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, 2004
Commission File Number 1-14161
KEYSPAN CORPORATION
(Exact name of registrant as specified in its charter)
NEW YORK 11-3431358
(State or other jurisdiction of (I.R.S. employer identification no.)
incorporation or organization)
One MetroTech Center, Brooklyn, New York 11201
175 East Old Country Road, Hicksville, New York 11801
(Address of principal executive offices) (Zip code)
(718) 403-1000 (Brooklyn)
(516) 755-6650 (Hicksville)
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of each class Name of each exchange on which registered
------------------- -----------------------------------------
Common Stock, $.01 par value New York Stock Exchange
Pacific Stock Exchange
Series AA Preferred Stock, $25 par value New York Stock Exchange
Pacific Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None (Title of
class) Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. 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, 2004, the aggregate market value of the common stock held by
non-affiliates (160,169,624 shares) of the registrant was $5,878,225,201 based
on the closing price of the New York Stock Exchange on such date, of $36.10 per
share. For purposes of this computation, all officers and directors of the
registrant are deemed to be affiliates.
As of February 15, 2005, there were 160,818,311 shares of common stock,
$.01 par value, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Proxy Statement dated on or about March 29, 2005 is incorporated by
reference into Part III hereof.
KEYSPAN CORPORATION
INDEX TO FORM 10-K
Page
----
PART I
Item 1. Business...............................................................................................1
Item 2. Properties........................................................................................... 33
Item 3. Legal Proceedings.....................................................................................33
Item 4. Submission of Matters to a Vote of Security Holders...................................................33
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities....................................................................................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 Mark Risk..............................................90
Item 8. Financial Statements and Supplementary Data...........................................................93
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure................................................................................172
Item 9A. Controls and Procedures..............................................................................172
Item 9B. Other Information....................................................................................173
PART III
Item 10. Directors and Executive Officers of the Registrant...................................................175
Item 11. Executive Compensation...............................................................................175
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.......175
Item 13. Certain Relationships and Related Transactions.......................................................175
Item 14. Principal Accountant Fees and Services...............................................................175
Item 15. Exhibits and Financial Statement Schedules ..........................................................176
PART I
Item 1. 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 2.6 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 2,450 megawatt
Ravenswood electric generation facility (the "Ravenswood Facility"), located in
Queens County in New York City, which includes the 250 megawatt combined cycle
generating unit which began full commercial operation in May 2004, as well as
market generating capacity and energy to commercial retail customers.
The Energy Services segment provides energy-related and fiber optic services to
customers primarily located within the Northeastern United States, with
concentrations in the New York City and Boston metropolitan areas through
various subsidiaries that operate under the following principal two lines of
business: (i) Home Energy Services; and (ii) Business Solutions. Management has
been reviewing the operating performance of this segment, which has experienced
significantly lower operating profits than originally projected. In January and
February of 2005, we disposed of our ownership interests in the companies
engaged in mechanical contracting activities.
1
The Energy Investments segment includes: (i) gas exploration and production
activities; (ii) domestic pipelines and gas storage facilities; and (iii)
natural gas pipeline activities in the United Kingdom.
KeySpan's strategic vision is to be the premier energy company in the
Northeastern United States. KeySpan is the largest gas distribution company in
the Northeast and the fifth largest in the United States. KeySpan's size and
scope enables 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 growth opportunities for natural
gas expansion in the Northeast by expanding our infrastructure, primarily on
Long Island and in New England.
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 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.
The risks, uncertainties and factors that could cause actual results to differ
materially include but are not limited to:
- - volatility of fuel prices used to generate electricity;
- - fluctuations in weather and in gas and electric prices;
- - general economic conditions, especially in the Northeast United States;
- - our ability to successfully manage 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 or changes in accounting
standards or GAAP which may require adjustment to financial statements;
- - inflationary trends and interest rates;
- - the ability of KeySpan to identify and make complementary acquisitions, as
well as the successful integration of such acquisitions;
- - available sources and cost of fuel;
- - creditworthiness of counter-parties to derivative instruments and commodity
contracts;
2
- - the resolution of certain disputes with LIPA concerning each party's rights
and obligations under various agreements;
- - retention of key personnel;
- - federal, state and local regulatory initiatives that 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, state and local 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 facing our unregulated Energy Services businesses;
- - 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;
- - change in political conditions, acts of war or terrorism;
- - a change in the fair market value of our investments that could cause a
significant change in the carrying value of such investments or the
carrying value of related goodwill;
- - timely receipts of payments from LIPA and the New York Independent System
Operator ("NYISO"), our two largest customers;
- - the outcome of LIPA's strategic business options study, pertaining to its
long-term future which include, as stated by LIPA, whether or not LIPA will
continue its operations as they presently exist, fully municipalize or
privatize, sell some, but not all of its assets and/or become a regulator
of rates and services, or merge with one or more utilities. In addition,
LIPA must make a determination by May 28, 2005, as to whether it will
purchase our interest in KeySpan Generation LLC, the owner of our Long
Island (excluding the Glenwood and Port Jefferson Energy Center units)
generating assets, pursuant to the terms of the Generation Purchase Rights
Agreement; 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.
3
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 an Ethical Business Conduct Statement
applicable to all directors, officers and employees of the Company as required
by securities rules and regulations.
KeySpan's Code of Ethics, Ethical Business Conduct Statement, Corporate
Governance Guidelines, the Corporate Governance and Nominating Committee
Charter, the Compensation and Management Development Committee Charter, the
Audit Committee Charter and the Executive Committee Charter (collectively,
"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.
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 2.6 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 1.68
million customers. In Massachusetts, Boston Gas, Colonial Gas and Essex Gas
serve three contiguous service territories consisting of 1,934 square miles and
approximately 792,000 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
80,000 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 23,336 miles of gas mains and
distribution pipelines.
4
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 either
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 maintain a diverse
portfolio of firm gas supply, storage and pipeline transportation capacity
contracts to adequately serve the requirements of our gas sales customers, to
maintain system reliability and system operations, and to meet our obligation to
serve. 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.
KeySpan actively promotes a competitive retail gas market by offering tariff
firm transportation services to firm gas customers who elect to purchase their
gas supplies from natural gas marketers rather than from the utility. KeySpan
further facilitates competition by releasing its pipeline transportation
capacity and offering bundled gas supply to natural gas marketers that would
otherwise not be able to obtain their own capacity, and are not participants of
mandatory capacity assignment programs in Massachusetts and New Hampshire.
KeySpan also participates in interstate markets by releasing pipeline capacity
and by selling bundled gas services to customers located outside of our service
territory ("off-system" customers).
KeySpan purchases natural gas for firm gas customers under both long and
short-term supply contracts, as well as on the spot market, and utilizes its
firm pipeline transportation contracts to transport the gas from the point of
purchase to the market. KeySpan also contracts for firm capacity in natural gas
underground storage facilities to store gas during the summer for later
withdrawal during the winter heating season when gas customer demand is higher.
KeySpan also contracts for firm winter peaking supplies to meet firm gas
customer demand on the coldest days of the year.
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
5
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.
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 2,115 MDTH (one MDTH equals 1,000 DTH or 1 billion British Thermal
Units) of gas for a peak-day during the 2004/05 winter season and that the gas
available to us on such a peak-day amounts to approximately 2,190 MDTH. The
highest sendout day most recently experienced occurred on January 18, 2005 in
which the demand of the firm New York customers was 1839 MDTH, and the average
temperature was 13(0)F. Our New York firm gas peak-day capability is summarized
in the following table:
MDTH per
Source day % of Total
- ---------------------------------- ------------------------- ------------------------
Pipeline 822 38%
Underground Storage 798 36%
Peaking Supplies 570 26%
--- ---
Total 2,190 100%
========================= ========================
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
2004/05 winter, approximately 80% of our New York natural gas supply was
available from domestic sources and 20% from Canadian sources. We have available
under firm contract 822 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.
6
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., National Fuel and Honeoye Storage Corporation
("Honeoye") for underground storage capacity of 60,456 MDTH and 798 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; (ii) peaking supply contracts with five dual-fuel
power producers located in our franchise areas; and (iii) three peaking supply
contracts with suppliers located outside our franchise area. For the 2004/05
winter season, we have the capability to provide a maximum peaking supplies of
570 MDTH on excessively cold days. The LNG plants provide us with peak-day
capacity of 394 MDTH and winter season availability of 2,053 MDTH. The peaking
supply contracts with the five dual fuel power producers provide us with
peak-day capacity of 176 MDTH and winter season availability of 4,146 MDTH.
Gas Supply Management. We have an agreement with Coral Resources, L.P.
("Coral"), a subsidiary of Shell Oil Company, under which Coral assists in the
origination, structuring, valuation and execution of energy-related transactions
on behalf of KEDNY and KEDLI which expires on March 31, 2005. Upon expiration of
the agreement with Coral, we will perform these services with our own staff.
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, 2005, approximately 105,334 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.
7
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 in Massachusetts and 80 effective degree
days in New Hampshire for peak-day demand. Under such criteria, KEDNE estimates
that the requirements to supply their firm gas customers would amount to
approximately 1,351 MDTH of gas for a peak-day during the 2004/2005 winter
season. The gas available to KEDNE on such a peak-day amounts to 1,420 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 1,456
MDTH.
The highest daily throughput, which includes both firm sales and firm
transportation, to our New England customers was 1,420 MDTH, which occurred on
January 15, 2004 at a level of 80 effective degree days. The total throughput of
1,420 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 2004/2005 winter season. The
firm gas supply peak-day capability of KEDNE for its firm customers is
summarized in the following table:
MDTH per
Source day % of Total
- ------------------------------------- ------------------------- -------------------------
Pipeline 500 35%
Underground Storage 248 18%
Peaking Supplies 672 47%
----- ----
Total 1,420 100%
========================= =========================
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. We have available
under firm contract 500 MDTH per day of year-round and seasonal transportation
capacity. 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. In order to meet our winter demand in the New England
service territories, 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 248 MDTH per day of maximum deliverability.
8
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 four leased facilities located in
Providence, Rhode Island, and Lynn, Salem and Everett, Massachusetts. For the
2004/2005 winter season, on a peak-day, KEDNE has access to 672 MDTH of peaking
supplies, 47% of peak-day supply.
Gas Supply Management. The New England based gas distribution subsidiaries
operate under portfolio management contracts with Merrill Lynch Commodities,
formerly Entergy Koch Trading, LP, ("Merrill Lynch") that will expire on March
31, 2006. Merrill Lynch provides the majority of the city gate supply
requirements to the four New England gas distribution companies (Boston Gas,
Colonial Gas, Essex Gas and EnergyNorth) at market prices and 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.
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, a recently completed 250 MW combined cycle generating
unit and 17 gas turbine generators. We also operate and maintain a 55 MW gas
turbine unit in Greenport, Long Island under an agreement with Hawkeye Energy
Greenport, LLC.
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 pursuant to a management services agreement (the "MSA"); (ii) supply LIPA
with electric generating capacity, energy conversion and ancillary services from
our Long Island generating units pursuant to a power supply agreement (the
"PSA") and other long-term agreements through which we 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
pursuant to 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." In addition, pursuant
9
to power purchase agreements with LIPA, we supply electric capacity and energy
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 MW 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, KeySpan-Ravenswood, LLC ("KSR"). For more information
concerning this lease arrangement, 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."
In 2004, we completed the construction of a 250 MW combined cycle generating
unit at the Ravenswood Facility (the "Ravenswood Expansion"), thereby increasing
the total electric capacity of the Ravenswood Facility to 2,450 MW. In mid-May
2004, the Ravenswood Expansion began full commercial operations. To finance the
Ravenswood Expansion, we entered into a leveraged lease financing arrangement
pursuant to which the Ravenswood Expansion was acquired by an unaffiliated
lessor from KSR and simultaneously leased back to it. This lease transaction
qualifies as an operating lease under SFAS 98. 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.
The Ravenswood Facility, including the Ravenswood Expansion, sells capacity,
energy and ancillary services into the NYISO electricity market at market-based
rates, subject to mitigation. The Ravenswood Facility 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.
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-six of our seventy-eight 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 instituted a program to reduce
nitrogen oxides for improved environmental performance while recovering 80 MW of
energy output.
10
The following table indicates the 2004 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 1711
Long Island City Combined Cycle Dual* 1 222
Northport, L.I. Steam Turbine Dual* 4 1549
Port Jefferson, L.I. Steam Turbine Dual* 2 384
Glenwood, L.I. Steam Turbine Gas 2 239
Island Park, L.I. Steam Turbine Dual* 2 398
Far Rockaway, L.I. Steam Turbine Dual* 1 111
Long Island City GT Units Dual* 17 452
Glenwood and Port Jefferson Energy GT Units Dual 4 160
Center, L.I.
Throughout L.I. GT Units Dual* 12 311
Throughout L.I. GT Units Oil 30 1074
--
TOTAL 78 6611
----
============================================================================================================================
*Dual - Oil (#2 oil, #6 residual oil) or kerosene, and natural gas.
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 LIPA Agreements and subsequent Power Purchase
Agreements, during 2004, KeySpan provided: 4,226 MW of summer generation
capacity and energy conversion services; operation, maintenance and capital
improvement services for LIPA's T&D 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 the FERC in accordance with
the terms of the PSA. The prior FERC approved rates, which had been in effect
since May 1998, expired on December 31, 2003. On October 1, 2004, the FERC
approved a settlement reached between KeySpan and LIPA with respect to new rates
and certain other costs and expenses. Pursuant to the FERC approved settlement,
KeySpan's rates reflect a cost of equity of 9.5% with no revenue increase. The
FERC also approved updated operating and maintenance expense levels and
KeySpan's recovery of certain other costs as agreed to by the parties. 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
11
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 2004, we earned
$4 million in incentives under the PSA.
The PSA runs for an original term of 15 years, expiring in 2013. 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 purchases, at fair market value, all of
KeySpan's interest in KeySpan Generation LLC 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.
Generation Purchase Rights Agreement. Under an amended Generation Purchase
Rights Agreement ("GPRA"), LIPA has the right for a 6-month period, beginning
November 29, 2004, to acquire KeySpan's interest in KeySpan Generation LLC,
which includes 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. We are
unable to predict whether LIPA will exercise its purchase option during this
period, what the purchase price would be or the effect of such purchase on our
financial condition, results of operations or cash flow.
Management Services Agreement. Under the MSA, we perform day-to-day operation
and maintenance services and capital improvements on LIPA's T&D system,
including, among other functions, T&D 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 T&D system.
12
In exchange for providing these services, we (i) are reimbursed for our budgeted
costs; (ii) are entitled to earn an annual management fee of $10 million; and
(iii) 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 2004, we earned $7.4 million in
non-cost performance incentives. The MSA expires on December 31, 2008.
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 original
term for the fuel supply service described in (i) above is fifteen years,
expiring May 28, 2013, and the original term for the off-system purchases and
sales services described 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 purchased on behalf of LIPA. In 2004, we earned EMA
incentives in an aggregate of $5 million.
On December 9, 2004, LIPA issued a Request for Proposal ("RFP") for a new energy
manager to provide system power supply services (commencing on May 29, 2006),
fuel procurement for Long Island generating facilities not acquired from LILCO
in 1998 and strategic fuel management services, commencing on January 1, 2006.
KeySpan intends to submit a bid to LIPA on or before March 1, 2005.
Power Purchase Agreements. KeySpan Glenwood Energy Center LLC and KeySpan Port
Jefferson Energy Center LLC each have 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 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.
Other Contingencies. LIPA is in the process of performing a strategic review
initiative regarding its future direction. It has engaged a team of advisors and
consultants and is conducting public hearings to develop recommendations to be
submitted to the LIPA Trustees. Some of the strategic options that LIPA is
considering include whether LIPA should continue its operations as they
13
presently exist, fully municipalize or fully privatize, sell some, but not all
of its assets and become a regulator of rates and services, or merge with one or
more utilities. In the near term, LIPA must make a determination by May 28, 2005
as to whether it will exercise its option to purchase our interest in KeySpan
Generation LLC pursuant to the terms of the GPRA. Until LIPA makes a
determination on its future direction, we are unable to determine what the
impact will be on our financial condition, results of operations or cash flows.
Other Rights. Pursuant to other agreements between LIPA and KeySpan, 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.
We own common plant assets (such as administrative office buildings and computer
systems) formerly owned by LILCO and recover an allocable share of the carrying
costs of such plant assets 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 assets 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 (during the pendency 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 or liabilities which 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 PSA.
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.
14
Energy Services Overview
The Energy Services segment includes companies that provide energy-related
services to customers primarily located within the northeastern United States,
with concentrations in the New York City and Boston metropolitan areas through
the following two lines of business: (i) Home Energy Services, which provides
residential customers and small commercial customers with installation, service
and maintenance of energy systems and appliances; and (ii) Business Solutions,
which provides energy-related operation and maintenance, design, engineering and
consulting services to commercial and industrial customers.
The Energy Services segment has more than 1,000 employees and approximately
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 HVAC, 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.
As a result of an extremely competitive market and sluggish economic conditions
within the construction industry in the Northeastern United States, the Energy
Services segment has experienced significantly lower operating profits and cash
flows than originally projected. As previously reported, management has been
reviewing the operating performance of this segment. In November 2004, KeySpan's
Board of Directors authorized management to begin the process of disposing of a
significant portion of its ownership interests in certain companies within the
Energy Services segment - specifically those companies engaged in mechanical
contracting activities. In the first quarter of 2005, the Company divested all
of its mechanical contracting subsidiaries.
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)
natural gas pipeline activities in the United Kingdom; and (iv) certain other
domestic energy-related investments, such as the transportation by truck of
liquid natural gas.
Gas Exploration and Production
KeySpan is engaged in the exploration for and production of domestic natural gas
and oil through wholly-owned subsidiaries Seneca-Upshur Petroleum, Inc., d/b/a
KeySpan Production & Development Company ("Seneca-Upshur") and KeySpan
Exploration and Production, LLC ("KeySpan Exploration and Production"). KeySpan
Exploration and Production is involved in a joint venture with The Houston
Exploration Company ("Houston Exploration") a former subsidiary of the Company.
15
In June 2004, KeySpan reduced its ownership in Houston Exploration from 55% to
23.5%, through an exchange of 10.8 million shares of its Houston Exploration
common stock for 100% of the stock of Seneca-Upshur, previously a wholly owned
subsidiary of Houston Exploration. Seneca-Upshur's assets consist of 50 billion
cubic feet of low risk, mature, onshore gas producing properties located
predominantly in West Virginia and Pennsylvania. In November 2004, KeySpan
decided to sell its remaining ownership interest (approximately 6.6 million
shares of common stock) in Houston Exploration. See Item 7. Management's
Discussion and Analysis of Financial Conditions and Results of Operations -
"Energy Investments" for a further discussion of these matters.
As indicated above, as a result of the transactions with Houston Exploration,
Seneca-Upshur, headquartered in Buckhannon, West Virginia, owns and operates
onshore gas producing properties, and operates approximately 1,300 wells in
north central West Virginia and southern Pennsylvania. To manage the inherent
volatility in commodity prices, Seneca-Upshur entered into a three-year hedge
for a majority of its production at favorable prices.
As previously indicated, KeySpan Exploration and Production is engaged in a
joint venture with Houston Exploration to explore for and produce 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 and
Production 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 and Production 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, KeySpan Exploration and
Production sold its interest in the gas-producing assets in the joint venture
drilling program to Houston Exploration. KeySpan Exploration and Production's
remaining joint venture assets are primarily proved undeveloped oil reserves
located off the Gulf of Mexico in the South Timbalier and Mustang Island areas.
Domestic Pipelines and Gas Storage Facilities
We own a 20.4% interest in Iroquois Gas Transmission System LP, the partnership
that owns a 411-mile pipeline that can bring up to 1,176,000 DTH per day of
Canadian gas supply 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 312,000 DTH of gas per day.
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, under Long Island
Sound, to a terminus near Shoreham, Long Island. Applications for all necessary
regulatory authorizations were filed in 2000 and 2001. Islander East has
received a final certificate from the FERC and all necessary permits from the
State of New York. The State of Connecticut denied Islander East's applications
for coastal zone management and Section 401 of the Clean Water Act
authorizations. Islander East appealed the State of Connecticut's determination
on the coastal zone management issue to the United States Department of
Commerce. On May 6, 2004, the Department of Commerce overrode Connecticut's
denial and granted the coastal zone management authorization. Islander East's
petition for a declaratory order challenging the denial of the Section 401
16
authorization is pending with Connecticut's State Superior Court. Once in
service, the pipeline is expected to transport up to 285,000 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. Various options for the financing of this pipeline
construction are currently being evaluated. As of December 31, 2004, KeySpan's
total capitalized costs associated with the siting and permitting of the
Islander East pipeline were approximately $20 million.
In August 2004, KeySpan acquired a 21% interest in the Millennium Pipeline
development project is anticipated to transport up to 500,000 DTH of natural gas
a day from Corning to Ramapo, New York, where it will connect to the Algonquin
pipeline. The other partners in the Millennium Pipeline are DTE Energy, Columbia
Gas Transmission Corp., a unit of NiSource Incorporated. The project has been
approved by the FERC and, pending an amendment to the project's FERC
certificate, construction could begin as early as the third quarter of 2005,
with service beginning as early as November 2006. The Millennium Pipeline will
provide KeySpan with new, competitively priced supplies of natural gas from
Canada. Further, the project will increase KeySpan's access to gas storage in
the Great Lakes region, adding critical flexibility to KeySpan's gas supply,
while helping to control price volatility based on weather conditions. Once
constructed, KeySpan plans to purchase 150,000 DTH per day from the Millennium
Pipeline system, which represents approximately 12.5% of New York City's
peak-day requirements. As of December 31, 2004, total capitalized costs
associated with the Millennium Pipeline project were $6 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 ("KLNG"), is regulated by FERC. In a joint
initiative with BG LNG Services, KeySpan plans to upgrade the KLNG facility to
accept marine deliveries and to triple vaporization (or regasification)
capacity.
On February 25, 2005, KLNG filed a lawsuit in federal court to clarify the
appropriate process to be used by the Rhode Island Coastal Resources Management
Council for its review of the proposed upgrade of KLNG's energy storage
facility. Pending regulatory approvals, the facility should be ready to accept
marine deliveries in the 2006 or 2007 timeframe.
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.
17
Natural Gas Distribution and Pipeline Activities in the United Kingdom
In December, 2003, the Company sold its interest in Phoenix Natural Gas Limited,
the gas distribution system serving the City of Belfast, Northern Ireland.
KeySpan continues to own a 50% interest in Premier Transmission Limited
("Premier"), 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. In January of 2005, KeySpan decided to
proceed with the disposition of our 50% ownership interest in Premier. In view
of the likely disposition on the terms currently contemplated, a determination
was also made that a material reduction in the carrying value of our investment
in this entity was required. Accordingly, in the fourth quarter of 2004, the
Company recorded a pre-tax impairment charge of $26.5 million for its investment
in Premier.
On February 25, 2005, subsidiaries of KeySpan entered into a Share Sale and
Purchase Agreement with BG Energy Holdings Limited and Premier Transmission
Financing plc ("PTF"), pursuant to which all of the outstanding shares of
Premier are to be purchased by PTF. It is expected that the sale of our 50%
interest in Premier will result in net proceeds before taxes of approximately
$42.5 million. It is anticipated that the closing of this transaction will occur
before the end of the second quarter.
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
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.
18
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 facilities 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 were to expire in
2004. To date, five of the permits were renewed and the remaining renewal
applications, although in various stages of the regulatory process, are deemed
completed by DEC. In addition, three permit modifications were also submitted
and approved. 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 low NOX 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 emission 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 to enhance compliance options.
In 2003, New York State promulgated regulations which establish separate NOX and
SO2 emission reduction requirements on electric generating facilities in New
York State beginning in late 2004 for NOX emissions and in 2005 for SO2
emissions. KeySpan's facilities are expected to comply with the NOX requirements
without material additional capital expenditures because of previously installed
emissions control equipment and gas combustion capability. SO2 compliance is
expected to require a reduction in the sulfur content of the fuel oil used in
our Northport and Port Jefferson facilities.
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.
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 ("CO2")) 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 additional natural gas firing
capability have resulted in approximately a 15% reduction in carbon dioxide
19
emissions since 1990, while the electric generation industry as a whole
increased carbon dioxide emissions by more than 25%. The addition of the
efficient, combined cycle unit which began operation at Ravenswood in 2004 will
further reduce average KeySpan CO2 emission rates.
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 will likely be required by
the DEC. We are currently conducting studies as directed by the DEC to determine
the impacts of our discharges on aquatic resources. It is not possible at this
time to predict the extent of such capital investments since they will depend
upon the outcome of the ongoing studies and the subsequent determination by the
DEC to apply the standards set forth in recently promulgated federal regulations
under Section 316 of the Clean Water Act designed to mitigate such impacts.
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."
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."
20
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 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.
State Utility Commissions. Our regulated gas distribution 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 subsidiary which engages in the retail
sale of electricity is subject to certain regulations of 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
21
for the Long Island generating facilities with agreed-upon yearly adjustments,
which have been approved by FERC. These FERC approved rates expired on December
31, 2003. A rate filing reflecting a recalculated revenue requirement was
submitted to FERC on October 31, 2003. On October 1, 2004 FERC approved a
settlement reached between KeySpan and LIPA with respect to new rates and
certain other costs and expenses. Pursuant to the FERC approved settlement,
KeySpan rates reflect a cost of equity of 9.5% with no revenue increase. FERC
also approved updated operating and maintenance expense levels and KeySpan's
recovery of certain other costs as agreed to by the parties.
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.
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.
22
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 and LIPA, at cost fairly and equitably allocated among them.
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
a customer service performance program. At the end of KEDNY's and KEDLI's
rate years (September 30, 2004 and November 30, 2004, respectively), their
ratios of debt to total utility capitalization were well in compliance with
the ratios set forth above and we have incurred no penalties under the
outstanding customer service performance program.
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.
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
23
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.
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 FERC. The pricing for both energy sales and services to the
NYISO energy market is still evolving and some of the FERC's price
mitigation measures are subject to rehearing and possible judicial review.
Our Risk Mitigation Techniques Such as Hedging and Purchase of Insurance May Not
Adequately Provide Protection
To 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.
24
SEC Rules for Exploration and Production Companies May Require Us to Recognize a
Non-Cash Impairment Charge at the End of Our Reporting Periods
Our investments in natural gas and oil consist of our ownership of KeySpan
Exploration and Production and Seneca-Upshur. We use the full cost method
for KeySpan Exploration and Production and Seneca-Upshur. 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 fluctuate substantially on a
seasonal basis. In addition, our New England-based gas distribution
subsidiaries do not have weather normalization tariffs, as we do in New
York, 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.
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, our interest in
KeySpan Generation LLC. LIPA is in the process of performing a long-term
strategic review initiative regarding its future direction. It has engaged
a team of advisors and consultants and is conducting public hearings to
develop recommendations to be submitted to the LIPA Trustees. Some of the
strategic options that LIPA is considering is whether it should continue
its operations as they presently exist, fully municipalize or fully
privatize, sell some, but not all of its assets and become a regulator of
rates and services, or merge with one or more utilities. Until LIPA makes a
determination on its future direction, we are unable to determine what the
impact will be on our financial condition, results of operations or cash
flows.
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 Our Financial Condition
25
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 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, we are unable to determine what effect, if any, the ultimate
resolution of these disputes will have on our financial condition, results
of operations, or cash flow.
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 segment
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
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.
26
Our Businesses are Subject to Competition and General Economic Conditions
Impacting Demand for Services
We recently expanded the Ravenswood Facility, our merchant generation
plant, in our Electric Services segment with the Ravenswood Expansion, a
250 MW combined cycle generating unit. However, the Ravenswood Facility and
Ravenswood Expansion continue to be subject to competition that could
adversely impact the market price for the electricity they produce. If new
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 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, economic factors and price elasticity.
In addition, our Gas Distribution segment's future growth 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 customer conversions from an
alternative fuel to gas, including general economic factors impacting
customers' willingness to invest in new gas equipment.
27
Employee Matters
As of December 31, 2004, KeySpan and its wholly-owned subsidiaries had
approximately 10,000 employees. Of that total, approximately 5,800 employees 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.
Prior to their expiration in February 2004, 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
were 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 68, 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, Keyera
Energy Management Ltd. and J & W Seligman & Co.
Robert J. Fani
Mr. Fani, age 51, was elected to serve on the Board of Directors of KeySpan in
January 2005 and was elected its President and Chief Operating Officer in
October 2003. Mr. Fani joined KEDNY in 1976, and held a variety of management
positions in distribution, engineering, planning, marketing and business
development. After being elected Vice President in 1992, he was promoted to
Senior Vice President of Marketing and Sales for KEDNY in 1997. 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.
28
Wallace P. Parker Jr.
Mr. Parker, age 55, 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 January 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 for KEDNY and in August 1998 was promoted to
Senior Vice President of Human Resources of KeySpan.
Steven L. Zelkowitz
Mr. Zelkowitz, age 55, was elected President of KeySpan's Energy Assets and
Supply Group in October 2003. Prior to that, he served as Executive Vice
President and 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 and 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 J. Bishar, Jr.
Mr. Bishar, age 55, was elected Executive Vice President, General Counsel, Chief
Governance Officer and Secretary effective March 1, 2005. He became Senior Vice
President, General Counsel and Secretary in May 2003, with responsibility for
the Company's Legal Department and the Corporate Secretary's Office. Prior to
that, he joined KeySpan as Senior Vice President and General Counsel in November
2002. Before joining KeySpan, Mr. Bishar practiced law with Cullen and Dykman
LLP since 1987. 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.
29
John A. Caroselli
Mr. Caroselli, age 50, 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 Strategy and. 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 strategic planning brand
management, marketing, communications, human resources, facilities management,
e-business, change management and strategic execution.
Gerald Luterman
Mr. Luterman, age 61, 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 IKON Office Solutions Inc., and
Technology Solutions Company.
David J. Manning
Mr. Manning, age 54, was elected Executive Vice President Corporate Affairs and
Chief Environmental Officer effective March 1, 2005. He became 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 as Queens Council.
Anthony Nozzolillo
Mr. Nozzolillo, age 56, 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 51, 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 46, was elected President, KeySpan Energy Delivery, in
June, 2004 and Executive Vice President in April 2002. He previously served as
President of KeySpan Energy New England since April 2002, and 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 a
director of Colonial Gas Company and currently serves on the Board of Directors
for Enterprise Bank and Trust Company.
Joseph F. Bodanza
Mr. Bodanza, age 57, was elected Senior Vice President Regulatory Affairs and
Asset Optimization effective March 1, 2005. He became Senior Vice President,
Regulatory Affairs and Chief Accounting Officer in April 2003. Prior to that, 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.
Coleen A. Ceriello
Ms. Ceriello, age 46, was named Senior Vice President of Shared Services of
KeySpan Corporate Services, LLC, effective March 1, 2005. She had been KeySpan's
Vice President - Property, Security and Employee Related Services since January
2005. Prior to that time, she served as Vice President of Property and Security
since June 2004 and Vice President of Strategic Planning since August 1999. She
joined KEDNY in 1980 and over the years held a succession of positions in
Corporate Planning, Regulatory Relations, Information Technology and Strategic
Planning and Performance.
31
John F. Haran
Mr. Haran, age 54, 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 April 2002. Mr. Haran joined KEDNY 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.
Michael J. Taunton
Mr. Taunton, age 49, was elected Senior Vice President, Treasurer and Chief Risk
Officer effective March 1, 2005. He became Senior Vice President and Treasurer
in March 2004, and 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.
Elaine Weinstein
Ms. Weinstein, age 58, was named Senior Vice President for Human Resources and
Chief Diversity Officer in March 2004. She previously served as Senior Vice
President of KeySpan's Human Resources division since November 2000, and as Vice
President of Staffing and Organizational Development from September 1998, to her
election as Senior Vice President. Prior to that time, Ms. Weinstein was General
Manager of Employee Development since joining KEDNY in June of 1995. Prior to
1995, Ms. Weinstein was Vice President of Training and Organizational
Development at Merrill Lynch.
Lawrence S. Dryer
Mr. Dryer, 45, 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 A. Balog
Ms. Balog, age 43, was elected Vice President and Chief Accounting Officer
effective March 1, 2005. She became 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.
32
Joseph E. Hajjar
Mr. Hajjar, age 52, was named Vice President and Controller effective March 1,
2005. He had been Senior Vice President and Chief Financial Officer of KeySpan
Services, Inc. since June 2003 and Senior Vice President and Chief Financial
Officer of KeySpan Business Solutions, LLC, since November 2001. Before joining
KeySpan from 1998 to 2001, Mr. Hajjar was Executive Vice President and Chief
Operating Officer of Opportunity America. He also was previously an officer of
the Bovis group and served for over 12 years with Price Waterhouse.
Michael A. Walker
Mr. Walker, age 48, was named Vice President and Deputy General Counsel of
KeySpan Corporation, effective March 1, 2005. He had been Senior Vice President
of KeySpan Services, Inc. since June 2004 and Senior Vice President and COO of
KeySpan Business Solutions, LLC, since June 2003. Prior to that time he was
Senior Vice President and General Counsel of KeySpan Services, Inc. from January
2001 to December 2003. Before joining KeySpan, Mr. Walker was a shareholder in
the Corporate Finance Section in the law firm of Buchanan Ingersoll. Prior to
joining Buchanan Ingersoll he worked for several law firms in the north east
representing both private and public sector clients on a wide variety of energy,
utility, regulatory, corporate and structured finance matters.
Item 2. Properties
Information with respect to KeySpan's material properties used in the conduct of
its business is set forth in, or incorporated by reference in, Item 1 hereof.
Except where otherwise specified, all such properties are owned or, in the case
of certain rights-of-way, used in the conduct of its gas distribution business,
held pursuant to municipal consents, easements or long-term leases, and in the
case of gas and oil properties, held under long-term mineral leases. In addition
to the information set forth therein with respect to properties utilized by each
business segment, KeySpan leases the executive headquarters located in Brooklyn,
New York. In addition, we lease other office and building space, office
equipment, vehicles and power operated equipment. Our properties are adequate
and suitable to meet our current and expected business requirements. Moreover,
their productive capacity and utilization meet our needs for the foreseeable
future. KeySpan continually examines its real property and other property for
its contribution and relevance to our businesses and when such properties are no
longer productive or suitable, they are disposed of as promptly as possible. In
the case of leased office space, we anticipate no significant difficulty in
leasing alternative space at reasonable rates in the event of the expiration,
cancellation or termination of a lease.
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, 2004.
33
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities
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 February 15, 2005,
there were approximately 72,549 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:
2004 High Low Dividends Per Share
-------------------------------------------------------------------------------------------------------
First Quarter $38.60 $35.72 $0.445
Second Quarter $38.99 $33.87 $0.445
Third Quarter $39.50 $35.19 $0.445
Fourth Quarter $41.53 $37.57 $0.445
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
34
EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth securities authorized for issuance under equity
compensation plans for the year ended December 31, 2004:
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 10,540,946 $33.15 5,245,064
Restricted Stock 80,409 N/A
Performance Shares 346,470 N/A
Equity compensation plans
not approved by 0 0 0
security holders
Total 10,967,825(1) $33.15 5,245,064
(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.
35
- ------------------------------------------------------------------------------------------------------------------------------------
Item 6 Selected Financial Data
Year Ended December 31,
(In Thousands of Dollars, Except Per 2004 2003 2002 2001 2000
Share Amounts) -------------------------------------------------------------------------------------
Income Summary
Revenues
Gas Distribution $ 4,407,292 $ 4,161,272 $ 3,163,761 $ 3,613,551 $ 2,555,785
Electric Services 1,738,660 1,605,973 1,645,688 1,850,381 1,702,908
Energy Services 182,406 158,908 208,624 243,553 245,775
Energy Investments 322,108 609,371 447,101 498,318 310,096
--------------------------------------------------------------------------------------
Total revenues 6,650,466 6,535,524 5,465,174 6,205,803 4,814,564
--------------------------------------------------------------------------------------
Operating expenses
Purchased gas for resale 2,664,492 2,495,102 1,653,273 2,171,113 1,408,680
Fuel and purchased power 540,302 414,633 395,860 538,532 460,841
Operations and maintenance 1,567,022 1,622,592 1,631,297 1,704,370 1,418,164
Depreciation, depletion and amortization 551,760 571,669 513,708 564,039 326,748
Early retirement and severance charges - - - - 65,175
Operating taxes 404,212 418,236 380,527 448,914 421,936
Impairment Charges 40,965 - - - -
--------------------------------------------------------------------------------------
Total operating expenses 5,768,752 5,522,232 4,574,665 5,426,968 4,101,544
--------------------------------------------------------------------------------------
Gain on sale of property 7,021 15,123 4,730 - -
Income from equity investments 46,536 19,214 14,096 13,129 20,010
--------------------------------------------------------------------------------------
Operating income 935,270 1,047,629 909,335 791,964 733,030
Other income (deductions) 4,983 (340,279) (301,368) (359,525) (233,322)
Income taxes 325,540 281,281 229,665 200,472 208,549
--------------------------------------------------------------------------------------
Earnings from continuing operations 614,713 426,069 378,302 231,967 291,159
--------------------------------------------------------------------------------------
Discontinued Operations
Income (loss) from operations, net of tax (78,960) (1,888) 15,692 22,643 9,648
Loss on disposal, net of tax (72,088) - (16,306) (30,356) -
--------------------------------------------------------------------------------------
Loss from discontinued operations (151,048) (1,888) (614) (7,713) 9,648
Cumulative change in accounting principles - (37,451) - - -
--------------------------------------------------------------------------------------
Net income 463,665 386,730 377,688 224,254 300,807
Preferred stock dividend requirements 5,612 5,844 5,753 5,904 18,113
--------------------------------------------------------------------------------------
Earnings for common stock $ 458,053 $ 380,886 $ 371,935 $ 218,350 $ 282,694
======================================================================================
Financial Summary
Earnings per share ($) 2.86 2.41 2.63 1.58 2.10
Cash dividends declared per share ($) 1.78 1.78 1.78 1.78 1.78
Book value per share, year-end ($) 24.22 22.99 20.67 20.73 20.65
Market value per share, year-end ($) 39.45 36.80 35.24 34.65 42.38
Shareholders, year-end 72,549 75,067 78,281 82,300 86,900
Capital expenditures ($) 750,329 1,009,393 1,057,507 1,059,759 925,257
Total assets ($) 13,364,130 14,640,182 12,980,050 11,789,606 11,307,465
Common shareholders' equity ($) 3,894,710 3,670,656 2,944,592 2,890,602 2,815,816
Preferred stock redemption required ($) 75,000 75,000 75,000 75,000 75,000
Preferred stock no redemption required ($) - 8,568 8,849 9,077 9,205
Long-term debt ($) 4,418,729 5,610,948 5,224,081 4,697,649 4,116,441
Total capitalization ($) 8,333,139 9,365,172 8,252,522 7,672,328 7,016,462
- ------------------------------------------------------------------------------------------------------------------------------------
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 2.6 million customers in New York City, Long
Island, Massachusetts and New Hampshire, making KeySpan the fifth largest gas
distribution company in the United States and the largest in the Northeast. We
also own and operate electric generating plants in Nassau and Suffolk Counties
on Long Island and in Queens County in New York City and are the largest
electric generation operator in New York State. Under contractual arrangements,
we provide power, electric transmission and distribution services, billing and
other customer services for approximately 1.1 million electric customers of the
Long Island Power Authority ("LIPA"). KeySpan's other subsidiaries are involved
in gas exploration and production; underground gas storage; liquefied natural
gas storage; retail electric marketing; large energy-system ownership,
installation and management; appliance service; and engineering and consulting
services. We also invest and participate in the development of natural gas
pipelines, electric generation and other energy-related projects. (See Note 2 to
the Consolidated Financial Statements "Business Segments" for additional
information on each operating segment.)
Executive Summary
Below is a table comparing the more significant items impacting earnings from
continuing operations and earnings available for common stock for the periods
indicated.
- ------------------------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars, Except per Share Amounts)
Year Ended December 31,
2004 2003 2002
--------------------------- --------------------------- ---------------------------
Earnings E.P.S. Earnings E.P.S. Earnings E.P.S.
Earnings from continuing operations, less
preferred stock dividends $ 609,101 $ 3.80 $ 420,225 $ 2.65 $ 372,549 $ 2.64
Discontinued operations (151,048) (0.94) (1,888) (0.01) (614) (0.01)
Cummulative change in accounting principle - - (37,451) (0.23) - -
--------------------------- --------------------------- ---------------------------
Earnings for Common Stock $ 458,053 $ 2.86 $ 380,886 $ 2.41 $ 371,935 $ 2.63
=========================== =========================== ===========================
Average shares outstanding 160,294 158,256 141,263
Components of Continuing Operations:
- -------------------------------------
Core operations $ 385,425 $ 2.41 353,191 $ 2.23 324,305 $ 2.30
Asset sales 257,506 1.60 995 - - -
Ceiling test write-down (31,074) (0.19) - - - -
Impairment charges (31,318) (0.20) - - - -
Debt redemption costs (29,264) (0.18) (13,565) (0.08) - -
Exploration and production operations 57,826 0.36 79,604 0.50 48,242 0.34
Earnings from continuing operations, less
preferred stock dividends --------------------------- --------------------------- ---------------------------
$ 609,101 $ 3.80 $ 420,225 $ 2.65 $ 372,547 $ 2.64
- ------------------------------------------------------------------------------------------------------------------------------------
37
Earnings from Continuing Operations 2004 vs 2003
KeySpan's earnings from continuing operations, less preferred stock dividends,
for the year ended December 31, 2004 were $609.1 million or $3.80 per share, an
increase of $188.9 million, or $1.15 per share compared to $420.2 million, or
$2.65 per share realized in 2003. Earnings from continuing operations, less
preferred stock dividends, for the year ended December 31, 2002 were $372.5
million, or $2.64 per share. KeySpan's financial results for the year ended
December 31, 2004 and 2003 reflect the following items that had a significant
impact on comparative results: (i) non-core asset sales recorded in both 2004
and 2003; (ii) impairment charges recorded in 2004; and (iii) debt redemption
charges recorded in both 2004 and 2003.
During 2004, KeySpan sold its interest in The Houston Exploration Company
("Houston Exploration") - an independent natural gas and oil exploration and
production company located in Houston, Texas. We received cash proceeds of
approximately $758 million in two stock transactions and recorded after-tax
gains of $222.7 million, or $1.39 per share. Also in 2004, KeySpan sold its
remaining ownership interest in KeySpan Canada - previously a 61% owned
subsidiary with natural gas processing plants and gathering facilities in
Western Canada. We received cash proceeds of approximately $255 million in two
transactions and recorded after-tax gains of $34.8 million, or $0.21 per share.
Combined, these asset sales provided KeySpan with approximately $1 billion of
cash proceeds and after-tax earnings of $257.5 million, or $1.60 per share.
As mentioned, during 2003 KeySpan completed two non-core asset sales. In 2003,
KeySpan sold 39.09% of its interest in KeySpan Canada. Additionally, we sold our
20% interest in Taylor NGL LP that owns and operates two extraction plants also
located in Canada. We recorded an after-tax loss of $34.1 million, or $0.22 per
share, associated with these sales. Additionally, 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, or $0.12 per share, on
this transaction. Income taxes were not provided on this transaction since the
transaction was structured as a return of capital. Further, in the fourth
quarter of 2003, we completed the sale of our 24.5% interest in Phoenix Natural
Gas, a natural gas distribution company located in Northern Ireland, and
recorded an after-tax gain of $16.0 million, or $0.10 per share. In total,
KeySpan recorded a pre-tax gain of $13.4 million from the monetization of these
non-core assets. The combined after-tax gain from these asset sales was minimal
due to the tax treatment associated with each transaction.
See Note 2 to the Consolidated Financial Statements "Business Segments" and the
discussions under the caption "Review of Operating Segments" for a more detailed
discussion of each of the above noted non-core stock transactions.
KeySpan recorded three significant impairment charges during 2004 (a goodwill
impairment charge recorded in the Energy Services segment, as well as a ceiling
test write-down and carrying value impairment charge recorded in the Energy
Investment segment) that resulted in after-tax charges to continuing operations
of $62.4 million, or 0.39 per share. The Energy Services segment recorded an
after-tax non-cash goodwill impairment charge of $12.6 million, or $0.08 per
share in continuing operations as a result of an evaluation of the carrying
value of goodwill recorded in this segment. Based upon the operating results
experienced by the Energy Services segment and management's opinion that it was
38
likely that a significant portion of the Energy Services segment would be sold
within one year, KeySpan conducted an evaluation of the carrying value of its
investments in this segment, including recorded goodwill. That evaluation
resulted in a total impairment charge of $152.4 million after tax, or $0.95 per
share - $12.6 million of this charge is attributable to continuing operations,
while the remaining $139.9 million, or $0.87 per share, has been reflected in
discontinued operations. (See Note 11 to the Consolidated Financial Statements
"Energy Services - Discontinued Operations" for additional details on this
charge.)
KeySpan's wholly-owned gas exploration and production subsidiaries recorded an
after-tax non-cash impairment charge of $31.1 million, or $0.19 per share, to
recognize the reduced valuation of proved reserves. (See Note 10 to the
Consolidated Financial Statements "Gas Exploration and Production Property -
Depletion" for additional details on this transaction.)
In addition to the asset sales noted previously, KeySpan has entered into an
agreement to sell its 50% interest in Premier Transmission Limited ("PTL"), a
gas pipeline from southwest Scotland to Northern Ireland, before the end of the
second quarter of 2005. In the fourth quarter of 2004 KeySpan recorded a pre-tax
non-cash impairment charge of $26.5 million - $18.8 million after-tax or $0.12
per share, reflecting the difference between the anticipated cash proceeds from
the sale of PTL compared to its carrying value. This investment is accounted for
under the equity method of accounting in the Energy Investments segment. (See
Note 2 to the Consolidated Financial Statements "Business Segments" and the
discussions under the caption "Review of Operating Segments" for a more detailed
discussion of the anticipated sale.
The remaining significant item noted above is debt redemption costs incurred in
2004 and 2003. In 2004, KeySpan redeemed approximately $758 million of
outstanding long-term debt. KeySpan incurred $54.5 million in call premiums
associated with this redemption, of which $45.9 was expensed and recorded in
other income and deductions on the Consolidated Statement of Income. The
remaining amount of the call premiums have been deferred for future recovery.
Further, KeySpan wrote-off $8.2 million of previously deferred financing costs
which have been reflected in interest expense on the Consolidated Statement of
Income. The total after-tax expense of the debt redemption was $29.3 million or
$0.18 per share. (See Note 6 to the Consolidated Financial Statements "Long-Term
Debt and Commercial Paper" as well as the discussion under the caption
"Financing" for additional details on this transaction.) In 2003, KeySpan
incurred $18.2 million in debt redemption costs associated with the redemption
of approximately $447 million of outstanding promissory notes that were issued
to the Long Island Power Authority ("LIPA") in connection with the KeySpan/Long
Island Lighting Company ("LILCO") business combination completed in May 1998.
Further, Houston Exploration, then a consolidated subsidiary, incurred debt
redemption costs of $5.9 million, to retire $100 million 8.625% Notes. The total
after-tax expense of the debt redemptions in 2003 was $13.6 million or $0.08 per
share.
The net impact of the above mentioned items resulted in an increase to earnings
from continuing operations of $165.9 million, or $1.03 per share for the year
ended December 31, 2004, compared to a loss of $12.6 million or $0.08 per share
in 2003.
The remaining items impacting comparative earnings from continuing operations
reflect higher earnings from the Gas Distribution segment, primarily due to a
Boston Gas Company rate increase resulting from a rate proceeding concluded in
November 2003, partially offset by the adverse effect on earnings from KeySpan's
lower ownership level in Houston Exploration. As mentioned above and discussed
39
in more detail in Note 2 to the Consolidated Financial Statements "Business
Segments," during the first half of 2004 KeySpan maintained an approximate 55%
ownership level in Houston Exploration. In June 2004, KeySpan's ownership
decreased to approximately 23.5% and then in November 2004 KeySpan decided to
sell its remaining investment.
Earnings Available for Common Stock 2004 vs 2003
Earnings available for common stock for the year ended December 31, 2004 also
includes losses from discontinued operations. As noted, at December 31, 2004,
KeySpan intended to sell a significant portion of its ownership interest in
certain companies within the Energy Services segment - specifically those
companies engaged in mechanical contracting activities. As a result, KeySpan
recorded a loss in discontinued operations of $151.1 million, or $0.94 per
share. This loss reflects the $139.9 million after-tax impairment charges to
reflect a reduction to the carrying value of assets associated with mechanical
contracting activities and operating losses of $11.2 million. (See Note 11 to
the Consolidated Financial Statements "Energy Services-Discontinued Operations"
for additional details on these items.)
Earnings available for common stock for the year ended December 31, 2003 have
been reclassified to reflect an operating loss from discontinued operations of
$1.9 million, or $0.01 per share associated with the operations of the
mechanical contracting activities. Earnings available for common stock also
include a charge for a cumulative change in accounting principle. 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." This Interpretation required us to,
among other things, consolidate the Ravenswood Master Lease (the lease under
which KeySpan leases and operates a portion of the Ravenswood electric
generating facility ("Ravenswood Facility") and classify the lease obligation as
long-term debt on the Consolidated Balance Sheet starting 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.)
Earnings from Continuing Operations 2003 vs 2002
Income from continuing operations, less preferred stock dividends, increased
$47.7 million in 2003 compared to 2002 primarily reflecting higher earnings from
the Energy Investments and Gas Distribution 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 of 2002, 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. Earnings per share from continuing operations
increased only $0.01 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.
40
Earnings Available for Common Stock 2003 vs 2002
As mentioned, earnings available for common stock for the year ended December
31, 2003, reflects an operating loss from discontinued operations of $1.9
million, or $0.01 per share associated with the operations of the mechanical
contracting activities, as well as a non-cash, after-tax charge of $37.6
million, or $0.23 per share related to the implementation of FIN 46.
Earnings available for common stock for the year ended December 31, 2002
includes a net loss of $0.6 million, or $0.01 per share, from discontinued
operations. The mechanical contracting operations reflected earnings of $19.1
million, or $0.13 per share in discontinued operations. This was offset by an
after-tax loss of $19.7 million associated with the sale of Midland Enterprises
LLC ("Midland"). In January 2002, KeySpan announced that it had entered into an
agreement to sell 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. (See Note 9 to the Consolidated Financial Statements "Discontinued
Midland Operations" for additional information.)
41
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) 2004 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------
Gas Distribution $ 579,563 $ 574,254 $ 531,134
Electric Services 289,781 269,874 289,694
Energy Services
Operations (33,878) (32,963) (45,581)
Goodwill impairment charge (14,424) - -
Energy Investments
Operations 179,424 238,554 142,594
Ceiling test write-down and impairment charge (74,731) - -
Eliminations and other 9,535 (2,090) (8,506)
-------------------------------------------------------
Operating Income 935,270 1,047,629 909,335
Interest charges (331,251) (307,694) (301,504)
Gain on Houston Exploration transactions 329,689 19,020 -
Gain (loss) on sale of KeySpan Canada 58,629 (30,345) -
Gain on sale of Phoenix Natural Gas - 24,681 -
Cost of debt redemption (45,879) (24,094) -
Other income and (deductions) (6,205) (21,847) 136
Income taxes (325,540) (281,281) (229,665)
-------------------------------------------------------
Income from Continuing Operations 614,713 426,069 378,302
Cumulative change in accounting principles - (37,451) -
Loss from discontinued operations (151,048) (1,888) (614)
-------------------------------------------------------
Net Income 463,665 386,730 377,688
Preferred stock dividend requirements 5,612 5,844 5,753
-------------------------------------------------------
Earnings for Common Stock $ 458,053 $ 380,886 $ 371,935
=======================================================
Basic Earnings per Share:
Continuing operations, less preferred stock dividends $ 3.80 $ 2.65 $ 2.64
Change in accounting principles - (0.23) -
Discontinued operations (0.94) (0.01) (0.01)
- -----------------------------------------------------------------------------------------------------------------------------
$ 2.86 $ 2.41 $ 2.63
- -----------------------------------------------------------------------------------------------------------------------------
Operating income, as indicated in the above table, decreased $112.4 million for
the twelve months ended December 31, 2004, compared to the same period of 2003.
Comparative operating income was adversely impacted by lower operating income
from the Energy Investment segment as a result of KeySpan's reduced ownership
interest in Houston Exploration and KeySpan Canada during the latter half of
2004. In addition, operating income in the Energy Investments segment was
adversely impacted by the $48.2 million non-cash impairment charge to recognize
the reduced valuation of proved reserves, as well as the $26.5 million non-cash
impairment charge in our investment in PTL. Further, the decrease in operating
income reflects the $14.4 million non-cash goodwill impairment charge recorded
in the Energy Services segment. The higher comparative operating income in the
Electric Services segment in 2004 primarily reflects higher net electric margins
associated with the Ravenswood Expansion, a recently constructed 250 MW combined
cycle generating facility located at the Ravenswood Facility site. The Gas
Distribution segment benefited from customer additions and oil-to-gas
conversions throughout our service territories, as well as from the full effect
of the rate increase resulting from the Boston Gas Company rate proceeding
concluded in November 2003. As mentioned earlier, in 2003 we recorded $15.1
million in gains from property sales, primarily 550 acres of real property
located on Long Island, that were recorded in the Gas Distribution segment. (See
the discussion under the caption "Review of Operating Segments" for further
details on each segment.)
42
The increase in interest expense of $23.6 million, or 8%, in 2004, compared to
the prior year, reflects a number of items. As noted earlier, interest expense
for 2004 includes the write-off of $8.2 million of previously deferred issuance
costs as a result of the redemption of $758 million of outstanding long-term
debt. In addition, interest expense in 2004 was impacted by the implementation
of FIN 46, mentioned earlier. Beginning January 1, 2004, lease payments
associated with the Ravenswood Master Lease have been reflected as interest
expense on the Consolidated Statement of Income resulting in an increase to
interest expense of approximately $30 million in 2004. (See Note 7 "Contractual
Obligations, Financial Guarantees and Contingencies for further information on
the Master Lease.")
Further, comparative interest expense also reflects the benefits realized in
2003 associated with interest rate swaps. In 2003, we terminated an interest
rate swap agreement with a notional amount of $270 million. This swap was used
to hedge a portion of outstanding promissory notes that were issued to LIPA in
connection with the KeySpan/LILCO business combination. As noted previously, in
March 2003, we called approximately $447 million of the outstanding promissory
notes, and settled the outstanding derivative instrument. The cash proceeds from
the termination of the interest rate hedge were $18.4 million, of which $8.1
million represented accrued swap interest. The difference between the
termination settlement amount and the amount of accrued swap interest, $10.3
million, was recorded to earnings (as an adjustment to interest expense) in 2003
and effectively offset a portion of the redemption charges.
Offsetting, to some extent, these adverse impacts to comparative interest
expense are the benefits associated with a lower level of outstanding long-term
debt.
In addition to the asset sales of $388.3 million and debt redemption costs of
$45.9 million previously noted, other income and (deductions) for 2004 reflects
a $12.6 million gain recorded on the settlement of a derivative financial
instrument entered into in connection with the sale/leaseback transaction
associated with the Ravenswood Expansion, as well as a $5.5 million foreign
currency gain on cash investments held off-shore. Other income and (deductions)
also includes the effects of minority interest of $36.8 million related to our
previous controlling interests in Houston Exploration and KeySpan Canada, as
well as carrying charges on certain regulatory assets. (See Note 7 and Note 8 to
the Consolidated Financial Statements, "Contractual Obligations, Financial
Guarantees and Contingencies" and "Hedging and Derivative Financial
Instruments," for additional information regarding the sale/leaseback
transaction and derivative financial instrument.)
In addition to the asset sales of $13.4 million and debt redemption costs of
$24.1 million previously noted, other income and (deductions) in 2003 also
reflects severance tax refunds totaling $21.6 million recorded by Houston
Exploration for severance taxes paid in 2002 and earlier periods, 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 of $63.9 million, as well as carrying
charges on certain regulatory assets.
43
Income tax expense generally reflects the level of pre-tax income. In addition,
tax expense for 2004 reflects: (i) a $6.0 million benefit resulting from a
revised appraisal associated with property that was disposed of in 2003; (ii) a
tax benefit of $14 million related to the repatriation of earnings from
KeySpan's Canadian investments; and (iii) the beneficial tax treatment afforded
the stock transaction with Houston Exploration.
Income tax expense for 2003 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 Commonwealth 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.
As noted earlier, earnings available for common stock for the year ended
December 31, 2004 also includes losses of $151.1 million, or $0.94 per share,
from discontinued operations. Earnings available for common stock for the year
ended December 31, 2003 includes a charge for a cumulative change in accounting
principles of $37.6 million, or $0.23 per share, associated with the
implementation of FIN 46, as well as operating losses of $1.9 million, or $0.01
per share associated with discontinued operations.
As a result of the items discussed above, earnings available for common stock
were $458.1 million, or $2.86 per share for the year ended December 31, 2004
compared to $380.9 million, or $2.41 per share realized in 2003.
Operating income in 2003 increased $138.3 million compared to 2002. This
increase in operating income reflects higher earnings from the Energy
Investments and Gas Distribution segments, somewhat offset by a decrease in
earnings from the Electric Services Segment. 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
of 2002, as well as from load growth. Further, as mentioned earlier, during 2003
we recorded $15.1 million in gains in the Gas Distribution segment from property
sales. 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 in 2003. (See the discussion
under the caption "Review of Operating Segments" for further details on each
segment.)
Interest charges increased 2% in 2003, compared to 2002, primarily as a result
of the absence of the benefits associated with certain interest-rate derivative
swap instruments that were in effect in 2002, but terminated in 2003. (See Note
8 to the Consolidated Financial Statements "Hedging, Derivative Financial
Instruments and Fair Values.")
44
As discussed in greater detail earlier, other income and (deductions) in 2003
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 Houston Exploration and
recorded a net gain of $13.4 million associated with these transactions.
Further, we incurred debt redemption costs of $24.1 million. Other income and
(deductions) in 2003 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) for both 2003 and 2002 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. As mentioned above,
the partial monetization of our Canadian investments in 2003 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 Commonwealth 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 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.
As discussed earlier, earnings available for common stock for the year ended
December 31, 2002 also includes a net loss from discontinued operations of $0.6
million.
As a result of the items just mentioned earnings available for common stock,
which includes both the cumulative change in accounting principle, as well as
discontinued operations, were $380.9 million, or $2.41 per share for the year
ended December 31, 2003 compared to $371.9 million, or $2.63 per share earned in
2002.
45
KeySpan's consolidated earnings for 2004 were 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) were forecasted to
be in the range of $2.20 to $2.30 per share. Earnings from gas exploration and
production operations, excluding the impact of the gain on the sale of Houston
Exploration and the impact of the non-cash impairment charge, were forecasted to
be in the range of $0.35 to $0.45 per share. Actual 2004 earnings from
continuing core operations, as defined, were $2.41 per share, while earnings
from exploration and production operations were $0.36 per share.
Financial Outlook for 2005
KeySpan's consolidated earnings for 2005 are forecasted to be in the range of
$2.30 to $2.40 per share, excluding special items. Since we sold the majority of
our non-core assets in 2004, the earnings forecast represents earnings from all
continuing operations less preferred stock dividends. Further, the earnings
forecast includes the anticipated dilutive impact from the conversion of the
MEDS Equity Units. (See Note 6 to the Consolidated Financial Statements
"Long-Term Debt" for an explanation of the MEDS Equity Units.)
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
- ----------------------------
KeySpan's segment results are reported on an Operating Income basis. 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.
46
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) 2004 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------
Revenues $ 4,407,292 $ 4,161,272 $ 3,163,761
Cost of gas 2,664,662 2,444,485 1,569,325
Revenue taxes 73,294 90,456 83,066
- ---------------------------------------------------------------------------------------------------------------------------
Net Gas Revenues 1,669,336 1,626,331 1,511,370
- ---------------------------------------------------------------------------------------------------------------------------
Operating Expenses
Operations and maintenance 672,548 659,932 608,266
Depreciation and amortization 276,487 259,934 237,186
Operating taxes 140,738 147,334 135,687
- ---------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 1,089,773 1,067,200 981,139
- ---------------------------------------------------------------------------------------------------------------------------
Gain on the sale of property - 15,123 903
Operating Income $ 579,563 $ 574,254 $ 531,134
- ---------------------------------------------------------------------------------------------------------------------------
Firm gas sales and transportation (MDTH) 324,549 328,073 284,281
Transportation - Electric Generation (MDTH) 27,656 34,778 64,173
Other Sales (MDTH) 155,992 158,722 209,002
Warmer (Colder) than Normal - New York & Long Island (1.0%) (8.0%) 7.0%
Warmer (Colder) than Normal - New England (6.8%) (10.0%) 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.
Executive Summary
Operating income increased $5.3 million for the twelve months ended December 31,
2004 compared to the same period last year, primarily due to an increase in net
revenues of $43.0 million resulting, for the most part, from the Boston Gas
Company's rate proceeding that was concluded in November 2003. Partially
offsetting the increase in net revenues were higher operating expenses of $22.6
million, primarily due to an increase of $13.0 million in the provision for
uncollectible accounts receivable as a result of higher gas costs, as well as
higher depreciation and amortization expenses. It should be noted that during
2003 we recorded $15.1 million in gains from property sales on Long Island.
Operating income increased $43.1 million for the twelve months ended December
31, 2003 compared to the same period of 2002, primarily due to an increase in
net revenues of $115.0 million resulting from significantly colder than normal
weather experienced throughout the Northeastern United States in 2003,
particularly during the primary winter heating months of January through March.
Partially offsetting the increase in net revenues were higher operating expenses
of $86.1 million, attributable, in part, to higher pension and other
postretirement benefit costs of $30.9 million. 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. Also depreciation and amortization expense increased as a
result of the expansion of the gas distribution system. As noted earlier, during
2003 we recorded $15.1 million in gains from property sales on Long Island.
47
Net Revenues
Net gas revenues (revenues less the cost of gas and associated revenue taxes)
from our gas distribution operations increased by $43.0 million, or 3%, for the
year-ended December 31, 2004 compared to the prior year. Net gas revenues
benefited from the Boston Gas Company rate increase granted in the fourth
quarter of 2003, as well as from customer additions and oil-to-gas conversions.
As measured in heating degree days, weather in 2004 in our New York and New
England service territories was approximately 1% and 7% colder than normal,
respectively, compared to approximately 8% and 10% colder than normal in 2003,
respectively. Weather in 2004 was approximately 6% warmer than 2003 in our New
York service territory and approximately 3% warmer than last year in our New
England service territory.
Net revenues from firm gas customers (residential, commercial and industrial
customers) in our New York service territory during the twelve months ended
December 31, 2004 were essentially equivalent to the same period of 2003. We
realized a $3.5 million benefit to net gas revenues as a result of an additional
billing day in the 2004 leap year and $1.6 million associated with regulatory
incentives. Weather, which was warmer than 2003, resulted in an adverse impact
to comparative net gas revenues of $3.6 million. 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 in
normal weather. Since weather was colder than normal we refunded to firm
customers $5.2 million through the weather normalization adjustment. The
benefits of customer additions and oil-to-gas conversions were effectively
offset by conservation and more efficient heating equipment, customer attrition
and the adverse impact to customer usage due to higher natural gas prices.
Also included in net gas revenues is the recovery of property taxes that were
$0.5 million lower in 2004 compared to 2003. These revenues, however, do not
impact net income since the taxes they are designed to recover are expensed as
amortization charges on the Consolidated Statement of Income. Firm gas
distribution rates for KEDNY and KEDLI during 2004, other than for the recovery
of gas costs, have remained substantially unchanged from rates charged in 2003.
Net revenues from firm gas customers in our New England service territory
increased by $40.3 million in 2004 compared to 2003. Customer additions and
oil-to-gas conversions, net of attrition and conservation, added $8.0 million to
net gas revenues. Further, we realized a $2.2 million benefit in net gas
revenues as a result of an additional billing day for leap year. As mentioned,
the Massachusetts Department of Telecommunications and Energy ("MADTE") approved
a $27 million base rate increase for the Boston Gas Company, which became
effective November 1, 2003. For the twelve months ended December 31, 2004, the
rate increase resulted in a benefit to net gas revenues of $29.4 million. (See
the caption under "Regulation and Rate Matters" for further information
regarding the rate filing.) The gas distribution operations of our New England
based subsidiaries do not have a weather normalization adjustment. Weather,
which was warmer in 2004 than 2003, resulted in an adverse impact to comparative
net gas revenues of $6.1 million. To mitigate the effect of fluctuations in
normal weather patterns on KEDNE's results of operations and cash flows, weather
derivatives were in place for the 2003/2004 and the 2004/2005 winter heating
seasons. The impact of these derivative instruments resulted in a favorable
impact to comparative net revenues of $6.8 million for the twelve months ended
December 31, 2004 compared to the same period in 2003. (See Note 8 to the
Consolidated Financial Statements "Hedging and Derivative Financial Instruments"
for further information.)
48
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. These "dual-fuel" customers
can consume either natural gas or fuel oil for heating purposes. Net revenues in
these markets increased $2.2 million in 2004 compared to 2003. The majority of
interruptible profits earned by KEDNE and KEDLI are returned to firm customers
as an offset to gas costs.
Net gas revenues from our gas distribution operations increased by $115.0
million, or 8%, for the year ended December 31, 2003, compared to the same
period in 2002. 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 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 of 2002. 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 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 of 2002. 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
49
utilities of approximately $25.1 million in 2003 compared to 2002. As noted
above, 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
in 2002. 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.
In our large-volume heating and other interruptible (non-firm) markets, net
revenues increased by $26.8 million during the twelve months ended December 31,
2003, compared to the same period of 2002. As mentioned, the majority of
interruptible profits earned by KEDNE and KEDLI are returned to firm customers
as an offset to gas costs.
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
37% of the residential and multi-family markets, and approximately 55% of the
commercial market currently use natural gas for space heating. Further, we
estimate that in our New England service territories approximately 50% of the
residential and multi-family markets, as well as 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.
50
Firm Sales, Transportation and Other Quantities
Firm gas sales and transportation quantities for the year-ended December 31,
2004, were approximately 1% lower compared to such quantities for the same
period in 2003 reflecting the warmer weather. Weather normalized sales
quantities increased 2% in our New York service territories during 2004. In our
New England service territories, weather normalized sales quantities during 2004
were essentially the same as weather normalized sales quantities experienced in
2003. Net revenues are not affected by customers opting to purchase their gas
supply from other sources, since delivery rates charged to transportation
customers generally are the same as delivery rates charged to full sales service
customers. Transportation quantities related to electric generation reflect the
transportation of gas to our electric generating facilities located on Long
Island. Net revenues from these services are not material.
Other sales quantities include on-system interruptible quantities, off-system
sales quantities (sales made to customers outside of our service territories)
and related transportation. We have an agreement with Coral Resources, L.P.
("Coral"), a subsidiary of Shell Oil Company, under which Coral assists in the
origination, structuring, valuation and execution of energy-related transactions
on behalf of KEDNY and KEDLI. Upon expiration of this agreement, March 31, 2005,
these services will be performed with KeySpan employees. We also have a
portfolio management contract with Merrill Lynch Trading, under which Merrill
Lynch Trading provides all of the city gate supply requirements at market prices
and manages certain upstream capacity, underground storage and term supply
contracts for KEDNE. This agreement expires on March 31, 2006.
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.
Purchased Gas for Resale
The increase in gas costs for the twelve months ended December 31, 2004,
compared to the same period of 2003 of $220.2 million, or 9%, reflects an
increase of 13% in the price per dekatherm of gas purchased, and a 3% decrease
in the quantity of gas purchased. The current gas rate structure of each of our
gas distribution utilities includes a gas adjustment clause, pursuant to which
variations between actual gas costs incurred for sale to firm customers and gas
costs billed to firm customers are deferred and refunded to or collected from
customers in a subsequent period. 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.
51
Operating Expenses
Total operating expenses for the year ended December 31, 2004 increased $22.6
million, or 2%, compared to the same period last year, reflecting higher
operations and maintenance and depreciation expense. Operations and maintenance
expense increased $12.6 million, or 2%, in 2004 compared to 2003 primarily due
to an increase of $13.0 million in the provision for uncollectible accounts
receivable as a result of increasing gas costs, as well as higher employee
welfare costs, primarily postretirement expenses of approximately $4 million.
These increases to operations and maintenance expenses were partially offset by
a benefit of approximately $3 million, net of amounts subject to regulatory
deferral treatment, associated with the implementation of the Medicare
Prescription Drug Improvement and Modernization Act of 2003 ("Medicare Act") and
implementation of Financial Accounting Standards Board Staff Position ("FSP")
106-2. (See Note 1 to the Consolidated Financial Statements "Summary of
Significant Accounting Policies" Item O "Recent Accounting Pronouncements" for
further information regarding the Act and FSP 106-2.) In addition, in September
2004, Boston Gas Company reached an agreement with an insurance carrier for
recovery of previously incurred environmental expenditures. Under a previously
issued MADTE order, insurance and third-party recoveries, after deducting legal
fees, are shared between Boston Gas and its firm gas customers. As a result of
the insurance agreement, in September 2004 Boston Gas recorded a $5 million
benefit to operations and maintenance expense.
Higher depreciation and amortization expense reflects the continued expansion of
the gas distribution system, while the lower operating taxes resulted primarily
from a property tax refund in our New York service territory.
Operating expenses in 2003 increased $86.1 million, or 9%, compared to 2002.
This increase was primarily attributable to higher pension and other
postretirement benefit costs, which increased (net of amounts deferred and
subject to regulatory true-ups) by $30.9 million during 2003. The cost of these
benefits grew 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.
52
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
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 Shoreham, Long Island. Applications for all necessary
regulatory authorizations were filed in 2000 and 2001. Islander East has
received a final certificate from the Federal Energy Regulatory Commission
("FERC") and all necessary permits from the State of New York. The State of
Connecticut denied Islander East's applications for coastal zone management and
Section 401 of the Clean Water Act authorizations. Islander East appealed the
State of Connecticut's determination on the coastal zone management issue to the
United States Department of Commerce. On May 6, 2004, the Department of Commerce
overrode Connecticut's denial and granted the coastal zone management
authorization. Islander East's petition for a declaratory order challenging the
denial of the Section 401 authorization is pending with Connecticut's State
Superior Court. 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. Various options for the
financing of this pipeline construction are being evaluated. At December 31,
2004, our investment in the Islander East pipeline was $20 million.
In addition, in August 2004, KeySpan acquired a 21% interest in the Millennium
Pipeline development project which is anticipated to transport up to 500,000 DTH
of natural gas a day to the Algonquin pipeline. The project has been approved by
the FERC and, pending an amendment to the project's FERC certificate,
construction could begin as early as the third quarter of 2005, with service
beginning in late 2006. Once constructed, KeySpan anticipates contracting for
150,000 DTH per day of transportation capacity from the Millennium Pipeline
system. As of December 31, 2004, our investment in this project was $6 million.
Electric Services
The Electric Services segment primarily consists of subsidiaries that own and
operate oil and gas-fired electric generating plants in the Borough of Queens
(including the "Ravenswood Projects") and the counties of Nassau and Suffolk on
Long Island. In addition, through long-term contracts of varying lengths, we
manage the electric transmission and distribution ("T&D") system, the fuel and
electric purchases, and the off-system electric sales for LIPA. The Electric
Services segment also provides retail marketing of electricity to commercial
customers, the earnings from which were previously reported in the Energy
Services segment. Financial results for 2003 and 2002 have been reclassified to
reflect these activities in the Electric Services segment.
53
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) 2004 2003 2002
- ------------------------------------------------------------------------------------------------------------------------
Revenues $ 1,738,660 $ 1,606,074 $ 1,645,789
Purchased fuel 539,589 464,802 479,603
- ------------------------------------------------------------------------------------------------------------------------
Net Revenues 1,199,071 1,141,272 1,166,186
- ------------------------------------------------------------------------------------------------------------------------
Operating Expenses
Operations and maintenance 653,292 658,652 676,900
Depreciation 88,252 67,161 61,377
Operating taxes 169,746 145,585 139,694
- ------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 911,290 871,398 877,971
- ------------------------------------------------------------------------------------------------------------------------
Gain on the sale of property 2,000 - 1,479
Operating Income $ 289,781 $ 269,874 $ 289,694
- ------------------------------------------------------------------------------------------------------------------------
Electric sales (MWH)* 6,232,190 4,738,331 4,998,111
Capacity(MW)* 2,450 2,200 2,200
Summer cooling degree days 1,045 988 1,280
- ------------------------------------------------------------------------------------------------------------------------
*Reflects the operations of the Ravenswood Projects only.
Executive Summary
Operating income increased $19.9 million for the twelve months ended December
31, 2004 compared to the same period last year, due primarily to an increase in
net revenues from the Ravenswood Projects of $53.8 million, partially offset by
higher depreciation expense and operating taxes. In addition, also in 2004,
KeySpan recognized a gain of $2.0 million on the sale of a parcel of land in Far
Rockaway, Queens, to LIPA.
Operating income decreased $19.8 million for the twelve months ended December
31, 2003 compared to the same period of 2002, primarily due to higher
postretirement expenses of $9.0 million. In addition, in 2002 we settled certain
outstanding issues with LIPA and The Consolidated Edison Company of New York
that resulted in a $13.0 million decrease to operating expenses in 2002.
Net Revenues
Total electric net revenues realized during 2004 were $57.8 million, or 5%
higher than such revenues realized during 2003. This increase is primarily
attributable to the operation of the Ravenswood Expansion.
Net revenues from the Ravenswood Projects increased $53.8 million, or 18% in
2004 compared to 2003 reflecting increased capacity revenues of $19.1 million,
as well as higher energy margins of $34.7 million. The increase in capacity
revenues for the twelve months ended December 31, 2004 compared to the
corresponding period last year primarily reflects the operation of the
Ravenswood Expansion. (See the discussion below under "Other Matters" for a
description of the Ravenswood Expansion.)
54
The increase in energy margins for the twelve months ended December 31, 2004,
reflects a 32% increase in the level of megawatt hours ("MWh") sold into the New
York Independent System Operator ("NYISO") energy market, as well as an increase
of 9% in realized "spark-spreads" (the selling price of electricity less the
cost of fuel, plus hedging gains or losses). The increase in energy sales
quantities reflects the operations of the Ravenswood Expansion. As measured in
cooling degree-days, weather during the peak summer months of 2004 was
approximately 6% warmer than last year, but 7% cooler than normal. Further,
energy sales quantities in 2003 were adversely impacted by the scheduled major
overhaul of our largest electric 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 Projects. Further, we have engaged in the use of
derivative financial hedging instruments to hedge the cash flow variability
associated with a portion of forecasted electric energy sales from the
Ravenswood Projects. These derivative instruments resulted in hedging gains,
which are reflected in net electric margins, of $23.0 million in 2004 compared
to hedging gains of $12.3 million for 2003. The benefits derived from KeySpan's
hedging strategy contributed to an increase in realized spark-spreads despite
the cooler weather during the peak summer months. (See Note 8 to the
Consolidated Financial Statements "Hedging and Derivative Financial Instruments
and Fair Values" as well as Item 7A. Quantitative and Qualitative Disclosures
about Market Risk for further information").
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
Federal Energy Regulatory Commission ("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. (See the caption "Market and Credit Risk
Management Activities" for a further discussion of these matters.)
Net revenues from the service agreements with LIPA, including the power purchase
agreements associated with two electric peaking facilities, increased $5.3
million for the twelve months ended December 31, 2004, compared to 2003. This
increase reflects, in part, recovery from LIPA of approximately $26 million in
higher property taxes and depreciation charges. These recoveries had no impact
on operating income since actual property taxes and depreciation charges
increased by a like amount. Further, comparative revenues reflect adjustments to
the cost recovery mechanism in the LIPA Service Agreements to match actual costs
incurred with recovery of such costs. These adjustments reduced revenues in 2004
by approximately $10 million compared to 2003. These adjustments to revenues had
no impact on operating income since actual operating costs decreased by a like
amount. Excluding these two items, net revenues from the service agreements with
LIPA decreased approximately $10 million in 2004, compared to 2003, reflecting a
lower level of off-system sales and emission credits, both of which are shared
with LIPA. In 2004 we earned $16.4 million associated with non-cost performance
incentives provided for under these agreements, compared to $16.2 million earned
in 2003. (For a description of the LIPA Agreements, see the discussion under the
caption "LIPA Agreements.")
55
In addition to the above, net revenues from our electric marketing activities
were slightly lower in 2004 compared to 2003.
Total electric net revenues decreased $24.9 million, or 2% 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 increases in the level of capacity sold
and in the selling price of capacity. Such increases were the result of two
measures. First, in 2002, the 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 methodology, and prior to the 2002/2003 winter season capacity auction,
corrected the calculation methodology to ensure that sufficient capacity was
procured. The corrected calculation methodology 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, FERC approved the NYISO's revised capacity market
procurement design with an effective date of May 21, 2003. This revised capacity
market procurement design was 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 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 was 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 23% cooler than
2002. 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
56
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 noted earlier) 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, as previously indicated.
As noted earlier, 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 Projects, as well as to hedge the cash
flow variability associated with a portion of forecasted peak electric energy
sales from these facilities. These derivative instruments resulted in hedging
gains, which were 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.)
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 in 2002.
Included in revenues for 2003 were billings to LIPA for certain third party
costs that were lower than such billings in 2002. These revenues had 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 2002. 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 in 2002.
Net revenues from the peaking facilities were $9.6 million higher in 2003
compared to 2002, reflecting a full year of operation. The facilities were
placed in service on June 1, 2002 and 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.
The remaining decrease in net revenues reflects lower net revenues associated
with KeySpan's electric marketing subsidiary.
Operating Expenses
Total operating expenses increased $39.9 million, or 5%, for the year-ended
December 31, 2004 compared to the same period of 2003, due to higher operating
taxes and depreciation charges, partially offset by lower operations and
maintenance expenses. Operations and maintenance expense decreased $5.3 million
reflecting, in part, $10 million in lower costs associated with the LIPA Service
Agreements as noted earlier. Operations and maintenance expense also reflects
the impact of FIN 46 which required KeySpan to consolidate the Ravenswood Master
Lease and classify the lease obligation as long-term debt on the Consolidated
Balance Sheet. Further, an asset was recorded 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. As a result of
57
implementing FIN 46, beginning January 1, 2004, lease payments associated with
the Ravenswood Master Lease have been reflected as interest expense on the
Consolidated Statement of Income and the leased assets are being depreciated.
The reclassification of lease payments associated with the Ravenswood Master
Lease to interest expense resulted in a comparative decrease to operations and
maintenance expense of $30 million. However, KeySpan incurred lease costs of $11
million associated with the sale/leaseback transaction involving the Ravenswood
Expansion, that went into effect May 2004. In addition, KeySpan incurred
increased repair and maintenance costs, including removal costs, associated with
the Ravenswood Projects, as well as higher postretirement costs, which, for the
most part, offset the beneficial impact of FIN 46.
The increase in depreciation expense of $21.1 million primarily relates to the
depreciation of the leased assets under the Ravenswood Master Lease which
increased depreciation by $16 million. The remaining increase in depreciation
expense is associated with KeySpan's Long Island based electric generating units
and is fully recoverable from LIPA. The higher operating taxes primarily reflect
an increase in property taxes which are fully recoverable from LIPA, as noted
earlier.
Operating expenses decreased $6.6 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
earlier. Excluding the decrease in these costs, operating expenses increased
approximately $23 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 two peaking facilities.
Other Matters
The Ravenswood Expansion, a 250 MW combined cycle generating 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 and in May 2004 the facility began full commercial
operations. The entire capacity and energy produced from this plant is being
sold into the NYISO markets.
To finance this facility, KeySpan entered into a leveraged lease financing
arrangement. In May 2004, the facility was acquired by a lessor from our
subsidiary, KeySpan Ravenswood, LLC, and simultaneously leased back to it. All
the obligations of our subsidiary under the lease have been unconditionally
guaranteed by KeySpan. This lease transaction generated cash proceeds of $385
58
million, before transaction costs, which approximates the fair market value of
the facility, as determined by a third-party appraiser. The lease has an initial
term of 36 years and the yearly operating lease expense will be approximately
$17 million per year. Lease payments will fluctuate from year to year, but are
substantially paid over the first 16 years. (See Note 7 to the Consolidated
Financial Statements, "Financial Guarantees and Contingencies" for additional
information regarding this financing arrangement.)
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 would have
jointly owned and operated two 250 MW electric generating facilities to be
located on Long Island, one of which is the Melville site and the other in the
town of Brookhaven which also has received all permits and approvals. In May
2004, LIPA tentatively selected proposals submitted by two other bidders in
response to the RFP. KeySpan remains committed to the Melville project and the
benefits to Long Island's energy future that this project would supply. The
project has received New York State Article X approval by having met all
operational and environmental permitting requirements. Further, the project is
strategically located in close proximity to both the high voltage power
transmission grid and the high pressure gas distribution network.
LIPA is in the process of performing a long-term strategic review initiative
regarding its future direction. Some of the strategic options that LIPA is
considering include whether LIPA should continue its operations as they
presently exist, fully municipalize or privatize, sell some, but not all of
their assets and become a regulator of rates and services. Until LIPA makes a
determination on its future direction, we are unable to determine what the
outcome of this strategic review will have on the Melville project. At December
31, 2004, total capitalized costs associated with the siting, permitting and
procurement of equipment for the Melville facility were approximately $62.5
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.
59
Energy Services
The Energy Services segment includes subsidiaries that provide energy-related
services to customers primarily located within the Northeastern United States,
with concentrations in the New York City and Boston metropolitan areas, through
the following lines of business: (i) Home Energy Services, which provides
residential and small commercial customers with service and maintenance of
energy systems and appliances and (ii) Business Solutions, which now provides
operation and maintenance, design, engineering and consulting services to
commercial and industrial customers.
The table below highlights selected financial information for the Energy
Services segment. The December 31, 2003 and 2002 data has been restated to
reflect certain businesses in the Business Solutions division - specifically the
mechanical contracting companies - as discontinued operations due to the sale of
these companies in January and February 2005.
- ---------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2004 2003 2002
- ---------------------------------------------------------------------------------------------------------
Revenues $ 193,921 $ 166,375 $ 208,624
Less: Operating expenses 227,799 199,338 254,205
Goodwill impairment 14,424 - -
- ---------------------------------------------------------------------------------------------------------
Operating (Loss) $ (48,302) $ (32,963) $ (45,581)
- ---------------------------------------------------------------------------------------------------------
The Energy Services segment incurred operating losses of $48.3 million for the
year-ended December 31, 2004 compared to losses of $33.0 million for the same
period last year. As noted earlier, in September 2004, KeySpan recorded a
non-cash goodwill impairment charge in continuing operations of $14.4 million as
a result of an evaluation of the carrying value of goodwill recorded in this
segment. Based upon the operating results experienced by the Energy Services
segment and management's opinion that it was likely that a significant portion
of the Energy Services segment would be sold within one year, KeySpan conducted
an evaluation of the carrying value of its investments in this segment. That
evaluation resulted in a total pre-tax impairment charge of $208.6 million
($152.4 million, or $0.95 per share after-tax) - $14.4 million of this charge is
attributable to continuing operations, while the remaining $194.2 million
($139.9 million after-tax, or $0.87 per share), has been reflected in
discontinued operations. (See Note 11 to the Consolidated Financial Statements
"Energy Services - Discontinued Operations" for additional details on this
charge.)
Excluding the goodwill impairment charge, operating income for the twelve months
ended December 31, 2004 was essentially the same as 2003. Lower operating
results realized by Home Energy Services were offset by lower operating expenses
of the remaining Business Solutions companies. Home Energy Services experienced
higher operating expenses as a result of the write-off of accounts receivable
and contract revenues on certain projects that were deemed to be uncollectible,
as well as the write-down of inventory balances.
60
Operating results were $12.6 million better in 2003 compared to 2002 due to the
operations of the Home Energy Services group of companies. Comparative operating
results reflect 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.
Energy Investments
The Energy Investments segment consists of our gas exploration and production
investments, as well as certain other domestic and international energy-related
investments. In June 2004, KeySpan exchanged 10.8 million shares of common stock
of The Houston Exploration Company ("Houston Exploration") an independent
natural gas and oil exploration company located in Houston, Texas for 100% of
the stock of Seneca Upshur Petroleum, Inc. ("Seneca-Upshur"), previously a
wholly owned subsidiary of Houston Exploration. This transaction reduced our
interest in Houston Exploration from 55% to approximately 23.5%. As part of this
transaction, Houston Exploration retired 4.6 million of its common shares and
issued 6.8 million new shares in a public offering. Based on Houston
Exploration's announced offering price of $48.00 per share, Seneca-Upshur's
shares were valued at the equivalent of $449 million, or $41.57 per share.
Seneca-Upshur's assets consisted of West Virginia gas producing properties
valued at $60 million, and $389 million in cash. 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, this
transaction resulted in a gain to KeySpan of $150.1 million. Effective June 1,
2004, Houston Exploration's earnings and our ownership interest in Houston
Exploration were accounted for on the equity basis of accounting. The
deconsolidation of Houston Exploration required the recognition of certain
deferred taxes on our remaining investment resulting in a net deferred tax
expense of $44.1 million. Therefore, the net gain on the share exchange less the
deferred tax provision was $106 million, or $0.66 per share.
In November 2004, KeySpan sold its remaining 23.5% interest in Houston
Exploration (6.6 million shares) and received cash proceeds of approximately
$369 million. KeySpan recorded a pre-tax gain of $179.6 million which is
reflected in other income and (deductions) on the Consolidated Statement of
Income. The after-tax gain was $116.8 million or $0.73 per share.
Our gas exploration and production activities now include our wholly-owned
subsidiaries Seneca-Upshur and KeySpan Exploration and Production, LLC ("KeySpan
Exploration and Production"), which is engaged in a joint venture with Houston
Exploration.
In the second quarter of 2004, KeySpan recorded a $48.2 million non-cash
impairment charge to recognize the reduced valuation of proved reserves. See
Note 1 to the Consolidated Financial Statements "Summary of Significant
Accounting Policies" Item F "Gas Exploration and Production Property -
Depletion" for further information on this charge.
Asset transactions regarding our investment in Houston Exploration were also
recorded in 2003. 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
61
realized net proceeds of $79 million in connection with this repurchase. 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.
Selected financial data and operating statistics for our gas exploration and
production activities is set forth in the following table for the periods
indicated. Operating income represents 100% of our gas exploration and
production subsidiaries' results for all periods prior to May 31, 2004 and five
months of equity earnings (June 1, 2004 through October 31, 2004) for our 23.5%
interest in Houston Exploration.
- ---------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2004 2003 2002
- ---------------------------------------------------------------------------------------------------------------------
Revenues $ 279,999 $ 501,255 $ 357,451
Less: Depletion and amortization expense 108,791 204,102 176,925
Full cost ceiling test write-down 48,190 - -
Other operating expenses 49,320 99,944 70,267
Plus: Equity earnings 20,757 - -
- ---------------------------------------------------------------------------------------------------------------------
Operating Income $ 94,455 $ 197,209 $ 110,259
- ---------------------------------------------------------------------------------------------------------------------
Executive Summary
Operating income decreased $102.8 million in 2004 compared to 2003 reflecting
KeySpan's lower ownership in Houston Exploration during the year, and its
ultimate sale as discussed above.
Operating income increased $87.0 million in 2003 compared to 2002 due to
significantly higher average realized gas prices and a moderate increase in
production volumes offset, to some extent, by an increase in operating expenses
associated with a higher depletion rate, as well as higher lease operating
expenses and severance taxes.
Operating Income
The decline in operating income of $102.8 million for the twelve months ended
December 31, 2004 compared to the corresponding period in 2003, reflects the
reduction in KeySpan's ownership interest in Houston Exploration. As noted, in
2003 KeySpan maintained a 55% ownership interest in Houston Exploration. In
2004, KeySpan maintained a 55% ownership interest for the five month period
January 1, 2004 through May 31, 2004, then held an approximate 23.5% interest
for the five month period June 1, 2004 through October 31, 2004. KeySpan sold
its remaining 23.5% interest in Houston Exploration in November 2004. Further,
the reduction in operating income in 2004 also reflects the $48.2 million
non-cash impairment charge recorded by KeySpan's wholly-owned gas exploration
and production subsidiaries to reflect the reduced valuation of proved reserves,
as noted above.
62
Seneca-Upshur utilizes over-the-counter ("OTC") natural gas swaps to hedge the
cash flow variability associated with forecasted sales of a portion of its
natural gas production. At December 31, 2004, Seneca-Upshur has hedge positions
in place for approximately 85% of its estimated 2005 through 2007 gas
production, net of gathering costs. We use forward index prices to value these
swap positions. (See Note 8 to the Consolidated Financial Statements "Hedging,
Derivative Financial Instruments and Fair Values" for further details on the
derivative financial instruments.)
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 increase in operating income of $87.0 million or 79% for the year ended
December 31, 2003, compared to the same period of 2002, reflected 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
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 were 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.
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 reflected downward
reserve revisions related to performance, the addition of more costs to Houston
Exploration's depletion base with fewer additions of 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 were increasing as new wells and
facilities were added and production from existing wells was maintained.
63
For much of 2004, subsidiaries in this segment also held an ownership interest
in certain midstream natural gas assets in Western Canada through KeySpan
Canada. These assets included 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. At the beginning of 2004, KeySpan
held a 60.9% ownership interest in KeySpan Canada. In April 2004, KeySpan and
KeySpan Facilities Income Fund (the "Fund"), an open-ended income fund trust
which previously owned the other 39.1% interest in KeySpan Canada, consummated a
transaction whereby the Fund sold 15.617 million units of the Fund at a price of
CDN$12.60 per unit for gross total proceeds of approximately CDN$196.8 million.
The proceeds of the offering were used by the Fund to acquire an additional
35.91% interest in KeySpan Canada from KeySpan. We received net proceeds of
approximately CDN$186.3 million (or approximately US$135 million), after
commissions and expenses. The Fund's ownership in KeySpan Canada increased from
39.1% to 75%, and KeySpan's ownership of KeySpan Canada decreased from 60.9% to
25%. KeySpan recorded a gain of $22.8 million ($10.1 million after-tax, or $0.06
per share) on this transaction. Effective April 1, 2004 KeySpan Canada's
earnings and our ownership interest in KeySpan Canada had been accounted for on
the equity basis of accounting.
In July 2004, the Fund issued an additional 10.7 million units, the proceeds of
which were used to fund the acquisition of the midstream assets of Chevron
Canada Midstream Inc. This transaction had the effect of further diluting
KeySpan's ownership of KeySpan Canada to 17.4%.
In December 2004, KeySpan sold its remaining 17.4% interest in KeySpan Canada to
the Fund and received net proceeds of approximately $119 million and recorded a
pre-tax gain of $35.8 million, which is reflected in other income and
(deductions) on the Consolidated Statement of Income. The after-tax gain was
approximately $24.7 million, or $0.15 per share.
Asset transactions regarding our investment in KeySpan Canada were also recorded
in 2003. In 2003, we sold a portion of our interest in KeySpan Canada through
the Fund. The Fund acquired a 39.1% ownership interest in KeySpan Canada through
an indirect subsidiary, and then issued 17 million trust units to the public
through an initial public offering. Each trust unit represented a beneficial
interest in the Fund and was 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 was 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.
This segment is also engaged in pipeline development activities. KeySpan and
Duke Energy Corporation each own a 50% interest in Islander East Pipeline
Company, LLC ("Islander East"). Islander East was created to pursue the
authorization and construction of an interstate pipeline from Connecticut,
across Long Island Sound, to a terminus near Shoreham, Long Island. 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. Further, in August 2004, KeySpan
acquired a 21% interest in the Millennium Pipeline project which will transport
up to 500,000 DTH of natural gas a day from Corning to Ramapo, New York, where
it will connect to an existing pipeline.
64
Additionally, subsidiaries in this segment 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 the KeySpan LNG facility
in Providence, Rhode Island, a 600,000 barrel liquefied natural gas storage and
receiving facility. 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 addition to the asset sales noted previously, KeySpan anticipates selling its
50% interest in PTL, a gas pipeline from southwest Scotland to Northern Ireland.
On February 25, 2005, KeySpan entered into a Share Sale and Purchase Agreement
with BG Energy Holdings Limited and Premier Transmission Financing plc ("PTF"),
pursuant to which all of the outstanding shares of PTL are to be purchased by
PTF. It is expected that the sale of our 50% interest in PTL will result in
proceeds of approximately $42.5 million and that the closing of this transaction
will occur before the end of the second quarter of 2005. In the fourth quarter
of 2004, KeySpan recorded a pre-tax non-cash impairment charge of $26.5 million
- - $18.8 million after-tax or $0.12 per share, reflecting the difference between
the anticipated cash proceeds from the sale of PTL compared to its carrying
value. This investment is also accounted for under the equity method.
In the fourth quarter of 2003, we completed the sale of our then 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.
Selected financial data for our other energy-related investments is set forth in
the following table for the periods indicated. Operating income below represents
100% of KeySpan Canada's results for three months ended March 31, 2004 and
equity earnings from April 1, 2004 through November 30, 2004.
- -------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2004 2003 2002
- -------------------------------------------------------------------------------------------------------
Revenues $ 46,988 $ 113,124 $ 90,778
Less: Operation and maintenance expense 33,453 68,568 57,161
Other operating expenses 7,556 22,317 17,622
Impairment charge 26,541 - -
Add: Equity earnings 25,779 19,106 13,992
Gain on sale of property 5,021 - 2,348
- -------------------------------------------------------------------------------------------------------
Operating Income $ 10,238 $ 41,345 $ 32,335
- -------------------------------------------------------------------------------------------------------
The decrease in comparative operating income in 2004 compared to last year
reflects the impairment charge associated with our investment in PTL, as well as
our lower ownership interest in KeySpan Canada. Operating income from our other
energy-related investments in 2004 was substantially the same as 2003.
The increase in operating income in 2003 compared to 2002 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
65
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 the KeySpan LNG storage facility located in Rhode
Island, which we acquired in December 2002.
Allocated Costs
As previously mentioned, KeySpan is subject to the jurisdiction of the
Securities and Exchange Commission ("SEC") under the Public Utility Holding
Company Act ("PUHCA") as amended. Under PUHCA, the SEC regulates various
transactions among affiliates within a holding company system. In accordance
with the SEC's regulations under PUHCA and the New York State Public Service
Commission, we have service companies that provide: (i) traditional corporate
and administrative services; (ii) gas and electric transmission and distribution
systems planning, marketing, and gas supply planning and procurement; and (iii)
engineering and surveying services to subsidiaries. Operating income variations
reflected in "eliminations and other" associated with these non-operating
subsidiaries reflect, in part, allocation adjustments recorded in 2003. As
required by the SEC, during 2003 we adjusted certain provisions in our
allocation methodology that resulted in certain costs being allocated back to
certain non-operating subsidiaries. Further, in 2004 KeySpan reached a
settlement with its insurance carriers regarding cost recovery for expenses
incurred at a non-utility environmental site and recorded an $11.6 million gain
from the settlement as a reduction to operating expenses.
The variation in operating income for these non-operating subsidiaries between
2003 and 2002 primarily reflects a $10 million favorable adjustment recorded in
2003 for environmental reserves associated with non-utility environmental sites
based on a site investigation study concluded in the fourth quarter of 2003.
Liquidity
Cash flow from operations for the year ended December 31, 2004 decreased $473.3
million, or 39%, compared to 2003 primarily due to federal tax refunds received
in 2003. 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 for 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
compared with federal tax payments made in 2004 of $63.2 million, resulted in a
comparative cash flow decrease in 2004 of approximately $340.5 million. Further,
cash flow from operations for 2004 was adversely impacted by the deconsolidation
of Houston Exploration in June 2004.
On October 26, 2004, the American Jobs Creation Act of 2004 (the "Act") was
enacted into law. A significant provision of the Act, as it relates to KeySpan,
is the 85% dividend deduction for dividends received from foreign corporations.
The Act allows KeySpan to tax-effectively bring funds invested outside the
United States back into the United States. At December 31, 2004 KeySpan had $360
million of temporary cash investments outside the United States. KeySpan intends
to repatriate this cash in 2005.
66
Cash flow from operations for the year ended December 31, 2003 increased $475.7
million, or 64%, compared to 2002. As noted above, in 2003 KeySpan received
approximately $277.3 in federal tax refunds. These refunds compared to 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 of 2003,
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
refill natural gas storage levels as a result of the higher natural gas prices.
At December 31, 2004, we had cash and temporary cash investments of $922.0
million. During 2004, we borrowed an additional $430.3 million of commercial
paper and, at December 31, 2004, $912.2 million of commercial paper was
outstanding at a weighted-average annualized interest rate of 2.4%. We had the
ability to borrow up to an additional $388 million at December 31, 2004, under
the terms of our credit facility. As discussed in more detail under the caption
"Financing", in January 2005 KeySpan used a portion of its temporary cash
investments to redeem $500 million of previously outstanding long-term debt.
In June 2004, KeySpan completed the restructuring of its credit facilities. We
entered into a new $640 million five year revolving credit facility to replace
the $450 million, 364 day facility which expired in June. We also amended our
existing three year $850 million facility due June 2006 to reduce commitments
thereunder by $190 million to a new level of $660 million. The two credit
facilities total $1.3 billion and are each syndicated among sixteen banks. These
facilities continue to support KeySpan's commercial paper program for working
capital needs.
The fees for these facilities are subject to a ratings-based grid, with an
annual fee of 0.08% on the new five-year facility and 0.125% on the existing
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 in the five-year facility are based on
the Eurodollar rate plus a margin of 0.40% for loans up to 33% of the total
five-year facility, and an additional 0.125% for loans over 33% of the total
five-year facility. In the three-year facility Eurodollar loans are based on the
Eurodollar rate plus a margin of 0.625% for loans up to 33% of the total
three-year facility, and an additional 0.125% for loans over 33% of the total
three-year facility. 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%. Competitive
bid loans are based on bid results requested by KeySpan from the lenders. We do
not anticipate borrowing against these facilities; however, if the credit rating
on our commercial paper program were to be downgraded, it may be necessary to do
so.
67
The facilities contain 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% until the
expiration of the existing three-year facility in 2006, at which time it will be
lowered to 62%. Violation of this covenant could result in the termination of
the facilities and the required repayment of amounts borrowed thereunder, as
well as possible cross defaults under other debt agreements.
Under the terms of the credit agreements, KeySpan's debt-to-total capitalization
ratio reflects 80% equity treatment for the MEDS Equity Units issued in May
2002. At December 31, 2004, consolidated indebtedness, as calculated under the
terms of the credit agreements was 53.4% of consolidated capitalization.
Houston Exploration and KeySpan Canada also had revolving credit facilities with
commercial banks. During the time period that Houston Exploration's results were
consolidated with KeySpan's (the five months ended May 31, 2004) Houston
Exploration borrowed $49 million under its credit facility and repaid $136
million. KeySpan Canada repaid $17.7 million under its facility during the first
three months of 2004 (the time period in which its results were consolidated
with KeySpan's). These borrowings and repayments are included in the
Consolidated Cash Flow Statement.
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. Additionally, our KEDNE gas
supply is concentrated with Merrill Lynch Trading. Accordingly, our cash flows
are dependent upon the timely payment or delivery of amounts or commodity owed
to us by these counterparties.
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.
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) 2004 2003
- --------------------------------------------------------------------------
Gas Distribution $ 414,522 $ 419,549
Electric Services 150,320 256,498
Energy Investments 160,225 314,097
Energy Services and other 25,262 19,249
- --------------------------------------------------------------------------
$ 750,329 $ 1,009,393
- --------------------------------------------------------------------------
68
Construction expenditures related to the Gas Distribution segment are primarily
for the renewal, replacement and expansion of the distribution system.
Construction expenditures for the Electric Services segment reflect cost to
maintain our generating facilities and construct the Ravenswood Expansion.
Construction expenditures related to the Energy Investments segment primarily
reflect costs associated with gas exploration and production activities,
including those of Houston Exploration through May 31, 2004, as well as costs
related to KeySpan Canada's gas processing facilities through April 1, 2004. The
decrease in capital expenditures in 2004 compared to 2003 primarily reflects the
lower ownership interest in Houston Exploration, as well as the completion of
the Ravenswood Expansion in May 2004.
Construction expenditures for 2005 are estimated to be approximately $650
million. The amount of future construction expenditures is reviewed on an
ongoing basis and can be affected by timing, scope and changes in investment
opportunities.
Financing
In August 2004, KeySpan redeemed approximately $758 million of outstanding debt.
The table below indicates the various series of debt redeemed and the associated
KeySpan subsidiary:
- ------------------------------------------------------------------------------------------------------------------
KeySpan Subsidiary Series Due Date Amount ($000)
- ------------------------------------------------------------------------------------------------------------------
KeySpan Corporation 7.25% Medium Term Notes November 2005 $ 700,000
EnergyNorth Natural Gas 9.70% Series B September 2019 7,000
EnergyNorth Natural Gas 9.75% Series C September 2020 10,000
EnergyNorth Natural Gas 8.44% Series D January 2009 1,667
EnergyNorth Natural Gas 7.40% Series E September 2027 21,285
Essex Gas Company 10.10% Series 1990 December 2020 8,000
Essex Gas Company 7.28% Series 1996 December 2016 10,000
- ------------------------------------------------------------------------------------------------------------------
$ 757,952
- ------------------------------------------------------------------------------------------------------------------
KeySpan incurred $54.5 million in call premiums associated with these
redemptions, of which $45.9 was expensed and recorded in other income and
deductions on the Consolidated Statement of Income. The remaining amount of the
call premiums have been deferred for future recovery. Further, KeySpan wrote-off
$8.2 million of previously deferred financing costs which have been reflected in
interest expense on the Consolidated Statement of Income. The total after-tax
expense of the debt redemption was $29.3 million or $0.18 per share.
During the third quarter of 2004, KEDNY retired $8.0 million of its outstanding
Gas Facilities Revenue Bonds. The funds used to retire this debt were drawn from
a special deposit defeasance trust previously established by KEDNY.
Approximately $640 million of Gas Facilities Revenue Bonds remain outstanding.
69
In August 2004, KeySpan redeemed 83,268 shares of preferred stock 6.00% Series A
par value $100 that were previously issued in a private placement. KeySpan
redeemed these shares at a 2% premium and incurred a cash expenditure of $8.5
million.
In addition, on January 14, 2005, KeySpan redeemed $500 million 6.15% Series due
2006 of outstanding debt. KeySpan incurred $20.9 million in call premiums and
wrote-off $1.0 million of previously deferred financing costs. Further, KeySpan
accelerated the amortization of approximately $10.5 million of previously
unamortized benefits associated with an interest rate swap on these bonds. The
accelerated amortization was recorded as a reduction to interest expense.
Further, $55.3 million 7.07% Series B of mandatory redeemable preferred stock is
scheduled to be redeemed in May 2005.
During the second quarter of 2004, KeySpan entered into a leveraged lease
financing arrangement associated with the Ravenswood Expansion. In May 2004, the
facility was acquired by a lessor from our subsidiary, KeySpan Ravenswood, LLC,
and simultaneously leased back to that subsidiary. All of the obligations of our
subsidiary under the lease have been unconditionally guaranteed by KeySpan. This
lease transaction generated cash proceeds of $385 million, before transaction
costs, which approximates fair market value of the facility, as determined by a
third-party appraiser. (See Note 7 to the Consolidated Financial Statements,
"Contractual Obligations, Financial Guarantees and Contingencies" for additional
information regarding this financing arrangement.)
In October 2004, KeySpan filed a new universal shelf Registration Statement to
issue, from time to time, up to $3 billion in securities. We will continue to
evaluate our capital structure and financing strategy for 2005 and beyond.
The following table represents the ratings of our long-term debt at December 31,
2004. During the fourth quarter of 2004 Standard & Poor's reaffirmed its ratings
on KeySpan's and its subsidiaries' long-term debt and removed its negative
outlook. Moody's Investor Services, however, continues to maintain its negative
outlook ratings on KeySpan's and its subsidiaries' long-term debt.
- -----------------------------------------------------------------------------------------------
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
KeySpan Generation A3 A N/A
- -----------------------------------------------------------------------------------------------
70
Off-Balance Sheet Arrangements
Guarantees
KeySpan has a number of financial guarantees with its subsidiaries at December
31, 2004. KeySpan had fully and unconditionally guaranteed: (i) $525 million of
medium-term notes issued by KEDLI; (ii) the obligations of KeySpan Ravenswood
LLC, which is the lessee under the $425 million Master Lease associated with the
Ravenswood Facility and the lessee under the sale/leaseback transaction for the
Ravenswood Expansion; 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 Authorities for the construction of two
electric-generation peaking facilities on Long Island. The medium-term notes,
the Master Lease and the tax-exempt bonds are reflected on the Consolidated
Balance Sheet; the sale/leaseback transaction is not recorded on the
Consolidated Balance Sheet. Further, KeySpan has guaranteed: (i) up to $258
million of surety bonds associated with certain construction projects currently
being performed by former subsidiaries within the Energy Services segment; (ii)
certain supply contracts, margin accounts and purchase orders for certain
subsidiaries in an aggregate amount of $74 million; and (iii) $74 million of
subsidiary letters of credit. These guarantees are not recorded on the
Consolidated Balance Sheet. KeySpan's guarantees on certain performance bonds
relating to current construction projects of the discontinued mechanical
contracting companies will remain in place throughout the construction period.
It is contemplated that the majority of the current contracts will be completed
by the end of 2005. KeySpan has received an indemnity bond issued by a third
party to offset potential exposure related to a significant portion of the
continuing guarantee. At this time, we have no reason to believe that our
subsidiaries or former 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, as well as Note 11 "Energy Services
- - Discontinued Operations" for additional information on the discontinued
mechanical contracting companies.)
Contractual Obligations
KeySpan has certain contractual obligations related to its outstanding long-term
debt, outstanding credit facility borrowings, outstanding commercial paper
borrowings, various 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 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."
71
The table below reflects maturity schedules for KeySpan's contractual
obligations at December 31, 2004. Included in the table is the long-term debt
that has been consolidated as part of the variable interest entity associated
with the Ravenswood Master Lease.
- ------------------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
Contractual Obligations Total 1 - 3 Years 4 - 5 Years After 5 Years
- ------------------------------------------------------------------------------------------------------------------------------
Long-term Debt $ 4,442,450 $ 527,000 $ 1,017,250 $ 2,898,200
Capital Leases 11,833 3,172 2,326 6,335
Operating Leases 411,149 190,961 124,529 95,659
Master Lease Payments 128,189 85,459 42,730 -
Sale/Leaseback Arrangement 598,920 69,375 72,430 457,115
Preferred Stock Redeemable 75,000 75,000 - -
Interest Payments 2,680,715 679,487 396,612 1,604,616
Demand Charges 485,209 485,209 - -
- ------------------------------------------------------------------------------------------------------------------------------
Total Contractual
Cash Obligations $ 8,833,465 $ 2,115,663 $ 1,655,877 $ 5,061,925
- ------------------------------------------------------------------------------------------------------------------------------
Commercial Paper $ 912,246 Revolving
- ------------------------------------------------------------------------------------------------------------------------------
For information regarding projected post retirement contributions, see Note 4 to
the Consolidated Financial Statements "Post Retirement Benefits."
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.
72
Valuation of Goodwill
KeySpan records goodwill on purchase transactions, representing the excess of
acquisition cost over the fair value of net assets acquired. In testing for
goodwill impairment under SFAS 142 "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.
As prescribed in SFAS 142, KeySpan is required to compare the fair value of a
reporting unit to its carrying amount, including goodwill. This evaluation is
required to be performed at least annually, unless facts and circumstances
indicated that the evaluation should be performed at an interim period during
the year. Prior to this evaluation, the recorded goodwill for the Energy
Services segment, as a result of prior acquisitions, was approximately $173
million.
The Energy Services segment has experienced significantly lower operating
profits and cash flows than originally projected. As previously reported,
management reviewed the operating performance of this segment. At a meeting held
on November 2, 2004, KeySpan's Board of Directors authorized management to begin
the process of disposing of a significant portion of its ownership interests in
certain companies within the Energy Services segment - specifically those
companies engaged in mechanical contracting activities. In January and February
of 2005, KeySpan sold its mechanical contracting companies.
During 2004 KeySpan conducted an evaluation of the carrying value of goodwill
recorded in its Energy Services segment. As a result of this evaluation, KeySpan
recorded a non-cash goodwill impairment charge of $108.3 million ($80.3 million
after tax, or $0.50 per share) in 2004. This charge was recorded as follows: (i)
$14.4 million as an operating expense on the Consolidated Statement of Income
reflecting the write-down of goodwill on Energy Services segment's continuing
operations; and (ii) $93.9 million as discontinued operations reflecting the
impairment on the mechanical contracting companies. KeySpan employed a
combination of two methodologies in determining the estimated fair value for its
investment in the Energy Services segment, a market valuation approach and an
income valuation approach. Under the market valuation approach, KeySpan utilized
a range of near-term potential realizable values for the mechanical contracting
businesses. Under the income valuation approach, the fair value was obtained by
discounting the sum of (i) the expected future cash flows and (ii) the terminal
value. KeySpan was required to make certain significant assumptions,
specifically the weighted-average cost of capital, short and long-term growth
rates and expected future cash flows. (See Note 11 to the Consolidated Financial
Statements "Energy Services-Discontinued Operations" for further details.)
73
In addition to the goodwill evaluation conducted for the Energy Services
segment, KeySpan conducted evaluations of the goodwill recorded in the Gas
Distribution and Energy Investments segments. Based on KeySpan's evaluation of
the fair value of the Gas Distribution unit, KeySpan concluded that the fair
value of the Gas Distribution unit exceeded the carrying value and no impairment
was necessary. As noted previously, KeySpan has entered into an agreement to
sell its 50% interest in PTL before the end of the second quarter of 2005. This
investment is accounted for under the equity method of accounting in the Energy
Investments segment. In the fourth quarter of 2004 KeySpan recorded a pre-tax
non-cash impairment charge of $26.5 million - $18.8 million after-tax or $0.12
per share. The impairment charge reflects the difference between anticipated
cash proceeds from the sale of PTL compared to its carrying value and was
recorded as a reduction to goodwill.
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 ("MADTE").
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 MADTE, 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.
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, 2004 could result in a charge to net income of approximately
$313 million or $1.95 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.
74
As is further discussed under the caption "Regulation and Rate Matters," in
October 2003 the MADTE rendered its decision on the Boston Gas Company's base
rate case and Performance Based Rate Plan proposal submitted to the MADTE in
April 2003. 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 rate 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. EnergyNorth Natural
Gas, Inc.'s base rates continue as set by the NHPUC in 1993. 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 changes 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.
For 2004, 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 performance of equity and fixed income investments
over long periods of time. The actual 10 year compound annual rate of return for
the KeySpan Plans is greater than 8.5%.
75
KeySpan's master trust investment allocation policy target is 70% equity and 30%
fixed income. At December 31, 2004, the actual investment allocation was in line
with the target. In an effort to maximize plan performance, actual asset
allocation will fluctuate from year to year depending on the then current
economic environment.
Based on the results of an asset and liability study conducted in 2003
projecting asset returns and expected benefit payments over a 10-year period,
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 performance 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 2004 expense by approximately $6 million, before
deferrals.
The year-end December 31, 2004 assumed discount rate used to determine
postretirement obligations was 6%. 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 2004 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 5.75% would have required an additional $38 million debit to
other comprehensive income ("OCI") before taxes and deferrals. A year-end
discount rate of 5.5% would have required an additional $290 million debit to
OCI before taxes and deferrals.
At January 1, 2004, the assumed discount rate used to determine postretirement
obligations was 6.25%. A 25 basis point increase or decrease in the assumed
discount rate at the beginning of the year would have impacted 2004 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, 2004, 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 2004. However, although we have presently exceeded
ERISA funding requirements, our pension plans, on an actuarial basis, are
currently underfunded. Therefore, during 2004 KeySpan contributed $186 million
to its funded and unfunded postretirement plans.
For 2005, KeySpan expects to contribute approximately $120 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.
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Full Cost Accounting
As noted previously, during 2004 KeySpan disposed of its ownership interest in
Houston Exploration. KeySpan continues to maintain gas exploration and
production activities through its two wholly-owned subsidiaries - KeySpan
Exploration and Seneca-Upshur. 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.
As a result of the disposition of Houston Exploration, during most of 2004
KeySpan calculated the ceiling test on KeySpan Exploration and Production's and
Seneca-Uphsur's assets independently of Houston Exploration's assets. Based on a
report furnished by an independent reservoir engineer during the second quarter
of 2004, it was determined that the remaining proved undeveloped oil reserves
held in the joint venture required a substantial investment in order to develop.
Therefore, KeySpan and Houston Exploration elected not to develop these oil
reserves. As a result, in the second quarter of 2004, we recorded a $48.2
million non-cash impairment charge to write down our wholly-owned gas
exploration and production subsidiaries' assets. This charge was recorded in
depreciation, depletion and amortization on the Consolidated Statement of
Income.
In calculating the ceiling test at December 31, 2004, 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.
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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. KeySpan's subsidiaries estimate
proved reserves and future net revenues using sales prices estimated to be in
effect as of the date they make the reserve estimates. Natural gas prices, which
have fluctuated widely in recent years, affect estimated quantities of proved
reserves and future net revenues. Any estimates of natural gas and oil reserves
and their values are inherently uncertain, including many factors beyond our
control. The accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment. In
addition, estimates of reserves may be revised based upon actual production,
results of future development and exploration activities, prevailing natural gas
and oil prices, operating costs and other factors, which revision may be
material. Reserve estimates are highly dependent upon the accuracy of the
underlying assumptions. Actual future production may be materially different
from estimated reserve quantities and the differences could materially affect
future amortization of natural gas and oil properties.
Accounting for Sales of Stock by a Subsidiary
KeySpan applies the accounting principle of income recognition for gains or
losses associated with the sale of stock by its subsidiaries. As provided for in
Staff Accounting Bulletin Topic 5-H ("SAB 51"), the SEC allows for income
recognition of gains or losses on subsidiary stock transactions in instances
where the transaction is not part of a broader corporate reorganization
contemplated by the parent. Provided that no other capital transactions are
contemplated with regard to the shares issued, income statement treatment in
consolidation for issuance of stock by a subsidiary is appropriate. SAB 51
requires that this accounting treatment, if elected by the parent, must be
consistently applied to all subsidiary stock transactions that meet the
conditions for income statement recognition. As noted earlier, KeySpan has
appropriately applied this accounting treatment to its subsidiary stock
transactions.
Accounting for the Sale/Leaseback Transaction and Ravenswood Master Lease
In May 2004 the Ravenswood Expansion, a new 250 MW combined cycle generating
facility at the Ravenswood Facility site began full commercial operations. The
entire capacity and energy produced from this plant is being sold into the NYISO
markets.
KeySpan structured a leverage-lease financing arrangement for this facility. At
the closing of the leasing transaction, the new facility was acquired by the
lessor from a KeySpan subsidiary and simultaneously leased back to that
subsidiary. KeySpan has unconditionally guaranteed all obligations of its
subsidiary under the lease. The lease has an initial term of 36 years.
The financing arrangement qualifies for operating lease accounting treatment
under Statement of Financial Accounting Standard ("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, an amendment of FASB Statements No. 13, 66, 91 and a rescission of
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FASB Statement No.26 and Technical Bulletin No. 79-11." The terms and conditions
of the financing arrangement are also in accordance with the accounting
requirements of SFAS 13 "Accounting for Leases," SFAS 66 "Accounting for Sales
of Real Estate," and Financial Interpretation No. ("FIN") 46R "Consolidation of
Variable Interest Entities."
As stated in SFAS 98, sale-leaseback accounting shall be used by the
seller-lessee only if the transaction includes all of the following: (i) a
normal leaseback; (ii) payment terms and provisions that adequately demonstrate
the buyer-lessor's initial and continuing investment in the property; and (iii)
payment terms and provisions that transfer all of the other risks and rewards of
ownership as demonstrated by the absence of any other continuing involvement by
the seller-lessee.
A normal leaseback is a lessee-lessor relationship that involves the active use
of the property by the seller-lessee in consideration for the payment of rent.
Active use of the property refers to the use of the property during the lease
term in the seller-lessee's trade or business. Electric generation is a
significant part of KeySpan's normal business and since we operate the new 250
MW facility, this criteria has been met. Further, since the buyer-lessor has
paid KeySpan the full fair market value of the facility, as determined by an
independent third-party appraiser, the second criteria has also been met.
With regard to criteria (iii), KeySpan is under no obligation to repurchase the
generating facility, nor does it have an option to repurchase the facility.
Further, the leasing arrangement does not contain a provision under which the
buyer-lessor can compel KeySpan to repurchase the facility. Further, the
buyer-lessor assumes a significant risk regarding return of and on the initial
capital investment.
SFAS 13 contains the following four basic criteria that, if met, would require a
lease to be classified as a capital lease: (i) the lease transfers ownership of
the property to the lessee by the end of the lease; (ii) the lease contains a
bargain purchase option; (iii) the lease term is equal to 75% or more of the
estimated economic life of the leased property; and (iv) the present value at
the beginning of the lease term of the minimum lease payments equals or exceeds
90% of the fair market value of the leased property. The financing arrangement
for the Ravenswood Expansion does not meet any of the above criteria.
Further, FIN 46R does not apply to this financing arrangement since the
arrangement meets the criteria for operating lease accounting treatment under
SFAS 98. More specifically the leasing arrangement does not absorb variability
in the fair value in the underlying assets of the lease since the leasing
arrangement does not guaranty (to the buyer/lessor) the residual value of the
leased assets and the arrangement does not contain an option for the
seller/lessee to acquire the leased assets after the term of the lease.
Dividends
In the third quarter of 2004 KeySpan increased its dividend to an annual rate of
$1.82 per common share beginning with the quarterly dividend to be paid in
February 2005. 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 $1.82 level.
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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, 2004 and November 30, 2004, respectively), the ratio of
debt to total utility capitalization was 43% and 44%, 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
KEDNY is subject to an earnings sharing provision pursuant to which it is
required to credit firm 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, 2004 was
13.25%. KEDNY did not earn above its threshold return level in its rate year
ended September 30, 2004. 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.
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, 2004. 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 MADTE.
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Effective November 1, 2003, the MADTE approved a $25.9 million increase in base
revenues for the Boston Gas Company with an allowed return on equity of 10.2%
reflecting an equal balance of debt and equity. On January 27, 2004, the MADTE
issued its order on Boston Gas Company's Motion for Recalculation,
Reconsideration and Clarification that granted an additional $1.1 million in
base revenues, for a total of $27 million. The MADTE also approved a Performance
Based Rate Plan (the "Plan") for up to ten years. On October 29, 2004, the MADTE
approved a base rate increase of $4.6 million under the Plan. In addition, an
increase of $7.9 million in the local distribution adjustment clause was
approved to recover pension and other postretirement costs. 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. This true-up mechanism allows for
carrying charges on deferred assets and liabilities at Boston Gas Company's
weighted-average cost of capital.
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
laws, accounting changes, or regulatory, judicial, or legislative changes. 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.
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 Federal Energy Regulatory Commission ("FERC") in
accordance with the Power Supply Agreement ("PSA") entered into between KeySpan
and LIPA in 1998. The prior FERC approved rates, which had 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 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. On
October 1, 2004 the FERC approved a settlement reached between KeySpan and LIPA.
Under the new Settlement Agreement, KeySpan's rates reflect a cost of equity of
9.5% with no revenue increase in the first year. The FERC approved updated
operating and maintenance expense levels and recovery of certain other costs as
agreed to by the parties.
Securities and Exchange Commission Regulation
KeySpan and certain of 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
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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.
KeySpan has the authorization, under PUHCA 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; (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 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. At December 31, 2004, KeySpan's consolidated common equity was
42% of its consolidated capitalization, including commercial paper, and each of
its utility subsidiaries common equity was at least 42% of its respective
capitalization.
On October 1, 2004, in accordance with its PUHCA authorization, KeySpan filed a
new universal shelf registration statement on Form S-3 with the SEC for the
issuance from time to time of up to $3.0 billion in securities.
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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. In 2002, we
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.
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.
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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 $5 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 was provided with a corresponding extension of 31
months for the MSA to the end of 2008.
LIPA is in the process of performing a long-term strategic review initiative
regarding its future direction. It has engaged a team of advisors and
consultants and is conducting public hearings to develop recommendations to be
submitted to the LIPA Trustees. Some of the strategic options that LIPA is
considering include whether LIPA should continue its operations as they
presently exist, fully municipalize or privatize, sell some, but not all of
their assets and become a regulator of rates and services. In the near term,
LIPA must make a determination by May 28, 2005 as to whether it will exercise
its option to purchase our Long Island generating plants pursuant to the terms
of the GPRA. Until LIPA makes a determination on its future direction, we are
unable to determine what the outcome of this strategic review will have on our
financial condition, results of operations or cash flows. Any action that may be
taken will have to take into consideration the term of our existing contracts.
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
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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 a 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 Projects
We currently sell capacity, energy and ancillary services associated with the
Ravenswood Projects through a bidding process into the NYISO energy and capacity
markets. Energy is sold 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 Projects 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. 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.
In 2004 Boston Gas Company reached an agreement with an insurance carrier for
recovery of previously incurred environmental expenditures. Under a previously
issued MADTE order, insurance and third-party recoveries, after deducting legal
fees, are shared between Boston Gas and its firm gas customers. As a result of
the insurance agreement, in September 2004 Boston Gas recorded a $5 million
benefit to operations and maintenance expense.
Also in 2004, KeySpan reached a settlement with its insurance carriers regarding
cost recovery for expenses incurred at a non-utility environmental site and
recorded an $11.6 million benefit from the settlement as a reduction to
operations and maintenance expense.
We estimate that the remaining cost of our MGP related environmental cleanup
activities, including costs associated with the Ravenswood Facility, will be
approximately $237.1 million and we have recorded a related liability for such
amount. We have also recorded an additional $19.7 million liability,
representing the estimated environmental cleanup costs related to a former coal
tar processing facility. As of December 31, 2004, we have expended a total of
$138.3 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.)
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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 prices, interest rates,
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.
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 value of investments held
change, or long-term interest rates change, the effect will be reflected in
KeySpan's recognition of periodic cost of such employee benefit plans and the
determination of contributions to the employee benefit plans.
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 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, 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 and in accordance with various
regulatory requirements.
We also have credit risk from LIPA, our largest customer, and from other energy
and financial services companies. Counterparty credit risk 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. In
instances where counterparties' credit quality has declined, or credit exposure
exceeds certain levels, 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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Regulatory Issues and Competitive Environment
We are subject to various other risk exposures and uncertainties associated with
our gas and electric operations. Set forth below is a description of these
exposures.
The Gas Industry
Long Island and New York
For the last several years, the NYPSC has been monitoring the progress of
competition in the energy market. Based upon its findings of the current market
and its continued desire to move toward fully competitive markets, the NYPSC, in
August 2004, issued a second policy statement. The underlying vision remains
unchanged. The items of importance in the new policy include:
o Elimination of a timeframe for the exit of utilities from the merchant
function. Experience, time and maturation of each market/customer class
will dictate the exit of utilities.
o Acknowledgement that competitive commodity markets for the largest
customers has occurred. However, workable competition for the mass markets
(i.e. residential and small commercial customers) is taking longer and
needs to be nurtured.
o Future rate filings must include a plan for facilitating customer migration
to competitive markets and a fully embedded cost of service study that
develops unbundled rates for the utility's delivery service and all
potentially competitive services.
o Utilities should avoid entering into long term capacity arrangements unless
it is necessary for reliability and safety purposes.
o Where markets are not workably competitive, the NYPSC must ensure that
rates continue to be just and reasonable, and protect customers from price
volatility.
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 are
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.
87
New England
In July 1997, the MADTE 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 MADTE in November 1998. In February 1999, the MADTE
issued its order on how unbundling of natural gas service will proceed. For a
five year transition period, the MADTE 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 MADTE 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 MADTE 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 MADTE began a proceeding to re-examine whether the upstream capacity market
has been sufficiently competitive to allow voluntary capacity assignment.
KeySpan submitted comments maintaining its position that the upstream capacity
market is not at this time sufficiently competitive to remove or modify the
MADTE's mandatory capacity assignment requirement.
Electric Industry
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
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 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 FERC has not acted on the
remand.
88
On June 25, 2004, the NYISO submitted a motion to FERC seeking refunds as a
result of the Decision. KeySpan and others submitted statements of opposition
opposing the refunds. On November 29, 2004, KeySpan filed a motion seeking a
settlement judge be appointed to settle the case. On January 6, 2005 FERC denied
KeySpan's request but has not yet issued a decision on the merits. We cannot
predict the outcome of these proceedings or what effect, if any, the outcome may
have on our financial position, results of operations or cash flows.
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 the electric infrastructure develops and the demand for electric
power increases over time 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 and generation facilities could also
cause significant changes to the market. KeySpan currently anticipates that
approximately 1,100 MW of new capacity may be available by the end of 2006 as a
result of the completion of in-City generation projects currently under
construction. We cannot, however, be certain as to when, or if, the new power
plants will be in operation or the nature of future New York City energy
requirements or market design.
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 appeal 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.
NYISO Standard Market Design 2.0 ("SMD2")
The NYISO's revised market design and software SMD2, was implemented on February
1, 2005. It replaced the NYISO's current two step real-time market system, which
consists of the Balancing Market Evaluation and Security Constrained Dispatch
applications, with a more integrated Real Time Scheduling system ("RTS"). RTS
uses a common computing platform, algorithms, and network models for both the
real-time commitment and real-time dispatch functions. This synergy between
commitment and dispatch functions is expected to result in improved consistency
between advisory and real-time price schedules, as well as more efficient use of
control area resources. SMD2 will more closely align the NYISO markets with the
FERC Standard Market Design Notice of Proposed Rule Making, issued on July 31,
2002.
89
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
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 distribution
operations, gas exploration and production activities and its electric
generating facilities. Our gas distribution operations utilize over-the-counter
("OTC") natural gas and fuel oil swaps to hedge the cash-flow variability of
specified portions of gas purchases and sales associated with certain
large-volume customers. Seneca-Upshur utilizes OTC natural gas swaps to hedge
cash flow variability associated with forecasted sales of natural gas. The
Ravenswood Projects use derivative financial instruments to hedge the cash flow
variability associated with the purchase of a portion of natural gas and oil
that will be consumed during the generation of electricity. The Ravenswood
Projects also hedge the cash flow variability associated with a portion of
electric energy sales using OTC electricity swaps.
KeySpan uses standard NYMEX futures prices to value gas futures and market
quoted forward prices to value OTC swap contracts.
The following tables set forth selected financial data associated with these
derivative financial instruments that were outstanding at December 31, 2004.
- --------------------------------------------------------------------------------------------------------------------------
Year of Volumes Fixed Price Current Price Fair Value
Type of Contract Maturity (mmcf) ($) ($) ($000)
- --------------------------------------------------------------------------------------------------------------------------
Gas
Swaps/Futures - Long Natural Gas 2005 6,595 4.95 - 7.11 6.07 - 6.28 (6,146)
-
OTC Swaps - Short Natural Gas 2005 1,980 6.58 - 6.70 6.33 - 7.15 212
2006 1,884 6.17 - 6.29 6.07 - 7.39 (516)
2007 1,812 5.86 - 5.97 5.71 - 6.93 (362)
- --------------------------------------------------------------------------------------------------------------------------
12,271 (6,812)
- --------------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------------
Year of Volumes Fixed Price Current Price Fair Value
Type of Contract Maturity (Barrels) ($) ($) ($000)
- --------------------------------------------------------------------------------------------------------------------------
Oil
Swaps - Long Fuel Oil 2005 84,000 24.65 - 34.40 33.90 - 34.75 268
2006 12,000 34.40 34.30 (1)
Swaps - Short Heating Oil 2005 52,372 55.44 47.25 - 52.75 7,451
- --------------------------------------------------------------------------------------------------------------------------
148,372 7,718
- --------------------------------------------------------------------------------------------------------------------------
90
- ----------------------------------------------------------------------------------------------------------------------------------
Year of Fixed Price Current Price Fair Value
Type of Contract Maturity MWh ($) ($) ($000)
- ----------------------------------------------------------------------------------------------------------------------------------
Electricity
Swaps - Energy 2005 1,562,400 29.95 - 103.10 33.89 - 101.69 353
- ---------------------------------------------------------------------------------------------------------------------------------
The following tables detail the changes in and sources of fair value for the
above derivatives:
- ------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars) 2004
Change in Fair Value of Derivative Hedging Instruments ($000)
- ------------------------------------------------------------------------------------------------------------
Fair value of contracts at January 1, 2004 $ (36,224)
Net (gains) on contracts realized (510)
Derivative balance that has been de-consolidated (Houston Exploration) 14,331
Increase in fair value of all open contracts 23,662
- ------------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at December 31, $ 1,259
- ------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- -----------------------------------------------------------------------------------------------------------
Fair Value of Contracts
- -----------------------------------------------------------------------------------------------------------
Maturity Maturity Total
Sources of Fair Value In 12 Months in 2006 and 2007 Fair Value
- -----------------------------------------------------------------------------------------------------------
Prices actively quoted $ 1,305 $ - $ 1,305
Local published indicies 834 (880) (46)
- -----------------------------------------------------------------------------------------------------------
$ 2,139 $ (880) $ 1,259
- -----------------------------------------------------------------------------------------------------------
91
We measure the commodity risk of our derivative hedging instruments (indicated
in the above table) using a sensitivity analysis. Based on a sensitivity
analysis as of December 31, 2004, a 10% increase in heating oil and natural gas
prices would decrease the value of derivative instruments maturing in 2005 by
$3.3 million, while the value of expected physical deliveries for 2005 would be
enhanced $6.4 million (net benefit to KeySpan of $3.1 million). A 10% decrease
in heating oil and natural gas prices would enhance the value of derivative
instruments maturing in 2005 by $3.3 million, while the value of expected
physical deliveries for 2005 would be decreased $6.4 million (net cost to
KeySpan of $3.1 million).
Based on a sensitivity analysis as of December 31, 2004, a 10% increase in
electricity and fuel prices would decrease the value of derivative instruments
maturing in 2005 by $5.2 million, while the value of expected physical power
production for 2005 would be enhanced $13.3 million (net benefit to KeySpan of
$8.1 million). A 10% decrease in electricity and fuel prices would have a $5.2
million favorable impact on the value of derivative instruments maturing in
2005, while the value of expected physical power production would be reduced
$15.9 million (net cost to KeySpan of $10.7 million).
Firm Gas Sales Derivative Instruments - Regulated Utilities: We use derivative
financial instruments to reduce the cash flow variability associated with the
purchase price for a portion of future natural gas purchases associated with our
Gas Distribution operations. The accounting for these derivative instruments is
subject to SFAS 71 "Accounting for the Effects of Certain Types of Regulation."
Therefore, changes in the fair value of these derivatives are recorded as a
regulatory asset or regulatory liability on the Consolidated Balance Sheet.
Gains or losses on the settlement of these contracts are deferred and then
refunded to or collected from our firm gas sales customers consistent with
regulatory requirements.
The following table sets forth selected financial data associated with these
derivative financial instruments that were outstanding at December 31, 2004.
- -----------------------------------------------------------------------------------------------------------------------------------
Year of Volumes Floor Ceiling Fixed Price Current Price Fair Value
Type of Contract Maturity (mmcf) ($) ($) ($) ($) ($000)
- -----------------------------------------------------------------------------------------------------------------------------------
Options 2005 10,330 5.00 - 6.00 5.00 - 7.00 - 6.07 - 6.88 (1,126)
2006 4,160 5.00 - 6.00 5.00 - 7.00 - 5.82 - 7.10 881
Swaps 2005 38,400 - - 6.48 - 6.56 6.07 - 6.88 (9,327)
2006 15,340 - - 6.76 - 7.03 5.82 - 7.10 (820)
- -----------------------------------------------------------------------------------------------------------------------------------
68,230 (10,392)
- -----------------------------------------------------------------------------------------------------------------------------------
See Note 8 to the Consolidated Financial Statements "Hedging, Derivative
Financial Instruments and Fair Values" for a further description of all our
derivative instruments.
92
Item 8. Financial Statements and Supplementary Data
CONSOLIDATED BALANCE SHEET
- ----------------------------------------------------------------------------------------------------------------------
At December 31,
(In Thousands of Dollars) 2004 2003
- ----------------------------------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash and temporary cash investments $ 921,973 $ 203,358
Accounts receivable 788,454 909,613
Unbilled revenue 591,394 446,573
Allowance for uncollectible accounts (67,796) (75,671)
Gas in storage, at average cost 515,459 488,521
Material and supplies, at average cost 123,476 118,912
Other 162,739 114,196
Assets of discontinued operations 42,923 181,823
-----------------------------------------------
3,078,622 2,387,325
-----------------------------------------------
Investments and Other 272,893 248,565
-----------------------------------------------
Property
Gas 6,871,221 6,522,251
Electric 2,402,052 2,636,537
Other 398,628 407,813
Accumulated depreciation (2,702,298) (2,601,701)
Gas exploration and production, at cost 187,053 3,088,242
Accumulated depletion (97,475) (1,167,427)
Property of discontinued operations 8,743 8,588
-----------------------------------------------
7,067,924 8,894,303
-----------------------------------------------
Deferred Charges
Regulatory assets 555,414 578,383
Goodwill and other intangible assets, net of amortization 1,677,601 1,717,010
Goodwill of discontinued operations - 92,702
Other 711,676 721,894
-----------------------------------------------
2,944,691 3,109,989
-----------------------------------------------
Total Assets $ 13,364,130 $ 14,640,182
===============================================
- ----------------------------------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
93
CONSOLIDATED BALANCE SHEET
- ------------------------------------------------------------------------------------------------------------
At December 31,
(In Thousands of Dollars) 2004 2003
- ------------------------------------------------------------------------------------------------------------
LIABILITIES AND CAPITALIZATION
Current Liabilities
Current maturities of long-term debt & capital leases $ 16,103 $ 1,471
Current redemption requirement of preferred stock 55,300 -
Accounts payable and other liabilities 906,650 1,065,742
Commercial paper 912,246 481,900
Dividends payable 74,059 72,289
Taxes accrued 161,629 43,943
Customer deposits 43,262 40,370
Interest accrued 48,822 64,609
Liabilities of discontinued operations 64,245 81,956
---------------------------------------------
2,282,316 1,852,280
---------------------------------------------
Deferred Credits and Other Liabilities
Regulatory liabilities:
Miscellaneous liabilities 73,963 104,034
Removal costs recovered 496,482 450,034
Deferred income tax 1,124,129 1,275,558
Postretirement benefits and other reserves 901,318 961,931
Other 139,149 121,624
---------------------------------------------
2,735,041 2,913,181
---------------------------------------------
Commitments and Contingencies (See Note 7) - -
Capitalization
Common stock 3,501,950 3,487,645
Retained earnings 792,177 621,430
Accumulated other comprehensive income (54,336) (59,932)
Treasury stock (345,081) (378,487)
---------------------------------------------
Total common shareholders' equity 3,894,710 3,670,656
Preferred stock 19,700 83,568
Long-term debt and capital leases 4,418,729 5,610,948
---------------------------------------------
Total Capitalization 8,333,139 9,365,172
---------------------------------------------
Minority Interest in Consolidated Companies 13,634 509,549
---------------------------------------------
Total Liabilities and Capitalization $ 13,364,130 $ 14,640,182
=============================================
- ------------------------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
94
CONSOLIDATED STATEMENT OF INCOME
- ---------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars, Except Per Share Amounts) 2004 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------
Revenues
Gas Distribution $ 4,407,292 $ 4,161,272 $ 3,163,761
Electric Services 1,738,660 1,605,973 1,645,688
Energy Services 182,406 158,908 208,624
Gas Exploration and Production 279,999 501,255 357,451
Energy Investments 42,109 108,116 89,650
--------------------------------------------------------
Total Revenues 6,650,466 6,535,524 5,465,174
--------------------------------------------------------
Operating Expenses
Purchased gas for resale 2,664,492 2,495,102 1,653,273
Fuel and purchased power 540,302 414,633 395,860
Operations and maintenance 1,567,022 1,622,592 1,631,297
Depreciation, depletion and amortization 551,760 571,669 513,708
Operating taxes 404,212 418,236 380,527
Impairment charges 40,965 - -
--------------------------------------------------------
Total Operating Expenses 5,768,753 5,522,232 4,574,665
--------------------------------------------------------
Gain on sale of property 7,021 15,123 4,730
Income from equity investments 46,536 19,214 14,096
--------------------------------------------------------
Operating Income 935,270 1,047,629 909,335
--------------------------------------------------------
Other Income and (Deductions)
Interest charges (331,251) (307,694) (301,504)
Sale of subsidiary stock 388,319 13,356 -
Cost of debt redemption (45,879) (24,094) -
Minority interest (36,797) (63,852) (24,918)
Other 30,591 42,005 25,054
--------------------------------------------------------
Total Other Income and (Deductions) 4,983 (340,279) (301,368)
--------------------------------------------------------
Income Taxes
Current 201,909 (99,798) (36,588)
Deferred 123,631 381,079 266,253
--------------------------------------------------------
Total Income Taxes 325,540 281,281 229,665
--------------------------------------------------------
Earnings from Continuing Operations 614,713 426,069 378,302
--------------------------------------------------------
Discontinued Operations
Income (loss) from operations, net of tax (78,960) (1,888) 15,692
Loss on disposal, net of tax (72,088) - (16,306)
--------------------------------------------------------
Loss from Discontinued Operations (151,048) (1,888) (614)
--------------------------------------------------------
Cumulative Change in Accounting Principles, net of tax - (37,451) -
--------------------------------------------------------
Net Income 463,665 386,730 377,688
Preferred stock dividend requirements 5,612 5,844 5,753
--------------------------------------------------------
Earnings for Common Stock $ 458,053 $ 380,886 $ 371,935
========================================================
Basic Earnings Per Share
Continuing Operations, less preferred stock dividends $ 3.80 $ 2.65 $ 2.64
Discontinued Operations (0.94) (0.01) (0.01)
Cumulative Change in Accounting Principles - (0.23) -
--------------------------------------------------------
Basic Earnings Per Share $ 2.86 $ 2.41 $ 2.63
========================================================
Diluted Earnings Per Share
Continuing Operations, less preferred stock dividends $ 3.78 $ 2.63 $ 2.62
Discontinued Operations (0.94) (0.01) (0.01)
Cumulative Change in Accounting Principles - (0.23) -
--------------------------------------------------------
Diluted Earnings Per Share $ 2.84 $ 2.39 $ 2.61
========================================================
Average Common Shares Outstanding (000) 160,294 158,256 141,263
Average Common Shares Outstanding - Diluted (000) 161,277 159,232 142,300
- ---------------------------------------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
95
CONSOLIDATED STATEMENT OF CASH FLOWS
- --------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2004 2003 2002
- --------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income $ 463,665 $ 386,730 $ 377,688
Adjustments to reconcile net income to net
cash provided by (used in) operating activities
Depreciation, depletion and amortization 551,760 571,669 513,708
Deferred income tax 123,631 188,689 89,284
Income from equity investments (46,536) (18,038) (14,096)
Dividends from equity investments 14,162 2,807 3,905
Amortization of interest rate swap (2,265) (9,861) -
(Gain) on interest rate swap (12,656) - -
(Gain) loss on disposal of subsidiary stock (388,319) (13,356) -
(Gain) on sale of assets (7,021) (15,123) (4,730)
Impairment charges 40,965 - -
Loss/(Income) from discontinued operations 151,048 1,888 (19,048)
Cumulative change in accounting principle - 37,451 -
Environmental reserve adjustment - (10,459) -
Minority interest 36,797 63,852 24,918
Changes in assets and liabilities
Accounts receivable (234,188) 60,394 (223,983)
Materials and supplies, fuel oil and gas in storage (38,967) (198,966) 42,547
Accounts payable and accrued expenses 159,513 225,756 (11,240)
Reserve payments (37,270) (36,486) (23,369)
Other (24,250) (13,591) (7,921)
------------------------------------------------------
Net Cash Provided by Operating Activities 750,069 1,223,356 747,663
------------------------------------------------------
Investing Activities
Construction expenditures (750,329) (1,009,393) (1,057,507)
Cost of removal (36,287) (31,103) (27,431)
Other investments - (211,370) (27,579)
Net proceeds from sale of subsidiary stock 1,001,142 294,573 175,110
Proceeds from sale of property 20,159 15,123 4,730
Issuance of long-term note - (55,000) -
------------------------------------------------------
Net Cash Provided by (Used in) Investing Activities 234,685 (997,170) (932,677)
------------------------------------------------------
Financing Activities
Treasury stock issued 33,406 96,687 86,710
Common stock issuance - 473,573 -
Issuance of long-term debt 49,336 1,024,553 549,260
Payment of long-term debt (920,081) (604,331) (124,863)
Net proceeds from sale/leasback transaction 382,049 - -
Issuance (Payment) of commercial paper 430,346 (433,797) (132,753)
Redemption of promissory notes - (447,005) -
Redemption of preferred stock (8,483) (14,293) -
Gain on interest rate swap 12,656 - 57,415
Common and preferred stock dividends paid (291,148) (280,560) (256,656)
Other 36,187 4,989 9,629
------------------------------------------------------
Net Cash (Used in) Provided by Financing Activities (275,732) (180,184) 188,742
------------------------------------------------------
Net Increase in Cash and Cash Equivalents $ 709,022 $ 46,002 $ 3,728
Net Cash Flow from Discontinued Operations 9,593 (13,261) 14,166
Cash and Cash Equivalents at Beginning of Period 203,358 170,617 152,723
------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 921,973 $ 203,358 $ 170,617
======================================================
Interest Paid $ 336,546 $ 355,136 $ 343,933
Income Tax Paid $ 122,033 $ 65,495 $ 98,344
- --------------------------------------------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
96
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
- ---------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2004 2003 2002
- ---------------------------------------------------------------------------------------------------------------------
Balance at Beginning of Period $ 621,430 $ 522,835 $ 452,206
Net Income for Period 463,665 386,730 377,688
- ---------------------------------------------------------------------------------------------------------------------
1,085,095 909,565 829,894
Deductions:
Cash dividends declared on common stock 287,306 282,291 252,175
Cash dividends declared on preferred stock 5,612 5,844 5,753
MEDS Equity Units - - 49,131
- ---------------------------------------------------------------------------------------------------------------------
Balance at End of Period $ 792,177 $ 621,430 $ 522,835
- ---------------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
- ---------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2004 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------
Net Income $ 463,665 $ 386,730 $ 377,688
- ---------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income, net of tax
Net losses (gains) on derivative instruments (332) 23,042 (17,033)
Deconsolidation of certain subsidiaries 9,315 - -
Foreign currency translation adjustments (21,536) 28,696 9,759
Unrealized gains (losses) on marketable securities 7,111 8,480 (10,019)
Premium on derivative instrument 3,437 (3,437) -
Accrued unfunded pension obligation (7,818) 8,380 (55,768)
Unrealized (losses) gains on derivative financial instruments 15,419 (25,379) (39,845)
- ---------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax 5,596 39,782 (112,906)
- ---------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 469,261 $ 426,512 $ 264,782
- ---------------------------------------------------------------------------------------------------------------------------------
Related tax (benefit) expense
Net losses (gains) on derivative instruments (178) 12,407 (9,172)
Deconsolidation of certain subsidiaries 5,016 - -
Foreign currency translation adjustments (11,596) 15,451 5,255
Unrealized gains (losses) on marketable securities 3,830 4,568 (5,395)
Accrued unfunded pension obligation (4,210) 4,513 (30,029)
Premium on derivative instrument 1,851 (1,851) -
Unrealized (losses) gains on derivative financial instruments 8,240 (13,666) (21,454)
- ---------------------------------------------------------------------------------------------------------------------------------
Total Tax (Benefit) Expense $ 2,953 $ 21,422 $ (60,795)
- ---------------------------------------------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
97
CONSOLIDATED STATEMENT OF CAPITALIZATION
- ------------------------------------------------------------------------------------------------------------------------------------
December 31, December 31,
(In Thousands of Dollars) 2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------------
Common Shareholders' Equity Shares Issued
Common stock, $0.01 par value 172,737,654 172,737,654 $ 1,727 $ 1,727
Premium on capital stock 3,500,223 3,485,918
Retained earnings 792,177 621,430
Other comprehensive income (54,336) (59,932)
Treasury stock 11,919,343 13,073,219 (345,081) (378,487)
- ------------------------------------------------------------------------------------------------------------------------------------
Total Common Shareholders' Equity 160,818,311 159,664,435 3,894,710 3,670,656
- ------------------------------------------------------------------------------------------------------------------------------------
Preferred Stock - 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 - 8,568
Less: current redemption requirements (553,000) - (55,300) -
- ------------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - Redemption Required 19,700 83,568
- ------------------------------------------------------------------------------------------------------------------------------------
Long - Term Debt Interest Rate Maturity
- ------------------------------------------------------------------------------------------------------------------------------------
Notes
Medium term notes 4.65% - 9.75% 2005 - 2033 2,485,000 3,185,000
Senior secured notes 6.08%- 8.8% 2008 - 2013 - 96,425
Senior subordinated notes 7.0% 2013 - 175,000
- ------------------------------------------------------------------------------------------------------------------------------------
Total Notes 2,485,000 3,456,425
- ------------------------------------------------------------------------------------------------------------------------------------
Gas Facilities Revenue Bonds Variable 2020 125,000 125,000
5.50% - 6.95% 2020 - 2026 515,500 523,500
- ------------------------------------------------------------------------------------------------------------------------------------
Total Gas Facilities Revenue Bonds 640,500 648,500
- ------------------------------------------------------------------------------------------------------------------------------------
Promissory Notes to LIPA
Pollution control revenue bonds 5.15% 2016 108,020 108,022
Electric facilities revenue bonds 5.30% 2023 - 2025 47,400 47,400
- ------------------------------------------------------------------------------------------------------------------------------------
Total Promissory Notes to LIPA 155,420 155,422
- ------------------------------------------------------------------------------------------------------------------------------------
MEDS Equity Units 8.75% 2005 460,000 460,000
Industrial Development Bonds 5.25% 2027 128,275 128,275
First Mortgage Bonds 6.08% - 8.80% 2008 - 2028 95,000 153,186
Authority Financing Notes Variable 2027 - 2028 66,005 66,005
Other Subsidiary Debt - 145,128
Ravenswood Master Lease & Capital Leases 2005 - 2022 424,083 425,262
- ------------------------------------------------------------------------------------------------------------------------------------
Subtotal 4,454,283 5,638,203
Unamortized interest rate hedge and debt discount (55,185) (69,243)
Derivative impact on debt 35,734 43,459
Less: current maturities 16,103 1,471
- ------------------------------------------------------------------------------------------------------------------------------------
Total Long-Term Debt 4,418,729 5,610,948
- ------------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 8,333,139 $ 9,365,172
- ------------------------------------------------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
98
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, 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 2.6 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 electric power,
electric transmission and distribution services, billing and other customer
services for approximately 1.1 million electric customers of the Long Island
Power Authority ("LIPA").
Our other subsidiaries are involved in gas production; gas storage; liquefied
natural gas storage; wholesale and retail electric marketing; appliance service;
a minimum amount of fiber optic services; and engineering and consulting
services. We also invest in, and participate in the development of natural gas
pipelines; electric generation, and other energy-related projects. (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
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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 intercompany transactions have been
eliminated. Certain reclassifications were made to conform prior period
financial statements to current period financial statement presentation. For
December 31, 2004, 2003 and 2002 we have reclassified the operations of
KeySpan's mechanical contracting subsidiaries, which are part of the Energy
Services segment, as discontinued operations on the Consolidated Statement of
Income, Consolidated Balance Sheet and Consolidated Statement of Cash Flows.
(See Note 11 "Energy Services - Discontinued Operations" for additional details
regarding these operations.) In addition, for December 31, 2003 we reclassified
the minimum pension liability for Boston Gas Company from accumulated other
comprehensive income to regulatory assets. (See Note 4 "Postretirement Benefits"
for additional information.)
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 ("MADTE"). 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.
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In separate merger related orders issued by the MADTE, 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, 2004 and
December 31, 2003.
- ---------------------------------------------------------------------------------------------------------
December 31,
(In Thousands of Dollars) 2004 2003
- ---------------------------------------------------------------------------------------------------------
Regulatory Assets
Regulatory tax asset $ 53,149 $ 60,700
Property taxes 45,235 51,390
Environmental costs 272,545 296,888
Postretirement benefits 110,603 106,682
Costs associated with the KeySpan/LILCO transaction 39,091 50,585
Derivative financial instruments 27,293 6,909
Other 7,498 5,229
- ---------------------------------------------------------------------------------------------------------
Total Regulatory Assets $ 555,414 $ 578,383
Miscellaneous Regulatory Liabilities (73,963) (104,034)
- ---------------------------------------------------------------------------------------------------------
Net Regulatory Assets 481,451 474,349
Removal Costs Recovered (496,482) (450,034)
- ---------------------------------------------------------------------------------------------------------
$ (15,031) $ 24,315
- ---------------------------------------------------------------------------------------------------------
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 $37.7 million and $53.4 million at December 31, 2004 and December
31, 2003, 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.
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
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and liabilities could result. If we were unable to continue to apply the
provisions of SFAS 71 for any of our rate regulated subsidiaries, we would apply
the provisions of SFAS 101, "Regulated Enterprises - Accounting for the
Discontinuation of Application of FASB Statement 71." We estimate that the
write-off of all net regulatory assets at December 31, 2004, before
consideration of removal costs recovered, could result in a charge to net income
of $313 million or $1.95 per share, which would be classified as an
extraordinary item. In 2003, KeySpan implemented SFAS 143 "Accounting for Asset
Retirement Obligations" and reclassified the cost of removal reserve from
accumulated depreciation to regulatory liability. In management's opinion, the
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.
As a result, fluctuations from normal weather may have a significant positive or
negative effect on the results of these operations. To mitigate the effect of
fluctuations from normal weather on our financial position and cash flows, we
may enter into weather related derivative instruments from time to time. (See
Note 8 "Hedging, Derivative Financial Instruments and Fair Values" for
additional information on these derivatives.)
Electric Services: Electric revenues are primarily derived from: (i) billings to
LIPA for management of LIPA's transmission and distribution ("T&D") system,
electric generation, and procurement of fuel, and (ii): subsidiaries that own
lease and operate the 2,200 megawatt ("MW") Ravenswood electric generation
facility ("Ravenswood Facility") and the recently completed 250 MW combined
cycle generating facility located at the Ravenswood facility site ("Ravenswood
Expansion").
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LIPA Agreements:
KeySpan manages the day-to-day operations, maintenance and capital improvements
of the T&D system under a Management Service Agreement ("MSA"). KeySpan's
billings to LIPA are based on certain agreed upon terms. In addition, 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 KeySpan 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, KeySpan 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.
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 its
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 KeySpan
earns 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 $5 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.
The Electric Services segment also conducts retail marketing of electricity to
commercial customers. Energy sales made by our electric marketing subsidiary are
recorded upon delivery of the related commodity.
LIPA is in the process of performing a long-term strategic review initiative
regarding its future direction which may impact the above mentioned service
agreements. (See Note 7 "Contractual Obligations, Financial Guarantees and
Contingencies" for further information regarding LIPA's strategic review.)
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Ravenswood Facilities:
In addition, electric revenues are derived from our investment in the 2,200
megawatt ("MW") Ravenswood electric generation facility ("Ravenswood Facility"),
(which KeySpan acquired in June 1999). KeySpan has an arrangement with a
variable interest entity through which we lease a portion of the Ravenswood
Facility. Further, in May 2004 KeySpan completed construction of a 250 MW
combined cycle generating facility located at the Ravenswood facility site
("Ravenswood Expansion"). To finance the Ravenswood Expansion, KeySpan entered
into a leveraged lease financing arrangement. Collectively the Ravenswood
Facility and Ravenswood Expansion will be referred to as the Ravenswood
Projects. (See Note 7 "Contractual Obligations, Financial Guarantees and
Contingencies" for a description of the financing arrangements associated with
the Ravenswood Projects.) We realize revenues from our investment in the
Ravenswood Projects 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. 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.
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.
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KeySpan has recently sold its mechanical contracting companies, the operations
of which have been reflected in discontinued operations on the Consolidated
Statement of Income and on the Consolidated Balance Sheet and Statement of Cash
Flows. (See Note 11 "Energy Services - Discontinued Operations" for additional
details on the mechanical contracting companies.)
Energy service and maintenance revenues associated with small commercial and
residential appliances are recognized as earned or over the life of the service
contract, as appropriate. 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
$28.5 million and $23.8 million as of December 31, 2004, and December 31, 2003,
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. During
2004 KeySpan disposed of its interest in The Houston Exploration Company
("Houston Exploration"), an independent natural gas and oil exploration company.
KeySpan continues to maintain, on a significantly smaller scale, gas exploration
and production activities. (See Note 2 "Business Segments" for a discussion on
the disposition of Houston Exploration and KeySpan's remaining gas exploration
activities.)
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 year ended December 31, 2004 ranged
from 1.54% to 6.47%. Capitalized interest for 2004, 2003 and 2002 was $7.4
million, $13.5 million and $19.7 million, respectively.
Depreciation is provided on a straight-line basis in amounts equivalent to
composite rates on average depreciable property. The cost of property retired 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, 2004 and 2003,
KeySpan had costs recovered in excess of costs incurred totaling $496 million
and $450 million, respectively. These amounts are reflected as a regulatory
liability.
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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,
2004 2003 2002
- -------------------------------------------------------------------------------
Electric 3.87% 3.81% 3.88%
Gas 3.55% 3.37% 3.44%
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
We also had $398.6 million of other property at December 31, 2004, consisting of
assets held primarily by our Corporate Service subsidiary of $293.7 million and
$89.9 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.
KeySpan capitalizes costs incurred in connection with its projects to develop
and build new energy facilities after a project has been determined to be
probable.
F. Gas Exploration and Production Property - Depletion
As noted previously and discussed in more detail in Note 2 "Business Segments",
during 2004, KeySpan disposed of its ownership interest in Houston Exploration.
KeySpan continues to maintain gas exploration and production activities through
its two wholly-owned subsidiaries - KeySpan Exploration and Production, LLC
("KeySpan Exploration"), which is engaged in a joint venture with Houston
Exploration, and Seneca-Upshur Petroleum, Inc. ("Seneca-Upshur"). At December
31, 2004, these subsidiaries had net exploration and production property in the
amount of $89.6 million. 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 plus asset
retirement obligations 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 is made as to the existence of proved
reserves. Properties are depleted and charged to operations using the unit of
production method using proved reserve quantities.
To the extent that such capitalized costs (net of accumulated depletion) less
deferred taxes exceed the present value (using a 10% discount rate) of estimated
future net cash flows from proved natural gas and oil reserves and the lower of
cost or fair value of unproved properties, 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.
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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 ceiling
test calculations.
As a result of the disposition of Houston Exploration, during most of 2004
KeySpan calculated the ceiling test on KeySpan Exploration and Production's and
Seneca-Uphsur's assets independently of Houston Exploration's assets. Based on a
report furnished by an independent reservoir engineer during the second quarter
of 2004, it was determined that the remaining proved undeveloped oil reserves
held in the joint venture required a substantial investment in order to develop.
Therefore, KeySpan and Houston Exploration elected not to develop these oil
reserves. As a result, in the second quarter of 2004, we recorded a $48.2
million non-cash impairment charge to write down our wholly-owned gas
exploration and production subsidiaries' assets. This charge was recorded in
depreciation, depletion and amortization on the Consolidated Statement of
Income.
As of December 31, 2004, we estimated, using an average wellhead price adjusted
for derivative instruments of $6.45 per MCF, that our capitalized costs did not
exceed the ceiling test limitation. As of December 31, 2003 and December 31,
2002, we estimated, using a wellhead prices of $5.79 and $4.35 per MCF,
respectively, that our capitalized costs did not exceed the ceiling test
limitation for those periods.
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 low,
there are significant downward revisions in our estimated proved reserves or we
have unsuccessful drilling results.
Houston Exploration capitalized 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, 2004, 2003 and 2002,
capitalized interest was $3.4 million, $7.3 million and $8.0 million,
respectively.
G. Goodwill and Other Intangible Assets
The balance of goodwill and other intangible assets was $1.7 billion at December
31, 2004 and $1.8 billion at December 31, 2003, 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.
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The table below summarizes the goodwill and other intangible assets balance for
each segment at December 31, 2004 and 2003:
- ------------------------------------------------------------------------------
(In Thousands of Dollars) December 31,
- ------------------------------------------------------------------------------
Operating Segment 2004 2003
Gas Distribution $1,436,917 $1,436,917
Energy Services 65,782 172,874
Energy Investments and other 174,902 199,921
- ------------------------------------------------------------------------------
$1,677,601 $1,809,712
- ------------------------------------------------------------------------------
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 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 is recorded as an
operating expense. During 2002, KeySpan conducted an impairment analysis for all
its reporting units and determined that no consolidated impairment existed.
In 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 this valuation, management determined that the fair value of the assets
adequately exceeded their carrying value and no impairment charge was necessary.
The Energy Services segment has experienced significantly lower operating
profits and cash flows than originally projected. As previously reported,
management had reviewed the operating performance of this segment. At a meeting
held on November 2, 2004, KeySpan's Board of Directors authorized management to
begin the process of disposing of a significant portion of its ownership
interests in certain companies within the Energy Services segment - specifically
those companies engaged in mechanical contracting activities. In January and
February of 2005, KeySpan sold these mechanical contracting investments.
In anticipation of these sales and in connection with the preparation of the
third quarter and fourth quarter financial statements, KeySpan conducted an
evaluation of the carrying value of these investments, including recorded
goodwill. Further, we evaluated the carrying value of goodwill for the entire
Energy Services segment.
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As a result of this evaluation, KeySpan recorded a non-cash goodwill impairment
charge of $108.3 million ($80.3 million after tax, or $0.50 per share) in 2004.
This charge was recorded as follows: (i) $14.4 million as an operating expense
on the Consolidated Statement of Income reflecting the write-down of goodwill on
Energy Services segment's continuing operations; and (ii) $93.9 million as
discontinued operations reflecting the impairment on the mechanical contracting
companies. (See Note 11 "Energy Services - Discontinued Operations" for further
details on the discontinued companies.)
In addition to the goodwill evaluation conducted for the Energy Services
segment, KeySpan conducted evaluations of the goodwill recorded in the Gas
Distribution and Energy Investments segments. Based on KeySpan's evaluation of
the fair value of the Gas Distribution unit, KeySpan concluded that the fair
value of the Gas Distribution unit exceeded the carrying value and no impairment
charge was necessary.
KeySpan has entered into an agreement to sell its 50% interest in Premier
Transmission Limited ("PTL"), a gas pipeline from southwest Scotland to Northern
Ireland, before the end of the second quarter of 2005. In the fourth quarter of
2004 KeySpan recorded a pre-tax non-cash impairment charge of $26.5 million -
$18.8 million after-tax or $0.12 per share, reflecting the difference between
the anticipated cash proceeds from the sale of PTL compared to its carrying
value. The impairment charge was recorded as a reduction to goodwill. This
investment is accounted for under the equity method of accounting in the Energy
Investments segment.
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
109
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.
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.
110
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 current
investments are publicly traded.
J. Income and Excise Tax
Upon implementation of SFAS 109, "Accounting for Income Taxes", certain of our
regulated subsidiaries recorded a regulatory asset and a net deferred tax
liability for the cumulative effect of providing deferred income taxes on
certain differences between the financial statement carrying amounts of assets
and liabilities, and their respective tax bases. This regulatory asset continues
to be amortized over the lives of the individual assets and liabilities to which
it relates. Additionally, investment tax credits which were available prior to
the Tax Reform Act of 1986, were deferred and generally amortized as a reduction
of income tax over the estimated lives of the related property.
We report our collections and payments of excise taxes on a gross basis. Gas
distribution revenues include the collection of excise taxes, while operating
taxes include the related expense. For the years ended December 31, 2004, 2003
and 2002, excise taxes collected and paid were $73.3 million, $90.5 million,
$83.1 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, 2004 and 2003, 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 anti-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.
111
At December 31, 2004 all options outstanding to purchase KeySpan common stock
were used in the calculation of diluted EPS. In 2003 and 2002 we had 85,676
shares of convertible preferred stock outstanding that could have been converted
into 221,153 shares of common stock. These shares were redeemed in 2004.
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) 2004 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------------
Earnings for common stock $ 458,053 $ 380,886 $ 371,935
Houston Exploration dilution - (269) (471)
Preferred stock dividend - 514 531
- -----------------------------------------------------------------------------------------------------------------------------------
Earnings for common stock - adjusted $ 458,053 $ 381,131 $ 371,995
- -----------------------------------------------------------------------------------------------------------------------------------
Weighted average shares outstanding (000) 160,294 158,256 141,263
Add dilutive securities:
Options 983 755 809
Convertible preferred stock - 221 228
- -----------------------------------------------------------------------------------------------------------------------------------
Total weighted average shares outstanding - assuming dilution 161,277 159,232 142,300
- -----------------------------------------------------------------------------------------------------------------------------------
Basic earnings per share $ 2.86 $ 2.41 $ 2.63
- -----------------------------------------------------------------------------------------------------------------------------------
Diluted earnings per share $ 2.84 $ 2.39 $ 2.61
- -----------------------------------------------------------------------------------------------------------------------------------
N. Stock Options and Other Stock Based Compensation
Stock options are issued 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 five to ten
years. Up to approximately 21 million shares have been authorized for the
issuance of options and approximately 5.2 million of these shares were remaining
at December 31, 2004. Moreover, under a separate plan, Houston Exploration had
issued and outstanding approximately 2.5 million stock options to key Houston
Exploration employees. KeySpan and Houston Exploration 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 continues to apply APB Opinion 25, "Accounting for Stock Issued to
Employees," and related Interpretations in accounting for grants awarded prior
to January 1, 2003. Prior to the disposition of Houston Exploration, Houston
Exploration also applied APB Opinion 25, 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
112
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:
- -------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars, Except Per Share Amounts) 2004 2003 2002
- -------------------------------------------------------------------------------------------------------------------------------
Earnings available for common stock:
As reported $ 458,053 $ 380,886 $ 371,935
Add: recorded stock-based compensation expense, net of tax 9,109 3,650 221
Deduct: total stock-based compensation expense, net of tax (12,356) (9,358) (7,547)
- -------------------------------------------------------------------------------------------------------------------------------
Pro-forma earnings $ 454,806 $ 375,178 $ 364,609
- -------------------------------------------------------------------------------------------------------------------------------
Earnings per share:
Basic - as reported $ 2.86 $ 2.41 $ 2.63
Basic - pro-forma $ 2.84 $ 2.37 $ 2.58
Diluted - as reported $ 2.84 $ 2.39 $ 2.61
Diluted - pro-forma $ 2.82 $ 2.36 $ 2.56
- -------------------------------------------------------------------------------------------------------------------------------
All grants are estimated on the date of the grant using the Black-Scholes
option-pricing model. The following table presents the weighted average fair
value, exercise price and assumptions used for the periods indicated:
- ------------------------------------------------------------------------------------------------------------
Year Ended December 31,
2004 2003 2002
- ------------------------------------------------------------------------------------------------------------
Fair value of grants issued $ 5.47 $ 4.26 $ 3.42
Dividend yield 4.74% 5.49% 5.36%
Expected volatility 23.48% 24.26% 22.47%
Risk free rate 3.22% 3.16% 4.94%
Expected lives 6.5 years 6 years 10 years
Exercise price $ 37.54 $ 32.40 $ 32.66
- ------------------------------------------------------------------------------------------------------------
A summary of the status of our fixed stock option plans and changes is presented
below for the periods indicated:
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
2004 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------------
Weighted Weighted Weighted
Exercise Exercise Exercise
Fixed Options Shares Price Shares Price Shares Price
- ------------------------------------------------------------------------------------------------------------------------------------
Outstanding at beginning of period 10,320,743 $ 31.39 9,524,900 $ 30.74 7,796,162 $ 29.67
Granted during the year 1,602,850 $ 37.54 1,650,450 $ 32.40 2,796,310 $ 32.66
Exercised (1,150,464) $ 28.05 (664,902) $ 23.64 (506,794) $ 24.42
Forfeited (232,183) $ 35.18 (189,705) $ 34.63 (560,778) $ 30.99
- ------------------------------------------------------------------------------------------------------------------------------------
Outstanding at end of period 10,540,946 $ 32.61 10,320,743 $ 31.39 9,524,900 $ 30.74
- ------------------------------------------------------------------------------------------------------------------------------------
Exercisable at end of period 5,523,259 $ 30.39 5,365,545 $ 28.76 4,105,999 $ 27.69
- ------------------------------------------------------------------------------------------------------------------------------------
113
- ------------------------------------------------------------------------------------------------------------------------------------
Options Options
Remaining Outstanding at Weighted Average Range of Exercisable at Weighted Average Range of
Contractual Life December 31, 2004 Exercise Price Exercise Price December 31, 2004 Exercise Price Exercise Price
- ------------------------------------------------------------------------------------------------------------------------------------
1 years 1,800 $ 27.00 $ 27.00 1,800 $ 27.00 $ 27.00
2 years 167,086 $ 30.41 $ 20.57 - 30.50 167,086 $ 30.41 $ 20.57 - 30.50
3 years 236,410 $ 32.54 $ 19.15 - 32.63 236,410 $ 32.54 $ 19.15 - 32.63
4 years 1,006,679 $ 27.92 $ 24.73 - 29.38 1,006,679 $ 27.92 $ 24.73 - 29.38
5 years 541,755 $ 26.98 $ 21.99 - 27.06 541,754 $ 26.98 $ 21.99 - 27.06
6 years 1,272,983 $ 22.72 $ 22.50 - 32.76 1,272,983 $ 22.72 $ 22.50 - 32.76
7 years 1,917,889 $ 39.50 $ 39.50 1,229,789 $ 39.50 $ 39.50
8 years 2,340,508 $ 32.66 $ 32.66 834,509 $ 32.66 $ 32.66
9 years 1,492,792 $ 32.40 $ 32.40 232,249 $ 32.40 $ 32.40
10 years 1,563,044 $ 37.54 $ 37.54 - $ 37.54 $ 37.54
- ------------------------------------------------------------------------------------------------------------------------------------
10,540,946 5,523,259
- ------------------------------------------------------------------------------------------------------------------------------------
Since 2003, KeySpan provides long-term incentive compensation for officers
consisting of 50% stock options and 50% performance shares. Performance shares
are awarded based upon the attainment of overall corporate performance goals and
better aligns incentive compensation with overall corporate performance.
O. Recent Accounting Pronouncements
In May 2004, the Financial Accounting Standards Board ("FASB") issued FASB Staff
Position ("FSP") 106-2 "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003." This
guidance superseded FSP 106-1 issued in January 2004 and clarifies the
accounting and disclosure requirements for employers with postretirement benefit
plans that have been or will be affected by the passage of the Medicare
Prescription Drug Improvement and Modernization Act of 2003 ("the Act"). The Act
introduced two new features to Medicare that an employer needs to consider in
measuring its obligation and net periodic postretirement benefit costs. The
effective date for the new requirements was the first interim or annual period
beginning after June 15, 2004.
KeySpan's retiree health benefit plan currently includes a prescription drug
benefit that is provided to retired employees. KeySpan implemented the
requirements of FSP 106-2 in September 2004 and determined that the savings
associated with the Act reduced KeySpan's retiree health care costs by
approximately $10 million in 2004. However, KEDLI and Boston Gas Company are
subject to certain deferral accounting requirements mandated by the New York
State Public Service Commission ("NYPSC") and the Massachusetts Department of
Telecommunications and Energy ("MADTE"), respectively for pension costs and
other postretirement benefit costs. Further, in accordance with our service
agreements with LIPA, variations between pension costs and other postretirement
benefit costs incurred by KeySpan compared to those costs recovered through
rates charged to LIPA are deferred subject to recovery from or refund to LIPA.
As a result of these various requirements, approximately $7 million of savings
attributable to the implementation of FSP 106-2 and the Act was deferred and
used to offset increases in overall pension and postretirement benefit costs,
with the remaining approximately $3 million recorded as a reduction to 2004
postretirement expense. The implementation of FSP 106-2 and the Act had no
immediate impact on KeySpan's cash flow.
114
In January 2005, the Department of Health and Human Services/Centers for
Medicare and Medicaid Services (CMS) released final regulations with regard to
the implementation of the major provisions of the Medicare Act. We are currently
evaluating the final regulations, and at this time we cannot determine the
impact, if any, these regulations may have on our results of operations,
financial position or cash flows.
In December 2004 the FASB issued SFAS 123 (revised 2004) "Share-Based Payment."
This Statement focuses primarily on accounting for transactions in which an
entity obtains employee services in share-based payment transactions. This
Statement revises certain provisions of SFAS 123 "Accounting for Stock-Based
Compensation" and supersedes APB Opinion 25 "Accounting for Stock Issued to
Employees." The fair-value-based method in this Statement is similar to the
fair-value-based method in Statement 123 in most respects. However, the
following are key differences between the two: Entities are required to measure
liabilities incurred to employees in share based payment transactions at fair
value as compared to using the intrinsic method allowed under Statement 123.
Entities are required to estimate the number of instruments for which the
requisite service is expected to be rendered, as compared to accounting for
forfeitures as they occur under Statement 123. Incremental compensation cost for
a modification of the terms or conditions of an award are also measured
differently under this Statement compared to Statement 123. This Statement also
clarifies and expands Statement 123's guidance in several areas. The effective
date of this Statement is the beginning of the first interim or annual reporting
period that begins after June 15, 2005. As noted earlier, KeySpan adopted the
prospective method of transition for stock options 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 for grants awarded after January 1,
2003. KeySpan is currently reviewing the requirements of this Statement, and
believes that implementation of this Statement will not have a material impact
on its results of operations or financial position and no effect on its cash
flows.
P. Impact of Cumulative Effect of Change in Accounting Principles
As noted previously, 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 Financial Accounting
Standards Board ("FASB") Interpretation No. 46 ("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, in 2003 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.)
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 2003
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.)
115
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) 2004 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------
Earnings for common stock N/A $ 380,886 $ 371,935
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
Less: SFAS 143 Accretion expense, net of taxes - (1,135)
Less:FIN 46 Depreciation expense, net of taxes (9,538) (8,024)
Add: SFAS 143 Costs of removal expense, net of taxes - 471
- ---------------------------------------------------------------------------------------------------------------------------------
Pro-forma earnings $ 408,799 $ 363,247
- ---------------------------------------------------------------------------------------------------------------------------------
Earnings per share before cumulative change in accounting principle:
Basic - as reported $ 2.64 $ 2.63
Basic - pro-forma $ 2.58 $ 2.57
Diluted - as reported $ 2.62 $ 2.61
Diluted - pro-forma $ 2.57 $ 2.55
- ---------------------------------------------------------------------------------------------------------------------------------
Earnings per share for common stock:
Basic - as reported $ 2.41 $ 2.63
Basic - pro-forma $ 2.58 $ 2.57
Diluted - as reported $ 2.39 $ 2.61
Diluted - pro-forma $ 2.57 $ 2.55
- ---------------------------------------------------------------------------------------------------------------------------------
Q. Accumulated Other Comprehensive Income
As required by SFAS 130, "Reporting Comprehensive Income," the components of
accumulated other comprehensive income are as follows:
- ----------------------------------------------------------------------------------------------------
December 31,
(In Thousands of Dollars) 2004 2003
- ----------------------------------------------------------------------------------------------------
Foreign currency translation adjustments $ 4,987 $ 26,523
Unrealized (losses) on marketable securities (419) (7,530)
Premium on derivative instrument - (3,437)
Accrued unfunded pension obligation (59,760) (51,942)
Unrealized (losses) on derivative financial instruments 856 (23,546)
- ----------------------------------------------------------------------------------------------------
Accumulated other comprehensive income $ (54,336) $ (59,932)
- ----------------------------------------------------------------------------------------------------
116
Note 2. Business Segments
We have four reportable segments: Gas Distribution, Electric Services, Energy
Services and Energy Investments.
The Gas Distribution segment consists of our six gas distribution subsidiaries.
KEDNY provides gas distribution services to customers in the New York City
Boroughs of Brooklyn, Staten Island and a portion of the Borough of Queens.
KEDLI provides gas distribution services to customers in the Long Island
counties of Nassau and Suffolk and the Rockaway Peninsula of Queens County. The
remaining gas distribution subsidiaries, collectively doing business as KEDNE,
provide gas distribution service to customers in Massachusetts and New
Hampshire.
The Electric Services segment consists of subsidiaries that: operate the
electric transmission and distribution system owned by LIPA; own and provide
capacity to and produce energy for LIPA from our generating facilities located
on Long Island; and manage fuel supplies for LIPA to fuel our Long Island
generating facilities. These services are provided in accordance with long-term
service contracts having remaining terms that range from four to nine years and
power purchase agreements having remaining terms that range from nine to 23
years. The Electric Services segment also includes subsidiaries that own or
lease and operate the 2,200 megawatt Ravenswood electric generation facility
("Ravenswood Facility") located in Queens, New York, as well as the recently
completed 250 MW combined-cycle electric generating unit located at the
Ravenswood site ("Ravenswood Expansion"). Collectively the Ravenswood Facility
and Ravenswood Expansion are referred to as the "Ravenswood Projects". All of
the energy, capacity and ancillary services related to the Ravenswood Projects
are sold to the NYISO energy markets. To finance the purchase and/or
construction of the Ravenswood Projects, KeySpan entered into leasing
arrangement for each facility. The Electric Services segment also conducts
retail marketing of electricity to commercial customers. (See Note 7
"Contractual Obligations, Financial Guarantees and Contingencies" for further
details on the leasing arrangements.)
The Energy Services segment includes companies that provide energy-related and
fiber optic services to customers located primarily within the Northeastern
United States, with concentrations in the New York City and Boston metropolitan
areas 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 operation and
maintenance, design, engineering and consulting services to commercial and
industrial customers. For December 31, 2004, 2003 and 2002 we have reclassified
the operations of Energy Services' mechanical contracting subsidiaries as
discontinued operations on the Consolidated Statement of Income, Consolidated
Balance Sheet and Consolidated Statement of Cash Flows. In 2004, KeySpan
recorded a non-cash goodwill impairment charge of $108.3 million ($80.3 million
after tax, or $0.50 per share) associated with its mechanical contracting
operations and certain remaining operations. In addition, an impairment charge
of $100.3 million ($72.1 million after-tax or $.45 per share) was also recorded
to reduce the carrying value of the remaining assets of the mechanical
contracting companies. (See Note 11 "Energy Services - Discontinued Operations"
for additional details regarding these charges.)
117
The Energy Investments segment consists of our gas exploration and production
investments, as well as certain other domestic and international energy-related
investments. In June 2004, KeySpan exchanged 10.8 million shares of common stock
of The Houston Exploration Company ("Houston Exploration"), an independent
natural gas and oil exploration company, for 100% of the stock of Seneca Upshur
Petroleum, Inc. ("Seneca-Upshur"), previously a wholly owned subsidiary of
Houston Exploration. This transaction reduced our interest in Houston
Exploration from 55% to approximately 23.5%. As part of this transaction,
Houston Exploration retired 4.6 million of its common shares and issued 6.8
million new shares in a public offering. Based on Houston Exploration's
announced offering price of $48.00 per share, Seneca-Upshur's shares were valued
at the equivalent of $449 million, or $41.57 per share. Seneca-Upshur's assets
consisted of West Virginia gas producing properties valued at $60 million, and
$389 million in cash. 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, this transaction resulted in a gain
to KeySpan of $150.1 million which was reflected in other income and deductions
on the Consolidated Statement of Income. Effective June 1, 2004, Houston
Exploration's earnings and our ownership interest in Houston Exploration were
accounted for on the equity basis of accounting. The deconsolidation of Houston
Exploration required the recognition of certain deferred taxes on our remaining
investment resulting in a net deferred tax expense of $44.1 million. Therefore,
the net gain on the share exchange less the deferred tax provision was $106
million, or $0.66 per share.
In November 2004, KeySpan sold its remaining 23.5% interest in Houston
Exploration (6.6 million shares) and received cash proceeds of approximately
$369 million. KeySpan recorded a pre-tax gain of $179.6 million which is
reflected in other income and (deductions) on the Consolidated Statement of
Income. The after-tax gain was $116.8 million or $0.73 per share.
Houston Exploration's revenues, which are reflected in KeySpan's Consolidated
Statement of Income, were $266.4 million, $494.7 million, and $345.4 million in
fiscal years 2004, 2003 and 2002, respectively. Houston Exploration's operating
income, including KeySpan's share of equity earnings, were $138.5 million,
$199.1 million and $109.3 million in fiscal years 2004, 2003 and 2002,
respectively.
Our gas exploration and production activities now include our wholly-owned
subsidiaries Seneca-Upshur and KeySpan Exploration and Production, LLC ("KeySpan
Exploration and Production"), which is engaged in a joint venture with Houston
Exploration. It should be noted that in the second quarter of 2004, KeySpan
recorded a $48.2 million non-cash impairment charge to recognize the reduced
valuation of proved reserves. (See Note 1 "Summary of Significant Accounting
Policies" Item F "Gas Exploration and Production Property - Depletion" for
further information on this charge.)
Asset transactions regarding our investment in Houston Exploration were also
recorded in 2003. 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
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.
118
For most of 2004, subsidiaries in this segment also held an ownership interest
in certain midstream natural gas assets in Western Canada through KeySpan
Canada. These assets included 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. At the beginning of 2004, KeySpan
held a 60.9% ownership interest in KeySpan Canada. In April 2004, KeySpan and
KeySpan Facilities Income Fund (the "Fund"), an open-ended income fund trust
which previously owned the other 39.1% interest in KeySpan Canada, consummated a
transaction whereby the Fund sold 15.617 million units of the Fund at a price of
CDN$12.60 per unit for gross total proceeds of approximately CDN$196.8 million.
The proceeds of the offering were used by the Fund to acquire an additional
35.91% interest in KeySpan Canada from KeySpan. We received net proceeds of
approximately CDN$186.3 million (or approximately US$135 million), after
commissions and expenses. The Fund's ownership in KeySpan Canada increased from
39.1% to 75%, and KeySpan's ownership of KeySpan Canada decreased from 60.9% to
25%. KeySpan recorded a gain of $22.8 million ($10.1 million after-tax, or $0.06
per share) on this transaction. Effective April 1, 2004, KeySpan Canada's
earnings and our ownership interest in KeySpan Canada had been accounted for on
the equity basis of accounting.
In July 2004, the Fund issued an additional 10.7 million units, the proceeds of
which were used to fund the acquisition of the midstream assets of Chevron
Canada Midstream Inc. This transaction had the effect of further diluting
KeySpan's ownership of KeySpan Canada to 17.4%. KeySpan continued to account for
its investment in KeySpan Canada on the equity basis of accounting since it
still exercised significant influence over this entity.
In December 2004, KeySpan sold its remaining 17.4% interest in KeySpan Canada to
the Fund and received net proceeds of approximately $119 million and recorded a
pre-tax gain of approximately $35.8 million, which is reflected in other income
and (deductions) on the Consolidated Statement of Income. The after-tax gain was
approximately $24.7 million, or $0.15 per share.
KeySpan Canada's revenues, which are reflected in KeySpan's Consolidated
Statement of Income, were $25.2 million, $90.3 million, and $74.9 million in
fiscal years 2004, 2003 and 2002, respectively. KeySpan Canada's operating
income, including KeySpan's share of equity earnings, were $16.5 million, $28.2
million and $24.5 million in fiscal years 2004, 2003 and 2002, respectively.
Asset transactions regarding our investment in KeySpan Canada were also recorded
in 2003. In 2003, we sold a portion of our interest in KeySpan Canada through
the Fund. The Fund acquired a 39.1% ownership interest in KeySpan Canada through
an indirect subsidiary, and then issued 17 million trust units to the public
through an initial public offering. Each trust unit represented a beneficial
interest in the Fund and was registered on the Toronto Stock Exchange under the
symbol KEY.UN. Additionally, we sold our 20% interest in Taylor NGL LP that owns
119
and operates two extraction plants 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.
This segment is also engaged in pipeline development activities. KeySpan and
Duke Energy Corporation each own a 50% interest in Islander East Pipeline
Company, LLC ("Islander East"). Islander East was created to pursue the
authorization and construction of an interstate pipeline from Connecticut,
across Long Island Sound, to a terminus near Shoreham, Long Island. 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. Further, in August 2004, KeySpan
acquired a 21% interest in the Millennium Pipeline project which will transport
up to 500,000 DTH of natural gas a day from Corning to Ramapo, New York, where
it will connect to an existing pipeline.
Additionally, subsidiaries in this segment 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 the KeySpan LNG facility
in Providence, Rhode Island, a 600,000 barrel liquefied natural gas storage and
receiving facility. Further, this segment has a 50% interest in the Premier
Transmission Pipeline ("PTL") in Northern Ireland. On February 25, 2005, KeySpan
entered into a Share Sale and Purchase Agreement with BG Energy Holdings Limited
and Premier Transmission Financing Public Limited Company ("PTFPL"), pursuant to
which all of the outstanding shares of PTL are to be purchased by PTFPL. It is
expected that the sale of our 50% interest in PTL will result in proceeds of
approximately $42.5 million and that the closing of this transaction will occur
before the end of the second quarter of 2005. In the fourth quarter of 2004,
KeySpan recorded a pre-tax non-cash impairment charge of $26.5 million - $18.8
million after-tax or $0.12 per share, reflecting the difference between the
anticipated cash proceeds from the sale of PTL compared to its carrying value.
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. The after-tax gain was
$16.0 million, or $0.10 per share.
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. As noted earlier, the mechanical
contracting subsidiaries, included in Energy Services, are reported as
discontinued operations in 2004, 2003 and 2002. Further, due to the July 2002
sale of Midland Enterprises LLC, an inland marine barge business, this
subsidiary is reported as discontinued operations for 2002. (See Note 9,
"Discontinued Operations" for more information on the sale of Midland). Further,
to better align the subsidiaries within our segments, we reclassified the
operating results of our electric marketing subsidiary from the Energy Services
segment to the Electric Services segment in the first quarter of 2004. As a
result we reclassified the financial results for all periods of 2003 and 2002.
120
The revised reportable segment information is as follows:
- ----------------------------------------------------------------------------------------------------------------------------------
Gas Electric Energy Gas Exploration Other Elimi- Consoli-
(In Thousands of Dollars) Distribution Services Services and Production Investments nations dated
- ----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2004
Unaffiliated revenue 4,407,292 1,738,660 182,406 279,999 42,109 - 6,650,466
Intersegment revenue - - 11,515 - 4,879 (16,394) -
Depreciation, depletion and
amortization 276,487 88,252 7,478 156,981 7,306 15,256 551,760
Sales of property - 2,000 - - 5,021 - 7,021
Income from equity investments - - - 20,757 25,779 - 46,536
Operating income 579,563 289,781 (48,302) 94,455 10,238 9,535 935,270
Interest income 2,215 9,926 40 3,504 2,989 (9,202) 9,472
Interest charges 176,799 72,945 19,399 3,487 3,882 54,739 331,251
Total assets 8,908,786 2,144,275 246,609 3,379 697,924 1,363,157 13,364,130
Equity method investments - - - - 107,059 - 107,059
Construction expenditures 414,522 150,320 13,693 146,543 13,682 11,569 750,329
- ----------------------------------------------------------------------------------------------------------------------------------
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 $1.7 billion for the year
ended December 31, 2004 represents approximately 25% of our consolidated
revenues during that period.
- ------------------------------------------------------------------------------------------------------------------------------------
Gas Electric Energy Gas Exploration Other Elimi- Consoli-
(In Thousands of Dollars) Distribution Services Services and Production Investments nations dated
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2003
Unaffiliated revenue 4,161,272 1,605,973 158,908 501,255 108,116 - 6,535,524
Intersegment revenue - 101 7,467 - 5,008 (12,576) -
Depreciation, depletion and
amortization 259,934 67,161 7,146 204,102 19,046 14,280 571,669
Sales of property 15,123 - - - - - 15,123
Income from equity investments - - - - 19,106 108 19,214
Operating income 574,254 269,874 (32,963) 197,209 41,345 (2,090) 1,047,629
Interest income 1,194 4,628 1,070 - 1,002 (2,235) 5,659
Interest charges 203,733 44,158 15,794 8,504 7,541 27,964 307,694
Total assets 8,457,469 2,511,125 407,485 1,530,875 915,383 817,845 14,640,182
Equity method investments - - - - 97,018 - 97,018
Construction expenditures 419,549 256,498 6,982 295,943 18,154 12,267 1,009,393
- -----------------------------------------------------------------------------------------------------------------------------------
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.
121
- -----------------------------------------------------------------------------------------------------------------------------------
Gas Electric Energy Gas Exploration Other Elimi- Consoli-
(In Thousands of Dollars) Distribution Services Services and Production Investments nations dated
- -----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2002
Unaffiliated revenue 3,163,761 1,645,688 208,624 357,451 89,650 - 5,465,174
Intersegment revenue - 101 - - 1,128 (1,229) -
Depreciation, depletion and
amortization 237,186 61,377 8,487 176,925 14,573 15,160 513,708
Sales of property 903 1,479 - - 2,348 - 4,730
Income from equity investments - - - - 13,992 104 14,096
Operating income 531,134 289,694 (45,581) 110,259 32,335 (8,506) 909,335
Interest income 2,020 1,834 1,248 - 238 (3,768) 1,572
Interest charges 215,140 58,788 18,187 7,303 6,858 (4,772) 301,504
Total assets 7,783,011 1,848,767 423,746 1,187,425 974,409 762,692 12,980,050
Equity method investments - - - - 130,815 - 130,815
Construction expenditures 412,433 348,147 8,133 241,477 31,243 16,074 1,057,507
- -----------------------------------------------------------------------------------------------------------------------------------
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 25% of our consolidated
revenues during that period.
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 asset 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) 2004 2003 2002
- ------------------------------------------------------------------------------------
Current income tax $ 201,909 $ (99,798) $ (36,588)
Deferred income tax 123,631 381,079 266,253
- ------------------------------------------------------------------------------------
Total income tax $ 325,540 $ 281,281 $ 229,665
- ------------------------------------------------------------------------------------
122
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) 2004 2003
- ---------------------------------------------------------------------------------------------------
Reserves not currently deductible $ 4,598 $ 34,342
New York corporation income tax (19,010) (56,188)
Property related differences (1,080,033) (1,049,237)
Regulatory tax asset (21,433) (21,222)
Property taxes (99,106) (98,089)
Other items - net 90,855 (85,164)
- ---------------------------------------------------------------------------------------------------
Net deferred tax liability $ (1,124,129) $ (1,275,558)
- ---------------------------------------------------------------------------------------------------
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 LILCO's tax returns for the tax years ending
December 31, 1996 through March 31, 1999 and KeySpan's and The Brooklyn Union
Gas Company's tax returns for the tax years ending September 30, 1997 through
December 31, 1998, pertaining to the KeySpan/LILCO combination, as well as other
return years. The primary issue raised in the conduct of the examination relates
to the valuation of the transferred assets in the KeySpan/LILCO combination. At
this time, we cannot predict the outcome of the ongoing audit. However, KeySpan
has evaluated the potential outcomes which may result based on the progress of
the examination to date and believes that it has adequately provided for any
potential tax which may be assessed.
The federal income tax amounts included in the Consolidated Statement of Income
differ from the amounts which result from applying the statutory federal income
tax rate to income before income tax.
The table below sets forth the reasons for such differences:
- -----------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2004 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------
Computed at the statutory rate $ 329,089 $ 247,573 $ 212,788
Adjustments related to:
Tax credits (2,150) - (1,026)
Removal costs (584) (6,592) (4,787)
Accrual to return adjustments (10,718) 549 (9,539)
Sale of Houston Exploration (8,445) - -
Sale of Canada (14,067) - -
Minority interest in Houston Exploration 12,879 19,969 9,490
State income tax, net of federal benefit 24,833 28,462 42,125
Other items - net (5,297) (8,680) (19,386)
- -----------------------------------------------------------------------------------------------------------------------------
Total income tax $ 325,540 $ 281,281 $ 229,665
- -----------------------------------------------------------------------------------------------------------------------------
Effective income tax rate (1) 35% 40% 38%
- -----------------------------------------------------------------------------------------------------------------------------
(1) Reflects both federal as well as state income taxes.
123
In December 2004, the FASB issued Staff Position ("FSP") No. 109-2, "Accounting
and Disclosure Guidance for the Foreign Earnings Repatriation Provision within
the American Jobs Creation Act of 2004." The American Jobs Creation Act of 2004
(the "Act"), signed into law on October 22, 2004, provides for a special
one-time tax deduction, or dividend received deduction ("DRD"), of 85% of
qualifying foreign earnings that are repatriated in either a company's last tax
year that began before the enactment date or the first tax year that begins
during the one-year period beginning on the enactment date. FSP 109-2 provides
entities additional time to assess the effect of repatriating foreign earnings
under the Act for purposes of applying SFAS 109, "Accounting for Income Taxes,"
which typically requires the effect of a new tax law to be required in the
period of enactment. KeySpan will elect, if applicable, to apply the DRD to
qualifying dividends of foreign earnings repatriated in 2005. KeySpan is
awaiting further clarifying guidance from the U.S. Treasury Department on
certain provisions of the Act. Once this guidance is received, KeySpan expects
to complete its evaluation of the effects of the Act during 2005. Because the
evaluation is ongoing, it is not yet practical to estimate a range of possible
income tax effects of potential repatriations.
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 typically based on age, 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 MADTE, respectively
for pension costs and other postretirement benefit costs.
The calculation of net periodic pension cost is as follows:
- -----------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2004 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------
Service cost, benefits earned during the period $ 52,908 $ 47,531 $ 42,423
Interest cost on projected benefit obligation 144,241 138,270 132,424
Expected return on plan assets (158,267) (130,556) (157,958)
Net amortization and deferral 63,307 66,949 (4,247)
- -----------------------------------------------------------------------------------------------------------------------------
Total pension cost $ 102,189 $ 122,194 $ 12,642
- -----------------------------------------------------------------------------------------------------------------------------
124
The following table sets forth the pension plans' funded status at December 31,
2004 and December 31, 2003.
- -----------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2004 2003
- -----------------------------------------------------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation at beginning of period $ (2,343,196) $ (2,080,193)
Service cost (52,908) (47,531)
Interest cost (144,241) (138,270)
Amendments (2,316) (3,079)
Actuarial loss (114,597) (192,617)
Benefits paid 137,142 118,494
- -----------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period (2,520,116) (2,343,196)
- -----------------------------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of period 1,855,239 1,544,518
Actual return on plan assets 164,225 335,757
Employer contribution 146,565 93,458
Benefits paid (137,142) (118,494)
- -----------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period 2,028,887 1,855,239
- -----------------------------------------------------------------------------------------------------------------------
Funded status (491,229) (487,957)
Unrecognized net loss from past experience different from that
assumed and from changes in assumptions 612,145 557,204
Unrecognized prior service cost 57,653 64,925
- -----------------------------------------------------------------------------------------------------------------------
Net prepaid pension cost reflected on consolidated balance sheet $ 178,569 $ 134,172
- -----------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------
Year Ended December 31,
2004 2003 2002
- -----------------------------------------------------------------------------------------------------
Assumptions:
Obligation discount 6.00% 6.25% 6.75%
Asset return 8.50% 8.50% 8.50%
Average annual increase in compensation 4.00% 4.00% 4.00%
- -----------------------------------------------------------------------------------------------------
125
The following benefit payments, which reflect expected future service, as
appropriate, are expected to be paid in the years indicated:
- ------------------------------------------------------------------
(In Thousands of Dollars) Pension Benefits
- ------------------------------------------------------------------
2005 $ 127,287
2006 $ 128,708
2007 $ 131,000
2008 $ 134,934
2009 $ 139,048
Years 2010- 2014 $ 796,286
- ------------------------------------------------------------------
Unfunded Pension Obligation: At December 31, 2004 the accumulated benefit
obligation was in excess of pension assets. As prescribed by SFAS 87 "Employers'
Accounting for Pensions," KeySpan had a $255.9 million minimum liability at
December 31, 2004, 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 accumulated other
comprehensive income on the Consolidated Balance Sheet.
Therefore, at year-end, we had a long-term asset in deferred charges other of
$49.7 million, representing the amount of unrecognized prior service cost and a
debit to other comprehensive income of $91.9 million, or $59.8 million
after-tax. The remaining amount of $114.3 million was recorded as a contractual
receivable from LIPA of $100.1 million and a regulatory asset of $14.2 million,
representing the amounts that could be recovered from LIPA and the Boston Gas
ratepayer in accordance with our service and rate agreements if the underlying
assumptions giving rise to this minimum liability were realized and recorded as
pension expense. The Boston Gas Company has received approval from the MADTE to
defer as a regulatory asset the amount of its current and future minimum pension
liability to reflect its ability to recover in rates its actual pension
liability.
At December 31, 2004 the projected benefit obligation, accumulated benefit
obligation and value of assets for plans with accumulated benefit obligations in
excess of plan assets were $ 1.3 billion, $1.2 billion and $881 million,
respectively.
At December 31, 2003, the accumulated benefit obligation was also in excess of
pension assets. As a result, we had a minimum liability of $244.4 million, a
long-term asset in deferred charges other of $55.3 million, and a debit to other
comprehensive income of $79.9 million, or $51.9 million after-tax. The remaining
amount of $109.2 million was recorded as a contractual receivable from LIPA of
$95.8 million and a regulatory asset of $13.4 million.
126
At December 31, 2003 the projected benefit obligation, accumulated benefit
obligation and value of assets for plans with accumulated benefit obligations in
plan assets were $1.2 billion, $1.1 billion and $794 million, respectively.
At the end of each 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 Contributory Medical and prescription drug programs
and non-contributory life insurance programs 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) 2004 2003 2002
- -----------------------------------------------------------------------------------------------------
Service cost, benefits earned during the period $ 19,656 $ 18,825 $ 16,566
Interest cost on accumulated
postretirement benefit obligation 70,225 69,803 65,486
Expected return on plan assets (33,892) (27,530) (36,839)
Net amortization and deferral 40,981 35,815 17,527
- -----------------------------------------------------------------------------------------------------
Other postretirement cost $ 96,970 $ 96,913 $ 62,740
- -----------------------------------------------------------------------------------------------------
127
The following table sets forth the plans' funded status at December 31, 2004 and
December 31, 2003.
- --------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2004 2003
- --------------------------------------------------------------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation at beginning of period $(1,267,624) $(1,056,944)
Impact due to new Medicare subsidy 60,578 -
Service cost (19,656) (18,825)
Interest cost (70,225) (69,803)
Plan participants' contributions (1,933) (1,757)
Amendments 27,392 35,458
Actuarial (loss) (119,914) (209,446)
Benefits paid 54,644 53,693
- --------------------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period (1,336,738) (1,267,624)
- --------------------------------------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of period 438,434 361,166
Actual return on plan assets 38,765 85,625
Employer contribution 39,510 43,578
Plan participants' contributions 1,932 1,757
Benefits paid (54,644) (53,693)
- --------------------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period 463,997 438,433
- --------------------------------------------------------------------------------------------------------------------------------
Funded status (872,741) (829,191)
Unrecognized net loss from past experience different from that assumed
and from changes in assumptions 576,856 573,277
Unrecognized prior service cost (106,523) (89,034)
- --------------------------------------------------------------------------------------------------------------------------------
Accrued postretirement cost reflected on consolidated balance sheet $ (402,408) $ (344,948)
- --------------------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
2004 2003 2002
- --------------------------------------------------------------------------------------------------------------------------
Assumptions:
Obligation discount 6.00% 6.25% 6.75%
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 11.0% grading down to 5.0% over five years, and 5.0% 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, 2004 by
$158.0 million and the net periodic health care expense by $12.6 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, 2004 by
$138.4 million and the net periodic health care expense by $10.7 million.
The reduction in the APBO for the subsidy related to the benefits attributed to
past service is $60.6 million. The effect of the subsidy on the measurement of
net periodic postretirement benefit cost for the current period is $10.1
million. That effect includes amortization of the actuarial experience gain in
128
the reduction in the APBO, for the subsidy related to benefits attributed to
past service, as a component of the net amortization called for by paragraph 59
of SFAS 106 of $5.8 million. The reduction in the current period service cost
due to the subsidy is $0.5 million. The resulting reduction in interest cost on
the APBO as a result of the subsidy is $3.8 million.
At December 31, 2004, KeySpan had a contractual receivable from LIPA of $256.9
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.
The following benefit payments, which reflect expected future service, as
appropriate, are expected to be paid in the years indicated:
- -------------------------------------------------------------------------------
Subsidiary
Gross Benefit Receipts
(In Thousands of Dollars) Payments Expected**
- -------------------------------------------------------------------------------
2005 $ 63,563 $ -
2006 $ 67,257 $ 3,530
2007 $ 70,605 $ 3,843
2008 $ 73,417 $ 4,145
2009 $ 76,368 $ 4,408
Years 2010- 2014 $ 418,664 $ 24,631
- --------------------------------------------------------------------------------
** Rebates are based on calendar year in which prescription drug costs are
incurred. Actual receipt of rebates may occur in the following year.
Pension/Other Post Retirement Benefit Plan Assets: Keyspan's weighted average
asset allocations at December 31, 2004 and 2003, by asset category, for both the
pension and other postretirement benefit plans are as follows:
- --------------------------------------------------------------------------------------------------------
Pension OPEB
Asset Category 2004 2003 2004 2003
- --------------------------------------------------------------------------------------------------------
Equity securities 64% 61% 72% 68%
Debt securities 28% 31% 23% 26%
Cash and equivalents 3% 2% 0% 2%
Venture capital 5% 6% 5% 4%
- --------------------------------------------------------------------------------------------------------
Total 100% 100% 100% 100%
- --------------------------------------------------------------------------------------------------------
129
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 and fixed income 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 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 performance of equity investments over long-term periods.
Cash Contributions: In 2005, KeySpan is expected to contribute approximately $82
million to its pension plans and approximately $36 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, 2004, 2003 and 2002, we recorded an expense of $14.7 million, $11.2
million, and $11.2 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, 2004, we had 11.9 million
shares, or approximately $345 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 2004, we issued 1.2 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.
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.
130
At December 31, 2004 we had 553,000 shares outstanding of 7.07% Mandatory
Redeemable Preferred Stock Series B par value $100 redeemable in 2005; and
197,000 shares outstanding of 7.17% Mandatory Redeemable Preferred Stock Series
C par value $100 redeemable in 2008.
In July 2004, KeySpan redeemed 83,268 shares of preferred stock 6.00% Series A
par value $100 that were previously issued in a private placement. KeySpan
redeemed these shares at a 2% premium and incurred a cash expenditure of $8.5
million.
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, 2004, each of which is guaranteed by KeySpan.
KeySpan had $2.66 billion of medium and long term notes outstanding at December
31, 2003 of which $1.65 billion of these notes were 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. During 2004, KeySpan redeemed the $700
million, 7.25% Notes due 2005 series. 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 $48.9 million
reflecting call premiums of $40.9 million and the write-off of $8.0 million of
previously deferred financing costs. The call premiums are reflected in other
income and (deductions) while the write-off of previously deferred financing
costs have been reflected in interest expense on the Consolidated Statement of
Income. Therefore, at December 31, 2004 KeySpan has $1.96 billion of notes
remaining having interest rates ranging from 4.65% to 9.75% that mature in
2005-2033.
On January 14, 2005, KeySpan redeemed $500 million 6.15% Series due 2006 of
outstanding debt. KeySpan incurred $20.9 million in call premiums and wrote-off
$1.0 million of previously deferred financing costs.
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. During 2004, KEDNY
retired $8.0 million of its outstanding Gas Facilities Revenue Bonds. The funds
used to retire this debt were drawn from a special deposit defeasance trust
previously established by KEDNY. Therefore, at December 31, 2004 $640.5 million
of Gas Facilities Revenue Bonds remain outstanding. The interest rate on the
variable rate series due December 1, 2020 is reset weekly and ranged from 0.64%
to 1.65% during the year ended December 31, 2004, at which time the rate was
1.65%.
131
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. At December 31, 2004, $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, 2004, KeySpan was in
compliance with this requirement.
MEDS Equity Units: At December 31, 2004, 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 9.2 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, 13 million shares will be issued. If the average
closing price over this time frame is greater than or equal to $42.36, 10.9
million shares will be issued. The number of shares issued at a price between
$35.30 and $42.36 will be between 10.9 million and 13 million based upon a
sliding scale.
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.
Industrial Development Revenue Bonds: At December 31, 2004 KeySpan had
outstanding $128.3 million of tax-exempt bonds with a 5.25% coupon maturing in
June 2027. Fifty-three million dollars of these Industrial Development Revenue
Bonds were issued in its behalf 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 in its behalf by the Suffolk County
Industrial Development Authority for the Port Jefferson electric-generation
peaking plant. KeySpan has guaranteed all payment obligations of our
subsidiaries with regard to these bonds.
132
First Mortgage Bonds: Colonial Gas Company ("Colonial"), Essex Gas Company
("Essex"), ENI and their respective subsidiaries, had outstanding $153.2 million
of first mortgage bonds at December 31, 2003. 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. During 2004, KeySpan redeemed $58.2 million of these bonds,
representing all previously outstanding bonds of Essex and ENI. KeySpan incurred
call premiums of $13.6 million associated with this redemption, of which $5.0
million was expensed. The remaining amount of the call premiums have been
deferred for future regulatory recovery. Further, KeySpan wrote-off $0.2 million
of previously deferred financing costs. The call premiums are reflected in other
income and (deductions) while the write-off of previously deferred financing
costs have been reflected in interest expense on the Consolidated Statement of
Income. Therefore, at December 31, 2004, $95.0 million of first mortgage bonds
remain outstanding having interest rates ranging from 6.08% to 8.80% and
maturities that range from 2008-2028.
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, 2004, $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 2004 ranged from 0.75% to 1.50%,
through December 31, 2004, at which time the rate was 1.45%.
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 0.88% to 2.01% from January 1, 2004 through
December 31, 2004, at which time the rate was 2.01%.
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, unaffiliated
financing entity that acquired a portion of the facility, or three steam
generating units, directly from Consolidated Edison and leased it to a KeySpan
subsidiary. The variable interest 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 are substantially equal to the monthly interest
expense on the debt securities.
We have classified the Master Lease as $412.3 million of long-term debt on the
Consolidated Balance Sheet based on our current status as primary beneficiary as
defined in Financial Accounting Standards Board Interpretation No. 46 ("FIN
46"), "Consolidation of Variable Interest Entities, an Interpretation of ARB No.
51." Further, we have an asset on the Consolidated Balance Sheet for an amount
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substantially equal to the fair market value of the leased assets at the
inception of the lease, less depreciation since that date, or approximately
$339.6 million. Under the terms of our two credit facilities, the Master Lease
is considered debt in the ratio of debt-to-total capitalization. (See Note 7
"Contractual Obligations, Financial Guarantees and Contingencies" for additional
information regarding the leasing arrangement associated with the Master Lease
Agreement.)
Registered Securities: In 2004, in accordance with its PUHCA authorization,
KeySpan filed a new universal shelf registration statement on Form S-3 with the
SEC for the issuance from time to time of up to $3.0 billion in securities. This
authorization provides KeySpan with the necessary flexibility to finance future
capital requirements for the next several years.
Commercial Paper and Revolving Credit Agreements: In 2004, KeySpan restructured
its credit facilities. We entered into a new $640 million five year revolving
credit facility to replace the $450 million, 364 day facility which expired in
June 2004. We also amended our existing three year $850 million facility due
June 2006 to reduce commitments thereunder by $190 million to $660 million. The
two credit facilities total $1.3 billion and are each syndicated among sixteen
banks. These facilities continue to support KeySpan's commercial paper program
for working capital needs.
The fees for these facilities are subject to a ratings-based grid, with an
annual fee of 0.08% on the new five-year facility and 0.125% on the existing
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 in the five-year facility are based on
the Eurodollar rate plus a margin of 0.40% for loans up to 33% of the facility,
and an additional 0.125% for loans over 33% of the facility. In the three-year
facility Eurodollar loans are based on the Eurodollar rate plus a margin of
0.625% for loans up to 33% of the facility, and an additional 0.125% for loans
over 33% of the facility. 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%.
Competitive bid loans are based on bid results requested by KeySpan from the
lenders. We do not anticipate borrowing against these facilities; however, if
the credit rating on our commercial paper program were to be downgraded, it may
be necessary to do so.
The facilities contain 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% until the
expiration of the existing three-year facility in 2006, at which time it will be
lowered to 62%. Violation of this covenant could result in the termination of
the facilities and the required repayment of amounts borrowed thereunder, as
well as possible cross defaults under other debt agreements.
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, 2004, consolidated indebtedness, as calculated
under the terms of the credit facility, was 53.4% of consolidated
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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.
At December 31, 2004, we had cash and temporary cash investments of $922.0
million. During 2004, we borrowed $430.3 million of commercial paper and, at
December 31, 2004, $912.2 million of commercial paper was outstanding at a
weighted average annualized interest rate of 2.4%. We had the ability to borrow
up to an additional $387.8 million at December 31, 2004, under the commercial
paper program.
As a result of the sale of Houston Exploration and KeySpan Canada, the credit
facilities of these previous subsidiaries are no longer reflected on KeySpan's
Consolidated Balance Sheet. However, the borrowings and repayments through these
credit facilities are reflected on KeySpan's Consolidated Cash Flow Statement
for the period that these subsidiaries were consolidated. During the time period
that Houston Exploration's results were consolidated with KeySpan's (the five
months ended May 31, 2004) Houston Exploration borrowed $49 million under its
credit facility and repaid $136 million. KeySpan Canada repaid $17.7 million
under its facility during the first three months of 2004 (the time period in
which its results were consolidated with KeySpan's).
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 6.07%.
Debt Maturity: The following table reflects the maturity schedule for our debt
repayment requirements, including capitalized leases and related maturities, at
December 31, 2004:
- --------------------------------------------------------------------------------------
Long-Term Capital
(In Thousands of Dollars) Debt Leases Total
- --------------------------------------------------------------------------------------
Repayments:
2005 $ 15,000 $ 1,103 $ 16,103
2006 512,000 1,006 513,006
2007 - 1,063 1,063
2008 605,000 1,129 606,129
2009 412,250 1,197 413,447
Thereafter 2,898,200 6,335 2,904,535
- --------------------------------------------------------------------------------------
$ 4,442,450 $ 11,833 $ 4,454,283
- --------------------------------------------------------------------------------------
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Note 7. Contractual Obligations, Financial Guarantees and Contingencies
Lease Obligations: Lease costs included in operation expense were $67.7 million
in 2004 reflecting, primarily, the lease of KeySpan's Brooklyn headquarters of
$14.4 million. Further, in May 2004 KeySpan entered into a leveraged lease
financing arrangement associated with the Ravenswood Expansion. The yearly
operating lease expense is expected to be approximately $17 million per year.
For the period May 2004 through December 31, 2004 lease expense associated with
this lease was $10.5 million. (See the caption below "Sale/Leaseback
Transaction" for further details of this lease.) Lease costs also include leases
for other buildings, office equipment, vehicles and power operated equipment.
Lease costs for the year ended December 31, 2003 and 2002 were $82.1 million and
$71.1 million, respectively. As previously mentioned, the Master Lease has been
consolidated and, as a result, lease payments in 2004 have been reflected as
interest expense on the Consolidated Statement of Income. The future minimum
cash lease payments under various leases, excluding the Master Lease but
including the Ravenswood Expansion lease, all of which are operating leases, are
$91.5 million per year over the next five years and $552.7 million, in the
aggregate, for all years thereafter. (See discussion below for further
information regarding the Master Lease and the Ravenswood Expansion
sale/leasback transaction.)
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.
Interest expense for the year ended December 31, 2004 was $29.9 million.
The initial term of the Master Lease expired on June 20, 2004 and was extended
until June 20, 2009 pursuant to the terms of the Master Lease. On all future
semi-annual payment dates, 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; or (ii) terminate the Master Lease and dispose of the facility. 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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We have classified the Master Lease as $412.3 million of long-term debt on the
Consolidated Balance Sheet based on our current status as primary beneficiary.
Further, we have 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
$339.6 million.
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.
Sale/leaseback Transaction: KeySpan also has a leveraged lease financing
arrangement associated with the Ravenswood Expansion. In May 2004, the unit was
acquired by a lessor from our subsidiary, KeySpan Ravenswood, LLC, and
simultaneously leased back to that subsidiary. All the obligations of KeySpan
Ravenswood, LLC have been unconditionally guaranteed by KeySpan. This lease
transaction generated cash proceeds of $385 million, before transaction costs,
which approximates the fair market value of the facility, as determined by a
third-party appraiser. This lease transaction qualifies 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 has an initial term of 36 years and the yearly operating
lease expense is approximately $17 million per year. Lease payments will
fluctuate from year to year, but are substantially paid over the first 16 years.
The future minimum cash lease payments under this lease is approximately $142
million over the next five years and $457 million, in the aggregate, for all
years thereafter. The sale/leaseback transaction resulted in a pre-tax gain of
approximately $6 million which has been deferred and is being amortized over the
life of the lease.
Asset Retirement Obligations: In 2003, KeySpan adopted SFAS 143, "Accounting for
Asset Retirement Obligations." SFAS 143 required us to record a liability and
corresponding asset representing the present value of legal obligations
associated with the retirement of tangible, long-lived assets that existed at
the inception of the obligation. At the time of implementation, KeySpan recorded
an asset retirement obligation ("ARO") related to its investment in Houston
Exploration and its other gas exploration and production subsidiaries. At
January 1, 2003 the ARO was $57.2 million. As a result of additions from
purchases and drilling during 2003 the ARO increased to $92.4 million at
December 31, 2003. Since Houston Exploration's operations have been
deconsolidated, Houston Exploration's liability is no longer reflected on
KeySpan's Consolidated Balance Sheet at December 31, 2004. The remaining ARO,
therefore, is related to our continuing gas exploration and production
activities and was approximately $1.9 million at December 31, 2004.
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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 has been 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 such obligation.
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, 2004, 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 Expiration
(In Thousands of Dollars) Exposure Dates
- -----------------------------------------------------------------------------------------------------
Guarantees for Subsidiaries
Medium-Term Notes - KEDLI (i) $ 525,000 2008 - 2010
Industrial Development Revenue Bonds (ii) 128,000 2027
Ravenswood - Master Lease (iii) 425,000 2009
Ravenswood - Sale/leaseback (iv) 385,000 2040
Surety Bonds (v) 258,000 2005 - 2008
Commodity Guarantees and Other (vi) 74,000 2005
Letters of Credit (vii) 74,000 2005
- -------------------------------------------------------------------------------------------------------
$ 1,869,000
- -------------------------------------------------------------------------------------------------------
The following is a description of KeySpan's outstanding subsidiary guarantees:
(i) KeySpan has fully and unconditionally guaranteed $525 million to holders of
Medium-Term Notes issued by KEDLI. These notes are due to be repaid on
January 15, 2008 and February 1, 2010. KEDLI is required to comply with
certain financial covenants under the debt agreements. The face values 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 two
electric-generation peaking plants on long Island. The face values 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 Master Lease. The initial term of the
lease expired on June 20, 2004 and was extended until June 20, 2009. The
Master Lease is classified as $412.3 million long-term debt on the
Consolidated Balance Sheet.
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(iv) KeySpan has guaranteed all payment and performance obligations of KeySpan
Ravenswood, LLC, the lessee under the sale/leaseback transaction associated
with the 250 MW Ravenswood Expansion. The initial term of the lease is for
36 years. As noted previously, this lease qualifies as an operating lease
and is not reflected on the Consolidated Balance Sheet.
(v) KeySpan has agreed to indemnify the issuers of various surety and
performance bonds associated with certain construction projects currently
being performed by certain current and former 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. KeySpan will continue to
provide this guarantee for the mechanical contracting companies throughout
the construction period of the currently outstanding projects. It is
contemplated that the majority of the current contracts will be completed
by the end of 2005. In addition, as discussed in Note 11 "Energy
Services-Discontinued Operations", a performance and payment bond issued
for the benefit of a former subsidiary with respect to a pending project,
which bond had been supported by a $150 million indemnity obligation
included in the table above, has been replaced. KeySpan has also received
from a former subsidiary an indemnity bond issued by a third party
insurance company, the purpose of which is to reimburse KeySpan in an
amount up to $80 million in the event it is required to perform under all
other indemnity obligations previously incurred by KeySpan to support such
company's bonded projects existing prior to divestiture.
(vi) 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, 2004.
(vii)KeySpan has arranged for stand-by letters of credit to be issued 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.
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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 or former 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.
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 $485 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 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 June 2004,
the parties reached an agreement in principle to settle the consolidated class
action lawsuit for $13.8 million. The proposed settlement provides for KeySpan
to make certain payments to plaintiffs, all of which is to be funded by the
insurance carrier providing liability coverage for KeySpan's directors and
officers. While KeySpan continues to deny any wrongdoing, we believe the
proposed settlement is in the best interest of KeySpan and its shareholders. The
settlement is subject to court approval, the timing of which cannot be
determined.
On February 9, 2005, KeySpan was served with a shareholder derivative action
asserting claims on behalf of KeySpan based upon breach of fiduciary duty. The
complaint, which was filed in the New York State Supreme Court for the County of
Kings, relates to the 2001 Roy Kay related losses and alleges that KeySpan's
directors and certain senior officers breached their fiduciary duties when they
placed their own personal interests above the interests of KeySpan by using
material non-public information (the fraud at Roy Kay) to sell securities at
artificially inflated prices.
This new complaint asserts essentially the same allegations as contained in two
prior federal shareholder derivative actions which were commenced in October
2001 and June 2002. On March 15, 2004, KeySpan and the individual defendants
filed a motion to dismiss those earlier federal complaints. On April 14, 2004,
the plaintiffs filed a notice of voluntary withdrawal of their actions. On April
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23, 2004, the federal court dismissed both actions without prejudice. KeySpan
intends to file a motion to dismiss this new complaint. While KeySpan denies any
wrongdoing, the outcome of this proceeding cannot be determined as yet.
In late 2001, KeySpan received inquires from the U.S. Attorney's Office,
Southern District of New York and the SEC 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.
In March 2002, the SEC issued a formal order of investigation pursuant to which
it indicated that it would review the trading activity of certain company
insiders as well as KeySpan's compliance with reporting rules and regulations,
generally during the period following the acquisition of the Roy Kay companies
through the July 17, 2001 announcement. Since mid 2002, KeySpan has not received
any further notifications or inquires concerning any of these matters.
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 Long
Island Lighting Company ("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
("PSA") between LIPA and KeySpan.
KeySpan is unable to determine the outcome of the outstanding asbestos
proceedings, but does not believe that such outcome, 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 PSA, its
indemnification rights against third parties and its insurance coverage (above
applicable deductible limits) cover its exposure for asbestos liabilities
generally.
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 29, 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,
results of operations or cash flows.
In addition, LIPA is in the process of performing a long-term strategic review
initiative regarding its future direction. It has engaged a team of advisors and
consultants and is conducting public hearings to develop recommendations to be
submitted to the LIPA Trustees. Some of the strategic options that LIPA is
considering include whether LIPA should continue its operations as they
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presently exist, fully municipalize or privatize, sell some, but not all of
their assets and become a regulator of rates and services. In the near term,
LIPA must make a determination by May 2005 as to whether they will exercise its
option to purchase our Long Island generating plants pursuant to the terms of
the Generation Purchase Rights Agreement. Until LIPA makes a determination on
its future direction, we are unable to determine what the outcome of this
strategic review will have on our financial condition, results of operations or
cash flows. Any action that may be taken will have to take into consideration
the long-term nature of our existing contracts.
Environmental Matters
Air: With respect to NOx emissions reduction requirements for our existing power
plants, our investments in low NOx 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 by May 1, 2003 under
Phase I, II and III of the Ozone Transport Commission memorandum in a
cost-effective manner. We have achieved and expect to continue to achieve such
emission reductions through the use of low NOx combustion control systems, the
use of natural gas fuel and/or the purchases of emission 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 to enhance compliance options.
Water: Additional capital expenditures associated with the renewal of the
surface water discharge permits for our power plants will likely be required by
the Department of Environmental Conservation ("DEC"). We are currently
conducting studies as directed by the DEC to determine the impacts of our
discharges on aquatic resources. It is not possible at this time to predict the
extent of such capital investments since they will depend upon the outcome of
the ongoing studies and the subsequent determination by the DEC to apply the
standards set forth in recently promulgated federal regulations under Section
316 of the Clean Water Act designed to mitigate such impacts.
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. KeySpan submitted applications to the DEC for
each of the remaining sites in August 2004 under the DEC's Brownfield Cleanup
Program ("BCP"). As a result of a recent United States Supreme Court decision,
KeySpan is currently reevaluating its continued participation in the DEC's BCP
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and VCA programs. Under the Supreme Court's ruling in Cooper Industries v.
Aviall, KeySpan would be prohibited from bringing a contribution action against
other responsible parties under the Comprehensive Environmental Response,
Compensation and Liability Act unless KeySpan had been sued by the DEC and
received a verdict against it or reached a settlement of the action with the
DEC.
We have identified 28 of these sites as being associated with the historical
operations of KEDNY. One site has been fully remediated. Subject to the issues
described in the preceding paragraph, the remaining 27 sites will be
investigated and, if necessary, remediated under the terms and conditions of
ACOs, VCAs or Brownfield Cleanup Agreements ("BCA"). Expenditures incurred to
date by us with respect to KEDNY MGP-related activities total $47.8 million.
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 $42.7 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, VCAs or
BCAs.
We presently estimate the remaining cost of our KEDNY and KEDLI MGP-related
environmental remediation activities will be $206.6 million, which amount has
been accrued by us as a reasonable estimate of probable cost for known sites
however, remediation costs for each site may be materially higher than noted,
depending upon changing technologies and regulatory standards, selected end use
for each site, and actual environmental conditions encountered and as a result,
it is possible that remediation costs could be up to $258 million higher.
Expenditures incurred to date by us with respect to these MGP-related activities
total $90.5 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, 2004, we have reflected a regulatory asset of $228.7
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, 2004, these previously
deferred regulatory liabilities totaled $37 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. That petition
is still pending.
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 $3.1 million, which amount has been
accrued by us. Expenditures incurred to date total $1.9 million.
143
New England Sites: Within the Commonwealth of Massachusetts and the State of New
Hampshire, we are aware of 77 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 67 of
these sites. A subsidiary of National Grid USA ("National Grid"), formerly New
England Electric System, has assumed responsibility for remediating 11 of these
sites, subject to a limited contribution from Boston Gas Company, and has
provided full indemnification to Boston Gas Company with respect to eight other
sites. In addition, Boston Gas Company, Colonial Gas Company, and Essex Gas
Company have assumed responsibility for remediating three sites each. 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.
We presently estimate the remaining cost of these Massachusetts KEDNE
MGP-related environmental cleanup activities will be $14.9 million, which amount
has been accrued by us as a reasonable estimate of probable cost for known
sites, however remediation costs for each site may be materially higher than
noted, depending upon changing technologies and regulatory standards, selected
end use for each site, and actual environmental conditions encountered and as a
result, it is possible that remediation costs could be up to $73 million higher.
Expenditures incurred since November 8, 2000, the date KeySpan acquired Eastern
Enterprises, with respect to these MGP-related activities total $22.5 million.
Boston Gas Company reached settlements with certain insurance carriers for
recovery of a portion of previously incurred environmental expenditures. Under a
previously issued MADTE rate order, insurance and third-party recoveries, after
deducting legal fees, are shared between Boston Gas and its firm gas customers.
As a result of these settlements, in 2004 Boston Gas Company recorded a $5
million benefit to operations and maintenance expense.
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.
We presently estimate the remaining cost of EnergyNorth MGP-related
environmental cleanup activities will be $12.5 million, which amount has been
accrued by us as a reasonable estimate of probable cost for known sites however,
remediation costs for each site may be materially higher than noted, depending
144
upon changing technologies and regulatory standards, selected end use for each
site, and actual environmental conditions encountered and as a result, it is
possible that remediation costs could be up to $13 million higher. Expenditures
incurred since November 8, 2000, with respect to these MGP-related activities
total $10.3 million.
By rate orders, the MADTE and the NHPUC provide for the recovery of site
investigation and remediation costs and, accordingly, at December 31, 2004, we
have reflected a regulatory asset of $43.8 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 orders 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.
In 2004, KeySpan reached a settlement with insurance carriers regarding cost
recovery for expenses at one of the above noted sites and recorded an $11.6
million reduction to operating expenses. We presently estimate the remaining
cost of our environmental cleanup activities for the three non-utility sites
will be approximately $19.7 million, which amount has been accrued by us as a
reasonable estimate of probable costs for known sites however, remediation costs
for each site may be materially higher than noted, depending upon changing
technologies and regulatory standards, selected end use for each site, and
actual environmental conditions encountered and as a result, it is possible that
remediation costs could be up to $57 million higher. Expenditures incurred since
November 8, 2000, with respect to these sites total $13.1 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 may be required to
145
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.
Insurance Reimbursement of MGP Response Costs: We have instituted lawsuits in
New York, Massachusetts and New Hampshire against numerous insurance carriers
for reimbursement of costs incurred for the investigation and remediation of
these MGP sites.
In January 1998 and July 2001, KEDLI and KEDNY, respectively, filed complaints
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 and KEDNY. The outcome of these proceedings cannot
yet be determined.
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. And 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 yet be determined.
EnergyNorth has filed a number of lawsuits 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. The outcome of these proceedings cannot yet
be determined.
In 1993 KeySpan New England LLC filed a declaratory judgment action against the
Hanover and Travelers insurance companies in the Superior Court for Middlesex
County for the Everett Facility ("the Eastern Action"). Eastern sought to have
the court compel the Insurers to defend Eastern in connection with the
Massachusetts DEP's Notice of Responsibility ("NOR"). In 2004, the Court granted
KeySpan's unopposed motion for leave to file a Second Amended Complaint in the
Eastern Action to seek a declaratory ruling that the insurers have a duty to
indemnify KeySpan for the costs associated with the Everett NOR and certain
other related private actions. The Second Amended Complaint also adds certain
excess insurance carriers as defendants in the Eastern Action. The outcome of
this proceeding cannot yet be determined.
Settlement negotiations have been ongoing while the litigation of these cases
have been proceeding. Over the past four years KeySpan has achieved settlements
with various insurance carriers in excess of $50 million for reimbursement of
MGP response costs incurred in New York, Massachusetts and New Hampshire.
146
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 distribution
operations, gas exploration and production activities and its electric
generating facilities at the Ravenswood site.
Derivative financial instruments are employed by our gas distribution operations
to reduce the cash flow variability associated with the purchase price for a
portion of future natural gas purchases for our regulated firm gas sales
customers. The accounting for these derivative instruments is subject to SFAS
71. See the caption below "Firm Gas Sales Derivative Instruments - Regulated
Utilities" for a further discussion of these derivatives. Certain derivative
instruments employed by our gas distribution operations are not subject to SFAS
71. Utility tariffs applicable to certain large-volume customers permit gas to
be sold at prices established monthly relative to a prevailing alternate fuel
price but limited to the cost of gas plus the tail block rate. KEDNY uses
over-the-counter ("OTC") natural gas swaps, with offsetting positions in OTC
fuel oil swaps of equivalent energy value, to hedge the cash-flow variability of
specified portions of gas purchases and sales associated with these customers.
The maximum length of time over which we have hedged cash flow variability
associated with forecasted purchases and sales of natural gas is through October
2005. We use standard New York Mercantile Exchange ("NYMEX") futures prices to
value the gas and heating oil positions. At December 31, 2004, the fair value of
gas swap contracts was a liability of $6.2 million; the fair value of the oil
swap contracts was an asset of $7.5 million. These derivative positions are
expected to be reclassified from other comprehensive income into earnings over
the next twelve months.
Seneca-Upshur utilizes OTC natural gas swaps to hedge the cash flow variability
associated with forecasted sales of a portion of its natural gas production. At
December 31, 2004, Seneca-Upshur has hedge positions in place for approximately
85% of its estimated 2005 through 2007 gas production, net of gathering costs.
We use market quoted forward prices to value these swap positions. The maximum
length of time over which Seneca-Upshur has hedged such cash flow variability is
through December 2007. The fair value of these derivative instruments at
December 31, 2004 was a liability of $0.7 million. The estimated amount of gains
associated with such derivative instruments that are reported in other
comprehensive income and that are expected to be reclassified into earnings over
the next twelve months is $0.2 million, or approximately $0.1 million after-tax.
The Ravenswood Projects use 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 Projects also
hedge the cash flow variability associated with a portion of electric energy
sales.
147
With respect to price exposure associated with fuel purchases for the Ravenswood
Projects, KeySpan employs natural gas futures contracts 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 by the Ravenswood Projects. We use standard NYMEX futures prices to
value the gas futures contracts and market quoted forward prices to value oil
swap contracts. The maximum length of time over which we have hedged cash flow
variability associated with forecasted purchases of natural gas is through
September 2005. The fair value of these derivative instruments at December 31,
2004 was negligible. The maximum length of time over which we have hedged cash
flow variability associated with forecasted purchases of fuel oil is through
April 2006. The fair value of these derivative instruments at December 31, 2004
was $0.3 million. A substantial portion of these derivative instruments, which
are reported in other comprehensive income, 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 electric energy
sales from the Ravenswood Projects. Our hedging strategy is to hedge at least
50% of forecasted on-peak summer season electric energy sales and a portion of
forecasted electric energy sales for the remainder of the year. The maximum
length of time over which we have hedged cash flow variability is through
December 2005. We use market quoted forward prices to value these outstanding
derivatives. The fair market value of these derivative instruments at December
31, 2004 was $0.4 million all of which is expected to be reclassified into
earnings over the next twelve months. The after-tax benefit is anticipated to be
$0.2 million.
The above noted 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 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 affects
earnings. Gains and losses are reflected as a component of either revenue or
fuel and purchased power depending on the hedged transaction. Hedge
ineffectiveness, which was negligible in 2004, results from changes during the
period in the price differentials between the index price of the derivative
contract and the price of the purchase or sale for the cash flow that is being
hedged, and is recorded directly to earnings.
The table below summarizes the fair value of outstanding financially-settled
commodity derivative instruments that qualify for hedge accounting at December
31, 2004 and the 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. It
should be noted that in the table below, December 31, 2003 balances include
outstanding derivatives of Houston Exploration; no such derivative instruments
are included in the December 2004 balances since Houston Exploration was sold
during the year.
148
- ----------------------------------------------------------------------------------------------------
(In Thousands of Dollars) December 31, 2004 December 31, 2003
- ----------------------------------------------------------------------------------------------------
Gas Contracts:
Other current assets $ 215 $ 3,458
Accounts payable and other liabilities (6,149) (35,592)
Other deferred liabilities (879) (4,734)
Oil Contracts:
Other current assets 7,719 -
Other deferred charges - 385
Electric Contracts:
Other current assets 353 -
Other deferred charges - 259
- ----------------------------------------------------------------------------------------------------
$ 1,259 $ (36,224)
- ----------------------------------------------------------------------------------------------------
Financially-Settled Commodity Derivative Instruments that Do Not Qualify for
Hedge Accounting: KeySpan subsidiaries also have employed a limited number of
financial derivatives that do not qualify for hedge accounting treatment under
SFAS 133. In 2004, we purchased a series of call options on the spread between
the price of heating oil and the price of natural gas. The options cover the
period February 2005 through October 2005 and further complement our hedging
strategy noted above regarding sales to certain large-volume customers. As
stated, we sell gas to certain large-volume customers at prices established
monthly relative to a prevailing alternate fuel price but limited to the cost of
gas plus the tail block rate. Utility tariffs, however, establish an upper limit
on the price KeySpan can charge for the sale of natural gas to these customers.
These options are intended to limit KeySpan's exposure to heating oil price
spikes. These options do not qualify for hedge accounting treatment under SFAS
133. We recorded a $2.5 million charge in other income and deductions on the
Consolidated Statement of Income to reflect the change in the market value
associated with this derivative instrument.
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. 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, 2004, these
derivatives had a negative fair value of $10.4 million and are reflected as a
regulatory asset on the Consolidated Balance Sheet.
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, 2004, these derivatives had a
negative fair market value of $16.5 million and are reflected as a regulatory
liability of $7.4 million and a regulatory asset of $23.9 on the Consolidated
Balance Sheet.
149
Interest Rate Derivative Instruments: In 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 received the fixed
coupon rate associated with these bonds and paid our swap counterparties a
variable interest rate based on LIBOR, that was reset on a semi-annual basis.
These swaps were designated as fair-value hedges and qualified for "short-cut"
hedge accounting treatment under SFAS 133. In the first quarter of 2004, we paid
our counterparty an average interest rate of 6.44%, and as a result, we realized
interest savings of $0.5 million.
On April 7, 2004 we terminated these swap agreements and received $1.2 million
from our swap counterparties, of which $0.7 million represented accrued swap
interest. The difference between the termination settlement amount and the
amount of accrued interest, $0.5 million, was being recorded as a reduction to
interest expense over the remaining life of the bonds. In August 2004, we
redeemed these bonds and recorded the remaining benefit.
KeySpan has a leveraged lease financing arrangement associated with the
Ravenswood Expansion. In May 2004, the facility was acquired by a lessor from
our subsidiary, KeySpan Ravenswood, LLC, and simultaneously leased back to that
subsidiary. In connection with this sale/leaseback transaction, KeySpan utilized
a $275 million treasury lock (at 4.2%) to hedge the 10-year US Treasury
component of the underlying notes issued by the lessor to purchase the facility.
The treasury lock was in effect for a five-week period during which time the
10-year US Treasury increased 70 basis points. KeySpan did not designate this
derivative instrument as a hedge for accounting purposes. The treasury lock
settled in May 2004 and KeySpan received cash proceeds of $12.6 million which
was recorded in other income and (deductions) in the Consolidated Statement of
Income. (See Note 7. "Contractual Obligations, Financial Guarantees and
Contingencies" for additional information regarding the sale/leaseback
transaction.)
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.
150
In 2003, KEDNE entered into heating-degree day call and put options for the
2003/2004 winter heating season - November 2003 through March 2004. With respect
to sold call options, KeySpan was required to make a payment of $27,500 per
heating degree day to its counterparties when actual weather experienced during
this time frame was above 4,440 heating degree days, which equates to
approximately 2% colder than normal weather, based on the then most recent
20-year average for normal weather. The maximum amount KeySpan was required to
pay on its sold call options was $5.5 million. With respect to purchased put
options, KeySpan would have received a $27,500 per heating degree day payment
from its counterparties when actual weather was below 4,266 heating degree days,
or approximately 2% warmer than normal. The maximum amount KeySpan would have
received on its purchased put options was $11 million. The net premium cost for
these options was $0.4 million. During the first quarter of 2004, weather, as
measured in heating degree-days, was 9.4% colder than normal and, as a result
$4.1 million was recorded as a reduction to revenues.
In 2004, we entered into heating-degree day put options to mitigate the effect
of fluctuations from normal weather on KEDNE's financial position and cash flows
for the 2004/2005 winter heating season - November 2004 through March 2005.
These put options will pay KeySpan up to $40,000 per heating degree day when the
actual temperature is below 4,130 heating degree days, or approximately 5%
warmer than normal, based on the most recent 20-year average for normal weather.
The maximum amount KeySpan may receive on these purchased put options is $16
million. The net premium cost for these options was $1.6 million and is being
amortized over the heating season. Unlike previous years if weather is colder
than normal KeySpan will have no financial obligation. Since weather was colder
than normal during the fourth quarter, there was no earnings impact associated
with these derivative instruments. We account for these derivatives pursuant to
the requirements of EITF 99-2, "Accounting for Weather Derivatives." In this
regard, such instruments are accounted for using the "intrinsic value method" as
set forth in such guidance.
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.
151
Long-term Debt: The following tables depict the fair values and carrying values
of KeySpan's long-term debt at December 31, 2004 and 2003.
Fair Values of Long-Term Debt
- ------------------------------------------------------------------------------
December 31,
(In Thousands of Dollars) 2004 2003
- ------------------------------------------------------------------------------
First Mortgage Bonds $ 115,820 $ 178,438
Notes 2,571,847 3,893,158
Gas Facilities Revenue Bonds 666,941 683,354
Authority Financing Notes 66,005 66,005
Promissory Notes 159,791 158,837
MEDS Equity Units 479,964 495,880
Master Lease 460,896 474,912
Tax Exempt Bonds 134,949 129,558
- ------------------------------------------------------------------------------
$ 4,656,213 $ 6,080,142
- ------------------------------------------------------------------------------
Carrying Values of Long-Term Debt
- -----------------------------------------------------------------------------
December 31,
(In Thousands of Dollars) 2004 2003
- -----------------------------------------------------------------------------
First Mortgage Bonds $ 95,000 $ 153,186
Notes 2,485,000 3,456,425
Gas Facilities Revenue Bonds 640,500 648,500
Authority Financing Notes 66,005 66,005
Promissory Notes 155,420 155,422
MEDS Equity Units 460,000 460,000
Master Lease 412,250 412,250
Tax Exempt Bonds 128,275 128,275
- -----------------------------------------------------------------------------
$ 4,442,450 $ 5,480,063
- -----------------------------------------------------------------------------
Our subsidiary debt was 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 Midland 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.
In 2001 we recorded a discontinued operations loss on disposal. 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 2001 loss provision.
These changes resulted in an additional after tax loss on disposal of $19.7
million.
152
The following is selected financial information for Midland for the period
January 1, 2002 through July 2, 2002:
- ---------------------------------------------------------------------------
(In Thousands of Dollars) 2002
- ---------------------------------------------------------------------------
Revenues $ 116,149
Pre-tax income (loss) (4,624)
Income tax (expense) benefit 1,268
- ---------------------------------------------------------------------------
Income (loss) from discontinued operations (3,356)
- ---------------------------------------------------------------------------
Estimated book gain on disposal 5,980
Tax expense associated with disposal (22,286)
- ---------------------------------------------------------------------------
Estimated loss on disposal (16,306)
- ---------------------------------------------------------------------------
Loss from discontinued operations $ (19,662)
- ---------------------------------------------------------------------------
10. Gas Exploration and Production Property - Depletion
As described in Note 2 "Business Segments," during much of 2004 KeySpan's
investments in gas exploration and production activities consisted of its
ownership interest in Houston Exploration, as well as KeySpan's wholly-owned
subsidiary KeySpan Exploration and Production, which is still engaged in a joint
drilling program with Houston Exploration. Further, KeySpan's investments in
these activities also includes its wholly-owned subsidiary Seneca-Upshur. These
assets were accounted for under the full cost method of accounting. After the
sale of Houston Exploration, Seneca-Upshur and KeySpan Exploration have remained
on full cost accounting. Under the full cost method, costs of acquisition,
exploration and development of natural gas and oil reserves plus asset
retirement obligations 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.
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 prices increase. The ceiling test is calculated using natural gas
and oil prices in effect as of the balance sheet date, adjusted for outstanding
derivative instruments, held flat over the life of the reserves.
As a result of the June 2004 stock transaction discussed in Note 2 "Business
Segments", KeySpan accounted for its investment in Houston Exploration on the
equity method from June 2004 through November 19, 2004, i.e. Houston
Exploration's operations were not consolidated with KeySpan's other
subsidiaries. Therefore, we were required to calculate a ceiling test on KeySpan
Exploration and Production's and Seneca-Uphsur's assets independently of Houston
Exploration's assets in the second quarter of 2004. Based on a report furnished
by an independent reservoir engineer at that time, it was determined that the
153
remaining proved undeveloped oil reserves held in the joint venture required a
substantial investment in order to develop. Therefore, KeySpan and Houston
Exploration elected not to develop these oil reserves. As a result, in the
second quarter of 2004, KeySpan recorded a $48.2 million non-cash impairment
charge to write down its wholly-owned gas exploration and production
subsidiaries' assets. This charge was recorded in depreciation, depletion and
amortization on the Consolidated Statement of Income.
11. Energy Services - Discontinued Operations
The Energy Services segment has experienced significantly lower operating
profits and cash flows than originally projected. As previously reported,
management has reviewed the operating performance of this segment. At a meeting
held on November 2, 2004, KeySpan's Board of Directors authorized management to
begin the process of disposing of a significant portion of its ownership
interests in certain companies within the Energy Services segment - specifically
those companies engaged in mechanical contracting activities. In January and
February of 2005, KeySpan sold its mechanical contracting investments. The
operating results and financial position of these companies, which were
previously consolidated within the Energy Services segment, have been reflected
as discontinued operations on the Consolidated Statement of Income, Consolidated
Balance Sheet and Consolidated Statement of Cash Flows.
In regard to the January 2005 transactions, KeySpan received proceeds of
approximately $16 million, approximately $5 million of which is to be paid
within a three year period. In addition, KeySpan retained its previously
incurred indemnity support obligations related to certain surety, performance
and payment bonds issued for the benefit of KeySpan's former subsidiaries prior
to closing. The current estimated cost to complete projects supported by such
indemnity obligations is approximately $25 million. The buyers have agreed to
cooperate with KeySpan to seek a release of KeySpan's indemnity obligation with
respect to all or a portion of such outstanding bonds after closing. Any costs
incurred to obtain such release will be borne by KeySpan.
In connection with the February 2005 transaction, KeySpan paid or contributed
approximately $26 million to its former subsidiary prior to closing the sale
transaction in exchange for, among other things, the disposition of outstanding
shares in the former subsidiary and the settlement of intercompany advances and
replacement of a performance and payment bond issued for the benefit of its
former subsidiary with respect to a pending project, which bond had been
supported by a $150 million indemnity obligation of KeySpan. In addition,
KeySpan received from its former subsidiary an indemnity bond issued by a third
party insurance company, the purpose of which is to reimburse KeySpan in an
amount up to $80 million in the event it is required to perform under all other
indemnity obligations previously incurred by KeySpan to support the remaining
bonded projects of its former subsidiary as of the closing. As of February 11,
2005, the total cost to complete such remaining bonded projects is estimated to
be approximately $70 million. The aforementioned guarantees are reflected in
Note 7 "Contractual Obligations, Financial Guarantees and Contingencies".
154
In anticipation of these sales and in connection with the preparation of the
third quarter and fourth quarter financial statements, KeySpan conducted an
evaluation of the carrying value of these investments, including recorded
goodwill. Further, we evaluated the carrying value of goodwill for the entire
Energy Services segment. As noted in prior SEC filings, KeySpan records goodwill
on purchased transactions, representing the excess of acquisition cost over the
fair value of net assets acquired.
As a result of these evaluations, KeySpan recorded a non-cash goodwill
impairment charge of $108.3 million ($80.3 million after tax, or $0.50 per
share) in 2004. This charge was recorded as follows: (i) $14.4 million as an
operating expense on the Consolidated Statement of Income reflecting the
write-down of goodwill on Energy Services segment's continuing operations; and
(ii) $93.9 million ($67.8 million after-tax) as discontinued operations
reflecting the impairment on the mechanical contracting companies.
In addition, an impairment charge of $100.3 million ($72.1 million after-tax or
$.45 per share) was also recorded to reduce the carrying value of the remaining
assets of the mechanical contracting companies. This charge is reflected in
discontinued operations on the Consolidated Statement of Income.
KeySpan employed a combination of two methodologies in determining the estimated
fair value for its investment in the Energy Services segment, a market valuation
approach and an income valuation approach. Under the market valuation approach,
KeySpan utilized a range of near-term potential realizable values for the
mechanical contracting businesses. Under the income valuation approach, the fair
value was obtained by discounting the sum of (i) the expected future cash flows
and (ii) the terminal value. KeySpan utilized certain significant assumptions in
this valuation, specifically the weighted-average cost of capital, short and
long-term growth rates and expected future cash flows. Approximately $65 million
of goodwill remains in this segment.
The information below highlights the major classes of assets and liabilities of
the discontinued mechanical contracting companies, as well as major income and
expense captions.
- --------------------------------------------------------------------------------------------------
December 31, December 31,
(In Thousands of Dollars) 2004 2003
-----------------------------------------------------
Property $ 8,743 $ 8,588
Current assets $ 42,923 $ 181,823
Goodwill $ - $ 92,702
Current liabilities $ 64,245 $ 81,956
- --------------------------------------------------------------------------------------------------
155
- ---------------------------------------------------------------------------------------------------------------------
For the Year Ended December 31,
(In Thousands of Dollars) 2004 2003 2002
- ---------------------------------------------------------------------------------------------------------------------
Revenues 338,666 379,637 505,492
Less:
Operating expenses 364,879 385,496 472,629
Goodwill impairment 108,289 - -
- ---------------------------------------------------------------------------------------------------------------------
(134,502) (5,859) 32,863
Income taxes (benefit) (55,542) (3,971) 13,815
- ---------------------------------------------------------------------------------------------------------------------
Operating loss (78,960) (1,888) 19,048
Loss on disposal, net tax of $28,174 (72,088) - -
- ---------------------------------------------------------------------------------------------------------------------
Net Income (151,048) (1,888) 19,048
- ---------------------------------------------------------------------------------------------------------------------
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.
156
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Income
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2004
(In Thousands of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Revenues $ 619 $ 1,124,417 $ 5,526,049 $ (619) $ 6,650,466
--------------------------------------------------------------------------------------------
Operating Expenses
Purchased gas - 664,857 1,999,635 - 2,664,492
Fuel and purchased power - - 540,302 - 540,302
Operations and maintenance 5,287 137,847 1,423,888 - 1,567,022
Intercompany expense 5,391 (5,391) -
Depreciation and amortization 79,856 471,904 - 551,760
Operating taxes - 65,722 338,490 - 404,212
Goodwill Impairment - - 40,965 - 40,965
--------------------------------------------------------------------------------------------
Total Operating Expenses 5,287 953,673 4,809,793 - 5,768,753
--------------------------------------------------------------------------------------------
Gain on sale of property - - 7,021 - 7,021
Income from equity investments - - 46,536 - 46,536
--------------------------------------------------------------------------------------------
Operating Income (Loss) (4,668) 170,744 769,813 (619) 935,270
--------------------------------------------------------------------------------------------
Interest charges (204,508) (61,503) (267,605) 202,365 (331,251)
Other income and (deductions) 635,450 836 423,895 (723,946) 336,235
--------------------------------------------------------------------------------------------
Total Other Income and (Deductions) 430,942 (60,667) 156,290 (521,581) 4,984
--------------------------------------------------------------------------------------------
Income Taxes (Benefit) (45,459) 35,827 335,173 - 325,541
--------------------------------------------------------------------------------------------
Earnings from Continuing Operations 471,733 74,250 590,930 (522,200) 614,713
Discontinued Operations - (151,048) (151,048)
--------------------------------------------------------------------------------------------
Net Income $ 471,733 $ 74,250 $ 439,882 $ (522,200) $ 463,665
============================================================================================
- ------------------------------------------------------------------------------------------------------------------------------------
157
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Income
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2003
(In Thousands of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Revenues $ 507 $ 1,046,931 $ 5,488,593 $ (507) $ 6,535,524
-------------------------------------------------------------------------------------------
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 1,474,029 - 1,622,592
Intercompany expense 5,282 3,570 (3,570) (5,282) -
Depreciation and amortization (53) 77,603 494,119 - 571,669
Operating taxes - 77,503 340,733 - 418,236
-------------------------------------------------------------------------------------------
Total Operating Expenses 16,569 869,908 4,641,037 (5,282) 5,522,232
-------------------------------------------------------------------------------------------
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) 190,997 867,811 4,775 1,047,629
-------------------------------------------------------------------------------------------
Interest charges (209,505) (62,992) (299,399) 264,202 (307,694)
Other income and (deductions) 621,151 (8,636) 54,315 (699,415) (32,585)
-------------------------------------------------------------------------------------------
Total Other Income and (Deductions) 411,646 (71,628) (245,084) (435,213) (340,279)
-------------------------------------------------------------------------------------------
Income Taxes (Benefit) (28,663) 40,796 269,148 - 281,281
-------------------------------------------------------------------------------------------
Earnings from Continuing Operations $ 424,355 $ 78,573 $ 353,579 $ (430,438) $ 426,069
Discontinued Operations - - (1,888) (1,888)
Cumulative Change in Accounting
Principle - - (37,451) - (37,451)
-------------------------------------------------------------------------------------------
Net Income $ 424,355 $ 78,573 $ 314,240 $ (430,438) $ 386,730
===========================================================================================
- ------------------------------------------------------------------------------------------------------------------------------
Statement of Income
- ------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2002
(In Thousands of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------
Revenues $ 463 $ 810,601 $ 4,654,573 $ (463) $ 5,465,174
---------------------------------------------------------------------------------------
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 1,572,615 - 1,631,297
Intercompany expense 2,772 79,826 (79,826) (2,772) -
Depreciation and amortization (44) 65,911 447,841 - 513,708
Operating taxes (2,149) 80,056 302,620 - 380,527
---------------------------------------------------------------------------------------
Total Operating Expenses 13,904 650,892 3,912,641 (2,772) 4,574,665
---------------------------------------------------------------------------------------
Gain on sale of property - 317 4,413 - 4,730
Income from equity investments 104 - 13,992 - 14,096
---------------------------------------------------------------------------------------
Operating Income (Loss) (13,337) 160,026 760,337 2,309 909,335
---------------------------------------------------------------------------------------
Interest charges (200,920) (62,520) (295,209) 257,145 (301,504)
Other income and (deductions) 565,262 7,835 60,106 (633,068) 135
---------------------------------------------------------------------------------------
Total Other Income and (Deductions) 364,342 (54,685) (235,103) (375,923) (301,369)
---------------------------------------------------------------------------------------
Income Taxes (Benefit) (26,683) 36,746 219,601 - 229,664
---------------------------------------------------------------------------------------
Earnings from Continuing Operations $ 377,688 $ 68,595 $ 305,633 $(373,614) $ 378,302
Discontinued Operations - - (614) - (614)
---------------------------------------------------------------------------------------
Net Income $ 377,688 $ 68,595 $ 305,019 $(373,614) $ 377,688
=======================================================================================
158
- -----------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
- -----------------------------------------------------------------------------------------------------------------------------------
December 31, 2004
(In Thousands of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- -----------------------------------------------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash and temporary cash investments $ 580,712 $ (894) $ 342,155 $ - $ 921,973
Accounts receivable, net 757 223,616 1,087,679 - 1,312,052
Other current assets 4,496 146,453 650,725 - 801,674
Assets of discontinued operations - - 42,923 42,923
-----------------------------------------------------------------------------------------
585,965 369,175 2,123,482 - 3,078,622
-----------------------------------------------------------------------------------------
Investments and others 4,567,314 2,039 169,063 (4,465,523) 272,893
-----------------------------------------------------------------------------------------
Property
Gas - 1,998,525 4,872,696 - 6,871,221
Other 13 - 2,987,720 - 2,987,733
Accumulated depreciation and depletion - (334,468) (2,465,305) - (2,799,773)
Property of discontinued operations - - 8,743 8,743
-----------------------------------------------------------------------------------------
13 1,664,057 5,403,854 - 7,067,924
-----------------------------------------------------------------------------------------
Intercompany Accounts Receivable 2,485,740 - 1,292,198 (3,777,938) -
Deferred Charges 381,300 221,393 2,341,998 - 2,944,691
-----------------------------------------------------------------------------------------
Total Assets $ 8,020,332 $ 2,256,664 $ 11,330,595 $ (8,243,461) $ 13,364,130
=========================================================================================
LIABILITIES AND CAPITALIZATION
Current Liabilities
Accounts payable $ 48,393 $ 111,551 $ 746,706 $ - $ 906,650
Commercial paper 912,246 - - - 912,246
Other current liabilities 294,642 167,201 (62,668) - 399,175
Liabilities of discontinued operations - - 64,245 64,245
-----------------------------------------------------------------------------------------
1,255,281 278,752 748,283 - 2,282,316
-----------------------------------------------------------------------------------------
Intercompany Accounts Payable - 101,345 2,147,777 (2,249,122) -
-----------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax (83,214) 298,062 909,281 - 1,124,129
Other deferred credits and liabilities 534,521 112,004 964,387 - 1,610,912
-----------------------------------------------------------------------------------------
451,307 410,066 1,873,668 - 2,735,041
-----------------------------------------------------------------------------------------
Capitalization
Common shareholders' equity 3,940,497 815,597 3,604,139 (4,465,523) 3,894,710
Preferred stock 19,700 - - - 19,700
Long-term debt 2,353,547 650,904 2,943,094 (1,528,816) 4,418,729
-----------------------------------------------------------------------------------------
Total Capitalization 6,313,744 1,466,501 6,547,233 (5,994,339) 8,333,139
-----------------------------------------------------------------------------------------
Minority Interest in Consolidated Companies - - 13,634 - 13,634
-----------------------------------------------------------------------------------------
Total Liabilities & Capitalization $ 8,020,332 $ 2,256,664 $ 11,330,595 $ (8,243,461) $ 13,364,130
=========================================================================================
- -----------------------------------------------------------------------------------------------------------------------------------
159
- -----------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
- -----------------------------------------------------------------------------------------------------------------------------------
December 31, 2003
(In Thousands of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- -----------------------------------------------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash and temporary cash investments $ 97,567 $ 1,554 $ 104,237 $ - $ 203,358
Accounts receivable, net 3,298 209,151 1,068,066 - 1,280,515
Other current assets 3,250 136,018 649,988 - 789,256
Assets of discontinued operations - - 114,196 114,196
--------------------------------------------------------------------------------------
104,115 346,723 1,936,487 - 2,387,325
--------------------------------------------------------------------------------------
Investments and others 4,475,949 1,123 153,520 (4,382,027) 248,565
--------------------------------------------------------------------------------------
Property
Gas - 1,899,375 4,622,876 - 6,522,251
Other - - 6,132,592 - 6,132,592
Accumulated depreciation and depletion - (355,376) (3,413,752) - (3,769,128)
Property of discontinued operations - - 8,588 8,588
--------------------------------------------------------------------------------------
- 1,543,999 7,350,304 - 8,894,303
--------------------------------------------------------------------------------------
Intercompany Accounts Receivable 3,105,571 - 1,274,283 (4,379,854) -
Deferred Charges 374,076 237,870 2,498,043 - 3,109,989
--------------------------------------------------------------------------------------
Total Assets $ 8,059,711 $ 2,129,715 $ 13,212,637 $ (8,761,881) $ 14,640,182
======================================================================================
LIABILITIES AND CAPITALIZATION
Current Liabilities
Accounts payable $ 125,892 $ 165,613 $ 773,989 $ - $ 1,065,494
Commercial paper 481,900 - - - 481,900
Other current liabilities 129,168 21,149 72,365 - 222,682
Liabilities of discontinued operations - - 82,204 82,204
--------------------------------------------------------------------------------------
736,960 186,762 928,558 - 1,852,280
--------------------------------------------------------------------------------------
Intercompany Accounts Payable - 116,197 2,679,091 (2,795,288) -
--------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax (48,059) 256,882 1,066,735 - 1,275,558
Other deferred credits and liabilities 532,062 136,747 968,814 - 1,637,623
--------------------------------------------------------------------------------------
484,003 393,629 2,035,549 - 2,913,181
--------------------------------------------------------------------------------------
Capitalization
Common shareholders' equity 3,707,785 782,223 3,562,675 (4,382,027) 3,670,656
Preferred stock 83,568 - - - 83,568
Long-term debt 3,047,395 650,904 3,497,215 (1,584,566) 5,610,948
--------------------------------------------------------------------------------------
Total Capitalization 6,838,748 1,433,127 7,059,890 (5,966,593) 9,365,172
--------------------------------------------------------------------------------------
Minority Interest in Subsidiary Companies - - 509,549 - 509,549
--------------------------------------------------------------------------------------
Total Liabilities & Capitalization $ 8,059,711 $ 2,129,715 $ 13,212,637 $ (8,761,881) $ 14,640,182
======================================================================================
- -----------------------------------------------------------------------------------------------------------------------------------
160
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2004
--------------------------------------------------------------------------
(In Thousands of Dollars) Guarantor KEDLI Other Subsidiaries Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net Cash (Used in) Provided by Operating Activities $ (88,676) $ 169,549 $ 669,196 $ 750,069
--------------------------------------------------------------------------
Investing Activities
Capital expenditures - (108,658) (641,671) (750,329)
Cost of removal - (7,140) (29,147) (36,287)
Proceeds from sale of property - - 20,159 20,159
Proceeds from sale of subsidiary stock - - 1,001,142 1,001,142
--------------------------------------------------------------------------
Net Cash (Used in) Provided by Investing Activities - (115,798) 350,483 234,685
--------------------------------------------------------------------------
Financing Activities
Treasury stock issued 33,406 - - 33,406
Issuance (payment) of debt, net (269,654) - (170,745) (440,399)
Redemption of preferred stock (8,483) - - (8,483)
Net proceeds from sale/leaseback transaction - - 382,049 382,049
Common and preferred stock dividends paid (291,148) - - (291,148)
Gain on interest rate swap 12,656 - - 12,656
Dividend paid to parent 447,590 (40,000) (407,590) -
Other 27,623 - 8,564 36,187
Net intercompany accounts 619,831 (16,199) (603,632) -
--------------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities 571,821 (56,199) (791,354) (275,732)
--------------------------------------------------------------------------
Net Increase in Cash and Cash Equivalents $ 483,145 $ (2,448) $ 228,325 $ 709,022
Net Cash Flow from Discontinued Operations - - 9,593 9,593
Cash and Cash Equivalents at Beginning of Period 97,567 1,554 104,237 203,358
--------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 580,712 $ (894) $ 342,155 $ 921,973
==========================================================================
- ------------------------------------------------------------------------------------------------------------------------------------
161
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2003
------------------------------------------------------------------------
(In Thousands of Dollars) Guarantor KEDLI Other Subsidiaries Consolidated
- -----------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net Cash (Used in) Provided by Operating Activities $ (547,516) $ 164,496 $ 1,606,376 $ 1,223,356
------------------------------------------------------------------------
Investing Activities
Capital expenditures - (130,275) (879,118) (1,009,393)
Cost of removal - (1,710) (29,393) (31,103)
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) (116,862) (825,308) (997,170)
------------------------------------------------------------------------
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)
(Payment) issuance of debt (133,797) - 120,222 (13,575)
Redemption of preferred stock - - (14,293) (14,293)
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) (739,407) (180,184)
------------------------------------------------------------------------
Net (Decrease) Increase in Cash and Cash Equivalents $ 9,259 $ (4,918) $ 41,661 $ 46,002
Net Cash from Discontinued Operations - - (13,261) (13,261)
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 $ 104,237 $ 203,358
========================================================================
- -----------------------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
- ---------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2002
-------------------------------------------------------------------------
(In Thousands of Dollars) Guarantor KEDLI Other Subsidiaries Consolidated
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net Cash (Used in) Provided by Operating Activities $ (97,981) $189,838 $ 655,806 $ 747,663
-------------------------------------------------------------------------
Investing Activities
Capital expenditures - (146,450) (911,057) (1,057,507)
Other - 903 151,358 152,261
Cost of removal - (883) (26,548) (27,431)
-------------------------------------------------------------------------
Net Cash (Used in) Investing Activities - (146,430) (786,247) (932,677)
-------------------------------------------------------------------------
Financing Activities
Treasury stock issued 86,710 - - 86,710
Issuance (payment) of debt, net 327,247 - (35,603) 291,644
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) 39,389 188,742
-------------------------------------------------------------------------
Net (Decrease) Increase in Cash and Cash Equivalents $ 88,308 $ 6,472 $ (91,052) $ 3,728
Net Cash Flow from Discontinued Operations - - 14,166 14,166
Cash and Cash Equivalents at Beginning of Period - - 152,723 152,723
-------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 88,308 $ 6,472 $ 75,837 $ 170,617
=========================================================================
- ---------------------------------------------------------------------------------------------------------------------------------
162
Note 15. Supplemental Gas and Oil Disclosures (Unaudited)
For December 31, 2003 and 2002 the following 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 and 34% in 2002. Gas and oil operations, and reserves, were located in the
United States in all years. As a result of the disposition of Houston
Exploration and the immateriality of KeySpan's ongoing gas exploration and
production activities supplemental gas and oil disclosures are not required for
2004.
Capitalized Costs Relating to Gas and Oil Producing Activities
- --------------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- --------------------------------------------------------------------------------------------------------------------------
At December 31, 2003 2002
- --------------------------------------------------------------------------------------------------------------------------
Unproved properties not being amortized $ 142,905 $ 110,623
Properties being amortized - productive and nonproductive 2,429,891 1,917,287
- --------------------------------------------------------------------------------------------------------------------------
Total capitalized costs 2,572,796 2,027,910
Accumulated depletion (1,159,509) (968,713)
- --------------------------------------------------------------------------------------------------------------------------
Net capitalized costs $ 1,413,287 $ 1,059,197
- --------------------------------------------------------------------------------------------------------------------------
Costs Incurred in Property Acquisition, Exploration and Development Activities
- -----------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- -----------------------------------------------------------------------------------------------
At December 31, 2003 2002
- -----------------------------------------------------------------------------------------------
Acquisition of properties -
Unproved properties $ 61,484 $ 14,600
Proved properties 171,297 90,004
Exploration 66,259 28,343
Development 170,493 139,108
Asset retirement obligation 31,858 -
- -----------------------------------------------------------------------------------------------
Total costs incurred $ 501,391 $ 272,055
- -----------------------------------------------------------------------------------------------
Costs included in development costs to develop proved undeveloped reserves for
the years ended December 31, 2003 and 2002 were $49.4 million, and $11.0
million, respectively.
Results of Operations from Gas and Oil Producing Activities*
- -------------------------------------------------------------------------------
(In Thousands of Dollars)
- -------------------------------------------------------------------------------
At December 31, 2003 2002
- -------------------------------------------------------------------------------
Revenues $ 497,948 $ 356,233
- -------------------------------------------------------------------------------
Production and lifting costs 63,591 44,822
Shipping and handling costs 10,388 9,450
Depletion 205,118 177,548
- -------------------------------------------------------------------------------
Total expenses 279,097 231,820
- -------------------------------------------------------------------------------
Income before taxes 218,851 124,414
Income taxes 76,598 42,519
- -------------------------------------------------------------------------------
Results of operations $ 142,253 $ 81,895
- -------------------------------------------------------------------------------
o (Excluding corporate overhead and interest costs)
163
Summary of Production and Lifting Costs
- ---------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- ---------------------------------------------------------------------------------------------
At December 31, 2003 2002
- ---------------------------------------------------------------------------------------------
Pumping, gauging and other labor $ 10,975 $ 7,846
Compressors and other rental equipment 5,136 4,135
Property taxes and insurance 7,155 6,801
Transportation 2,329 2,131
Processing fees 2,354 3,078
Workover and well stimulation 5,225 2,348
Repairs, maintenance and supplies 3,735 2,972
Fuel and chemicals 3,109 2,582
Environmental, regulatory and other 7,614 3,307
Severance taxes 15,959 9,622
- ---------------------------------------------------------------------------------------------
Total production and lifting costs $ 63,591 $ 44,822
- ---------------------------------------------------------------------------------------------
The gas and oil reserves information is based on estimates of proved reserves
attributable to the interest of Seneca-Upshur and KeySpan Exploration and
Production, LLC as of December 31, 2004. For December 31, 2003 and 2002 the gas
and oil reserves information reflects Houston Exploration and KeySpan
Exploration and Production, LLC. 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
- --------------------------------------------------------------------------------
Proved Reserves
Beginning of year 614,734 585,659
Revisions of previous estimates (32,433) (15,324)
Extensions and discoveries 140,632 105,798
Production (100,130) (107,507)
Purchases of reserves in place 89,380 48,777
Sales of reserves in place - (2,669)
- --------------------------------------------------------------------------------
Proved reserves - End of year (1) 712,183 614,734
Proved developed reserves
Beginning of year 435,629 448,921
End of Year (2) 488,012 435,629
- --------------------------------------------------------------------------------
(1) Includes minority interest of 318,417, and 208,516, in 2003 and 2002,
respectively.
(2) Includes minority interest of 218,190, and 148,811in 2003 and, 2002,
respectively.
164
Crude Oil, Condensate and Natural Gas Liquids (MBbls)
- -------------------------------------------------------------------------------
At December 31, 2003 2002
- -------------------------------------------------------------------------------
Proved reserves
Beginning of Year 9,548 10,234
Revisions of previous estimates (3,542) (5)
Extension and discoveries 117 342
Production (1,514) (1,025)
Purchases of reserves in place 3,753 483
Sales of reserves in place - (481)
- -------------------------------------------------------------------------------
Proved reserves - End of year (1) 8,362 9,548
Proved developed reserves
Beginning of year 2,413 2,479
End of year (2) 4,273 2,413
- -------------------------------------------------------------------------------
(1) Includes minority interest of 3,739 and 2,256 in 2003 and 2002,
respectively.
(2) Includes minority interest of 1,910 and 824 in 2003 and 2002, respectively.
The standardized measure of discounted future net cash flows was prepared by
applying year-end prices of gas and oil adjusted for the effects of KeySpan's
hedging program 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 Seneca-Upshur, KeySpan Exploration and Production LLC, or Houston
Exploration. 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
- ----------------------------------------------------------------------------------------------------------------------------
Future cash flows $ 4,375,781 $ 2,951,622
Future costs-
Production (769,892) (495,097)
Development (378,547) (263,926)
- ----------------------------------------------------------------------------------------------------------------------------
Future net inflows before income tax 3,227,342 2,192,599
Future income taxes (853,425) (559,853)
- ----------------------------------------------------------------------------------------------------------------------------
Future net cash flows 2,373,917 1,632,746
10% discount factor (853,403) (528,829)
- ----------------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows (1) $ 1,520,514 $ 1,103,917
- ----------------------------------------------------------------------------------------------------------------------------
(1) Includes minority interest of $672,620 and $361,435 in 2003 and 2002,
respectively
165
Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserve Quantities
- ------------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------------------
At December 31, 2003 2002
- ------------------------------------------------------------------------------------------------------------------------
Standardized measure - beginning of year $ 1,103,917 $ 586,186
Sales and transfers, net of production costs (492,328) (285,603)
Net change in sales and transfer prices, net
of production costs 384,299 589,632
Extensions and discoveries and improved
recovery, net of related costs 434,311 242,055
Changes in estimated future development costs (9,352) (6,453)
Development costs incurred during the period
that reduced future development costs 81,025 42,075
Revisions of quantity estimates (123,954) (36,368)
Accretion of discount 142,296 68,986
Net change in income taxes (236,551) (215,369)
Net purchases of reserves in place 254,030 99,741
Sales of reserves in place - (31,488)
Changes in production rates (timing) and other (17,179) 50,523
- ------------------------------------------------------------------------------------------------------------------------
Standardized measure - end of year $ 1,520,514 $ 1,103,917
- ------------------------------------------------------------------------------------------------------------------------
Average Sales Prices and Production Costs Per Unit
- ----------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2003 2002
- ----------------------------------------------------------------------------------------------------------------
Average Sales Price*
Natural gas ($/Mcf) 5.23 3.16
Oil, condensate and natural gas liquid ($/Bbl) 28.26 24.06
Production cost per equivalent Mcf ($) 0.58 0.42
- ----------------------------------------------------------------------------------------------------------------
*Represents the cash price received which excludes the effect of any hedging
transactions.
166
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, 2004.
Quarter Ended
- -----------------------------------------------------------------------------------------------------------------------------------
(In Thousands of Dollars, Except Per Share Amounts) 3/31/2004 6/30/2004 9/30/2004 12/31/2004
- -----------------------------------------------------------------------------------------------------------------------------------
Operating Revenue 2,510,592 1,277,806 975,544 1,886,524
Operating Income 487,627 122,158 (a) 87,613 (c) 237,872(e)
Earnings (loss) from continuing operations,
less preferred stock dividends 246,636 128,485 (a)(b) (30,133) (c)(d) 264,113(e)(f)
Earnings (loss) from discontinued operations (g) (401) 793 (87,006) (64,434)
Earnings (loss) for common stock 246,235 129,278 (117,139) 199,679
Basic earnings per common share from continuing operations
less preferred stock dividends 1.54 0.81 (0.19) 1.64
Basic earnings per common share from discontinued operations 0.00 0.00 (0.54) (0.40)
Basic earnings per common share 1.54 0.81 (0.73) 1.24
Diluted earnings per common share 1.53 0.80 (0.73) 1.23
Dividends declared 0.445 0.445 0.445 0.445
- -------------------------------------------------------------------------------------------------------------------------------
(a) KeySpan's wholly owned gas exploration and production subsidiaries recorded
a non-cash impairment charge of $48.2 million ($31.1 million after-tax) or $0.19
per share to recognize the reduced valuation of proved reserves.
(b) In June 2004, KeySpan exchanged 10.8 million shares of common stock of
Houston Exploration for 100% of the stock of Seneca Upshur Petroleum, Inc. We
recorded a gain of $150.1 million and were required to record deferred tax
expense of $44.1 million. The net gain on the share exchange less the deferred
tax provision was $106 million or $0.66 per share. In April 2004, KeySpan
recorded a gain of $22.8 million ($10.1 million after-tax) or $0.06 per share,
resulting from the sale of 35.9% of our ownership interest in KeySpan Canada.
(c) KeySpan recorded a $14.4 million ($12.6 million after-tax) or $0.08 per
share non-cash goodwill impairment charge associated with our continuing
investments in the Energy Services segment.
(d) In August 2004, we redeemed approximately $758 million of outstanding debt
and recorded a charge of $45.9 million ($29.3 million after-tax) or $0.18 per
share representing call premiums incurred on this redemption.
(e) In December 2004, we recorded a $26.5 million ($18.8 million after-tax) or
$0.12 per share non-cash impairment charge related to our 50% ownership interest
in Premier Transmission Pipeline.
(f) In November 2004, KeySpan decided to sell its remaining 6.6 million shares
of Houston Exploration. We recorded a gain of $179.6 million ($116.8 million
after-tax) or $0.73 per share. In December 2004, KeySpan sold its remaining
interest in KeySpan Canada. We recorded a gain of $35.8 million ($24.7 million
after tax) or $0.15 per share.
(g) At December 31, 2004, KeySpan intended to sell a significant portion of its
ownership interest in certain companies within the Energy Services segment,
specifically those companies engaged in mechanical contracting activities. As a
result, KeySpan recorded a loss in discontinued operations of $151.1 million, or
$0.94 per share. This loss reflects $139.9 million after-tax impairment charges,
which were recorded in the third and fourth quarters, and operating losses at
$11.2 million.
167
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 Revenue 2,423,482 1,307,366 1,032,532 1,772,144
Operating income 455,082 139,087 112,205 341,255
Earnings (loss) from continuing operations less preferred stock
dividends 240,684 (a) (7,089) (b) 13,407 173,223 (c)
Earnings (loss) from discontinued operations (e) 946 (310) (2,283) (241)
Cumulative change in accounting principle 174 - - (37,625) (d)
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 1.54 (0.05) 0.08 1.09
Basic earnings per common share from discontinued
operations (a) 0.00 0.00 (0.01) 0.00
Change in accounting principle 0.00 0.00 0.00 (0.24)
Basic earnings per common share 1.54 (0.05) 0.07 0.85
Diluted earnings per common share 1.53 (0.05) 0.07 0.84
Dividends declared 0.445 0.445 0.445 0.445
- ------------------------------------------------------------------------------------------------------------------------------------
(a) In February 2003, we reduced our ownership interest in Houston Exploration
from 66% to 56% following the repurchase, by Houston Exploration, of 3 million
shares of stock owned by KeySpan. This transaction resulted in an after-tax gain
of $19.0 million or $0.12 per share.
(b) In May 2003, we monetized 39% of our interest in KeySpan Canada, and sold
our 20% interest in Taylor NGL LP, a company that owns and operates extraction
plants in Canada. The transactions resulted in an after-tax loss of $34.1
million or $0.22 per share.
(c) In December 2003, we sold our 24.5% interest in Phoenix Natural Gas, a
natural gas distribution business in Northern Ireland. KeySpan recognized an
after-tax gain on the sale of $16.0 million per share or $.10 per share.
(d) As a result of the implementation of FASB Interpretation No. 46
"Consolidation of Variable Interest Entities", in December 2003, KeySpan
consolidated the Ravenswood Master Lease. KeySpan recorded a cumulative effect
change in accounting principle of $37.6 million or $0.23 per share, related to
"catch-up" depreciation of the facility since its acquisition in June 1999.
(e) In December 2004, KeySpan reflected certain Energy Services companies as
discontinued. Amounts for each of the quarters in the year 2003 have been
restated to reflect this presentation.
168
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of KeySpan Corporation
We have audited the accompanying Consolidated Balance Sheets and the
Consolidated Statement of Capitalization of KeySpan Corporation and subsidiaries
(the "Company") as of December 31, 2004 and 2003, 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, 2004. Our audits also
included the consolidated financial statement schedule included in the Index in
Item 15. These financial statements and the financial statement schedule are the
responsibility of the Company's management. Our responsibility is to express an
opinion on the financial statements and the financial statement schedule based
on our audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (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, such consolidated financial statements present fairly, in all
material respects, the financial position of KeySpan Corporation and
subsidiaries as of December 31, 2004 and 2003, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2004, in conformity with accounting principles generally accepted
in the United States of America. Also in our opinion, such consolidated
financial statement schedule, when considered in relation to the basic
consolidated financial statements taken as a whole, presents fairly in all
material respects, the information set forth therein.
As discussed in Note 1(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," 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-Transaction and Disclosure" and SFAS No. 143,
"Accounting for Asset Retirement Obligations", 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).
We have also audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the effectiveness of the Company's
internal control over financial reporting as of December 31, 2004, based on the
criteria established in Internal Control--Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission and our report
dated February 28, 2005, expressed an unqualified opinion on management's
assessment of the effectiveness of the Company's internal control over financial
reporting and an unqualified opinion on the effectiveness of the Company's
internal control over financial reporting.
/s/DELOITTE & TOUCHE LLP
February 28, 2005
New York, New York
169
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None
Item 9A. Controls and Procedures
We maintain disclosure controls and procedures (as defined under Exchange Act
Rule 13a-15(e)) that are designed to ensure that information required to be
disclosed by us in the reports we file or submit under 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
our Chief Executive Officer and Chief Financial Officer, as appropriate, to
allow timely decisions regarding required disclosure. Any control system, no
matter how well designed and operated, can provide only reasonable assurance of
achieving the desired control objectives. Our management, under the supervision
and with the participation of our Chief Executive Officer and Chief Financial
Officer, has evaluated the effectiveness of our disclosure controls and
procedures as of December 31, 2004. Based upon that evaluation, our Chief
Executive Officer and Chief Financial Officer concluded that the design and
operation of our disclosure controls and procedures provided reasonable
assurance that the disclosure controls and procedures are effective to
accomplish their objectives.
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, which has materially
affected, or is reasonably likely to materially affect, KeySpan's internal
control over financial reporting.
Management's Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal
control over financial reporting (as defined under Exchange Act Rule 13a-15(f)).
KeySpan's internal control over financial reporting is designed to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements, errors or fraud. Also, projections of
any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of or compliance with the policies or procedures may deteriorate.
Under the supervision and with participation of KeySpan's Chief Executive
Officer and Chief Financial Officer, our management assessed the effectiveness
of our internal control over financial reporting as of December 31, 2004. In
making this assessment, our management used the criteria set forth by the
Committee of Sponsoring Organizations of the Treadway Commission ("COSO") in a
report entitled Internal Control-Integrated Framework. Our management concluded,
as of December 31, 2004, that KeySpan's internal control over financial
reporting is effective based on the COSO criteria.
Our independent registered public accounting firm, Deloitte & Touche LLP, has
issued their report on management's assessment of KeySpan's internal control
over financial reporting as of December 31, 2004, which is included herein.
170
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of KeySpan Corporation:
We have audited management's assessment, included in the accompanying
Management's Report on Internal Control over Financial Reporting, that KeySpan
Corporation and subsidiaries (the "Company") maintained effective internal
control over financial reporting as of December 31, 2004, based on criteria
established in Internal Control--Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. The Company's management is
responsible for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting. Our responsibility is to express an opinion on management's
assessment and an opinion on the effectiveness of the Company's internal control
over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, evaluating management's assessment, testing and evaluating
the design and operating effectiveness of internal control, and performing such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed by,
or under the supervision of, the company's principal executive and principal
financial officers, or persons performing similar functions, and effected by the
company's board of directors, management, and other personnel to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.
171
Because of the inherent limitations of internal control over financial
reporting, including the possibility of collusion or improper management
override of controls, material misstatements due to error or fraud may not be
prevented or detected on a timely basis. Also, projections of any evaluation of
the effectiveness of the internal control over financial reporting to future
periods are subject to the risk that the controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
In our opinion, management's assessment that the Company maintained effective
internal control over financial reporting as of December 31, 2004, is fairly
stated, in all material respects, based on the criteria established in Internal
Control--Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Also in our opinion, the Company
maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2004, based on the criteria established in Internal
Control--Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the Consolidated financial
statements and financial statement schedule as of and for the year ended
December 31, 2004, of the Company and our report dated February 28, 2005
expressed an unqualified opinion on those financial statements and financial
statement schedule.
/s/DELOITTE & TOUCHE LLP
February 28, 2005
New York, New York
172
Item 9B. Other Information
The following disclosures would otherwise have been filed on Form 8-K under the
heading "Item 1.01 - Entry into a Material Definitive Agreement".
On February 24, 2005, following the recommendation of the Compensation and
Management Development Committee (the "Compensation Committee"), KeySpan's Board
of Directors set the 2005 annual base salaries for Robert B. Catell, Robert J.
Fani, Wallace P. Parker Jr., Steven L. Zelkowitz and Gerald Luterman, each of
whom is a KeySpan named executive officer. Such 2005 base salaries are as
follows: Mr. Catell - $1,075,000, Mr. Fani - $734,000, Mr. Parker - $587,000,
Mr. Zelkowitz - $545,000, and Mr. Luterman - $467,000. For further information
regarding executive compensation, see "Item 11. Executive Compensation," herein.
In December 2004, the Board approved the compensation formulas for
performance-based incentive awards that may be paid to our executive officers
for the fiscal year ending December 31, 2005 ("Fiscal 2005") under the KeySpan
Corporate Annual Incentive Compensation Plan (the "Corporate Plan").
Performance-based incentive awards as a percentage of cumulative base salary are
based upon earnings per share, cash flow, business unit operating income, a
diversity initiative, customer satisfaction and other individual strategic
initiatives. Award amounts will be calculated for each participant based on the
attainment of the indicated financial and performance measures and may be
adjusted by the Compensation Committee at its discretion. For Fiscal 2005, the
performance-based target award levels for each of the named executive officers
have been increased. Further information regarding the target award levels for
Fiscal 2005 is contained in Exhibit 10.20-b filed herewith and incorporated by
reference herein.
Also in December 2004, the Compensation Committee approved the compensation
formulas for performance-based equity awards that may be granted to our
executive officers for Fiscal 2005 under the KeySpan Long-Term Performance
Incentive Compensation Plan (the "Long-Term Incentive Plan"). Target award
levels have been modified to align closer with industry benchmarks at 50th
percentile levels. Equity awards granted under the Long-Term Incentive Plan
include a cumulative three-year total shareholder return ("TSR") goal. The TSR
goal measures the total return to shareholders of KeySpan Common Stock,
including price appreciation and dividends. KeySpan's performance will be
measured against the S&P Utility Group over a three-year performance period,
with the goal for KeySpan's TSR to be at or above the median of those companies
comprising the group. For Fiscal 2005, the performance-based target award levels
for each of the named executive officers have been modified. Further information
regarding the target award levels for Fiscal 2005 is contained in Exhibit
10.22-b filed herewith and incorporated by reference herein.
For the fiscal year ending December 31, 2004, the Corporate Plan provided for
award opportunities to the named executive officers with performance criteria
based upon earnings per share, cash flow, business unit operating income, a
diversity initiative, customer satisfaction and other individual strategic
initiatives. Based upon actual 2004 performance, an award payout for each of the
named executive officers was approved by the Board on February 24, 2005, as
follows: Mr. Catell - $1,047,344, Mr. Fani - $545,574, Mr. Parker - $361,903,
Mr. Zelkowitz - $372,769, and Mr. Luterman - $262,355.
173
With respect to the Long Term Incentive Plan awards, on February 24, 2005, the
Compensation Committee approved grants to the named executive officers based on
actual 2004 performance as follows: Mr. Catell - 80,700 performance shares; Mr.
Fani - 125,800 non-qualified stock options and 16,300 performance shares; Mr.
Parker - 88,600 non-qualified stock options and 11,400 performance shares; Mr.
Zelkowitz - 88,600 non-qualified stock options and 11,400 performance shares;
and Mr. Luterman - 54,800 non-qualified stock options, 5,000 shares of
restricted stock and 7,100 performance shares.
The options shall vest pro-rata over a five-year period with a ten year exercise
period from the date of grant. Vesting will accelerate in the third year upon
achievement of KeySpan's cumulative three-year TSR goal. In the event of
retirement, the options shall vest pro-rata using the number of full months of
employment from the grant date to retirement, divided by 36 months.
With respect to the performance shares, at threshold performance, 50% of the
award shall be earned; at target, 100% of the award shall be earned; and at
maximum, 150% of the award shall be earned. If the threshold level of
performance is not achieved all shares granted shall be forfeited. In the event
of retirement, performance shares shall be distributed based upon results
achieved at the end of the performance period and pro-rated through the date of
retirement.
On February 25, 2005, KeySpan entered into an employment agreement with Mr.
Catell relating to his services as Chairman and Chief Executive Officer. The
employment agreement supersedes all prior agreements between the parties and
provides for, among other things, an extension of Mr. Catell's employment term
until July 31, 2006 (or, in the event of a change of control, until two years
following the consummation of the transaction resulting in such change of
control), a minimum annual base salary, as well as participation in the
Company's annual and long term incentive compensation plans. Upon termination of
employment for any reason other than cause, death or disability, Mr. Catell will
be entitled to payment of certain compensation accruable through the term of the
agreement. A copy of Mr. Catell's employment agreement is filed herewith as
Exhibit 10.10 and incorporated herein by reference.
On February 25, 2005, subsidiaries of KeySpan entered into a Share Sale and
Purchase Agreement with BG Energy Holdings Limited and Premier Transmission
Financing plc ("PTF"), pursuant to which all of the outstanding shares of
Premier are to be purchased by PTF. It is expected that the sale of our 50%
interest in Premier will result in proceeds of approximately $42.5 million. It
is anticipated that the closing of this transaction will occur before the end of
the second quarter.
The following disclosure would otherwise have been filed on Form 8-K under the
heading "Item 5.02 - Departure of Directors or Principal Officers; Election of
Directors; Appointment of Principal Officers."
On February 24, 2005 Mr. Bodanza was elected by the Board to serve as Senior
Vice President, Regulatory Affairs and Asset Optimization effective March 1,
2005. Mr. Bodanza previously served as Chief Accounting Officer. Also on
February 24, 2005, the Board elected Theresa A. Balog as Vice President and
Chief Accounting Officer of KeySpan Corporation, effective March 1, 2005. Ms.
174
Balog, age 43, 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.
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 29,
2005 (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
"Compliance with Section 16(a) of the Exchange Act" contained in the Proxy
Statement, which information is incorporated herein by reference thereto.
Item 11. Executive Compensation
The information required by this item is set forth under the captions "Director
Compensation" and "Executive Compensation" in the Proxy Statement, which
information is incorporated herein by reference thereto.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The information required by this item is set forth under the captions "Security
Ownership of Management" and "Security Ownership of Certain Beneficial Owners"
in the Proxy Statement, and in 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 herein by reference thereto.
Item 14. Principal Accountant Fees and Services
The information required by this item is set forth under the caption "Proposal
2. Ratification of Deloitte & Touche LLP as Independent Registered Public
Accounting Firm," "Fiscal Year 2004 Audit Firm Fee Summary" and "Report of the
Audit Committee" in the Proxy Statement, which information is incorporated
herein by reference thereto.
175
Item 15. Exhibits and Financial Statement Schedules
(a) Required Documents
1. Financial Statements
The following consolidated financial statements of KeySpan and its subsidiaries
and Reports of the Independent Registered Public Accounting Firm are included in
Item 8 and are filed as part of this Report:
o Consolidated Statement of Income for the year ended December 31, 2004, the
year ended December 31, 2003, and the year ended December 31, 2002
o Consolidated Statement of Retained Earnings for the year ended December 31,
2004, the year ended December 31, 2003, and the year ended December 31,
2002
o Consolidated Balance Sheet at December 31, 2004 and December 31, 2003
o Consolidated Statement of Capitalization at December 31, 2004 and December
31, 2003
o Consolidated Statement of Cash Flows for the year ended December 31, 2004,
the year ended December 31, 2003, and the year ended December 31, 2002
o Consolidated Statement of Comprehensive Income for the Year ended December
31, 2004, the year ended December 31, 2003 and the year ended December 31,
2002
o Notes to Consolidated Financial Statements
o Reports of the Independent Registered Public Accounting Firm
176
2. Financial Statement Schedules
Consolidated Schedule of Valuation and Qualifying Accounts for the year ended
December 31, 2004, the year ended December 31, 2003, and the year ended December
31, 2002.
SCHEDULE OF VALUATION AND QUALIFYING ACCOUNTS
- -----------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
- -----------------------------------------------------------------------------------------------------------------------
Descriptions Balance at Charged to Balance at
Beginning of costs and Net End of
Period expenses Deductions Period
- -----------------------------------------------------------------------------------------------------------------------
Twelve Months Ended December 31, 2004
- -------------------------------------
Deducted from asset accounts:
Allowance for doubtful accounts* $ 75,671 $ 74,089 $ 81,964 $ 67,796
Additions to liability accounts:
Reserve for injury and damages $ 9,370 $ - $ - $ 9,370
Reserve for environmental expenditures $ 294,691 $ - $ 37,902 $ 256,789
Twelve Months Ended December 31, 2003
- -------------------------------------
Deducted from asset accounts:
Allowance for doubtful accounts* $ 60,111 $ 82,120 $ 66,560 $ 75,671
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 $ 71,127 $ 60,111
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
*Reflects discontinued operations
All other schedules are omitted because they are not applicable or the required
information is shown in the financial statements or notes thereto.
(b) 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.
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)
177
3.2 By-Laws 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 7.625%
notes issued on November 20, 2000 (filed as Exhibit 4-c to the
Company's Form 8-K on November 20, 2000)
4.1-c 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)
4.2-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. and Citibank, N.A., as co-syndication agents, The Bank
of New York and The Royal Bank of Scotland plc, as co-documentation
agents, and JPMorgan Chase Bank, as administrative agent for $640
million, dated as of June 30, 2004 (filed as Exhibit 4.1 to the
Company's Form 10-Q for the quarterly period ended June 30, 2004)
4.4-a 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 JP 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)
178
4.4-b First Amendment to Credit Agreement dated as of June 27, 2003 among
KeySpan Corporation, the several Lenders, Citibank N.A., as
Syndication Agent, The Bank of New York and The Royal Bank of Scotland
plc, as co-documentation agents, and JPMorgan Chase Bank, as
administrative agent to reduce the amount from $850 million to $660
million, dated as of June 25, 2004 (filed as Exhibit 4.2 to the
Company's Form 10-Q for the quarterly period ended June 30, 2004)
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)
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)
179
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)
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)
180
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 (filed as Exhibit 4.14-a to the Company's
Form 10-K for the year ended December 31, 2003)
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 (filed as Exhibit 4.14-b to the
Company's Form 10-K for the year ended December 31, 2003)
4.14-c Guaranty, dated as of November 26, 2003, from KeySpan Corporation to
the Suffolk County Industrial Development Agency (filed as Exhibit
4.14-c to the Company's Form 10-K for the year ended December 31,
2003)
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 (filed as Exhibit 4.15-a to the Company's Form 10-K
for the year ended December 31, 2003)
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 (filed as Exhibit 4.15-b to the Company's Form 10-K
for the year ended December 31, 2003)
181
4.15-c Guaranty, dated as of November 26, 2003, from KeySpan Corporation to
the Nassau County Industrial Development Agency (filed as Exhibit
4.14-c to the Company's Form 10-K for the year ended December 31,
2003)
4.16 Indenture, dated as of December 1, 1989, between Boston Gas Company
and The Bank of New York, as 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 quarterly
period ended June 30, 1990)
4.25 Letter of Credit and Reimbursement Agreement, dated December 9, 2003,
by and between KeySpan Generation LLC and Royal Bank of Scotland Bank
PLC (filed as Exhibit 4.34 to the Company's Form 10-K for the year
ended December 31, 2003)
182
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)
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)
183
10.8** * Cash Compensation for Non-Management Directors of KeySpan
10.9** * Base Salaries of Named Executive Officers of KeySpan in effect as of
February 24, 2005
10.10** * Employment Agreement, dated February 24, 2005, between KeySpan
Corporation and Robert B. Catell
10.11** Employment Agreement, dated January 1, 2005, between KeySpan and
Anthony Sartor (filed as Exhibit 10.01 to the Company's Form 8-K dated
as of January 4, 2005)
10.12** Supplemental Retirement Agreement, dated January 1, 2005, between
KeySpan and Anthony Sartor (filed as Exhibit 10.12 to Company's Form
8-K dated as of January 4, 2005)
10.13** 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)
10.14** 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)
10.15** 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)
10.16** 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)
10.17** Directors' Deferred Compensation Plan effective April 2003 (filed as
Exhibit 10.16 to the Company's Form 10-K for the year ended December
31, 2003)
10.18** 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)
10.19** Officers' Deferred Stock Unit Plan of 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)
184
10.20-a** 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-b** * Corporate Annual Incentive Compensation Plan Target Performance
Award Level for Fiscal 2005
10.21** Senior Executive Change of Control Severance Plan effective as of
October 29, 2003 (filed as Exhibit 10.20 to the Company's Annual
Report on Form 10-K for the year ended December 31, 2003)
10.22-a** 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-b** * KeySpan's Long-Term Performance Incentive Compensation Plan
Target Performance Award Level for Fiscal 2005
10.23 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)
10.24 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)
10.25 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)
10.26 KeySpan Guaranty, dated May 25, 2004, relating to the 250 MW
Ravenswood expansion plant (filed as Exhibit 10.1 to the Company's
Form 10-Q for the quarterly period ended June 30, 2004)
10.27 Facility Lease Agreement, dated as of May 25, 2004, between SE
Ravenswood Trust, a Delaware statutory trust, and KeySpan-Ravenswood,
LLC relating to the 250 MW Ravenswood expansion plant (filed as
Exhibit 10.2 to the Company's Form 10-Q for the quarterly period ended
June 30, 2004)
10.28 Site Lease and Easement Agreement, dated as of May 25, 2004, between
KeySpan-Ravenswood, LLC and SE Ravenswood Trust relating to the 250 MW
Ravenswood expansion plant (filed as Exhibit 10.3 to the Company's
Form 10-Q for the quarterly period ended June 30, 2004)
10.29 Site Sublease, dated as of May 25, 2004, between SE Ravenswood Trust
and KeySpan-Ravenswood, LLC relating to the 250 MW Ravenswood
expansion plant (filed as Exhibit 10.4 to the Company's Form 10-Q for
the quarterly period ended June 30, 2004)
185
10.30 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)
10.31 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)
10.32 Distribution Agreement, dated June 2, 2004, by and among The Houston
Exploration Company, Seneca-Upshur Petroleum, Inc., THEC Holdings
Corp. and KeySpan Corporation (filed as Exhibit 99.2 to The Houston
Exploration Company's Form 8-K dated as of June 3, 2004)
10.33 Asset Contribution Agreement, dated June 2, 2004, between The Houston
Exploration Company and Seneca-Upshur Petroleum, Inc. (filed as
Exhibit 99.3 to The Houston Exploration Company's Form 8-K dated as of
June 3, 2004)
10.34 Tax Matters Agreement, dated June 2, 2004, by and among The Houston
Exploration Company, Seneca-Upshur Petroleum, Inc., THEC Holdings
Corp. and KeySpan Corporation (filed as Exhibit 99.4 to The Houston
Exploration Company's Form 8-K dated as of June 3, 2004).
10.35* Purchase Agreement, dated January 28, 2005, among Robert B. Snyder,
Frank J. Sullivan, Robert B. Snyder, Jr., Philip J. Andreoli, William
J. McKean, Binsky & Snyder, LLC, Binsky & Snyder Service, LLC and
KeySpan Business Solutions, LLC
10.36* Purchase Agreement, dated February 11, 2005, among WDF Holding Corp.,
WDF, Inc. and KeySpan Business Solutions, LLC
10.37* Share Sale and Purchase Agreement dated February 25, 2005 with BG
Energy Holdings Limited and Premier Transmission Financing Public
Limited Company
14* Code of Ethics (filed as Exhibit 14 to the Company's Form 10-K for the
year ended December 31, 2003).
21* Subsidiaries of the Registrant
23.1* Consent of Deloitte & Touche LLP, Independent Registered Public
Accounting Firm
23.2* Consent of Netherland, Sewell & Associates, Inc., Independent
Petroleum Consultants
186
23.3* Consent of Miller and Lents, Ltd., Independent Petroleum Consultants
24.1* Power of Attorney executed by Andrea S. Christensen on February 24,
2005
24.2* Power of Attorney executed by Robert J. Fani on February 24, 2005
24.3* Power of Attorney executed by Alan H. Fishman on February 24, 2005
24.4* Power of Attorney executed by James R. Jones on February 24, 2005
24.5* Power of Attorney executed by James L. Larocca on February 24, 2005
24.6* Power of Attorney executed by Gloria C. Larson on February 24, 2005
24.7* Power of Attorney executed by Stephen W. McKessy on February 24, 2005
24.8* Power of Attorney executed by Edward D. Miller on February 24, 2005
24.9* Power of Attorney executed by Vikki L. Pryor on February 24, 2005
24.10* 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
187
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
- ---------------------
Theresa A. Balog Vice President and
Chief Accounting Officer
By:/s/Theresa A. Balog
--------------------
*
- --------------------
Andrea S. Christensen Director
*
- ----------------------
Robert J. Fani Director
*
- --------------------
Alan H. Fishman Director
188
*
- --------------------
James R. Jones Director
*
- --------------------
Gloria C. Larson Director
*
- --------------------
James L. Larocca Director
*
- --------------------
Stephen W. McKessy Director
*
- --------------------
Edward D. Miller Director
*
- --------------------
Vikki L. 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
189