. During 2003, we repaid $433.8 million of commercial paper and, at
December 31, 2003, $481.9 million of commercial paper was outstanding at a
weighted-average annualized interest rate of 1.2%. We had the ability to borrow
up to an additional $818.1 million at December 31, 2003, under the terms of our
credit facility.
In 2003, KeySpan renewed its $1.3 billion revolving credit facility, which was
syndicated among sixteen banks. The facility is used to support KeySpan's
commercial paper program, and consists of two separate credit facilities with
different maturities but substantially similar terms and conditions: a $450
million facility that extends for 364 days, and a $850 million facility that is
committed for three years. The fees for the facilities are subject to a
ratings-based grid, with an annual fee that ranges from eight to twenty five
basis points on the 364-day facility and ten to twenty basis points on the
three-year facility. Both credit agreements allow for KeySpan to borrow using
several different types of loans; specifically, Eurodollar loans, ABR loans, or
competitively bid loans. Eurodollar loans are based on the Eurodollar rate plus
a margin. ABR loans are based on the highest of the Prime Rate, the base CD rate
plus 1%, or the Federal Funds Effective Rate plus 0.5%, plus a margin.
Competitive bid loans are based on bid results requested by KeySpan from the
lenders. The margins on both facilities are ratings based and range from zero
basis points to 112.5 basis points. The margins are increased if outstanding
loans are in excess of 33% of the total facility. In addition, the 364-day
facility has a one-year term out option, which would cost an additional 0.25% if
utilized. 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
64%. 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.
61
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 2002. At
December 31, 2003, consolidated indebtedness, as calculated under the terms of
the credit facility was 58.2% of consolidated capitalization. The leasing
arrangement associated with the Ravenswood facility ("Master Lease") has always
been treated as debt for the calculation of debt-to-total capitalization under
KeySpan's credit facility. Beginning on December 31, 2003, KeySpan was required
to consolidate the Master Lease Agreement as required by FIN 46 and as a result
the Master Lease Agreement is reflected as debt on the Consolidated Balance
Sheet. See the discussion under "Off-Balance Sheet Arrangements" for an
explanation of the Master Lease Agreement.
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, 2003, KeySpan was in compliance
with all covenants.
Houston Exploration has a revolving credit facility with a commercial banking
syndicate that provides Houston Exploration with a commitment of $300 million,
which can be increased at its option to a maximum of $350 million with prior
approval from the banking syndicate. The credit facility is subject to borrowing
base limitations, currently set at $300 million and is re-determined
semi-annually. Up to $25 million of the borrowing base is available for the
issuance of letters of credit. The credit facility matures on July 15, 2005, is
unsecured and, with the exception of trade payables, ranks senior to all
existing debt of Houston Exploration.
Under the Houston Exploration credit facility, interest on base rate loans is
payable at a fluctuating rate, or base rate, equal to the sum of (a) the greater
of the federal funds rate plus 0.50% or the bank's prime rate plus (b) a
variable margin between 0% and 0.50%, depending on the amount of borrowings
outstanding under the credit facility. Interest on fixed rate loans is payable
at a fixed rate equal to the sum of (a) a quoted reserve adjusted LIBOR rate,
plus (b) a variable margin between 1.25% and 2.00%, depending on the amount of
borrowings outstanding under the credit facility.
Financial covenants require Houston Exploration to, among other things, (i)
maintain an interest coverage ratio of at least 3.00 to 1.00 of earnings before
interest, taxes and depreciation ("EBITDA") to cash interest; (ii) maintain a
total debt to EBITDA ratio of not more than 3.50 to 1.00; and (iii) generally
prohibits the hedging of more than 70% of natural gas and oil production during
any 12-month period. At December 31, 2003, Houston Exploration was in compliance
with all financial covenants.
During 2003, Houston Exploration borrowed $239 million under its credit facility
and repaid $264 million. At December 31, 2003, Houston Exploration had $127
million of borrowings outstanding under its credit facility at an average rate
of 3.42%. In addition, $0.4 million was committed under outstanding letters of
credit obligations and $172.6 million of borrowing capacity was available.
62
In 2003, KeySpan Canada replaced its two outstanding credit facilities with one
new facility with three tranches that combined allowed KeySpan Canada to borrow
up to approximately $125 million. At the time of the partial sale of KeySpan
Canada, net proceeds from the sale of $119.4 million plus an additional $45.7
million drawn under the new credit facilities were used to pay down existing
outstanding debt of $160.4 million. During the third quarter of 2003, KeySpan
Canada issued Cdn$125 million, or approximately US$93 million, in long-term
secured notes in a private placement. The proceeds of the offering were used to
pay-down, in its entirety, outstanding borrowings under the credit facility.
Further, one tranch of the credit facility was discontinued. (See "Capital
Expenditures and Financing - Financing" below for further information regarding
the long-term debt issuance.) At December 31, 2003, KeySpan Canada's credit
facility had the following two tranches with the following maturities: (i) $37.5
million matures in 364 days: and (ii) $37.5 million matures in two years. During
2003, KeySpan Canada borrowed $71.5 million from its prior credit facilities and
repaid $240.3 million. During the fourth quarter of 2003, KeySpan Canada
borrowed $18.1 million under the new facility and at December 31, 2003, $56.9
million was available for future borrowing.
In 2003, the Boston Gas Company redeemed all 562,700 shares of its outstanding
Variable Term Cumulative Preferred Stock, 6.42% Series A at its par value of $25
per share. The total payment was $14.3 million that included $0.2 million of
accumulated dividends. This preferred stock series had been reflected as
minority interest on KeySpan's Consolidated Balance Sheet.
On January 17, 2003, KeySpan sold 13.9 million shares of common stock on 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 to call $447
million of outstanding promissory notes to LIPA as is further explained in
"Capital Expenditures and Financing" below. In addition, as previously noted, we
used the net proceeds of approximately $79 million received in connection with
the partial monetization of Houston Exploration to repay short-term 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.
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.
63
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) 2003 2002
- -------------------------------------------------------------------------
Gas Distribution $ 419,549 $ 412,433
Electric Services 256,498 348,147
Energy Investments 314,097 272,720
Energy Services and other 21,572 27,722
- -------------------------------------------------------------------------
$ 1,011,716 $ 1,061,022
- -------------------------------------------------------------------------
Construction expenditures related to the Gas Distribution segment are primarily
for the renewal and replacement of mains and services and for the expansion of
the gas distribution system. Construction expenditures for the Electric Services
segment reflect costs to: (i) maintain our generating facilities; (ii) expand
the Ravenswood facility; and (iii) construct new Long Island generating
facilities as previously noted. The decrease in Electric Services construction
expenditures in 2003, compared to last year reflects the fact that construction
of the Glenwood and Port Jefferson peaking facilities was substantially
completed by June 30, 2002. 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.
Construction expenditures for 2004 are estimated to be approximately the same as
2003 at $1 billion. 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
In November 2003, KeySpan closed on a financing transaction pursuant to which
$128 million tax-exempt bonds with a 5.25% coupon maturing in June 2027 were
issued on its behalf. Fifty-three million dollars of these Industrial
Development Revenue Bonds were issued through the Nassau County Industrial
Development Authority for the construction of the Glenwood electric-generation
peaking plant and the balance of $75 million was issued by the Suffolk County
Industrial Development Authority for the Port Jefferson electric-generation
peaking plant. Proceeds from the transaction were used to pay down commercial
paper used for the construction, installation and equipping of the two
facilities.
In 2003, KeySpan Canada, issued Cdn$125 million, or approximately US$93 million,
long-term secured notes in a private placement to investors in Canada and the
United States. The notes were issued in the following three series: (i) Cdn$20
million 5.42% senior secured notes due 2008; (ii) Cdn$52.5 million 5.79% senior
secured notes due 2010; and (iii) Cdn$52.5 million 6.16% senior secured notes
due 2013. The proceeds of the offering were used to repay KeySpan Canada's
credit facility.
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In addition, Houston Exploration closed on a private placement issue of $175
million 7.0%, senior subordinated notes due 2013. Interest payments began on
December 15, 2003, and will be paid semi-annually thereafter. The notes will
mature on June 15, 2013. Houston Exploration has the right to redeem the notes
as of June 15, 2008, at a price equal to the issue price plus a specified
redemption premium. Until June 15, 2006, Houston Exploration may also redeem up
to 35% of the notes at a redemption price of 107% with proceeds from an equity
offering. Houston Exploration incurred approximately $4.5 million of debt
issuance costs on this private placement. Houston Exploration used a portion of
the net proceeds from the issuance to redeem all of its outstanding $100 million
principal amount of 8.625% senior subordinated notes due 2008 at a price of
104.313% of par plus interest accrued to the redemption date. Debt redemption
costs totaled approximately $5.9 million. The remaining net proceeds from the
offering were used to reduce debt amounts associated with Houston Exploration's
bank revolving credit facility.
We also issued $300 million of medium-term and long-term debt in 2003. The debt
was issued in the following two series: (i) $150 million 4.65% Notes due 2013;
and (ii) $150 million 5.875% Notes due 2033. The proceeds of this issuance were
used to pay down outstanding commercial paper.
In connection with the KeySpan/LILCO business combination, KeySpan and certain
of its subsidiaries issued promissory notes to LIPA to support certain debt
obligations assumed by LIPA. At December 31, 2002, the remaining principal
amount of promissory notes issued to LIPA was approximately $600 million. Under
these promissory notes, KeySpan is required to obtain letters of credit to
secure its payment obligations if its long-term debt is not rated at least in
the "A" range by at least two nationally recognized statistical rating agencies.
In an effort to mitigate the dilutive effect of the equity issuance previously
mentioned, in March 2003, we called approximately $447 million aggregate
principal amount of such promissory notes at the applicable redemption prices
plus accrued and unpaid interest through the dates of redemption. Interest
savings associated with this redemption were $15.6 million after-tax, or $0.10
per share, in 2003.
In the fourth quarter of 2003, KeySpan received authorization from the SEC,
under PUHCA, to issue up to an additional $3 billion of securities through
December 31, 2006. This authorization provides KeySpan with the necessary
flexibility to finance our future capital requirements over the next three
years. See the discussion under the caption "Regulation and Rate Matters -
Securities and Exchange Commission Regulation" for a further discussion of this
approval.
We anticipate replacing outstanding commercial paper related to the construction
of a new 250 MW combined cycle generating facility at the Ravenswood facility
site with the proceeds from a proposed sale/leaseback transaction anticipated to
be completed in the second quarter of 2004. (See Note 15 to the Consolidated
Financial Statements "Subsequent Events" for further details on this proposed
transaction). We will continue to evaluate our capital structure and financing
strategy for 2004 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) are sufficient to meet
our anticipated capital needs for the foreseeable future.
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The following table represents the ratings of our long-term debt at December 31,
2003. Currently, Standard & Poor's and Moody's Investor Services ratings on
KeySpan's and its subsidiaries' long-term debt are on negative outlook.
Moody's Investor Standard
Services & Poor's FitchRatings
- --------------------------------------------------------------------------------
KeySpan Corporation A3 A A-
KEDNY N/A A+ A+
KEDLI A2 A+ A-
Boston Gas A2 A N/A
Colonial Gas A2 A+ N/A
Electric Generation A3 A N/A
- --------------------------------------------------------------------------------
Off-Balance Sheet Arrangements
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, three steam generating units, directly from Consolidated Edison and
leased it to a KeySpan subsidiary. The variable interest unaffiliated financing
entity acquired the property for $425 million, financed with debt of $412.3
million (97% of capitalization) and equity of $12.7 million (3% of
capitalization). Monthly lease payments generally equal the monthly interest
expense on the debt securities.
In December 2003, KeySpan implemented FIN 46 that required us to consolidate
this variable interest entity and classify the Master Lease as $412.3 million
long-term debt on the Consolidated Balance Sheet. Further, we recorded an asset
on the Consolidated Balance Sheet for an amount substantially equal to the
estimated fair market value of the leased assets at inception of the lease, less
depreciation since that time. As previously mentioned, under the terms of our
credit facility the Master Lease has been considered debt in the ratio of
debt-to-total capitalization since the inception of the lease and therefore,
implementation of FIN 46 had no impact on our credit facility. The
Interpretation also requires us to continue to depreciate the leased assets over
their remaining economic lives. (See Note 7 to the Consolidated Financial
Statements, "Contractual Obligations, Financial Guarantees and Contingencies"
for additional information regarding the leasing arrangement associated with the
Master Lease Agreement and FIN 46 implementation issues.)
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Guarantees
KeySpan had a number of financial guarantees for its subsidiaries at December
31, 2003. KeySpan has fully and unconditionally guaranteed: (i) $525 million of
medium-term notes issued by KEDLI; (ii) the obligations of KeySpan Ravenswood
LLC, the lessee under the $425 million Master Lease Agreement associated with
the Ravenswood facility; and (iii) the payment obligations of our subsidiaries
related to $128 million of tax-exempt bonds issued through the Nassau County and
Suffolk County Industrial Development Authority for the construction of the
Glenwood and Port Jefferson electric-generation peaking facilities. The
medium-term notes, the Master Lease Agreement and the tax-exempt bonds are
reflected on the Consolidated Balance Sheet. Further, KeySpan has guaranteed:
(i) up to $168 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 an aggregate amount of $43 million; and (iii) $67
million of subsidiary letters of credit. The guarantee of the KEDLI medium-term
notes expires in 2010, while the Master Lease Agreement can be extended to 2009.
The guarantee of the payment obligations of our subsidiaries related to the
tax-exempt financing extends to 2027. The other guarantees have terms that do
not extend beyond 2005 and are not recorded on the Consolidated Balance Sheet.
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 additional information regarding KeySpan's
guarantees.)
In addition, KeySpan intends to guarantee approximately $360 million in
connection with a proposed sale/leaseback transaction for the financing of a new
250 MW electric generating facility located on the Ravenswood site. (See Note 15
to the Consolidated Financial Statements "Subsequent Events" for further details
regarding this transaction.)
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."
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The table below reflects maturity schedules for KeySpan's contractual
obligations at December 31, 2003:
- ------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
Contractual Obligations Total 1 - 3 Years 4 - 5 Years After 5 Years
- ------------------------------------------------------------------------------------------------------------
Long-term Debt $ 5,625,706 $ 1,814,999 $ 161,094 $ 3,649,613
Capital Leases 12,981 3,237 2,192 7,552
Operating Leases 417,124 179,316 115,597 122,211
Master Lease Payments 169,532 92,472 61,648 15,412
Interest Payments 3,387,891 910,937 458,547 2,018,407
Demand Charges 452,045 452,045 - -
- ------------------------------------------------------------------------------------------------------------
Total Contractual
Cash Obligations $ 10,065,279 $ 3,453,006 $ 799,078 $ 5,813,195
- ------------------------------------------------------------------------------------------------------------
Commercial Paper $ 481,900 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 a method of accounting for long-term
construction type contracts in accordance with Generally Accepted Accounting
Principles and, accordingly, the method used for engineering and mechanical
contracting 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 known. 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. Unapproved change orders and claims also
involve the use of estimates, and it is reasonably possible that revisions to
the estimated recoverable amounts of recorded change orders and claims may be
made in the near-term. Application of percentage-of-completion accounting
requires that the impact of those revised estimates be reported in the
consolidated financial statements prospectively.
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Valuation of Goodwill
KeySpan records goodwill on purchase transactions, representing the excess of
acquisition cost over the fair value of net assets acquired. In testing for
goodwill impairment under Statement of Financial Accounting Standards ("SFAS")
142 "Goodwill and Other Intangible Assets", significant reliance is placed upon
a number of estimates regarding future performance that require broad
assumptions and significant judgment by management. A change in the fair value
of our investments could cause a significant change in the carrying value of
goodwill. 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.
KeySpan currently has $1.8 billion of recorded goodwill, the majority of which
is recorded in the Gas Distribution and Energy Investments segment, with
approximately $171 million recorded in the Energy Services segment. 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 and there is no economic
indication that the carrying value of goodwill may be impaired. In the case of
the Gas Distribution and the Energy Investments segments, the above criteria
have been met and therefore, there was no impairment to goodwill in 2003. In
regard to the Energy Services segment, adverse economic conditions experienced
in the construction industry in the Northeastern United States during 2003 and
its related impact on the operating results of this segment, prompted management
to conduct an impairment test during the fourth quarter.
KeySpan employed a combination of two methodologies in determining the fair
value for its investment in the Energy Services segment, a market valuation
approach and an income valuation approach. A third party specialist was engaged
to assist with the valuation and evaluate the reasonableness of key assumptions
employed.
Since the companies included in the Energy Services segment are not publicly
traded, the market valuation approach was used to estimate their total
enterprise value or aggregate potential market value. Under the market valuation
approach, KeySpan compared relevant financial information relating to the
companies included in the Energy Services segment to the corresponding financial
information for a peer group of companies in the specialty trade-contracting
sector of the construction industry. The market valuation approach derived
enterprise value to earnings before interest and taxes ("EV/EBIT") multiples and
enterprise value to earnings before interest, taxes, depreciation and
amortization ("EV/EBITDA") multiples. Though there are numerous multiples that
can be used to value an individual firm, these multiples were selected since
they offer the closest parallels to discounted cash flow valuation and are most
appropriate for the Energy Services segment's market sector.
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In addition to the market valuation approach, we also used an income valuation
approach or discounted cash flow ("DCF") valuation approach to estimate the fair
market value for the companies included in the Energy Services segment. Under
the income valuation approach, the fair value of a firm is obtained by
discounting the sum of (i) the expected future cash flows to a firm; and (ii)
the terminal value of a firm. The discount factor used in the calculation is
basically a firm's weighted-average cost of capital. KeySpan was required to
make certain significant assumptions in the income approach, specifically the
weighted-average cost of capital, short and long-term growth rates and expected
future cash flows. The cash flow model is based on relevant industry forecasts
projecting improved market conditions over the next five years, continued
increases in business activity that are likely to result in backlog growth, and
short and long-term revenue and operating margin growth projections that
management believes are reasonable given historical performance.
As a result of our valuation, management has determined that the fair value of
the assets adequately exceeds their carrying value and no impairment charge is
necessary. Management will continue to review and focus on our overall strategy
for this business unit and accordingly will continue to evaluate the related
carrying value of the goodwill. While we believe that our assumptions are
reasonable, actual results, however, may differ from our projections.
Accounting for the Effects of Rate Regulation on Gas Distribution Operations
The financial statements of the Gas Distribution segment reflect the ratemaking
policies and orders of the New York Public Service Commission ("NYPSC"), the New
Hampshire Public Utilities Commission ("NHPUC"), and the Massachusetts
Department of Telecommunications and Energy ("DTE").
Four of our six regulated gas utilities (KEDNY, KEDLI, Boston Gas Company and
EnergyNorth Natural Gas, Inc.) are subject to the provisions of SFAS 71,
"Accounting for the Effects of Certain Types of Regulation." This statement
recognizes the actions of regulators, through the ratemaking process, to create
future economic benefits and obligations affecting rate-regulated companies.
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 ten-year periods ending 2009 and 2008, respectively. 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.
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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 our net regulatory assets at December 31, 2003 could result in a
charge to net income of approximately $300 million or $1.89 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.
As is further discussed under the caption "Regulation and Rate Matters," in
October 2003 the DTE rendered its decision on the Boston Gas Company's base rate
case and Performance Based Rate Plan proposal submitted to the DTE in April
2003. The DTE approved a $27 million increase in base revenues, as well as an
allowed rate of return on equity of 10.2%. The DTE also approved a Performance
Based Rate Plan for up to ten years. The rate plans previously in effect for
KEDNY and KEDLI have expired. The continued application of SFAS 71 to record the
activities of these subsidiaries is contingent upon the actions of regulators
with regard to future rate plans. We are currently evaluating various options
that may be available to us including, but not limited to, 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 to 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. 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. (However, KEDNY, although subject to SFAS 71,
does not have a recovery mechanism in place for increases in postretirement
costs.) Further, changes in postretirement expenses associated with subsidiaries
that service the LIPA Agreements are also deferred for future recovery from or
refund to LIPA.
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For 2003, the assumed long-term rate of return on our postretirement plans'
assets was 8.5% (pre-tax), net of expenses. This is an appropriate long-term
expected rate of return on assets based on KeySpan's investment strategy, asset
allocation and the historical outperformance of equity investments over long
periods of time. The actual 10 year compound annual rate of return for the
KeySpan Plans is greater than 8.5%.
KeySpan's master trust investment allocation policy target is 70% equity and 30%
fixed income. At December 31, 2003, the actual investment allocation was 67%
equities, 33% fixed income and cash. In an effort to maximize plan performance,
actual asset allocation will fluctuate from year to year depending on the then
current economic environment.
During 2003, KeySpan conducted an asset & liability study projecting asset
returns and expected benefit payments over a 10-year period. Based on the
results, KeySpan has developed a multiyear funding strategy for its
postretirement plans. KeySpan believes that it is reasonable to assume assets
can achieve or outperform the assumed long-term rate of return with the target
allocation as a result of historical outperformance of equity investments over
long-term periods.
A 25 basis point increase or decrease in the assumed long-term rate of return on
plan assets would have impacted 2003 expense by approximately $4 million, before
deferrals.
The year-end December 31, 2003 assumed discount rate used to determine
postretirement obligations was 6.25%. Our discount rate assumption is based upon
the current investment yield associated with rating agency indices that have
high quality long-term corporate bonds. A 25 basis point increase or decrease in
the assumed year-end discount rate would have had no impact on 2003 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. A year-end
discount rate of 6.00% would have required an additional $11 million debit to
other comprehensive income ("OCI"), net of tax and deferrals.
At January 1, 2003, the assumed discount rate used to determine postretirement
obligations was 6.75%. A 25 basis point increase or decrease in the assumed
discount rate at the beginning of the year would have impacted 2003 expense by
approximately $14 million, before deferrals.
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 outlook.
Historically, we have funded our qualified pension plans in excess of the amount
required to satisfy minimum ERISA funding requirements. At December 31, 2003, we
had a funding credit balance in excess of the ERISA minimum funding requirements
and as a result KeySpan was not required to make any contributions to its
qualified pension plans in 2003. However, although we have presently exceeded
ERISA funding requirements, our pension plans, on an actuarial basis, are
currently underfunded. Therefore, during 2003 KeySpan contributed $137 million
to its postretirement plans.
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For 2004, KeySpan expects to contribute a total of $147 million to its funded
and unfunded post-retirement plans. Future funding requirements are heavily
dependent on actual return on plan assets and prevailing interest rates.
Full Cost Accounting
Our gas exploration and production subsidiaries use the full cost method to
account for their natural gas and oil properties. Under full cost accounting,
all costs incurred in the acquisition, exploration, and development of natural
gas and oil reserves are capitalized into a "full cost pool." Capitalized costs
include costs of all unproved properties, internal costs directly related to
natural gas and oil activities, and capitalized interest.
Under full cost accounting rules, total capitalized costs are limited to a
ceiling equal to the present value of future net revenues, discounted at 10%,
plus the lower of cost or fair value of unproved properties less income tax
effects (the "ceiling limitation"). A quarterly ceiling test is performed to
evaluate whether the net book value of the full cost pool exceeds the ceiling
limitation. If capitalized costs (net of accumulated depreciation, depletion and
amortization) less deferred taxes are greater than the discounted future net
revenues or ceiling limitation, a write-down or impairment of the full cost pool
is required. A write-down of the carrying value of the full cost pool is a
non-cash charge that reduces earnings and impacts stockholders' equity in the
period of occurrence and typically results in lower depreciation, depletion and
amortization expense in future periods. Once incurred, a write-down is not
reversible at a later date.
The ceiling test is calculated using natural gas and oil prices in effect as of
the balance sheet date, held constant over the life of the reserves. Our gas
exploration and production subsidiaries use derivative financial instruments
that qualify for hedge accounting under SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities" 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, 2003, 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 write-down 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,
73
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 manage commodity and financial market risk.
All of our derivative instruments, except for certain weather derivatives, are
reported on the Consolidated Balance Sheet at fair value in accordance with SFAS
133; weather derivatives are accounted for in accordance with Emerging Issues
Task Force ("EITF") 99-2. None of KeySpan's derivative instruments qualify as
"energy trading contracts" as defined by current accounting literature.
For those derivative instruments designated as cash flow hedges under SFAS 133,
which are the majority of KeySpan's derivative instruments, changes in the
market value are recorded in other comprehensive income on the Consolidated
Balance Sheet, (in line with effectiveness measurements) and are recorded
through earnings at the time of settlement. Hedge effectiveness is dependent
upon various factors such as the use of hedge contracts with market points that
are different from the underlying transaction, and to the extent hedge contracts
are deemed ineffective, that portion will impact earnings.
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; the accounting for
such derivative instruments is subject to SFAS 71. Changes in the market value
of these derivative instruments are recorded as regulatory assets and
liabilities, as appropriate, on the Consolidated Balance Sheet. KeySpan's
non-regulated subsidiaries employ a limited number of financial derivatives that
do not qualify for hedge accounting treatment under SFAS 133, and, therefore,
changes in the market value of these derivative instruments are recorded through
earnings.
When available, quoted market prices are used to record a derivative contract's
fair value. However market values for certain derivative contracts may not be
readily available or determinable. If no active market exists for a commodity, a
specific contract type, or for the entire term of a contract's duration, fair
values are based on pricing models. Such models employ matrix pricing based on
contracts with similar terms and risks, including pricing based on broker quotes
and industry publications. KeySpan validates its internally developed fair
values by using forecasted market information and mathematical extrapolation
techniques. In addition, for hedges of forecasted transactions, KeySpan
estimates the expected future cash flows of the forecasted transactions, as well
as evaluates the probability of occurrence and timing of such transactions.
Changes in market conditions or the occurrence of unforeseen events could affect
the timing of recognition of changes in fair value of certain hedging
derivatives.
See Note 8 to the Consolidated Financial Statements "Hedging, Derivative
Financial Instruments and Fair Values" and Item 7A, "Quantitative and
Qualitative Disclosures About Market Risk" for a further description of all our
derivative instruments.
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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 annual 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 most recent rate
years (September 30, 2003 and November 30, 2003, respectively), the ratio of
debt to total utility capitalization was 41% and 49%, 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
"Regulation and Rate Matters - Securities and Exchange Commission Regulation").
Regulation and Rate Matters
Gas Distribution
By orders dated February 5, 1998 and April 14, 1998, the NYPSC approved the
KeySpan/LILCO 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 is 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 level. The threshold level for the rate year ended
September 30, 2003 was 13.25%. KEDNY did not earn above its threshold return
level in its rate year ended September 30, 2003. 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.
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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, 2003. 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.
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.
Regarding the Boston Gas Company, we filed a base rate case and Performance
Based Rate Plan on April 16, 2003, to be effective in the fourth quarter of
2003. On October 31, 2003, the DTE rendered its decision on the Boston Gas
Company's proposal and approved a $25.9 million increase in base revenues with
an allowed return on equity of 10.2% assuming an equal balance of debt and
equity. On January 27, 2004 the DTE issued orders on Boston Gas Company's
Motions for Recalculation, Reconsideration and Clarification that granted an
additional $1.1 million in base revenues, for a total of $27 million. The DTE
also approved a true-up mechanism for pension and other postretirement benefit
costs under which variations between actual pension and other postretirement
benefit costs and amounts used to establish rates are deferred and collected
from or refunded to customers in subsequent periods through an adjustment
clause. This true-up mechanism allows for carrying charges on deferred assets
and liabilities at Boston Gas Company's weighted-average cost of capital.
The DTE also approved a Performance Based Rate Plan (the "Plan") for up to ten
years. The Plan allows for an annual revenue adjustment based on inflation, less
a 0.41 percent productivity factor. Further, the plan contained a margin sharing
mechanism, whereby 25% of earnings in excess of a 15% return on equity will be
passed back to customers. Similarly, ratepayers would absorb 25% of any
shortfall below a 7% return on equity.
Prior to the change in base rates and the new Plan noted above, Boston Gas
Company's gas rates for local distribution service were governed by a five-year
Performance-Based Rate Plan approved by the DTE in 1996 (the "Plan"). Under this
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 had 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%.
In connection with the Eastern Enterprises 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
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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. 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.
Electric Rate Matters
KeySpan 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 in accordance with the Power Supply Agreement
("PSA") entered into between KeySpan and LIPA in 1998. The current FERC approved
rates, which have been in effect since May 1998, expired on December 31, 2003.
KeySpan filed with the FERC an updated cost of service for the Long Island based
oil and gas-fired generating plants in October 2003. The rate filing included,
among other things, an annual revenue increase of 2.1% or approximately $6.4
million, a return on equity of 11%, updated operating and maintenance expense
levels and recovery of certain other costs. FERC approved implementation of new
rates starting January 1, 2004, subject to refund. Settlement negotiations are
currently ongoing.
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 December 18, 2003, provides us with, among other
things, authorization to do the following through December 31, 2006 (the
"Authorization Period"): (a) to issue and sell up to an additional amount of
$3.0 billion of common stock, preferred stock, preferred and equity-linked
securities, and long-term debt securities (the "Long-Term Financing Limit") in
accordance with certain defined parameters; (b) in addition to the Long-Term
Financing Limit, to issue and sell up to an aggregate amount of $1.3 billion of
short-term debt (the "Short-Term Financing Limit"); (c) to issue up to 13
million shares of common stock under dividend reinvestment and stock-based
management incentive and employee benefit plans; (d) to maintain existing and
enter into additional hedging transactions with respect to outstanding
indebtedness in order to manage and minimize interest rate costs; (e) to issue
guarantees and other forms of credit support in an aggregate principal amount
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not to exceed $4.0 billion outstanding at any one time; (f) to refund,
repurchase (through open market purchases, tender offers or private
transactions), replace or refinance debt or equity securities outstanding during
the Authorization Period through the issuance of similar or any other type of
authorized securities; (g) to pay dividends out of capital and unearned surplus
as well as paid-in-capital with respect to certain subsidiaries, subject to
certain limitations; (h) to engage in preliminary development activities and
administrative and management activities in connection with anticipated
investments in exempt wholesale generators, foreign utility companies and other
energy-related companies; (i) to organize and/or acquire the equity securities
of entities that will serve the purpose of facilitating authorized financings;
(j) to invest up to $3.0 billion in exempt wholesale generators and foreign
utility companies; (k) to create and/or acquire the securities of entities
organized for the purpose of facilitating investments in other non-utility
subsidiaries; and (l) to enter into certain types of affiliate transactions
between certain non-utility subsidiaries involving cost structures above the
typical "at-cost" limit.
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. As of December 31, 2003 our consolidated common equity was 38%
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")
KeySpan manages the day-to-day operations, maintenance and capital improvements
of the transmission and distribution ("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.
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Power Supply Agreement ("PSA")
KeySpan 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. As noted previously, rates under the PSA have
been reestablished for the contract year commencing January 1, 2004. Rates
charged to LIPA include a fixed and variable component. The variable component
is billed to LIPA on a monthly per megawatt hour 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. The
PSA runs for a term of fifteen years through May 2013, with LIPA having the
option to renew the PSA for an additional fifteen year term.
Energy Management Agreement ("EMA")
The EMA provides for KeySpan 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 is expected to be in effect through 2013 for
the procurement of fuel supplies and through 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 originally 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.
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The extension is the result of an 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 (the "PPAs") with LIPA.
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. During 2003, we undertook an extensive
review of all our current and former properties that are or may be subject to
environmental cleanup activities. As a result of this study, we adjusted reserve
balances for estimated manufactured gas plant ("MGP") related environmental
cleanup activities, as well as estimated environmental cleanup costs related to
three non-utility sites. Through various rate orders issued by the NYPSC, DTE
and NHPUC, costs related to MGP environmental cleanup activities are recovered
in rates charged to gas distribution customers and, as a result, adjustments to
these reserve balances do not impact earnings. However, environmental cleanup
activities related to the three non-utility sites are not subject to rate
recovery. Based on the recently concluded environmental study we reduced our
reserve balance for future cleanup costs related to these sites and realized a
pre-tax operating income benefit of $10 million.
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We estimate that the remaining cost of our MGP related environmental cleanup
activities, including costs associated with the Ravenswood facility, will be
approximately $269.1 million and we have recorded a related liability for such
amount. We have also recorded an additional $25.6 million liability,
representing the estimated environmental cleanup costs related to a former coal
tar processing facility. As of December 31, 2003, we have expended a total of
$101.1 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.)
Market and Credit Risk Management Activities
Market Risk: KeySpan is 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.
Credit Risk: KeySpan is exposed to credit risk arising from the potential that
our counterparties fail to perform on their contractual obligations. Our credit
exposures are created primarily through the sale of gas and transportation
services to residential, commercial, electric generation, and industrial
customers and the provision of retail access services to gas marketers, by our
regulated gas businesses; the sale of commodities and services to LIPA and the
NYISO; the sale of gas, power and services to our retail customers by our
unregulated energy service businesses; entering into financial and energy
derivative contracts with energy marketing companies and financial institutions;
and the sale of gas, natural gas liquids, oil and processing services to energy
marketing and oil and gas production companies.
We have regional concentration of credit risk due to receivables from
residential, commercial and industrial customers in New York, New Hampshire and
Massachusetts, although this credit risk is spread over a diversified base of
residential, commercial and industrial customers. Customers' payment records are
monitored and action is taken, when appropriate. Companies within the Energy
Services segment have a concentration of credit risk to large customers and to
the governmental and healthcare industries.
We also have concentrations of credit risk from LIPA, our largest customer, and
from other energy companies. Concentration of energy company counterparties may
impact overall exposure to credit risk in that our counterparties may be
similarly impacted by changes in economic, regulatory or other considerations.
We actively monitor the credit profile of our wholesale counterparties in
derivative and other contractual arrangements, and manage our level of exposure
accordingly. Over the past year, the credit quality of certain energy companies
has declined. In instances where counterparties' credit quality has declined, we
may limit our credit exposure by restricting new transactions with the
counterparty, requiring additional collateral or credit support and negotiating
the early termination of certain agreements.
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Equity and Debt Securities Risk: KeySpan is exposed to price risk due to
investments in equity and debt securities held to fund benefit payments for
various employee pension and other postretirement benefit plans. To the extent
that the values of investments held decline, the effect will be reflected in
KeySpan's recognition of periodic cost of such employee benefit plans and the
determination of the amount of cash to be contributed to the employee benefit
plans.
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 January
27, 2004, the NYPSC issued a notice seeking further comments on the matters
addressed in the RD, in light of the current state of the retail market and the
experience of the past few years.
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. The Joint Proposal expired on
November 30, 2003. However, by Order dated November 25, 2003 the NYPSC approved
tariff amendments that allow KEDNY and KEDLI to continue the merchant function
backout credit and the lost revenue recovery mechanism through May 31, 2005.
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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
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. Pursuant to
the Act, the NYPSC proposed regulations implementing the Act through a notice of
Proposed Rulemaking dated January 27, 2004. The Act became 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 LDCs' 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. In January 2004, the DTE began a proceeding
to re-examine whether the upstream capacity market has been sufficiently
competitive to allow voluntary capacity assignment.
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.
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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.
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. On September 16, 2004, FERC
terminated various RTO proceedings, including the NYISO/ISONE proceeding,
because it determined their continuation is no longer necessary to achieve the
Commission's objective of establishing RTOs. Nevertheless, the Commission
continues to guide the evolution of competitive markets in other proceedings
including the development of a Standard Market Design.
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.
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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 implemented a new in-City real time
automated mitigation procedure. On November 26, 2003, the NYISO filed with FERC
a request for tariff revisions reflecting the implementation of enhanced
real-time scheduling software. Among other things, the new software included
changes to the in-City day-ahead energy mitigation measures. The in-City
day-ahead energy mitigation will no longer use the Indian Point 2 price as a
proxy for determining whether an energy offer should be mitigated. The NYISO is
going to apply its conduct and impact mitigation scheme to in-City offers. This
will be applied on an hour by hour basis rather than on a 24-hour basis. Overall
the changes are intended to address longstanding issues in the NYISO market and
help the NYISO markets reach their full potential. The revisions are expected to
lead to prices that reflect actual market and system conditions, including
scarcity conditions. FERC approved the tariff revisions on February 11, 2004 and
the NYISO will implement the revisions when they complete testing of the
software revisions in the fall of 2004. However, the NYISO will implement the
revisions associated with the in-City mitigation measures in its existing
systems before the summer of 2004. 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.
NYISO Demand Curve Capacity Market Implementation
On March 21, 2003 the NYISO made a filing at FERC seeking approval of a Demand
Curve to be used in place of its current deficiency auction for capacity
procurement. On May 20, 2003, FERC approved, with some modifications, the Demand
Curve to become effective May 21, 2003. On October 23, 2003, FERC denied various
requests for rehearing of its order approving the Demand Curve and approved the
NYISO's compliance filing. On December 9, 2003, the NYISO filed its first status
report with FERC with respect to how the Demand Curve was working. The NYISO
report found that there was no evidence of inappropriate withholding of capacity
resources and that the Demand Curve was working as intended. On December 22,
2003, the Electric Consumers Resource Council filed an appeal with the DC
Circuit Court of Appeals of FERC's May 20, 2003 order approving the Demand Curve
and its October 23, 2003 order denying rehearing. This case is still pending and
we are unable to determine to what extent, if any, this proceeding will impact
the Ravenswood facility's financial condition, results of operations or cash
flows.
10-Minute Non-Spinning Reserves - DC Court of Appeals
Due to volatility in the market clearing price of 10-minute spinning and
non-spinning reserves during the first quarter of 2000, the NYISO requested that
FERC approve a bid cap on reserves as well as requiring a refunding of so called
alleged "excess payments" received by sellers, including Ravenswood. On May 31,
2000, FERC issued an order that granted approval of a $2.52 per MWh bid cap for
10 minute non-spinning reserves, plus payments for the opportunity cost of not
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making energy sales. The other requests, such as a bid cap for spinning
reserves, retroactive refunds, recalculation of reserve prices for March 2000,
and convening a technical conference and settlement proceeding, were rejected.
The NYISO, Con Edison, Niagara Mohawk Power Corporation and Rochester Gas and
Electric (joint petitioners) each individually appealed FERC's order to Federal
court. The appeals were consolidated into one case by the court. On November 7,
2003 the United States Court of Appeals for the District of Columbia (the
"Court") issued its decision in the case of Consolidated Edison Company of New
York, Inc., v. Federal Energy Regulatory Commission ("Decision"). Essentially,
the Court found errors in the Commission's decision and remanded some issues in
the case back to the Commission for further explanation and action. The
Commission has not acted on the remand. At this time we can not predict the
outcome of the remand proceeding.
Foreign Currency Fluctuations
We follow the principles of SFAS 52, "Foreign Currency Translation" for
recording our investments in foreign affiliates. At December 31, 2003, the net
assets of these affiliates was approximately $323 million and at December 31,
2003, the accumulated after-tax foreign currency translation included in Other
Comprehensive Income was a credit of $26.5 million. (See Note 1 to the
Consolidated Financial Statements "Summary of Significant Accounting Policies.")
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Financially-Settled Commodity Derivative Instruments - Non-Regulated Hedging
Activities: From time to time, KeySpan subsidiaries have utilized derivative
financial instruments, such as futures, options and swaps, for the purpose of
hedging the cash flow variability associated with changes in commodity prices.
KeySpan is exposed to commodity price risk primarily with regard to its gas
exploration and production activities and its electric generating facilities.
Derivative financial instruments are employed by Houston Exploration to hedge
cash flow variability associated with forecasted sales of natural gas. The
Ravenswood facility uses derivative financial instruments to hedge the cash flow
variability associated with the purchase of natural gas and oil that will be
consumed during the generation of electricity. The Ravenswood facility also
hedges the cash flow variability associated with a portion of peak electric
energy sales.
For derivative instruments associated with gas exploration and production
activities, KeySpan uses standard New York Mercantile Exchange ("NYMEX") future
price quotes to value swap positions and published volatility in its
Black-Scholes calculation for outstanding options. Further, KeySpan uses
standard NYMEX futures prices to value gas futures contracts and market quoted
forward prices to value oil swap and natural gas basis swap contracts associated
with its Ravenswood facility. We also use market quoted forward prices to value
electric derivatives associated with the Ravenswood facility.
86
The following tables set forth selected financial data associated with these
derivative financial instruments that were outstanding at December 31, 2003.
- -----------------------------------------------------------------------------------------------------------------------------------
Year of Volumes Floor Ceiling Fixed Price Current Price Fair Value
Type of Contract Maturity (mmcf) ($) ($) ($) ($) ($000)
- -----------------------------------------------------------------------------------------------------------------------------------
Gas
Collars 2004 64,100 3.75-4.13 5.05-6.02 - 5.11 - 6.19 (29,449)
2005 36,500 4.50 5.50 - 4.65 - 5.61 (1,534)
Put Options - Short Natural Gas 2004 9,100 - - 5.00 5.11 - 5.26 4,228
Swaps/Futures - Short Natural Gas 2004 14,640 - - 4.96 5.11 - 6.19 (6,912)
2005 18,250 - - 4.77 4.65 - 5.61 (3,194)
Swaps/Futures - Long Natural Gas 2005 10 - - 4.95 4.65 (6)
- -----------------------------------------------------------------------------------------------------------------------------------
142,600 (36,867)
- -----------------------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------------
Year of Volumes Fixed Price Current Price Fair Value
Type of Contract Maturity (Barrels) ($) ($) ($000)
- --------------------------------------------------------------------------------------------------------------------------
Oil
Swaps - Long Fuel Oil 2004 100,548 20.55 - 29.60 28.28 - 32.42 361
2005 28,000 24.65 - 27.25 27.35 24
- --------------------------------------------------------------------------------------------------------------------------
128,548 385
- --------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------
Year of Fixed Price Current Price Fair Value
Type of Contract Maturity MWh ($) ($) ($000)
- ------------------------------------------------------------------------------------------------------------------------------
Electricity
Swaps - Energy 2004 580,000 14.00 - 28.00 14.10 - 39.33 259
- ------------------------------------------------------------------------------------------------------------------------------
The following tables detail the changes in and sources of fair value for the
above derivatives:
- ------------------------------------------------------------------------------
(In Thousands of Dollars) 2003
Change in Fair Value of Derivative Hedging Instruments ($000)
- ------------------------------------------------------------------------------
Fair value of contracts at January 1, $ (32,628)
Net losses on contracts realized 35,449
(Decrease) in fair value of all open contracts (39,045)
- ------------------------------------------------------------------------------
Fair value of contracts outstanding at December 31, $ (36,224)
- ------------------------------------------------------------------------------
87
- ---------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- ---------------------------------------------------------------------------------------------------------
Fair Value of Contracts
- ---------------------------------------------------------------------------------------------------------
Maturity Maturity Total
Sources of Fair Value In 12 Months in 2005 Fair Value
- ---------------------------------------------------------------------------------------------------------
Prices actively quoted $ (23,142) $ (3,677) $ (26,819)
Prices provided by external sources (3) - (3)
Prices based on models and
other valuation methods (8,992) (1,054) (10,046)
Local published indicies 620 24 644
- ---------------------------------------------------------------------------------------------------------
$ (31,517) $ (4,707) $ (36,224)
- ---------------------------------------------------------------------------------------------------------
Firm Gas Sales Derivative Instruments - Regulated Utilities: We use derivative
financial instruments to reduce the cash flow variability associated with the
purchase price for a portion of future natural gas purchases associated with our
Gas Distribution operations. The accounting for these derivative instruments is
subject to SFAS 71 "Accounting for the Effects of Certain Types of Regulation."
Therefore, changes in the fair value of these derivatives have been recorded as
a regulatory asset or regulatory liability on the Consolidated Balance Sheet.
Gains or losses on the settlement of these contracts are initially deferred and
then refunded to or collected from our firm gas sales customers consistent with
regulatory requirements.
The following table sets forth selected financial data associated with these
derivative financial instruments that were outstanding at December 31, 2003.
- -----------------------------------------------------------------------------------------------------------------------------------
Year of Volumes Floor Ceiling Fixed Price Current Price Fair Value
Type of Contract Maturity (mmcf) ($) ($) ($) ($) ($000)
- -----------------------------------------------------------------------------------------------------------------------------------
Options 2004 6,460 3.75 - 5.00 4.75 - 6.00 - 5.11 - 6.19 3,008
Swaps 2004 17,122 - - 4.42 - 6.23 5.11 - 6.19 6,501
2005 3,310 - - 4.61 - 5.65 4.65 - 5.61 352
- -----------------------------------------------------------------------------------------------------------------------------------
26,892 9,861
- -----------------------------------------------------------------------------------------------------------------------------------
See Note 8 to the Consolidated Financial Statements "Hedging, Derivative
Financial Instruments and Fair Values" for a further description of all our
derivative instruments.
88
Item 8. Financial Statements and Supplementary Data
CONSOLIDATED BALANCE SHEET
- --------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2003 2002
- --------------------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash and temporary cash investments $ 205,751 $ 170,617
Accounts receivable 1,029,459 1,122,022
Unbilled revenue 505,633 473,060
Allowance for uncollectible accounts (79,184) (63,029)
Gas in storage, at average cost 488,521 297,060
Material and supplies, at average cost 121,415 113,519
Other 115,304 93,980
-------------------------------------------
2,386,899 2,207,229
-------------------------------------------
Investments and Other 248,565 264,729
-------------------------------------------
Property
Gas 6,522,251 6,125,529
Electric 2,636,537 1,974,352
Other 425,576 394,374
Accumulated depreciation (2,610,876) (2,374,772)
Gas exploration and production, at cost 3,088,242 2,438,998
Accumulated depletion (1,167,427) (973,889)
-------------------------------------------
8,894,303 7,584,592
-------------------------------------------
Deferred Charges
Regulatory assets 564,985 438,516
Goodwill and other intangible assets, net
of amortization 1,809,712 1,796,225
Other 722,320 688,759
-------------------------------------------
3,097,017 2,923,500
-------------------------------------------
Total Assets $ 14,626,784 $ 12,980,050
===========================================
See accompanying Notes to the Consolidated Financial Statements.
89
CONSOLIDATED BALANCE SHEET
- ----------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2003 2002
- ----------------------------------------------------------------------------------------------------------
LIABILITIES AND CAPITALIZATION
Current Liabilities
Current redemption of long-term debt $ 1,471 $ 11,413
Accounts payable and other liabilities 1,141,597 1,096,654
Commercial paper 481,900 915,697
Dividends payable 72,289 64,714
Taxes accrued 46,580 51,276
Customer deposits 40,370 38,387
Interest accrued 64,609 77,092
----------------------------------------------
1,848,816 2,255,233
----------------------------------------------
Deferred Credits and Other Liabilities
Regulatory liabilities:
Miscellaneous liabilities 104,034 84,479
Removal costs recovered 450,034 -
Removal costs recovered - 365,744
Deferred income tax 1,273,651 877,013
Postretirement benefits and other reserves 961,962 759,731
Other 121,790 154,907
----------------------------------------------
2,911,471 2,241,874
----------------------------------------------
Commitments and Contingencies (See Note 7) - -
Capitalization
Common stock 3,487,645 3,005,354
Retained earnings 621,430 522,835
Accumulated other comprehensive income (68,640) (108,423)
Treasury stock (378,487) (475,174)
----------------------------------------------
Total common shareholders' equity 3,661,948 2,944,592
Preferred stock 83,568 83,849
Long-term debt 5,611,432 5,224,081
----------------------------------------------
Total Capitalization 9,356,948 8,252,522
----------------------------------------------
Minority Interest in Subsidiary Companies 509,549 230,421
----------------------------------------------
Total Liabilities and Capitalization $ 14,626,784 $ 12,980,050
==============================================
See accompanying Notes to the Consolidated Financial Statements.
90
CONSOLIDATED STATEMENT OF INCOME
- -------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars, Except Per Share Amounts) 2003 2002 2001
- -------------------------------------------------------------------------------------------------------------------------
Revenues
Gas Distribution $ 4,161,272 $ 3,163,761 $ 3,613,551
Electric Services 1,503,086 1,421,043 1,421,079
Energy Services 641,432 938,761 1,100,167
Gas Exploration and Production 501,255 357,451 400,031
Energy Investments 108,116 89,650 98,287
-------------------------------------------------------
Total Revenues 6,915,161 5,970,666 6,633,115
-------------------------------------------------------
Operating Expenses
Purchased gas for resale 2,495,102 1,653,273 2,171,113
Fuel and purchased power 414,633 395,860 538,532
Operations and maintenance 2,005,796 2,101,897 2,114,759
Depreciation, depletion and amortization 574,074 514,613 559,138
Operating taxes 418,236 381,767 448,924
-------------------------------------------------------
Total Operating Expenses 5,907,841 5,047,410 5,832,466
-------------------------------------------------------
Gain on sale of property 15,123 4,730 -
Income from equity investments 19,214 14,096 13,129
-------------------------------------------------------
Operating Income 1,041,657 942,082 813,778
-------------------------------------------------------
Other Income and (Deductions)
Interest charges (307,694) (301,504) (353,470)
Sale of subsidiary stock 13,356 - -
Cost of debt redemption (24,094) - -
Minority interest (63,852) (24,918) (40,847)
Other 42,119 25,169 34,924
-------------------------------------------------------
Total Other Income and (Deductions) (340,165) (301,253) (359,393)
-------------------------------------------------------
Income Taxes
Current (104,355) (24,212) 101,738
Deferred 381,666 267,691 108,955
-------------------------------------------------------
Total Income Taxes 277,311 243,479 210,693
-------------------------------------------------------
Earnings from Continuing Operations 424,181 397,350 243,692
-------------------------------------------------------
Discontinued Operations
Income (loss) from operations, net of tax - (3,356) 10,918
Loss on disposal, net of tax - (16,306) (30,356)
-------------------------------------------------------
Loss from Discontinued Operations - (19,662) (19,438)
-------------------------------------------------------
Cumulative Change in Accounting Principles, net of tax (37,451) - -
-------------------------------------------------------
Net Income 386,730 377,688 224,254
Preferred stock dividend requirements 5,844 5,753 5,904
-------------------------------------------------------
Earnings for Common Stock $ 380,886 $ 371,935 $ 218,350
=======================================================
Basic Earnings Per Share:
Continuing Operations, less preferred stock dividends $ 2.64 $ 2.77 $ 1.72
Discontinued Operations - (0.14) (0.14)
Change in Accounting Principles (0.23) - -
-------------------------------------------------------
Basic Earnings Per Share $ 2.41 $ 2.63 $ 1.58
=======================================================
Diluted Earnings Per Share
Continuing Operations, less preferred stock dividends $ 2.62 $ 2.75 $ 1.70
Discontinued Operations - (0.14) (0.14)
Change in Accounting Principles (0.23) - -
-------------------------------------------------------
Diluted Earnings Per Share $ 2.39 $ 2.61 $ 1.56
=======================================================
Average Common Shares Outstanding (000) 158,256 141,263 138,214
Average Common Shares Outstanding - Diluted (000) 159,232 142,300 139,221
- -------------------------------------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
91
CONSOLIDATED STATEMENT OF CASH FLOWS
- -------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2003 2002 2001
- -------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income $ 386,730 $ 377,688 $ 224,254
Adjustments to reconcile net income to net
cash provided by (used in) operating activities
Depreciation, depletion and amortization 574,074 514,613 559,138
Deferred income tax 189,275 90,724 108,955
Income from equity investments (18,038) (14,096) (13,129)
Dividends from equity investments 2,807 3,905 7,570
Amortization of interest rate swap (9,861) - -
(Gain) loss on disposal of subsidiary stock (13,356) - 19,438
Gain on sale of property (15,123) (4,730) -
Gain from class action settlement - - (33,510)
Provision for losses on contracting business - - 63,682
Change in accounting principle 37,451 - -
Environmental reserve adjustment (10,459) - -
Minority interest 63,852 24,918 40,847
Changes in assets and liabilities
Accounts receivable 77,750 (259,454) 401,976
Materials and supplies, fuel oil and gas in storage (199,357) 42,508 (43,856)
Accounts payable and accrued expenses 199,980 18,179 (400,636)
Reserve payments (36,486) (23,369) -
Other (44,596) (39,394) (44,548)
-----------------------------------------------------
Net Cash Provided by Operating Activities 1,184,643 731,492 890,181
-----------------------------------------------------
Investing Activities
Construction expenditures (1,011,716) (1,061,022) (1,059,759)
Other Investments (211,370) (27,579) -
Proceeds from sale of property and subsidiary stock 309,696 179,840 18,458
Issuance of long-term note (55,000) - -
Other - - (6)
-----------------------------------------------------
Net Cash (Used in) Investing Activities (968,390) (908,761) (1,041,307)
-----------------------------------------------------
Financing Activities
Treasury stock issued 96,687 86,710 88,786
Common stock issuance 473,573 - -
Issuance of long-term debt 1,024,912 549,280 812,116
Payment of long-term debt (605,625) (124,991) (183,410)
Payment of commercial paper (433,797) (132,753) (251,787)
Redemption of promissory notes (447,005) - -
Redemption of preferred stock (14,293) - -
Common and preferred stock dividends paid (280,560) (256,656) (251,502)
Termination of interest rate swaps - 57,415 -
Other 4,989 9,629 12,846
-----------------------------------------------------
Net Cash (Used in) Provided by Financing Activities (181,119) 188,634 227,049
-----------------------------------------------------
Net Increase in Cash and Cash Equivalents $ 35,134 $ 11,365 $ 75,923
Cash and Cash Equivalents at Beginning of Period 170,617 159,252 83,329
-----------------------------------------------------
Cash and Cash Equivalents at End of Period $ 205,751 $ 170,617 $ 159,252
=====================================================
Interest Paid $ 355,136 $ 343,933 $ 328,910
Income Tax Paid $ 65,495 $ 98,344 $ 128,558
- -------------------------------------------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
92
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
- --------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2003 2002 2001
- --------------------------------------------------------------------------------------------------------
Balance at Beginning of Period $522,835 $452,206 $480,639
Net Income for Period 386,730 377,688 224,254
- --------------------------------------------------------------------------------------------------------
909,565 829,894 704,893
Deductions:
Cash dividends declared on common stock 282,291 252,175 246,783
Cash dividends declared on preferred stock 5,844 5,753 5,904
MEDS Equity Units - 49,131 -
- --------------------------------------------------------------------------------------------------------
Balance at End of Period $621,430 $522,835 $452,206
- --------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
- ------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2003 2002 2001
- ------------------------------------------------------------------------------------------------------------------------------
Net Income $ 386,730 $ 377,688 $ 224,254
- ------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income, net of tax
Net losses (gains) on derivative instruments 23,042 (17,033) (27,690)
Reclassification adjustment for other gains reclassified to net income - - (3,242)
Foreign currency translation adjustments 28,696 9,759 (9,627)
Unrealized gains (losses) on marketable securities 8,480 (10,019) (5,464)
Premium on derivative instrument (3,437) - -
Accrued unfunded pension obligation 8,380 (55,768) (13,262)
Unrealized (losses) gains on derivative financial instruments (25,379) (39,845) 62,943
- ------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax 39,782 (112,906) 3,658
- ------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 426,512 $ 264,782 $ 227,912
- ------------------------------------------------------------------------------------------------------------------------------
Related tax (benefit) expense
Net losses (gains) on derivative instruments 12,407 (9,172) $ (14,910)
Reclassification adjustment for other gains reclassified to net income - - (1,746)
Foreign currency translation adjustments 15,451 5,255 (5,184)
Unrealized gains (losses) on marketable securities 4,568 (5,395) (2,942)
Accrued unfunded pension obligation 4,513 (30,029) (7,140)
Premium on derivative instrument (1,851) - -
Unrealized (losses) gains on derivative financial instruments (13,666) (21,454) 33,892
- ------------------------------------------------------------------------------------------------------------------------------
Total Tax (Benefit) Expense $ 21,422 $ (60,795) $ 1,970
- ------------------------------------------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
93
CONSOLIDATED STATEMENT OF CAPITALIZATION
- ------------------------------------------------------------------------------------------------------------------------------------
December 31,
(In Thousands of Dollars) 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------------
Common Shareholders' Equity Shares Issued
Common stock, $0.01 par Value 172,737,654 158,837,654 $ 1,727 $ 1,588
Premium on capital stock 3,485,918 3,003,766
Retained earnings 621,430 522,835
Other comprehensive income (68,640) (108,423)
Treasury stock 13,073,219 16,412,880 (378,487) (475,174)
- ------------------------------------------------------------------------------------------------------------------------------------
Total Common Shareholders' Equity 159,664,435 142,424,774 3,661,948 2,944,592
- ------------------------------------------------------------------------------------------------------------------------------------
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 85,676 88,486 8,568 8,849
- ------------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - No Redemption Required 83,568 83,849
- ------------------------------------------------------------------------------------------------------------------------------------
Long - Term Debt Interest Rate Maturity
- ------------------------------------------------------------------------------------------------------------------------------------
Notes
Medium term notes 4.65% - 9.75% 2005 - 2033 3,185,000 2,885,000
Senior secured notes 5.42% - 6.16% 2008-2013 96,425 -
Senior subordinated notes 7.0% 2013 175,000 100,000
- ------------------------------------------------------------------------------------------------------------------------------------
Total Notes 3,456,425 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
Pollution control revenue bonds 5.15% 2016 108,022 108,022
Electric facilities revenue bonds 5.30% 2023 - 2025 47,400 224,405
- ------------------------------------------------------------------------------------------------------------------------------------
Total Promissory Notes to LIPA 155,422 602,427
- ------------------------------------------------------------------------------------------------------------------------------------
MEDS Equity Units 8.75% 2005 460,000 460,000
Industrial Development Bonds 5.25% 2027 128,275 -
First Mortgage Bonds 5.50% - 10.10% 2003 - 2028 153,186 163,625
Authority Financing Notes Variable 2027 - 2028 66,005 66,005
Other Subsidiary Debt 145,612 304,298
Ravenswood Master Lease & Capital Leases 2005 - 2022 425,262 13,884
- ------------------------------------------------------------------------------------------------------------------------------------
Subtotal 5,638,687 5,243,739
Unamortized interest rate hedge and debt discount (69,243) (75,265)
Derivative impact on debt 43,459 67,020
Less: current maturities 1,471 11,413
- ------------------------------------------------------------------------------------------------------------------------------------
Total Long-Term Debt 5,611,432 5,224,081
- ------------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 9,356,948 $ 8,252,522
- ------------------------------------------------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
94
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 1.0 million electric customers of the Long Island Power Authority
("LIPA").
Our other subsidiaries are involved in gas and oil exploration and production;
gas storage; liquefied natural gas storage; wholesale and retail electric
marketing; appliance service; plumbing; heating, ventilation, air conditioning
and other mechanical services; large energy-system ownership, installation and
management; fiber optic services; and engineering and consulting services. We
also invest in, 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.)
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
95
and, as a result, we depend on the earnings and cash flow of, and dividends or
distributions from, our subsidiaries to provide the funds necessary to meet our
debt and contractual obligations. Furthermore, a substantial portion of our
consolidated assets, earnings and cash flow is derived from the operations of
our regulated utility subsidiaries, whose legal authority to pay dividends or
make other distributions to us is subject to regulation by state regulatory
authorities.
B. Basis of Presentation
The Consolidated Financial Statements presented herein reflect the accounts of
KeySpan and its subsidiaries. Most of our subsidiaries are fully consolidated in
the financial information presented, except for certain subsidiary investments
in the Energy 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. Certain reclassifications were made to conform prior period
financial statements to current period financial statement presentation. For
December 31, 2003, 2002 and 2001, we reclassified income from equity investments
and property sales from other income and (deductions) to operating income on the
Consolidated Statement of Income. On the 2001 Consolidated Statement of Cash
Flows, "minority interest", "changes in assets and liabilities - other", and
"(gain) loss on disposal of subsidiary stock" amounts have been reclassified.
The amount related to the loss from discontinued operations has been separately
identified as "(gain) loss on disposal of subsidiary stock". In addition,
"minority interest" was previously disclosed as a component of "changes in
assets and liabilities - other"; it has now been reclassified as a separate
line item for all periods presented.
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.
96
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 ten-year periods, ending 2009 and 2008, respectively. 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, 2003 and
December 31, 2002.
- ------------------------------------------------------------------------------------------------------------
December 31,
(In Thousands of Dollars) 2003 2002
- ------------------------------------------------------------------------------------------------------------
Regulatory Assets
Regulatory tax asset $ 47,236 $ 53,401
Property taxes 64,854 58,400
Environmental costs 296,888 182,163
Postretirement benefits 93,284 82,563
Costs associated with the KeySpan/LILCO transaction 50,585 61,989
Derivative Financial Instruments 6,909 -
Other 5,229 -
- ------------------------------------------------------------------------------------------------------------
Total Regulatory Assets $ 564,985 $ 438,516
Miscellaneous Regulatory Liabilities (104,034) (84,479)
- ------------------------------------------------------------------------------------------------------------
Net Regulatory Assets 460,951 354,037
Removal Costs Recovered (450,034) -
- ------------------------------------------------------------------------------------------------------------
$ 10,917 $ 354,037
- ------------------------------------------------------------------------------------------------------------
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 $53.4 million and $61.8 million at December 31, 2003 and December
31, 2002, 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 10
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
97
Discontinuation of Application of FASB Statement 71." We estimate that the
write-off of all net regulatory assets at December 31, 2003, before
consideration of removal costs recovered, could result in a charge to net income
of $300 million or $1.89 per share, which would be classified as an
extraordinary item. In 2003, KeySpan implemented SFAS 143 "Accounting for Asset
Retirement Obligations" and reclassified cost of removal accruals from
accumulated depreciation to regulatory liabilities. For the 2002 Consolidated
Balance Sheet presentation, these accruals are reflected as a separate line item
in deferred credits and other liabilities. In management's opinion, our
regulated subsidiaries that are currently subject to the provisions of SFAS 71
will continue to be subject to SFAS 71 for the foreseeable future.
D. Revenues
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.
KeySpan manages the day-to-day operations, maintenance and capital improvements
of the T&D system under a Management Service Agreement ("MSA"). In exchange for
providing the services, KeySpan earns a $10 million annual management fee.
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.
98
In addition, KeySpan sells to LIPA under a Power Supply Agreement ("PSA") 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. Rates charged to LIPA include a fixed and variable component. The variable
component is billed to LIPA on a monthly per megawatt hour basis and is
dependent on the number of megawatt hours dispatched. 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.
KeySpan also procures and manages fuel supplies on behalf of LIPA, under an
Energy Management Agreement ("EMA"), 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.
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. Each plant is 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.)
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 derived from service rendered under fixed
price, cost-plus, guaranteed maximum price, and time and materials-type
contracts and generally recognized on the percentage-of-completion method.
Percentage-of-completion is measured principally by 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. In the case of
customer change orders, estimated recoveries are included for work performed in
forecasting ultimate profitability on certain contracts. Due to uncertainties
inherent in the estimation process, changes in job performance, job conditions,
estimated profitability and final contract settlements may result in revisions
to estimated costs and, therefore, revenues. Such revisions to costs and income
are recognized in the period in which the revisions are determined.
99
Costs and estimated earnings in excess of billings on uncompleted contracts
arise when revenues have been recorded but the amounts cannot be billed under
the terms of the contracts. Such amounts are recoverable from customers upon
various measures of performance, including achievement of certain milestones,
completion of specified units or completion of the contract.
Also included in costs and estimated earnings on uncompleted contracts are
amounts to be collected from customers for changes in contract specifications or
design, contract change orders in dispute or unapproved as to scope or price, or
other customer-related causes of unanticipated additional contract costs. These
amounts are recorded at their estimated net realizable value when realization is
probable and can be reasonably estimated. Claims and unapproved change orders
involve negotiation and, in certain cases, litigation. Unapproved change orders
and claims also involve the use of estimates, and it is reasonably possible that
revisions to the estimated recoverable amounts of recorded change orders and
claims may be made in the near-term. If KeySpan does not successfully resolve
these matters, an expense may be required, in addition to amounts that have been
previously provided for. Claims against KeySpan are recognized when a loss is
considered probable and amounts are reasonably determinable.
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
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 $23.8 million and $19.2 million for the
years ended December 31, 2003, and December 31, 2002, respectively. These
balances represent primarily unearned revenues for service contracts and leases
on 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 five to 30 years.
Gas Exploration and Production: Natural gas and oil revenues earned by our gas
exploration and production activities are 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.
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 the years ended December 31, 2001 through
2003 ranged from 2.95% to 10.67%. Capitalized interest for 2003, 2002 and 2001
was $13.5 million, $19.7 million and $8.5 million, respectively.
100
Depreciation is provided on a straight-line basis in amounts equivalent to
composite rates on average depreciable property. The cost of property retired is
charged to accumulated depreciation.
KeySpan recovers certain asset retirement costs through rates charged to
customers as a portion of depreciation expense. At December 31, 2003 and 2002,
KeySpan had costs recovered in excess of costs incurred totaling $450 million
and $366 million, respectively. These amounts are reflected as a regulatory
liability for 2003 and in deferred credits and other liabilities for 2002 on the
Consolidated Balance Sheet.
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,
2003 2002 2001
- --------------------------------------------------------------------------
Electric 3.81% 3.88% 3.78%
Gas 3.37% 3.44% 3.40%
- --------------------------------------------------------------------------
We also had $425.6 million of other property at December 31, 2003, which is not
reflected in "rate base" for utility rate making purposes. This property
consists of assets held primarily by our Corporate Service subsidiary of $320.3
million and $105.3 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. We allocate the carrying
cost of these assets to our operating subsidiaries through our PUHCA allocation
methodology. Energy Services 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 unless they represent replacement of property to be capitalized.
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, 2003, we had exploration and production property in the amount
of $3.1 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 depletion
and 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.
101
These investments consist of our 55% 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
("KeySpan Exploration"), our wholly-owned subsidiary engaged in a joint venture
with Houston Exploration. 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, 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, 2003, we estimated, using a
wellhead price of $5.79 per MCF, that our capitalized costs did not exceed the
ceiling test limitation. At December 31, 2002, we estimated, using a wellhead
price of $4.35 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, a $42.0 million
impairment charge to write down our gas exploration and production assets was
recorded. This charge was recorded in depreciation, depletion and amortization
on the Consolidated Statement of Income. KeySpan's 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 a write down to the
full cost pool increases when, among other things, natural gas prices are
depressed, there are 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 amortized. For years ended December 31, 2003, 2002 and 2001,
capitalized interest was $7.3 million, $8.0 million and $12.0 million,
respectively.
102
G. Goodwill and Other Intangible Assets
The balance of goodwill and other intangible assets was $1.8 billion at December
31, 2003 and 2002, representing primarily the excess of acquisition cost over
the fair value of net assets acquired. Goodwill and other intangible assets
reflect the Eastern and ENI acquisitions, the KeySpan/LILCO transaction, as well
as acquisitions of energy-related service companies and also relates to certain
ownership interests of 50% or less in energy-related investments in Northern
Ireland which are accounted for under the equity method.
The table below summarizes the goodwill and other intangible assets balance for
each segment at December 31, 2003 and 2002:
- ----------------------------------------------------------------------------
(In Thousands of Dollars) Year Ended December 31,
- ----------------------------------------------------------------------------
Operating Segment 2003 2002
Gas Distribution $1,436,917 $1,436,917
Energy Services 172,874 148,596
Energy Investments and other 199,921 210,712
- ----------------------------------------------------------------------------
$1,809,712 $1,796,225
- ----------------------------------------------------------------------------
The increase in goodwill related to the Energy Services segment primarily
reflects the acquisition of Bard, Rao + Athanas Consulting Engineers, LLC.
("BR+A"), a Boston, Massachusetts company engaged in the business of providing
engineering services relating to heating, ventilation, and air conditioning
systems. The purchase price was approximately $35 million, plus up to $14.7
million in contingent consideration depending on the financial performance of
BR+A over the five-year period following the closing of the acquisition. We have
recorded goodwill of approximately $26 million and intangible assets of
approximately $2 million associated with this transaction. The intangible
assets, which relate primarily to a portion of the backlog purchased, as well as
to non-compete agreements entered into with all of the former owners of BR+A,
will be amortized over two and three years, respectively.
The decrease in goodwill related to Energy Investments and other primarily
reflects the sale of our 24.5% interest in Phoenix Natural Gas Limited, located
in Northern Ireland, and the related write-off of the goodwill associated with
this investment.
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
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. 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.
103
In the fourth quarter of 2003, KeySpan updated its review of the carrying value
of goodwill associated with the Energy Services segment. KeySpan employed a
combination of two methodologies in determining the fair value for its
investment in the Energy Services segment, a market valuation approach and an
income valuation approach. A third party specialist was engaged to assist with
the valuation and evaluate the reasonableness of key assumptions employed. Under
the market valuation approach, KeySpan compared relevant financial information
relating to the companies included in the Energy Services segment to the
corresponding financial information for a peer group of companies in the
specialty trade-contracting sector of the construction industry. Under the
income valuation approach, the fair value of a firm is obtained by discounting
the sum of (i) the expected future cash flows to a firm; and (ii) the terminal
value of a firm. As a result of our valuation, management has determined that
the fair value of the assets adequately exceeds their carrying value and no
impairment charge was necessary.
As required by SFAS 142, below is a reconciliation of reported earnings
available for common stockholders for the years ended December 31, 2003, 2002
and 2001 and pro-forma net income, for the same periods, adjusted for the
discontinuance of goodwill amortization.
- ------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars, Except for Per Share Amounts) 2003 2002 2001
- ------------------------------------------------------------------------------------------------------------------------
Earnings for common stockholders $ 380,886 $ 371,935 $ 218,350
Add back: goodwill amortization* - - 49,550
- ------------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 380,886 $ 371,935 $ 267,900
- ------------------------------------------------------------------------------------------------------------------------
Basic earnings per share $ 2.41 $ 2.63 $ 1.58
Add back: goodwill amortization - - 0.36
- ------------------------------------------------------------------------------------------------------------------------
Adjusted basic earnings per share $ 2.41 $ 2.63 $ 1.94
- ------------------------------------------------------------------------------------------------------------------------
Diluted earnings per share $ 2.39 $ 2.61 $ 1.56
Add back: goodwill amortization - - 0.36
- ------------------------------------------------------------------------------------------------------------------------
Adjusted diluted earnings per share $ 2.39 $ 2.61 $ 1.92
- ------------------------------------------------------------------------------------------------------------------------
* 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, goodwill amortization was
recorded in each segment as follows: Gas Distribution $35.6 million; Energy
Services $8.2 million; and Energy Investments and other $5.8 million.
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 was
reviewed if the facts and circumstances, such as significant declines in sales,
earnings or cash flows, or material adverse changes in the business climate,
suggested it might be impaired. If this review indicated that goodwill was not
recoverable, as determined based upon the estimated undiscounted cash flows of
the entity acquired, impairment was measured by comparing the carrying value of
the investment in such entity to its fair value. Fair value was 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.)
104
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-related 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 149,
"Amendment of Statement 133 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. Unrealized gains and losses (on such cash flow hedges) that are
recorded as other comprehensive income are subsequently reclassified into
earnings concurrent 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 England 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 regulatory assets or regulatory
liabilities 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.
105
Physically-Settled Commodity Derivative Instruments: Upon 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
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
Emerging Issues Task Force ("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 our cost of capital, 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.
106
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, 2003, 2002
and 2001, excise taxes collected and paid were $90.5 million, $83.1 million,
$119.1 million, respectively.
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, 2003 and 2002, the foreign currency
translation adjustment was included 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, 2003 we have approximately 2 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
85,676 shares of convertible preferred stock outstanding that can be converted
into 221,153 shares of common stock. These shares were not included in the
calculation of diluted EPS for the year ending December 31, 2001 since to do so
would have been anti-dilutive.
107
Under the requirements of SFAS 128, "Earnings Per Share" our basic and diluted
EPS are as follows:
- --------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars, Except Per Share Amounts) 2003 2002 2001
- --------------------------------------------------------------------------------------------------------------------------------
Earnings for common stock $ 380,886 $ 371,935 $ 218,350
Houston Exploration dilution (269) (471) (1,116)
Preferred stock dividend 514 531 -
- --------------------------------------------------------------------------------------------------------------------------------
Earnings for common stock - adjusted $ 381,131 $ 371,995 $ 217,234
- --------------------------------------------------------------------------------------------------------------------------------
Weighted average shares outstanding (000) 158,256 141,263 138,214
Add dilutive securities:
Options 755 809 1,007
Convertible preferred stock 221 228 -
- --------------------------------------------------------------------------------------------------------------------------------
Total weighted average shares outstanding - assuming dilution 159,232 142,300 139,221
- --------------------------------------------------------------------------------------------------------------------------------
Basic earnings per share $ 2.41 $ 2.63 $ 1.58
- --------------------------------------------------------------------------------------------------------------------------------
Diluted earnings per share $ 2.39 $ 2.61 $ 1.56
- --------------------------------------------------------------------------------------------------------------------------------
N. Stock Options and Other Stock Based Compensation
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 exercise periods between 5-10 years.
Up to approximately 21 million shares have been authorized for the issuance of
options and approximately 7.0 million of these shares were remaining at December
31, 2003. Moreover, under a separate plan, Houston Exploration has issued and
outstanding approximately 2.5 million stock options to key Houston Exploration
employees. 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 has
been recognized by employing the fair value recognition provisions of SFAS 123
"Accounting for Stock-Based Compensation" for grants awarded after January 1,
2003.
KeySpan and Houston Exploration continue to apply APB Opinion 25, "Accounting
for Stock Issued to Employees," and related Interpretations in accounting for
grants awarded prior to January 1, 2003. Accordingly, no compensation cost has
been recognized for these fixed stock option plans in the Consolidated Financial
Statements since the exercise prices and market values were equal on the grant
dates. Had compensation cost for these plans been determined based on the fair
value at the grant dates for awards under the plans consistent with SFAS 123,
our net income and earnings per share would have decreased to the pro-forma
amounts indicated below:
108
- ------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars, Except Per Share Amounts) 2003 2002 2001
- ------------------------------------------------------------------------------------------------------------------------------
Earnings available for common stock:
As reported $ 380,886 $ 371,935 $ 218,350
Add: recorded stock-based compensation expense, net of tax 3,650 221 261
Deduct: total stock-based compensation expense, net of tax (9,358) (7,547) (8,459)
- ------------------------------------------------------------------------------------------------------------------------------
Pro-forma earnings $ 375,178 $ 364,609 $ 210,152
- ------------------------------------------------------------------------------------------------------------------------------
Earnings per share:
Basic - as reported $ 2.41 $ 2.63 $ 1.58
Basic - pro-forma $ 2.37 $ 2.58 $ 1.52
Diluted - as reported $ 2.39 $ 2.61 $ 1.56
Diluted - pro-forma $ 2.36 $ 2.56 $ 1.50
- ------------------------------------------------------------------------------------------------------------------------------
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,
2003 2002 2001
- -------------------------------------------------------------------------------------------------
Fair value of grants issued $ 4.26 $ 3.42 $ 5.29
Dividend yield 5.49% 5.36% 4.91%
Expected volatility 24.26% 22.47% 29.04%
Risk free rate 3.16% 4.94% 5.13%
Expected lives 6 years 10 years 10 years
Exercise price $ 32.40 $ 32.66 $ 39.50
- -------------------------------------------------------------------------------------------------
A summary of the status of our fixed stock option plans and changes is presented
below for the periods indicated:
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
2003 2002 2001
- ------------------------------------------------------------------------------------------------------------------------------------
Weighted Weighted Weighted
Exercise Exercise Exercise
Fixed Options Shares Price Shares Price Shares Price
- ------------------------------------------------------------------------------------------------------------------------------------
Outstanding at beginning of period 9,524,900 $ 30.74 7,796,162 $ 29.67 6,456,627 $ 25.61
Granted during the year 1,650,450 $ 32.40 2,796,310 $ 32.66 2,285,350 $ 39.50
Exercised (664,902) $ 23.64 (506,794) $ 24.42 (809,983) $ 25.15
Forfeited (189,705) $ 34.63 (560,778) $ 30.99 (135,832) $ 29.19
- ------------------------------------------------------------------------------------------------------------------------------------
Outstanding at end of period 10,320,743 $ 31.39 9,524,900 $ 30.74 7,796,162 $ 29.67
- ------------------------------------------------------------------------------------------------------------------------------------
Exercisable at end of period 5,365,545 $ 28.76 4,105,999 $ 27.69 2,996,771 $ 24.86
- ------------------------------------------------------------------------------------------------------------------------------------
109
- ------------------------------------------------------------------------------------------------------------------------------------
Options Weighted Range of Options Weighted Range of
Remaining Outstanding at Average Exercise Exercisable at Average Exercise
Contractual Life December 31, 2003 Exercise Price Price December 31,2003 Exercise Price Price
- ------------------------------------------------------------------------------------------------------------------------------------
2 years 30,138 $ 25.98 $14.86 - 27.00 30,138 $ 25.98 $14.86 - 27.00
3 years 221,086 $ 30.43 $20.57 - 30.50 221,086 $ 30.43 $20.57 - 30.50
4 years 301,410 $ 32.56 $19.15 - 32.63 301,410 $ 32.56 $19.15 - 32.63
5 years 1,359,727 $ 27.86 $24.73 - 29.38 1,359,727 $ 27.86 $24.73 - 29.38
6 years 652,344 $ 26.97 $21.99 - 27.06 652,344 $ 26.97 $21.99 - 27.06
7 years 1,567,924 $ 22.79 $22.50 - 32.76 1,546,262 $ 22.64 $22.50 - 32.76
8 years 2,012,038 $ 39.50 $39.50 805,553 $ 39.50 $39.50
9 years 2,565,404 $ 32.66 $32.66 449,025 $ 32.66 $32.66
10 years 1,610,672 $ 32.40 $32.40 - $ 32.40 $32.40
- ------------------------------------------------------------------------------------------------------------------------------------
10,320,743 5,365,545
- ------------------------------------------------------------------------------------------------------------------------------------
In early 2003, KeySpan's Board of Directors approved a modification to the
Long-Term Incentive Compensation Plan design and its application to officers of
KeySpan. Long-term incentive compensation for officers 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
In January 2003, the Financial Accounting Standards Board ("FASB") issued FASB
Interpretation No. 46 ("FIN 46"), "Consolidation of Variable Interest Entities,
an Interpretation of ARB No. 51" which was revised in December 2003. 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 was 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
original provisions of FIN 46 were to be applied for the first interim or annual
period beginning after June 15, 2003. In October, the FASB delayed
implementation of FIN 46 until the fourth quarter 2003 for certain variable
interest entities. We currently have an arrangement with a variable interest
entity through which we lease a portion of the Ravenswood facility. As required
by FIN 46, this variable entity was consolidated at December 31, 2003. (See Note
7 "Contractual Obligations, Financial Guarantees and Contingencies - Variable
Interest Entity" for a detailed description of this leasing arrangement.)
In April 2003, the FASB issued SFAS 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." This Statement amends and
clarifies financial accounting and reporting for derivative instruments,
including certain instruments embedded in other contracts and for hedging
activities under Statement No. 133, "Accounting for Derivative Instruments and
Hedging Activities." This Statement: (i) clarifies under what circumstances a
contract with an initial net investment meets the characteristic of a
derivative; (ii) clarifies when a derivative contains a financing component;
(iii) amends the definition of an underlying; and (iv) amends certain other
existing pronouncements. The implementation of this Statement will not have a
significant impact on our results of operations, financial condition or cash
flows since our derivative instruments that meet the definition of a derivative
and qualify for hedge accounting treatment will continue to do so. The Statement
was effective for contracts entered into or modified after June 30, 2003.
110
In May 2003, the FASB issued SFAS 150, "Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and Equity." This Statement
establishes standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and equity. It
requires that an issuer classify certain financial instruments as a liability
(or an asset in some circumstances) when there is an obligation to redeem the
issuer's shares and either requires or may require satisfaction of the
obligation by transferring assets, or satisfy the obligation by issuing
additional equity shares subject to certain criteria. This Statement was
effective for financial instruments entered into or modified after May 31, 2003,
and otherwise was effective at the beginning of the first interim period
beginning after June 15, 2003. It is to be implemented by reporting the
cumulative effect of a change in an accounting principle for financial
instruments created before the issuance date of the Statement and still existing
at the beginning of the interim period of adoption. The implementation of this
Statement did not have an impact on our results of operations, financial
condition or cash flows.
In July 2003, the FASB concluded its discussions on EITF 03-11 "Reporting
Realized Gains and Losses on Derivative Instruments That Are Subject to FASB
Statement No. 133 Accounting for Derivative Instruments and Hedging Activities
and Not Held for Trading Purposes as Defined in EITF Issue No. 02-3 Issues
Involved in Accounting for Derivative Contracts held for Trading Purposes and
Contracts Involved in Energy Trading and Risk Management Activities." The Task
Force reached a consensus that determining whether realized gains or losses on
physically settled derivative contracts not "held for trading purposes" should
be reported in the income statement on a gross or net basis is a matter of
judgment that depends on the relevant facts and circumstances. KeySpan reports
realized gains or losses on its derivative instruments that hedge the cash flow
variability associated with the forecasted sales of natural gas and electricity
in its reported revenues at time of their settlement. Realized gains or losses
on derivative instruments that hedge the cash flow variability associated with
the forecasted purchase of natural gas or fuel oil are reported in operating
expense. We believe that this EITF does not have a significant impact on our
results of operations, financial condition or cash flows. This Statement was
effective October 1, 2003.
In December 2003, the FASB issued SFAS 132 (revised 2003) "Employers'
Disclosures about Pensions and Other Postretirement Benefits." This Statement
revises employers' disclosures about pension and other postretirement benefit
plans. This Statement retains the disclosure requirements contained in FASB
Statement 132 "Employers' Disclosures about Pensions and Other Postretirement
Benefits", which it replaces. It requires additional disclosures to those in the
original Statement 132 about assets, obligations, cash flows, and net periodic
benefit cost of defined benefit pension plans and other defined benefit
postretirement plans. KeySpan has implemented all the requirements of this
Statement in Footnote 4 "Postretirement Benefits."
P. Impact of Cumulative Effect of Change in Accounting Principles
KeySpan has an arrangement with a variable interest entity through which it
leases a portion of the 2,200-megawatt Ravenswood electric generation facility.
On December 31, 2003, KeySpan adopted FIN 46. This pronouncement required
KeySpan to consolidate its variable interest entity, which had a fair market
value of a $425 million at the inception of the lease, June 1999. As a result,
KeySpan recorded a $37.6 million after-tax charge, or $0.23 per share, change in
accounting principle on the Consolidated Statement of Income, representing
approximately four and a half years of depreciation. (See Note 7, "Contractual
Obligations, Financial Guarantees and Contingencies - Variable Interest Entity"
for a detailed description of the impact of the adoption of this standard.)
111
On January 1, 2003, KeySpan adopted 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. The cumulative
effect of SFAS 143 and the change in accounting principle was a benefit to net
income of $0.2 million, after-tax. (See Note 7, "Contractual Obligations,
Financial Guarantees and Contingencies - Asset Retirement Obligation" for
further details.)
Under Accounting Principle Board Opinion No. 20 ("APB 20"), the pro-forma impact
of the retroactive application resulting from the adoption of a change in
accounting principle is to be disclosed as follows:
- ----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars, Except Per Share Amounts) 2003 2002 2001
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings for common stock $ 380,886 $ 371,935 $ 218,350
Add back: Cumulative effect of a change in accounting principle 37,451 - -
Earnings for common stock before cumulative effect of a change in
accounting principle:
As reported 418,337 371,935 218,350
Less: SFAS 143 Accretion expense, net of taxes - (1,135) (1,067)
Less:FIN 46 Depreciation expense, net of taxes (9,538) (8,024) (8,024)
Add: SFAS 143 Costs of removal expense, net of taxes - 471 471
- ----------------------------------------------------------------------------------------------------------------------------------
Pro-forma earnings $ 408,799 $ 363,247 $ 209,730
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings per share before cumulative change in accounting principle:
Basic - as reported $ 2.64 $ 2.63 $ 1.58
Basic - pro-forma $ 2.58 $ 2.57 $ 1.52
Diluted - as reported $ 2.62 $ 2.61 $ 1.56
Diluted - pro-forma $ 2.57 $ 2.55 $ 1.51
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings per share for common stock:
Basic - as reported $ 2.41 $ 2.63 $ 1.58
Basic - pro-forma $ 2.58 $ 2.57 $ 1.52
Diluted - as reported $ 2.39 $ 2.61 $ 1.56
Diluted - pro-forma $ 2.57 $ 2.55 $ 1.51
- ----------------------------------------------------------------------------------------------------------------------------------
Q. Accumulated Other Comprehensive Income
As required by SFAS 130, "Reporting Comprehensive Income", the components of
accumulated other comprehensive income are as follows:
- ---------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2003 2002
- ---------------------------------------------------------------------------------------------
Foreign currency translation adjustments $ 26,523 $ (2,173)
Unrealized (losses) on marketable securities (7,530) (16,012)
Premium on derivative instrument (3,437) -
Accrued unfunded pension obligation (60,650) (69,031)
Unrealized (losses) on derivative financial instruments (23,546) (21,207)
- ---------------------------------------------------------------------------------------------
Accumulated other comprehensive income $(68,640) $ (108,423)
- ---------------------------------------------------------------------------------------------
112
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 three to eleven years
and Power Purchase agreements for 25 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. KeySpan is currently analyzing proposals from
interested investors to participate in a leveraged lease financing of a new 250
MW combined cycle electric generating facility located at the existing
Ravenswood facility site. (See Note 15, "Subsequent Events" for further
details.)
The Energy Services segment includes companies that provide energy-related and a
minimal amount of fiber optic services to customers primarily located within the
Northeastern United States, with concentrations in the New York City
metropolitan area, including New Jersey and Connecticut, as well as Rhode
Island, Pennsylvania, Massachusetts and New Hampshire, through the following
lines of business: (i) Home Energy Services, which provides residential
customers with service and maintenance of energy systems and appliances, as well
as the retail marketing of electricity to commercial customers; and (ii)
Business Solutions, which provides plumbing, heating, ventilation, air
conditioning and mechanical services, as well as operation and maintenance,
design, engineering and consulting services to commercial and industrial
customers.
In 2003, KeySpan Services, Inc. and its wholly-owned subsidiary Paulus,
Sokolowski, and Sartor, LLC. acquired Bard, Rao + Athanas Consulting Engineers,
LLC. ("BR+A"), a Boston, Massachusetts company engaged in the business of
providing engineering services relating to heating, ventilation, and air
conditioning systems. The purchase price was approximately $35 million, plus up
to $14.7 million in contingent consideration depending on the financial
performance of BR+A over the five-year period following the closing of the
acquisition. We have recorded goodwill of $26 million and intangible assets of
$2 million associated with this transaction. The intangible assets, which relate
primarily to a portion of the backlog purchased, as well as to non-compete
113
agreements entered into with all of the former owners of BR+A, will be amortized
over two and three years, respectively. In 2003, KeySpan's gas and electric
marketing subsidiary, KeySpan Energy Services Inc., assigned the majority of its
retail natural gas customers, consisting mostly of residential and small
commercial customers, to ECONnergy Energy Co., Inc. ("ECONnergy"). KeySpan
Energy Services will continue its electric marketing activities.
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 55%
equity interest in The Houston Exploration Company ("Houston Exploration"), an
independent natural gas and oil exploration company, as well as our wholly-owned
subsidiary KeySpan Exploration and Production, LLC, our wholly owned subsidiary
engaged in a joint venture with Houston Exploration. In February 2003, we
reduced our ownership interest in Houston Exploration from 66% to approximately
55% following the repurchase, by Houston Exploration, of three million shares of
common stock owned by KeySpan. We realized net proceeds of $79 million in
connection with this repurchase. KeySpan follows an accounting policy of income
statement recognition for Parent company gains or losses from common stock
transactions initiated by its subsidiaries. As a result, KeySpan realized a gain
of $19 million on this transaction, which is reflected in other income and
(deductions) on the Consolidated Statement of Income. Income taxes were not
provided, since this transaction was structured as a return of capital.
In the fourth quarter of 2003, Houston Exploration acquired the entire Gulf of
Mexico shallow-water asset base of Transworld Exploration and Production, Inc.
for $149 million. The properties, which are 75% natural gas, have proven
reserves of 92 billion cubic feet of natural gas equivalent. Current production
from 11 fields is approximately 35 million cubic feet of natural gas equivalent
per day. Houston Exploration funded the transaction from its bank revolving
credit facility and with cash on hand at the time of closing.
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; and a 50% interest in the Premier
Transmission Pipeline Limited in Northern Ireland. These subsidiaries are
accounted for under the equity method. Accordingly, equity income from these
investments is reflected as a component of operating income in the Consolidated
Statement of Income. In the fourth quarter of 2003, we completed the sale of our
24.5% interest in Phoenix Natural Gas Limited for $96 million and recorded a
pre-tax gain of $24.7 million in other income and (deductions) on the
Consolidated Statement of Income.
We also have investments in certain midstream natural gas assets in Western
Canada through KeySpan Canada. These assets include 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. In 2003, we
sold a portion of our interest in KeySpan Canada through the establishment of an
open-ended income fund trust ("KeySpan Facilities Income Fund" or the "Fund")
organized under the laws of Alberta, Canada. The Fund acquired a 39.09%
ownership interest in KeySpan Canada through an indirect subsidiary, and then
114
issued 17 million trust units to the public through an initial public offering.
Each trust unit represents a beneficial interest in the Fund and is registered
on the Toronto Stock Exchange under the symbol KEY.UN. Additionally, we sold our
20% interest in Taylor NGL LP that owns and operates two extraction plants also
in Canada to AltaGas Services, Inc. Net proceeds of $119.4 million from the two
sales, plus proceeds of $45.7 million drawn under a new credit facility made
available to KeySpan Canada, were used to pay down existing KeySpan Canada
credit facilities of $160.4 million. A pre-tax loss of $30.3 million was
recognized on the transactions and is included in other income and (deductions)
on the Consolidated Statement of Income. These transactions produced a tax
expense of $3.8 million as a result of certain United States partnership tax
rules and resulted in an after-tax loss of $34.1 million. In February 2004,
KeySpan entered into an agreement to sell an additional 36% of its interest in
KeySpan Canada. (See Note 15 to the Consolidated Financial Statements,
"Subsequent Events.")
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 operating income basis. Due to the July 2002 sale of Midland
Enterprises LLC, an inland marine barge business, this subsidiary is reported as
discontinued operations for 2002 and 2001. (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 Electric Energy Gas Exploration Other
(In Thousands of Dollars) Distribution Services Services and Production Investments Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2003
Unaffiliated revenue 4,161,272 1,503,086 641,432 501,255 108,116 - 6,915,161
Intersegment revenue - 101 8,158 - 5,008 (13,267) -
Depreciation, depletion and
amortization 259,934 66,843 9,869 204,102 19,046 14,280 574,074
Sales of property 15,123 - - - - - 15,123
Income from equity investments - - - - 19,106 108 19,214
Operating income 574,254 268,977 (38,066) 197,209 41,345 (2,062) 1,041,657
Interest income 1,194 4,628 1,070 - 1,002 (2,235) 5,659
Interest charges 203,733 43,065 16,863 8,504 7,541 27,988 307,694
Total assets 8,444,071 2,473,076 445,534 1,530,875 915,383 817,845 14,626,784
Equity method investments - - - - 97,018 - 97,018
Construction expenditures 419,549 256,498 9,305 295,943 18,154 12,267 1,011,716
- ------------------------------------------------------------------------------------------------------------------------------------
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 $1.5 billion for the year
ended December 31, 2003, represents approximately 22% of our consolidated
revenues during that period.
115
- ------------------------------------------------------------------------------------------------------------------------------------
Gas Electric Energy Gas Exploration Other
(In Thousands of Dollars) Distribution Services Services and 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
Sales of property 903 1,479 - - 2,348 - 4,730
Income from equity investments - - - - 13,992 104 14,096
Operating income 531,134 288,796 (11,935) 110,259 32,335 (8,507) 942,082
Interest income 2,020 1,834 1,248 - 238 (3,768) 1,572
Interest charges 215,140 57,589 19,386 7,303 6,858 (4,772) 301,504
Total assets 7,783,011 1,775,244 497,269 1,187,425 974,409 762,692 12,980,050
Equity method investments - - - - 130,815 - 130,815
Construction expenditures 412,433 348,147 11,648 241,477 31,243 16,074 1,061,022
- ------------------------------------------------------------------------------------------------------------------------------------
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, 2002 represents approximately 24% of our consolidated
revenues during that period.
- ------------------------------------------------------------------------------------------------------------------------------------
Gas Electric Energy Gas Exploration Other
(In Thousands of Dollars) Distribution Services Services and Production Investments Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2001
Unaffiliated revenue 3,613,551 1,421,079 1,100,167 400,031 98,287 - 6,633,115
Intersegment revenue - 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
Operating income 481,393 269,721 (147,485) 159,661 19,122 31,366 813,778
Interest income 3,879 433 3,185 - 334 495 8,326
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.
116
Note 3. Income Tax
KeySpan files a consolidated federal income tax return. A tax sharing agreement
between the 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 return. 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) 2003 2002 2001
- ------------------------------------------------------------------------------
Current income tax $(104,355) $ (24,212) $101,738
Deferred income tax 381,666 267,691 108,955
- ------------------------------------------------------------------------------
Total income tax $277,311 $243,479 $210,693
- ------------------------------------------------------------------------------
At December 31, the significant components of KeySpan's deferred tax assets and
liabilities calculated under the provisions of SFAS No.109 "Accounting for
Income Taxes" were as follows:
- ------------------------------------------------------------------------------
December 31,
(In Thousands of Dollars) 2003 2002
- ------------------------------------------------------------------------------
Reserves not currently deductible $ 34,342 $ 38,275
New York corporation income tax (56,188) (13,997)
Property related differences (1,049,237) (818,116)
Regulatory tax asset (16,532) (18,690)
Property taxes (98,089) (52,339)
Other items - net (87,947) (12,146)
- ------------------------------------------------------------------------------
Net deferred tax liability $(1,273,651) $ (877,013)
- ------------------------------------------------------------------------------
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. 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.
The federal income tax amounts included in the Statement of Income differ from
the amounts which result from applying the statutory federal income tax rate to
income before income tax.
117
The table below sets forth the reasons for such differences:
- ---------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2003 2002 2001
- ---------------------------------------------------------------------------------------------------------------
Computed at the statutory rate $ 245,522 $ 224,290 $ 159,035
Adjustments related to:
Tax credits - (1,026) (1,100)
Removal costs (6,592) (4,787) (1,470)
Accrual to return adjustment 549 (9,539) 2,354
Goodwill amortization - - 21,126
Minority interest in Houston Exploration 19,969 9,490 13,862
State income tax 28,462 42,125 26,418
Other items - net (10,599) (17,074) (9,532)
- ---------------------------------------------------------------------------------------------------------------
Total income tax $ 277,311 $ 243,479 $ 210,693
- ---------------------------------------------------------------------------------------------------------------
Effective income tax rate (1) 40% 38% 46%
- ---------------------------------------------------------------------------------------------------------------
(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 and Boston Gas Company are subject to certain deferral accounting
requirements mandated by the NYPSC and DTE, respectively for pension costs and
other postretirement benefit costs.
Information pertaining to discontinued operations has been excluded from this
presentation.
The calculation of net periodic pension cost is as follows:
- ---------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2003 2002 2001
- ---------------------------------------------------------------------------------------------------------------------------------
Service cost, benefits earned during the period $ 47,531 $ 42,423 $ 41,162
Interest cost on projected benefit obligation 138,270 132,424 128,481
Expected return on plan assets (130,556) (157,958) (180,757)
Net amortization and deferral 66,949 (4,247) (39,772)
- ---------------------------------------------------------------------------------------------------------------------------------
Total pension (benefit) cost $ 122,194 $ 12,642 $ (50,886)
- ---------------------------------------------------------------------------------------------------------------------------------
118
The following table sets forth the pension plans' funded status at December 31,
2003 and December 31, 2002.
- ------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2003 2002
- ------------------------------------------------------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation at beginning of period $ (2,080,193) $ (1,915,154)
Service cost (47,531) (42,423)
Interest cost (138,270) (132,424)
Amendments (3,079) (2,932)
Actuarial loss (192,617) (103,988)
Benefits paid 118,494 116,728
- ------------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period (2,343,196) (2,080,193)
- ------------------------------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of period 1,544,518 1,899,256
Actual return on plan assets 335,757 (347,270)
Employer contribution 93,458 109,260
Benefits paid (118,494) (116,728)
- ------------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period 1,855,239 1,544,518
- ------------------------------------------------------------------------------------------------------------------------
Funded status (487,957) (535,675)
Unrecognized net loss from past experience different from that assumed
and from changes in assumptions 557,204 627,199
Unrecognized prior service cost 64,925 71,126
Unrecognized transition obligation - 237
- ------------------------------------------------------------------------------------------------------------------------
Net prepaid pension cost reflected on consolidated balance sheet $ 134,172 $ 162,887
- ------------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------
Year Ended December 31,
2003 2002 2001
- -----------------------------------------------------------------------------------------------
Assumptions:
Obligation discount 6.25% 6.75% 7.00%
Asset return 8.50% 8.50% 8.50%
Average annual increase in compensation 4.00% 4.00% 4.00%
- -----------------------------------------------------------------------------------------------
Unfunded Pension Obligation: At December 31, 2003 the accumulated benefit
obligation was in excess of pension assets. As prescribed by SFAS 87 "Employers'
Accounting for Pensions," KeySpan had a $244.4 million minimum liability at
December 31, 2003, for this unfunded pension obligation. As permitted under
current accounting guidelines, these accruals 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 on the Consolidated Balance Sheet.
119
Therefore, at year-end, we had a long-term asset in deferred charges other of
$55.3 million, representing the amount of unrecognized prior service cost and a
debit to other comprehensive income of $93.3 million, or $60.6 million
after-tax. The remaining amount of $95.8 was recorded as a contractual
receivable, representing the amount that would have been 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.
At December 31, 2003 the projected benefit obligation, accumulated benefit
obligation and value of assets for plans with accumulated benefit obligations in
excess of plan assets were $1.2 billion, $1.1 billion and $794 million.
At December 31, 2002, the accumulated benefit obligation was also in excess of
pension assets. As a result, we had an additional minimum liability of $286.3
million, a long-term asset in deferred charges other of $61.5 million, and a
debit to other comprehensive income of $106.2 million, or $69.0 million
after-tax. The remaining amount of $118.6 was recorded as a contractual
receivable from LIPA.
At December 31, 2002 the projected benefit obligation, accumulated benefit
obligation and value of assets for plans with accumulated benefit obligations in
plan assets were $1.1 billion, $948 million and $621 million, respectively.
At the end of the year, we will re-measure the accumulated benefit obligation
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) 2003 2002 2001
- -------------------------------------------------------------------------------------------------------
Service cost, benefits earned during the period $ 18,825 $ 16,566 $ 20,339
Interest cost on accumulated
postretirement benefit obligation 69,803 65,486 64,649
Expected return on plan assets (27,530) (36,839) (42,822)
Net amortization and deferral 35,815 17,527 11,664
- -------------------------------------------------------------------------------------------------------
Other postretirement cost $ 96,913 $ 62,740 $ 53,830
- -------------------------------------------------------------------------------------------------------
120
The following table sets forth the plans' funded status at December 31, 2003 and
December 31, 2002.
- ---------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2003 2002
- ---------------------------------------------------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation at beginning of period $(1,056,944) $ (969,692)
Service cost (18,825) (16,566)
Interest cost (69,803) (65,486)
Plan participants' contributions (1,757) (1,587)
Amendments 35,458 57,984
Actuarial (loss) (209,446) (115,563)
Benefits paid 53,693 53,966
- ---------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period (1,267,624) (1,056,944)
- ---------------------------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of period 361,166 476,146
Actual return on plan assets 85,625 (82,950)
Employer contribution 43,578 20,349
Plan participants' contributions 1,757 1,587
Benefits paid (53,693) (53,966)
- ---------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period 438,433 361,166
- ---------------------------------------------------------------------------------------------------------------------
Funded status (829,191) (695,778)
Unrecognized net loss from past experience different from that assumed
and from changes in assumptions 573,277 464,269
Unrecognized prior service cost (89,034) (60,104)
- ---------------------------------------------------------------------------------------------------------------------
Accrued postretirement cost reflected on consolidated balance sheet $ (344,948) $ (291,613)
- ---------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------
Year Ended December 31,
2003 2002 2001
- ------------------------------------------------------------------------------------------------
Assumptions:
Obligation discount 6.25% 6.75% 7.00%
Asset return 8.50% 8.50% 8.50%
Average annual increase in compensation 4.00% 4.00% 4.00%
- ------------------------------------------------------------------------------------------------
The measurement of plan liabilities also assumes a health care cost trend rate
of 11% grading down to 5% over five years, and 5% 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, 2003 by $149.9
million and the net periodic health care expense by $12.3 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, 2003 by $131.8
million and the net periodic health care expense by $10.5 million.
121
At December 31, 2003, KeySpan had a contractual receivable from LIPA of $226.3
million representing the postretirement benefits associated with the electric
business unit employees recorded in deferred charges other on 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.
KeySpan's retiree health benefit plan currently includes a prescription drug
benefit that is provided to retired employees. In December 2003, new Medicare
legislation (the Medicare Prescription Drug, Improvement and Modernization Act
of 2003 - "the Medicare Act") was enacted that may ultimately affect KeySpan's
obligations and expense related to retiree health benefits. Keyspan has elected
to defer accounting for the effects of the Medicare Act, as permitted by FASB
Staff Position 106-1 "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003".
Therefore, any measure of the accumulated postretirement benefit obligation or
retiree benefit costs reflected in the accompanying notes do not reflect the
effects of this new legislation. In consideration of this new law, KeySpan may
need to amend certain benefit plans and, therefore, the impact of the Medicare
Act on KeySpan's financial condition and cash flows can not be determined with
any degree of certainty at this time. Further, the FASB will be issuing specific
guidance on the accounting for the subsidy arising under the Medicare Act and
that guidance, when issued, could require KeySpan to change previously reported
information.
Pension/Other Post Retirement Benefit Plan Assets: Keyspan's weighted average
asset allocations at December 31, 2003 and 2002, by asset category, for both the
pension and other postretirement benefit plans are as follows:
- ---------------------------------------------------------------------------------------------
Pension OPEB
Asset Category 2003 2002 2003 2002
- ---------------------------------------------------------------------------------------------
Equity securities 61% 54% 68% 60%
Debt securities 31% 30% 26% 28%
Cash and equivalents 2% 8% 2% 7%
Venture capital 6% 8% 4% 5%
- ---------------------------------------------------------------------------------------------
Total 100% 100% 100% 100%
- ---------------------------------------------------------------------------------------------
The long-term rate of return on assets (pre-tax) is assumed to be 8.5% which
management believes is an appropriate long-term expected rate of return on
assets based on our investment strategy, asset allocation mix and the historical
performance of equity investments over long periods of time. The actual ten-
year compound rate of return for our Plans is greater than 8.5%.
Our master trust investment allocation policy target for the assets of the
pension and other postretirement benefit plans is 70% equity and 30% fixed
income.
During 2003, KeySpan conducted an asset and liability study projecting asset
returns and expected benefit payments over a ten-year period. Based on the
results of the study, KeySpan has developed a multi-year funding strategy for
its plans. We believe that it is reasonable to assume assets can achieve or
outperform the assumed long-term rate of return with the target allocation as a
result of historical out-performance of equity investments over long-term
periods.
122
Cash Contributions: In 2004, KeySpan is expected to contribute approximately $89
million to its pension plans and approximately $58 million to its other
postretirement benefit plans.
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. The
matching contributions are in KeySpan's common stock. For the years ended
December 31, 2003, 2002 and 2001, we recorded an expense of $11.2 million, $11.2
million, and $11.0 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, 2003, we had 13.1 million
shares, or approximately $378.5 million of treasury stock outstanding. We
completed this repurchase plan in 1999 and have since utilized treasury stock to
satisfy our common stock benefit plans. During 2003, we issued 3.3 million
shares out of treasury for the dividend reinvestment feature of our Investor
Program, the Employee Stock Discount Purchase Plan, the 401(k) Plan and Stock
Option Plans.
On January 17, 2003, we issued 13.9 million shares of common stock in a public
offering that generated net proceeds of approximately $473 million. All shares
were offered by KeySpan pursuant to an effective shelf registration statement
filed with the SEC.
Preferred Stock: We have the authority to issue 100,000,000 shares of preferred
stock with the following classifications: 16,000,000 shares of preferred stock,
par value $25 per share; 1,000,000 shares of preferred stock, par value $100 per
share; and 83,000,000 shares of preferred stock, par value $.01 per share.
At December 31, 2003 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 85,676 shares outstanding of 6% Preferred Stock
Series A par value $100, in the aggregate totaling $83.6 million.
123
In September 2003, the Boston Gas Company redeemed all 562,700 shares of its
outstanding Variable Term Cumulative Preferred Stock, 6.42% Series A at its par
value of $25 per share. The total payment was $14.3 million, which included $0.2
million of accumulated dividends. This preferred stock series had been reflected
as Minority Interest on KeySpan's Consolidated Balance Sheet.
Note 6. Long-Term Debt
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, 2003, each of which is guaranteed by KeySpan.
Further, KeySpan had $2.36 billion of medium and long term notes outstanding at
December 31, 2003 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 notes of $710 million have
interest rates ranging from 6.15% to 9.75% and mature in 2005-2025.
In 2003, we issued $300 million of medium-term and long-term debt. The debt was
issued in the following two series: (i) $150 million 4.65% Notes due 2013; and
(ii) $150 million 5.875% Notes due 2033. The proceeds of this issuance were used
to pay down outstanding commercial paper.
Also during 2003, KeySpan Canada, issued Cdn$125 million, or approximately US$93
million, long-term secured notes in a private placement to investors in Canada
and the United States. The notes were issued in the following three series: (i)
Cdn$20 million 5.42% senior secured notes due 2008; (ii) Cdn$52.5 million 5.79%
senior secured notes due 2010; and (iii) Cdn$52.5 million 6.16% senior secured
notes due 2013. The proceeds of the offering have been used to re-pay KeySpan
Canada's credit facility.
In 2003 Houston Exploration finalized a private placement issuance of $175
million of 7.0%, senior subordinated notes due 2013. Interest payments began on
December 15, 2003, and will be paid semi-annually thereafter. The notes will
mature on June 15, 2013. Houston Exploration has the right to redeem the notes
as of June 15, 2008, at a price equal to the issue price plus a specified
redemption premium. Until June 15, 2006, Houston Exploration may also redeem up
to 35% of the notes at a redemption price of 107% with proceeds from an equity
offering. Houston Exploration incurred approximately $4.5 million of debt
issuance costs on this private placement.
Houston Exploration used a portion of the net proceeds from the issuance to
redeem all of its outstanding $100 million principal amount of 8.625% senior
subordinated notes due 2008 at a price of 104.313% of par plus interest accrued
to the redemption date. Debt redemption costs totaled approximately $5.9 million
and is reflected in other income and (deductions) in the Consolidated Statement
of Income. The remaining net proceeds from the offering were used to reduce debt
amounts associated with Houston Exploration's bank revolving credit facility.
124
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,
2003, 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 0.60% to 1.20% during the year ended December 31, 2003, at which
time the rate was 1.10%.
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
2003 we called approximately $447 million aggregate principal amount of such
promissory notes at the applicable redemption prices plus accrued and unpaid
interest through the dates of redemption. Therefore, at December 31, 2003,
$155.4 million of these promissory notes remained outstanding. 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. At December
31, 2003, KeySpan was in compliance with this requirement.
Interest savings associated with this redemption were $15.6 million after-tax,
or $0.10 per share, in 2003. We applied the provisions of SFAS 145 "Rescission
of FASB Statement No. 4, 44 and 64, Amendment of FASB Statement No. 13, and
Technical Corrections" and recorded an expense of $18.2 million, reflecting
redemption costs, as well as the write-off of previously deferred debt issuance
costs. This expense has been recorded in other income and (deductions) in the
Consolidated Statement of Income.
MEDS Equity Units: At December 31, 2003, KeySpan had $460 million of MEDS Equity
Units outstanding 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, May 2005, 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.
There were eight million MEDS Equity units issued which are subject to
conversion upon execution of the three-year forward purchase contract. The
number of shares to be issued depends on the average closing price of our common
stock over the 20 day trading period ending on the third trading day prior to
May 16, 2005. If the average closing price over this time frame is less than or
equal to $35.30 of KeySpan's common stock, 11.3 million shares will be issued.
If the average closing price over this time frame is greater than or equal to
$42.36, 9.4 million shares will be issued. The number of shares issued at a
price between $35.30 and $42.36 will be between 9.4 million and 11.3 million
based upon a sliding scale.
125
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.
Industrial Development Revenue Bonds: In the fourth quarter of 2003, KeySpan
closed on a financing transaction pursuant to which $128 million tax-exempt
bonds with a 5.25% coupon maturing in June 2027 were issued on its behalf.
Fifty-three million dollars of these Industrial Development Revenue Bonds were
issued through the Nassau County Industrial Development Authority for the
construction of the Glenwood electric-generation peaking plant and the balance
of $75 million was issued by the Suffolk County Industrial Development Authority
for the Port Jefferson electric-generation peaking plant. Proceeds from the
transaction were used to repay commercial paper used to finance the
construction, installation and equipping of the two facilities. KeySpan has
guaranteed all payment obligations of our subsidiaries with regard to these
bonds.
First Mortgage Bonds: Colonial Gas Company, Essex Gas Company, ENI and their
respective subsidiaries, have issued and outstanding approximately $153.2
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.
Authority Financing Notes: Certain of our electric generation subsidiaries can
issue tax-exempt bonds through the New York State Energy Research and
Development Authority. At December 31, 2003, $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 2003 ranged from 0.56% to 1.15%,
through December 31, 2003, at which time the rate was 1.10%.
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 0.70 % to 1.21% from January 1, 2003 through
December 31, 2003 at which time the rate was 1.08%.
126
Ravenswood Master Lease: We have an arrangement with a variable interest
unaffiliated 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 financing entity
that acquired a portion of the facility, three steam generating units, directly
from Consolidated Edison and leased it to a KeySpan subsidiary. The variable
interest financing entity acquired the property for $425 million, financed with
debt of $412.3 million (97% of capitalization) and equity of $12.7 million (3%
of capitalization). Monthly lease payments are substantially equal to the
monthly interest expense on the debt securities.
In December 2003, KeySpan implemented FASB Interpretation No. 46 ("FIN 46"),
"Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51."
This Interpretation required us to, among other things, consolidate this
variable interest entity and classify the Master Lease as $412.3 million
long-term debt on the Consolidated Balance Sheet. Further, we recorded an asset
on the Consolidated Balance Sheet for an amount substantially equal to the fair
market value of the leased assets at the inception of the lease, less
depreciation since that date. Under the terms of our credit facility the Master
Lease has been considered debt in the ratio of debt-to-total capitalization
since the inception of the lease and therefore, implementation of FIN 46 has no
impact on our credit facility. (See Note 7 "Contractual Obligations, Financial
Guarantees and Contingencies" for additional information regarding the leasing
arrangement associated with the Master Lease Agreement and FIN 46 implementation
issues.)
PUHCA Authorization: In the fourth quarter of 2003 KeySpan received
authorization from the SEC, under PUCHA, to issue up to an additional $3 billion
of securities through December 31, 2006. This authorization provides KeySpan
with the necessary flexibility to finance future capital requirements over the
next three years.
Commercial Paper and Revolving Credit Agreements: In June 2003, KeySpan renewed
its $1.3 billion revolving credit facility, which was syndicated among sixteen
banks. The credit facility supports KeySpan's commercial paper program, and
consists of two separate credit facilities with different maturities but
substantially similar terms and conditions: a $450 million facility that extends
for 364 days, and a $850 million facility that is committed for three years. The
fees for the facilities are subject to a ratings-based grid, with an annual fee
that ranges from eight to twenty five basis points on the 364-day facility and
ten to thirty basis points on the three-year facility. Both credit agreements
allow for KeySpan to borrow using several different types of loans;
specifically, Eurodollar loans, ABR loans, or competitively bid loans.
Eurodollar loans are based on the Eurodollar rate plus a margin. ABR loans are
based on the highest of the Prime Rate, the base CD rate plus 1%, or the Federal
Funds Effective Rate plus 0.5%, plus a margin. Competitive bid loans are based
on bid results requested by KeySpan from the lenders. The margins on both
127
facilities are ratings based and range from zero basis points to 112.5 basis
points. The margins are increased if outstanding loans are in excess of 33% of
the total facility. In addition, the 364-day facility has a one-year term out
option, which would cost an additional 0.25% if utilized. 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 and certain financial
covenants that require us to, among other things, maintain a consolidated
indebtedness to consolidated capitalization ratio of no more than 64%.
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. At December 31, 2003, consolidated indebtedness, as calculated
under the terms of the credit facility, was 58.2% of consolidated
capitalization. Violation of this covenant could result in the termination of
the credit facility and the required repayment of amounts borrowed thereunder,
as well as possible cross defaults under other debt agreements.
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, 2003, KeySpan was in compliance with
all covenants.
At December 31, 2003, we had cash and temporary cash investments of $205.8
million. During 2003, we repaid $433.8 million of commercial paper and, at
December 31, 2003, $481.9 million of commercial paper was outstanding at a
weighted average annualized interest rate of 1.2%. We had the ability to borrow
up to an additional $818.1 million at December 31, 2003, under the commercial
paper program.
Houston Exploration has a revolving credit facility with a commercial banking
syndicate that provides Houston Exploration with a commitment of $300 million,
which can be increased, at its option to a maximum of $350 million with prior
approval from the banking syndicate. The credit facility is subject to borrowing
base limitations, currently set at $300 million and is 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, with the exception of trade payables, 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.
128
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, 2003, Houston Exploration was in compliance with all financial covenants.
During 2003, Houston Exploration borrowed $239 million under its credit facility
and repaid $264 million. At December 31, 2003, $127 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, 2003, $172.6 million of borrowing capacity was
available.
In 2003, KeySpan Canada replaced its two outstanding credit facilities with one
new facility with three tranches that combined allowed KeySpan Canada to borrow
up to approximately $125 million. At the time of the partial sale of KeySpan
Canada, net proceeds from the sale of $119.4 million plus an additional $45.7
million drawn under the new credit facilities were used to pay down existing
outstanding debt of $160.4 million. During the third quarter of 2003, KeySpan
Canada issued Cdn$125 million, or approximately US$93 million, in long-term
secured notes in a private placement, as previously mentioned. The proceeds of
the offering were used to pay-down, in its entirety, outstanding borrowings
under the credit facility. Further, one tranch of the credit facility was
discontinued. At December 31, 2003, KeySpan Canada's credit facility has the
following two tranches with the following maturities: (i) $37.5 million matures
in 364 days: and (ii) $37.5 million matures in two years. During 2003, KeySpan
Canada borrowed $71.5 million from its prior credit facilities and repaid $240.3
million. During the fourth quarter of 2003, KeySpan Canada borrowed $18.1
million under the new facility and at December 31, 2003 $56.9 million is
available for future borrowing. KeySpan is not a guarantor of this facility.
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 6.12%.
Debt Maturity: The following table reflects the maturity schedule for our debt
repayment requirements, including capitalized leases and related maturities, at
December 31, 2003:
- --------------------------------------------------------------------------------
Long-Term Capital
(In Thousands of Dollars) Debt Leases Total
- --------------------------------------------------------------------------------
Repayments:
Year 1 $ 333 $ 1,138 $ 1,471
Year 2 1,302,333 1,096 1,303,429
Year 3 512,333 1,003 513,336
Year 4 333 1,063 1,396
Year 5 160,761 1,129 161,890
Thereafter 3,649,613 7,552 3,657,165
- --------------------------------------------------------------------------------
$5,625,706 $ 12,981 $ 5,638,687
- --------------------------------------------------------------------------------
129
Note 7. Contractual Obligations, Financial Guarantees and Contingencies
Lease Obligations: Lease costs included in operation expense were $82.1 million
in 2003 reflecting, primarily, the Master Lease and the lease of our Brooklyn
headquarters of $29.3 million and $14.6 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, 2002 and 2001
were $71.1 million and $75.8 million, respectively. As previously mentioned, the
Master Lease has been consolidated as required by FIN 46, and as a result,
future lease payments will be reflected as interest expense on the Consolidated
Statement of Income beginning January 1, 2004. The future minimum cash lease
payments under various leases, excluding the Master Lease, all of which are
operating leases, are $58.9 million per year over the next five years and $122.2
million, in the aggregate, for all years thereafter. (See discussion below for
further information regarding the Master Lease.)
Variable Interest Entity: As mentioned, KeySpan has an arrangement with a
variable interest entity through which we lease a portion of the Ravenswood
facility. We acquired the Ravenswood facility, a 2,200-megawatt electric
generating facility located in Queens, New York, 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. Monthly lease payments
substantially equal the monthly interest expense on such debt securities.
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.
At this time, KeySpan intends to maintain a leasing arrangement for the
foreseeable future. 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 December 2003, KeySpan implemented FASB Interpretation No. 46 ("FIN 46"),
"Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51."
This Interpretation required us to, among other things, consolidate this
variable interest entity and classify the Master Lease as $412.3 million
long-term debt on the Consolidated Balance Sheet based on our current status as
primary beneficiary. Further, we recorded an asset on the Consolidated Balance
Sheet for an amount substantially equal to the fair market value of the leased
assets at the inception of the lease, less depreciation since that date, or
approximately $388 million. As previously mentioned, under the terms of our
credit facility the Master Lease has been considered debt in the ratio of
debt-to-total capitalization since the inception of the lease and therefore,
implementation of FIN 46 has no impact on our credit facility. In addition, we
recorded a $37.6 million after-tax charge, or $0.23 per share, change in
accounting principle on the Consolidated Statement of Income, representing
approximately four and a half years of depreciation. Based upon expected average
outstanding shares, we anticipate the incremental impact of the additional
depreciation expense for 2004 to be approximately $0.05 per share. Yearly lease
payments will be reflected as interest expense on the Consolidated Statement of
Income beginning January 1, 2004. Future minimum lease payments are $30.8 per
year over the next five years and $15.4 million for 2009.
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.
Asset Retirement Obligations: On January 1, 2003, KeySpan adopted 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.
At December 31, 2003, the present value of our future asset retirement
obligation ("ARO") was approximately $92.4 million, primarily related to our
investment in Houston Exploration. The cumulative effect of SFAS 143 and the
change in accounting principle was a benefit to net income of $0.2 million,
after-tax.
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The following table describes on a pro-forma basis the asset retirement
obligation associated with Houston Exploration as if SFAS 143 had been adopted
on January 1, 2002.
- -----------------------------------------------------------------------------------------------
For the Year Ended December 31,
(In Thousands of Dollars) 2003 2002
- -----------------------------------------------------------------------------------------------
ARO Liability at January 1, $ 57,197 $ 45,759
Additions from drilling 5,738 8,507
Additions from purchases 29,244 286
Deletions from abandonment (160) -
Changes resulting from timing (3,330) -
ARO accretion expense 3,668 2,645
- -----------------------------------------------------------------------------------------------
ARO Liability at December 31, $ 92,357 $ 57,197
- -----------------------------------------------------------------------------------------------
Reflected on Consolidated Balance Sheet
ARO Liability - Current $ 7,703 N/A
ARO Liability - Long term $ 84,654 N/A
- -----------------------------------------------------------------------------------------------
KeySpan's largest asset base is its gas transmission and distribution system. A
legal obligation exists due to certain safety requirements at final abandonment.
In addition, a legal obligation may be construed to exist with respect to
KeySpan's liquefied natural gas ("LNG") storage tanks due to clean up
responsibilities upon cessation of use. However, mass assets such as storage,
transmission and distribution assets are believed to operate in perpetuity and,
therefore, have indeterminate cash flow estimates. Since that exposure is in
perpetuity and cannot be measured, no liability will be recorded pursuant to
SFAS 143. KeySpan's ARO will be re-evaluated in future periods until sufficient
information exists to determine a reasonable estimate of fair value.
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, 2003, the following amounts would have to be
paid by KeySpan in the event of non-payment by the primary obligor at the time
payment is due:
- ------------------------------------------------------------------------------------------
Amount of
(In Thousands of Dollars) Exposure Expiration Dates
- ------------------------------------------------------------------------------------------
Medium-Term Notes - KEDLI (i) $ 525,000 2008-2010
Industrial Development Revenue Bonds (ii) 128,000 2027
Master Lease - Ravenswood (iii) 425,000 2004
Surety Bonds (iv) 168,000 Revolving
Commodity Guarantees and Other (v) 43,000 2005
Letters of Credit (vi) 67,000 2004
- ------------------------------------------------------------------------------------------
$ 1,356,000
- ------------------------------------------------------------------------------------------
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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 fully and unconditionally guaranteed the payment obligations of
its subsidiaries with regard to $128 million of Industrial Development
Revenue Bonds issued through the Nassau County and Suffolk County
Industrial Development Authorities for the construction of the Glenwood and
Port Jefferson electric-generation peaking plants. The face value of these
notes are included in long-term debt on the Consolidated Balance Sheet.
(iii)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.
(iv) KeySpan has agreed to indemnify the issuers of various surety and
performance bonds associated with certain construction projects currently
being performed by subsidiaries within the Energy Services segment. In the
event that the operating companies in the Energy Services segment fail to
perform their obligations under contracts, 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, 2003.
(vi) KeySpan has issued stand-by letters of credit in the amount of $67 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 or letters of credit and we have no reason to believe that our
subsidiaries will default on their current obligations. However, we cannot
predict when or if any defaults may take place or the impact such defaults may
have on our consolidated results of operations, financial condition or cash
flows.
133
In June 2003, Hawkeye Electric, LLC et al. ("Hawkeye") and KeySpan reached an
agreement settling certain legal matters. Under the terms of the settlement: (i)
certain obligations between the parties have been modified and clarified, (ii)
certain contracts were awarded to Hawkeye, (iii) certain credit and bonding
support made available by KeySpan to Hawkeye was terminated and (iv) KeySpan and
a Hawkeye affiliate closed on a $55 million long-term note receivable due from
Hawkeye on July 20, 2018 bearing interest at an annual rate of 5% and secured by
a power plant in Greenport, New York.
Fixed Charges Under Firm Contracts: Our utility subsidiaries and the Ravenswood
facility have entered into various contracts for gas delivery, storage and
supply services. Certain of these contracts require payment of annual demand
charges in the aggregate amount of approximately $452 million. We are liable for
these payments regardless of the level of service we require from third parties.
Such charges associated with gas distribution operations are currently recovered
from utility customers through the gas adjustment clause.
Legal Matters: From time to time we are subject to various legal proceedings
arising out of the ordinary course of our business. Except as described below,
we do not consider any of such proceedings to be material to our business or
likely to result in a material adverse effect on our results of operations,
financial condition 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.
On March 5, 2002, the SEC, as part of its continuing inquiry, issued a formal
order of investigation, pursuant to which it will review the trading activity of
certain company insiders from May 1, 2001 to the present, as well as KeySpan's
compliance with its reporting rules and regulations, generally during the period
following the acquisition by KeySpan Services, Inc., a KeySpan subsidiary, of
the Roy Kay companies through the July 17, 2001 announcement.
KeySpan and certain of its current and former officers and directors are
defendants in a consolidated class action lawsuit filed in the United States
District Court for the Eastern District of New York. This lawsuit alleges, 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. In October
2001, a shareholder's derivative action was commenced in the same court against
certain current and former 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. On June 12,
2002, a second derivative action was commenced which asserted similar
134
allegations. Each of these proceedings seeks monetary damages in an unspecified
amount. On March 18, 2003, the court granted our motion to dismiss the class
action complaint. The court's order dismissed certain class allegations with
prejudice, but provided the plaintiffs a final opportunity to file an amended
complaint concerning the remaining allegations. In April 2003, plaintiffs filed
an amended complaint and in July 2003 the court denied our motion to dismiss the
amended complaint but did strike certain allegations. On November 20, 2003, the
court granted our motion for reconsideration of the July 2003 order and the
court struck additional allegations from the amended complaint which effectively
limited the potential class period. On December 19, 2003, KeySpan filed a motion
to dismiss the derivative actions. The motion is still pending. KeySpan intends
to vigorously defend each of these proceedings. However, we are unable to
predict the outcome of these proceedings or what effect, if any, such outcome
will have on our financial condition, results of operations or cash flows.
KeySpan subsidiaries, along with several other parties, have been named as
defendants in numerous proceedings filed by plaintiffs claiming various degrees
of injury from asbestos exposure at generating facilities formerly owned by
LILCO and others. In connection with the May 1998 transaction with LIPA, costs
incurred by KeySpan for liabilities for asbestos exposure arising from the
activities of the generating facilities previously owned by LILCO are
recoverable from LIPA through the Power Supply Agreement between LIPA and
KeySpan.
KeySpan is unable to determine the outcome of the other outstanding asbestos
proceedings, but does not believe that such outcomes, if adverse, will have a
material effect on its financial condition, results of operation or cash flows.
KeySpan believes that its cost recovery rights under the Power Supply Agreement,
its indemnification rights against third parties and its insurance coverage
(above applicable deductible limits) cover its exposure for asbestos liabilities
generally.
As previously reported, 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 commenced this
proceeding because it believed that, among other things, the former owners
misstated the financial statements of the Roy Kay companies and certain
underlying work-in-progress schedules. The former owners filed counterclaims
against KeySpan and certain of its subsidiaries, as well as certain of their
respective officers, to recover damages they claimed 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. In March 2004, KeySpan entered into an agreement with
these formers owners settling this proceeding, the terms of which did not have a
material effect on our financial condition or results of operations.
135
Other Contingencies: 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, the terms and conditions thereof. In
addition, given the complexity of these agreements, disputes arise from time to
time between KeySpan and LIPA concerning the rights and obligations of each
party to make and receive payments as required pursuant to the terms of these
agreements. As a result, KeySpan is unable to determine what effect, if any, the
ultimate resolution of these disputes will have on its financial condition or
results of operations.
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.
Water: Additional capital expenditures associated with the renewal of the
surface water discharge permits for our power plants may be required by the
Department of Environmental Conservation ("DEC"). Until our monitoring
obligations are completed and changes to the Environmental Protection Agency
regulations under Section 316 of the Clean Water Act are promulgated, the need
for and the cost of equipment upgrades cannot be determined.
Land, Manufactured Gas Plants and Related Facilities
New York Sites: Within the State of New York we have identified 43 historical
manufactured gas plant ("MGP") sites and related facilities, which were 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 the
NYPSC and the DEC for inclusion on appropriate site inventories. Administrative
Orders on Consent ("ACO") or Voluntary Cleanup Agreements ("VCA") have been
executed with the DEC to address the investigation and remediation activities
associated with certain sites. Investigation and remediation activities required
at the remaining sites will be addressed as part of an application KeySpan
submitted to the DEC in October 2003 under its Voluntary Cleanup Program ("VCA
Application").
We have identified 28 of these sites as being associated with the historical
operations of KEDNY. One site has been fully remediated. The remaining sites
will be investigated and, if necessary, remediated under the terms and
conditions of ACOs or VCAs. Expenditures incurred to date by us with respect to
KEDNY MGP-related activities total $38.8 million. In July 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.
136
The remaining 15 sites have been identified as being associated with the
historical operations of KEDLI. Expenditures incurred to date by us with respect
to KEDLI MGP-related activities total $32.2 million. One site has been fully
investigated and requires no further action. The remaining sites will be
investigated and, if necessary, remediated under the conditions of ACOs or VCAs.
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 cost of our KEDNY and KEDLI MGP-related
environmental remediation activities will be $226.4 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 $71 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. At December 31, 2003, we have reflected a regulatory asset of $245.3
million for our KEDNY/KEDLI MGP sites. In accordance with NYPSC policy, KeySpan
records a reduction to regulatory liabilities as costs are incurred for
environmental clean-up activities. At December 31, 2003, these previously
deferred regulatory liabilities totaled $61.0 million. In October 2003, KEDNY
and KEDLI filed a joint petition with the NYPSC seeking rate treatment for
additional environmental costs that may be incurred in the future.
We are also responsible for environmental obligations associated with the
Ravenswood facility, purchased from Consolidated Edison in 1999, including
remediation activities associated with its historical 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 $3.4 million, which amount has been
accrued by us. Expenditures incurred to date total $1.6 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 of
these sites. A subsidiary of National Grid USA ("National Grid"), formerly New
England Electric System, has assumed responsibility for remediating 11 of these
137
sites, subject to a limited contribution from Boston Gas Company, and has
provided full indemnification to Boston Gas Company with respect to 8 other
sites. In addition, Boston Gas Company, Colonial Gas Company, and Essex Gas
Company has each assumed responsibility for remediating 3 sites. At this time,
it is uncertain as to whether Boston Gas Company, Colonial Gas Company or Essex
Gas Company have or share responsibility for remediating any of the 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. In October 2002, Boston Gas Company filed a complaint in
the United States District Court - Massachusetts District against one of the
insurance companies that issued comprehensive general liability policies to
Boston Gas Company for its remaining sites. The outcome of these proceedings
cannot be determined at this time.
We presently estimate the remaining cost of these Massachusetts KEDNE
MGP-related environmental cleanup activities will be $25.4 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 $13.5 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. At four of these sites we have entered
into cost sharing agreements with other parties who share responsibility for
remediation of these sites. 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.
We presently estimate the remaining cost of EnergyNorth MGP-related
environmental cleanup activities will be $13.9 million, which amount has been
accrued by us as a reasonable estimate of probable cost for known sites.
Expenditures incurred since November 8, 2000, with respect to these MGP-related
activities total $7.8 million.
138
By rate orders, the DTE and the NHPUC provide for the recovery of site
investigation and remediation costs and, accordingly, at December 31, 2003, we
have reflected a regulatory asset of $51.5 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 KeySpan New England, LLC, a successor company to Eastern
Enterprises, for which we may have or share environmental remediation or ongoing
maintenance responsibility. These three sites, located in Philadelphia,
Pennsylvania, New Haven, Connecticut and Everett, Massachusetts, were associated
with historical operations involving the production of coke and related
industrial processes. Honeywell International, Inc. and Beazer East, Inc. (both
former owners and/or operators of certain facilities at Everett ("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 a portion of that 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 for, among other things, reallocation of proportionate liability. In
2002, Beazer East commenced an action in 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.
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 $25.6 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 $7.2 million.
We believe that in the aggregate, the accrued liability for these MGP sites and
related facilities identified above are reasonable estimates of the probable
cost for the investigation and remediation of these sites and facilities. As
circumstances warrant, we periodically re-evaluate the accrued liabilities
associated with MGP sites and related facilities. We did such a re-evaluation in
2003 and the results of this study have been reflected in KeySpan's accruals.
The re-evaluation of KeySpan's accruals resulted in a $10 million benefit to
earnings in 2003. We may be required to investigate and, if necessary, remediate
each site previously noted, 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.
139
Note 8. Hedging, Derivative Financial Instruments and Fair Values
Financially-Settled Commodity Derivative Instruments - Hedging Activities: From
time to time, KeySpan subsidiaries have utilized derivative financial
instruments, such as futures, options and swaps, for the purpose of hedging the
cash flow variability associated with changes in commodity prices. KeySpan is
exposed to commodity price risk primarily with regard to its gas exploration and
production activities and its electric generating facilities. Derivative
financial instruments are employed by Houston Exploration to hedge cash flow
variability associated with forecasted sales of natural gas. The Ravenswood
facility uses derivative financial instruments to hedge the cash flow
variability associated with the purchase of natural gas and oil that will be
consumed during the generation of electricity. The Ravenswood facility also
hedges the cash flow variability associated with a portion of peak season
electric energy sales. In addition, during 2003 KeySpan Canada employed
derivative financial instruments to hedge cash flow variability associated with
the purchase of natural gas and electricity used in the operation of its gas
processing plants; all such derivative instruments settled during the year.
The majority of these derivative financial instruments are cash flow hedges that
qualify for hedge accounting under SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities", as amended by SFAS 149 "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities", collectively
SFAS 133, and are not considered held for trading purposes as defined by current
accounting literature. Accordingly, we carry the fair market value of our
derivative instruments on the Consolidated Balance Sheet as either a current or
deferred asset or liability, as appropriate, and defer the effective portion of
unrealized gains or losses in accumulated other comprehensive income. Gains and
losses are reclassified from accumulated other comprehensive income to the
Consolidated Statement of Income in the period the hedged transaction effects
earnings. Gains and losses are reflected as a component of either revenue or
fuel and purchased power depending on the hedged transaction. Hedge
ineffectiveness is measured using the change in variable cash flows and the
hypothetical derivative methods and recorded directly to earnings.
Houston Exploration has utilized collars and purchased put options, 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. In 2003,
Houston Exploration hedged slightly less than 70% of its gas production. At
December 31, 2003, Houston Exploration has hedge positions in place for
approximately 70% of its estimated 2004 gas production, with an effective floor
price of $4.26 and an effective ceiling price of $5.65. Further, Houston
Exploration has hedge positions in place for approximately 44% of its estimated
2005 gas production, with an effective floor price of $4.59 and an effective
ceiling price of $5.26. Houston Exploration uses standard New York Mercantile
Exchange ("NYMEX") futures prices to value its swap positions, and, in addition,
uses published volatility in its Black-Scholes calculation for outstanding
options. The maximum length of time over which Houston Exploration has hedged
such cash flow variability is through December 2005. The fair market value of
these derivative instruments at December 31, 2003 was a liability of $36.9
million. 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 $32.1
million, or $20.9 million after-tax.
140
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 for 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 for 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 forecasted purchases of
natural gas and fuel oil is through September 2005. We use standard NYMEX
futures prices to value the gas futures contracts and market quoted forward
prices to value oil swap and natural gas basis swap contracts. The fair market
value of these derivative instruments at December 31, 2003 was an asset of $0.4
million. These derivative instruments are reported in other comprehensive income
and are expected to be reclassified into earnings over the next twelve months.
We have also engaged in the use of cash-settled swap instruments to hedge the
cash flow variability associated with a portion of forecasted peak season
electric energy sales from the Ravenswood facility. The maximum length of time
over which we have hedged cash flow variability is through December 2004. We use
market quoted forward prices to value these outstanding derivatives. The fair
market value of these derivative instruments at December 31, 2003 was an asset
of $0.3 million. These derivative instruments are reported in other
comprehensive income and are expected to be reclassified into earnings over the
next twelve months.
The table below summarizes the fair value of each category of derivative
instrument outstanding at December 31, 2003 and its related line item on the
Consolidated Balance Sheet. Fair value is the amount at which derivative
instruments could be exchanged in a current transaction between willing parties,
other than in a forced liquidation sale.
- ----------------------------------------------------------------------------
(In Thousands of Dollars) December 31, 2003
- ----------------------------------------------------------------------------
Gas Contracts:
Other current assets $ 3,458
Accounts payable and other liabilities (35,592)
Other deferred liabilities (4,734)
Oil Contracts:
Other deferred charges 385
Electric Contracts:
Other deferred charges 259
- ----------------------------------------------------------------------------
$ (36,224)
- ----------------------------------------------------------------------------
Financially-Settled Commodity Derivative Instruments that Do Not Qualify for
Hedge Accounting: KeySpan subsidiaries also employ a limited number of financial
derivatives that do not qualify for hedge accounting treatment under SFAS 133.
In November 2003, we sold a "swaption" to hedge the cash flow variability
associated with 50 MW of forecasted 2004 summer electric energy sales from the
141
Ravenswood facility. The swaption is an option that gives the counterparty the
right, but not the obligation, to enter into a swap transaction with KeySpan in
the future at a given strike price. This swaption can be converted into a swap,
at the election of the counterparty and has an expiration date of June 1, 2004.
The premium payment KeySpan received was recorded as a current liability on the
Consolidated Balance Sheet. The premium generally will be recorded into income
at the time the swaption is either exercised or expires. An internally developed
option-pricing model is used to value the swaption and at December 31, 2003 the
fair value of the swaption was immaterial.
At December 31, 2003, KeySpan Canada has a portfolio of financially-settled
natural gas collars and swap transactions for natural gas liquids. Such
contracts are executed by KeySpan Canada to: (i) 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 to
counterparties. These derivative financial instruments also do not qualify for
hedge accounting treatment. At December 31, 2003, these instruments had a net
fair market value of $1.0 million, which was recorded as a $1.8 million current
asset and $0.8 million current liability on the Consolidated Balance Sheet.
Based on the non-hedge designation of these instruments, an unrealized gain was
recorded in the Consolidated Statement of Income.
Firm Gas Sales Derivative Instruments - Regulated Utilities: We use derivative
financial instruments to reduce the cash flow variability associated with the
purchase price for a portion of future natural gas purchases associated with our
Gas Distribution operations. Our strategy is to minimize fluctuations in firm
gas sales prices to our regulated firm gas sales customers in our New York and
New England service territories. The accounting for these derivative instruments
is subject to SFAS 71 "Accounting for the Effects of Certain Types of
Regulation." Therefore, changes in the fair value of these derivatives have been
recorded as a regulatory asset or regulatory liability on the Consolidated
Balance Sheet. Gains or losses on the settlement of these contracts are
initially deferred and then refunded to or collected from our firm gas sales
customers consistent with regulatory requirements. At December 31, 2003, these
derivatives had a net fair market value of $9.9 million and are reflected as a
regulatory liability on the Consolidated Balance Sheet.
142
Physically-Settled Commodity Derivative Instruments: SFAS 133 establishes
criteria that must be satisfied in order for option contracts, forward contracts
with optionality features, or contracts that combine a forward contract and a
purchase option contract to be exempted as normal purchases and sales. Based
upon a continuing review of our physical gas contracts, we determined that
certain contracts for the physical purchase of natural gas associated with our
regulated gas utilities are not exempt as normal purchases from the requirements
of SFAS 133. 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. At December 31, 2003 these contracts had a net
negative fair market value of $1.9 million, and are reflected as a $6.9 million
regulatory asset and $5.0 million regulatory liability on the Consolidated
Balance Sheet.
Interest Rate Derivative Instruments: In May 2003, we entered into interest rate
swap agreements in which we swapped $250 million of 7.25% fixed rate debt to
floating rate debt. Under the terms of the agreements, we will receive the fixed
coupon rate associated with these bonds and pay our swap counterparties a
variable interest rate based on LIBOR, that is reset on a semi-annual basis.
These swaps are designated as fair-value hedges and qualify for "short-cut"
hedge accounting treatment under SFAS 133. During the twelve months ended
December 31, 2003, we paid our counterparty an average interest rate of 6.43%,
and as a result, we realized interest savings of $1.2 million. The fair market
value of this derivative was negligible at December 31, 2003.
During 2002, we had interest rate swap agreements in which we swapped
approximately $1.3 billion of fixed rate debt to floating rate debt. Under the
terms of the agreements, we received the fixed coupon rate associated with these
bonds and paid the swap counterparties a variable interest rate that was reset
on a quarterly basis. These swaps were designated as fair-value hedges and
qualified for "short-cut" hedge accounting treatment under SFAS 133. In 2002, we
terminated two of these interest rate swap agreements with an aggregate notional
amount of $1.0 billion. The remaining swap, which had a notional amount of
$270.0 million, was terminated on February 25, 2003. We received $18.4 million
from our swap counterparties as a result of the latter termination, of which
$8.1 million represented accrued swap interest. The difference between the
termination settlement amount and the amount of accrued interest, $10.3 million,
was recorded as a reduction to interest expense 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 called a portion of these
promissory notes during the first quarter of 2003.
Additionally, we had an interest rate swap agreement that hedged the cash flow
variability associated with the forecasted issuance of a series of commercial
paper offerings. This hedge expired in March 2003.
Weather Derivatives: The utility tariffs associated with KEDNE's operations do
not contain weather normalization adjustments. As a result, fluctuations from
normal weather may have a significant positive or negative effect on the results
of these operations. To mitigate a substantial portion of the effect of
fluctuations from normal weather on our financial position and cash flows, we
143
sold heating degree-day call options and purchased heating-degree day put
options for the November 2002-March 2003 winter season. With respect to sold
call options, KeySpan was required to make a payment of $40,000 per heating
degree day to its counterparties when actual weather experienced during the
November 2002 - March 2003 time frame was above 4,470 heating degree days, which
equates to approximately 1% colder than normal weather. With respect to
purchased put options, KeySpan would have received a $20,000 per heating degree
day payment from its counterparties when actual weather was below 4,150 heating
degree days, or approximately 7% warmer than normal. Based on the terms of such
contracts, we account for such instruments pursuant to the requirements of EITF
99-2, "Accounting for Weather Derivatives." In this regard, such instruments
were accounted for using the "intrinsic value method" as set forth in such
guidance. During the first quarter of 2003, weather was 10% colder than normal
and, as a result, $11.9 million was recorded as a reduction to revenues.
In October 2003, we entered into heating-degree day call and put options to
mitigate the effect of fluctuations from normal weather on KEDNE's financial
position and cash flows for the 2003/2004 winter heating season - November 2003
through March 2004. With respect to sold call options, KeySpan will be required
to make a payment of $27,500 per heating degree day to its counterparties when
actual weather experienced during this time frame is above 4,440 heating degree
days, which equates to approximately 2% colder than normal weather, based on the
most recent 20-year average for normal weather. The maximum amount KeySpan may
be required to pay on its sold call options is $5.5 million. With respect to
purchased put options, KeySpan will receive a $27,500 per heating degree day
payment from its counterparties when actual weather is below 4,266 heating
degree days, or approximately 2% warmer than normal. The maximum amount KeySpan
may receive on its purchased put options is $11 million. The net premium cost
for these options was $0.4 million. We account for these derivatives pursuant to
the requirements of EITF 99-2. During the fourth quarter of 2003, weather, as
measured in heating degree-days, was slightly warmer normal and, as a result, a
$0.5 million benefit was recorded through 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
non-performance by a counterparty to a derivative contract, the desired impact
may not be achieved. The risk of counterparty non-performance is generally
considered a credit risk and is actively managed by assessing each counterparty
credit profile and negotiating appropriate levels of collateral and credit
support. We believe that our credit risk related to the above mentioned
derivative financial instruments is no greater than the risk associated with the
primary contracts which they hedge and that the elimination of a portion of the
price risk reduces volatility in our reported results of operations, financial
position and cash flows and lowers overall business risk.
Long-term Debt: The following tables depict the fair values and carrying values
of KeySpan's long-term debt at December 31, 2003 and 2002.
Fair Values of Long-Term Debt
- ------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2003 2002
- ------------------------------------------------------------------------------
First Mortgage Bonds $ 178,438 $ 180,666
Notes 3,893,158 3,441,619
Gas Facilities Revenue Bonds 683,354 674,828
Authority Financing Notes 66,005 66,005
Promissory Notes 158,837 616,240
MEDS Equity Units 495,880 525,918
Tax Exempt Bonds 129,558 -
- ------------------------------------------------------------------------------
$ 5,605,230 $ 5,505,276
- ------------------------------------------------------------------------------
144
Carrying Values of Long-Term Debt
- ------------------------------------------------------------------------------
(In Thousands of Dollars) 2003 2002
- ------------------------------------------------------------------------------
First Mortgage Bonds $ 153,186 $ 163,625
Notes 3,456,425 2,985,000
Gas Facilities Revenue Bonds 648,500 648,500
Authority Financing Notes 66,005 66,005
Promissory Notes 155,422 602,427
MEDS Equity Units 460,000 460,000
Master Lease 412,300 -
Tax Exempt Bonds 128,275 -
- ------------------------------------------------------------------------------
$ 5,480,113 $ 4,925,557
- ------------------------------------------------------------------------------
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.
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:
- ---------------------------------------------------------------------------------------
(In Thousands of Dollars) 2002 2001
- ---------------------------------------------------------------------------------------
Revenues $ 116,149 $ 266,792
Pre-tax income (loss) (4,624) 18,489
Income tax (expense) benefit 1,268 (7,571)
- ---------------------------------------------------------------------------------------
Income (loss) from discontinued operations (3,356) 10,918
- ---------------------------------------------------------------------------------------
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)
- ---------------------------------------------------------------------------------------
145
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. During 2003 KeySpan
incurred $11.4 million in operating losses, which reflected provisions made for
the resolution of outstanding claims and change orders, as well as additional
costs incurred in connection with the collection of outstanding contract
balances.
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 and 2001 the Roy Kay companies recorded
operating losses of $10.8 million and $137.8 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.
146
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.
- -----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2003
Other
(In Thousands of Dollars) Guarantor KEDLI Subsidiaries Eliminations Consolidated
- -----------------------------------------------------------------------------------------------------------------------------------
Revenues $ 507 $ 1,046,931 $ 5,868,230 $ (507) $ 6,915,161
--------------------------------------------------------------------------------------------
Operating Expenses
Purchased gas - 574,009 1,921,093 - 2,495,102
Fuel and purchased power - - 414,633 - 414,633
Operations and maintenance 11,340 137,223 1,857,233 - 2,005,796
Intercompany expense 5,282 3,570 (3,570) (5,282) -
Depreciation and amortization (53) 77,603 496,524 - 574,074
Operating taxes - 77,503 340,733 - 418,236
--------------------------------------------------------------------------------------------
Total Operating Expenses 16,569 869,908 5,026,646 (5,282) 5,907,841
--------------------------------------------------------------------------------------------
Gain on sale of property - 13,974 1,149 - 15,123
Income from equity investments 108 - 19,106 - 19,214
--------------------------------------------------------------------------------------------
Operating Income (Loss) (15,954) 190,997 861,839 4,775 1,041,657
--------------------------------------------------------------------------------------------
Interest charges (209,505) (62,992) (299,399) 264,202 (307,694)
Other income and (deductions) 621,151 (8,636) 54,429 (699,415) (32,471)
--------------------------------------------------------------------------------------------
Total Other Income and (Deductions) 411,646 (71,628) (244,970) (435,213) (340,165)
--------------------------------------------------------------------------------------------
Income Taxes (Benefit) (28,663) 40,796 265,178 - 277,311
--------------------------------------------------------------------------------------------
Earnings from Continuing Operations $ 424,355 $ 78,573 $ 351,691 $ (430,438) $ 424,181
Cumulative Change in Accounting
Principle - - (37,451) - (37,451)
--------------------------------------------------------------------------------------------
Net Income $ 424,355 $ 78,573 $ 314,240 $ (430,438) $ 386,730
============================================================================================
147
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Income
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2002
Other
(In Thousands of Dollars) Guarantor KEDLI 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 - - 395,860 - 395,860
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) 80,056 303,860 - 381,767
-----------------------------------------------------------------------------------------
Total Operating Expenses 13,904 650,892 4,385,386 (2,772) 5,047,410
-----------------------------------------------------------------------------------------
Gain on sale of property - 317 4,413 - 4,730
Income from equity investments 104 - 13,992 - 14,096
-----------------------------------------------------------------------------------------
Operating Income (Loss) (13,337) 160,026 793,084 2,309 942,082
-----------------------------------------------------------------------------------------
Interest charges (200,920) (62,520) (295,209) 257,145 (301,504)
Other income and (deductions) 565,262 7,835 60,222 (633,068) 251
-----------------------------------------------------------------------------------------
Total Other Income and (Deductions) 364,342 (54,685) (234,987) (375,923) (301,253)
-----------------------------------------------------------------------------------------
Income Taxes (Benefit) (26,683) 36,746 233,416 - 243,479
-----------------------------------------------------------------------------------------
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
=========================================================================================
148
- -----------------------------------------------------------------------------------------------------------------------------------
Statement of Income
- -----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2001
Other
(In Thousands of Dollars) Guarantor KEDLI 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
-----------------------------------------------------------------------------------------
Income from equity investments - - 13,129 - 13,129
-----------------------------------------------------------------------------------------
Operating Income (Loss) 19396 144,591 650,017 (226) 813,778
-----------------------------------------------------------------------------------------
Interest charges (230,618) (65,206) (264,286) 206,640 (353,470)
Other income and (deductions) 426,346 9,721 5,326 (447,316) (5,923)
-----------------------------------------------------------------------------------------
Total Other Income and (Deductions) 195,728 (55,485) (258,960) (240,676) (359,393)
-----------------------------------------------------------------------------------------
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
=========================================================================================
149
- -----------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
- -----------------------------------------------------------------------------------------------------------------------------------
December 31, 2003
Other
(In Thousands of Dollars) Guarantor KEDLI Subsidiaries Eliminations Consolidated
- -----------------------------------------------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash and temporary cash investments $ 97,567 $ 1,554 $ 106,630 $ - $ 205,751
Accounts receivable, net 3,298 209,151 1,243,459 - 1,455,908
Other current assets 3,250 130,994 590,996 - 725,240
--------------------------------------------------------------------------------------------
104,115 341,699 1,941,085 - 2,386,899
--------------------------------------------------------------------------------------------
Equity Investments 4,475,949 1,123 153,520 (4,382,027) 248,565
--------------------------------------------------------------------------------------------
Property
Gas - 1,899,375 4,622,876 - 6,522,251
Other - - 6,150,355 - 6,150,355
Accumulated depreciation and
depletion - (312,204) (3,466,099) - (3,778,303)
--------------------------------------------------------------------------------------------
- 1,587,171 7,307,132 - 8,894,303
--------------------------------------------------------------------------------------------
Intercompany Accounts Receivable 3,105,571 - 1,191,394 (4,296,965) -
Deferred Charges 374,076 237,870 2,485,071 - 3,097,017
--------------------------------------------------------------------------------------------
Total Assets $ 8,059,711 $ 2,167,863 $ 13,078,202 $ (8,678,992) $ 14,626,784
============================================================================================
LIABILITIES AND CAPITALIZATION
Current Liabilities
Accounts payable $ 125,892 $ 165,613 $ 850,092 $ - $ 1,141,597
Notes payable 481,900 - - - 481,900
Other current liabilities 129,168 16,125 80,026 - 225,319
--------------------------------------------------------------------------------------------
736,960 181,738 930,118 - 1,848,816
--------------------------------------------------------------------------------------------
Intercompany Accounts Payable - 116,197 2,596,202 (2,712,399) -
--------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax (48,059) 256,882 1,064,828 - 1,273,651
Other deferred credits and liabilities 532,062 179,919 925,839 - 1,637,820
--------------------------------------------------------------------------------------------
484,003 436,801 1,990,667 - 2,911,471
--------------------------------------------------------------------------------------------
Capitalization
Common shareholders' equity 3,707,785 782,223 3,553,967 (4,382,027) 3,661,948
Preferred stock 83,568 - - - 83,568
Long-term debt 3,047,395 650,904 3,497,699 (1,584,566) 5,611,432
--------------------------------------------------------------------------------------------
Total Capitalization 6,838,748 1,433,127 7,051,666 (5,966,593) 9,356,948
--------------------------------------------------------------------------------------------
Minority Interest in Subsidiary
Companies - - 509,549 - 509,549
--------------------------------------------------------------------------------------------
Total Liabilities & Capitalization $ 8,059,711 $ 2,167,863 $ 13,078,202 $ (8,678,992) $ 14,626,784
============================================================================================
150
- ------------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
- ------------------------------------------------------------------------------------------------------------------------------------
December 31, 2002
Other
(In Thousands of Dollars) Guarantor KEDLI Subsidiaries Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash & temporary cash investments $ 88,308 $ 6,472 $ 75,837 $ - $ 170,617
Accounts receivable, net 23,982 208,512 1,299,559 - 1,532,053
Other current assets 1,757 79,206 423,596 - 504,559
------------------------------------------------------------------------------------------
114,047 294,190 1,798,992 - 2,207,229
------------------------------------------------------------------------------------------
Equity Investments 3,797,964 1,469 201,675 (3,736,379) 264,729
------------------------------------------------------------------------------------------
Property
Gas - 1,773,028 4,352,501 - 6,125,529
Other - - 4,807,724 - 4,807,724
Accumulated depreciation and
depletion - (282,832) (3,065,829) - (3,348,661)
------------------------------------------------------------------------------------------
- 1,490,196 6,094,396 - 7,584,592
------------------------------------------------------------------------------------------
Intercompany Accounts Receivable 3,619,515 - 712,394 (4,331,909) -
Deferred Charges 339,443 192,652 2,391,405 - 2,923,500
------------------------------------------------------------------------------------------
Total Assets $ 7,870,969 $ 1,978,507 $ 11,198,862 $ (8,068,288) $ 12,980,050
==========================================================================================
LIABILITIES AND CAPITALIZATION
Current Liabilities
Accounts payable $ 132,966 $ 68,772 $ 894,916 $ - $ 1,096,654
Notes payable 915,697 - - - 915,697
Other current liabilities 107,605 104,975 30,302 - 242,882
------------------------------------------------------------------------------------------
1,156,268 173,747 925,218 - 2,255,233
------------------------------------------------------------------------------------------
Intercompany Accounts Payable - 178,843 2,071,682 (2,250,525) -
------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax (43,110) 139,715 780,408 - 877,013
Other deferred credits and liabilities 481,964 138,209 744,688 - 1,364,861
------------------------------------------------------------------------------------------
438,854 277,924 1,525,096 - 2,241,874
------------------------------------------------------------------------------------------
Capitalization
Common shareholders' equity 2,983,214 647,089 3,050,668 (3,736,379) 2,944,592
Preferred stock 83,849 - - - 83,849
Long-term debt 3,208,784 700,904 3,395,777 (2,081,384) 5,224,081
------------------------------------------------------------------------------------------
Total Capitalization 6,275,847 1,347,993 6,446,445 (5,817,763) 8,252,522
------------------------------------------------------------------------------------------
Minority Interest in Subsidiary Companies - - 230,421 - 230,421
------------------------------------------------------------------------------------------
Total Liabilities & Capitalization $ 7,870,969 $ 1,978,507 $ 11,198,862 $ (8,068,288) $ 12,980,050
==========================================================================================
151
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2003
--------------------------------------------------------------------------
Other
(In Thousands of Dollars) Guarantor KEDLI Subsidiaries Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net Cash (Used in) Provided by Operating Activities $ (547,516) $ 162,786 $ 1,569,373 $ 1,184,643
--------------------------------------------------------------------------
Investing Activities
Capital expenditures - (130,275) (881,441) (1,011,716)
Proceeds from the sale of property and
subsidiary stock - 15,123 294,573 309,696
Investments in subsidiaries - - (211,370) (211,370)
Issuance of note receiveable (55,000) - - (55,000)
--------------------------------------------------------------------------
Net Cash (Used in) Investing Activities (55,000) (115,152) (798,238) (968,390)
--------------------------------------------------------------------------
Financing Activities
Proceeds from equity issuance 473,573 - 473,573
Treasury stock issued 96,687 - - 96,687
Redemption of LIPA promissory notes (447,005) - (447,005)
Issuance of debt, net of payments 300,000 - 119,287 419,287
Redemption of preferred stock - (14,293) (14,293)
Payment of commercial paper (433,797) - (433,797)
Common and preferred stock dividends paid (280,560) - (280,560)
Other 28,933 - (23,944) 4,989
Net intercompany accounts 873,944 (52,552) (821,392) -
-
--------------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities 611,775 (52,552) (740,342) (181,119)
--------------------------------------------------------------------------
Net (Decrease) Increase in Cash and Cash Equivalents $ 9,259 $ (4,918) $ 30,793 $ 35,134
Cash and Cash Equivalents at Beginning of Period 88,308 6,472 75,837 170,617
--------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 97,567 $ 1,554 $ 106,630 $ 205,751
==========================================================================
- ---------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
- ---------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2002
------------------------------------------------------------------------
Other
(In Thousands of Dollars) Guarantor KEDLI Subsidiaries Consolidated
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net Cash (Used in) Provided by Operating Activities $ (97,981) $ 188,955 $ 640,518 $ 731,492
------------------------------------------------------------------------
Investing Activities
Capital expenditures - (146,450) (914,572) (1,061,022)
Other - 903 151,358 152,261
------------------------------------------------------------------------
Net Cash (Used in) Investing Activities - (145,547) (763,214) (908,761)
------------------------------------------------------------------------
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)
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
========================================================================
152
- -----------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
- -----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2001
------------------------------------------------------------------------
Other
(In Thousands of Dollars) 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
========================================================================
Note 13. 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 14. 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.
153
Note 15. Subsequent Events (Unaudited)
KeySpan is currently analyzing proposals from interested investors to
participate in the equity portion of a leveraged lease financing of a new 250 MW
combined cycle electric generating facility located at the existing Ravenswood
electric generating facility site. KeySpan is seeking to arrange for the lease
to be consummated in late April to coincide with the commencement of full
commercial operation of the new facility. At the closing, the new facility will
be acquired by the lessor from our subsidiary, KeySpan Ravenswood, LLC, and
simultaneously leased back to it. All obligations of our subsidiary under the
lease will be unconditionally guaranteed by KeySpan. We anticipate that this
lease transaction will generate cash proceeds equivalent to the fair market
value of the facility, currently anticipated to be approximately $360 million.
It is expected that the cash proceeds from this transaction will be used to
redeem outstanding commercial paper. It is intended for this lease transaction
to qualify as an operating lease under SFAS 98 "Accounting for Leases:
Sale/Leaseback Transactions Involving Real Estate; Sales-Type Leases of Real
Estate; Definition of the Lease Term; an Initial Direct Costs of Direct
Financing Leases, an amendment of FASB Statements No.13, 66, 91 and a rescission
of FASB Statement No. 26 and Technical Bulletin No. 79-11." The lease will have
a term of approximately 35 years and operating lease expense is anticipated to
be between $15 million to $17 million per year. Lease payments will fluctuate
from year to year, but are substantially paid over the first 16 years.
On February 27, 2004 KeySpan and KeySpan Facilities Income Fund (the "Fund")
announced that the Fund has entered into an agreement to sell 15.617 million
units of the Fund at a price of $12.60 per unit for gross total proceeds of
approximately CDN$196.8 million. The proceeds of the offering will be used to
acquire a 35.91% interest in the business of KeySpan Energy Canada Partnership
("KeySpan Canada") from KeySpan. KeySpan will receive net proceeds of
approximately CDN$186.3 million (or approximately US$139 million), after
commissions and expenses. This offer is subject to regulatory approvals and is
expected to close on or about April 1, 2004. After closing, the Fund's ownership
in KeySpan Canada will increase from 39.1% to 75%. KeySpan's ownership of
KeySpan Canada will decrease to approximately 25%.
154
Note 16. 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, 2003. Shareholders
other than KeySpan had a minority interest of approximately 45% in Houston
Exploration at December 31, 2003, 34% in 2002 and 33% in 2001. Gas and oil
operations, and reserves, were located in the United States in all years.
Capitalized Costs Relating to Gas and Oil Producing Activities
- --------------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- --------------------------------------------------------------------------------------------------------------------------
At December 31, 2003 2002 2001
- --------------------------------------------------------------------------------------------------------------------------
Unproved properties not being amortized $ 142,905 $ 110,623 $ 195,478
Properties being amortized - productive and nonproductive 2,429,891 1,917,287 1,590,014
- --------------------------------------------------------------------------------------------------------------------------
Total capitalized costs 2,572,796 2,027,910 1,785,492
Accumulated depletion (1,159,509) (968,713) (791,194)
- --------------------------------------------------------------------------------------------------------------------------
Net capitalized costs $ 1,413,287 $ 1,059,197 $ 994,298
- --------------------------------------------------------------------------------------------------------------------------
Costs Incurred in Property Acquisition, Exploration and Development Activities
- -------------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------------------
At December 31, 2003 2002 2001
- -------------------------------------------------------------------------------------------------------------------------
Acquisition of properties -
Unproved properties $ 61,484 $ 14,600 $ 31,718
Proved properties 171,297 90,004 85,435
Exploration 66,259 28,343 74,497
Development 170,493 139,108 191,927
Asset retirement obligation 31,858 - -
- -------------------------------------------------------------------------------------------------------------------------
Total costs incurred $ 501,391 $ 272,055 $ 383,577
- -------------------------------------------------------------------------------------------------------------------------
Costs included in development costs to develop proved undeveloped reserves for
the years ended December 31, 2003, 2002 and 2001 were $49.4 million, $11.0
million and $19.9 million, respectively.
Results of Operations from Gas and Oil Producing Activities*
- -------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------
At December 31, 2003 2002 2001
- -------------------------------------------------------------------------------------------------------
Revenues $ 497,948 $ 356,233 $ 404,584
- -------------------------------------------------------------------------------------------------------
Production and lifting costs 63,591 44,822 37,574
Shipping and handling costs 10,388 9,450 7,850
Depletion 205,118 177,548 173,566
- -------------------------------------------------------------------------------------------------------
Total expenses 279,097 231,820 218,990
- -------------------------------------------------------------------------------------------------------
Income before taxes 218,851 124,414 185,594
Income taxes 76,598 42,519 64,118
- -------------------------------------------------------------------------------------------------------
Results of operations $ 142,253 $ 81,895 $ 121,476
- -------------------------------------------------------------------------------------------------------
* (Excluding corporate overhead and interest costs)
155
Summary of Production and Lifting Costs
- ----------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- ----------------------------------------------------------------------------------------------------------------------
At December 31, 2003 2002 2001
- ----------------------------------------------------------------------------------------------------------------------
Pumping, gauging and other labor $ 10,975 $ 7,846 $ 5,342
Compressors and other rental equipment 5,136 4,135 3,023
Property taxes and insurance 7,155 6,801 3,640
Transportation 2,329 2,131 3,162
Processing fees 2,354 3,078 2,267
Workover and well stimulation 5,225 2,348 1,478
Repairs, maintenance and supplies 3,735 2,972 2,204
Fuel and chemicals 3,109 2,582 1,424
Environmental, regulatory and other 7,614 3,307 3,639
Severance taxes 15,959 9,622 11,395
- ----------------------------------------------------------------------------------------------------------------------
Total production and lifting costs $ 63,591 $ 44,822 $ 37,574
- ----------------------------------------------------------------------------------------------------------------------
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, 2003 2002 2001
- -------------------------------------------------------------------------------------------------------------
Proved Reserves
Beginning of year 614,734 585,659 545,858
Revisions of previous estimates (32,433) (15,324) (39,994)
Extensions and discoveries 140,632 105,798 86,401
Production (100,130) (107,507) (90,754)
Purchases of reserves in place 89,380 48,777 84,148
Sales of reserves in place - (2,669) -
- -------------------------------------------------------------------------------------------------------------
Proved reserves - End of year (1) 712,183 614,734 585,659
Proved developed reserves
Beginning of year 435,629 448,921 431,536
End of Year (2) 488,012 435,629 448,921
- -------------------------------------------------------------------------------------------------------------
(1) Includes minority interest of 318,417, 208,516, and 188,077 in 2003, 2002,
and 2001, respectively.
(2) Includes minority interest of 218,190, 148,811 and 148,593 in 2003, 2002,
and 2001, respectively.
156
Crude Oil, Condensate and Natural Gas Liquids (MBbls)
- ----------------------------------------------------------------------------------------------------------
At December 31, 2003 2002 2001
- ----------------------------------------------------------------------------------------------------------
Proved reserves
Beginning of Year 9,548 10,234 7,912
Revisions of previous estimates (3,542) (5) (289)
Extension and discoveries 117 342 3,061
Production (1,514) (1,025) (536)
Purchases of reserves in place 3,753 483 115
Sales of reserves in place - (481) (29)
- ----------------------------------------------------------------------------------------------------------
Proved reserves - End of year (1) 8,362 9,548 10,234
Proved developed reserves
Beginning of year 2,413 2,479 2,126
End of year (2) 4,273 2,413 2,479
- ----------------------------------------------------------------------------------------------------------
(1) Includes minority interest of 3,739, 2,256 and 2,186 in 2003, 2002, and
2001, respectively.
(2) Includes minority interest of 1,910, 824 and 821 in 2003, 2002, and 2001,
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, 2003 2002 2001
- ------------------------------------------------------------------------------------------------------------------------------------
Future cash flows $ 4,375,781 $ 2,951,622 $ 1,580,077
Future costs-
Production (769,892) (495,097) (316,421)
Development (378,547) (263,926) (227,158)
- ------------------------------------------------------------------------------------------------------------------------------------
Future net inflows before income tax 3,227,342 2,192,599 1,036,498
Future income taxes (853,425) (559,853) (221,324)
- ------------------------------------------------------------------------------------------------------------------------------------
Future net cash flows 2,373,917 1,632,746 815,174
10% discount factor (853,403) (528,829) (228,988)
- ------------------------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows (1) $ 1,520,514 $ 1,103,917 $ 586,186
- ------------------------------------------------------------------------------------------------------------------------------------
(1) Includes minority interest of $672,620, $361,435 and $182,555 in 2003, 2002
and 2001, respectively
Costs included in future development costs related to proved undeveloped
reserves for the years ending December 31, 2004, 2005 and 2006 are $96.3
million, $135.4 million, and $10.5 million, respectively.
157
Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserve Quantities
- -----------------------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- -----------------------------------------------------------------------------------------------------------------------------------
At December 31, 2003 2002 2001
- -----------------------------------------------------------------------------------------------------------------------------------
Standardized measure - beginning of year $ 1,103,917 $ 586,186 $ 2,165,759
Sales and transfers, net of production costs (492,328) (285,603) (359,163)
Net change in sales and transfer prices, net
of production costs 384,299 589,632 (2,250,252)
Extensions and discoveries and improved
recovery, net of related costs 434,311 242,055 117,326
Changes in estimated future development costs (9,352) (6,453) (23,395)
Development costs incurred during the period
that reduced future development costs 81,025 42,075 75,652
Revisions of quantity estimates (123,954) (36,368) (52,928)
Accretion of discount 142,296 68,986 293,581
Net change in income taxes (236,551) (215,369) 666,373
Net purchases of reserves in place 254,030 99,741 51,674
Sales of reserves in place - (31,488) (133)
Changes in production rates (timing) and other (17,179) 50,523 (98,308)
- -----------------------------------------------------------------------------------------------------------------------------------
Standardized measure - end of year $ 1,520,514 $ 1,103,917 $ 586,186
- -----------------------------------------------------------------------------------------------------------------------------------
Average Sales Prices and Production Costs Per Unit
- ---------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2003 2002 2001
- ---------------------------------------------------------------------------------------------------------------------------
Average Sales Price*
Natural gas ($/Mcf) 5.23 3.16 4.09
Oil, condensate and natural gas liquid ($/Bbl) 28.26 24.06 23.09
Production cost per equivalent Mcf ($) 0.58 0.42 0.40
- ---------------------------------------------------------------------------------------------------------------------------
*Represents the cash price received which excludes the effect of any hedging
transactions.
158
Acreage
- ------------------------------------------------------------------------------
At December 31, 2003 Gross Net
- ------------------------------------------------------------------------------
Producing 638,425 396,192
Undeveloped 464,874 388,830
- ------------------------------------------------------------------------------
Number of Producing Wells
- -----------------------------------------------------------------------------
At December 31, 2003 Gross Net
- -----------------------------------------------------------------------------
Gas wells 2,435.0 1,748.0
Oil wells 31.0 15.9
- -----------------------------------------------------------------------------
Drilling Activity (Net)
- -----------------------------------------------------------------------------------------------------------------------------------
At December 31, 2003 2002 2001
- -----------------------------------------------------------------------------------------------------------------------------------
Producing Dry Total Producing Dry Total Producing Dry Total
--------------------------------------------------------------------------------------------------
Net developmental wells 84.4 20.0 104.4 65.1 9.4 74.5 51.9 10.2 62.1
Net exploratory wells 5.4 7.0 12.4 4.0 2.2 6.2 5.3 4.3 9.6
- -----------------------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------
At December 31, 2003 Gross Net
- -----------------------------------------------------------------------------
Exploratory 4.0 3.3
Developmental 12.0 9.2
- -----------------------------------------------------------------------------
159
Note 17. Summary of Quarterly Information (Unaudited)
The following is a table of financial data for each quarter of KeySpan's year
ended December 31, 2003.
Quarter Ended
- --------------------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars, Except Per Share Amounts) 3/31/2003 6/30/2003 9/30/2003 12/31/2003
- --------------------------------------------------------------------------------------------------------------------------------
Operating revenues 2,512,525 1,408,152 1,131,814 1,862,670
Operating income 456,694 138,229 107,923 338,811
Earnings (loss) from continuing operations 243,091 (5,938) 12,585 174,443
Cumulative change in accounting principle 174 - - (37,625)
Earnings (loss) for common stock 241,804 (7,399) 11,124 135,357
Basic earnings per common share from continuing
operations less preferred stock dividends (a) 1.54 (0.05) 0.07 1.08
Change in accounting principle (a) - - - (0.23)
Basic earnings per common share (a) 1.54 (0.05) 0.07 0.85
Diluted earnings per common share (a) 1.53 (0.05) 0.07 0.84
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, 2002.
Quarter Ended
- --------------------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars, Except Per Share Amounts) 3/31/2002 6/30/2002 9/30/2002 12/31/2002
- --------------------------------------------------------------------------------------------------------------------------------
Operating revenues 1,873,577 1,218,201 1,078,336 1,800,552
Operating income 406,038 115,383 97,692 322,969
Earnings from continuing operations 214,631 29,174 4,964 148,581
Earnings (loss) from discontinued 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
discontinued 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.
160
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors of KeySpan Corporation:
We have audited the accompanying Consolidated Balance Sheets of KeySpan
Corporation and subsidiaries (the Company) as of December 31, 2003 and 2002, and
the related Consolidated Statements of Income, Retained Earnings, Comprehensive
Income, Capitalization, and Cash Flows for each of the two years in the period
ended December 31, 2003. Our audits also included the consolidated financial
statement schedule, for each of the two years in the period ended December 31,
2003, included in the Index in Item 15. 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 statement
schedule based on our audits. The consolidated financial statements and
consolidated financial statement schedule of KeySpan Corporation for the year
ended December 31, 2001 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 audits 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 audits provide 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, 2003 and 2002, and the results of their
operations and their cash flows for each of the two years in the period ended
December 31, 2003, in conformity with accounting principles generally accepted
in the United States of America. Also in our opinion, such consolidated
financial statement schedule, for each of the two years in the period ended
December 31, 2003, 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(G) to the consolidated financial statements, on January
1, 2002, the Company adopted Statement of Financial Accounting Standards
("SFAS") No. 142, "Goodwill and Other Intangible Assets," (SFAS No. 142) to
change its method of accounting for goodwill and other intangibles. As discussed
in Note 1(N) and Note 1(P), on January 1, 2003, the Company adopted SFAS No.
148, "Accounting for Stock-Based Compensation - Transition and Disclosure" and
SFAS No. 143 "Accounting for Asset Retirement Obligations" (SFAS No. 143),
respectively. Also, as discussed in Note 1(P), on December 31, 2003, the Company
adopted FASB Interpretation No. 46, "Consolidation of Variable Interest
Entities, an Interpretation of ARB No. 51" (FIN 46).
161
As discussed above, the consolidated financial statements of the Company as of
December 31, 2001 were audited by other auditors who have ceased operations. The
notes related to these consolidated financial statements have been revised from
those originally issued to include the transitional disclosures required by SFAS
No. 142, SFAS No. 143 and FIN 46, which were adopted by the Company as of
January 1, 2002, January 1, 2003 and December 31, 2003, respectively. Our audit
procedures with respect to the disclosures in Note 1(G) for 2001 included (i)
agreeing the previously reported earnings for common shareholders to the
previously issued consolidated financial statements and the adjustments to
earnings for common shareholders 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. Our audit procedures
with respect to the disclosures in Note 1(P) for 2001 included (i) agreeing the
previously reported earnings for common stock to the previously issued
consolidated financial statements and the adjustments to earnings for common
stock representing accretion, cost of removal and amortization expense to the
Company's underlying records obtained from management, and (ii) testing the
mathematical accuracy of the reconciliation of Earnings for Common Stock to
reported pro forma earnings, and the related earnings-per-share amounts.
In addition, the 2001 consolidated financial statements have also been revised
from those originally issued to reflect certain reclassifications as discussed
in Note 1(B). These reclassifications have been made to the Consolidated
Statement of Income and the Consolidated Statement of Cash Flows. On the
Consolidated Statement of Income, "Income from Equity Investments" has been
reclassified from a component of "Other Income and (Deductions)" to a component
of "Operating Income." On the Consolidated Statement of Cash Flows, "Net
Income," "Minority Interest," "Changes in Assets and Liabilities - Other," and
"(Gain) Loss on Disposal of Subsidiary Stock" amounts have been reclassified.
Our audit procedures with respect to such reclassifications for 2001 included
(i) agreeing the amount to the previously issued consolidated financial
statements, and (ii) testing the mathematical accuracy of the consolidated
financial statements.
In our opinion, the adjustments in Note 1(G), Note 1(P), and the
reclassifications reflected in the Consolidated Statements of Income and Cash
Flows are appropriate and have been properly applied. However, we were not
engaged to audit, review, or apply any procedures to the 2001 financial
statements of the Company other than with respect to such adjustments and
reclassifications and, accordingly, we do not express an opinion or any other
form of assurance on the 2001 financial statements taken as a whole.
/s/Deloitte & Touche LLP
February 18, 2004
New York, New York
162
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholder 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 KeySpan Corporation's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audit 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 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 Andersen LLP completed
its last post-audit review of the December 31, 2001, consolidated financial
information on April 29, 2002.
163
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 three fiscal years,
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 three fiscal years, 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.
Item 9A. Controls and Procedures
KeySpan maintains "disclosure controls and procedures", as such term is defined
under Exchange Act Rule 13a-15(e), that are designed to ensure that information
required to be disclosed by KeySpan in the reports it files or submits under the
Securities Exchange Act of 1934, as amended (the "Exchange Act"), is recorded,
processed, summarized and reported within the time periods specified in the
Securities and Exchange Commission's rules and forms, and that such information
is accumulated and communicated to KeySpan's management, including its Chief
Executive Officer and Chief Financial Officer, as appropriate to allow timely
decisions regarding required disclosure.
An evaluation of the effectiveness of KeySpan's disclosure controls and
procedures as of December 31, 2003 was conducted under the supervision and with
the participation of KeySpan's Chief Executive Officer and Chief Financial
Officer. Based on that evaluation, KeySpan's Chief Executive Officer and Chief
Financial Officer have concluded that KeySpan's disclosure controls and
procedures were adequate and designed to ensure that material information
relating to KeySpan and its consolidated subsidiaries would be made known to the
Chief Executive Officer and Chief Financial Officer by others within those
entities, particularly during the periods when periodic reports under the
Exchange Act are being prepared. Furthermore, there has been no change in
KeySpan's internal control over financial reporting, identified in connection
with the evaluation of such control, that occurred during KeySpan's last fiscal
quarter that has materially affected, or is reasonably likely to materially
affect, KeySpan's internal control over financial reporting. Refer to the
Certifications by KeySpan's Chief Executive Officer and Chief Financial Officer
filed as exhibits 31.1 and 31.2 to this report.
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 25,
2004 (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, Certain Relationships and
Related Transactions", "Committees of the Board", "Code of Ethics" and "Section
16(a) Beneficial Ownership Reporting Compliance" contained in the Proxy
Statement, which information is incorporated herein by reference thereto.
164
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 and Item 5 of this report, which information is
incorporated herein by reference thereto.
Item 13. Certain Relationships and Related Transactions
The information required by this item is set forth under the caption "Agreements
with Executives" and "Certain Relationships and Related Transactions" in the
Proxy Statement, which information is incorporated by reference thereto.
Item 14. Principal Accounting Fees and Services
The information required by this item is set forth under the caption "Proposal
2. Ratification of Deloitte & Touche LLP as Independent Public Accountants,"
"Fiscal Year 2003 Audit Firm Fee Summary" and "Report of the Audit Committee" in
the Proxy Statement, which information is incorporated by reference thereto.
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) Required Documents
1. Financial Statements
The following consolidated financial statements of KeySpan and its subsidiaries
and report of independent accountants are included in Item 8 and are filed as
part of this Report:
o Consolidated Statement of Income for the year ended December 31, 2003, the
year ended December 31, 2002, and the year ended December 31, 2001
o Consolidated Statement of Retained Earnings for the year ended December 31,
2003, the year ended December 31, 2002, and the year ended December 31,
2001
o Consolidated Balance Sheet at December 31, 2003 and December 31, 2002
o Consolidated Statement of Capitalization at December 31, 2003 and December
31, 2002
o Consolidated Statement of Cash Flows for the year ended December 31, 2003,
the year ended December 31, 2002, and the year ended December 31, 2001
o Consolidated Statement of Comprehensive Income for the Year ended December
31, 2003, the year ended December 31, 2002 and the year ended December 31,
2001
o Notes to Consolidated Financial Statements
o Independent Auditors' Report
165
2. Financial Statement Schedules
Consolidated Schedule of Valuation and Qualifying Accounts for the year ended
December 31, 2003, the year ended December 31, 2002, and the year ended December
31, 2001.
SCHEDULE OF VALUATION AND QUALIFYING ACCOUNTS
- ------------------------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
- ------------------------------------------------------------------------------------------------------------------------------------
Descriptions Balance at Charged to Acquisitions Net Balance at
Beginning of costs and Deductions End of
Period expenses Period
- ------------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------
Twelve Months Ended December 31, 2003
- ------------------------------------------
Deducted from asset accounts:
Allowance for doubtful accounts $ 63,029 $ 82,120 $ - $ 65,965 $ 79,184
Additions to liability accounts:
Reserve for injury and damages $ 25,780 $ 3,928 $ - $ 20,338 $ 9,370
Reserve for environmental
expenditures $ 232,146 $ 106,270 $ - $ 43,725 $ 294,691
Twelve Months Ended December 31, 2002
- ------------------------------------------
Deducted from asset accounts:
Allowance for doubtful accounts $ 72,299 $ 58,939 $ - $ 68,209 $ 63,029
Additions to liability accounts:
Reserve for injury and damages $ 20,880 $ 11,984 $ - $ 7,084 $ 25,780
Reserve 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
Reserve for environmental
expenditures $ 157,507 $ 115,942 $ - $ 15,800 $ 257,649
- -----------------------------------------------------------------------------------------------------------------------------------
All other schedules are omitted because they are not applicable or the required
information is shown in the financial statements or notes thereto.
166
(b) Reports on Form 8-K
In our report on Form 8-K dated November 6, 2003, we disclosed that we issued a
press release concerning, among other things, our earnings for the third quarter
ended September 30, 2003.
In our report on Form 8-K dated December 18, 2003, we disclosed that we issued a
press release disclosing, among other things, our expectations for 2004
earnings.
In our report on Form 8-K dated February 5, 2004, we disclosed that we issued a
press release concerning, among other things, our consolidated earnings for the
year ended December 31, 2003.
(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 as of June 25, 2003, as amended (filed
as Exhibit 3.1 to the Company's Form 10-Q for the quarterly period
ended June 30, 2003)
4.1-a Indenture, dated as of November 1, 2000, between KeySpan Corporation
and the Chase Manhattan Bank, as Trustee, with 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)
167
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 Credit Agreement among KeySpan Corporation, the several Lenders, ABN
AMRO Bank, N.V., as Syndication Agent, Bank One, N. A. and Wachovia
Bank, N.A, as Co-Documentation Agents, and J.P. Morgan Chase Bank, as
Administrative Agent for $450 million, dated as of June 27, 2003
(filed as Exhibit 4.1 to the Company's Form 10-Q for the quarterly
period ended June 30, 2003)
4.4 Credit Agreement among KeySpan Corporation, the several Lenders,
Citibank N.A., as Syndication Agent, 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 $850 million, dated as of June
27, 2003 (filed as Exhibit 4.1 to the Company's Form 10-Q for the
quarterly period ended June 30, 2003)
4.5-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)
4.5-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)
4.5-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)
4.5-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)
168
4.6-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)
4.6-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)
4.7-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)
4.7-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)
4.8-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)
4.8-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)
4.9-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)
4.9-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)
4.10-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)
169
4.10-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)
4.11-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)
4.11-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)
4.11-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)
4.12-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)
4.12-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)
4.13-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)
4.13-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)
4.14-a* Lease Agreement, dated as of November 1, 2003, by and between the
Suffolk County Industrial Development Agency and KeySpan-Port
Jefferson Energy Center, LLC
4.14-b* Company Lease Agreement, dated as of November 1, 2003, by and between
KeySpan-Port Jefferson Energy Center, LLC and the Suffolk County
Industrial Development Agency
4.14-c* Guaranty, dated as of November 26, 2003, from KeySpan Corporation to
the Suffolk County Industrial Development Agency
170
4.15-a* Lease Agreement, dated as of November 1, 2003, by and between the
Nassau County Industrial Development Agency and KeySpan-Glenwood
Energy Center, LLC
4.15-b* Company Lease Agreement, dated as of November 1, 2003, by and between
KeySpan-Glenwood Energy Center, LLC and the Nassau County Industrial
Development Agency
4.15-c* Guaranty, dated as of November 26, 2003, from KeySpan Corporation to
the Nassau County Industrial Development Agency
4.16 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))
4.17 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
Statement (File No. 33-31869))
4.18 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)
4.19 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)
4.20 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)
4.21 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)
4.22 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)
4.23 Fourth Supplemental Indenture for Colonial Gas Company dated as of
March 1, 1998 (filed as Exhibit 4(l) to Colonial Gas Company's Form
10-Q for the quarter ended March 31, 1998)
4.24 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)
171
4.25 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 Natural Gas, Inc.'s Form 10-K for the fiscal year ended
September 30, 1989 (File No. 0-11035))
4.26 Third Supplemental Indenture, dated as of September 1, 1990, to Gas
Service, Inc.'s General and Refunding Mortgage Indenture, dated as of
June 30, 1987 (filed as Exhibit 4.2 to EnergyNorth Natural Gas, Inc.'s
Form 10-K for the fiscal year ended September 30, 1990 (File No.
0-11035))
4.27 Fourth Supplemental Indenture, dated as of January 10, 1992, to Gas
Service, Inc.'s General and Refunding Mortgage Indenture, dated as of
June 30, 1987 (filed as Exhibit 4.3 of EnergyNorth Natural Gas, Inc.'s
Form 10-K for the fiscal year ended September 30, 1992 (File No.
0-11035))
4.28 Fifth Supplemental Indenture, dated as of February 1, 1995, to Gas
Service, Inc.'s General and Refunding Mortgage Indenture, dated as of
June 30, 1987 (filed as Exhibit 4.4 to EnergyNorth Natural Gas, Inc.'s
Form 10-K for the fiscal year ended September 30, 1996 (File No.
1-11441))
4.29 Sixth Supplemental Indenture, dated as of September 15, 1997, to Gas
Service, Inc.'s 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)
4.30 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))
4.31 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% Series due 2020 (filed as Exhibit 4-14 to Essex
Gas Company's Form 10-Q for the quarter ended February 28, 1991)
4.32 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 % Series due 2017 (filed as Exhibit 4.5 to the
Essex Gas Company's Form 10-Q for the quarter ended February 28, 1997)
4.33 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 Essex Gas Company's Form 10-Q for the quarter ended
February 28, 1991)
4.34* Letter of Credit and Reimbursement Agreement dated December 9, 2003,
by and between KeySpan Generation LLC and Royal Bank of Scotland Bank
PLC
172
4.35 Indenture, dated as of March 2, 1998, between The Houston Exploration
Company and The Bank of New York, as Trustee, with respect to the 8
5/8% Senior Subordinated Notes Due 2008 (including form of 8 5/8%
Senior Subordinated Note Due 2008) (filed as Exhibit 4.1 to The
Houston Exploration Company's Registration Statement on Form S-4 (No.
333-50235))
4.36 Indenture, dated as of June 10, 2003, between The Houston Exploration
Company and the Bank of New York, as Trustee, with respect to the 7%
Senior Subordinated Notes due 2013. (filed as Exhibit 4.2 to The
Houston Exploration Company's Registration Statement on Form S-4 (No.
333-106836)
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 (filed as Exhibit 10.4-b to the
Company's Annual Report on Form 10-K for the year ended December 31,
2002)
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)
173
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 (filed as Exhibit
10.6-b to the Company's Annual Report on Form 10-K for the year ended
December 31, 2002)
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)
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 July 1, 2002 between KeySpan
and Gerald Luterman (filed as Exhibit 10.11 to the Company's Annual
Report on Form 10-K for the year ended December 31, 2002)
10.12** Supplemental Retirement Agreement dated July 1, 2002 between KeySpan
and Steven L. Zelkowitz (filed as Exhibit 10.12 to the Company's
Annual Report on Form 10-K for the year ended December 31, 2002)
10.13** Supplemental Retirement Agreement dated July 1, 2002 between KeySpan
and David J. Manning (filed as Exhibit 10.13 to the Company's Annual
Report on Form 10-K for the year ended December 31, 2002)
10.14** Supplemental Retirement Agreement dated July 1, 2002 between KeySpan
and Neil Nichols (filed as Exhibit 10.14 to the Company's Annual
Report on Form 10-K for the year ended December 31, 2002)
10.15** Supplemental Retirement Agreement dated July 1, 2002 between KeySpan
and Elaine Weinstein (filed as Exhibit 10.15 to the Company's Annual
Report on Form 10-K for the year ended December 31, 2002)
174
10.16** * Directors' Deferred Compensation Plan effective April 2003
10.17** Officers' Deferred Stock Unit Plan of KeySpan Corporation (filed as
Exhibit 10.17 to the Company's Annual Report on Form 10-K for the year
ended December 31, 2002)
10.18** Officers' Deferred Stock Unit Plan KeySpan Services, Inc. (filed as
Exhibit 10.18 to the Company's Annual Report on Form 10-K for the year
ended December 31, 2002)
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 29, 2003
10.21** KeySpan's Amended Long Term Performance Incentive Compensation Plan
(filed as Exhibit A to the Company's 2001 Proxy Statement filed 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 filed on
March 30, 1999)
10.23 Generating Plant and Gas Turbine Asset Purchase and Sale Agreement for
the Ravenswood Generating Plants and Gas Turbines dated January 28,
1999, between the Company 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 Agreement between KeySpan-Ravenswood, LLC
and LIC Funding, Limited Partnership, dated as of June 27, 2002 (filed
as Exhibit 10.25 to the Company's Annual Report on Form 10-K for the
year ended December 31, 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 as Exhibit 10.27 to the
Company's Annual Report on Form 10-K for the year ended December 31,
2002)
175
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-a 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)
10.29-b First Amendment to Credit Agreement among The Houston Exploration
Company, the lenders Wachovia Bank, National Association, as issuing
bank and as administrative agent, The Bank of Nova Scotia and Fleet
National Bank, as co-syndication agents; and BNP Paribas, as
documentation agent, effective June 5, 2003 (filed as Exhibit 10.1 to
The Houston Exploration Company's Quarterly Report on Form 10-Q for
the quarter ended June 30, 2003 (File No. 001-11899)).
10.29-c Second Amendment to Credit Agreement among The Houston Exploration
Company, the lenders named therein, Wachovia Bank, National
Association, as issuing bank and as administrative agent, The Bank of
Nova Scotia and Fleet National Bank, as co-syndication agents; and BNP
Paribas, as documentation agent, effective September 3, 2003 (filed as
Exhibit 10.1 to The Houston Exploration Company's Quarterly Report on
Form 10-Q for the quarter ended September 30, 2003 (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
176
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)
10.33 Registration Rights Agreement dated as of July 2, 1996 between The
Houston Exploration Company and THEC Holdings Corp. (filed as Exhibit
10.13 to The Houston Exploration Company's Registration Statement on
Form S-1 (Registration No. 333-4437))
10.34 Registration Rights Agreement between The Houston Exploration Company
and Smith Offshore Exploration Company (filed as Exhibit 10.15 to The
Houston Exploration Company's Registration Statement on Form S-1
(Registration No. 333-4437))
10.35 Registration Rights Agreement dated as of June 5, 2003, among The
Houston Exploration Company and Wachovia Securities, Inc., Lehman
Brothers Inc., BNP Paribas Securities Corp., Fleet Securities, Inc.
and Scotia Capital (USA) Inc., as Initial Purchasers. (Exhibit 4.5 to
The Houston Exploration Company's Registration Statement on Form S-4
(Registration No. 333-106836))
12* Computation in support of earnings to fixed charges and ratio of
combined fixed charges and dividends
14* Code of Ethics
21* Subsidiaries of the Registrant
23.1* Consent of Deloitte & Touche LLP, Independent Auditors
177
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 Andrea S. Christensen on March 10, 2004
24.2* Power of Attorney executed by Alan H. Fishman on March 10, 2004
24.3* Power of Attorney executed by J. Atwood Ives on March 10, 2004
24.4* Power of Attorney executed by James R. Jones on March 10, 2004
24.5* Power of Attorney executed by James L. Larocca on March 10, 2004
24.6* Power of Attorney executed by Gloria C. Larson on March 10, 2004
24.7* Power of Attorney executed by Stephen W. McKessy on March 10, 2004
24.8* Power of Attorney executed by Edward D. Miller on March 10, 2004
24.9* Certified copy of the Resolution of the Board of Directors authorizing
signatures pursuant to power of attorney
31.1* Certification of the Chairman and Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
31.2* Certification of the Executive Vice President and Chief Financial
Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1* Certification of the Chairman and Chief Executive Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
32.2* Certification of the Executive Vice President and Chief Financial
Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
* filed herewith
** compensation agreement
178
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, this report has been signed by the registrant and on behalf of the
registrant by the following persons in the capacities indicated.
KEYSPAN CORPORATION
By:/s/ Robert B. Catell
-----------------
Robert B. Catell
Chairman of the Board of
Directors and
Chief Executive Officer
Robert B. Catell Chairman of the Board of Directors
and Chief Executive Officer
By:/s/ Robert B. Catell
- ------------------------
Gerald Luterman Executive Vice President and
Chief Financial Officer
By:/s/ Gerald Luterman
- ----------------------
Joseph F. Bodanza Senior Vice President and
Chief Accounting Officer
By:/s/Joseph F. Bodanza
- -----------------------
*
- --------------------
Andrea S. Christensen Director
*
- --------------------
Alan H. Fishman Director
*
- --------------------
J. Atwood Ives Director
*
- --------------------
James R. Jones Director
179
*
- --------------------
Gloria C. Larson Director
*
- --------------------
James L. Larocca Director
*
- --------------------
Stephen W. McKessy Director
*
- --------------------
Edward D. Miller Director
- --------------------
Vikki Pryor 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.
180