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
For the fiscal year ended December 31, 2005
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
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None
(Title of class)
Indicate by check mark if the registrant is a well known seasoned issuer,
as defined in Rule 405 of the Securities Act.
X Yes ___No
Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Act.
___Yes X No
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 (ss. 229.405 of this chapter) 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.
___Yes X No
Indicate by check mark whether the registrant is a large accelerated filer,
or a non-accelerated filler.
Large accelerated filer X Accelerated filer__ Non-accelerated filer__
Indicate by check mark whether the registrant is a shell company (as
defined in Rule 12b-2 of the Act).
___Yes X No
The aggregate market value of the voting and non-voting common equity held
by non-affiliates (174,014,400 shares) of the registrant was $7,150,251,696
based on the closing price of the New York Stock Exchange on February 23, 2006,
of $41.09 per share.
As of February 23, 2006, there were 174,573,840 shares of common stock,
$.01 par value, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
The Proxy Statement dated on or about March 31, 2006 is incorporated by
reference into Part III, Items 10, 11, 12 and 13 hereof.
KEYSPAN CORPORATION
INDEX TO FORM 10-K
Page
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PART I
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ITEM 1. BUSINESS............................................................................................1
ITEM 1A RISK FACTORS........................................................................................28
ITEM 1B UNRESOLVED STAFF COMMENTS...........................................................................35
ITEM 2. PROPERTIES..........................................................................................35
ITEM 3. LEGAL PROCEEDINGS...................................................................................35
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.................................................35
PART II
-------
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES...........................................................36
ITEM 6. SELECTED FINANCIAL DATA.............................................................................38
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION................39
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK..........................................98
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.........................................................95
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS..........................................................104
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES.....................................................104
NOTE 2. BUSINESS SEGMENTS..............................................................................122
NOTE 3. INCOME TAX.....................................................................................127
NOTE 4. POSTRETIREMENT BENEFITS........................................................................128
NOTE 5. CAPITAL STOCK..................................................................................133
NOTE 6. LONG-TERM DEBT AND COMMERCIAL PAPER............................................................134
NOTE 7. CONTRACTUAL OBLIGATIONS, FINANCIAL GUARANTEES
AND CONTINGENCIES.......................................................................138
NOTE 8. HEDGING, DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUES......................................149
NOTE 9. GAS EXPLORATION AND PRODUCTION PROPERTY - DEPLETION............................................153
NOTE 10. ENERGY SERVICES- DISCONTINUED OPERATIONS......................................................154
NOTE 11. 2006 LIPA SETTLEMENT..........................................................................156
NOTE 12. SUBSEQUENT EVENTS.............................................................................158
NOTE 13. KEYSPAN GAS EAST CORPORATION SUMMARY FINANCIAL DATA...........................................159
NOTE 14. SUPPLEMENTAL GAS AND OIL DISCLOSURES (UNAUDITED) .............................................165
NOTE 15. SUMMARY OF QUARTERLY INFORMATION (UNAUDITED) .................................................168
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE...............................................................................171
ITEM 9A. CONTROLS AND PROCEDURES............................................................................171
ITEM 9B. OTHER INFORMATION..................................................................................175
PART III
--------
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.................................................177
ITEM 11. EXECUTIVE COMPENSATION.............................................................................177
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS........................................................................177
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.....................................................177
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES ...........................................................177
PART I
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ITEM 1. BUSINESS
CORPORATE OVERVIEW
KeySpan Corporation ("KeySpan") is a member of the Standard and Poor's 500
Index. KeySpan is a New York corporation and a holding company under the Public
Utility Holding Company Act of 2005 ("PUHCA 2005"). 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. We also own, lease 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 operating subsidiaries are primarily involved in gas exploration
and production; underground gas storage; liquefied natural gas ("LNG") storage;
retail electric marketing; large energy-system ownership, installation and
management; service and maintenance of energy systems; and engineering and
consulting services. We also invest and participate in the development of
natural gas pipelines, electric generation and other energy-related projects.
Recent Developments
- -------------------
On February 25, 2006, Keyspan entered into an Agreement and Plan of Merger (the
"Merger Agreement"), with National Grid PLC, a public limited company
incorporated under the laws of England and Wales ("Parent") and National Grid
USA, Inc, a New York Corporation ("Merger Sub"), pursuant to which Merger Sub
will merge with and into KeySpan (the "Merger"), with KeySpan continuing as the
surviving Company. Pursuant to the Merger Agreement, at the effective time of
the Merger, each outstanding share of common stock, par value $.01 per share of
KeySpan (the "Shares"), other than shares owned by KeySpan, shall be canceled
and shall be converted into the right to receive $42.00 in cash, without
interest.
Consummation of the Merger is subject to various closing conditions, including
but not limited to the satisfaction or waiver of conditions regarding the
receipt of requisite regulatory approvals and the adoption of the Merger
Agreement by the stockholders of KeySpan and the Parent. Assuming receipt or
waiver of the foregoing, it is currently anticipated that the Merger will be
consummated in early 2007. Accordingly, any statements contained herein
concerning expectations, beliefs, plans, objectives, goals, strategies, future
events or performance and underlying assumptions are "forward-looking
statements" and do not take into account the occurrence or impact of any
potential strategic transaction on the future operations, financial condition
and cash flows of KeySpan. However, no assurance can be given that the Merger
will occur, or, the timing of its completion.
At December 31, 2005, KeySpan was a holding company under the Public Utility
Holding Company Act of 1935, as amended ("PUHCA 1935"). In August 2005, the
Energy Policy Act of 2005 (the "Energy Act") was enacted. The Energy Act is a
broad energy bill that places an increased emphasis on the production of energy
and promotes the development of new technologies and alternative energy sources
and provides tax credits to companies that produce natural gas, oil, coal,
electricity and renewable energy. For KeySpan, one of the more significant
provisions of the Energy Act was the repeal of PUHCA 1935, which became
effective on February 8, 2006. Since that time, the jurisdiction of the
Securities and Exchange Commission ("SEC") over certain holding company
activities, including the regulation of our affiliate transactions and service
companies, has been transferred to the jurisdiction of the Federal Energy
Regulatory Commission ("FERC") pursuant to PUHCA 2005. See "Regulation and Rate
Matters" for additional information on the Energy Act and PUHCA 2005. 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.
1
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 business segments: 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 LIPA; provide generating
capacity and, to the extent required, energy conversion services for LIPA from
our approximately 4,200 megawatts ("MW") of generating facilities located on
Long Island; and manage fuel supplies for LIPA to fuel our Long Island
generating facilities. The Electric Services segment also includes subsidiaries
that own, lease and operate the 2,200 MW Ravenswood electric generation facility
(the "Ravenswood Facility"), located in Queens County in New York City, and the
250 MW combined cycle generating unit (the "Ravenswood Expansion") which began
full commercial operation in May 2004 (collectively, the Ravenswood Facility and
the Ravenswood Expansion are referred to herein as the "Ravenswood Generating
Station" and have a total electric capacity of 2,450 MW). Moreover, subsidiaries
in this segment also provide retail marketing of electricity to commercial
customers.
The Energy Services segment provides energy-related services to customers
primarily located within the Northeastern United States, with concentrations in
the New York City and Boston metropolitan areas. During January and February
2005, we disposed of our ownership interests in companies engaged in mechanical
contracting activities under this segment.
The Energy Investments segment includes our gas exploration and production
activities, domestic pipelines, gas storage facilities and LNG facilities and
operations.
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 it 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.
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. You may also read
and copy any of these documents at the SEC's public reference room at 100 F
Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for
further information on the public reference room. Our SEC filings are also
available to the public on the SEC's web site at www.sec.gov.
2
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
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.
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. In New
York, 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. In Massachusetts
and New Hampshire, there are mandatory capacity assignment programs in place
whereby capacity is released to natural gas marketers on behalf of customers
they serve. 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.
3
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 a utility tariff that contains a weather
normalization adjustment that significantly offsets variations in firm net
revenues due to fluctuations in normal weather. However, the tariffs for our
four KEDNE gas distribution companies do not contain such a weather
normalization adjustment and, therefore, fluctuations in seasonal weather
conditions between years may have a significant effect on results of operations
and cash flows for these four subsidiaries. We utilize weather derivatives for
KEDNE to mitigate variations in firm net revenues due to fluctuations in
weather.
New York Gas Distribution Systems - KEDNY and KEDLY 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 2,093 MDTH (one MDTH equals 1,000 DTH or 1 billion British Thermal
Units) of gas for a peak-day during the 2005/06 winter season and that the gas
available to us on such a peak-day amounts to approximately 2,177 MDTH.
4
The highest daily throughput most recently experienced occurred on January 15,
2006 in which the demand of the firm New York customers was 1,654 MDTH, and the
average temperature was 20(degree)F. KEDNY and KEDLI have sufficient gas supply
available to meet the requirements of their firm gas customers for the 2005/06
winter season.
Our New York firm gas peak-day capability is summarized in the following table:
MDTH per % of
Source day Total
- ----------------------------------------------------------
Pipeline 842 39%
Underground Storage 800 37%
Peaking Supplies 535 24%
--- ---
Total 2,177 100%
========== =========
Pipelines. Our New York based gas distribution utilities purchase natural gas
for sale under contracts with suppliers of 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
2005/06 gas year, approximately 73% of our New York natural gas supply was
available from domestic sources and 27% from Canadian sources. We have available
under firm contract 842 MDTH per day of year-round and seasonal pipeline
transportation capacity. Our major providers of interstate pipeline capacity and
related services include: Transcontinental Gas Pipe Line Corporation
("Transco"), Texas Eastern Transmission Corporation ("Tetco"), Iroquois Gas
Transmission System, L.P. ("Iroquois"), Tennessee Gas Pipeline Company
("Tennessee"), Dominion Transmission Incorporated ("Dominion"), and Texas Gas
Transmission Company.
Underground Storage. In order to meet winter demand in our New York service
territories, we also have long-term contracts with Transco, Tetco, Tennessee,
Dominion, Equitrans, Inc., National Fuel Gas Supply Corporation ("National
Fuel") and Honeoye Storage Corporation ("Honeoye") for underground storage
capacity of 60,766 MDTH and 800 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 LNG plants; (ii)
peaking supply contracts with dual-fuel power producers located in our franchise
areas; and (iii) peaking supply contracts with suppliers located outside our
franchise area. For the 2005/06 winter season, we have the capability to provide
maximum peaking supplies of 535 MDTH on extremely 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 dual fuel power producers
provide us with peak-day capacity of 140 MDTH and winter season availability of
3,446 MDTH.
Gas Supply Management. We currently perform our New York-based gas supply
management services internally.
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.
5
Combined Gas Supply Portfolios. Effective November 1, 2005 the New York
Department of Public Service authorized KEDNY and KEDLI to combine the planning,
management and utilization of their respective gas supply portfolios to enable
each company to serve its customers more reliably and cost effectively.
Specifically, these companies plan the acquisition of incremental pipeline
capacity, underground storage, gas supply and peaking supply contracts to meet
projected growth in firm customer demand on a combined portfolio basis. This
approach enables these companies to realize synergies that would otherwise not
be attainable if they were to plan independently for the development of their
respective portfolios. These two companies, by virtue of their geographic
proximity, complementary customer demand profiles and similar gas contracts are
able to add incremental capacity more effectively to meet expected customer
demand growth by planning the portfolios on a combined basis.
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, 2006, 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.
New England Gas Distribution Systems - KEDNE 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.
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 England gas systems assumes
an average temperature of -6(0)F in Massachusetts and -8(0)F in New Hampshire
for peak-day demand. Under such criteria, we estimate that the requirements to
supply our firm gas customers would amount to approximately 1,361 MDTH of gas
for a peak-day during the 2005/06 winter season and that the gas available to us
on such a peak-day amounts to approximately 1,420 MDTH.
The highest daily throughput most recently experienced occurred on January 15,
2006 in which the demand of the firm New England customers (which includes both
firm sales and firm transportation) was 1,015 MDTH, and the average temperature
was 15*F. KEDNE has sufficient gas supply available to meet the requirements of
their firm gas customers for the 2005/06 winter season.
6
Our New England firm gas peak-day capability is summarized in the following
table:
MDTH % of
Source per day 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 of natural gas located in domestic and
Canadian supply basins and arrange for transportation to our 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 pipeline
transportation capacity. Our major providers of interstate pipeline capacity and
related services include: Algonquin Gas Transmission Company, Iroquois,
Maritimes and Northeast Pipelines, Portland Natural Gas Transmission System,
Tennessee and Tetco.
Underground Storage. In order to meet winter demand in our New England service
territories, we also have long-term contracts with Tetco, Tennessee, Dominion,
National Fuel and Honeoye for underground storage capacity of 23,280 MDTH and
248 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) local production
plants that store LNG and liquid propane until vaporized, which are located
strategically across the service territory; (ii) contracts for LNG storage and
delivery with our LNG subsidiary, KeySpan LNG LP, located in Providence, Rhode
Island; and (iii) Distrigas of Massachusetts located in Everett, Massachusetts.
For the 2005/06 winter season, we have the capability to provide maximum peaking
supplies of 672 MDTH on extremely cold days.
Gas Supply Management. From April 1, 2002 through March 31, 2005, we had an
agreement with Coral Resources, L.P. ("Coral"), a subsidiary of Shell Oil
Company, under which Coral assisted in the origination, structuring, valuation
and execution of energy-related transactions on behalf of KEDNY and KEDLI. Upon
the expiration of this agreement, these services are provided by 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 has a three year
term expiring on March 31, 2006. A new three year agreement has been negotiated
between Merrill Lynch and the Massachusetts KEDNE utilities, whereby Merrill
Lynch will assist in the origination, structuring, valuation and execution of
energy related transactions for the Massachusetts portfolio. This agreement is
pending approval by the Massachusetts Department of Telecommunications and
Energy ("MADTE"). In New Hampshire, these services will be provided by KeySpan
employees.
7
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.
For additional information and for financial 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"
and Note 2 to the Consolidated Financial Statements, "Business Segments".
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. The Ravenswood Generating Station 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 a third party.
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 T&D system pursuant to a Management
Services Agreement (the "1998 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 "1998 PSA"); 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 "1998 EMA").
The 1998 MSA, 1998 PSA and 1998 EMA became effective on May 28, 1998 and are
collectively referred to herein as the "1998 LIPA Agreements."
On February 1, 2006, KeySpan and LIPA entered into (i) an amended and restated
Management Services Agreement (the "2006 MSA"), pursuant to which KeySpan will
continue to operate and maintain the electric T&D System owned by LIPA on Long
Island; (ii) a new Option and Purchase and Sale Agreement (the "2006 Option
Agreement"), which allows LIPA to purchase either or both of KeySpan's Barrett
and Far Rockaway generating stations and which replaces the Generation Purchase
Rights Agreement (the "GPRA"), pursuant to which LIPA had the option, through
December 15, 2005, to acquire substantially all of the electric generating
facilities owned by KeySpan on Long Island; and (iii) a Settlement Agreement
(the "2006 Settlement Agreement") resolving outstanding issues between the
parties regarding the 1998 LIPA Agreements. The 2006 MSA, the 2006 Option
Agreement and the 2006 Settlement Agreement are collectively referred to herein
as the "2006 LIPA Agreements". In the event LIPA exercises its rights under the
2006 Option Agreement, KeySpan and LIPA will enter into an operation and
maintenance agreement, pursuant to which KeySpan would continue to operate the
subject generating units, as well as related amendments to the 1998 PSA and 1998
EMA. The 2006 LIPA Agreements will become effective as of January 1, 2006,
following receipt of all necessary governmental approvals, which are pending.
The effectiveness of each of the 2006 LIPA Agreements is conditioned upon all of
the 2006 LIPA Agreements becoming effective.
8
Portions of our Electric Services business can be affected by seasonal weather
conditions and market conditions. The majority of the capacity revenue
associated with the Ravenswood Generating Station is realized during the six
months between May and October of each year. Energy and ancillary service sales
from our Ravenswood Generating Station are directly correlated to the demand for
electricity and competition from other resources. Typically, the demand and
price for electricity increases during extreme temperature conditions. However,
depending on the availability of alternative competitive supply, extreme
temperature conditions may not result in increased revenue. As a result,
fluctuations in weather and competitive supply between years may have a
significant effect on our results of operations for our Electric Services
business.
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 Note 7 to the Consolidated Financial
Statements, "Contractual Obligations, Financial Guarantees and Contingencies."
In 2004, we completed construction of the Ravenswood Expansion, a 250 MW
combined cycle generating unit at the Ravenswood Facility, 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 Generating Station sells capacity, energy and ancillary services
into the New York Independent System Operator ("NYISO") electricity market at
market-based rates, subject to mitigation. The Ravenswood Generating Station
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 Ravenswood Generating Station and our New York City Operations
Currently, the NYISO's New York City local reliability rules require that 80% of
the electric capacity needs of New York City be provided by "in-City"
generators. On February 9, 2006, the NYISO Operating Committee increased the
"in-City" generator requirement to 83% beginning in May 2006 through the period
ending on April 2007, based in part on the statewide reserve margin of 118% set
by the New York State Reliability Council. On February 16, 2006, an appeal was
filed with the NYISO Management Committee requesting that the February 9th
decision be rejected and that the "in-City" requirement be increased to a larger
percentage than 83%. A vote on this appeal is expected to occur at the NYISO
Management Committee meeting scheduled for February 28, 2006.
9
Our Ravenswood Generating Station is an "in-City" generator. As the electric
infrastructure in New York City and the surrounding areas continues to change
and evolve and the demand for electric power increases, the "in-City" generator
requirement could be further modified. Construction of new transmission and
generation facilities may cause significant changes to the market for sales of
capacity, energy and ancillary services from our Ravenswood Generating Station.
Recently 500 MW of capacity came on line and it is anticipated that another 500
MW of new capacity may be available during 2006 as a result of the completion of
an in-City generation project currently under construction. We cannot, however,
be certain as to when the new power plant will be in operation or the nature of
future New York City energy, capacity or ancillary services market requirements
or design.
KeySpan continues to believe that New York City represents a strong capacity
market and has entered into an International Swap Dealers Association ("ISDA")
Master Agreement for a fixed for float unforced capacity financial swap (the
"Swap Agreement") with Morgan Stanley Capital Group Inc. ("Morgan Stanley")
dated as of January 18, 2006. The Swap Agreement has a three year term beginning
May 1, 2006, (assuming a condition to effectiveness has been satisfied by such
date). The notional quantity is 1,800,000kW (the "Notional Quantity") of In-City
Unforced Capacity and the fixed price is $7.57/kW-month ("Fixed Price"), subject
to adjustment upon the occurrence of certain events. Settlement would occur on a
monthly basis based on the In-City Unforced Capacity price determined by the
relevant New York Independent System Operator Spot Demand Curve Auction Market
("Floating Price"). For each monthly settlement period, the price difference
will equal the Fixed Price minus the Floating Price. If such price difference is
less than zero, Morgan Stanley will pay KeySpan an amount equal to the product
of (a) the Notional Quantity and (b) the absolute value of such price
difference. Conversely, if such price difference is greater than zero, KeySpan
will pay Morgan Stanley an amount equal to the product of (a) the Notional
Quantity and (b) the absolute value of such price difference. KeySpan believes
that the average annual monthly capacity market price will settle above the
Fixed Price.
The New York State competitive wholesale market for capacity, energy and
ancillary services administered by the NYISO is still evolving and 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 2005 summer capacity of all of our steam
generation facilities and gas turbine ("GT") units as reported to the NYISO:
- --------------------------------------------------------------------------------
Location of Units Description Units MW
Fuel
- --------------------------------------------------------------------------------
Long Island City Steam Turbine Dual* 3 1737
Long Island City Combined Cycle Dual* 1 226
Northport, L.I. Steam Turbine Dual* 4 1550
Port Jefferson, L.I. Steam Turbine Dual* 2 388
Glenwood, L.I. Steam Turbine Gas 2 240
Island Park, L.I. Steam Turbine Dual* 2 396
Far Rockaway, L.I. Steam Turbine Dual* 1 110
Long Island City GT Units Dual* 17 438
Glenwood and Port GT Units Dual 4 154
Jefferson Energy Center,
L.I.
Throughout L.I. GT Units Dual* 12 301
Throughout L.I. GT Units Oil 30 1060
-- ----
TOTAL 78 6600
================================================================================
*Dual - Oil (#2 oil or #6 residual oil) or kerosene, and natural gas.
For additional information and for financial 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"
and Note 2 to the Consolidated Financial Statements, "Business Segments".
Agreements with LIPA
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, KeySpan and LIPA entered into three
major long-term service agreements, the 1998 MSA, 1998 PSA and 1998 EMA. Under
these agreements, as well as through additional power purchase agreements,
KeySpan provides: 4,214 MW of power generation capacity and energy conversion
services; operation, maintenance and capital improvement services for LIPA's
transmission and distribution system; and energy management services.
On February 1, 2006, KeySpan and LIPA entered into the 2006 LIPA Agreements
which will become effective as of January 1, 2006, following receipt of all
necessary governmental approvals, which are pending. The effectiveness of each
of the 2006 LIPA Agreements is conditioned upon all of the 2006 LIPA Agreements
becoming effective.
2006 Settlement Agreement. Pursuant to the terms of the 2006 Settlement
Agreement, KeySpan and LIPA agreed to resolve issues that have existed between
the parties relating to the various agreements effective in May 1998. In
addition to the resolution of these matters, KeySpan's entitlement to utilize
LILCO's available tax credits and other tax attributes will increase from
approximately $50 million to approximately $200 million. These credits and
11
attributes may be used to satisfy KeySpan's previously incurred indemnity
obligation to LIPA for any federal income tax liability that may result from the
settlement of a pending Internal Revenue Service ("IRS") audit for LILCO's tax
year ended March 31, 1999. In recognition of these items, as well as for the
modification and extension of the 1998 MSA and the elimination of the GPRA, upon
effectiveness of the 2006 Settlement Agreement KeySpan will record a contractual
asset in the amount of approximately $160 million, of which approximately $110
million will be attributed to the right to utilize such additional tax credits
and attributes and approximately $50 million will be amortized over the eight
year term of the 2006 MSA. In order to compensate LIPA for the foregoing,
KeySpan will pay LIPA $69 million in cash and will settle certain accounts
receivable in the amount of approximately $90 million due from LIPA.
Generation Purchase Rights Agreement and 2006 Option Agreement. Under an amended
GPRA, LIPA had the right 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.
LIPA was initially required to exercise its option by May 2005, but KeySpan and
LIPA agreed to extend the date by which LIPA was to make this determination to
December 15, 2005. Pursuant to the December 2005 settlement between KeySpan and
LIPA, the parties entered into the 2006 Option Agreement, whereby LIPA has the
option during the period January 1, 2006 to December 31, 2006 to purchase only
KeySpan's Far Rockaway and/or E.F. Barrett Generating Stations (and certain
related assets) at a price equal to the net book value of each facility. The
2006 Option Agreement replaces the GPRA, the expiration of which has been stayed
pending effectiveness of the 2006 LIPA Agreements which are pending governmental
approvals. In the event such agreements do not become effective by reason of
failure to secure requisite governmental approvals, the GPRA will be reinstated
for a period of 90 days. If LIPA were to exercise the option and purchase one or
both of the generation facilities (i) LIPA and KeySpan will enter into an
operation and maintenance agreement, pursuant to which KeySpan will continue to
operate these facilities through May 28, 2013 for a fixed management fee plus
reimbursement for certain costs; and (ii) the 1998 PSA and 1998 EMA would be
amended to reflect that the purchased generating facilities would no longer be
covered by those agreements. It is anticipated that the fees received pursuant
to the operation and maintenance agreement will offset the reduction in the
operation and maintenance expense recovery component of the 1998 PSA and the
reduction in fees under the 1998 EMA.
It is also contemplated that to the extent any emission credits attributable to
the acquired facilities are not needed to satisfy the operating requirements of
such plants, such excess emissions credits will be pooled and applied pro rata
to satisfy the operating requirements of KeySpan's generating facilities subject
to the amended PSA. Thereafter, any remaining credits attributable to the
acquired plants may be sold by LIPA, who shall retain 100% of the net proceeds.
Management Services Agreement. Pursuant to the 1998 MSA, we perform day-to-day
operation and maintenance services and capital improvements for LIPA's
transmission and distribution system, including, among other functions,
transmission and distribution facility operations, customer service, billing and
collection, meter reading, planning, engineering, and construction, all in
accordance with policies and procedures adopted by LIPA. KeySpan furnishes such
services as an independent contractor and does not have any ownership or
leasehold interest in the transmission and distribution system.
12
In exchange for providing these services, we are reimbursed for our budgeted
costs and entitled to earn an annual management fee of $10 million and may also
earn certain cost-based incentives, or be responsible for certain cost-based
penalties. The incentives provided us the ability 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 accrued to LIPA. The penalties
required 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, the agreement
provided 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 apply, for system reliability, worker
safety, and customer satisfaction. In 2005, we earned $7.4 million in non-cost
performance incentives.
The 1998 MSA was originally set to expire on May 28, 2006, but in 2005 it was
extended through December 31, 2008, in connection with the extension of the
option period under the GPRA as was more fully described in the discussion on
"Generation Purchase Rights Agreement and 2006 Option Agreement" above.
As a result of the recent negotiations and settlement between KeySpan and LIPA
discussed above, the parties entered into a 2006 MSA. Under the 2006 MSA,
KeySpan will continue to perform the 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, meter reading, planning,
engineering, and construction, all in accordance with prudent utility practice
and policies and procedures adopted by LIPA. The 2006 MSA will not become
effective unless and until all governmental approvals are received and, only if
all of the 2006 LIPA Agreements are approved. If all governmental approvals are
received, then the 2006 MSA will be implemented with an effective date of
January 1, 2006 and will operate through December 31, 2013.
In place of the previous compensation structure (whereby KeySpan was reimbursed
for budgeted costs, and earned a management fee and certain performance and
cost-based incentives), KeySpan's compensation for managing the T&D System under
the 2006 MSA consists of two components: a minimum compensation component of
$224 million per year and a variable component based on electric sales. The $224
million component will remain unchanged for three years and then increase
annually by 1.7%, plus inflation. The variable component, which will comprise no
more than 20% of KeySpan's compensation, is based on electric sales on Long
Island exceeding a base amount of 16,558 gigawatt hours, increasing by 1.7% in
each year. Above that level, KeySpan will receive approximately 1.34 cents per
kilowatt hour for the first contract year, 1.29 cents per kilowatt hour in the
second contract year (plus an annual inflation adjustment), 1.24 cents per
kilowatt hour in the third contract year (plus an annual inflation adjustment),
with the per kilowatt hour rate thereafter adjusted annually by inflation.
Subject to certain limitations, KeySpan will be able to retain all operational
efficiencies realized during the term of the 2006 MSA.
LIPA will continue to reimburse KeySpan for certain expenditures incurred in
connection with the operation and maintenance of the T&D System, and other
payments made on behalf of LIPA, including: real property and other T&D System
taxes, return postage, capital construction expenditures and storm costs.
13
The 2006 MSA provides for a number of performance metrics measuring various
aspects of KeySpan's performance in the operations and customer service areas.
Poor performance in any metric may subject KeySpan to financial and other
non-cost penalties (such financial penalties not to exceed $7 million in the
aggregate for all performance metrics in any contract year). Subject to certain
limitations, superior performance in certain metrics can be used to offset
underperformance in other metrics. Consistent failure to meet threshold
performance levels for two metrics, System Average Interruption Duration Index
(two out of three consecutive years) and Customer Satisfaction Index (three
consecutive years), will constitute an event of default under the 2006 MSA.
Should LIPA sell the T&D System to a private entity during the term of the 2006
MSA, LIPA shall have the right to terminate the 2006 MSA, provided that LIPA
will be required to pay KeySpan's reasonable transition costs and a termination
fee of (a) $28 million if the termination date occurs on or before December 31,
2009, and (b) $20 million if the termination date occurs after December 31,
2009.
Power Supply Agreement. A KeySpan subsidiary sells to LIPA all of the capacity
and, to the extent requested, energy conversion services from our 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. Since October 1, 2004, pursuant to a FERC approved
settlement, the rates reflect a cost of equity of 9.5% with no revenue increase
in the first year of the new rate period. 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 ("MWh") dispatched. LIPA has no
obligation to purchase energy conversion services from us and is able to
purchase energy or energy conversion services on a least-cost basis from all
available sources consistent with existing interconnection limitations of the
T&D system. The PSA provides incentives and penalties that can total $4 million
annually for the maintenance of the output capability and the efficiency of the
generating facilities. In 2005, we earned $4 million in incentives under the
PSA.
The 1998 PSA runs for an original term of 15 years, expiring in 2013. The 1998
PSA has a renewal provision for an additional 15 years on similar terms at
LIPA's option. However, the 1998 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 1998 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 1998 PSA.
If LIPA ramps-down the generation capacity in years 11 through 15 of the 1998
PSA, the capacity charges otherwise payable by LIPA will be reduced in
accordance with a formula established in the 1998 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 1998 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 1998 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 GPRA discussed in greater detail above
14
Energy Management Agreement. Pursuant to the 1998 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 2005, the EMA was amended to extend the term for the services
described in (ii) and (iii) through December 31, 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 2005, we earned EMA
incentives in an aggregate of $5 million.
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 1998 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 ("NYSDEC"), 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.
In March 2005, LIPA issued a Request for Proposal ("RFP") to provide system
power supply management services beginning May 29, 2006 and fuel management
services for certain of its peaking generating units beginning January 1, 2006.
A KeySpan subsidiary is currently performing these services. KeySpan submitted a
bid in response to the new RFP in April 2005. LIPA was scheduled to select a
service provider in June 2005, but has deferred such decision at this time. We
cannot predict the outcome or the timing of any decisions by LIPA on this matter
at this time. Pending LIPA's determination on the RFP, the EMA was extended
through December 31, 2006.
Power Purchase Agreements with KeySpan Glenwood and KeySpan Port Jefferson.
KeySpan Glenwood Energy Center, LLC and KeySpan Port Jefferson Energy Center LLC
each have 25 year power purchase agreements with LIPA expiring in 2027 (the
"2002 LIPA PPAs"). Under the terms of the 2002 LIPA PPAs, these subsidiaries
sell capacity, energy conversion services and ancillary services to LIPA. Each
plant is designed to produce 79.9 MW. Pursuant to the 2002 LIPA 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. In 2005, LIPA completed the strategic organizational review
initiative it commenced in 2004. As part of its strategic review, LIPA engaged a
team of advisors and consultants, held public hearings and explored its
strategic options, including continuing its existing operations, municipalizing,
15
privatizing, selling some, but not all of its assets, becoming a regulator of
rates and services, or merging with one or more utilities. The strategic review
team also considered whether LIPA should exercise its option under the GPRA.
Upon completion of its strategic review, LIPA determined that it would continue
its existing organizational structure and engage KeySpan in the renegotiation of
the 1998 MSA, GPRA and related agreements. As stated above, these negotiations
culminated in the parties entering into the 2006 LIPA Agreements. As previously
noted, the 2006 LIPA Agreements are subject to receipt of governmental
approvals. Also, the LIPA Agreements do not preclude LIPA from continuing to
explore privatization, municipalization or other strategic alternatives.
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 (from May 1998) 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 (from May 1998), 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 (from May 1998) 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
1998 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.
16
ENERGY SERVICES OVERVIEW
The Energy Services segment includes companies that provide energy-related
services to customers located primarily within the Northeastern United States,
with concentrations in the New York City and Boston metropolitan areas.
Subsidiaries in this segment provide residential and small commercial customers
with service and maintenance of energy systems and appliances, as well as
operation and maintenance, design, engineering, consulting and fiber optic
services to commercial, institutional and industrial customers. Our subsidiaries
in this segment have over 200,000 service contracts in place to provide home
energy services, completed over 250,000 service calls during 2005 and completed
more than 16,000 installations during 2005.
In January and February of 2005, KeySpan sold its mechanical contracting
subsidiaries in this segment and exited such businesses. These subsidiaries were
engaged in design, building, installing and servicing heating, ventilation and
air conditioning ("HVAC") systems and plumbing systems for industrial and
commercial customers. In the fourth quarter of 2004, KeySpan's investment in its
discontinued mechanical contracting subsidiaries was written-down to an
estimated fair value. 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.
For additional information and financial 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",
Item 8. "Financial Statements and Supplementary Data", Note 2 to the
Consolidated Financial Statements, "Business Segments" and Note 10 "Energy
Services - "Discontinued Operations".
ENERGY INVESTMENTS OVERVIEW
We are also engaged in Energy Investments which includes gas exploration and
production activities, domestic pipelines, gas storage facilities and LNG
facilities and operations.
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 KeySpan, to
explore for and produce natural gas and oil. KeySpan Exploration and
Production's remaining venture assets are primarily proved undeveloped oil
reserves located off the Gulf of Mexico in the South Timbalier and Mustang
Island areas.
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.
17
Domestic Pipelines and Gas Storage Facilities
We own a 20.4% interest in Iroquois Gas Transmission System LP, a partnership of
affiliates of six U.S. and Canadian energy companies, which is the owner of a
411-mile interstate natural gas pipeline extending from the U.S.-Canadian border
at Waddington, NY through western Connecticut to its terminus in Commack, NY,
and from Huntington to the Bronx. Its wholly owned subsidiary, the Iroquois
Pipeline Operating Company, headquartered in Shelton, Connecticut, is the agent
for and operator of the pipeline. The Iroquois pipeline can transport up to
1,124,500 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 304,950 DTH of gas per day.
We also have a 50% interest in Islander East Pipeline Company, LLC ("Islander
East"), which 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. In addition, we own a 21% ownership interest in the
Millennium Pipeline project which is anticipated to transport up to 525,000 DTH
of natural gas a day from Corning to Ramapo, New York, interconnecting with the
pipeline systems of various other utilities in New York.
We are also the owner and operator of a 600,000 barrel LNG storage and receiving
facility located in Providence, Rhode Island, known as KeySpan LNG. We acquired
the KeySpan LNG facility from Algonquin LNG, a subsidiary of Duke Energy on
December 12, 2002. Our subsidiary, Boston Gas is the facility's largest customer
and contracts for more than half of the LNG facility's storage. KeySpan LNG is
regulated by FERC.
For additional information concerning these energy related investments in
pipelines and gas storage facilities, see the discussion on "Energy Investments"
in Item 7 Management's Discussion and Analysis of Financial Condition and
Results of Operations contained herein.
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 4.3 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.
18
Former Energy Investments
KeySpan had previously been involved in natural gas distribution and pipeline
activities in the United Kingdom. However, on March 18, 2005, KeySpan sold its
50% interest in Premier Transmission Limited ("Premier"), a gas pipeline from
southwest Scotland to Northern Ireland pursuant to an agreement among KeySpan,
its 50% partner, BG Energy Holdings Limited and Premier Transmission Financing
Public Limited Company ("PTFPL"), pursuant to which all of the outstanding
shares of PTL were purchased by PTFPL. In two transactions in April and December
2004, KeySpan sold its ownership in KeySpan Energy Canada Partnership ("KeySpan
Canada") a company that owned certain midstream natural gas assets in Western
Canada.
For additional information and financial information concerning the Energy
Investments segment, see the discussion in Item 7 Management's Discussion and
Analysis of Financial Condition and Results of Operations - "Energy Investments"
and Note 2 to the Consolidated Financial Statements, "Business Segments".
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.
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 were submitted in a timely
manner for 13 existing facilities whose initial permits were to expire in 2004.
To date, all of the permits except one were renewed and the remaining renewal
application has been deemed complete by NYSDEC and is undergoing final review by
the United States Environmental Protection Agency ("EPA"). During 2005, a timely
renewal application was submitted for a facility whose permit expires in 2006.
The permits and timely renewal applications allow our electric generating plants
to continue to operate without any additional significant expenditures, except
as described below.
19
Our generating facilities are located within a CAA ozone non-attainment and PM
2.5 (fine particulate matter) 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 and forthcoming requirements
under the Clean Air Interstate Rule ("CAIR") designed to address both ozone and
particulate matter. Our previous investments in low NOX boiler combustion
modifications, the use of natural gas firing systems at our steam electric
generating stations, and the compliance flexibility available under these cap
and trade programs, have enabled KeySpan to achieve the emission reductions
required in a cost-effective manner. KeySpan is developing its compliance
strategy in response to the implementation of CAIR, which is expected in 2009.
Since detailed requirements under CAIR have not yet been fully articulated, it
is not possible to definitively estimate capital expenditures that may be
required to meet these regulatory mandates. Although it is anticipated that NOx
control equipment may be required at one or more of KeySpan's Long Island
facilities at a cost of between $25 to $35 million. However, such amounts are
recoverable from LIPA pursuant to the 1998 PSA, or if applicable, the 2006 PSA.
In 2003, New York State promulgated regulations which establish separate NOX and
SO2 emission reduction requirements on electric generating facilities in New
York State, which commenced in late 2004 for NOX emissions and in 2005 for SO2
emissions. KeySpan's facilities have been able to comply with the NOX
requirements without material additional capital expenditures because of
previously installed emissions control equipment and gas combustion capability.
SO2 compliance was achieved through a reduction in the sulfur content of the
fuel oil used in our Northport and Port Jefferson facilities and a further
reduction is expected to be required in 2008.
In 2004, the EPA issued regulations that require reductions, on a national
basis, of mercury emissions from electric generating facilities on a national
basis. The mercury regulations have no impact on KeySpan facilities since their
application is limited to coal-fired plants. EPA determined that nickel
emissions from oil fired plants do not pose health risks that require
regulation. This determination has been challenged and litigation is pending.
Until a final outcome is obtained, the nature and extent of the financial impact
on KeySpan from nickel regulation, if any, cannot be determined.
In 2003, the Governor of New York initiated a Regional Greenhouse Gas Initiative
that seeks to establish a coordinated multi-state plan to reduce greenhouse gas
emissions (primarily carbon dioxide ("CO2")) from electric generating emission
sources in the Northeast. In December of 2005, seven northeast states, including
New York, issued a memorandum of understanding capping CO2 emissions from
electric generating facilities in 2009 and, beginning in 2015, gradually
requiring a 10 percent reduction in regional emissions by 2018. Each of the
seven states will be promulgating individual state rules to implement the MOU.
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 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 the Ravenswood Generating Station in 2004 has further reduced
average KeySpan CO2 emission rates.
20
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 NYSDEC. We are currently conducting studies as directed by the NYSDEC to
determine the impacts of our discharges on aquatic resources and are engaged in
discussions with the NYSDEC regarding the nature of capital upgrades or other
mitigation measures necessary to satisfy these evolving regulatory requirements.
It is difficult to predict with any certainty the costs of such capital
investments, but these upgrades are expected to cost up to $60 million. However,
such amounts are recoverable from LIPA pursuant to the 1998 PSA, or applicable,
the 2006 PSA. The Ravenswood Generating Station may also require upgrades at a
cost of up to $15 million. The actual expenditures will depend upon the outcome
of the ongoing studies and the subsequent determination by the NYSDEC of how 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 investigating and
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. 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 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.
21
The Ravenswood Generating Station, 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.
Regulation. Public utility holding companies, like KeySpan, are now regulated by
the FERC pursuant to PUHCA 2005 and to some extent by state utility commissions
through the regulation of certain affiliate transaction regulations. Our utility
subsidiaries are subject to extensive federal and state regulation by FERC and
state utility commissions. 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 MADTE 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 also 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. As noted above, our regulated gas distribution
utility subsidiaries are subject to regulation by the NYPSC, MADTE and NHPUC.
The NYPSC regulates KEDNY and KEDLI. Although KeySpan 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 Station under a
lightened regulatory standard. Our KEDNE subsidiaries and to some extent our
service companies are also subject to regulation by the MADTE and NHPUC.
Securities and Exchange Commission. As a result of the acquisition of Eastern
and EnergyNorth, we became a holding company under PUHCA 1935. The Energy Act
repealed PUHCA 1935 and replaced it with PUHCA 2005 effective February 8, 2006.
Whereas our corporate and financial activities and those of our subsidiaries had
been subject to regulation by the SEC, FERC now has jurisdiction over certain of
our holding company activities. However, the SEC continues to have jurisdiction
over the registration and issuance of our securities under the federal
securities laws.
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
22
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.
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 1935, 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. The regulation of our three service companies has also
been transferred to FERC under PUHCA 2005.
Federal Energy Regulatory Commission. FERC has jurisdiction over certain of our
holding company activities, including (i) regulating certain transactions among
our affiliates within our holding company system; (ii) governing the issuance,
acquisition and disposition of securities and assets by certain of our public
utility subsidiaries; and (iii) approving certain utility mergers and
acquisitions. In addition to its new authority pursuant to PUHCA 2005, FERC also
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 Generating Station are subject to FERC
regulation based on their wholesale energy transactions.
Our Ravenswood Generating Station's rates are based on a market-based rate
application approved by FERC. The rates that our Ravenswood Generating Station
may charge are subject to FERC mandated mitigation measures due to market power
issues. 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 Generating Station'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 Generating Station 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.
23
Executive Officers of KeySpan
Certain information regarding executive officers of KeySpan and certain of its
subsidiaries is set forth below:
Robert B. Catell
Mr. Catell, age 69, 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
(NYSE:THX), Independence Community Bank (NASDAQ:ICBC) and Keyera Energy
Management Ltd. (TSX:KEY.UN)
Robert J. Fani
Mr. Fani, age 52, 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.
Wallace P. Parker Jr.
Mr. Parker, age 56, 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 56, 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
24
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 KeySpan, 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 56, 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
KeySpan'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.
John A. Caroselli
Mr. Caroselli, age 51, 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, Customer
Relations and Information Technology Strategy and Governance. 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 62, 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. (NYSE:IKN)
and Technology Solutions Company (NASDAQ:TSCC).
David J. Manning
Mr. Manning, age 55, 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 Queen's Counsel.
25
Anthony Nozzolillo
Mr. Nozzolillo, age 57, was elected Executive Vice President of Electric
Operations in February 2000. He previously served as Senior Vice President of
KeySpan's Electric Business Unit from December 1998 to January 2000. He joined
LILCO in 1972 and held various positions, including Manager of Financial
Planning and Manager of Systems Planning. Mr. Nozzolillo served as LILCO's
Treasurer from 1992 to 1994 and as Senior Vice President of Finance and Chief
Financial Officer from 1994 to 1998.
Lenore F. Puleo
Ms. Puleo, age 52, 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 47, 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 (NASDAQ:EBTC) and Dynamics Research
Corporation (NASDAQ:DRCO).
Joseph F. Bodanza
Mr. Bodanza, age 58, 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 47, 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.
26
John F. Haran
Mr. Haran, age 55, 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 50, 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 59, 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, age 46, 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 44, 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.
27
Joseph E. Hajjar
Mr. Hajjar, age 53, 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 49, 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.
EMPLOYEE MATTERS
As of December 31, 2005, KeySpan and its wholly-owned subsidiaries had
approximately 9,700 employees. Of that total, approximately 6,154 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.
ITEM 1A. RISK FACTORS
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 the following:
We are a Holding Company, and Our Subsidiaries are Subject to State Regulation
Which Limits Their Ability to Pay Dividends and Make Distributions to Us
We are a holding company 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.
28
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, 2005 and November 30, 2005, 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.
Our Gas Distribution and Electric Services Businesses May Be Adversely Affected
by Changes in Federal and State Regulation
The regulatory environment applicable to our gas distribution and our
electric services businesses has undergone substantial changes in recent
years, on both the federal and state levels. These changes have
significantly affected the nature of the gas and electric utility and power
industries and the manner in which their participants conduct their
businesses. Moreover, existing statutes and regulations may be revised or
reinterpreted, new laws and regulations may be adopted or become applicable
to us or our facilities and future changes in laws and regulations may
affect our gas distribution and our electric services businesses in ways
that we cannot predict.
In addition, our operations are subject to extensive government regulation
and require numerous permits, approvals and certificates from various
federal, state and local governmental agencies. A significant portion of
our revenues in our Gas Distribution and Electric Services segments are
directly dependent on rates established by federal or state regulatory
authorities, and any change in these rates and regulatory structure could
significantly impact our financial results. Increases in utility costs
other than gas, not otherwise offset by increases in revenues or reductions
in other expenses, could have an adverse effect on earnings due to the time
lag associated with obtaining regulatory approval to recover such increased
costs and expenses in rates.
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 capacity, energy and ancillary services
from our Ravenswood Generating Station 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
capacity, energy sales and ancillary services in to the NYISO market is
still evolving. and some of the FERC's price mitigation measures are
subject to rehearing and possible judicial review, as well as revision in
response to market participant complaints or NYISO requests.
29
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 at our
Ravenswood Generating Station, especially in the significant summer period,
could materially impact our financial results. Damage to pipelines,
equipment, properties and people caused by natural disasters, accidents,
terrorism or other damage by third parties could exceed our insurance
coverage. Although we do have insurance to protect against many of these
contingent liabilities, this insurance is capped at certain levels, has
self-insured retentions and does not provide coverage for all liabilities.
SEC Rules for Exploration and Production Companies May Require Us to Recognize a
Non-Cash Impairment Charge at the End of Our Reporting Periods
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 Station 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.
30
A Substantial Portion Of Our Revenues Are Derived From Our Agreements With LIPA
And No Assurances Can Be Made That These Arrangements Will Not Be Discontinued
At Some Point In The Future Or That The New Agreements Will Become Effective.
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. On February 1, 2006, KeySpan and LIPA
entered into amended and restated agreements whereby KeySpan will continue
to operate and maintain the electric T&D System owned by LIPA on Long
Island. As part of the amended agreements, the GPRA, pursuant to which LIPA
had the option, through December 15, 2005, to acquire substantially all of
the electric generating facilities owned by KeySpan on Long Island is
replaced with the 2006 Option Agreement where LIPA only has the right to
acquire two of our facilities, our Far Rockaway and/or E.F. Barrett
Generating Stations during the period January 1, 2006 to December 31, 2006.
Additionally, the new agreements resolve many outstanding issues between
the parties regarding the current LIPA Agreements and provide new pricing
and extensions of the Agreements. There is a risk that these agreements
will not receive the necessary governmental approvals, which are pending,
and the effectiveness of each of the 2006 LIPA Agreements is conditioned
upon all of the 2006 LIPA Agreements becoming effective. If the 2006 LIPA
Agreements do not become effective, there is uncertainty as to whether LIPA
will exercise their option under the GPRA and the status of the resolution
of the various disputes between KeySpan and LIPA.
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 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
31
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, financial condition
and cash flows.
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 capacity, energy and ancillary
services they sell. In addition, if new generation and/or transmission
facilities are constructed, and/or the availability of our Ravenswood
Generating Station deteriorates, then the quantities of capacity and energy
sales could be adversely affected. In December 2005, NYPA completed
construction of a nominal 500 MW generating facility in New York City, and
it began selling its capacity and energy into the NYISO markets. In
addition, another nominal 500 MW facility is expected to come on-line in
2006. We cannot predict, however, when or if new power plants or
transmission facilities in addition to the above-noted resources will be
built or the nature of the future New York City capacity and 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.
Risk Associated with our Financial Swap Agreement for In-City Unforced Capacity
KeySpan believes that the New York City market represents a strong capacity
market due to, among other things, its local reliability rules (which
recently increased to 83% from 80%), increasing demand and the time
required for new resources to be constructed. KeySpan anticipates that
demand will increase and that the high cost to construct capacity in New
York City will result in favorable In-City Unforced Capacity prices.
Therefore, KeySpan entered into an ISDA Master Agreement for a fixed for
floating unforced capacity financial swap for a notional quantity of
32
1,800,000kW at the Fixed Price is $7.57/kW-month. If the demand is less
than KeySpan's estimates, additional resources enter the market, or costs
are less than forecast, In-City Unforced Capacity prices could be on
average less than the Fixed Price resulting in a loss to KeySpan, which
under certain circumstances could be material.
Labor Disruptions at Our Facilities Could Adversely Affect Our Results of
Operations and Cash Flow
Approximately 6,154 employees, or 63% of our employees, are represented by
unions through various collective bargaining agreements that expire between
2006 and 2009. The bargaining agreements expiring in 2006 affect
approximately 1,300 employees who primarily work for KEDNE and at our
Ravenswood Generating Station. KeySpan is currently engaging in discussions
with these unions for new collective bargaining agreements. It is possible
that our employees may seek an increase in wages and benefits at the
expiration of these agreements, and that we may be unable to negotiate new
agreements without labor disruption.
Counterparties to Our Transactions May Fail to Perform their Obligations, Which
Could Harm Our Results of Operations
Our operations are exposed to the risk that counterparties to our
transactions that owe us money or supplies will not perform their
obligations. Should the counterparties to arrangements with us fail to
perform, we might be forced to enter into alternative hedging arrangements
or honor our underlying commitment at then-current market prices that may
exceed our contractual prices. In such event, we might incur additional
losses to the extent of amounts, if any, already paid to counterparties.
This risk is most significant where we have concentrations of receivables
from natural gas and electric utilities and their affiliates, as well as
industrial customers and marketers throughout the Northeastern United
States.
We Are Exposed to Risks That Are Beyond Our Control
The cost of repairing damage to our operating subsidiaries' facilities and
the potential disruption of their operations or supplier operations due to
storms, natural disasters, wars, terrorist acts and other catastrophic
events could be substantial. The occurrence or risk of occurrence of future
terrorist attacks or related acts of war may lead to increased political,
economic and financial market instability and volatility in prices for
natural gas which could materially adversely affect us in ways we cannot
predict at this time. A lower level of economic activity for these or other
reasons could result in a decline in energy consumption, which could
adversely affect our net revenues.
The Long-Term Financial Condition of Our Gas Distribution Business Depends on
the Continued Availability of Natural Gas Reserves
The development of additional natural gas reserves requires significant
capital expenditures by others for exploring, drilling and installing
production, gathering, storage, transportation and other facilities that
permit natural gas to be produced and delivered to our distribution
systems. Low prices for natural gas, regulatory restrictions, or the lack
of available capital for these projects could adversely affect the
33
development of additional natural gas reserves. Additional natural gas
reserves may not be developed in sufficient amounts to fill the capacities
of our distribution systems, thus limiting our prospects for long-term
growth.
Gathering, Processing and Transporting Activities Involve Numerous Risks that
May Result in Accidents and Other Operating Risks and Costs
Our gas distribution facilities pose a variety of hazards and operating
risks, such as leaks, explosions and mechanical problems caused by natural
disasters, accidents, terrorism or other damage by third parties, which
could cause substantial financial losses. In addition to impairing our
operations, these risks could also result in loss of human life and
environmental pollution. In accordance with standard industry practice, we
maintain insurance against some, but not all, of these potential risks and
losses. The occurrence of any of these events not fully covered by
insurance could have a material adverse effect on our financial position,
results of operations and cash flows.
Additional risks, uncertainties and factors that could cause actual results to
differ materially include but are not limited to the following:
- volatility of fuel prices used to generate electricity;
- fluctuations in weather and in gas and electric prices;
- 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;
- 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;
- 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;
- 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 NYISO, our two largest
customers; and
- other risks detailed from time to time in other reports and other
documents filed by KeySpan with the SEC.
34
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.
ITEM 1B UNRESOLVED STAFF COMMENTS.
None.
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, 2005.
35
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, 2006,
there were approximately 68,318 registered record holders of KeySpan's common
stock. In the fourth quarter of 2005, KeySpan increased its dividend to an
annual rate of $1.86 per common share beginning with the quarterly dividend to
be paid in February 2006. Our dividend framework 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 $1.86 level to be paid on a quarterly basis at a rate of $0.465.
KeySpan's scheduled dividend payment dates are February 1, May 1, August 1 and
November 1, or the next business day, if such date is not a business day.
The following table sets forth, for the quarters indicated, the high and low
sales prices and dividends declared per share for the periods indicated:
2005 High Low Dividends Per Share
-----------------------------------------------------------------------------
First Quarter $40.90 $38.04 $0.455
Second Quarter $40.88 $36.83 $0.455
Third Quarter $41.03 $36.35 $0.455
Fourth Quarter $37.10 $32.66 $0.455
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
36
EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth securities authorized for issuance under equity
compensation plans for the year ended December 31, 2005:
Number of securities remaining
Number of securities available for future issuance
to be issued upon exercise Weighted-average exercise under equity compensation plans
of outstanding options, price of outstanding (excluding securities reflected
Plan category warrants and rights options, warrants and rights in column (a))
------------- ------------------- ---------------------------- -------------------------------
(a) (b) (c)
Equity compensation plans
approved by security holders
KeySpan Long Term
Incentive Compensation Plan
Stock Options 10,443,055 $33.74 -
Restricted Stock 90,599 N/A -
Performance Shares 555,927 N/A -
Equity compensation plans not
approved by security holders N/A N/A N/A
Total 11,089,581(1) $33.74 3,736,121(2)
(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.
(2) This total amount reflects the aggregate number of stock options,
restricted stock and performance shares available for issuance pursuant to
KeySpan's Long Term Incentive Compensation Plan.
37
ITEM 6. SELECTED FINANCIAL DATA
- --------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Millions of Dollars, Except Per Share
Amounts) 2005 2004 2003 2002 2001
- --------------------------------------------------------------------------------------------------------------------
Income Summary
Revenues
Gas Distribution $ 5,390.1 $ 4,407.3 $ 4,161.3 $ 3,163.8 $ 3,613.6
Electric Services 2,042.8 1,738.7 1,606.0 1,645.7 1,850.4
Energy Services 191.2 182.4 158.9 208.6 243.5
Energy Investments 37.9 322.1 609.3 447.1 498.3
------------ ------------ ------------ ----------- --------------
Total revenues 7,662.0 6,650.5 6,535.5 5,465.2 6,205.8
------------ ------------ ------------ ----------- --------------
Operating expenses
Purchased gas for resale 3,597.3 2,664.5 2,495.1 1,653.3 2,171.1
Fuel and purchased power 752.1 540.3 414.6 395.9 538.5
Operations and maintenance 1,617.9 1,567.0 1,622.6 1,631.3 1,704.4
Depreciation, depletion and amortization 396.5 551.8 571.7 513.7 564.0
Operating taxes 407.1 404.2 418.2 380.5 448.9
Impairment Charges - 41.0 - - -
------------ ------------ ------------ ----------- --------------
Total operating expenses 6,770.9 5,768.8 5,522.2 4,574.7 5,426.9
------------ ------------ ------------ ----------- --------------
Gain on sale of property 1.6 7.0 15.1 4.7 -
Income from equity investments 15.1 46.5 19.2 14.1 13.1
------------ ------------ ------------ ----------- --------------
Operating income 907.8 935.3 1,047.6 909.3 792.0
Other income and (deductions) (269.9) 4.9 (340.3) (301.4) (359.5)
Income taxes 239.3 325.5 281.3 229.6 200.5
------------ ------------ ------------ ----------- --------------
Earnings from continuing operations 398.6 614.7 426.0 378.3 232.0
------------ ------------ ------------ ----------- --------------
Discontinued Operations
Income (loss) from operations, net of tax (4.1) (79.0) (1.9) 15.7 22.6
Loss on disposal, net of tax 2.3 (72.0) - (16.3) (30.3)
------------ ------------ ------------ ----------- --------------
Loss from discontinued operations (1.8) (151.0) (1.9) (0.6) (7.7)
Cumulative change in accounting principles (6.6) - (37.4) - -
------------ ------------ ------------ ----------- --------------
Net income 390.2 463.7 386.7 377.7 224.3
Preferred stock dividend requirements 2.2 5.6 5.8 5.8 5.9
------------ ------------ ------------ ----------- --------------
Earnings for common stock $ 388.0 $ 458.1 $ 380.9 $ 371.9 $ 218.4
============ ============ ============ =========== ==============
Financial Summary
Earnings per share ($) 2.28 2.86 2.41 2.63 1.58
Cash dividends declared per share ($) 1.82 1.78 1.78 1.78 1.78
Book value per share, year-end ($) 25.60 24.22 22.99 20.67 20.73
Market value per share, year-end ($) 35.69 39.45 36.80 35.24 34.65
Shareholders, year-end 68,421 72,549 75,067 78,281 82,300
Capital expenditures ($) 539.5 750.3 1,009.4 1,057.5 1,059.8
Total assets ($) 13,812.6 13,364.1 14,640.2 12,980.1 11,789.6
Common shareholders' equity ($) 4,464.1 3,894.7 3,670.7 2,944.6 2,890.6
Preferred stock redemption required ($) - 75.0 75.0 75.0 75.0
Preferred stock no redemption required ($) - - 8.6 8.8 9.1
Long-term debt ($) 3,920.8 4,418.7 5,610.9 5,224.1 4,697.6
Total capitalization ($) 8,384.9 8,333.2 9,365.2 8,252.5 7,672.3
- -------------------------------------------------- ------------ ------------ ------------ ----------- --------------
38
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
KeySpan Corporation (referred to in the Notes to the Financial Statements as
"KeySpan," "we," "us" and "our") is a holding company that 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, lease 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 operating subsidiaries are primarily involved in gas exploration
and production; underground gas storage; liquefied natural gas storage; retail
electric marketing; large energy-system ownership, installation and management;
service and maintenance of energy systems; 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
"Business Segments" for additional information on each operating segment.)
Recent Developments
- -------------------
On February 25, 2006, Keyspan entered into an Agreement and Plan of Merger (the
"Merger Agreement"), with National Grid PLC, a public limited company
incorporated under the laws of England and Wales ("Parent") and National Grid
USA, Inc, a New York Corporation ("Merger Sub"), pursuant to which Merger Sub
will merge with and into KeySpan (the "Merger"), with KeySpan continuing as the
surviving Company. Pursuant to the Merger Agreement, at the effective time of
the Merger, each outstanding share of common stock, par value $.01 per share of
KeySpan (the "Shares"), other than shares owned by KeySpan, shall be canceled
and shall be converted into the right to receive $42.00 in cash, without
interest.
Consummation of the Merger is subject to various closing conditions, including
but not limited to the satisfaction or waiver of conditions regarding the
receipt of requisite regulatory approvals and the adoption of the Merger
Agreement by the stockholders of KeySpan and the Parent. Assuming receipt or
waiver of the foregoing, it is currently anticipated that the Merger will be
consummated in early 2007. Accordingly, any statements contained herein
concerning expectations, beliefs, plans, objectives, goals, strategies, future
events or performance and underlying assumptions are "forward-looking
statements" and do not take into account the occurrence or impact of any
potential strategic transaction on the future operations, financial condition
and cash flows of KeySpan. However, no assurance can be given that the Merger
will occur, or, the timing of its completion.
At December 31, 2005, KeySpan was a holding company under the Public Utility
Holding Company Act of 1935, as amended ("PUHCA 1935"). In August 2005, the
Energy Policy Act of 2005 (the "Energy Act") was enacted. The Energy Act is a
broad energy bill that places an increased emphasis on the production of energy
and promotes the development of new technologies and alternative energy sources
and provides tax credits to companies that produce natural gas, oil, coal,
electricity and renewable energy. For KeySpan, one of the more significant
provisions of the Energy Act is the repeal of PUHCA 1935, which became effective
on February 8, 2006. Since that time, the jurisdiction of the Securities and
Exchange Commission ("SEC") over certain holding company activities, including
the regulation of our affiliate transactions and service companies, has been
transferred to the jurisdiction of the Federal Energy Regulatory Commission
("FERC") pursuant to the Public Utility Holding Company Act of 2005 ("PUHCA
2005"). See "Regulation and Rate Matters" for additional information on the
Energy Act and PUHCA 2005.
39
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 Millions of Dollars, Except per Share Amounts)
Year Ended December 31, 2005 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------------
Earnings E.P.S. Earnings E.P.S. Earnings E.P.S.
Earnings from continuing operations, less
preferred stock dividends $ 396.4 $ 2.33 $ 609.1 $ 3.80 $ 420.2 $ 2.65
Discontinued operations (1.8) (0.01) (151.0) (0.94) (1.9) (0.01)
Cummulative change in accounting principle (6.6) (0.04) - - (37.4) (0.23)
- ------------------------------------------------------------------------------------------------------------------------------------
Earnings for Common Stock $ 388.0 $ 2.28 $ 458.1 $ 2.86 $ 380.9 $ 2.41
- ------------------------------------------------------------------------------------------------------------------------------------
Components of Continuing Operations:
- ------------------------------------------------------------------------------------------------------------------------------------
Core operations $ 403.2 $ 2.37 $ 359.4 $ 2.25 $ 334.2 $ 2.11
Asset sales - - 257.5 1.60 0.9 -
Non core operations - - 83.9 0.52 98.7 0.62
Impairment charges - - (62.4) (0.39) - -
Debt redemption costs (6.8) (0.04) (29.3) (0.18) (13.6) (0.08)
- ------------------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations, less
preferred stock dividends $ 396.4 $ 2.33 $ 609.1 $ 3.80 $ 420.2 $ 2.65
- ------------------------------------------------------------------------------------------------------------------------------------
Earnings from Continuing Operations 2005 vs 2004
KeySpan's earnings from continuing operations, less preferred stock dividends,
for the year ended December 31, 2005 were $396.4 million or $2.33 per share, a
decrease of $212.7 million, or $1.47 per share compared to $609.1 million, or
$3.80 per share realized in 2004. KeySpan's financial results for the year ended
December 31, 2005 and 2004, reflect the following items that had a significant
impact on comparative results: (i) earnings from core operations; (ii) asset
sales of non-core subsidiaries recorded in 2004 and their respective results for
2004; (iii) impairment charges recorded in 2004; and (iv) debt redemption
charges recorded in both 2005 and 2004.
As indicated in the above table, KeySpan's earnings from core operations
increased $43.8 million or $0.12 per share in 2005, primarily reflecting higher
earnings from the Electric Services segment, improved results from the Energy
Services segment, and a decrease in interest charges. KeySpan's electric
services operations benefited from an increase in net electric revenues
principally as a result of improved pricing due, in part, to the warm weather
during the 2005 summer. Lower operating losses were incurred at the Energy
Services segment as a result of lower operating expenses.
The decrease in interest expense resulted from the benefits attributable to
lower outstanding debt resulting from debt redemptions in 2004 and the first
quarter of 2005, as well as from the sale of Houston Exploration and KeySpan
Canada. These favorable results were somewhat offset by a decrease in operating
40
income from KeySpan's gas distribution operations as a result of higher
operating expenses, primarily due to an increase in the provision for
uncollectible accounts receivable as a result of increasing gas costs and the
adverse impact from recent collection experience.
The full benefit to earnings per share from the favorable operating results of
the Electric Services and Energy Services segments, as well as the decrease in
interest charges was offset by the higher level of common shares outstanding. On
May 16, 2005, KeySpan issued 12.1 million shares of common stock upon the
scheduled conversion of the MEDs Equity Units. The dilutive effect of this
issuance on earnings per share for the year ended December 31, 2005, was
approximately $0.12 per share. (See Note 6 to the Consolidated Financial
Statements "Long-term Debt and Commercial Paper" for additional details on the
MEDs Equity Units.)
The remaining items impacting comparative earnings from continuing operations -
asset sales, impairment charges and debt redemption charges - are discussed
below.
During 2004, KeySpan sold its remaining 55% equity interest in The Houston
Exploration Company ("Houston Exploration"), an independent natural gas and oil
exploration company based in Houston, Texas. We received cash proceeds of
approximately $758 million in two stock transactions that resulted in after-tax
gains of $222.7 million, or $1.39 per share. The first transaction occurred in
June 2004 and the second transaction was completed in November 2004. The
operations of Houston Exploration were fully consolidated in KeySpan's
Consolidated Financial Statements during the first five months of 2004, but were
then accounted for on the equity method of accounting after the first
transaction reduced our ownership interest below 50%.
Also in 2004, KeySpan sold its remaining 60.9% investment in KeySpan Energy
Canada Partnership ("KeySpan Canada"), a company that owned certain midstream
natural gas assets in Western Canada. We received cash proceeds of approximately
$255 million in two transactions that resulted in a total after-tax gain of
$34.8 million, or $0.21 per share. The first transaction took place in April
2004 and the second transaction was completed in December 2004. The operations
of KeySpan Canada were fully consolidated in KeySpan's Consolidated Financial
Statements during the first three months of 2004, but then were accounted for on
the equity method of accounting after the first transaction reduced our
ownership interest below 50%.
Combined, these asset sales provided KeySpan with approximately $1 billion in
cash proceeds and after-tax earnings of $257.5 million, or $1.60 per share.
Further, during 2004, KeySpan's share of the after-tax operating earnings of
Houston Exploration and KeySpan Canada was $83.9 million or $0.52 per share.
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 transactions.
KeySpan recorded three significant impairment charges during 2004: (i) a
goodwill impairment charge recorded in the Energy Services segment; (ii) a
ceiling test write-down recorded in the Energy Investments segment; and (iii) a
carrying value impairment charge also recorded in the Energy Investments
segment. These impairment charges resulted in after-tax charges to continuing
operations of $62.4 million, or $0.39 per share.
41
Specifically, 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. 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
was attributable to continuing operations, while the remaining $139.9 million,
or $0.87 per share, was reflected in discontinued operations. (See Note 10 to
the Consolidated Financial Statements "Energy Services - Discontinued
Operations" for additional details on this charge.)
KeySpan's remaining 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) in 2004 to recognize the reduced valuation of proved
reserves. (See Note 9 to the Consolidated Financial Statements "Gas Exploration
and Production Property - Depletion," for additional details on this charge.)
In addition to the asset sales noted previously, in the fourth quarter of 2004,
KeySpan anticipated selling its previous 50% ownership interest in Premier
Transmission Limited ("Premier"), a gas pipeline from southwest Scotland to
Northern Ireland. In the fourth quarter of 2004, KeySpan recorded a 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
Premier compared to its carrying value. This investment was accounted for under
the equity method of accounting in the Energy Investments segment. The sale of
Premier was completed in the first quarter of 2005 and resulted in cash proceeds
of approximately $48.1 million and a pre-tax gain of $4.1 million reflecting the
difference from earlier estimates. (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 sale.)
The remaining significant item impacting comparative results, as noted above,
was debt redemption costs incurred in both 2005 and 2004. In 2005, KeySpan
redeemed $500 million of 6.15% Notes due in 2006. KeySpan incurred $20.9 million
in call premiums, which were expensed and recorded in other income and
deductions on the Consolidated Statement of Income, and wrote-off $1.3 million
of previously deferred financing costs. Further, KeySpan accelerated the
amortization of approximately $11.2 million of previously unamortized benefits
associated with an interest rate swap on these Notes. The accelerated
amortization was recorded as a reduction to interest expense. The net after-tax
expense of this debt redemption was $6.8 million or $0.04 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 2004, KeySpan redeemed approximately $758 million of
various series of outstanding long-term debt. 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 rate
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 2004 debt
redemption was $29.3 million or $0.18 per share.
42
The net impact of the above mentioned items resulted in a decrease to earnings
from continuing operations of $6.8 million or $0.04 per share for the year ended
December 31, 2005, compared to a gain of $249.7 million, or $1.55 per share, in
2004.
Earnings Available for Common Stock 2005 vs 2004
Earnings available for common stock also include losses from discontinued
operations associated with KeySpan's former mechanical contracting subsidiaries;
these companies were discontinued in the fourth quarter of 2004 and sold in
early 2005. In the fourth quarter of 2004, KeySpan's investment in its
mechanical contracting subsidiaries was written-down to fair value. During 2005,
operating losses amounting to $4.1 million after-tax were incurred through the
dates of sale of these companies, including, but not limited to, costs incurred
for employee related benefits. Partially offsetting these losses was an after
tax-gain of $2.3 million associated with the related divestitures, reflecting
the difference between the fair value estimates and the financial impact of the
actual sale transactions. The net income impact of the operating losses and the
disposal gain was a loss of $1.8 million, or $0.01 per share for the year ended
December 31, 2005.
Further, earnings available for common stock for 2005 include a $6.6 million, or
$0.04 per share, cumulative change in accounting principle charge as a result of
implementing the accounting requirements of FASB Interpretation No. 47 ("FIN
47") "Accounting for Conditional Asset Retirement Obligations." This
pronouncement required KeySpan to record a liability for the estimated future
cost associated with the legal obligation to dispose of long-lived assets at the
time of their retirement or disposal date. Upon initial implementation, December
31, 2005, a cumulative change in accounting principle charge was recorded on
KeySpan's Consolidated Statement of Income, representing the present value of
KeySpan's future retirement obligation. See Note 7 to the Consolidated Financial
Statements "Contractual Obligations, Financial Guarantees and Contingencies" for
further information on this charge.
As previously noted, in 2004 KeySpan conducted an evaluation of the carrying
value of its investments in the Energy Services segment. As a result of this
evaluation, KeySpan recorded a loss in discontinued operations of $151.0
million, or $0.94 per share. This loss reflects a $139.9 million after-tax
impairment charge to reflect a reduction to the carrying value of assets
associated with our mechanical contracting activities and operating losses of
$11.1 million. (See Note 10 to the Consolidated Financial Statements "Energy
Services - Discontinued Operations" for additional details on these items.)
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. 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) earnings from core operations; (ii) non-core
asset sales recorded in both 2004 and 2003; (iii) impairment charges recorded in
2004; and (iv) debt redemption charges recorded in both 2004 and 2003.
43
As indicated in the table above, KeySpan's earnings from core operations
increased $25.2 million or $0.14 per share for the twelve months ended December
31, 2004 compared to 2003, primarily reflecting an increase in net electric
revenues associated with KeySpan's Electric Services segment, as well as from
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.
The remaining items impacting comparative earnings from continuing operations -
asset sales, impairment charges and debt redemption charges - are discussed
below.
As noted previously, during 2004 KeySpan sold its ownership interests in Houston
Exploration and KeySpan Canada. 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. Further, during 2004, KeySpan's share of the
after-tax operating earnings of Houston Exploration and KeySpan Canada was $83.9
million or $0.52 per share.
During 2003, KeySpan completed two non-core asset sales. KeySpan sold a 39.09%
interest in KeySpan Canada and a 20% interest in Taylor NGL LP which owned and
operated two extraction plants 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. KeySpan's share of
the after-tax operating earnings of Houston Exploration and KeySpan Canada was
$98.7 million or $0.62 per share for the twelve months ended December 31, 2003.
Further, in the fourth quarter of 2003, we completed the sale of a 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 $13.3 million from the
monetization of 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 transactions.
As previously noted, KeySpan recorded three significant impairment charges
during 2004: (i) a goodwill impairment charge recorded in the Energy Services
segment of $152.4 million after-tax, or $0.95 per share, - $12.6 million of
which was attributable to continuing operations, while the remaining $139.9
million, or $0.87 per share, was reflected in discontinued operations; (ii) an
after-tax ceiling test write-down of $31.1 million, or $0.19 per share, to
recognize the reduced valuation of proved reserves associated with KeySpan's
wholly-owned gas exploration and production subsidiaries; and (iii) a non-cash
impairment charge of $26.5 million, - $18.8 million after-tax or $0.12 per
share, recorded in the Energy Investments segment reflecting the difference
between the anticipated cash proceeds from the sale of Premier compared to its
carrying value.
44
The remaining significant item noted above is debt redemption costs incurred in
2004 and 2003. As noted previously, in 2004, KeySpan redeemed approximately $758
million of outstanding long-term debt. The total after-tax expense of this debt
redemption was $29.3 million or $0.18 per share. 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 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 $249.7 million, or $1.55 per share for the year
ended December 31, 2004, compared to $86.0 million or $0.54 per share in 2003.
Earnings Available for Common Stock 2004 vs 2003
Earnings available for common stock for the year ended December 31, 2004 also
include losses from discontinued operations of $151.0 million, or $0.94 per
share. This loss includes $139.9 million of after-tax impairment charges to
reflect a reduction to the carrying value of assets associated with KeySpan's
former mechanical contracting subsidiaries and operating losses of $11.1
million.
Earnings available for common stock for the year ended December 31, 2003, also
reflect an operating loss from discontinued operations associated with KeySpan's
former mechanical contracting subsidiaries of $1.9 million, or $0.01 per share
and 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 KeySpan
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 (the "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 $37.4 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.)
45
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 Millions of Dollars, Except Per Share Amounts) 2005 2004 2003
- -----------------------------------------------------------------------------------------------------------
Gas Distribution $ 565.7 $ 579.6 $ 574.3
Electric Services 342.3 289.8 269.9
Energy Services
Operations (2.7) (33.9) (33.0)
Goodwill impairment charge - (14.4) -
Energy Investments
Operations of continuing companies 20.6 24.4 12.5
Operations of sold companies - 155.0 226.0
Ceiling test write-down and impairment charge - (74.7) -
Eliminations and other (18.1) 9.5 (2.1)
- -----------------------------------------------------------------------------------------------------------
Operating Income 907.8 935.3 1,047.6
- -----------------------------------------------------------------------------------------------------------
Other Income and (Deductions)
Interest charges (269.3) (331.3) (307.7)
Gain on sale of assets 4.1 388.3 13.3
Cost of debt redemption (20.9) (45.9) (24.1)
Minority interest (0.4) (36.8) (63.9)
Other income and (deductions) 16.6 30.6 42.1
- -----------------------------------------------------------------------------------------------------------
(269.9) 4.9 (340.3)
- -----------------------------------------------------------------------------------------------------------
Income taxes (239.3) (325.5) (281.3)
- -----------------------------------------------------------------------------------------------------------
Income from Continuing Operations 398.6 614.7 426.0
Loss from discontinued operations (1.8) (151.0) (1.9)
Cumulative change in accounting principles (6.6) - (37.4)
- -----------------------------------------------------------------------------------------------------------
Net Income 390.2 463.7 386.7
Preferred stock dividend requirements 2.2 5.6 5.8
- -----------------------------------------------------------------------------------------------------------
Earnings for Common Stock $ 388.0 $ 458.1 $ 380.9
- -----------------------------------------------------------------------------------------------------------
Basic Earnings per Share:
Continuing operations, less preferred stock dividends $ 2.33 $ 3.80 $ 2.65
Discontinued operations (0.01) (0.94) (0.01)
Cumulative change in accounting principles (0.04) - (0.23)
- -----------------------------------------------------------------------------------------------------------
$ 2.28 $ 2.86 $ 2.41
- -----------------------------------------------------------------------------------------------------------
Operating Income 2005 vs 2004
As indicated in the above table, operating income decreased $27.5 million, or
3%, for the twelve months ended December 31, 2005 compared to the same period of
2004. The comparative operating results reflect the following two items that had
a significant impact on results: (i) operating results of non-core subsidiaries
recorded in 2004; offset by (ii) impairment charges recorded in 2004. As noted
earlier, during 2004 KeySpan held equity ownership interests in Houston
Exploration and KeySpan Canada. For the twelve months ended December 31, 2004,
KeySpan's share of the combined operating income of Houston Exploration and
KeySpan Canada was $155.0 million. KeySpan sold its remaining ownership interest
in these non-core operations in the fourth quarter of 2004. Offsetting this
income to some extent were pre-tax non-cash impairment charges of $89.1 million
recorded in 2004. As noted earlier, KeySpan recorded the following three
46
impairment charges during 2004: (i) a goodwill impairment charge recorded in the
Energy Services segment attributable to continuing operations of $14.4 million;
(ii) a ceiling test write-down of $48.2 million to recognize the reduced
valuation of proved reserves associated with KeySpan's wholly-owned gas
exploration and production subsidiaries; and (iii) a non-cash impairment charge
of $26.5 million also recorded in the Energy Investments segment reflecting the
difference between the anticipated cash proceeds from the sale of Premier
compared to its carrying value.
The combined impact of the non-core operating income recorded in 2004 offset by
the impairment charges contributed $65.9 million to operating income for the
twelve months ended December 31, 2004. KeySpan's core businesses, therefore,
posted an increase in operating income of $38.4 million for the twelve months
ended December 31, 2005, compared to the same period of 2004, primarily
reflecting an increase of $52.5 million in the Electric Services segment,
partially offset by a $13.9 million decrease in the Gas Distribution segment.
The favorable results from KeySpan's electric services operations reflect an
increase in net electric revenues as a result of higher electric prices that
were due, in part, to the warm weather during the summer of 2005. Gas
distribution results, however, were adversely impacted by higher operating
expenses, primarily due to an increase in the provision for uncollectible
accounts receivable as a result of higher gas costs and by higher property
taxes. For the most part, the beneficial impact on comparative operating income
from lower net operating losses incurred at the Energy Services segment, was
offset by an increase in expenses residing at the holding company level.
Further, in 2004 KeySpan reached a settlement with certain of 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 expense.
Other income and (deductions) reflects interest charges, costs associated with
debt redemptions, income from subsidiary stock transactions, minority interest
charges and other miscellaneous items. For the twelve months ended December 31,
2005, other income and (deductions) reflects a net expense of $269.9 million
compared to income of $4.9 million for the twelve months ended December 31,
2004. This unfavorable variation of $274.8 is due to higher gains from asset
sales recorded in 2004 compared to 2005 of $384.2 million, offset by a decrease
in interest charges of $62.0 million, lower debt redemption costs of $25.0
million and the absence of minority interest expenses of $36.4 million. The
following is a discussion of these items.
As noted earlier, in the first quarter of 2005, KeySpan finalized its sale of
Premier. The final sale of Premier resulted in a pre-tax gain of $4.1 million
reflecting the difference from earlier estimates and what was recorded in the
first quarter of 2005. For the twelve months ended December 31, 2004, KeySpan
realized pre-tax income of $388.3 million from subsidiary stock transactions
associated with Houston Exploration and KeySpan Canada, as discussed earlier.
Interest expense decreased $62.0 million, or 19%, for the twelve months ended
December 31, 2005, compared to the same period of 2004, reflecting the benefits
attributable to recent debt redemptions, as well as the sale of Houston
Exploration and KeySpan Canada. In addition, as noted earlier, in 2005 KeySpan
redeemed $500 million 6.15% Series Notes due 2006. KeySpan incurred $20.9
million in call premiums, wrote-off $1.3 million of previously deferred
financing costs and accelerated the amortization of approximately $11.2 million
of previously unamortized benefits associated with an interest rate swap on
these bonds. The accelerated amortization of the interest rate swap and the
write-off of previously deferred financing costs reduced interest expense in
2005 by $9.9 million.
47
In 2004, KeySpan redeemed approximately $758 million of various series of
outstanding debt and incurred $45.9 million in call premiums and wrote-off $8.2
million of previously deferred financing costs. The net impact of the 2005 and
2004 debt redemptions lowered comparative interest expense by $18.1 million.
For the year ended December 31, 2004 other income and (deductions) also includes
the effects of minority interest of $36.8 million related to our previous
majority ownership interests in Houston Exploration and KeySpan Canada. Finally,
other income and (deductions) for the year ended December 31, 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, a 250 MW combined cycle generating
facility located at the Ravenswood site, as well as a $5.5 million foreign
currency gain.
Income taxes decreased $86.2 million for the year ended December 31, 2005
compared to last year due, for the most part, to lower pre-tax earnings. 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 $12 million related to the repatriation of earnings from
KeySpan's foreign investments; and (iii) the beneficial tax treatment afforded
the stock transaction with Houston Exploration.
As noted earlier, earnings available for common stock for the year ended
December 31, 2005, also includes losses of $1.8 million, or $0.01 per share,
from discontinued operations, as well as a $6.6 million, or $0.04 per share
cumulative change in accounting principles charge. Earnings available for common
stock for the year ended December 31, 2004, includes losses of $151.0 million,
or $0.94 per share, from discontinued operations.
As a result of the items discussed above, earnings available for common stock
were $388.0 million, or $2.28 per share for the year ended December 31, 2005,
compared to $458.1 million, or $2.86 per share realized in 2004.
Operating Income 2004 vs 2003
Operating income decreased $112.3 million, or 11%, 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
Investments segment as a result of KeySpan's reduced ownership interest in
Houston Exploration and KeySpan Canada during the latter half of 2004. KeySpan's
lower ownership level in these former subsidiaries reduced comparative operating
income by $71.0 million. 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 associated with our previous investment in
Premier. Further, the decrease in operating income reflects the $14.4 million
non-cash goodwill impairment charge recorded in the Energy Services segment. The
combined impact of the decrease in non-core operating income and the impairment
charges recorded in 2004 reduced operating income for the twelve months ended
48
December 31, 2004, by $160.1 million. KeySpan's core businesses, therefore,
posted an increase in operating income of $47.8 million for the twelve months
ended December 31, 2004 compared to the same period of 2003, primarily
reflecting increases of $19.9 million in the Electric Services segment, $5.3
million in the Gas Distribution segment and $11.9 million from the continuing
operations in the Energy Investments segment.
The increase in comparative operating income in the Electric Services segment in
2004 primarily reflects higher net electric margins associated with the
Ravenswood Expansion. 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. In 2003, we recorded $15.1
million in gains from property sales, primarily the sale of 550 acres of real
property located on Long Island, that were recorded in the Gas Distribution
segment. The continuing operations in the Energy Investments segment realized
higher earnings from the sale of property, as well as from an increase in
earnings from gas pipeline investments and generally lower administrative costs.
(See the discussion under the caption "Review of Operating Segments" for further
details on each segment.)
Other income and (deductions) reflects interest charges, costs associated with
debt redemptions, income from subsidiary stock transactions, minority interest
charges and other miscellaneous items. For the twelve months ended December 31,
2004, other income and (deductions) reflects a net gain of $4.9 million compared
to a net expense of $340.3 million for the twelve months ended December 31,
2003. This favorable variation of $345.2 million is due to higher gains from
asset sales recorded in 2004 compared to 2003 of $375.0 million and a lower
minority interest adjustment of $27.1 million, offset by an increase in interest
charges of $23.6 million and higher debt redemption costs of $21.8 million. The
following is a discussion of these items.
As noted earlier, for the twelve months ended December 31, 2004, KeySpan
realized pre-tax income of $388.3 million from subsidiary stock transactions
associated with Houston Exploration and KeySpan Canada. 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 $13.3 million associated with these transactions. Further, the lower
ownership level in Houston Exploration and KeySpan Canada in 2004 resulted in an
associated decrease in the minority interest adjustment of $27.1 million.
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, discussed 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.")
49
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. In March 2003, we
redeemed 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.
As noted previously, during 2004, KeySpan redeemed approximately $758 million of
outstanding long-term debt and recorded $45.9 million in debt redemption costs.
In 2003, KeySpan incurred debt redemption costs of $24.1 million associated with
(i) the redemption of approximately $447 million of outstanding promissory notes
issued to LIPA in connection with the KeySpan/LILCO business combination; and
(ii) Houston Exploration's debt redemption costs of $5.9 million to retire $100
million 8.625% Notes. The operating results for Houston Exploration were
consolidated in 2003.
Other income and (deductions) for 2004 also 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) for 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.
(See Note 7 to the Consolidated Financial Statements, "Contractual Obligations,
Financial Guarantees and Contingencies" for additional information regarding the
sale/leaseback transaction.)
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 $12 million related to the repatriation of earnings from
KeySpan's foreign 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 our regulated utilities in
Massachusetts. 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.
50
As noted earlier, earnings available for common stock for the year ended
December 31, 2004, also included losses of $151.0 million, or $0.94 per share,
from discontinued operations. Earnings available for common stock for the year
ended December 31, 2003, included a charge for a cumulative change in accounting
principles of $37.4 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.
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.
51
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 Millions of Dollars) 2005 2004 2003
- -------------------------------------------------------------------------------------------------------------------------------
Revenues $ 5,390.1 $ 4,407.3 $ 4,161.3
Cost of gas 3,607.0 2,664.7 2,444.5
Revenue taxes 65.8 73.3 90.5
- -------------------------------------------------------------------------------------------------------------------------------
Net Gas Revenues 1,717.3 1,669.3 1,626.3
- -------------------------------------------------------------------------------------------------------------------------------
Operating Expenses
Operations and maintenance 727.0 672.5 659.9
Depreciation and amortization 276.9 276.5 259.9
Operating taxes 147.8 140.7 147.3
- -------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 1,151.7 1,089.7 1,067.1
- -------------------------------------------------------------------------------------------------------------------------------
Gain on the sale of property 0.1 - 15.1
Operating Income $ 565.7 $ 579.6 $ 574.3
- -------------------------------------------------------------------------------------------------------------------------------
Firm gas sales and transportation (MDTH) 323,347 324,549 328,073
Transportation - Electric Generation (MDTH) 25,076 27,656 34,778
Other Sales (MDTH) 187,805 155,992 158,722
Warmer (Colder) than Normal - New York & Long Island (1.0%) (1.0%) (8.0%)
Warmer (Colder) than Normal - New England (8.6%) (6.8%) (10.0%)
- -------------------------------------------------------------------------------------------------------------------------------
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 2005 vs 2004
Operating income decreased $13.9 million, or 2%, for the twelve months ended
December 31, 2005, compared to the same period last year due to higher operating
expenses. Operating expenses increased $62.0 million reflecting primarily an
increase in the provision for uncollectible accounts receivable and higher
property taxes totaling $45.8 million. Partially offsetting the higher operating
expenses was an increase of $48.0 million in net gas revenues (revenues less the
cost of gas and associated revenue taxes) resulting from customer additions and
oil-to-gas conversions in our firm gas sales market, as well as from higher net
gas revenues in our large-volume heating markets.
Net Revenues
Net gas revenues from our gas distribution operations increased $48.0 million,
or 3%, for the twelve months ended December 31, 2005, compared to the same
period last year. Net gas revenues benefited from customer additions and
oil-to-gas conversions in our firm gas sales market (residential, commercial and
industrial customers), as well as from higher net gas revenues in our
large-volume heating and interruptible (non-firm) markets. As measured in
heating degree days, weather in 2005 in our New York and New England service
territories was approximately 1.0% and 8.6% colder than normal, respectively.
Compared to 2004, weather in 2005 was 1.2% colder in KeySpan's New England
service territory, while weather was consistent between years in the New York
service territory.
52
Net revenues from firm gas customers (residential, commercial and industrial
customers) increased $24.3 million for the twelve months ended December 31,
2005, compared to the same period last year. Customer additions and oil-to-gas
conversions, net of attrition and conservation, added $25.1 million to net gas
revenues. Further, we realized a benefit of $3.8 million as a result of the
Boston Gas Company's Performance Based Rate Plan (the "Plan") that was approved
by the Massachusetts Department of Telecommunications and Energy ("MADTE") in
2003. The Plan provides for firm gas sales rates to be adjusted each year based
on an inflation factor offset by a productivity factor. (See the caption under
"Regulation and Rate Matters" for further information regarding the rate
filing.)
Offsetting, to some extent, the beneficial impact of the customer additions and
oil-to-gas conversions was the adverse impact to comparative net gas revenues
from the additional billing day last year due to the leap year. In 2004, KeySpan
realized $5.7 million in additional net gas revenues from the additional billing
day. Further, KeySpan earned $8.7 million less in regulatory incentives for the
twelve months ended December 31, 2005, compared to the same period last year.
Also included in net revenues is the recovery of certain regulatory items and
certain taxes that added $6.6 million to net revenues. However, the recovery of
these items through revenues 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. Firm gas distribution rates for KEDNY, KEDLI
and KEDNE in 2005, other than for the recovery of gas costs and as noted, have
remained substantially unchanged from rates charged in 2004.
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. However, the gas distribution
operations of our New England based subsidiaries do not have a weather
normalization adjustment. 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 2004/2005 and 2005/2006 winter heating
seasons. These financial derivatives afforded KeySpan some protection against
warmer than normal weather. As a result of the weather fluctuations and
financial weather derivatives, weather had a $3.2 million favorable impact on
comparative net gas revenues. (See Note 8 to the Consolidated Financial
Statements "Hedging, Derivative Financial Instruments and Fair Values" for
further information on derivative transactions.)
In our large-volume heating and 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 $23.7 million during the twelve months ended December
31, 2005, compared to the same period last year, primarily reflecting higher
pricing. Further, since weather during January 2004 was significantly colder
than normal, KeySpan interrupted service to a segment of its dual-fuel customers
for a number of days during the month, as permitted under its tariff, to ensure
reliable service to firm customers. The majority of interruptible profits earned
by KEDLI and KEDNE are returned to firm customers as an offset to gas costs.
53
Firm Sales, Transportation and Other Sales Quantities
Both actual firm gas sales and transportation quantities, as well as weather
normalized sales quantities for the twelve months ended December 31, 2005,
remained consistent with those quantities realized in 2004. 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
transportation 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. The increase in these sales quantities for the
twelve months ended December 31, 2005 compared to the same period of 2004
reflects higher off-system sales. The majority of these profits earned are
returned to firm customers as an offset to gas costs. From April 1, 2002 through
March 31, 2005, we had an agreement with Coral Resources, L.P. ("Coral"), a
subsidiary of Shell Oil Company, under which Coral assisted in the origination,
structuring, valuation and execution of energy-related transactions on behalf of
KEDNY and KEDLI. Upon the expiration of this agreement, these services are
provided by 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. A new three
year agreement has been negotiated with Merrill Lynch to provide portfolio
management services to KeySpan's Massachusetts gas distribution subsidiaries.
This agreement is pending MADTE approval. KeySpan will provide these services
internally for its New Hampshire gas distribution subsidiary, EnergyNorth.
Purchased Gas for Resale
The increase in gas costs for the twelve months ended December 31, 2005,
compared to the same period of 2004, of $942.3 million, or 35%, reflects an
increase of 23% in the price per dekatherm of gas purchased for firm gas sales
customers, as well as an increase in the quantity of gas purchased for
large-volume heating and interruptible (non-firm) customers. 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 resale to firm sales customers and gas costs billed to firm sales
customers are deferred and refunded to or collected from customers in a
subsequent period.
Operating Expenses
For the twelve months ended December 31, 2005, operating expenses increased
$62.0 million, or 6% compared to the same period last year. Operations and
maintenance expense increased $54.5 million, or 8%, in 2005 compared to 2004
primarily due to an increase of $38.7 million in the provision for uncollectible
accounts as a result of increasing gas costs and the adverse impact from recent
collection experience. Further, the gas distribution operations realized an
increase in insurance and regulatory fees, as well as postretirement expenses in
2005 compared to 2004. In 2004, KeySpan recognized 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 ( the "Medicare Act") and implementation of Financial
54
Accounting Standards Board Staff Position ("FSP") 106-2. In addition, in 2004,
Boston Gas reached an agreement with an insurance carrier for recovery of
previously incurred environmental expenditures. Insurance and third-party
recoveries, after deducting legal fees, are shared between Boston Gas and its
firm gas customers as provided under a previously issued MADTE rate order. As a
result of this insurance settlement, Boston Gas recorded a $5 million benefit to
operations and maintenance expense.
Comparative operating taxes increased $7.1 million due to the expiration of a
five-year property tax assessment agreement with New York City, as well as to a
$2.5 million property tax refund received in 2004. Higher depreciation charges
of $4.5 million reflecting the continued expansion of the gas distribution
system were offset by lower regulatory amortization charges of $4.1 million.
In December 2005, Boston Gas received a MADTE order permitting regulatory
recovery of the 2004 gas cost component of bad debt write-offs. This was
approved for full recovery as an exogenous cost effective November 1, 2005. In
addition, effective January 1, 2006, Boston Gas is permitted to fully recover
the gas cost component of bad debt write-offs through its cost-of-gas adjustment
clause rather than filing for recovery as an exogenous cost. We have reflected
both of these favorable recovery mechanisms in our December 31, 2005 Allowance
for Doubtful Accounts reserve requirement and related expense. Boston Gas also
plans to request full recovery, as an exogenous cost, of the 2005 gas cost
component of bad debt write-offs beginning November 1, 2006.
Executive Summary
Operating Income 2004 vs 2003
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 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 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.
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 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 2003 in our New England service
territory.
55
Net revenues from firm gas customers (residential, commercial and industrial
customers) increased $40.8 million for the twelve months ended December 31, 2004
compared to the same period of 2003. As previously mentioned, the MADTE approved
a $27 million base rate increase for Boston Gas, which became effective on
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.) Customer additions and oil-to-gas conversions, net of
attrition and conservation, added $8.0 million to net gas revenues. Further, we
realized a $5.7 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.
Also included in net gas revenues is the recovery of property taxes that were
$1.0 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 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.
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. However, the gas distribution
operations of our New England based subsidiaries do not have a weather
normalization adjustment. To mitigate the effect of fluctuations in weather
patterns on KEDNE's results of operations and cash flows, weather derivatives
were in place for the 2003/2004 and 2004/2005 winter heating seasons. These
financial derivatives afforded KeySpan some protection against warmer than
normal weather. As a result of weather fluctuations year-to-year, offset by the
benefits of the financial weather derivatives, weather had a $2.9 million
unfavorable impact on comparative net gas revenues.
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 KEDLI and KEDNE are returned to firm customers
as an offset to gas costs.
Firm Sales, Transportation and Other Sales 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 service territories during 2004. 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.
56
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.
Operating Expenses
Total operating expenses for the year ended December 31, 2004 increased $22.6
million, or 2%, compared to 2003, 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 $3
million, net of amounts subject to regulatory deferral treatment, associated
with the implementation of the Medicare Act and implementation of Financial
Accounting Standards Board Staff Position ("FSP") 106-2. In addition, in 2004,
Boston Gas reached a settlement with an insurance carrier for recovery of
previously incurred environmental expenditures. Insurance and third-party
recoveries, after deducting legal fees, are shared between Boston Gas and its
firm gas customers under a previously issued MADTE rate order. As a result of
this insurance settlement, Boston Gas recorded a $5 million benefit to
operations and maintenance expense.
Higher depreciation and amortization expense in 2004 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.
Sale of Property
During 2003 we recorded $15.1 million in gains from property sales, primarily
the sale of 550 acres of real property located on Long Island.
Gas Supply and Pricing
KeySpan has adequate gas supply available to meet its gas load demand in its
service territories for the 2005/2006 winter heating season as KeySpan's gas
storage was 100% full at the start of the winter heating season. The current gas
rate structure of each of our gas distribution utilities includes a gas
adjustment clause, pursuant to which gas costs are recovered in billed sales to
regulated firm gas sales customers. Although KeySpan is allowed to "pass
through" the cost of gas to its customers, management is concerned with the
rising natural gas prices and the related impact on customers' gas bills and
recovery of customer accounts receivable. As noted, KeySpan has already
experienced an increase in bad debt expense and an increase in collection lag.
Also, it is likely that the high gas prices will lead to an increase in price
elasticity possibly resulting in an increase in customer conservation measures
and attrition. The recent MADTE order permitting Boston Gas regulatory recovery
of the gas cost component of net bad debt write-offs should help to mitigate the
increase in bad debt expense.
57
With our strategy of having KeySpan's storage facilities 100% full at the start
of the heating season and our use of financial derivatives, KeySpan has
effectively hedged the price of approximately two-thirds of the gas supply
needed to serve its customers during the upcoming 2005/2006 winter. This helps
mitigate the impact from rising natural gas prices on customers' winter heating
gas bills. Further, KeySpan has programs in place to help customers manage their
gas bills, such as balanced billing plans, deferred payment arrangements and the
low income home energy assistance program, which we supported the expansion of
through the Energy Act. Management believes that these measures will help
mitigate the impact of rising gas prices on customers' bills.
Other Matters
We remain committed to our ongoing gas system expansion strategies. We believe
that significant growth opportunities exist on Long Island and in our New
England service territories, as well as continued growth in the New York service
territory, despite the rising gas prices. We estimate that on Long Island
approximately 37% of the residential and multi-family markets, and approximately
60% 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 approximately 60% of
the commercial market, currently use natural gas for space heating purposes. We
will continue to seek growth, in all our market segments, through the expansion
of our gas distribution system for new construction and to penetrate existing
communities where no distribution system exists, as well as through the
conversion of residential homes from oil-to-gas for space heating purposes where
natural gas is already in the home for other uses and the pursuit of
opportunities to grow multi-family, industrial and commercial markets.
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. Once in service, the pipeline is
expected to transport up to 260,000 DTH of natural gas to the Long Island and
New York City energy markets, enough natural gas to heat 600,000 homes. In
addition, during 2004 KeySpan acquired a 21% interest in the Millennium Pipeline
development project which is anticipated to transport up to 525,000 DTH of
natural gas a day to the Algonquin pipeline. KEDLI has executed a Precedent
Agreement for 150,000 DTH of natural gas per day of transportation capacity from
the Millennium Pipeline system, increasing to 200,000 DTH in the third year of
the pipeline being in service. These pipeline projects will allow KeySpan to
diversify the geographic sources of its gas supply. See the discussion under the
caption "Energy Investments" for additional information regarding these pipeline
projects.
58
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 Generating Station" which comprises the Ravenswood
Facility and Ravenswood Expansion) and the counties of Nassau and Suffolk on
Long Island. In addition, through long-term contracts of varying lengths, 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 "1998 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 "1998 PSA"); 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 "1998 EMA"). The 1998 MSA, 1998
PSA and 1998 EMA all became effective on May 28, 1998 and are collectively
referred to herein as the "1998 LIPA Agreements."
On February 1, 2006, KeySpan and LIPA entered into (i) an amended and restated
Management Services Agreement (the "2006 MSA"), pursuant to which KeySpan will
continue to operate and maintain the electric T&D System owned by LIPA on Long
Island; (ii) a new Option and Purchase and Sale Agreement (the "2006 Option
Agreement"), to replace the Generation Purchase Rights Agreement as amended, the
("GPRA"), pursuant to which LIPA had the option, through December 15, 2005, to
effectively acquire substantially all of the electric generating facilities
owned by KeySpan on Long Island; and (iii) a Settlement Agreement (the "2006
Settlement Agreement") resolving outstanding issues between the parties
regarding the 1998 LIPA Agreements. The 2006 MSA, the 2006 Option Agreement and
the 2006 Settlement Agreement are collectively referred to herein as the "2006
LIPA Agreements". (For a further discussion on these LIPA agreements see the
discussion under the caption "Electric Services - LIPA Agreements" and Note 11
to the Consolidated Financial Statements "2006 LIPA Settlement.") The Electric
Services segment also provides retail marketing of electricity to commercial
customers.
Selected financial data for the Electric Services segment is set forth in the
table below for the periods indicated.
- -------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Millions of Dollars) 2005 2004 2003
- -------------------------------------------------------------------------------------------------------
Revenues $ 2,047.3 $ 1,738.7 $ 1,606.1
Purchased fuel 751.4 539.6 464.8
- -------------------------------------------------------------------------------------------------------
Net Revenues 1,295.9 1,199.1 1,141.3
- -------------------------------------------------------------------------------------------------------
Operating Expenses
Operations and maintenance 684.5 653.3 658.6
Depreciation 91.7 88.3 67.2
Operating taxes 178.6 169.7 145.6
- -------------------------------------------------------------------------------------------------------
Total Operating Expenses 954.8 911.3 871.4
- -------------------------------------------------------------------------------------------------------
Gain on the sale of property 1.2 2.0 -
Operating Income $ 342.3 $ 289.8 $ 269.9
- -------------------------------------------------------------------------------------------------------
Electric sales (MWH)* 6,364,279 6,232,190 4,738,331
Capacity(MW)* 2,450 2,450 2,200
Summer cooling degree days 1,472 1,045 988
- -------------------------------------------------------------------------------------------------------
*Reflects the operations of the Ravenswood Generating Station only.
59
Executive Summary
Operating Income 2005 vs 2004
For the twelve months ended December 31, 2005, operating income increased $52.5
million, or 18%, compared to last year, primarily due to an increase in net
revenues from the Ravenswood Generating Station of $78.7 million mainly as a
result of improved pricing, partially offset by an increase in operating
expenses associated with the Ravenswood Generating Station of $11.8 million, as
well as lower net revenues associated with KeySpan's retail electric marketing
activities of $7.6 million.
Net Revenues
Total electric net revenues realized during the twelve months ended December 31,
2005, were $96.8 million, or 8% higher than such revenues realized during the
corresponding period last year.
For the year ended December 31, 2005, net revenues from the Ravenswood
Generating Station increased $78.7 million, or 22%, compared to the same period
last year reflecting higher energy margins of $66.0 million, as well as
increased capacity revenues of $12.7 million. The increase in capacity revenues
reflects the operation of the Ravenswood Expansion which went into full
commercial operation in May 2004, as well as load growth in New York City.
The increase in energy margins for 2005 reflects an increase of 45% in realized
"spark-spreads" (the selling price of electricity less the cost of fuel, plus
hedging gains or losses), as well as from an increase of 2% in the level of
megawatt hours ("MWh") sold into the New York Independent System Operator
("NYISO") energy market. These favorable energy results were primarily driven by
the pricing differential between number 6-grade fuel oil and natural gas used in
the Ravenswood Generating Station in 2005. Due to the dual-fuel nature of the
Ravenswood Generating Station, KeySpan was able to take advantage of their
ability to switch to cheaper fuel as the gap between number 6 grade fuel oil and
gas prices spread during the latter part of the 2005 summer. The two hurricanes
which occurred this past summer in the Gulf Coast of the United States
contributed to the gap between number 6-grade fuel oil and natural gas prices.
Further, in 2005 KeySpan received $9.2 million from the NYISO to settle billing
issues regarding the sale of energy provided by the Ravenswood Generating
Station to the NYISO in May 2000. Weather for 2005, as measured in cooling
degree days, was 40% warmer than last year and 28% warmer than normal.
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 Generating Station. 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 Generating Station. These derivative instruments resulted in
hedging losses, which are reflected in net electric margins, of $16.0 million in
2005 compared to hedging gains of $23.0 million in 2004. The results derived
from KeySpan's hedging strategy are reflected in the calculation of realized
spark-spreads. (See Note 8 to the Consolidated Financial Statements "Hedging,
Derivative Financial Instruments and Fair Values" as well as Item 7A.
Quantitative and Qualitative Disclosures about Market Risk for further
information on KeySpan's hedging strategies.)
60
The rules and regulations for capacity, energy sales and the sale of certain
ancillary services to the NYISO energy markets continue to evolve and there are
several matters pending with the FERC. See the discussion under the caption
"Market and Credit Risk Management Activities" for further details on these
matters.
Net revenues for the twelve months ended December 31, 2005, from the service
agreements with LIPA, including the power purchase agreements associated with
two electric peaking facilities, increased $25.7 million compared to the
corresponding period of 2004. The increase is due, in part, to recovery of
operating expenses billed to LIPA of approximately $14 million and the recovery
of depreciation charges and property taxes of approximately $8 million. These
recoveries had no impact on operating income since actual expenses increased by
a like amount. The remaining increase primarily reflects an increase in emission
credits earned and variable revenues, which are a function of electric
generation output. In 2005 and 2004 we earned $16.4 million associated with
non-cost performance incentives provided for under these agreements. (For a
description of the LIPA Agreements and power purchase agreements, see the
discussion under the caption "Electric Services - LIPA Agreements.")
Net revenues associated with KeySpan's retail electric marketing activities
decreased $7.6 million in 2005 compared to 2004, due to a significant
curtailment in these activities. KeySpan has terminated all indexed price
contracts and has elected to maintain only its fixed priced contracts. As a
result, the retail electric marketing business has approximately 40 MW under
contract.
Operating Expenses
For the twelve months ended December 31, 2005, operating expenses increased
$43.5 million, or 5%, compared to the same period last year. Operations and
maintenance expense increased $31.2 million, or 5% over last year reflecting an
increase of $7.5 million in operating lease costs associated with our financing
arrangement for the Ravenswood Expansion, as well as an increase in overhaul
work and plant retirement costs associated with the Ravenswood Generating
Station amounting to approximately $8 million. The remaining increase reflects
operating costs billed to LIPA of approximately $14 million.
Depreciation expense and operating taxes increased $12.3 million in 2005
compared to 2004. Of this amount, approximately $8 million is associated with
KeySpan's Long Island based electric generating units and are fully recoverable
from LIPA, as noted above. The remaining increase in these line items is
associated with the Ravenswood Generating Station.
61
Executive Summary
Operating Income 2004 vs 2003
Operating income increased $19.9 million for the twelve months ended December
31, 2004 compared to the same period in 2003, due primarily to an increase in
net revenues from the Ravenswood Generating Station of $53.8 million, partially
offset by higher depreciation expense and operating taxes. In addition, in 2004,
KeySpan recognized a gain of $2.0 million on the sale of a parcel of land in Far
Rockaway, Queens, to LIPA.
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 Generating Station 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 in 2004, compared to 2003 primarily reflects the operation of
the Ravenswood Expansion.
The increase in energy margins for the twelve months ended December 31, 2004,
reflects a 32% increase in the level of MWh's sold into the NYISO energy market,
as well as an increase of 9% in realized spark-spreads. 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 2003, 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.
As noted, 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 Generating Station. 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 Generating Station. 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.
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.
62
In addition to the above, net revenues from our electric marketing activities
were slightly lower in 2004 compared to 2003.
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 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 classification 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 Generating Station, as well as higher
postretirement costs, which, for the most part, offset the beneficial impact of
FIN 46. (See Note 7 to the Consolidated Financial Statements "Contractual
Obligations, Financial Guarantees and Contingencies" for an explanation of the
Ravenswood Master Lease.)
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.
Other Matters
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 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 power from a non-Long Island source of
between 250 to 600 MW of electricity by no later than the summer of 2007.
KeySpan filed a proposal in response to LIPA's RFP. In 2004, LIPA 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
63
distribution network. In addition, given the intense public pressure to reduce
emissions from existing generating facilities, development of the Melville
project is possible as a means to "virtually re-power" older, less efficient
generating units. Specifically, KeySpan believes that it would be able to reduce
emissions on Long Island in a cost effective manner by developing the Melville
project and retiring an older, less efficient generating facility. We have begun
discussions with LIPA regarding this proposal. At December 31, 2005, total
capitalized costs associated with the siting, permitting and procurement of
equipment for the Melville facility were $61.2 million.
In March 2005, LIPA issued a RFP to provide system power supply management
services beginning May 29, 2006 and fuel management services for certain of its
peaking generating units beginning January 1, 2006. A KeySpan subsidiary is
currently performing these services. KeySpan submitted a bid in response to the
new RFP in April 2005. LIPA was scheduled to select a service provider in June
2005, but has deferred such decision at this time. Pending LIPA's determination
on the RFP, the service agreements between KeySpan and LIPA which provide for
these services have been extended to December 31, 2006. We cannot predict the
outcome or the timing of any decisions by LIPA on this matter at this time.
Also, in March 2005, the New York Power Authority ("NYPA") issued a RFP for
long-term New York City capacity and energy to meet the needs of its customers
at prices that are economical, stable and predictable over the long run. In June
2005, KeySpan submitted a non-binding bid in response to NYPA's RFP in which we
proposed to construct a 500 MW, combined cycle, natural gas fired power plant to
be located in New York City, which could provide energy and capacity to NYPA.
The proposed facility could be in commercial operation by June 2009. We cannot
predict the outcome or the timing of any decisions by NYPA on this matter at
this time.
As part of our growth strategy, we continually evaluate the possible acquisition
and development of additional generating facilities in the Northeast, as well as
other assets to complement our core operations. 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.
Currently, the NYISO's New York City local reliability rules require that 80% of
the electric capacity needs of New York City be provided by "in-City"
generators. On February 6, 2006, the NYISO Operating Committee increased the
"in-City" generator requirement to 83% beginning in May 2006 through the period
ending on April 2007, based in part on the statewide reserve margin of 118% set
by the New York State Reliability Council. On February 16, 2006 an appeal was
filed with the NYISO Management Committee requesting that the February 6th
decision be rejected and that the "in-City" requirement be increased to a larger
percentage than 83%. A vote on this appeal is expected to occur at the NYISO
Management Committee meeting scheduled for February 28, 2006.
Our Ravenswood Generating Station is an "in-City" generator. As the electric
infrastructure in New York City and the surrounding areas continues to change
and evolve and the demand for electric power increases, the "in-City" generator
requirement could be further modified. Construction of new transmission and
generation facilities may cause significant changes to the market for sales of
capacity, energy and ancillary services from our Ravenswood Generating Station.
Recently 500 MW of capacity came on line and it is anticipated that another
500MW of new capacity may be available during 2006 as a result of the completion
of an in-City generation project currently under construction. We can not,
however, be certain as to when the new power plant will be in operation or the
nature of future New York City energy, capacity or ancillary services market
requirements or design.
64
KeySpan continues to believe that New York City represents a strong capacity
market and has entered into an International Swap Dealers Association ("ISDA")
Master Agreement for a fixed for float unforced capacity financial swap (the
"Swap Agreement") with Morgan Stanley Capital Group Inc. ("Morgan Stanley")
dated as of January 18, 2006. The Swap Agreement has a three year term beginning
May 1, 2006, (assuming a condition to effectiveness has been satisfied by such
date). The notional quantity is 1,800,000kW (the "Notional Quantity") of In-City
Unforced Capacity and the fixed price is $7.57/kW-month ("Fixed Price"), subject
to adjustment upon the occurrence of certain events. Settlement would occur on a
monthly basis based on the In-City Unforced Capacity price determined by the
relevant New York Independent System Operator Spot Demand Curve Auction Market
("Floating Price"). For each monthly settlement period, the price difference
will equal the Fixed Price minus the Floating Price. If such price difference is
less than zero, Morgan Stanley will pay KeySpan an amount equal to the product
of (a) the Notional Quantity and (b) the absolute value of such price
difference. Conversely, if such price difference is greater than zero, KeySpan
will pay Morgan Stanley an amount equal to the product of (a) the Notional
Quantity and (b) the absolute value of such price difference.
Energy Services
The Energy Services segment includes companies that provide energy-related
services to customers located primarily within the Northeastern United States.
Subsidiaries in this segment provide residential and small commercial customers
with service and maintenance of energy systems and appliances, as well as
operation and maintenance, design, engineering, consulting and fiber optic
services to commercial, institutional and industrial customers.
In January and February of 2005, KeySpan sold its mechanical contracting
subsidiaries in this segment and exited such businesses. In the fourth quarter
of 2004, KeySpan's investment in its discontinued mechanical contracting
subsidiaries was written-down to an estimated fair value. In 2005, operating
losses were incurred through the dates of sale of these companies of $4.1
million after-tax, including, but not limited to, costs incurred for employee
related benefits. Partially offsetting these losses was an after-tax gain of
$2.3 million associated with the related divestitures, reflecting the difference
between the fair value estimates and the financial impact of the actual sale
transactions. The net income impact of the operating losses and the disposal
gain was a loss of $1.8 million, or $0.01 per share in 2005. (See Note 2 to the
Consolidated Financial Statements "Business Segments" for additional details on
the sale of the mechanical companies.)
The table below highlights selected financial information for the Energy
Services segment.
- --------------------------------------------------------------------------------
Year Ended December 31,
(In Millions of Dollars) 2005 2004 2003
- --------------------------------------------------------------------------------
Revenues $ 202.0 $ 193.9 $ 166.4
Less: Operating expenses 204.7 227.8 199.4
Goodwill impairment 14.4 -
- --------------------------------------------------------------------------------
Operating (Loss) $ (2.7) $ (48.3) $ (33.0)
- --------------------------------------------------------------------------------
65
Operating Income 2005 vs 2004
The Energy Services segment incurred an operating loss of $2.7 million in 2005,
compared to a loss of $48.3 million in 2004. In 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. 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), was reflected in
discontinued operations. (See Note 10 to the Consolidated Financial Statements
"Energy Services - Discontinued Operations" for additional details on this
charge.)
For 2005, the improved performance over last year, excluding the goodwill
impairment charge, primarily reflects a reduction in operating expenses. In
2004, charges associated with the write-off of accounts receivable and contract
revenues on certain projects that were determined to be uncollectible, were
incurred as well as the write-down of inventory balances. Further, this segment
experienced an increase in gross profit margins and generally lower
administrative costs in 2005.
Operating Income 2004 vs 2003
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, in 2004 KeySpan recorded a non-cash goodwill
impairment charge in continuing operations of $14.4 million. Excluding the
goodwill impairment charge, operating income for the twelve months ended
December 31, 2004, was essentially the same as 2003, as higher revenues were
offset by higher operating expenses.
Energy Investments
The Energy Investments segment consists of our gas exploration and production
investments, as well as certain other domestic energy-related investments.
KeySpan's gas exploration and production activities include its wholly-owned
subsidiaries Seneca Upshur Petroleum, Inc. ("Seneca-Upshur") and KeySpan
Exploration and Production, LLC ("KeySpan Exploration"). Seneca-Upshur is
engaged in gas exploration and production activities primarily in West Virginia.
KeySpan Exploration is primarily engaged in a joint venture with Houston
Exploration.
This segment is also engaged in pipeline development activities. KeySpan and
Duke Energy Corporation each own a 50% interest in 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. Further, KeySpan has a 21% interest in the Millennium
Pipeline project which is expected to transport up to 525,000 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. These subsidiaries are
66
accounted for under the equity method of accounting. Accordingly, equity income
from these investments is reflected as a component of operating income in the
Consolidated Statement of Income. KeySpan also owns a 600,000 barrel liquefied
natural gas ("LNG") storage and receiving facility in Providence, Rhode Island,
through its wholly owned subsidiary KeySpan LNG, the operations of which are
fully consolidated. KeySpan LNG is re-evaluating its plans to upgrade its LNG
facility in Providence, Rhode Island in light of the FERC decision that denied
KeySpan LNG's application for FERC authorization to expand the facility to
accept marine deliveries and triple vaporization capacity.
During the first quarter of 2004, we also had an approximate 61% investment in
certain midstream natural gas assets in Western Canada through KeySpan Canada.
These assets included 14 processing plants and associated gathering systems that
produced approximately 1.5 BCFe of natural gas daily and provided associated
natural gas liquids fractionation. These operations were fully consolidated in
KeySpan's Consolidated Financial Statements. On April 1, 2004, KeySpan and
KeySpan Facilities Income Fund (the "Fund"), an open-ended income trust which
previously owned a 39% interest in KeySpan Canada, consummated a transaction
that reduced KeySpan's ownership interest in KeySpan Canada to 25%. The
transaction resulted in a gain of $22.8 million ($10.1 million after-tax, or
$0.06 per share). Effective April 1, 2004 KeySpan Canada's earnings and our
ownership interest in KeySpan Canada were accounted for on the equity method 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. (See Note 2 to the Consolidated
Financial Statements "Business Segments" for additional details regarding this
transaction.)
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. Additionally, we sold our 20% interest in Taylor NGL LP
that owned and operated 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.
In the first quarter of 2005, KeySpan sold its 50% interest in Premier, a gas
pipeline from southwest Scotland to Northern Ireland pursuant to a Share Sale
and Purchase Agreement with BG Energy Holdings Limited and Premier Transmission
Financing Public Limited Company ("PTFPL"), under which all of the outstanding
67
shares of Premier were to be purchased by PTFPL. On March 18, 2005, the sale was
completed and generated cash proceeds of $48.1 million. In the fourth quarter of
2004, KeySpan recorded a pre-tax non-cash impairment charge of $26.5 million
reflecting the difference between the anticipated cash proceeds from the sale of
Premier compared to its carrying value. The final sale of Premier resulted in a
pre-tax gain of $4.1 million reflecting the difference from earlier estimates.
This gain was recorded in other income and (deductions) on the Consolidated
Statement of Income.
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 and operating statistics for these energy-related
investments are set forth in the following table for the periods indicated.
These results exclude the results of Houston Exploration.
- ---------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Millions of Dollars) 2005 2004 2003
- ---------------------------------------------------------------------------------------------------
Revenues $ 43.0 $ 58.9 $ 119.0
Less: Operation and maintenance expense 26.5 33.5 68.6
Ceiling test write-down - 48.2 -
Impairment charge - 26.5 -
Other operating expenses 11.1 15.3 27.3
Add: Equity earnings 15.1 25.8 19.1
Sale of assets 0.1 5.0 -
- ---------------------------------------------------------------------------------------------------
Operating Income (Loss) $ 20.6 $ (33.8) $ 42.2
- ---------------------------------------------------------------------------------------------------
Operating income above reflects 100% of KeySpan Canada's results from January 1,
2003 through April 1, 2004.
Operating Income 2005 vs 2004
For the twelve months ended December 31, 2005, operating income for this segment
increased $54.4 million compared to the same period of 2004, reflecting non-cash
impairment charges recorded last year of $74.7 million. As noted earlier, in
2004, KeySpan's wholly owned gas exploration and production subsidiaries that
have remained with KeySpan after the Houston Exploration transaction, recorded a
non-cash impairment charge of $48.2 million 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.)
Further, in the fourth quarter of 2004, KeySpan recorded a pre-tax non-cash
impairment charge of $26.5 million reflecting the difference between the
anticipated cash proceeds from the sale of Premier compared to its carrying
value.
Operating income for the twelve months ended December 31, 2004, also includes
$16.5 million in earnings from KeySpan Canada. The remaining activities
reflected a decrease in operating income of $3.8 million primarily due to the
sale of real property in 2004.
68
Operating Income 2004 vs 2003
The decrease in comparative operating income in 2004 compared to 2003 of $76.0
million reflects the impairment charges recorded in 2004, as well as our lower
ownership interest in KeySpan Canada. Operating income for the twelve months
ended December 31, 2004, includes $16.5 million in earnings from KeySpan Canada
compared to operating income of $29.7 million for the twelve months ended
December 31, 2003. Excluding the impairment charges and KeySpan Canada, the
remaining activities reflected an increase in operating income of $11.9 million
primarily due to the sale of real property in 2004, higher earnings from gas
pipeline investments and lower administrative costs.
During the first five months of 2004, our gas exploration and production
investments also included a 55% equity interest in Houston Exploration, the
operations of which were consolidated in KeySpan's Consolidated Financial
Statements. On June 2, 2004, KeySpan exchanged 10.8 million shares of common
stock of Houston Exploration for 100% of the stock of Seneca-Upshur, previously
a wholly owned subsidiary of Houston Exploration. This transaction reduced our
interest in Houston Exploration from 55% to the then current level of 23.5%.
Effective June 2, 2004, Houston Exploration's earnings and our ownership
interest in Houston Exploration were accounted for on the equity method of
accounting. 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. 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.
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.
69
Selected financial data and operating statistics for Houston Exploration for
2004 and 2003 are set forth in the following table.
- ------------------------------------------------------------------------------
Year Ended December 31,
(In Millions of Dollars) 2004 2003
- ------------------------------------------------------------------------------
Revenues $ 268.1 $ 495.3
Depletion and amortization expense 104.6 204.1
Other operating expenses 45.7 94.9
Add: Equity Earnings 20.7 -
- ------------------------------------------------------------------------------
Operating Income $ 138.5 $ 196.3
- ------------------------------------------------------------------------------
Houston Exploration
Operating Income 2004 vs 2003
The decline in operating income of $57.8 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 June 2, 2004, then held an approximate 23.5% interest
for the five month period June 2, 2004 through October 31, 2004. KeySpan then
sold its remaining 23.5% interest in Houston Exploration in November 2004.
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 FERC and all necessary permits from the
State of New York. The State of Connecticut denied Islander East's request for a
consistency determination under the Coastal Zone Management Act ("CZMA") and
application for a permit under Section 401 of the Clean Water Act. Islander East
appealed the State of Connecticut's determination on the CZMA issue to the
United States Department of Commerce. In 2004, the Department of Commerce
overrode Connecticut's denial and granted the CZMA authorization. Islander
East's petition for a declaratory order overriding the denial of the Clean Water
Act permit is pending with Connecticut's State Superior Court. Pursuant to a
provision of the Energy Act, Islander East has appealed the denial of the Clean
Water Act permit directly to the United States Court of Appeals for the Second
Circuit and has moved to stay the Connecticut case pending the Second Circuit's
decision. The State of Connecticut has filed a motion to challenge the
constitutionality of the provisions of the Energy Act providing this appeal
right. The appeal was argued in January 2006 and a decision is expected within
the first six months of 2006. Various options for the financing of this pipeline
construction are being evaluated. As of December 31, 2005, KeySpan's total
capitalized costs associated with the siting and permitting of the Islander East
pipeline were approximately $24.6 million.
70
KeySpan also owns a 21% ownership interest in the Millennium Pipeline project.
KeySpan acquired its interest in the project from Duke Energy in August 2004.
The other partners in the Millennium Pipeline are Columbia Gas Transmission
Corp., a unit of NiSource Incorporated and DTE Energy. It is anticipated that
KeySpan will acquire an additional 5.25% ownership interest in Millennium from
Columbia during the first quarter of 2006, bringing our total ownership interest
in Millennium to 26.25%. The Millennium Pipeline project is anticipated to
transport up to 525,000 DTH of natural gas a day from Corning to Ramapo, New
York, interconnecting with the pipeline systems of various other utilities in
New York. The project received a FERC certificate to construct, acquire and
operate the facilities in 2002. On August 1, 2005, the project filed an amended
application with FERC requesting, among other things, approval of a reduction in
capacity and maximum allowable operating pressure, minor route modifications,
the addition of certain facilities and the acquisition of certain facilities
from Columbia Gas Transmission Corporation. Additionally, in December 2005, The
Consolidated Edison Company of New York ("Con Edison"), KEDLI and Columbia Gas
Transmission each entered into amended precedent agreements to purchase capacity
on the pipeline. KEDLI has agreed to purchase 150,000 DTH per day from the
Millennium Pipeline system, increasing to 200,000 DTH in the third year of the
pipeline being in service. This will provide KEDLI with new, competitively
priced supplies of natural gas from Canada. Subject to, among other things, the
conditions precedent in the precedent agreements, the receipt of necessary
regulatory approvals and financing, it is anticipated that construction on the
Millennium Pipeline will be in service in either 2007 or 2008. As of December
31, 2005, total capitalized costs associated with the Millennium Pipeline
project were $10.4 million.
In 2005, KeySpan LNG entered into a joint development agreement with BG, LNG
Services, a subsidiary of British Gas, to upgrade KeySpan LNG's liquidfied
natural gas ("LNG") facility to accept marine deliveries and to triple
vaporization (or regasification) capacity. In June 2005, the FERC denied KeySpan
LNG's application to expand the facility citing concerns that the proposed
upgraded facility would not meet current federal safety standards, which the
facility is not currently subject to. KeySpan sought a rehearing with FERC, and
on January 20, 2006 the FERC denied such request, although the order provided
that KeySpan LNG could file an amendment to its original application addressing
a revised expansion project which would differ substantially from that
originally proposed by KeySpan. Any amendment application would need to include
a detailed analysis of the new project scope, including upgrades to the existing
facilities and alternative plans for any service disruptions that may be
necessary during construction of a new expanded project. KeySpan is evaluating
whether to appeal FERC's current order.
In addition to the
proceeding at FERC, KeySpan LNG also is involved in seeking other required
regulatory approvals and the resolution of certain litigation regarding such
approvals. In February 2005, KeySpan LNG filed an action in Federal District
Court in Rhode Island seeking a declaratory judgment that it is not required to
obtain a "Category B Assent" from the State of Rhode Island and an injunction
preventing the Rhode Island Coastal Resources Management Council ("CRMC") from
enforcing the Category B assent requirements. In March 2005, the Rhode Island
Attorney General answered the complaint and moved to substitute the State of
Rhode Island as the defendant and filed a counterclaim seeking a declaratory
judgment that the expansion requires a Category B Assent. In April, the parties
filed cross motions for summary judgment with respect to all issues presented to
the Court. On April 14, 2005, the Attorney General also filed on behalf of the
State a complaint against KeySpan LNG in Rhode Island State Superior Court
raising substantially the same issues as the federal court action. KeySpan LNG
removed that action to federal court and moved for summary judgment. The
Attorney General subsequently withdrew both the motion to substitute defendants
and the counterclaim. Although the Court had indicated its intention to issue a
decision in the pending cases by August 2005, the Court has now indicated that
it will stay the litigation pending resolution of the FERC rehearing and/or
appeal process discussed above. Since the FERC order is a recent development,
the Court has not yet taken any action. As of December 31, 2005, our investment
in this project was $15.3 million.
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Allocated Costs
As previously noted, at December 31, 2005 KeySpan was a holding company under
PUHCA 1935. As a result of the Energy Act, PUHCA 1935 was repealed and replaced
by PUHCA 2005 as of February 8, 2006. Under PUHCA 1935, the SEC had jurisdiction
over our holding company activities, including the regulation of our affiliate
transactions and service companies. In accordance with those regulations and
state regulatory agencies' regulations, we established service companies that
provide: (i) traditional corporate and administrative services; (ii) gas and
electric transmission and distribution system planning, marketing, and gas
supply planning and procurement; and (iii) engineering and surveying services to
subsidiaries. The SEC's jurisdiction over our holding company activities was
eliminated under PUHCA 2005, although the SEC continues to have jurisdiction
over the registration and issuance of our securities under the securities law.
These service companies are now subject to the jurisdiction of the FERC under
PUHCA 2005, as well as subject to regulations and orders of the NYPSC, MADTE and
NHPUC. See "Regulation and Rate Matters" for additional information on the
Energy Act.
The operating income variation as reflected in "elimination and other" is due
primarily to costs residing at KeySpan's holding company level such as corporate
advertising and strategic review costs. 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.
Operating income variations in "eliminations and other" between 2004 and 2003
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, as noted, in 2004 KeySpan recorded an $11.6 million gain
from the settlement with its insurance carriers regarding cost recovery for
expenses incurred at a non-utility environmental site. It should be noted that
in 2003 KeySpan recorded a $10 million favorable adjustment 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 decreased $346.8 million, or 46%, for the twelve
months ended December 31, 2005 compared to 2004, reflecting, in part, the
absence of Houston Exploration and KeySpan Canada which combined contributed
approximately $230 million to consolidated operating cash flow in 2004. It
should be noted that in prior years, Houston Exploration funded its gas
exploration and development activities, in part, from available cash flow from
operations. In addition, due to the significant increase in natural gas prices
in 2005, KeySpan's gas distribution utilities paid approximately $215 million
more in 2005 compared to 2004 for the purchase of natural gas that is currently
in inventory. As noted previously, 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. Further in 2005 the Internal Revenue Service
("IRS") published new regulations related to the capitalization of costs of
self-constructed property for income tax purposes. As a result of these
72
regulations, KeySpan incurred approximately $60 million in higher income tax
payments for the twelve months ended December 31, 2005 compared to the same
period in 2004. These adverse impacts to cash flow from operations were
partially offset by lower interest payments and higher core earnings.
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.
At December 31, 2005, we had cash and temporary cash investments of $124.5
million. During the twelve months ended December 31, 2005, we repaid $254.6
million of commercial paper and, at December 31, 2005, $658 million of
commercial paper was outstanding at a weighted-average annualized interest rate
of 4.38%. At December 31, 2005, KeySpan had the ability to issue up to an
additional $842 million of short-term debt under its commercial paper program.
In June 2005, KeySpan closed on a $920 million revolving credit facility for
five years due June 24, 2010, which was syndicated among fifteen banks, and an
amended $580 million revolving credit facility due June 24, 2009. These
facilities replaced an existing $660 million, 3-year facility due June 2006, and
a 5-year $640 million facility due June 2009. The two credit facilities, which
now total $1.5 billion - $920 million for five years through 2010, and $580
million for the amended facility through 2009, will continue to support
KeySpan's commercial paper program for ongoing working capital needs.
The fees for the facilities are based on KeySpan's current credit ratings and
are increased or decreased based on a downgrading or upgrading of our ratings.
The current annual facility fee is 0.07% based on our credit rating of A3 by
Moody's Investor Services and A by Standard & Poor's for each facility. Both
credit facilities allow for KeySpan to borrow using several different types of
loans; specifically, Eurodollar loans, ABR loans, or competitively bid loans.
Eurodollar loans are based on the Eurodollar rate plus a margin that is tied to
our applicable credit ratings. ABR loans are based on the higher 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 utility 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 65% as at the
73
last day of any fiscal quarter. Violation of these covenants 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. At
December 31, 2005, KeySpan's consolidated indebtedness was 50.7% of its
consolidated capitalization and KeySpan was in compliance with all covenants.
Subject to certain conditions set forth in the credit facility, KeySpan has the
right, at any time, to increase the commitments under the $920 million facility
up to an additional $300 million. In addition, KeySpan has the right to request
that the termination date be extended for an additional period of 365 days prior
to each anniversary of the closing date. This extension option, however,
requires the approval of lenders holding more than 50% of the total commitments
to such extension request. Under the agreements, KeySpan has the ability to
replace non-consenting lenders with other pre-approved banks or financial
institutions. Upon effectiveness of PUHCA 2005, KeySpan's ability to issue
commercial paper is no longer limited by the SEC. Accordingly, subject to
compliance with the foregoing conditions, KeySpan is currently able to issue up
to $1.5 billion of commercial paper.
A substantial portion of consolidated revenues are derived from the operations
of businesses within the Electric Services segment, that are largely dependent
upon two large customers - LIPA and the NYISO. Accordingly, our cash flows are
dependent upon the timely payment of amounts owed to us by these counterparties.
(See the discussion under the caption "Electric Services - LIPA Agreements" for
information regarding the recent settlement between KeySpan and LIPA regarding
the current contractual agreements.)
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 Millions of Dollars) 2005 2004
- --------------------------------------------------------------------------
Gas Distribution $ 410.3 $ 414.5
Electric Services 88.8 150.3
Energy Investments 23.6 160.2
Energy Services and other 16.8 25.3
- --------------------------------------------------------------------------
$ 539.5 $ 750.3
- --------------------------------------------------------------------------
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 costs to
maintain our generating facilities and, for 2004, expand the Ravenswood
74
Generating Station. Construction expenditures related to the Energy Investments
segment for 2004 primarily reflect costs associated with gas exploration and
production activities of Houston Exploration, as well as costs related to
KeySpan Canada's gas processing facilities.
Construction expenditures for 2006 are estimated to be approximately $630
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 January 2006, the NYPSC issued orders granting additional financing authority
to KEDNY and KEDLI. KEDNY has the authority, through December 31, 2008, to issue
up to $475 million of new securities and to refinance up to $650 million of its
existing debt obligations. KEDLI has the authority, through December 31, 2008,
to issue up to $450 million of new securities and to refinance up to $525
million of its existing debt obligations. KEDNY and KEDLI had sought a waiver
from the requirement in the existing rate plans that KEDNY and KEDLI must raise
their own long-term debt or preferred stock and may not derive such securities
from KeySpan. The NYPSC declined to grant the requested waiver.
In December 2005, KEDNY converted $50 million of fixed rate Gas Facility Revenue
Bonds ("GFRB") (5.64% GFRB Series D1 and D2 due 2026) into variable rate debt.
The interest rate on these bonds is now reset, through an auction process, every
seven days.
In November 2005, KEDNY, issued $137 million of tax-exempt GFRB through the New
York State Energy Research and Development Authority ("NYSERDA") in the
following series: (i) $82 million of 4.70% GFRB, 2005 Series A (the "Series A
Bonds"); and (ii) $55 million GFRB, 2005 Series B (the "Series B Bonds"). The
interest rate on the Series B bonds is reset every seven days through an auction
process. KEDNY used the proceeds from this issuance to redeem the following
three series: (i) $41 million Adjustable Rate GFRB Series 1989 A due February
2024; (ii) $41 million Adjustable Rate GFRB Series 1989 B due February 2024; and
(iii) $55 million 5.60% GFRB Series 1993 C due June 2025. KEDNY incurred $3.7
million in call premiums and financing fees, all of which have been deferred for
future rate recovery.
In January 2005, KeySpan redeemed $500 million of outstanding debt - 6.15% notes
due 2006. KeySpan incurred $20.9 million in call premiums and wrote-off $1.3
million of previously deferred costs. Further, we accelerated the amortization
of approximately $11.2 million of previously unamortized benefits associated
with an interest rate swap on these bonds. The accelerated amortization, as well
as the write-off of previously deferred costs was recorded to interest expense.
In addition, during the first quarter of 2005, $15 million of 8.87% notes of a
KeySpan subsidiary were redeemed at maturity.
Further, $55.3 million of 7.07% Series B preferred stock was redeemed in May
2005 on its scheduled redemption date. Additionally, also in May 2005, KeySpan
called for optional redemption $19.7 million of 7.17% Series C of preferred
stock due 2008. KeySpan no longer has preferred stock outstanding.
In May 2002, KeySpan issued 9.2 million MEDS Equity Units which were subject to
conversion to common stock upon execution of the three-year forward purchase
contract. In 2005, KeySpan was required to remarket the note component of the
Equity Units between February 2005 and May 2005 and reset the interest
75
rate to the then current market rate of interest; however, the reset interest
rate could not be set below 4.9%. In March 2005, KeySpan remarketed the note
component of $394.9 million of the Equity Units at the reset interest rate of
4.9% through their maturity date of May 2008. The balance of the notes ($65.1
million) were held by the original MEDS Equity Unit holders in accordance with
their terms and not remarketed. KeySpan then exchanged $300 million of the
remarketed notes for $307.2 million of new 30 year notes bearing an interest
rate of 5.8%. Therefore, KeySpan now has $160 million of 4.9% notes outstanding
with a maturity date of May 2008 and $307.2 million of 5.8% notes outstanding
with a maturity date of April 2035.
On May 16, 2005, KeySpan issued 12.1 million shares of common stock, at an
issuance price of $37.93 per share pursuant to the terms of the forward purchase
contract. KeySpan received proceeds of approximately $460 million from the
equity issuance. The number of shares issued was dependent 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.
The following table represents the ratings of our long-term debt at December 31,
2005. 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. Further in the second quarter of 2005, Fitch Ratings revised its
ratings on KeySpan's and its subsidiaries' long-term debt to positive 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
- --------------------------------------------------------------------------------
Off-Balance Sheet Arrangements
Guarantees
KeySpan had a number of financial guarantees with its subsidiaries at December
31, 2005. KeySpan has 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 $385 million sale/leaseback
transaction for the Ravenswood Expansion including future decommission costs of
$19 million; 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 obligation is not recorded on the Consolidated
Balance Sheet. Further, KeySpan has guaranteed: (i) up to $76.0 million of
surety bonds associated with certain construction projects currently being
76
performed by current and former subsidiaries; (ii) certain supply contracts,
margin accounts and purchase orders for certain subsidiaries in an aggregate
amount of $83.2 million; and (iii) $73.0 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 for these projects. 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 10 "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 and Commercial Paper." 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."
The table below reflects maturity schedules for KeySpan's contractual
obligations at December 31, 2005. 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 Millions of Dollars)
Contractual Obligations Total 1 - 3 Years 4 - 5 Years After 5 Years
- ----------------------------------------------------------------------------------------------------
Long-term Debt $ 3,934.7 $ 317.0 $ 1,522.3 $ 2,095.4
Capital Leases 10.8 3.2 2.5 5.1
Operating Leases 585.7 213.6 137.5 234.6
Master Lease Payments 99.7 85.5 14.2 -
Sale/Leaseback Arrangement 569.5 73.0 78.8 417.7
Interest Payments 2,873.6 663.7 380.0 1,829.9
Demand Charges 492.7 492.7 - -
- ----------------------------------------------------------------------------------------------------
Total Contractual
Cash Obligations $ 8,566.7 $ 1,848.7 $ 2,135.3 $ 4,582.7
- ----------------------------------------------------------------------------------------------------
Commercial Paper $ 657.6 Revolving
- ----------------------------------------------------------------------------------------------------
For information regarding projected postretirement contributions, see Note 4 to
the Consolidated Financial Statements "Postretirement Benefits." For information
regarding asset retirement obligations, see Note 7 to the Consolidated Financial
Statements "Contractual Obligations, Financial Guarantees and Contingencies."
77
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.
KeySpan continually evaluates its critical accounting policies. Based upon
current facts and circumstances KeySpan has decided that certain accounting
policies that were considered "critical" at December 31, 2004 should no longer
be considered as critical accounting policies. The accounting policies that are
no longer considered critical are as follows: (i) Percentage-of-completion
accounting is a method of accounting for long-term construction type contracts
in accordance with generally accepted accounting principles. This accounting
policy was used for engineering and mechanical contracting revenue recognition
by the Energy Services segment. However, since KeySpan has sold its mechanical
contracting subsidiaries, contracting revenue recognition is no longer a
significant accounting issue; and (ii) The full cost accounting method is used
by our gas exploration and production subsidiaries to account for their natural
gas and oil properties. Seneca-Upshur and KeySpan Exploration continue to apply
this accounting treatment. However, since KeySpan has sold its ownership
interest in Houston Exploration, KeySpan's gas exploration and production
activities are not a significant aspect of its overall business operations and
therefore, full cost accounting is no longer a significant accounting policy.
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. The assumptions used to
measure the fair value of our investments are the same as those used by us to
prepare annual operating segment and consolidated earnings and cash flow
forecasts. In addition, these assumptions are used to set annual budgetary
guidelines.
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. At December 31, 2005, KeySpan had $1.7 billion of recorded goodwill
and has concluded that the fair value of the business units that have recorded
goodwill exceed their carrying value.
78
As noted previously, 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.
(See Note 10 to the Consolidated Financial Statements "Energy
Services-Discontinued Operations" for further details.)
Also as noted previously, at the end of 2004, KeySpan anticipated selling its
then 50% interest in Premier. This investment was 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 reflected the
difference between the anticipated cash proceeds from the sale of Premier
compared to its carrying value at that time 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 and
EnergyNorth) 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 orders issued by the MADTE relating to the acquisition by Eastern
Enterprises of Colonial Gas and Essex Gas, the base rates charged by these
companies have been frozen at their current levels for a ten-year period ending
2009. Due to the length of these base rate freezes, Colonial Gas and Essex Gas
had previously discontinued the application of SFAS 71. EnergyNorth base rates
continue as set by the NHPUC in 1993.
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, 2005 could result in a charge to net income of approximately
79
$308.0 million or $1.81 per share, which would be classified as an extraordinary
item. In management's opinion, our regulated subsidiaries that currently are
subject to the provisions of SFAS 71 will continue to be subject to SFAS 71 for
the foreseeable future.
As is further discussed under the caption "Regulation and Rate Matters," in
October 2003 the MADTE rendered its decision on the Boston Gas 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 and the
rates established in those plans remain in effect. 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.
Management believes that currently available facts support the continued
application of SFAS 71 and that all regulatory assets and liabilities are
recoverable or refundable in the current 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 2005, 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%.
80
KeySpan's master trust investment allocation policy target is 70% equity and 30%
fixed income. At December 31, 2005, 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 2005 expense by approximately $6 million, before
deferrals.
The year-end December 31, 2005 weighted average discount rate used to determine
postretirement obligations was 5.75%. Our discount rate assumption was developed
by matching our plans' cash flows to the Citigroup above-median discount curve
spot rates. The resulting yield is then rounded to the nearest 25 basis points.
A 25 basis point increase or decrease in the weighted average year-end discount
rate would have had no impact on 2005 expense. However, a 25 basis point
decrease in the weighted average year-end discount rate would result in the
recording of an additional minimum pension liability. A year-end discount rate
of 5.5% would have required an additional $42 million debit to other
comprehensive income ("OCI") before taxes and deferrals. A year-end discount
rate of 5.25% would have required an additional $338 million charge to OCI
before taxes and deferrals.
At January 1, 2005, the weighted average discount rate used to determine pension
and postretirement obligations was 6.0%. A 25 basis point increase or decrease
in the weighted average discount rate at the beginning of the year would have
impacted 2005 expense by approximately $15 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, 2005, 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 2005. However, although we have presently exceeded
ERISA funding requirements, our pension plans, on an actuarial basis, are
currently underfunded. Therefore, during 2005 KeySpan contributed $174 million
to its funded and unfunded postretirement plans.
For 2006, 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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Dividends
In the fourth quarter of 2005 KeySpan increased its dividend to an annual rate
of $1.86 per common share beginning with the quarterly dividend to be paid in
February 2006. Our dividend framework 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 $1.86 level.
Pursuant to NYPSC orders, the ability of KEDNY and KEDLI to pay dividends to
KeySpan is conditioned upon maintenance of a utility capital structure with debt
not exceeding 55% and 58%, respectively, of total utility capitalization. In
addition, the level of dividends paid by both utilities may not be increased
from current levels if a 40 basis point penalty is incurred under the customer
service performance program. At the end of KEDNY's and KEDLI's most recent rate
years (September 30, 2005 and November 30, 2005, respectively), each company was
in compliance with the utility capital structure required by the NYPSC.
Additionally, we have met the requisite customer service performance standards.
Regulation and Rate Matters
Gas Distribution
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 a 13.25% return on
equity), remain in effect until changed by the NYPSC. Under the agreement, 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 a 13.25% return on equity (other than any earnings associated with
discrete incentives) and 50% of any utility earnings in excess of 100 basis
points above such threshold level. KEDNY did not earn above a 13.25% return on
equity in its rate year ended September 30, 2005.
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. Under the agreement, KEDLI is subject to an earnings sharing
provision pursuant to which it is required to credit to firm customers 60% of
any utility earnings for any rate year ended November 30, 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 an11.10% return on equity
in its rate year ended November 30, 2005.
At this time, we are evaluating various options regarding the KEDNY and KEDLI
rate plans, including but not limited to, proposing new rate plans. In the
meantime, KeySpan filed a joint petition for KEDNY and KEDLI with the NYPSC
seeking authority to defer certain costs associated with high gas costs.
Specifically, KeySpan seeks authority to defer the following costs, each of
which is directly linked to increased gas prices: (i) the portion of increased
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bad debt expense attributable to increased gas cost; (ii) the return requirement
on the increased cost of gas in storage; and (iii) the return requirement on the
increased need for working capital. KeySpan projects total combined deferrals of
approximately $67 million and $65 million in 2006 and 2007, respectively. On
January 25, 2006, the NYPSC noticed the joint petition in the New York State
Register.
Boston Gas, Colonial Gas and Essex Gas 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.
Effective November 1, 2003, the MADTE approved a $25.9 million increase in base
revenues for Boston Gas 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 November 1, 2005, the MADTE approved a base rate
increase of $7.2 million under the Plan. In addition, an increase of $7.5
million in the local distribution adjustment clause was approved to recover
pension and other postretirement costs. The MADTE 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's weighted-average cost
of capital.
In connection with the Eastern Enterprises acquisition of Colonial Gas in 1999,
the MADTE approved a merger and rate plan that resulted in a ten year freeze of
base rates to Colonial Gas'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 discontinued its application of SFAS 71.
Essex Gas is also under a ten-year base rate freeze and has also discontinued
its application of SFAS 71.
In December 2005, Boston Gas received a MADTE order permitting regulatory
recovery of the 2004 gas cost component of bad debt write-offs. This was
approved for full recovery as an exogenous cost effective November 1, 2005. In
addition, effective January 1, 2006, Boston Gas is permitted to fully recover
the gas cost component of bad debt write-offs through its cost-of-gas adjustment
clause rather than filing for recovery as an exogenous cost. We have reflected
both of these favorable recovery mechanisms in our December 31, 2005 Allowance
for Doubtful Accounts reserve requirement and related expense. Boston Gas also
plans to request full recovery, as an exogenous cost, the 2005 gas cost
component of bad debt write-offs from Boston Gas ratepayers beginning November
1, 2006.
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
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under rates approved by the FERC in accordance with the PSA entered into between
KeySpan and LIPA in 1998. The original 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 to reset rates effective
January 1, 2004. Under the new 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. (See Electric Services - "LIPA Agreements"
for a discussion of the 2006 settlement between KeySpan and LIPA regarding the
current contractual agreements.)
The Energy Policy Act of 2005 and the Public Utility Holding Company Acts of
1935 and 2005
At December 31, 2005, KeySpan and certain of its subsidiaries were subject to
the jurisdiction of the SEC under PUHCA 1935. The rules and regulations under
PUHCA 1935, generally limited the operations of a holding company to a single
integrated public utility system, plus additional energy-related businesses. In
addition, the principal regulatory provisions of PUHCA 1935: (i) regulated
certain transactions among affiliates within a holding company system, including
the payment of dividends by such subsidiaries to a holding company; (ii)
governed the issuance, acquisition and disposition of securities and assets by a
holding company and its subsidiaries; (iii) limited the entry by registered
holding companies and their subsidiaries into businesses other than electric
and/or gas utility businesses; and (iv) required SEC approval for certain
utility mergers and acquisitions.
In August 2005, the Energy Act was enacted by Congress and signed into law by
the President. The Energy Act is a broad based energy bill that places an
increased emphasis on the production of energy and promotes the development of
new technologies and alternative energy sources by providing tax credits to
companies that produce natural gas, oil, coal, electricity and renewable energy.
For KeySpan, one of the more significant provisions of the Energy Act was the
repeal of PUHCA 1935, effective February 8, 2006, and the transfer of certain
holding company oversight from the SEC to FERC pursuant to PUHCA 2005.
Pursuant to PUHCA 2005, the SEC no longer has jurisdiction over our holding
company activities, other than those traditionally associated with the
registration and issuance of our securities under the federal securities laws.
FERC now has jurisdiction over certain of our holding company activities,
including (i) regulating certain transactions among our affiliates within our
holding company system; (ii) governing the issuance, acquisition and disposition
of securities and assets by certain of our public utility subsidiaries; and
(iii) approving certain utility mergers and acquisitions.
Moreover, our affiliate transactions also remain subject to certain regulations
of the NYPSC, MADTE and NHPUC, in addition to FERC.
Electric Services - 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, KeySpan and LIPA entered into three
major long-term service agreements that (i) provide to LIPA all operation,
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maintenance and construction services and significant administrative services
relating to the Long Island electric transmission and distribution ("T&D")
system pursuant to the Management Services Agreement (the "1998 MSA"); (ii)
supply LIPA with electric generating capacity, energy conversion and ancillary
services from our Long Island generating units pursuant to the Power Supply
Agreement (the "1998 PSA") and other long-term agreements through which we
provide LIPA with approximately one half 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 the Energy Management Agreement (the "1998 EMA").
We also purchase energy, capacity and ancillary services in the open market on
LIPA's behalf under the 1998 EMA. The 1998 MSA, 1998 PSA and 1998 EMA all became
effective on May 28, 1998 and are collectively referred to as the 1998 LIPA
Agreements.
On February 1, 2006, KeySpan and LIPA entered into (i) an amended and restated
Management Services Agreement (the "2006 MSA"), pursuant to which KeySpan will
continue to operate and maintain the electric T&D System owned by LIPA on Long
Island; (ii) a new Option and Purchase and Sale Agreement (the "2006 Option
Agreement"), to replace the Generation Purchase Rights Agreement (as amended,
the "GPRA"), pursuant to which LIPA had the option, through December 15, 2005,
to acquire substantially all of the electric generating facilities owned by
KeySpan on Long Island; and (iii) a Settlement Agreement (the "2006 Settlement
Agreement") resolving outstanding issues between the parties regarding the LIPA
Agreements. The 2006 MSA, the 2006 Option Agreement and the 2006 Settlement
Agreement are collectively referred to herein as the "2006 LIPA Agreements".
Each of the 2006 Agreements will become effective as of January 1, 2006 upon all
of the 2006 LIPA Agreements receiving the required governmental approvals;
otherwise none of the 2006 LIPA Agreements will become effective.
2006 Settlement Agreement
Pursuant to the terms of the 2006 Settlement Agreement, KeySpan and LIPA agreed
to resolve issues that have existed between the parties relating to the various
1998 LIPA Agreements. In addition to the resolution of these matters, KeySpan's
entitlement to utilize LILCO's available tax credits and other tax attributes
will increase from approximately $50 million to approximately $200 million.
These credits and attributes may be used to satisfy KeySpan's previously
incurred indemnity obligation to LIPA for any federal income tax liability that
may result from the settlement of a pending Internal Revenue Service audit for
LILCO's tax year ended March 31, 1999. In recognition of these items, as well as
for the modification and extension of the 1998 MSA and the elimination of the
GPRA, upon effectiveness of the Settlement Agreement KeySpan will record a
contractual asset in the amount of approximately $160 million, of which
approximately $110 million will be attributed to the right to utilize such
additional credits and attributes and approximately $50 million will be
amortized over the eight year term of the 2006 MSA. In order to compensate LIPA
for the foregoing, KeySpan will pay LIPA $69 million in cash and will settle
certain accounts receivable in the amount of approximately $90 million due from
LIPA.
Generation Purchase Rights Agreement and 2006 Option Agreement.
Under an amended GPRA, LIPA had the right to acquire certain of KeySpan's Long
Island-based generating assets formerly owned by LILCO, at fair market value at
the time of the exercise of such right. LIPA was initially required to make a
determination by May 2005, but KeySpan and LIPA agreed to extend the date by
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which LIPA was to make this determination to December 15, 2005. As part of the
2006 settlement between KeySpan and LIPA, the parties entered into the 2006
Option Agreement whereby LIPA has the option during the period January 1, 2006
to December 31, 2006 to purchase only KeySpan's Far Rockaway and/or E.F. Barrett
Generating Stations (and certain related assets) at a price equal to the net
book value of each facility. The 2006 Option Agreement replaces the GPRA, the
expiration of which has been stayed pending effectiveness of the 2006 LIPA
Agreements. In the event such agreements do not become effective by reason of
failure to secure the requisite governmental approvals, the GPRA will be
reinstated for a period of 90 days. If LIPA were to exercise the option and
purchase one or both of the generation facilities (i) LIPA and KeySpan will
enter into an operation and maintenance agreement, pursuant to which KeySpan
will continue to operate these facilities, through May 28, 2013, for a fixed
management fee plus reimbursement for certain costs; and (ii) the 1998 PSA and
1998 EMA will be amended to reflect that the purchased generating facilities
would no longer be covered by those agreements. It is anticipated that the fees
received pursuant to the operation and maintenance agreement will offset the
reduction in the operation and maintenance expense recovery component of the
1998 PSA and the reduction in fees under the 1998 EMA.
Management Services Agreements
Pursuant to the 1998 MSA, KeySpan manages the day-to-day operations, maintenance
and capital improvements of the T&D system. LIPA exercises control over the
performance of the T&D system through specific standards for performance and
incentives. In exchange for providing the services, the 1998 MSA provides for a
$10 million annual management fee and provides certain incentives and imposes
certain penalties based upon performance. We earn certain incentives for budget
under runs 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 under runs, and (ii) retain 50% of
additional annual under runs up to 15% of the total cost budget, thereafter all
savings accrue to LIPA. With respect to cost overruns, we 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. During 2005, we
performed our obligations under the 1998 MSA within the agreed upon budget and
we earned $7.4 million in non-cost performance incentives.
When originally executed the 1998 MSA had a term expiring on May 28, 2006. In
2002, in connection with an extension of the GPRA term, the 1998 MSA was
extended for 31 months through 2008. As a result of the recent negotiations and
settlement between KeySpan and LIPA discussed above, the parties entered into
the 2006 MSA.
In place of the previous compensation structure (whereby KeySpan was reimbursed
for budgeted costs, and earned a management fee and certain performance and
cost-based incentives), KeySpan's compensation for managing the T&D System under
the 2006 MSA consists of two components: a minimum compensation component of
$224 million per year and a variable component based on electric sales. The $224
million component will remain unchanged for three years and then increase
annually by 1.7%, plus inflation. The variable component, which will comprise no
more than 20% of KeySpan's compensation, is based on electric sales on Long
Island exceeding a base amount of 16,558 gigawatt hours, increasing by 1.7% in
each year. Above that level, KeySpan will receive approximately 1.34 cents per
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kilowatt hour for the first contract year, 1.29 cents per kilowatt hour in the
second contract year (plus an annual inflation adjustment), 1.24 cents per
kilowatt hour in the third contract year (plus an annual inflation adjustment),
with the per kilowatt hour rate thereafter adjusted annually by inflation.
Subject to certain limitations, KeySpan will be able to retain all operational
efficiencies realized during the term of the 2006 MSA.
LIPA will continue to reimburse KeySpan for certain expenditures incurred in
connection with the operation and maintenance of the T&D System, and other
payments made on behalf of LIPA, including: real property and other T&D System
taxes, return postage, capital construction expenditures and storm costs.
The 2006 MSA provides for a number of performance metrics measuring various
aspects of KeySpan's performance in the operations and customer service areas.
Poor performance in any metric may subject KeySpan to financial and other
non-cost penalties (such financial penalties not to exceed $7 million in the
aggregate for all performance metrics in any contract year). Subject to certain
limitations, superior performance in certain metrics can be used to offset
underperformance in other metrics. Consistent failure to meet threshold
performance levels for two metrics, System Average Interruption Duration Index
(two out of three consecutive years) and Customer Satisfaction Index (three
consecutive years), will constitute an event of default under the 2006 MSA.
Should LIPA sell the T&D System to a private entity during the term of the 2006
MSA, LIPA shall have the right to terminate the 2006 MSA, provided that LIPA
will be required to pay KeySpan's reasonable transition costs and a termination
fee of (a) $28 million if the termination date occurs on or before December 31,
2009, and (b) $20 million if the termination date occurs after December 31,
2009.
Power Supply Agreements
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. Since October 1, 2004, pursuant to a FERC
approved settlement, the 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 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 1998
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 2005, we earned $4 million in incentives under this agreement.
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The 1998 PSA has a term of fifteen years through May 2013, with LIPA having the
option to renew the 1998 PSA for an additional fifteen year term. The 1998 PSA
will be terminated in the event that the GPRA is renewed and LIPA purchases at
fair market value certain of KeySpan's Long Island based generating units. If
the 2006 LIPA Agreements receive the requisite governmental approvals and become
effective, and if LIPA exercises its rights under the 2006 Option Agreement to
purchase the two generating plants, then LIPA and KeySpan will enter into an
operation and maintenance agreement, pursuant to which KeySpan will continue to
operate these facilities for a fixed management fee plus reimbursement for
certain costs; and the 1998 PSA will be amended to reflect that the purchased
generating facilities would no longer be covered by the 1998 PSA. It is
anticipated that the fees received pursuant to the operation and maintenance
agreement will offset the reduction in the operation and maintenance expense
recovery component of the 1998 PSA.
Energy Management Agreement
The 1998 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 1998 EMA provides incentives and
penalties that can total $5 million annually for performance related to fuel
purchases and off-system power purchases. In 2005, we earned EMA incentives in
an aggregate of $5 million.
The original term for the fuel supply service is fifteen years, expiring May 28,
2013, and the original term for the off-system purchases and sales services
described is eight years, expiring May 28, 2006. In March 2005, LIPA issued a
RFP for system power supply management services beginning May 29, 2006 and fuel
management services for certain of its peaking generating units beginning
January 1, 2006. KeySpan submitted a bid in response to this RFP in April 2005.
LIPA has not yet selected a service provider.
In the event LIPA exercises its rights under the 2006 Option Agreement, KeySpan
and LIPA will enter into an amendment to the 1998 EMA reflecting that the
facilities that LIPA acquires pursuant to the Option Agreement are no longer
covered under the 1998 EMA and as noted above, an operation and maintenance
agreement, whereby KeySpan will continue to operate the newly acquired
facilities for a fixed management fee plus reimbursement for certain costs. It
is anticipated that the fees received pursuant to the operation and maintenance
agreement will offset the reduction in any fees earned by KeySpan pursuant to
the 1998 EMA.
Under the 1998 LIPA Agreements and the 2006 LIPA 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.
Power Purchase Agreements
KeySpan-Glenwood Energy Center, LLC and KeySpan-Port Jefferson Energy Center LLC
each have 25 year power purchase agreements with LIPA expring in 2027 (the "2002
LIPA PPAs"). Under the terms of the 2002 LIPA PPAs, these subsidiaries sell
capacity, energy conversion services and ancillary services to LIPA. Each plant
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is designed to produce 79.9 MW. Pursuant to the 2002 LIPA 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.
Ravenswood Generating Station
We currently sell capacity, energy and ancillary services associated with the
Ravenswood Generating Station 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 Generating Station to load
serving entities, i.e. entities that sell to end-users or to brokers and
marketers.
Other Contingencies
LIPA completed its strategic review initiative that it had undertaken in
connection with among other reasons, its option under the GPRA. As part of its
review, LIPA engaged a team of advisors and consultants, held public hearings
and explored its strategic options, including continuing its existing
operations, municipalizing, privatizing, selling some, but not all of its
assets, becoming a regulator of rates and services, or merging with one or more
utilities. Upon completion of its strategic review, LIPA determined that it
would continue its existing operations, as part of its settlement with KeySpan
and the negotiation of the 2006 LIPA Agreements. As previously noted, the 2006
LIPA Agreements are subject to governmental approvals, and if such governmental
approvals are not received and the 2006 LIPA Agreements do not become effective,
then LIPA may revisit its strategic review alternatives.
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, MADTE 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.
During 2005, KeySpan undertook an extensive review of all its current and former
properties that are or may be subject to environmental cleanup activities. As a
result of this study, we adjusted reserve balances for estimated manufactured
gas plant ("MGP") related environmental cleanup activities. As noted above,
through various rate orders issued by the NYPSC, MADTE and NHPUC, costs related
to MGP environmental cleanup activities are recovered in rates charged to gas
distribution customers and, as a result, these adjustments to these reserve
balances did not impact earnings.
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We estimate that the remaining cost of our MGP related environmental cleanup
activities, including costs associated with the Ravenswood Generating Station,
will be approximately $404.0 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, 2005, we have expended a total of
$174.0 million on environmental investigation and remediation activities. (See
Note 7 to the Consolidated Financial Statements, "Contractual Obligations,
Guarantees and Contingencies" for a further explanation of these matters.)
Market and Credit Risk Management Activities
Market Risk: KeySpan is exposed to market risk arising from potential changes in
one or more market variables, such as energy commodity 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
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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.
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
New York and Long Island
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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 companion policy statements regarding its vision for the
future of competitive markets and guidelines for separately stating the cost of
competitive services currently performed by New York utilities. The NYPSC's
vision for the future of competitive markets, as stated in the first policy
statement, remains unchanged. Items of importance 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.
The NYPSC's second policy statement of August 2004 addresses the means by which
New York utilities should state separately, or "unbundle," the costs of
competitive and potentially competitive services currently performed by
utilities from the cost of providing local distribution service. The objective
of unbundling is to facilitate competition by providing customers with
information as to savings available from purchasing competitive services from
third-party providers, and to credit the customer's utility bill for the cost of
unbundled services when they migrate to purchase them from competitive
91
suppliers. In its unbundling policy statement, the NYPSC directed utilities to
file with their next base rate proceedings updated cost studies for unbundled
competitive services that, once approved by the NYPSC, would replace existing
backout credits for these services established in prior utility proceedings. The
NYPSC also asked utilities to file with the unbundled cost studies a lost
revenue recovery mechanism that would permit the utility to recover revenue
associated with the difference between the cost the utility is able to avoid
when a customer migrates to a competitive service provider and the unbundled
rate for that service credited to the customer's bill.
KEDNY's and KEDLI's current backout credits for the billing function are both
$.78 per account per month, and were established in May 2001 by the NYPSC's
Order Establishing Retail Access Billing and Payment Processing Practices.
Pursuant to that Order, customers that purchase commodity service from
third-party providers and receive a consolidated bill from the utility receive a
$.78 billing credit on their utility bills. KEDNY/KEDLI then invoices the
third-party commodity provider for the billing service at the same $.78 per
account per month that is credited to the customer's utility bill. As for the
commodity merchant function, KEDNY's and KEDLI's existing backout credits are
$.21/Dth and $.19/Dth, respectively, as established in May 2002 by the NYPSC's
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 also
established Transition Balancing Accounts ("TBA") for KEDNY and KEDLI that are
funded by property tax refunds and other sums due to firm gas sales customers.
The TBAs are currently the mechanisms for KEDNY and KEDLI to recover revenue
lost to the merchant function backout credit. While the Joint Proposal expired
in November 2003, the KEDNY and KEDLI tariffs provide that the merchant function
backout credits and the TBAs will remain in effect until November 2006. As part
of a retail choice program, KEDNY and KEDLI will propose a program to facilitate
competition in their service territories, cost-based unbundled rates for
competitive services, and a lost revenue recovery mechanism that prevents them
from being harmed by the migration of customers to competitive services.
On December 5, 2005, a petition was filed with the NYPSC requesting authority to
defer costs associated with high gas prices that are not reflected in existing
gas sales rates, including commodity-related uncollectible expense, gas working
capital and gas in storage. The NYPSC commenced the required 45-day notice of
this petition in the New York State Register on January 25, 2006.
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
92
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.
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. On June 6,
2005, the MADTE issued an order in its continuing investigation into gas
unbundling and found that mandatory capacity assignment should be continued,
including continuation of slice of system versus path method of assignment,
essentially maintaining the status-quo.
Beginning on November 1, 2001, the NHPUC began requiring gas utilities to offer
transportation services to all commercial and residential customers. Since such
time EnergyNorth has provided such transportation in accordance with the NHPUC
order.
Electric Industry
10-Minute Spinning and Non-Spinning Reserves
- --------------------------------------------
Due to the 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 such reserves, as well as requiring a refunding of so
called alleged "excess payments" received by sellers, including the Ravenswood
Facility. 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 NYISO's other requests, such as
a bid cap for spinning reserves, retroactive refunds, recalculation of reserve
prices, etc., were rejected.
The NYISO, The Consolidated Edison Company of New York ("Con Edison"), Niagara
Mohawk Power Corporation and Rochester Gas and Electric each individually
appealed FERC's order in federal court. The appeals were consolidated into one
case and 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 (the "Decision"). Essentially, the Court found errors in FERC's order
and remanded some issues back to FERC for further explanation and action.
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 March 4, 2005, FERC issued an order upholding its
original decision not to order refunds. FERC also provided the further
explanation requested by the Court as to why refunds were not being ordered. The
93
NYISO and other market participants requested rehearing of FERC's latest order
and on November 17, 2005, FERC denied those requests. The NYISO and various New
York Transmission Owners appealed FERC's November 17, 2005 order to the United
States Court of Appeals for the District of Columbia.
May 2000 Energy Market Clearing Prices
- --------------------------------------
Due to unseasonably warm weather and scheduled maintenance outages in May 2000,
energy prices spiked, and the NYISO revised prices downward after it determined
a market design flaw existed which caused prices to be higher than what would
occur in a competitive market. FERC originally agreed with the NYISO, but
reversed its original decision on remand from the Court of Appeals. On March 4,
2005, FERC issued an order requiring the NYISO to reinstate the original prices
for May 8 and 9, 2000 and to pay suppliers, including the Ravenswood Facility,
accordingly. In 2005, the Ravenswood Generating Station received a $9.2 million
increase in its payments for its May 2000 energy sales. The NYISO and other
market participants requested rehearing of this March 4, 2005 order, and on
November 22, 2005, FERC denied those requests. The NYISO and various New York
Transmission Owners appealed FERC's November 22, 2005 order to the United States
Court of Appeals for the District of Columbia.
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. On May 13, 2005, this appeal
was denied.
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. The NYISO reported that SMD2 is performing as expected, and they continue
to monitor the market improvements.
94
The Ravenswood Generating Station and our New York City Operations
- ------------------------------------------------------------------
Currently, the NYISO's New York City local reliability rules require that 80% of
the electric capacity needs of New York City be provided by "in-City"
generators. On February 6, 2006, the NYISO Board increased the "in-City"
generator requirement to 83% beginning in May 2006 through the period ending on
April 2007, based in part on the statewide reserve margin of 118% set by the New
York State Reliability Council. Our Ravenswood Generating Station is an
"in-City" generator. As the electric infrastructure in New York City and the
surrounding areas continues to change and evolve and the demand for electric
power increases, the "in-City" generator requirement could be further modified.
Construction of new transmission and generation facilities may cause significant
changes to the market for sales of capacity, energy and ancillary services from
our Ravenswood Generating Station. Recently 500 MW of capacity came on line and
it is anticipated that another 500MW of new capacity may be available during
2006 as a result of the completion of an in-City generation project currently
under construction. We can not, however, be certain as to when the new power
plant will be in operation or the nature of future New York City energy,
capacity or ancillary services market requirements or design.
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. Seneca-Upshur utilizes OTC natural gas swaps to hedge
cash flow variability associated with forecasted sales of natural gas. The
Ravenswood Generating Station uses derivative financial instruments to hedge the
cash flow variability associated with the purchase of a portion of natural gas
or fuel oil that will be consumed during the generation of electricity. The
Ravenswood Generating Station also hedges the cash flow variability associated
with a portion of electric energy sales. During 2005, our gas distribution
operations utilized 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. These derivative positions have
all settled as of December 31, 2005.
KeySpan uses standard NYMEX futures prices to value gas futures and market
quoted forward prices to value OTC swap contracts.
95
The following tables set forth selected financial data associated with these
derivative financial instruments that were outstanding at December 31, 2005.
- -----------------------------------------------------------------------------------------------------------------------------
Year of Volumes Fixed Price Current Price Fair Value
Type of Contract Maturity (mmcf) ($) ($) ($Millions)
- -----------------------------------------------------------------------------------------------------------------------------
Gas
OTC Swaps - Short Natural Gas 2006 2,035 6.17 - 6.29 10.67 - 12.04 (8.6)
2007 1,691 5.86 - 5.97 9.81 - 12.49 (8.1)
2008 1,549 6.77 - 6.85 8.91 - 11.52 (4.5)
- -----------------------------------------------------------------------------------------------------------------------------
5,275 (21.2)
- -----------------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------------
Year of Volumes Fixed Price Current Price Fair Value
Type of Contract Maturity (Barrels) ($) ($) ($Millions)
- ---------------------------------------------------------------------------------------------------------------------------
Oil
Swaps - Long Heating Oil 2006 2,056,794 39.65 - 67.75 56.00 - 57.80 (6.3)
- ---------------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------------
2,056,794 (6.3)
- ---------------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------------
Year of Fixed Price Current Price Fair Value
Type of Contract Maturity MWh ($) ($) ($Millions)
- -----------------------------------------------------------------------------------------------------------------------------
Electricity
Swaps - Energy 2006 1,648,000 76.00 - 208.00 107.61 - 153.25 9.4
- ----------------------------------------------------------------------------------------------------------------------------
The following tables detail the changes in and sources of fair value for the
above derivatives:
- -------------------------------------------------------------------------------
(In Millions of Dollars) 2005
Change in Fair Value of Derivative Hedging Instruments ($Millions)
- -------------------------------------------------------------------------------
Fair value of contracts at January 1, 2005 $ (1.4)
Net losses on contracts realized 36.6
Decrease in fair value of all open contracts (53.3)
- -------------------------------------------------------------------------------
Fair value of contracts outstanding at December 31, $ (18.1)
- -------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------
(In Millions 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 $ (9.2) $ (12.6) $ (21.8)
Local published indicies 3.7 - 3.7
- ----------------------------------------------------------------------------------------------
$ (5.5) $ (12.6) $ (18.1)
- ----------------------------------------------------------------------------------------------
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, 2005, a 10% increase/decrease in heating oil and
natural gas prices would decrease/increase the value of derivative instruments
maturing in one year by $2.2 million. Further, a 10% increase/decrease in
electricity and fuel prices would decrease/increase the value of derivative
instruments maturing in one year by $9.7 million.
96
Firm Gas Sales Derivative Instruments - Regulated Utilities: We use derivative
financial instruments to reduce the cash flow variability associated with the
purchase price for a portion of future natural gas purchases associated with our
Gas Distribution operations. The accounting for these derivative instruments is
subject to SFAS 71 "Accounting for the Effects of Certain Types of Regulation."
Therefore, changes in the fair value of these derivatives are recorded as a
regulatory asset or regulatory liability on the Consolidated Balance Sheet.
Gains or losses on the settlement of these contracts are deferred and then
refunded to or collected from our firm gas sales customers consistent with
regulatory requirements.
The following table sets forth selected financial data associated with these
derivative financial instruments that were outstanding at December 31, 2005.
- ------------------------------------------------------------------------------------------------------------------------------------
Year of Volumes Floor Ceiling Fixed Price Current Price Fair Value
Type of Contract Maturity (mmcf) ($) ($) ($) ($) ($Millions)
- ------------------------------------------------------------------------------------------------------------------------------------
Options 2006 7,200 5.50 - 12.00 5.50 - 13.55 - 8.75 - 13.06 15.6
Swaps 2006 52,030 - - 5.34 - 14.16 10.29 - 11.36 115.9
2007 20,480 - - 6.81 - 11.99 9.44 - 11.88 26.1
- ------------------------------------------------------------------------------------------------------------------------------------
79,710 157.6
- ------------------------------------------------------------------------------------------------------------------------------------
See Note 8 to the Consolidated Financial Statements "Hedging, Derivative
Financial Instruments and Fair Values" for a further description of all our
derivative instruments.
97
Item 8. Financial Statements and Supplementary Data
CONSOLIDATED BALANCE SHEET
- ----------------------------------------------------------------------------------------------------------------------
December 31,
(In Millions of Dollars) 2005 2004
- ----------------------------------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash and temporary cash investments $ 124.5 $ 922.0
Restricted cash 13.2 -
Accounts receivable 1,035.6 788.5
Unbilled revenue 685.6 590.8
Allowance for uncollectible accounts (62.8) (67.8)
Gas in storage, at average cost 766.9 515.5
Material and supplies, at average cost 140.5 123.4
Derivative contracts 142.8 0.6
Other 173.8 162.7
Assets of discontinued operations - 42.9
-----------------------------------------------
3,020.1 3,078.6
-----------------------------------------------
Investments and Other 242.4 272.9
-----------------------------------------------
Property
Gas 7,275.9 6,871.2
Electric 2,492.3 2,402.1
Other 416.3 398.6
Accumulated depreciation (2,922.6) (2,702.3)
Gas exploration and production, at cost 184.2 187.1
Accumulated depletion (109.2) (97.5)
Property of discontinued operations - 8.7
-----------------------------------------------
7,336.9 7,067.9
-----------------------------------------------
Deferred Charges
Regulatory assets
Miscellaneous assets 688.3 535.3
Derivative contracts 30.9 20.1
Goodwill and other intangible assets, net of amortization 1,666.3 1,677.6
Derivative contracts 75.2 29.2
Other 752.5 682.5
-----------------------------------------------
3,213.2 2,944.7
-----------------------------------------------
Total Assets $ 13,812.6 $ 13,364.1
===============================================
- ----------------------------------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
98
CONSOLIDATED BALANCE SHEET
- -----------------------------------------------------------------------------------------------------------------------
December 31,
(In Millions of Dollars) 2005 2004
- -----------------------------------------------------------------------------------------------------------------------
LIABILITIES AND CAPITALIZATION
Current Liabilities
Accounts payable and other liabilities $ 1,087.0 $ 906.7
Commercial paper 657.6 912.2
Current maturities of long-term debt & capital leases 13.0 16.1
Current redemption requirement of preferred stock - 55.3
Taxes accrued 176.3 161.6
Dividends payable 81.1 74.1
Customer deposits 39.1 43.3
Interest accrued 53.8 48.8
Other current liability, derivative contracts 47.3 -
Liabilities of discontinued operations - 64.2
----------------------------------------------
2,155.2 2,282.3
----------------------------------------------
Deferred Credits and Other Liabilities
Regulatory liabilities:
Miscellaneous liabilities 69.9 66.5
Removal costs recovered 516.4 496.5
Derivative accounts 175.4 7.4
Asset retirement obligations 47.4 1.9
Deferred income tax 1,157.9 1,124.1
Postretirement benefits and other reserves 1,118.4 900.4
Derivative contracts 44.3 43.9
Other 127.5 94.3
----------------------------------------------
3,257.2 2,735.0
----------------------------------------------
Commitments and Contingencies (See Note 7) - -
Capitalization
Common stock 3,975.9 3,502.0
Retained earnings 866.9 792.2
Accumulated other comprehensive income (74.8) (54.3)
Treasury stock (303.9) (345.1)
----------------------------------------------
Total common shareholders' equity 4,464.1 3,894.8
Preferred stock - 19.7
Long-term debt and capital leases 3,920.8 4,418.7
----------------------------------------------
Total Capitalization 8,384.9 8,333.2
----------------------------------------------
Minority Interest in Consolidated Companies 15.3 13.6
----------------------------------------------
Total Liabilities and Capitalization $ 13,812.6 $ 13,364.1
==============================================
See accompanying Notes to the Consolidated Financial Statements.
99
CONSOLIDATED STATEMENT OF INCOME
- ---------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Millions of Dollars, Except Per Share Amounts) 2005 2004 2003
- ---------------------------------------------------------------------------------------------------------------------------
Revenues
Gas Distribution $ 5,390.1 $ 4,407.3 $ 4,161.3
Electric Services 2,042.7 1,738.7 1,606.0
Energy Services 191.2 182.4 158.9
Houston Exploration - 268.1 495.3
Energy Investments 38.0 54.0 114.0
-----------------------------------------------------------
Total Revenues 7,662.0 6,650.5 6,535.5
-----------------------------------------------------------
Operating Expenses
Purchased gas for resale 3,597.3 2,664.5 2,495.1
Fuel and purchased power 752.1 540.3 414.6
Operations and maintenance 1,617.9 1,567.0 1,622.6
Depreciation, depletion and amortization 396.5 551.8 571.7
Operating taxes 407.1 404.2 418.2
Impairment charges - 41.0 -
-----------------------------------------------------------
Total Operating Expenses 6,770.9 5,768.8 5,522.2
-----------------------------------------------------------
Gain on sale of property 1.6 7.0 15.1
Income from equity investments 15.1 46.5 19.2
-----------------------------------------------------------
Operating Income 907.8 935.3 1,047.6
-----------------------------------------------------------
Other Income and (Deductions)
Interest charges (269.3) (331.3) (307.7)
Sale of subsidiary stock 4.1 388.3 13.3
Cost of debt redemption (20.9) (45.9) (24.1)
Minority interest (0.4) (36.8) (63.9)
Other 16.6 30.6 42.1
-----------------------------------------------------------
Total Other Income and (Deductions) (269.9) 4.9 (340.3)
-----------------------------------------------------------
Income Taxes
Current 206.6 201.9 (99.8)
Deferred 32.7 123.6 381.1
-----------------------------------------------------------
Total Income Taxes 239.3 325.5 281.3
-----------------------------------------------------------
Earnings from Continuing Operations 398.6 614.7 426.0
-----------------------------------------------------------
Discontinued Operations
Income (loss) from operations, net of tax (4.1) (79.0) (1.9)
Gain (Loss) on disposal, net of tax 2.3 (72.0) -
-----------------------------------------------------------
Loss from Discontinued Operations (1.8) (151.0) (1.9)
-----------------------------------------------------------
Cumulative Change in Accounting Principles, net of tax (6.6) - (37.4)
-----------------------------------------------------------
Net Income 390.2 463.7 386.7
Preferred stock dividend requirements 2.2 5.6 5.8
-----------------------------------------------------------
Earnings for Common Stock $ 388.0 $ 458.1 $ 380.9
===========================================================
Basic Earnings Per Share
Continuing Operations, less preferred stock dividends $ 2.33 $ 3.80 $ 2.65
Discontinued Operations (0.01) (0.94) (0.01)
Cumulative Change in Accounting Principles (0.04) - (0.23)
-----------------------------------------------------------
Basic Earnings Per Share $ 2.28 $ 2.86 $ 2.41
===========================================================
Diluted Earnings Per Share
Continuing Operations, less preferred stock dividends $ 2.32 $ 3.78 $ 2.63
Discontinued Operations (0.01) (0.94) (0.01)
Cumulative Change in Accounting Principles (0.04) - (0.23)
-----------------------------------------------------------
Diluted Earnings Per Share $ 2.27 $ 2.84 $ 2.39
===========================================================
Average Common Shares Outstanding (000) 169,940 160,294 158,256
Average Common Shares Outstanding - Diluted (000) 170,801 161,277 159,232
- ---------------------------------------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
100
CONSOLIDATED STATEMENT OF CASH FLOWS
- ------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Millions of Dollars) 2005 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income $ 390.2 $ 463.7 $ 386.7
Adjustments to reconcile net income to net
cash provided by (used in) operating activities
Depreciation, depletion and amortization 396.5 551.8 571.7
Deferred income tax 32.7 123.6 188.7
Income from equity investments (15.1) (46.5) (18.0)
Dividends from equity investments 9.3 14.2 2.8
Amortization of financing fees / interest rate swaps (1.4) (14.9) (9.9)
Gain on sale of investments and property (5.6) (395.3) (28.5)
Hedging (gain)/losses (3.2) 2.5 (1.0)
Amortization of property taxes 126.2 101.9 87.5
Impairment charges - 41.0 -
Loss from discontinued operations 1.8 151.0 1.9
Cumulative change in accounting principle 6.6 - 37.4
Environmental reserve adjustment - - (10.5)
Minority interest 0.4 36.8 63.9
Changes in assets and liabilities
Accounts receivable (305.7) (234.2) 60.4
Materials and supplies, fuel oil and gas in storage (268.4) (39.0) (199.0)
Accounts payable and accrued expenses 196.3 159.5 225.8
Prepaid property taxes (136.2) (112.1) (133.9)
Reserve payments (35.7) (37.3) (36.5)
Insurance settlements 21.1 - -
Other (6.5) (16.6) 33.9
----------------------------------------------------------
Net Cash Provided by Continuing Operating Activities 403.3 750.1 1,223.4
----------------------------------------------------------
Investing Activities
Construction expenditures (539.5) (750.3) (1,009.4)
Cost of removal (27.8) (36.3) (31.1)
Net proceeds from sale of property and investments 47.0 1,021.3 309.7
Derivative margin call (8.9) - -
Other investments - - (211.3)
Issuance of long-term note - - (55.0)
----------------------------------------------------------
Net Cash (Used in) Provided by Continuing Investing Activities (529.2) 234.7 (997.1)
----------------------------------------------------------
Financing Activities
Treasury stock issued 41.2 33.4 96.7
Common stock issuance 460.0 - 473.6
Issuance of long-term debt - 49.3 1,024.5
Payment of long-term debt (515.0) (920.1) (614.3)
Issuance / (payment) of commercial paper (254.6) 430.4 (433.8)
Redemption of preferred stock (75.0) (8.5) (14.3)
Net proceeds from sale/leasback transaction - 382.0 -
Redemption of promissory notes - - (447.0)
Common and preferred stock dividends paid (308.4) (291.1) (280.6)
Gain on interest rate swap - 12.7 -
Other (5.4) 36.1 15.0
----------------------------------------------------------
Net Cash (Used in) Continuing Financing Activities (657.2) (275.8) (180.2)
----------------------------------------------------------
Net Increase in Cash and Cash Equivalents $ (783.1) $ 709.0 $ 46.1
Cash Flow from Discontinued Operations - Operating Activities* (3.8) 8.1 (16.5)
Cash Flow from Discontinued Operations - Investing Activities* (10.6) 1.3 2.3
Cash Flow from Discontinued Operations - Financing Activities* - 0.2 0.9
Cash and Cash Equivalents at Beginning of Period 922.0 203.4 170.6
----------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 124.5 $ 922.0 $ 203.4
==========================================================
Interest Paid $ 262.7 $ 336.5 $ 355.1
Income Tax Paid $ 181.5 $ 122.0 $ 65.5
- ------------------------------------------------------------------------------------------------------------------------------
*Revised - See Note 1
See accompanying Notes to the Consolidated Financial Statements.
101
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
- ------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Millions of Dollars) 2005 2004 2003
- ------------------------------------------------------------------------------------------------------------------
Balance at Beginning of Period $ 792.2 $ 621.4 $ 522.8
Net Income for Period 390.2 463.7 386.7
- ------------------------------------------------------------------------------------------------------------------
1,182.4 1,085.1 909.5
Deductions:
Cash dividends declared on common stock 313.3 287.3 282.3
Cash dividends declared on preferred stock 2.2 5.6 5.8
- ------------------------------------------------------------------------------------------------------------------
Balance at End of Period $ 866.9 $ 792.2 $ 621.4
- ------------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
- -------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Millions of Dollars) 2005 2004 2003
- -------------------------------------------------------------------------------------------------------------------------------
Net Income $ 390.2 $ 463.7 $ 386.7
- -------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income, net of tax
Net losses (gains) on derivative instruments 23.8 (0.3) 23.0
Unrealized (losses) gains on derivative financial instruments (35.1) 15.4 (25.4)
Deconsolidation of certain subsidiaries - 9.3 -
Foreign currency translation adjustments (5.0) (21.5) 28.7
Unrealized gains (losses) on marketable securities (0.5) 7.1 8.5
Premium on derivative instrument - 3.4 (3.4)
Accrued unfunded pension obligation (3.7) (7.8) 8.4
- -------------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax (20.5) 5.6 39.8
- -------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 369.7 $ 469.3 $ 426.5
- -------------------------------------------------------------------------------------------------------------------------------
Related tax (benefit) expense
Net losses (gains) on derivative instruments 12.8 (0.2) 12.4
Unrealized (losses) gains on derivative financial instruments (20.7) 8.2 (13.6)
Deconsolidation of certain subsidiaries - 5.0 -
Foreign currency translation adjustments (2.7) (11.6) 15.4
Unrealized gains (losses) on marketable securities (0.2) 3.8 4.6
Accrued unfunded pension obligation (2.1) (4.2) 4.5
Premium on derivative instrument - 1.9 (1.9)
- -------------------------------------------------------------------------------------------------------------------------------
Total Tax (Benefit) Expense $ (12.9) $ 2.9 $ 21.4
- -------------------------------------------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
102
CONSOLIDATED STATEMENT OF CAPITALIZATION
- -----------------------------------------------------------------------------------------------------------------------------------
December 31, December 31,
(In Millions of Dollars) 2005 2004 2005 2004
- -----------------------------------------------------------------------------------------------------------------------------------
Common Shareholders' Equity Shares Issued
Common stock, $0.01 par value 184,864,124 172,737,654 $ 1.7 $ 1.7
Premium on capital stock 3,974.2 3,500.3
Retained earnings 866.9 792.2
Other comprehensive income (74.8) (54.3)
Treasury stock (10,495,743) (11,919,343) (303.9) (345.1)
- -----------------------------------------------------------------------------------------------------------------------------------
Total Common Shareholders' Equity 174,368,381 160,818,311 4,464.1 3,894.8
- -----------------------------------------------------------------------------------------------------------------------------------
Preferred Stock - Redemption Required
Par Value $100 per share
7.07% Series B -private placement - 553,000 - 55.3
7.17% Series C-private placement - 197,000 - 19.7
Less: current redemption requirements - (553,000) - (55.3)
- -----------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - Redemption Required - 197,000 - 19.7
- -----------------------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------------------
Long - Term Debt Interest Rate Maturity
- -----------------------------------------------------------------------------------------------------------------------------------
Medium and Long Term Notes 4.65% - 9.75% 2006 - 2035 2,437.2 2,485.0
Gas Facilities Revenue Bonds Variable 2020 - 2026 230.0 125.0
4.70% - 6.95% 2020 - 2026 410.5 515.5
- -----------------------------------------------------------------------------------------------------------------------------------
Total Gas Facilities Revenue Bonds 640.5 640.5
- -----------------------------------------------------------------------------------------------------------------------------------
Promissory Notes to LIPA
Pollution Control Revenue Bonds 5.15% 2016 - 2028 108.0 108.0
Electric Facilities Revenue Bonds 5.30% 2023 - 2027 47.4 47.4
- -----------------------------------------------------------------------------------------------------------------------------------
Total Promissory Notes to LIPA 155.4 155.4
- -----------------------------------------------------------------------------------------------------------------------------------
MEDS Equity Units 8.75% 2005 - 460.0
Industrial Development Bonds 5.25% 2027 128.3 128.3
First Mortgage Bonds 6.08% - 8.80% 2008 - 2028 95.0 95.0
Authority Financing Notes Variable 2027 - 2028 66.0 66.0
Ravenswood Master Lease & Capital Leases 2006 - 2022 423.0 424.1
- -----------------------------------------------------------------------------------------------------------------------------------
Subtotal 3,945.4 4,454.3
-
-
Unamortized interest rate hedge and debt discount (30.4) (55.2)
Derivative impact on debt 18.8 35.7
Less: current maturities 13.0 16.1
- -----------------------------------------------------------------------------------------------------------------------------------
Total Long-Term Debt 3,920.8 4,418.7
- -----------------------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 8,384.9 $ 8,333.2
- -----------------------------------------------------------------------------------------------------------------------------------
See accompanying Notes to the Consolidated Financial Statements.
103
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."
On February 25, 2006, Keyspan entered into an Agreement and Plan of Merger (the
"Merger Agreement"), with National Grid PLC, a public limited company
incorporated under the laws of England and Wales ("Parent") and National Grid
USA, Inc, a New York Corporation ("Merger Sub"), pursuant to which Merger Sub
will merge with and into KeySpan (the "Merger"), with KeySpan continuing as the
surviving Company. Pursuant to the Merger Agreement, at the effective time of
the Merger, each outstanding share of common stock, par value $.01 per share of
KeySpan (the "Shares"), other than shares owned by KeySpan, shall be canceled
and shall be converted into the right to receive $42.00 in cash, without
interest.
Consummation of the Merger is subject to various closing conditions, including
but not limited to the satisfaction or waiver of conditions regarding the
receipt of requisite regulatory approvals and the adoption of the Merger
Agreement by the stockholders of KeySpan and the Parent. Assuming receipt or
waiver of the foregoing, it is currently anticipated that the Merger will be
consummated in early 2007. However, no assurance can be given that the Merger
will occur, or, the timing of its completion.
KeySpan's core businesses are engaged in gas distribution, electric services and
generation and other energy related activities. KeySpan's gas distribution
operations are 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 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"). On February 1, 2006, KeySpan and LIPA entered into agreements to
extend, amend and restate these contractual arrangements. See Note 11 "2006 LIPA
Settlement" for a discussion of the settlement.
Our other subsidiaries are involved in gas production; gas storage; liquefied
natural gas storage; retail electric marketing; appliance service; 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.)
104
At December 31, 2005, KeySpan was a holding company under the Public Utility
Holding Company Act of 1935, as amended ("PUCHA 1935"). In August 2005, the
Energy Policy Act of 2005 (the "Energy Act") was enacted. The Energy Act is a
broad energy bill that places an increased emphasis on the production of energy
and promotes the development of new technologies and alternative energy sources
and provides tax credits to companies that produce natural gas, oil, coal,
electricity and renewable energy. For KeySpan, one of the more significant
provisions of the Energy Act is the repeal of PUHCA 1935, which became effective
on February 8, 2006, and the transfer of certain holding company oversight from
the Securities and Exchange Commission ("SEC") to the Federal Energy Regulatory
Commission ("FERC") pursuant to the Public Utility Holding Company Act of 2005
("PUHCA 2005').
Pursuant to PUHCA 2005, the SEC no longer has jurisdiction over our holding
company activities, other than those associated with the registration and
issuance of our securities under the federal securities laws. FERC now has
jurisdiction over certain of our holding company activities, including (i)
regulating certain transactions among our affiliates within our holding company
system; (ii) governing the issuance, acquisition and disposition of securities
and assets by certain of our public utility subsidiaries; and (iii) approving
certain utility mergers and acquisitions.
Moreover, our affiliate transactions also remain subject to certain regulations
of the Public Service Commission of the State of New York ("NYPSC"), the
Massachusetts Department of Telecommunications and Energy ("MADTE") and the New
Hampshire Public Utility Commission ("NHPUC") in addition to FERC.
Under our holding company structure, we have no independent operations or source
of income of our own and conduct all of our operations through our subsidiaries
and, as a result, we depend on the earnings and cash flow of, and dividends or
distributions from, our subsidiaries to provide the funds necessary to meet our
debt and contractual obligations. Furthermore, a substantial portion of our
consolidated assets, earnings and cash flow is derived from the operations of
our regulated utility subsidiaries, whose legal authority to pay dividends or
make other distributions to us is subject to regulation by state regulatory
authorities.
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.
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 all
periods presented, KeySpan revised and has separately disclosed the operating,
investing and financing portions of the cash flows attributable to its
discontinued operations, which in prior periods were reported on a combined
basis as a single amount.
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 NYPSC, the
NHPUC, and the MADTE. Our electric generation subsidiaries are not subject to
105
state rate regulation, but they are subject to 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.
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, 2005 and
December 31, 2004.
- ---------------------------------------------------------------------------------------------
December 31,
(In Millions of Dollars) 2005 2004
- ---------------------------------------------------------------------------------------------
Regulatory Assets
Regulatory tax asset $ 33.4 $ 39.5
Property and other taxes 53.8 58.8
Environmental costs 454.7 272.6
Postretirement benefits 109.3 110.6
Costs associated with the KeySpan/LILCO transaction 27.3 39.1
Derivative financial instruments 30.9 20.1
Other 9.8 14.7
- ---------------------------------------------------------------------------------------------
Total Regulatory Assets $ 719.2 $ 555.4
Regulatory Liabilities (245.3) (73.9)
- ---------------------------------------------------------------------------------------------
Net Regulatory Assets 473.9 481.5
Removal Costs Recovered (516.4) (496.5)
- ---------------------------------------------------------------------------------------------
$ (42.5) $ (15.0)
- ---------------------------------------------------------------------------------------------
The regulatory assets above are not included in utility 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 except for the current market value of our derivative
financial instruments. 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 $11.3 million and $37.7 million at December 31, 2005 and
December 31, 2004, 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 9 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
106
operations may no longer meet the criteria for the application of SFAS 71. In
that event, a write-down of all or a portion of our existing regulatory assets
and liabilities could result. If we were unable to continue to apply the
provisions of SFAS 71 for any of our rate regulated subsidiaries, we would apply
the provisions of SFAS 101, "Regulated Enterprises - Accounting for the
Discontinuation of Application of FASB Statement 71." We estimate that the
write-off of all net regulatory assets at December 31, 2005, before
consideration of removal costs recovered, could result in a charge to net income
of $308.0 million after-tax or $1.81 per share, which would be classified as an
extraordinary item. 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.)
In December 2005, Boston Gas received a MADTE order permitting regulatory
recovery of the 2004 gas cost component of bad debt write-offs. This was
approved for full recovery as an exogenous cost effective November 1, 2005. In
addition, effective January 1, 2006 Boston Gas is permitted to fully recover the
gas cost component of bad debt write-offs through its cost-of-gas adjustment
clause rather than filing for recovery as an exogenous cost. We have reflected
both of these favorable recovery mechanisms in our December 31, 2005 Allowance
for Doubtful Accounts reserve requirement and related expense. Boston Gas also
plans to request full recovery, as an exogenous cost, of the 2005 gas cost
component of bad debt write-offs beginning November 1, 2006.
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 250 MW combined cycle generating
facility located at the Ravenswood facility site ("Ravenswood Expansion").
107
LIPA Agreements:
In 1998, KeySpan and LIPA entered into three major long-term service agreements
that (i) provide to LIPA all operation, maintenance and construction services
and significant administrative services relating to the Long Island T&D system
pursuant to the Management Services Agreement (the "1998 MSA"); (ii) supply LIPA
with electric generating capacity, energy conversion and ancillary services from
our Long Island generating units pursuant to the Power Supply Agreement (the
"1998 PSA"); 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 the Energy Management Agreement (the
"1998 EMA"). The 1998 MSA, 1998 PSA and 1998 EMA all are collectively referred
to as the 1998 LIPA Agreements and are discussed in greater detail below.
KeySpan manages the day-to-day operations, maintenance and capital improvements
of the T&D system under the 1998 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 1998 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 the 1998 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 1998 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 the
1998 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 1998 EMA provides incentives
and penalties that can total $5 million annually for performance related to fuel
purchases and off-system power purchases. The 1998 EMA is expected to be in
effect through 2013 for the procurement of fuel supplies and through 2006 for
off-system arrangement services.
108
On February 1, 2006, KeySpan and LIPA entered into (i) an amended and restated
Management Services Agreement (the "2006 MSA"), pursuant to which KeySpan will
continue to operate and maintain the electric T&D System owned by LIPA on Long
Island; (ii) a new Option and Purchase and Sale Agreement (the "2006 Option
Agreement"), to replace the Generation Purchase Rights Agreement (as amended,
the "GPRA"), pursuant to which LIPA had the option, through December 15, 2005,
to effectively acquire substantially all of the electric generating facilities
owned by KeySpan on Long Island; and (iii) a Settlement Agreement (the "2006
Settlement Agreement") resolving outstanding issues between the parties
regarding the 1998 LIPA Agreements. The 2006 MSA, the 2006 Option Agreement and
the 2006 Settlement Agreement are collectively referred to herein as the "2006
LIPA Agreements". Each of the 2006 LIPA Agreements will become effective as of
January 1, 2006 upon all of the 2006 LIPA Agreements receiving the required
governmental approvals; otherwise none of the 2006 LIPA Agreements will become
effective. See Note 11, "2006 LIPA Settlement" for additional details on these
agreements.
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") each. 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.
Ravenswood Facilities:
In addition, electric revenues are derived from our investment in the 2,200 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 Generation Station. (See Note 7
"Contractual Obligations, Financial Guarantees and Contingencies" for a
description of the financing arrangements associated with the Ravenswood
Generation Station.) We realize revenues from our investment in the Ravenswood
Generation Station 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 service and
maintenance contracts associated with small commercial and residential
appliances are recognized as earned or over the life of the service contract, as
appropriate. Revenues earned for engineering services are derived from services
rendered under fixed price and cost-plus contracts and generally are recognized
on the percentage-of-completion method. 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 $29.3 million and $28.5 million as of December 31, 2005, and December
31, 2004, respectively. These balances represent primarily unearned revenues for
service contracts and are generally amortized to income over a one year period.
109
KeySpan completed its sale of its mechanical contracting companies in the first
quarter of 2005, and therefore, no longer has revenues form mechanical
contracting operations. (See Note 10 "Energy Services - Discontinued Operations"
for additional details on the mechanical contracting companies.)
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, 2005 ranged
from 1.80% to 7.02%. Capitalized interest for 2005, 2004 and 2003 was $1.4
million, $7.4 million and $13.5 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 cost of removal through rates charged to customers as a portion
of depreciation expense. At December 31, 2005 and 2004, KeySpan had costs
recovered in excess of costs incurred totaling $516.4 million and $496.5
million, respectively. These amounts are reflected as a regulatory liability.
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,
2005 2004 2003
- ---------------------------------------------------------------------
Electric 3.75% 3.87% 3.81%
Gas 3.72% 3.55% 3.37%
- ---------------------------------------------------------------------
- ---------------------------------------------------------------------
We also had $416.3 million of other property at December 31, 2005, consisting of
assets held primarily by our corporate service subsidiary of $290.0 million and
$96.0 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
110
depreciable lives ranging from three to 40 years. We allocate the carrying cost
of these assets to our operating subsidiaries through our filed allocation
methodology. Energy Services assets consist largely of computer 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 energy facilities after a project has been determined to be probable
of completion.
F. Gas Exploration and Production Property - Depletion
KeySpan maintains gas exploration and production activities through its two
wholly-owned subsidiaries - KeySpan Exploration and Production, LLC ("KeySpan
Exploration") and Seneca-Upshur Petroleum, Inc. ("Seneca-Upshur"). At December
31, 2005, these subsidiaries had net exploration and production property in the
amount of $75.0 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.
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 of December 31, 2005, we estimated that our capitalized costs did not exceed
the ceiling test limitation. We used an average wellhead price of $10.43 per
MCF, adjusted for derivative instruments.
As a result of the disposition of Houston Exploration in 2004, during 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.
111
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.
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, for 2004 and 2003, capitalized interest related to their
unevaluated natural gas and oil properties, as well as some properties under
development which were not being amortized. For years ended December 31, 2004
and 2003, capitalized interest was $3.4 million and $7.3 million, respectively.
G. Goodwill and Other Intangible Assets
The balance of goodwill and other intangible assets was $1.7 billion at December
31, 2005 and December 31, 2004, representing primarily the excess of acquisition
cost over the fair value of net assets acquired. Goodwill and other intangible
assets reflect the Eastern and EnergyNorth acquisitions, the KeySpan/LILCO
transaction, as well as acquisitions of non-utility energy-related service
companies and also relates to certain ownership interests of 50% or less in
energy-related investments, which are accounted for under the equity method.
The table below summarizes the goodwill and other intangible assets balance for
each segment at December 31, 2005 and 2004:
- -----------------------------------------------------------------------
(In Millions of Dollars) At December 31,
2005 2004
- -----------------------------------------------------------------------
Operating Segment
Gas Distribution $1,436.9 $1,436.9
Energy Services 65.2 65.8
Energy Investments and other 164.2 174.9
- -----------------------------------------------------------------------
$1,666.3 $1,677.6
- -----------------------------------------------------------------------
As prescribed in SFAS 142 "Goodwill and Other Intangible Assets," 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. At December 31, 2005, KeySpan
had $1.7 billion of recorded goodwill and has concluded that the fair value of
the business units that have recorded goodwill exceed their carrying value.
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. (See Note 10 to the
Consolidated Financial Statements "Energy Services-Discontinued Operations" for
further details.)
112
At the end of 2004, KeySpan entered into an agreement to sell its then 50%
interest in Premier Transmission Limited ("Premier"). This investment was
accounted for under the equity method of accounting in the Energy Investments
segment. In the fourth quarter of 2004 KeySpan recorded a partial pre-tax
non-cash impairment charge of $26.5 million - $18.8 million after-tax or $0.12
per share. The impairment charge reflected the difference between the
anticipated cash proceeds from the sale of Premier compared to its carrying
value at that time and was recorded as a reduction to goodwill.
H. Hedging and Derivative Financial Instruments
From time to time, we employ derivative instruments to hedge a portion of our
exposure to commodity price risk and interest rate risk, as well as to 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 currently outstanding derivative instruments do
not qualify as energy trading contracts as defined by current accounting
literature.
Financially-Settled Commodity Derivative Instruments: We employ derivative
financial instruments, such as futures, options and swaps, for the purpose of
hedging the cash flow variability associated with forecasted purchases and sales
of various energy-related commodities. All such derivative instruments are
accounted for pursuant to the requirements of SFAS 133 "Accounting for
Derivative Instruments and Hedging Activities," as amended by SFAS 149,
"Amendment of Statement 133 Derivative Instruments and Hedging Activities"
(collectively, "SFAS 133"). With respect to those commodity derivative
instruments that are designated and accounted for as cash flow hedges, the
effective portion of periodic changes in the fair market value of cash flow
hedges is recorded as other comprehensive income on the Consolidated Balance
Sheet, while the ineffective portion of such changes in fair value is recognized
in earnings. Unrealized gains and losses (on such cash flow hedges) that are
recorded as other comprehensive income are subsequently reclassified into
earnings concurrent when hedged transactions impact earnings. With respect to
those commodity derivative instruments that are not designated as hedging
instruments, such derivatives are accounted for on the Consolidated Balance
Sheet at fair value, with all changes in fair value reported in earnings.
Firm Gas Sales Derivatives Instruments - Regulated Utilities: We utilize
derivative financial instruments to reduce cash flow variability associated with
the purchase price for a portion of our future natural gas purchases. Our
strategy is to minimize fluctuations in firm gas sales prices to our regulated
firm gas sales customers in our New York and New England service territories.
Since these derivative instruments are being employed to support our gas sales
prices to regulated firm gas sales customers, the accounting for these
derivative instruments is subject to SFAS 71. Therefore, changes in the market
value of these derivatives are recorded as regulatory assets or regulatory
liabilities on our Consolidated Balance Sheet. Gains or losses on the settlement
of these contracts are initially deferred and then refunded to or collected from
our firm gas sales customers during the appropriate winter heating season
consistent with regulatory requirements.
113
Physically-Settled Commodity Derivative Instruments: Certain of our contracts
for the physical purchase of natural gas were assessed as no longer being exempt
from the requirements of SFAS 133 as normal purchases. As such, these contracts
are recorded on the Consolidated Balance Sheet at fair market value. However,
since such contracts were executed for the purchases of natural gas that is sold
to regulated firm gas sales customers, and pursuant to the requirements of SFAS
71, changes in the fair market value of these contracts are recorded as a
regulatory asset or regulatory liability on the Consolidated Balance Sheet.
Weather Derivatives: The utility tariffs associated with our New England gas
distribution operations do not contain a weather normalization adjustment. As a
result, fluctuations from normal weather may have a significant positive or
negative effect on the results of these operations. To mitigate the effect of
fluctuations from normal weather on our financial position and cash flows, we
may enter into derivative instruments from time to time. Based on the terms of
the contracts, we account for these instruments pursuant to the requirements of
Emerging Issues Task Force ("EITF") 99-2 "Accounting for Weather Derivatives."
In this regard, we account for weather derivatives using the "intrinsic value
method" as set forth in such guidance.
Interest Rate Derivative Instruments: We continually assess the cost
relationship between fixed and variable rate debt. Consistent with our objective
to minimize our cost of capital, we periodically enter into hedging transactions
that effectively convert the terms of underlying debt obligations from fixed to
variable or variable to fixed. Payments made or received on these derivative
contracts are recognized as an adjustment to interest expense as incurred.
Hedging transactions that effectively convert the terms of underlying debt
obligations from fixed to variable are designated and accounted for as
fair-value hedges pursuant to the requirements of SFAS 133. Hedging transactions
that effectively convert the terms of underlying debt obligations from variable
to fixed are considered cash flow hedges.
I. Equity Investments
Certain subsidiaries own as their principal assets, investments (including
goodwill), representing ownership interests of 50% or less in energy-related
businesses that are accounted for under the equity method. None of these 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, 2005, 2004
and 2003, excise taxes collected and paid were $65.8 million, $73.3 million,
$90.5 million, respectively.
114
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 followed 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, the foreign currency
translation adjustment was included on the Consolidated Balance Sheet. The
functional currency for our foreign affiliates was their local currency. At
December 31, 2005, SFAS 52 was not applicable to KeySpan since we completed the
sale of our remaining foreign investment in the first quarter of 2005.
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.
At December 31, 2005, we had approximately 4.6 million options outstanding to
purchase KeySpan common stock that were not used in the calculation of diluted
EPS since the exercise price associated with these options were greater than the
average per share market price of Keyspan's common stock. In addition, there
were approximately 384,000 performance shares not used in the calculation of
diluted EPS since these shares would not have been issued if December 31, 2005
were the end of the performance period. In 2003, 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 Millions of Dollars, Except Per Share Amounts) 2005 2004 2003
- ----------------------------------------------------------------------------------------------------------------
Earnings for common stock $ 388.0 $ 458.1 $ 380.9
Houston Exploration dilution - - (0.3)
Preferred stock dividend - - 0.5
- ----------------------------------------------------------------------------------------------------------------
Earnings for common stock - adjusted $ 388.0 $ 458.1 $ 381.1
- ----------------------------------------------------------------------------------------------------------------
Weighted average shares outstanding (000) 169,940 160,294 158,256
Add dilutive securities:
Options 861 983 755
Convertible preferred stock - - 221
- ----------------------------------------------------------------------------------------------------------------
Total weighted average shares outstanding - assuming dilution 170,801 161,277 159,232
- ----------------------------------------------------------------------------------------------------------------
Basic earnings per share $ 2.28 $ 2.86 $ 2.41
- ----------------------------------------------------------------------------------------------------------------
Diluted earnings per share $ 2.27 $ 2.84 $ 2.39
- ----------------------------------------------------------------------------------------------------------------
115
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 3.7 million of these shares were available
for issuance at December 31, 2005. Under a separate plan, Houston Exploration
had issued stock options to its key 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
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 Millions of Dollars, Except Per Share Amounts) 2005 2004 2003
- ------------------------------------------------------------------------------------------------------------------------
Earnings available for common stock:
As reported $ 388.0 $ 458.1 $ 380.9
Add: recorded stock-based compensation expense, net of tax 7.0 9.1 3.7
Deduct: total stock-based compensation expense, net of tax (8.9) (12.4) (9.4)
- ------------------------------------------------------------------------------------------------------------------------
Pro-forma earnings $ 386.1 $ 454.8 $ 375.2
- ------------------------------------------------------------------------------------------------------------------------
Earnings per share:
Basic - as reported $ 2.28 $ 2.86 $ 2.41
Basic - pro-forma $ 2.27 $ 2.84 $ 2.37
Diluted - as reported $ 2.27 $ 2.84 $ 2.39
Diluted - pro-forma $ 2.26 $ 2.82 $ 2.36
- ------------------------------------------------------------------------------------------------------------------------
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,
2005 2004 2003
- --------------------------------------------------------------------------------
Fair value of grants issued $ 6.15 $ 5.47 $ 4.26
Dividend yield 4.64% 4.74% 5.49%
Expected volatility 22.63% 23.48% 24.26%
Risk free rate 4.10% 3.22% 3.16%
Expected lives 6.4 years 6.5 years 6 years
Exercise price $ 39.25 $ 37.54 $ 32.40
- --------------------------------------------------------------------------------
116
A summary of the status of our fixed stock option plans and changes is presented
below for the periods indicated:
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
2005 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------------
Weighted Weighted Weighted
Exercise Exercise Exercise
Fixed Options Shares Price Shares Price Shares Price
- ------------------------------------------------------------------------------------------------------------------------------------
Outstanding at beginning of period 10,540,946 $ 32.61 10,320,743 $ 31.39 9,524,900 $ 30.74
Granted during the year 1,451,650 $ 39.25 1,602,850 $ 37.54 1,650,450 $ 32.40
Exercised (1,400,190) $ 30.65 (1,150,464) $ 28.05 (664,902) $ 23.64
Forfeited (149,351) $ 36.32 (232,183) $ 35.18 (189,705) $ 34.63
- ------------------------------------------------------------------------------------------------------------------------------------
Outstanding at end of period 10,443,055 $ 33.74 10,540,946 $ 32.61 10,320,743 $ 31.39
- ------------------------------------------------------------------------------------------------------------------------------------
Exercisable at end of period 5,673,084 $ 31.55 5,523,259 $ 30.39 5,365,545 $ 28.76
- ------------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------------
Remaining Weighted Average Weighted Average Range of
Contractual Options Outstanding at Exercise Range of Options Exercisable Exercise Exercise
Life December 31, 2005 Price Exercise Price at December 31, 2005 Price Price
- ------------------------------------------------------------------------------------------------------------------------------------
1 years 148,000 $ 30.50 30.50 148,000 $ 30.50 30.50
2 years 230,410 $ 32.54 $ 19.15 - 32.63 230,410 $ 32.54 $ 19.15 - 32.63
3 years 844,625 $ 27.96 $ 24.73 - 29.38 844,625 $ 27.96 $ 24.73 - 29.38
4 years 392,848 $ 26.97 $ 21.99 - 27.06 392,847 $ 26.97 $ 21.99 - 27.06
5 years 998,887 $ 22.68 $ 22.50 - 32.76 998,887 $ 22.68 $ 22.50 - 32.76
6 years 1,657,075 $ 39.50 $39.50 1,313,025 $ 39.50 $39.50
7 years 1,944,811 $ 32.66 $32.66 1,054,195 $ 32.66 $32.66
8 years 1,286,493 $ 32.40 $32.40 415,856 $ 32.40 $32.40
9 years 1,502,756 $ 37.54 $37.54 275,239 $ 37.54 $37.54
10 years 1,437,150 $ 39.25 $39.25 - $ 39.25 $39.25
- ------------------------------------------------------------------------------------------------------------------------------------
10,443,055 5,673,084
- ------------------------------------------------------------------------------------------------------------------------------------
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. These
performance shares are measured over a three year period by comparing KeySpan's
cumulative total shareholder return to the S&P Utilities Group. The award
"cliff" vests after each 3 year period.
During 2005, it became apparent to management that the 2003 performance share
award would not be achieved and the 2004 performance share award would not be
achieved at the level of expense being recorded. Since these awards meet the
definition of a performance condition not achieved under SFAS 123, KeySpan
reversed the previously recognized expense for the 2003 award and one half of
previously recognized expense for the 2004 award amounting to $3.8 million ($2.5
million after tax). For the 2005 award, it is too early to predict whether the
performance condition will be achieved and therefore none of the expense
recorded to date for the 2005 performance share award has been reversed.
117
In December 2004, the FASB issued SFAS 123R "Share-Based Payment" which
superseded SFAS 123. The effective date of SFAS 123R is the first quarter of
2006. Under this standard, we will be prohibited from reversing any previously
recorded expense for the portion of the 2004 and 2005 performance share awards
currently deemed attainable. This is due to the fact that the condition of our
current performance share awards will be viewed as market conditions under SFAS
123R.
O. Recent Accounting Pronouncements
On July 14, 2005, the Financial Accounting Standards Board ("FASB") issued an
Exposure Draft "Accounting for Uncertain Tax Positions," that would interpret
SFAS 109, "Accounting for Income Taxes." This proposal seeks to reduce the
diversity in practice associated with certain aspects of the recognition and
measurement requirements related to accounting for income taxes. Specifically,
the proposal would require that a tax position meet a "probable recognition
threshold" for the benefit of an uncertain tax position to be recognized in the
financial statements. The proposal would require recognition in the financial
statements of the best estimate of the effect of a tax position only if that
position is probable of being sustained on audit by the appropriate taxing
authorities, based solely on the technical merits of the position.
The proposed effective date has been delayed until the first fiscal year ending
after January 1, 2007. KeySpan is currently evaluating this Exposure Draft, and
at this time cannot determine the impact, if any, that the potential
requirements of this Exposure Draft may have on its results of operations,
financial position or cash flows.
In March 2005, the FASB issued FASB Interpretation No. 47 ("FIN 47") "Accounting
for Conditional Asset Retirement Obligations - an interpretation of FASB
Statement No. 143." FIN 47 clarifies that the term conditional asset retirement
obligation as used in SFAS No. 143 "Accounting for Asset Retirement
Obligations", refers to a legal obligation to perform an asset retirement
activity in which the timing and/or method of settlement are conditional on a
future event that may or may not be within the control of the entity. The
obligation to perform the asset retirement activity is unconditional even though
uncertainty exists about the timing and/or method of settlement. Accordingly, an
entity is required to recognize a liability for the fair value of a conditional
asset retirement obligation if the fair value of the liability can be reasonably
estimated. Uncertainty about the timing and/or method of settlement of a
conditional asset retirement obligation should be factored into the measurement
of the liability when sufficient information exists. An entity shall recognize
the cumulative effect of initially applying FIN 47 as a change in accounting
principle. KeySpan implemented FIN 47 in December 2005. See Note 1 Item P below
and Note 7 "Contractual Obligations, Financial Guarantees and Contingencies" for
further information on FIN 47.
In 2004, the 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 clarified the accounting and
disclosure requirements for employers with postretirement benefit plans that
have been affected by the passage of the Medicare Prescription Drug Improvement
and Modernization Act of 2003 (the "Medicare 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.
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 2004 and determined that the savings associated
with the Medicare Act reduced KeySpan's retiree health care costs by
approximately $10 million in 2004. However, KEDLI and Boston Gas Company are
118
subject to certain deferral accounting requirements mandated by the NYPSC and
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 Medicare 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 Medicare Act had
no immediate impact on KeySpan's cash flow.
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. KeySpan reviewed
the new provisions and believes that the new guidance will not have a material
impact on its 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 SFAS 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 SFAS 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 SFAS 123; and 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
SFAS 123's guidance in several areas. The effective date of this Statement is
the beginning of the first fiscal year beginning after June 15, 2005. 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 believes that implementation of this Statement will not
have a material impact on its results of operations or financial position and no
impact on its cash flows.
P. Impact of Cumulative Effect of Change in Accounting Principles
As previously discussed, KeySpan implemented FIN 47, effective December 31,
2005. FIN 47 required KeySpan to record a liability and corresponding asset
representing the present value of conditional asset retirement obligations
associated with the retirement of tangible, long-lived assets on the date the
obligations were incurred. At year-end, we recorded a $45.6 million liability
and corresponding asset representing the present value of conditional asset
retirement obligations associated with the retirement of tangible, long-lived
assets on the date the obligations were incurred. For the $45.6 million initial
asset recorded, approximately $4.3 million represents asset retirement costs
that have been deferred on the Consolidated Balance Sheet and will be
depreciated over the remaining life of the underlying associated assets lives.
119
The remaining $41.3 million represented cumulative accretion and depreciation
expense associated with the liability and asset from the dates the various
obligations would have been recorded had this Interpretation been in effect at
the time the obligations were incurred.
Of the $41.3 million recorded, $11.3 million ($6.6 million, net of taxes), was
recorded as a cumulative change in accounting principle on the Consolidated
Statement of Income. The remaining $30.0 million was attributable to the Gas
Distribution segment and was recorded as a reduction to the removal cost
recovered. For asset retirement costs incurred in the Gas Distribution segment,
KeySpan is recovering these costs from utility customers and has been expensing
a like amount through its depreciation expense. A portion of this depreciation
expense represents removal costs not yet incurred. The $30 million recorded to
the removal cost recovered is for purposes of reclassifying a portion of this
reserve to the asset retirement obligation. (See Note 7, "Contractual
Obligations, Financial Guarantees and Contingencies - Asset Retirement
Obligations" for further details.)
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 FASB Interpretation No. 46 ("FIN 46").
This pronouncement required KeySpan to consolidate its variable interest entity,
which had a fair market value of $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, cumulative 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.)
120
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 Millions of Dollars, Except Per Share Amounts) 2005 2004 2003
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings for common stock $ 388.0 $ 458.1 $ 380.9
Add back: Cumulative effect of a change in accounting principle 6.6 - 37.4
Earnings for common stock before cumulative effect of a change
in accounting principle:
As reported 394.6 458.1 418.3
Less: FIN 47 Accretion expense, net of taxes (0.5) (0.4) (0.4)
Add: FIN 47 Depreciation expense, net of taxes (0.2) (0.2) (0.1)
Less: FIN 46 Depreciation expense, net of taxes - - (9.5)
- ----------------------------------------------------------------------------------------------------------------------------------
Pro-forma earnings $ 393.9 $ 457.5 $ 408.3
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings per share before cumulative change in accounting principle:
Basic - as reported $ 2.32 $ 2.86 $ 2.64
Basic - pro-forma $ 2.32 $ 2.85 $ 2.58
Diluted - as reported $ 2.31 $ 2.84 $ 2.62
Diluted - pro-forma $ 2.31 $ 2.84 $ 2.56
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings per share for common stock:
Basic - as reported $ 2.28 $ 2.86 $ 2.41
Basic - pro-forma $ 2.32 $ 2.85 $ 2.58
Diluted - as reported $ 2.27 $ 2.84 $ 2.39
Diluted - pro-forma $ 2.31 $ 2.84 $ 2.56
- ----------------------------------------------------------------------------------------------------------------------------------
In addition to the above disclosure, FIN 47 requires disclosure of the pro-forma
impact of the liability for the asset retirement obligation for the beginning of
the earliest year presented and at the end of all years presented as if this
Interpretation had been applied during all periods effected. The disclosure is
as follows:
- --------------------------------------------------------------------------------
(In Millions of Dollars)
DECEMBER 31, 2005 2004
- --------------------------------------------------------------------------------
Asset retirement obligation - January 1 $ 44.9 $ 42.5
Accretion 2.5 2.4
- --------------------------------------------------------------------------------
Asset retirement obligation - December 31 $ 47.4 $ 44.9
- --------------------------------------------------------------------------------
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 Millions of Dollars) 2005 2004
- ----------------------------------------------------------------------------------------
Foreign currency translation adjustments $ - $ 5.0
Unrealized (losses) on marketable securities (0.9) (0.4)
Accrued unfunded pension obligation (63.5) (59.8)
Unrealized (losses) gain on derivative financial instruments (10.4) 0.9
- ----------------------------------------------------------------------------------------
Accumulated other comprehensive income $ (74.8) $ (54.3)
- ----------------------------------------------------------------------------------------
121
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 one to seven years and
power purchase agreements having remaining terms that range from seven to 21
years. On February 1, 2006, KeySpan and LIPA agreed to extend, amend and restate
these contractual arrangements. (See Note 11, "2006 LIPA Settlement" for a
further discussion of these agreements.) The Electric Services segment also
includes subsidiaries that own or lease and operate the 2,200 megawatt
Ravenswood Facility located in Queens, New York, and the 250 MW combined-cycle
Ravenswood Expansion. Collectively the Ravenswood Facility and Ravenswood
Expansion are referred to as the "Ravenswood Generating Station". All of the
energy, capacity and ancillary services related to the Ravenswood Generating
Station are sold to the NYISO energy markets. To finance the purchase and/or
construction of the Ravenswood Generating Station, 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
services to customers located primarily within the Northeastern United States.
Subsidiaries in this segment provide residential and small commercial customers
with service and maintenance of energy systems and appliances, as well as
operation and maintenance, design, engineering, consulting and fiber optic
services to commercial, institutional and industrial customers.
In January and February of 2005, KeySpan sold its mechanical contracting
subsidiaries. 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, including approximately $5 million to be paid within
a three year period. In addition, KeySpan retained a portion of its previously
incurred surety indemnity support obligations related to certain performance and
payment bonds issued for the benefit of KeySpan's former subsidiaries prior to
closing. In June 2005, the balance to be paid over a three year period was fully
collected on a present value basis and a significant portion of the performance
bonds were replaced without any remaining indemnification obligation on the part
122
of KeySpan. The current estimated cost to complete projects supported by the
remaining indemnity obligations associated with the January 2005 transactions is
approximately $0.2 million. The buyers have agreed to complete the projects for
which such indemnity obligations were incurred and to indemnify and hold KeySpan
harmless with respect to its liabilities in connection with such bonds.
In connection with the February 2005 transaction, KeySpan paid or contributed
approximately $26 million to a 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 surety 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 December 31,
2005, the total cost to complete such remaining bonded projects is estimated to
be approximately $40 million. The aforementioned guarantees are reflected in
Note 7 "Contractual Obligations, Financial Guarantees and Contingencies."
KeySpan's former subsidiary has also agreed to complete the projects for which
such indemnity obligations were incurred and indemnify and hold KeySpan harmless
with respect to any liabilities in connection with such bonds.
In the fourth quarter of 2004, KeySpan's investment in its mechanical
contracting subsidiaries was written-down to an estimated fair value. During
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 10 "Energy Services - Discontinued
Operations" for additional details regarding these charges.) During the first
six months of 2005, operating losses were incurred through the dates of sale of
these companies of $4.1 million after-tax, including but not limited to costs
incurred for employee related benefits. Partially offsetting these losses was a
gain of $2.3 million associated with the related divestitures, reflecting the
difference between the fair value estimates and the financial impact of the
actual sale transactions. The net income impact of the operating losses and the
disposal gain was a loss of $1.8 million, or $0.01 per share for the twelve
months ended December 31, 2005.
The Energy Investments segment consists of our gas exploration and production
investments, as well as certain other domestic energy-related investments.
KeySpan's gas exploration and production activities include our wholly-owned
subsidiaries Seneca Upshur Petroleum, Inc. ("Seneca-Upshur") and KeySpan
Exploration and Production, LLC ("KeySpan Exploration"). Seneca-Upshur is
engaged in gas exploration and production activities primarily in West Virginia.
KeySpan Exploration is engaged in a joint venture with The Houston Exploration
Company ("Houston Exploration"), an independent natural gas and oil exploration
company located in Houston, Texas.
During the first five months of 2004, our gas exploration and production
investments also included a 55% equity interest in Houston Exploration, the
operations of which were fully consolidated in KeySpan's Consolidated Financial
Statements. On June 2, 2004, KeySpan exchanged 10.8 million shares of common
stock of Houston Exploration for 100% of the stock of Seneca-Upshur, previously
123
a wholly owned subsidiary of Houston Exploration. This transaction reduced our
interest in Houston Exploration from 55% to the then current level of 23.5%.
Effective June 1, 2004, Houston Exploration's earnings and our ownership
interest in Houston Exploration were accounted for on the equity method of
accounting. This transaction resulted in a gain to KeySpan of $150.1 million.
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 in fiscal years 2004 and 2003, were $268.1 million, and
$495.3 million, respectively. Houston Exploration's operating income, including
KeySpan's share of equity earnings, was $138.5 million and $196.3 million in
fiscal years 2004 and 2003, respectively.
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.
The per share gain on this transaction was $0.12.
The Energy Investments segment is also engaged in pipeline development
activities. KeySpan and Duke Energy Corporation each own a 50% interest in the
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, KeySpan has a 21%
interest in the Millennium Pipeline project which is expected to transport up to
525,000 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. 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.
Through its wholly owned subsidiary, KeySpan LNG, LP, KeySpan owns a liquefied
natural gas storage and receiving facility in Providence, Rhode Island, the
operations of which are fully consolidated.
During the first quarter of 2004, we also had an approximate 61% investment in
certain midstream natural gas assets in Western Canada through KeySpan Energy
Canada Partnership ("KeySpan Canada"). These assets included 14 processing
plants and associated gathering systems that produced approximately 1.5 BCFe of
natural gas daily and provided associated natural gas liquids fractionation.
124
These operations were fully consolidated in KeySpan's Consolidated Financial
Statements. On April 1, 2004, KeySpan and KeySpan Facilities Income Fund (the
"Fund"), which previously owned a 39.09% interest in KeySpan Canada, consummated
a transaction whereby the Fund sold 15.617 million units of the Fund and
acquired an additional 35.91% interest in KeySpan Canada from KeySpan. As a
result of this transaction, KeySpan's ownership of KeySpan Canada decreased to
25%. KeySpan recorded a gain of $22.8 million ($10.1 million after-tax, or $0.06
per share) at the time of this transaction. Effective April 1, 2004 KeySpan
Canada's earnings and our ownership interest in KeySpan Canada were accounted
for on the equity method 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 in fiscal years 2004 and 2003, were $25.2 million and $90.3
million, respectively. KeySpan Canada's operating income, including KeySpan's
share of equity earnings, was $16.5 million and $29.7 million, 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. Additionally, we sold our 20% interest in
Taylor NGL LP that owns 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 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, or $0.22 per share.
In the first quarter of 2005, KeySpan sold its 50% interest in Premier
Transmission Limited ("Premier"), 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 Public Limited Company ("PTFPL"), pursuant to which all of the
outstanding shares of Premier were to be purchased by PTFPL. On March 18, 2005,
the sale was completed and generated cash proceeds of approximately $48.1
million. In the fourth quarter of 2004, KeySpan recorded a pre-tax non-cash
impairment charge of $26.5 million reflecting the difference between the
anticipated cash proceeds from the sale of Premier compared to its carrying
value. The final sale of Premier resulted in a pre-tax gain of $4.1 million
reflecting the difference from earlier estimates; this gain was recorded in the
first quarter of 2005.
125
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. For fiscal years 2004 and 2003, the
operating data of Houston Exploration has been separately displayed. The
reportable segment information is as follows:
- ------------------------------------------------------------------------------------------------------------------------------------
Gas Electric Energy Other
(In Millions of Dollars) Distribution Services Services Investments Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2005
Unaffiliated revenue 5,390.1 2,042.7 191.2 38.0 - 7,662.0
Intersegment revenue - 4.6 10.8 5.0 (20.4) -
Depreciation, depletion and amortization 277.0 91.7 7.6 6.8 13.4 396.5
Gain on sales of property 0.1 1.2 - 0.1 0.2 1.6
Income from equity investments - - - 15.1 - 15.1
Operating income 565.7 342.3 (2.7) 20.6 (18.1) 907.8
Interest income 0.9 0.8 0.2 2.8 7.6 12.3
Interest charges 178.2 71.7 18.4 1.8 (0.8) 269.3
Total assets 10,052.5 2,348.0 199.0 341.9 871.2 13,812.6
Equity method investments - - - 106.7 - 106.7
Construction expenditures 410.3 88.8 7.4 23.6 9.4 539.5
- ------------------------------------------------------------------------------------------------------------------------------------
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 $2.0 billion for the year
ended December 31, 2005 represents approximately 26% of our consolidated
revenues during that period.
- ------------------------------------------------------------------------------------------------------------------------------------
Gas Electric Energy Houston Other
(In Millions of Dollars) Distribution Services Services Exploration Investments Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2004
Unaffiliated revenue 4,407.3 1,738.7 182.4 268.1 54.0 - 6,650.5
Intersegment revenue - - 11.5 - 4.9 (16.4) -
Depreciation, depletion and
amortization 276.5 88.2 7.5 104.6 59.7 15.3 551.8
Gain on sales of property - 2.0 - - 5.0 - 7.0
Income from equity investments - - - 20.7 25.8 - 46.5
Operating income 579.6 289.8 (48.3) 138.5 (33.8) 9.5 935.3
Interest income 2.2 9.9 - 3.5 3.0 (9.2) 9.4
Interest charges 176.8 72.9 19.4 3.5 3.9 54.8 331.3
Total assets 8,908.8 2,144.3 246.6 - 701.3 1,363.1 13,364.1
Equity method investments - - - - 107.1 - 107.1
Construction expenditures 414.5 150.3 13.7 146.5 13.7 11.6 750.3
- ------------------------------------------------------------------------------------------------------------------------------------
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 $1.7 billion for the year
ended December 31, 2004 represents approximately 25% of our consolidated
revenues during that period.
126
- ------------------------------------------------------------------------------------------------------------------------------------
Gas Electric Energy Houston Other
(In Millions of Dollars) Distribution Services Services Exploration Investments Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2003
Unaffiliated revenue 4,161.3 1,606.0 158.9 495.3 114.0 - 6,535.5
Intersegment revenue - 0.1 7.5 - 5.0 (12.6) -
Depreciation, depletion and
amortization 259.9 67.2 7.1 204.1 19.1 14.3 571.7
Gain on sales of property 15.1 - - - - - 15.1
Income from equity investments - - - - 19.1 0.1 19.2
Operating income 574.3 269.9 (33.0) 196.3 42.2 (2.1) 1,047.6
Interest income 1.2 4.6 1.1 - 1.0 (2.2) 5.7
Interest charges 203.7 44.2 15.8 8.5 7.5 28.0 307.7
Total assets 8,457.5 2,511.1 407.5 1,530.9 915.4 817.8 14,640.2
Equity method investments - - - - 97.0 - 97.0
Construction expenditures 419.6 256.5 7.0 295.9 18.1 12.3 1,009.4
- ------------------------------------------------------------------------------------------------------------------------------------
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 $1.5 billion for the year
ended December 31, 2003 represents approximately 22% 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 Millions of Dollars) 2005 2004 2003
- ------------------------------------------------------------------------
Current income tax $ 206.6 $ 201.9 $ (99.8)
Deferred income tax 32.7 123.6 381.1
- ------------------------------------------------------------------------
Total income tax $ 239.3 $ 325.5 $ 281.3
- ------------------------------------------------------------------------
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 Millions of Dollars) 2005 2004
- --------------------------------------------------------------------------
Reserves not currently deductible $ 28.4 $ 23.9
State income tax (20.6) (19.0)
Property related differences (1,080.8) (1,080.0)
Regulatory tax asset (24.5) (21.4)
Property taxes (84.1) (99.1)
Employee benefits and compensation (64.4) (16.6)
Other items - net 88.1 88.1
- --------------------------------------------------------------------------
Net deferred tax liability $ (1,157.9) $ (1,124.1)
- --------------------------------------------------------------------------
127
KeySpan is currently in discussions with the Internal Revenue Service ("IRS") at
the Appeals level with regard to 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 years ending September 30, 1997 through
December 31, 1998. The primary issue relates to the valuation of the transferred
assets in the KeySpan/LILCO combination. Additionally, the IRS has recently
commenced the examination of KeySpan's tax returns for the year ended 2002 and
2003. At this time, we cannot predict the result of these audits. However,
KeySpan has evaluated the potential outcomes based on the issues raised and
progress of the discussions to date. KeySpan believes that it has adequately
provided for the additional tax, if any, which may result.
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 Millions of Dollars) 2005 2004 2003
- ----------------------------------------------------------------------------------------------
Computed at the statutory rate $ 223.3 $ 329.1 $ 247.6
Adjustments related to:
Tax credits (1.4) (2.2) -
Removal costs (2.9) (0.6) (6.6)
Accrual to return adjustments 6.7 (10.7) 0.5
Sale of subsidiary stock - (22.5) -
Minority interest in Houston Exploration - 12.9 20.0
State income tax, net of federal benefit 29.0 24.8 28.5
Contribution of land (3.8) - -
Dividends paid to employee benefit plan (3.9) (3.6) -
Other items - net (7.7) (1.7) (8.7)
- ----------------------------------------------------------------------------------------------
Total income tax $ 239.3 $ 325.5 $ 281.3
- ----------------------------------------------------------------------------------------------
Effective income tax rate (1) 38% 35% 40%
- ----------------------------------------------------------------------------------------------
(1) Reflects both federal as well as state income taxes.
The American Jobs Creation Act of 2004, 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 2004 or
2005. We currently estimate that KeySpan has repatriated dividends of
approximately $9.5 million of earnings under this provision and received, as a
result, a tax benefit of $2.8 million.
As of December 31, 2005 KeySpan has $285 million of state tax net operating loss
carryforwards which, if fully utilized at current rates, will yield tax credits
of approximately $25 million. These credits will expire between 2011 and 2022.
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.
128
The calculation of net periodic pension cost is as follows:
- -------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Millions of Dollars) 2005 2004 2003
- -------------------------------------------------------------------------------------------------
Service cost, benefits earned during the period $ 56.5 $ 52.9 $ 47.5
Interest cost on projected benefit obligation 148.5 144.2 138.3
Expected return on plan assets (173.1) (158.2) (130.6)
Net amortization and deferral 74.1 63.3 67.0
Special termination benefits 2.2 - -
- -------------------------------------------------------------------------------------------------
Total pension cost $ 108.2 $ 102.2 $ 122.2
- -------------------------------------------------------------------------------------------------
The following table sets forth the pension plans' funded status at December 31,
2005 and December 31, 2004.
- -------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Millions of Dollars) 2005 2004
- -------------------------------------------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation at beginning of period $ (2,520.1) $ (2,343.2)
Service cost (56.6) (52.9)
Interest cost (148.5) (144.2)
Amendments (0.1) (2.3)
Actuarial loss (117.9) (114.6)
Benefits paid 130.4 137.1
Special termination benefits (2.2) -
- -------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period $ (2,715.0) $ (2,520.1)
- -------------------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of period 2,028.9 1,855.2
Actual return on plan assets 166.7 164.2
Employer contribution 148.3 146.6
Benefits paid (130.4) (137.1)
- -------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period 2,213.5 2,028.9
- -------------------------------------------------------------------------------------------------------------
Funded status (501.5) (491.2)
Unrecognized net loss from past experience different from that
assumed and from changes in assumptions 672.1 612.1
Unrecognized prior service cost 48.2 57.7
- -------------------------------------------------------------------------------------------------------------
Net prepaid pension cost reflected on consolidated balance sheet $ 218.8 $ 178.6
- -------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
Year Ended December 31,
2005 2004 2003
- -------------------------------------------------------------------------------
Assumptions:
Obligation discount 5.75% 6.00% 6.25%
Asset return 8.50% 8.50% 8.50%
Average annual increase in compensation 4.00% 4.00% 4.00%
- -------------------------------------------------------------------------------
129
The following benefit payments, which reflect expected future service, as
appropriate, are expected to be paid in the years indicated:
- -------------------------------------------------
(In Millions of Dollars) Pension Benefits
- -------------------------------------------------
2006 $ 132.2
2007 $ 134.1
2008 $ 137.7
2009 $ 141.4
2010 $ 146.0
Years 2011- 2015 $ 839.3
- -------------------------------------------------
Unfunded Pension Obligation: At December 31, 2005 the accumulated benefit
obligation was in excess of pension assets. As prescribed by SFAS 87 "Employers'
Accounting for Pensions," KeySpan had a $257.3 million minimum liability at
December 31, 2005, 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
$41.2 million, representing the amount of unrecognized prior service cost and a
debit to accumulated other comprehensive income of $97.8 million, or $63.6
million after-tax. The remaining amount of $118.3 million was recorded as a
contractual receivable from LIPA of $103.8 million and a regulatory asset of
$14.5 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. Boston Gas 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, 2005 the projected benefit obligation, accumulated benefit
obligation and value of assets for plans with accumulated benefit obligations in
excess of plan assets were $1.4 billion, $1.3 billion and $997 million,
respectively.
At December 31, 2004, the accumulated benefit obligation was also in excess of
pension assets. As a result, we had a minimum liability of $255.9 million, a
long-term asset in deferred charges other of $49.7 million, 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.
At December 31, 2004 the projected benefit obligation, accumulated benefit
obligation and value of assets for plans with accumulated benefit obligations in
plan assets were $1.3 billion, $1.2 billion and $881 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.
130
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 Millions of Dollars) 2005 2004 2003
- -------------------------------------------------------------------------------
Service cost, benefits earned during the period $ 24.4 $ 19.7 $ 18.8
Interest cost on accumulated
postretirement benefit obligation 75.7 70.2 69.8
Expected return on plan assets (36.1) (33.9) (27.5)
Net amortization and deferral 59.9 41.0 35.8
Special termination benefit 1.7 - -
- -------------------------------------------------------------------------------
Other postretirement cost $ 125.6 $ 97.0 $ 96.9
- -------------------------------------------------------------------------------
The following table sets forth the plans' funded status at December 31, 2005 and
December 31, 2004.
- ----------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Millions of Dollars) 2005 2004
- ----------------------------------------------------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation at beginning of period $ (1,336.7) $ (1,267.6)
Impact due to Medicare subsidy - 60.6
Service cost (24.4) (19.7)
Interest cost (75.7) (70.2)
Plan participants' contributions (3.4) (1.9)
Amendments 3.2 27.4
Actuarial (loss) (38.3) (119.9)
Benefits paid 62.7 54.6
Special termination benefit (1.7) -
- ----------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period (1,414.3) (1,336.7)
- ----------------------------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of period 464.0 438.4
Actual return on plan assets 29.1 38.8
Employer contribution 35.8 39.5
Plan participants' contributions 3.4 1.9
Benefits paid (62.7) (54.6)
- ----------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period 469.6 464.0
- ----------------------------------------------------------------------------------------------------------------------
Funded status (944.7) (872.7)
Unrecognized net loss from past experience different from that assumed
and from changes in assumptions 557.5 576.8
Unrecognized prior service cost (97.5) (106.5)
- ----------------------------------------------------------------------------------------------------------------------
Accrued postretirement cost reflected on consolidated balance sheet $ (484.7) $ (402.4)
- ----------------------------------------------------------------------------------------------------------------------
131
- -----------------------------------------------------------------------------------
Year Ended December 31,
2005 2004 2003
- -----------------------------------------------------------------------------------
Assumptions:
Obligation discount 5.75% 6.00% 6.25%
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 9.5% grading down to 4.75% over six years, and 4.75% 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, 2005 by
$173.1 million and the net periodic health care expense by $14.9 million. A 1%
decrease in the health care cost trend rate would have the effect of decreasing
the accumulated postretirement benefit obligation as of December 31, 2005 by
$151.1 million and the net periodic health care expense by $12.6 million.
At December 31, 2005, KeySpan had a contractual receivable from LIPA of $297.4
million representing the pension and other 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:
- -------------------------------------------------------------------------------
Gross Benefit Subsidiary Receipts
(In Millions of Dollars) Payments Expected**
- -------------------------------------------------------------------------------
2006 $ 65.9 $ 3.5
2007 $ 70.6 $ 3.9
2008 $ 74.9 $ 4.3
2009 $ 79.6 $ 4.7
2010 $ 83.9 $ 5.0
Years 2011- 2015 $ 469.3 $ 28.1
- -------------------------------------------------------------------------------
** 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, 2005 and 2004, by asset category, for both the
pension and other postretirement benefit plans are as follows:
- -----------------------------------------------------------------------------
Pension OPEB
Asset Category 2005 2004 2005 2004
- -----------------------------------------------------------------------------
Equity securities 65% 64% 70% 72%
Debt securities 27% 28% 23% 23%
Cash and equivalents 3% 3% 2% -
Venture capital 5% 5% 5% 5%
- -----------------------------------------------------------------------------
Total 100% 100% 100% 100%
- -----------------------------------------------------------------------------
132
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 2006, KeySpan is expected to contribute approximately $90
million to its pension plans and approximately $30 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"). Eligible employees contributing to the Plan may receive certain
employer contributions including matching contributions and a 10% discount on
the purchase of KeySpan Common Stock in the Plan. The matching contributions
were in KeySpan's common stock until January 2006. The matching contributions as
now determined at the election of KeySpan employees. For the years ended
December 31, 2005, 2004 and 2003, we recorded an expense of $15.2 million, $14.7
million, and $11.2 million, respectively.
Note 5. Capital Stock
Common Stock: Currently we have 450,000,000 shares of authorized common stock.
At December 31, 2005, we had 10.5 million shares, or $303.9 million of treasury
stock outstanding. During 2005, we issued 1.4 million shares out of treasury for
the dividend reinvestment feature of our Investor Program, the Employee Stock
Discount Stock Purchase Plan, the 401(k) Plan and the Long-Term Incentive
Compensation Plan.
On May 16, 2005, KeySpan issued 12.1 million shares of common stock, in
association with the MEDS Equity Units conversion, at an issuance price of
$37.93 per share pursuant to the terms of the forward purchase contract. KeySpan
received proceeds of approximately $460 million from the equity conversion. The
number of shares issued was dependent 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. (See Note 6 "Long-Term Debt and Commercial Paper" for further
details on the MEDS Equity Units.)
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.
133
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 May 2005, $55.3 million of 7.07% Series B preferred stock was redeemed on its
scheduled redemption date. Additionally, also in May 2005, KeySpan called for
the optional redemption of $19.7 million of 7.17% Series C of Preferred Stock
due 2008. KeySpan no longer has preferred stock outstanding.
Note 6. Long-Term Debt And Commercial Paper
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, 2005 and 2004, each of which is guaranteed by
KeySpan.
KeySpan also had $1.96 billion of medium and long term notes outstanding at
December 31, 2004 of which $950 million of these notes were associated with the
acquisition of Eastern and ENI. These notes were issued in two series as
follows: $700 million of 7.625% Notes due 2010 and $250 million of 8.00% Notes
due 2030. The remaining debt of approximately $1 billion had interest rates
ranging from 4.65% to 9.75%.
During 2005, KeySpan redeemed $500 million 6.15% Notes due 2006 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 $20.9 million associated with call premiums and wrote-off $1.3
million of previously deferred financing costs. Further, KeySpan accelerated the
amortization of approximately $11.2 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 on the Consolidated
Statement of Income. In addition, during the first quarter of 2005, $15 million
of 8.87% notes of a KeySpan subsidiary were redeemed at maturity.
Further, in association with the MEDS Equity Units conversion, KeySpan converted
$460 million of MEDS Equity Units into $467.2 million of medium and long term
bonds. (For further details on the MEDS Equity Units see "MEDS Equity Units"
below.) As a result of the aforementioned transactions, at December 31, 2005
KeySpan had $2.4 billion of notes outstanding with interest rates ranging from
4.65% to 9.75% that mature in 2006-2035.
Gas Facilities Revenue Bonds: KEDNY can issue tax-exempt bonds through the New
York State Energy Research and Development Authority ("NYSERDA"). 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 ("GFRBs"). At
December 31, 2005, $640.5 million of GFRBs were outstanding. The interest rate
on the variable rate series due through December 1, 2026 is reset weekly and
ranged from 1.40% to 2.95% during the year ended December 31, 2005, at which
time the rate was 2.85%.
134
In November 2005, KEDNY, issued $137 million of tax-exempt GFRBs through the
NYSERDA in the following series: (i) $82 million of 4.70% GFRB, 2005 Series A
(the "Series A Bonds"); and (ii) $55 million GFRB, 2005 Series B (the "Series B
Bonds"). The interest rate on the Series B bonds is re-set every seven days
through an auction process and at December 31, 2005 the interest rate on these
bonds was 3.15%. KEDNY used the proceeds from this issuance to redeem the
following three series: (i) $41 million Adjustable Rate GFRB Series 1989 A due
February 2024; (ii) $41 million Adjustable Rate GFRB Series 1989 B due February
2024; and (iii) $55 million 5.60% GFRB Series 1993 C due June 2025. KEDNY
incurred $3.7 million in call premiums and financing fees, all of which have
been deferred for future rate recovery.
In December 2005, KEDNY converted $50 million of fixed rate GFRB's (5.64% GFRB
Series D1 and D2 due 2026) into variable rate debt. The interest rate on these
bonds is reset, through an auction process, every seven days. At December 31,
2005 the interest rate was 3.00%.
Promissory Notes to LIPA: 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, 2005, $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,
2005, 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 required us,
three years from the date of issuance of the MEDS Equity Units, May 16, 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 was 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%.
In 2005, KeySpan was required to remarket the note component of the Equity Units
between February 2005 and May 2005 and reset the interest rate to the then
current market rate of interest; however, the reset interest rate could not be
set below 4.9%. In March 2005, KeySpan remarketed the note component of $394.9
million of the Equity Units at the reset interest rate of 4.9% through their
maturity date of May 2008. The balance of the notes ($65.1 million) were held by
the original MEDS equity holders in accordance with their terms and not
remarketed. KeySpan then exchanged $300 million of the remarketed notes for
$307.2 million of new 30 year notes bearing an interest rate of 5.8%. Therefore,
KeySpan now has $160 million of 4.9% notes outstanding with a maturity date of
May 2008 and $307.2 million of 5.8% notes outstanding with a maturity date of
April 2035 that are classified as Medium and Long Term Notes.
On May 16, 2005 KeySpan issued 12.1 million shares of common stock, at an
issuance price of $37.93 per share, pursuant to the terms of the financial
purchase contract described above. KeySpan received proceeds of approximately
$460 million from the equity conversion. The number of shares issued was
dependent 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.
135
Industrial Development Revenue Bonds: At December 31, 2005 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 Energy Center an
electric-generation peaking plant. KeySpan has guaranteed all payment
obligations of these subsidiaries with regard to these bonds.
First Mortgage Bonds: Colonial Gas Company had outstanding $95.0 million of
first mortgage bonds at December 31, 2005. These bonds are secured by 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. At December 31, 2005, these bonds remain outstanding and have 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 NYSERDA. At December 31, 2005, $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 2005 ranged from 1.40%
to 2.85%, through December 31, 2005, at which time the rate was 3.00%.
We also have outstanding $24.9 million variable rate 1997 Series A Electric
Facilities Revenue Bonds due December 1, 2027. The interest rate on these bonds
is reset weekly and ranged from 1.47% to 3.42% for the year ended December 31,
2005, at which time the rate was 3.42%.
Ravenswood Master Lease: We have an arrangement with an unaffiliated variable
interest financing entity through which we lease a portion of the Ravenswood
Facility. We acquired the Ravenswood Facility, in part, through the variable
interest entity, from the Consolidated Edison Company of New York ("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 the variable interest 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
substantially equal to the fair market value of the leased assets at the
inception of the lease, less depreciation since that date, or approximately
$322.8 million. Under the terms of our 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.)
136
Commercial Paper and Revolving Credit Agreements: In June 2005, KeySpan closed
on a $920 million revolving credit facility for five years due June 24, 2010,
which was syndicated among fifteen banks, and an amended $580 million revolving
credit facility due June 24, 2009. These facilities replaced an existing $660
million, 3-year facility due June 2006, and a 5-year $640 million facility due
June 2009. The two credit facilities, which now total $1.5 billion - $920
million for five years through 2010, and $580 million for the amended facility
through 2009, will continue to support KeySpan's commercial paper program for
ongoing working capital needs.
The fees for the facilities are based on KeySpan's current credit ratings and
are increased or decreased based on a downgrading or upgrading of our ratings.
The current annual facility fee is 0.07% based on our credit rating of A3 by
Moody's Investor Services and A by Standard & Poor's for each facility. Both
credit facilities allow for KeySpan to borrow using several different types of
loans; specifically, Eurodollar loans, ABR loans, or competitively bid loans.
Eurodollar loans are based on the Eurodollar rate plus a margin that is tied to
our applicable credit ratings. ABR loans are based on the higher 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 utility 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 65% at the
last day of any fiscal quarter. Violation of these covenants 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. At
December 31, 2005, KeySpan's consolidated indebtedness was 50.7% of its
consolidated capitalization and KeySpan was in compliance with all covenants.
Subject to certain conditions set forth in the credit facility, KeySpan has the
right, at any time, to increase the commitments under the $920 million facility
up to an additional $300 million. In addition, KeySpan has the right to request
that the termination date be extended for an additional period of 365 days prior
to each anniversary of the closing date. This extension option, however,
requires the approval of lenders holding more than 50% of the total commitments
to such extension request. Under the agreements, KeySpan has the ability to
replace non-consenting lenders with other pre-approved banks or financial
institutions.
At December 31, 2005, we had cash and temporary cash investments of $124.5
million. During 2005, we repaid $254.6 million of commercial paper and, at
December 31, 2005, $657.6 million of commercial paper was outstanding at a
weighted average annualized interest rate of 4.38%. At December 31, 2005,
KeySpan had the ability to issue up to an additional $842 million, under its
commercial paper program.
137
Capital Leases: Our subsidiaries lease certain facilities and equipment under
long-term leases, which expire on various dates through 2014. The weighted
average interest rate on these obligations was 6.0%.
Debt Maturity: The following table reflects the maturity schedule for our debt
repayment requirements, including capitalized leases and related maturities, at
December 31, 2005:
- -----------------------------------------------------------------------------
- -----------------------------------------------------------------------------
Long-Term Capital
(In Millions of Dollars) Debt Leases Total
- -----------------------------------------------------------------------------
Repayments:
2006 $ 12.0 $ 1.0 $ 13.0
2007 - 1.1 1.1
2008 305.0 1.1 306.1
2009 412.3 1.2 413.5
2010 1,110.0 1.3 1,111.3
Thereafter 2,095.4 5.1 2,100.5
- -----------------------------------------------------------------------------
$ 3,934.7 $ 10.8 $ 3,945.5
- -----------------------------------------------------------------------------
Note 7. Contractual Obligations, Financial Guarantees and Contingencies
Lease Obligations: Lease costs included in operating expense were $76.5 million
in 2005 including, the lease of KeySpan's Brooklyn headquarters of $14.1million.
Further, in March 2005, KeySpan renegotiated the lease of the Brooklyn
headquarters. The original agreement was to expire in 2012. The current lease
will expire in 2025. Yearly lease expense is approximately $11.7 million. In May
2004 KeySpan entered into a leveraged lease financing arrangement associated
with the Ravenswood Expansion. The yearly operating lease expense is
approximately $17 million per year. (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, 2004 and 2003 were $67.7 million and
$82.1 million, respectively. As previously mentioned, the Master Lease is
consolidated and, as a result, lease payments are 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 $100.6 million per year
over the next five years and $652.4 million, in the aggregate, for all years
thereafter. (See discussion below for further information regarding the Master
Lease and the Ravenswood Expansion sale/leaseback transaction.)
Variable Interest Entity: As mentioned, KeySpan has an arrangement with an
unaffiliated variable interest financing 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 the variable interest 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 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, 2005 was $29.7 million.
138
The term of the Master Lease extends through June 20, 2009. On all future
semi-annual payment dates, we have the right to: (i) 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.
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
$322.8 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 $152
million over the next five years and $417 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:
On December 31, 2005, KeySpan implemented FIN 47 "Accounting for Conditional
Asset Retirement Obligations." FIN 47 was issued to clarify that the term
conditional asset obligation used in SFAS 143 "Accounting for Asset Retirement
Obligations" refers to a legal obligation to perform an asset retirement
activity in which the timing and (or) method of settlement are conditional on a
future event that may or may not be within the control of the entity.
Previously, KeySpan adopted SFAS 143 on January 1, 2003. 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.
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At December 31, the following asset retirement obligations are recorded on the
Consolidated Balance Sheet at their estimated present values:
- ---------------------------------------------------------------------------------------------------------
(In Millions of Dollars)
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December 31, 2005 2004
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Asset Retirement Obligations
Asbestos removal (i) $ 3.5 $ -
Tanks removal and cleaning (ii) 6.9 -
Main -cutting, purging and capping (iii) 30.6 -
Wells - plug and capping (iv) 0.2 -
KeySpan LNG tank demolition (v) 2.1 -
Waste water treatment pond removal (vi) 1.4 -
Fiber network removal (vii) 0.8 -
Exploration wells-plug and capping (viii) 1.9 1.9
------------------------------------------------------------------------------------------------------
Total Asset Retirement Obligations $ 47.4 $ 1.9
------------------------------------------------------------------------------------------------------
(i) Asbestos-containing materials was deemed to exist in roof flashing,
floor tiles, pipe insulation and mechanical room insulation within our
common facilities as well as in our older generation plants. KeySpan
has a legal obligation to remove asbestos upon either a major
renovation or demolition.
(ii) KeySpan has numerous storage tanks that contain among other things
waste oil, #2 and #6 fuel oil, diesel fuel, multi chemicals, lube oil,
kerosene, ammonia, and other waste contaminants. All of these tanks
are subject to cleaning and removal requirements prior to demolition
and retirement if so specified by law or regulation.
(iii) KeySpan has a legal requirement to cut (disconnect from the gas
distribution system), purge (clean of natural gas and PCB
contaminants) and cap gas mains within its gas distribution and
transmission system when mains are retired in place. Gas mains are
generally abandoned in place when retired, unless the main and other
equipment needs to be removed due to sewer or water system rerouting
or other roadblock work. When such main and equipment are removed
certain PCB test procedures must be employed.
(iv) KeySpan owns approximately 52% of an underground gas storage facility
in western New York State. The facility includes 39 gas injection and
extraction wells. There is a regulatory obligation to close and seal
the wells.
(v) KeySpan owns a 600,000 gallon barrel Liquefied Natural Gas ("LNG")
tank and ancillary facilities located in Providence, RI under a 30
year contract with New England Gas Company. At the end of the
contract, the contract can be; (i) Extended; or (ii) New England Gas
Company can require KeySpan to
140
dismantle and remove the LNG tank and ancillary facilities or; (iii)
KeySpan can elect to dismantle and remove the LNG tank and ancillary
facilities. Since we may or may not be required to dismantle and
remove the LNG tank and ancillary facilities, the obligation to
perform was discounted to a 50% probability as allowed under FIN 47.
(vi) KeySpan has several wastewater treatment ponds associated with certain
of its power stations. There are closure requirements for wastewater
treatment pond systems based on regulations promulgated by the State
of New York which were effective May 11, 2003.
(vii) KeySpan Communications has portions of its fiber optic network
(underground and above ground) that are required to be removed upon
termination of various agreements.
(viii) KeySpan has a regulatory obligation to close and seal the wells
primarily associated with its gas exploration and production
activities.
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, 2005, 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 Millions of Dollars) Exposure Dates
- -----------------------------------------------------------------------------------------------
Guarantees for Subsidiaries
Medium-Term Notes - KEDLI (i) $ 525.0 2008 - 2010
Industrial Development Revenue Bonds (ii) 128.3 2027
Ravenswood - Master Lease (iii) 425.0 2009
Ravenswood - Sale/leaseback (iv) 403.5 2019
Surety Bonds (v) 76.0 2005 - 2008
Commodity Guarantees and Other (vi) 83.2 2005 - 2009
Letters of Credit (vii) 73.0 2006 - 2010
- -----------------------------------------------------------------------------------------------
$ 1,714.0
- -----------------------------------------------------------------------------------------------
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.
141
(iii) KeySpan has guaranteed all payment and performance obligations of
KeySpan Ravenswood, LLC, the lessee under the Master Lease. The term
extends through June 20, 2009. The Master Lease is classified as
$412.3 million long-term debt on the Consolidated Balance Sheet.
(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, including
future decommissioning costs. 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 being
performed by certain current or former subsidiaries. In the event that
the subsidiaries 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. Although
KeySpan is not guaranteeing any new bonds for any of the former
subsidiaries, KeySpan's indemnity obligation supports the contractual
obligation of these former subsidiaries. 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.
At December 31, 2005, the total cost to complete such remaining bonded
projects is estimated to be approximately $40.2 million.
(vi) KeySpan has guaranteed commodity-related payments for subsidiaries
within the Energy Services segment, as well as for 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, 2005.
(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.
To date, KeySpan has not had a claim made against it for any of the
above guarantees and we have no reason to believe that our
subsidiaries or former subsidiaries will default on their current
obligations. However, we cannot predict when or if any defaults may
take place or the impact any such defaults may have on our
consolidated results of operations, financial condition or cash flows.
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Fixed Charges Under Firm Contracts: Our utility subsidiaries and the Ravenswood
Generation Station 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 $492.7 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 were named
as defendants in 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 on February 9, 2005,
also 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. On January 3, 2006, the parties entered into a
settlement agreement to settle the action for a nominal sum of $250,000 for
plaintiff's counsel fees and for KeySpan to implement certain corporate
governance practices. The settlement agreement is subject to court approval, the
timing of which cannot be predicted. While KeySpan denies any wrongdoing, we
believe the settlement is in the best interest of KeySpan and its shareholders.
KeySpan subsidiaries, along with several other parties, have been named as
defendants in numerous proceedings filed by plaintiffs claiming various degrees
of injury from asbestos exposure at generating facilities formerly owned by
LILCO and others. In connection with the May 1998 transaction with LIPA, costs
incurred by KeySpan for liabilities for asbestos exposure arising from the
activities of the generating facilities previously owned by LILCO are
recoverable from LIPA through the 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 1998 and 2006 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. KeySpan and LIPA have entered
into agreements to extend, amend, and restate these contractual arrangements.
See Note 11 "2006 LIPA Settlement" for a further discussion these agreements.
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LIPA completed its strategic review initiative that it had undertaken in
connection with among other reasons, its option under the Generation Purchase
Rights Agreement As part of its review, LIPA engaged a team of advisors and
consultants, held public hearings and explored its strategic options, including
continuing its existing operations, municipalizing, privatizing, selling some,
but not all of its assets, becoming a regulator of rates and services, or
merging with one or more utilities. Upon completion of its strategic review,
LIPA determined that it would continue its existing operations, as part of its
settlement with KeySpan and the renegotiated 2006 LIPA Agreements noted above.
The 2006 LIPA Agreements are subject to governmental approvals, and if such
governmental approvals are not received then LIPA may revisit its strategic
review alternatives.
Environmental Matters
Air: Our generating facilities are located within a Clean Air Act ("CAA") ozone
non-attainment and PM 2.5 (fine particulate matter) non-attainment area, and are
subject to Phase I, II and III NOx reduction requirements established under the
Ozone Transport Commission memorandum of understanding and forthcoming
requirements under the Clean Air Interstate Rule ("CAIR") designed to address
both ozone and particulate matter. Our previous investments in low NOx boiler
combustion modifications, the use of natural gas firing systems at our steam
electric generating stations, and the compliance flexibility available under
these cap and trade programs, have enabled KeySpan to achieve the emission
reductions required. KeySpan is developing its compliance strategy in response
to the implementation of the CAIR rule, which is expected in 2009. Since
detailed requirements under the CAIR rule have not yet been fully articulated,
it is not possible to definitively estimate capital expenditures that may be
required to meet these regulatory mandates. Although, it is anticipated that NOx
control equipment may be required at one or more of the KeySpan's Long Island
facilities at a cost between $25 to $35 million, such amounts are recoverable
from LIPA pursuant to the 1998 PSA or if applicable, the 2006 PSA.
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 and are engaged in discussions with the DEC
regarding the nature of capital upgrades or other mitigation measures necessary
to satisfy these evolving regulatory requirements. It is not possible at this
time to predict the extent of such capital investments but these upgrades are
expected to cost up to $60 million, however, such amounts are recoverable from
LIPA pursuant to the 1998 PSA or if applicable, the 2006 PSA. The Ravenswood
Generating Station may also require upgrades at a cost of up to $15 million. The
actual expenditures will depend upon the outcome of the ongoing studies and the
subsequent determination by the DEC of how 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 During 2005, KeySpan
undertook an extensive review of all its current and former properties that are
or may be subject to environmental cleanup activities. As a result of this
study, we adjusted reserve balances for estimated manufactured gas plant ("MGP")
related environmental cleanup activities. Through various rate orders issued by
the NYPSC, MADTE 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.
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New York Sites: Within the State of New York we have identified 43 historical
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 and one waterway. In March 2005, KeySpan withdrew its previously filed
applications under the DEC's Brownfield Cleanup Program ("BCP") because of the
uncertainty associated with contribution suits which we may need to bring
against other parties who impacted these sites for their share of remedial cost.
As a result of the December 2004 Cooper Industries v. Aviall Services, Inc.
decision by the United States Supreme Court and the emerging case law in New
York, KeySpan continues to evaluate how to proceed with respect to participation
in the BCP or alternative DEC remediation programs.
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 $60.9 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 $51.8 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 $355.3 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. Expenditures
incurred to date by us with respect to these MGP-related activities total $112.7
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, 2005, we have reflected a regulatory asset of $388.0
million for our KEDNY/KEDLI MGP sites. 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
145
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 $1.7 million, which amount has been
accrued by us. Expenditures incurred to date total $3.3 million.
New England Sites: Within the Commonwealth of Massachusetts and the State of New
Hampshire, we are aware of 74 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 64 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 $15.5 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 upon changing technologies and regulatory standards, selected
end use for each site, and actual environmental conditions encountered.
Expenditures incurred since November 8, 2000, the date KeySpan acquired Eastern
Enterprises, with respect to these MGP-related activities total $27.9 million.
In 2004, 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 $5.0 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 $31.5 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
upon changing technologies and regulatory standards, selected end use for each
site, and actual environmental conditions encountered. Expenditures incurred
since November 8, 2000, with respect to these MGP-related activities total $17.0
million.
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By rate orders, the MADTE and the NHPUC provide for the recovery of site
investigation and remediation costs and, accordingly, at December 31, 2005, we
have reflected a regulatory asset of $66.7 million for the KEDNE MGP sites. As
previously mentioned, Colonial Gas Company and Essex Gas Company are not subject
to the provisions of SFAS 71 and therefore have recorded no regulatory asset.
However, rate 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, 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 entered into a cost-sharing agreement under which each company
agreed to pay one-third of the costs of compliance with the consent order, while
preserving any claims 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
sought a judicial determination on the allocation of liability for the Everett
Facility. A confidential settlement agreement has been executed on favorable
terms to KeySpan and the Beazer lawsuit has been discontinued.
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. 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
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.
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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. On November 14, 2005, the trial
commenced on the declaratory judgment action of Boston Gas against Century
Indemnity for insurance coverage for the costs incurred in the investigation and
remediation at the former Boston Gas Everett MGP site and on December 6, 2005,
the jury returned a verdict in favor of KeySpan. KeySpan anticipates that
Century Indemnity will appeal this verdict. 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. On October 5, 2004, EnergyNorth's case
against the London Market Insurers for the costs incurred investigating and
remediating the former MGP site in Laconia went to trial and on October 25,
2004, the jury returned a verdict in favor of EnergyNorth, finding that
EnergyNorth was entitled to recover against London Market Insurers. The precise
amount of the recovery will depend on the allocation calculations which the
court has yet to apply to this case. We anticipate that London Market Insurers
will appeal this verdict. On February 15, 2005, the trial of EnergyNorth's
coverage action for the Dover MGP site began against the only remaining
defendant, Century Indemnity (all other carriers settled prior to trial) and at
the conclusion of the trial the federal judge directed a verdict in
EnergyNorth's favor on all issues. Century filed an appeal with the First
Circuit Court of Appeals and oral argument on Century's appeal was on January
13, 2006. A jury trial in the Nashua MGP action commenced against the London
Market Insurers and Century Indemnity on November 1, 2005 and on November 14,
2005, the jury returned a verdict in favor of KeySpan finding that London and
Century was obligated to indemnify EnergyNorth of response costs incurred at the
site. We anticipate that the carriers will appeal this verdict. 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.
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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. During 2005 our gas
distribution operations employed certain derivative instruments associated with
large-volume customers that were not subject to SFAS 71. Those derivative
financial instruments settled by year-end.
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, 2005, Seneca-Upshur has hedge positions in place for approximately
85% of its estimated 2005 through 2008 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 2008. The fair value of these derivative instruments at
December 31, 2005 was a liability of $21.8 million. The estimated amount of
losses associated with such derivative instruments that are reported in other
comprehensive income and that are expected to be reclassified into earnings over
the next twelve months is $9.2 million, or approximately $6.0 million after-tax.
Ineffectiveness associated with these outstanding derivative financial
instruments was immaterial at December 31, 2005.
The Ravenswood Generating Station uses derivative financial instruments to hedge
the cash flow variability associated with the purchase of natural gas or fuel
oil that will be consumed during the generation of electricity. The Ravenswood
Generating Station also hedges the cash flow variability associated with a
portion of electric energy sales.
With respect to price exposure associated with fuel purchases for the Ravenswood
Generating Station, KeySpan employed the use of financially-settled oil swap
contracts to hedge the cash flow variability for a portion of forecasted
purchases of fuel oil that was consumed by the Ravenswood Generating Station. We
use 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 fuel oil is through June 2006. The fair value of these
derivative instruments at December 31, 2005 was $0.3 million, which is reported
in other comprehensive income and is expected to be reclassified into earnings
within the next twelve months. Ineffectiveness associated with these outstanding
derivative financial instruments was immaterial at December 31, 2005.
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 Generating Station. Our hedging strategy is to hedge
at least 50% of forecasted on-peak summer season electric energy sales and a
149
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 August 2006. To accomplish our stated hedging strategy, KeySpan employs
financially-settled electric-power swap contracts with offsetting
financially-settled oil swap contracts and OTC natural gas swaps. We use market
quoted forward prices to value the electric-power swap contracts. The fair value
of these derivative instruments at December 31, 2005 was $9.5 million all of
which is expected to be reclassified into earnings within the next twelve
months. We use market quoted forward prices to value the oil swap contracts. The
fair value of these derivative instruments at December 31, 2005 was a liability
of $6.6 million all of which is expected to be reclassified into earnings within
the next twelve months. We use market quoted forward prices to value the gas
swap contracts. The fair value of these derivative instruments at December 31,
2005 was $0.5 million all of which is expected to be reclassified into earnings
within the next twelve months. The after-tax benefit of these derivative
instruments is anticipated to be $2.2 million. Ineffectiveness associated with
these outstanding derivative financial instruments was immaterial at December
31, 2005.
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 for the year ended December 31, 2005,
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.
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, 2005, these
derivatives had a fair value of $ 157.6 million and are reflected as a current
asset of $131.6 million and a deferred asset of $26.0 million, with offsetting
positions in regulatory liabilities and deferred credits of $146.5 million and
$11.1 million, respectively 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. 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
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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, 2005, these derivatives had a fair value of $18.4 million and
are reflected as a deferred asset of $49.2 million and a regulatory asset of
$30.9 million with offsetting positions in regulatory liabilities, current
liabilities and deferred credits of $28.9 million, $30.6 million and $20.6
million, respectively on the Consolidated Balance Sheet.
The table below summarizes the fair value of the above outstanding derivative
instruments at December 31, 2005 and 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.
- -----------------------------------------------------------------------------
(In Millions of Dollars) December 31, 2005 December 31, 2004
- -----------------------------------------------------------------------------
Gas Contracts:
Other current assets $ 132.1 $ -
Other deferred charges 75.2 21.7
Regulatory asset 30.9 20.1
Other current liability (39.8) -
Other deferred liabilities (44.3) (43.9)
Regulatory liability (175.4) (7.4)
Oil Contracts:
Other current assets 0.5 0.3
Other deferred charges - 7.5
Other current liability (6.8) -
Electric Contracts:
Other current assets 10.2 0.3
Other current liability (0.7)
- -----------------------------------------------------------------------------
$ (18.1) $ (1.4)
- -----------------------------------------------------------------------------
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. During 2004, we purchased a series of call options on the spread
between the price of heating oil and the price of natural gas to further
complement our hedging strategy regarding sales to certain large-volume
customers. As stated, these positions settled prior to year end. In addition,
the Ravenswood Generating Station sold a three year option for 30-day peaking
gas service. The 30-day peaking gas service is for the following three winter
seasons: October 2004 - March 2005, October 2005 - March 2006 and October 2006 -
March 2007. For each of these winter seasons, the counterparty can call on the
Ravenswood Generating Station to supply no more than 30,000 Mdth of a gas a day
for no more than 30 days. We recorded a $0.8 million gain in other income and
deductions on the Consolidated Statement of Income to reflect the change in the
market value associated with this derivative instrument for the twelve months
ended December 31, 2005.
Interest Rate Derivative Instruments: In January 2005, KeySpan redeemed $500
million of outstanding debt - 6.15% Notes due 2006, and accelerated the
amortization of approximately $11.2 million of previously unamortized benefits
associated with an interest rate swap on these notes that was previously
settled. The accelerated amortization was recorded as a reduction to interest
expense. (See Note 6 "Long-term Debt and Commercial Paper" for additional
details regarding the debt redemption.) There were no interest rate derivative
instruments outstanding at December 31, 2005.
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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.
In 2005, 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 2005/2006 winter heating season - November 2005 through March 2006.
These put options will pay KeySpan up to $40,000 per heating degree day when the
actual temperature is below 4,169 heating degree days, or approximately 5%
warmer than normal, based on the most recent 20-year average for normal weather.
The maximum amount KeySpan will receive on these purchased put options is $16
million. The net premium cost for these options is $1.2 million and will be
amortized over the heating season. Since weather was near normal during the
fourth quarter of 2005, there was no earnings impact associated with these
derivative instruments other than the premium cost for purchasing the options.
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.
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 would have paid KeySpan up to $40,000 per heating degree day
when the actual temperature was 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 would have received on these
purchased put options was $16 million. The net premium cost for these options
was $1.6 million and was amortized over the heating season. Since weather was
colder than normal during the first quarter of 2005, there was no earnings
impact associated with these derivative instruments other than the premium cost
for purchasing the options.
Credit and Collateral: 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. In instances where the counterparties' credit
quality has declined, or credit exposure exceeds certain levels, we may limit
our credit exposure by restricting new transactions with counterparties,
requiring additional collateral or credit support and negotiating the early
termination of certain agreements. At December 31, 2005, KeySpan has received
$13.2 million from its counterparties as collateral associated with outstanding
derivative contracts. This amount has been recorded as restricted cash, with an
offsetting position in current liabilities on the Consolidated Balance Sheet.
Further, KeySpan has paid $8.9 million in margin calls to its counterparties.
This amount has been recorded as an accounts receivable on the December 31, 2005
Consolidated Balance Sheet.
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.
152
Long-term Debt: The following tables depict the fair values and carrying values
of KeySpan's long-term debt at December 31, 2005 and 2004.
Fair Values of Long-Term Debt
- ------------------------------------------------------------------------------
December 31,
(In Millions of Dollars) 2005 2004
- ------------------------------------------------------------------------------
First Mortgage Bonds $ 114.1 $ 115.8
Notes 2,692.1 2,571.8
Gas Facilities Revenue Bonds 651.3 666.9
Authority Financing Notes 66.0 66.0
Promissory Notes 156.6 159.8
MEDS Equity Units - 480.0
Master Lease 430.5 460.9
Tax Exempt Bonds 130.8 135.0
- ------------------------------------------------------------------------------
$ 4,241.4 $ 4,656.2
- ------------------------------------------------------------------------------
Carrying Values of Long-Term Debt
- ------------------------------------------------------------------------------
December 31,
- ------------------------------------------------------------------------------
(In Millions of Dollars) 2005 2004
- ------------------------------------------------------------------------------
First Mortgage Bonds $ 95.0 $ 95.0
Notes 2,437.2 2,485.0
Gas Facilities Revenue Bonds 640.5 640.5
Authority Financing Notes 66.0 66.0
Promissory Notes 155.4 155.4
MEDS Equity Units - 460.0
Master Lease 412.3 412.3
Tax Exempt Bonds 128.3 128.3
- ------------------------------------------------------------------------------
$ 3,934.7 $ 4,442.5
- ------------------------------------------------------------------------------
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. Gas Exploration and Production Property - Depletion
As described in Note 2 "Business Segments," during much of 2004 KeySpan's
investment 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 investment in
these activities also includes its wholly-owned subsidiary Seneca-Upshur. 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 as to the
existence of proved reserves. Properties are depleted and charged to operations
using the unit of production method.
153
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. 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 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.
Note 10. Energy Services - Discontinued Operations
In 2004, the Energy Services segment experienced significantly lower operating
profits and cash flows than originally projected. 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, are 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, including approximately $5 million 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.
In June 2005, the balance to be paid over the three year period was fully
collected on a present value basis and a significant portion of the performance
bonds were replaced without any remaining indemnification obligation on the part
of KeySpan. The current estimated cost to complete projects supported by such
indemnity obligations is approximately $0.2 million. The buyers have agreed to
complete the projects for which such indemnity obligations were incurred and to
indemnify and hold KeySpan harmless with respect to its liabilities in
connection with such bonds.
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
154
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 December 31,
2005, the total cost to complete such remaining bonded projects is estimated to
be approximately $40 million. The aforementioned guarantees are reflected in
Note 7 "Contractual Obligations, Financial Guarantees and Contingencies".
KeySpan's former subsidiary has also agreed to complete the projects for which
such indemnity obligations were incurred and to indemnify and hold KeySpan
harmless with respect to its liabilities in connection with such bonds.
In anticipation of these sales and in connection with the preparation of the
third quarter and fourth quarter 2004 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, 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
$0.45 per share) was also recorded in 2004 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 to
reflect the estimated loss on disposal.
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,
(In Millions of Dollars) 2004
- -----------------------------------------------------------------------
Property $ 8.7
Current assets $ 42.9
Current liabilities $ 64.2
- -----------------------------------------------------------------------
155
- ----------------------------------------------------------------------------------------------------
For the Year Ended December 31,
(In Millions of Dollars) 2005 2004 2003
- ----------------------------------------------------------------------------------------------------
Revenues $ 33.8 $ 338.7 $ 379.6
Less:
Operating expenses 40.2 364.9 385.5
Goodwill impairment - 108.3 -
- ----------------------------------------------------------------------------------------------------
(6.4) (134.5) (5.9)
Income taxes (benefit) (2.3) (55.5) (4.0)
- ----------------------------------------------------------------------------------------------------
Operating income (loss) (4.1) (79.0) (1.9)
Gain (Loss) on disposal, net of tax 2.3 (72.0) -
- ----------------------------------------------------------------------------------------------------
Net (Loss) $ (1.8) $ (151.0) $ (1.9)
- ----------------------------------------------------------------------------------------------------
Note 11. 2006 LIPA Settlement
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, KeySpan and LIPA entered into three
major long-term service agreements that (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 "1998 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
"1998 PSA") and other long-term agreements through which we provide LIPA with
approximately one half 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 "1998 EMA"). We also purchase
energy, capacity and ancillary services in the open market on LIPA's behalf
under the 1998 EMA. The 1998 MSA, 1998 PSA and 1998 EMA all became effective on
May 28, 1998 and are collectively referred to as the 1998 LIPA Agreements.
On February 1, 2006, KeySpan and LIPA entered into (i) an amended and restated
Management Services Agreement (the "2006 MSA"), pursuant to which KeySpan will
continue to operate and maintain the electric T&D System owned by LIPA on Long
Island; (ii) a new Option and Purchase and Sale Agreement (the "2006 Option
Agreement"), to replace the Generation Purchase Rights Agreement (as amended,
the "GPRA"), pursuant to which LIPA had the option, through December 15, 2005,
to effectively acquire substantially all of the electric generating facilities
owned by KeySpan on Long Island; and (iii) a Settlement Agreement (the "2006
Settlement Agreement") resolving outstanding issues between the parties
regarding the 1998 LIPA Agreements. The 2006 MSA, the 2006 Option Agreement and
the 2006 Settlement Agreement are collectively referred to herein as the "2006
LIPA Agreements". Each of the 2006 LIPA Agreements will become effective as of
January 1, 2006 upon all of the 2006 LIPA Agreements receiving the required
governmental approvals; otherwise none of the 2006 LIPA Agreements will become
effective.
2006 Settlement Agreement
Pursuant to the terms of the 2006 Settlement Agreement, KeySpan and LIPA agreed
to resolve issues that have existed between the parties relating to the various
1998 LIPA Agreements. In addition to the resolution of these matters, KeySpan's
entitlement to utilize LILCO's available tax credits and other tax attributes
will increase from approximately $50 million to approximately $200 million.
These credits and attributes may be used to satisfy KeySpan's previously
156
incurred indemnity obligation to LIPA for any federal income tax liability that
may result from the settlement of a pending Internal revenue Service ("IRS")
audit for LILCO's tax year ended March 31, 1999. In recognition of these items,
as well as for the modification and extension of the 1998 MSA and the
elimination of the GPRA, upon effectiveness of the Settlement Agreement KeySpan
will record a contractual asset in the amount of approximately $160 million, of
which approximately $110 million will be attributed to the right to utilize such
additional tax credits and attributes and approximately $50 million will be
amortized over the eight year term of the 2006 MSA. In order to compensate LIPA
for the foregoing, KeySpan will pay LIPA $69 million in cash and will settle
certain accounts receivable in the amount of approximately $90 million due from
LIPA.
Generation Purchase Rights Agreement and 2006 Option Agreement.
Under an amended GPRA, LIPA had the right to acquire certain of KeySpan's Long
Island-based generating assets formerly owned by LILCO, at fair market value at
the time of the exercise of such right. LIPA was initially required to make a
determination by May 2005, but KeySpan and LIPA agreed to extend the date by
which LIPA was to make this determination to December 15, 2005. As part of the
2006 settlement between KeySpan and LIPA, the parties entered into the 2006
Option Agreement whereby LIPA has the option during the period January 1, 2006
to December 31, 2006 to purchase only KeySpan's Far Rockaway and/or E.F. Barrett
Generating Stations (and certain related assets) at a price equal to the net
book value of each facility. The 2006 Option Agreement replaces the GPRA, the
expiration of which has been stayed pending effectiveness of the 2006 LIPA
Agreements. In the event such agreements do not become effective by reason of
failure to secure the requisite governmental approvals, the GPRA will be
reinstated for a period of 90 days. If LIPA were to exercise the option and
purchase one or both of the generation facilities (i) LIPA and KeySpan will
enter into an operation and maintenance agreement, pursuant to which KeySpan
will continue to operate these facilities for a fixed management fee plus
reimbursement for certain costs; and (ii) the 1998 PSA and 1998 EMA will be
amended to reflect that the purchased generating facilities would no longer be
covered by those agreements. It is anticipated that the fees received pursuant
to the operation and maintenance agreement will offset the reduction in the
operation and maintenance expense recovery component of the 1998 PSA and the
reduction in fees under the 1998 EMA.
Management Services Agreements
In place of the previous compensation structure (whereby KeySpan was reimbursed
for budgeted costs, and earned a management fee and certain performance and
cost-based incentives), KeySpan's compensation for managing the T&D System under
the 2006 MSA consists of two components: a minimum compensation component of
$224 million per year and a variable component based on electric sales. The $224
million component will remain unchanged for three years and then increase
annually by 1.7%, plus inflation. The variable component, which will comprise no
more than 20% of KeySpan's compensation, is based on electric sales on Long
Island exceeding a base amount of 16,558 gigawatt hours, increasing by 1.7% in
each year. Above that level, KeySpan will receive approximately 1.34 cents per
kilowatt hour for the first contract year, 1.29 cents per kilowatt hour in the
second contract year (plus an annual inflation adjustment), 1.24 cents per
kilowatt hour in the third contract year (plus an annual inflation adjustment),
with the per kilowatt hour rate thereafter adjusted annually by inflation.
Subject to certain limitations, KeySpan will be able to retain all operational
efficiencies realized during the term of the 2006 MSA.
157
LIPA will continue to reimburse KeySpan for certain expenditures incurred in
connection with the operation and maintenance of the T&D System, and other
payments made on behalf of LIPA, including: real property and other T&D System
taxes, return postage, capital construction expenditures and storm costs.
Note 12. Subsequent Events
On February 25, 2006, Keyspan entered into an Agreement and Plan of Merger (the
"Merger Agreement"), with National Grid PLC, a public limited company
incorporated under the laws of England and Wales ("Parent") and National Grid
USA, Inc, a New York Corporation ("Merger Sub"), pursuant to which Merger Sub
will merge with and into KeySpan (the "Merger"), with KeySpan continuing as the
surviving Company. Pursuant to the Merger Agreement, at the effective time of
the Merger, each outstanding share of common stock, par value $.01 per share of
KeySpan (the "Shares"), other than shares owned by KeySpan, shall be canceled
and shall be converted into the right to receive $42.00 in cash, without
interest.
Consummation of the Merger is subject to various closing conditions, including
but not limited to the satisfaction or waiver of conditions regarding the
receipt of requisite regulatory approvals and the adoption of the Merger
Agreement by the stockholders of KeySpan and the Parent. Assuming receipt or
waiver of the foregoing, it is currently anticipated that the Merger will be
consummated in early 2007. However, no assurance can be given that the Merger
will occur, or, the timing of its completion.
Financial Swap Agreement for In-City Unforced Capacity
Currently, the NYISO's New York City local reliability rules require that 80% of
the electric capacity needs of New York City be provided by "in-City"
generators. On February 6, 2006, the NYISO Operating Committee increased the
"in-City" generator requirement to 83% beginning in May 2006 through the period
ending on April 2007, based in part on the statewide reserve margin of 118% set
by the New York State Reliability Council. On February 16, 2006, an appeal was
filed with the NYISO Management Committee requesting that the February 6th
decision be rejected and that the "in-City" requirement be increased to a larger
percentage of 83%. A vote on this appeal is expected to occur at the NYISO
Management Committee meeting scheduled for February 28, 2006.
Our Ravenswood Generating Station is an "in-City" generator. As the electric
infrastructure in New York City and the surrounding areas continues to change
and evolve and the demand for electric power increases, the "in-City" generator
requirement could be further modified. Construction of new transmission and
generation facilities may cause significant changes to the market for sales of
capacity, energy and ancillary services from our Ravenswood Generating Station.
Recently 500 MW of capacity came on line and it is anticipated that another
500MW of new capacity may be available during 2006 as a result of the completion
of an in-City generation project currently under construction. We can not,
however, be certain as to when the new power plant will be in operation or the
nature of future New York City energy, capacity or ancillary services market
requirements or design.
Notwithstanding the foregoing, KeySpan continues to believe that New York City
represents a strong capacity market and has entered into an International SWAP
Dealers Association Master Agreement for a fixed for float unforced capacity
financial swap (the "Agreement") with Morgan Stanley Capital Group Inc. ("Morgan
Stanley") dated as of January 18, 2006. The Agreement has a three year term
beginning May 1, 2006, (assuming a condition to effectiveness has been satisfied
by such date). The notional quantity is 1,800,000kW (the "Notional Quantity") of
In-City Unforced Capacity and the fixed price is $7.57/kW-month ("Fixed Price"),
subject to adjustment upon the occurrence of certain events. Cash settlement
will occur on a monthly basis based on the In-City Unforced Capacity price
determined by the relevant New York Independent System Operator Spot Demand
Curve Auction Market ("Floating Price"). For each monthly settlement period, the
price difference will equal the Fixed Price minus the Floating Price. If such
price difference is less than zero, Morgan Stanley will pay KeySpan an amount
equal to the product of (a) the Notional Quantity and (b) the absolute value of
such price difference. Conversely, if such price difference is greater than
zero, KeySpan will pay Morgan Stanley an amount equal to the product of (a) the
Notional Quantity and (b) the absolute value of such price difference. KeySpan
believes that the average annual monthly capacity market price will settle above
the Fixed Price. This derivative instrument will not qualify for hedge
accounting treatment under SFAS 133 and will be subject to mark-to-market
accounting treatment.
158
Note 13. KeySpan Gas East Corporation Summary Financial Data
KEDLI is a wholly owned subsidiary of KeySpan. KEDLI was formed on May 7, 1998
and on May 28, 1998 acquired substantially all of the assets related to the gas
distribution business of LILCO. KEDLI provides gas distribution services to
customers in the Long Island counties of Nassau and Suffolk and the Rockaway
peninsula of Queens county. KEDLI established a program for the issuance, from
time to time, of up to $600 million aggregate principal amount of Medium-Term
Notes, which will be fully and unconditionally guaranteed by 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.
- -----------------------------------------------------------------------------------------------------------------------------------
Statement of Income
- -----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2005
(In Millions of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- -----------------------------------------------------------------------------------------------------------------------------------
Revenues $ 0.6 $ 1,432.9 $ 6,229.1 $ (0.6) $ 7,662.0
---------------------------------------------------------------------------------------
Operating Expenses
Purchased gas - 963.0 2,634.3 - 3,597.3
Fuel and purchased power - - 752.1 - 752.1
Operations and maintenance 22.0 133.5 1,462.4 - 1,617.9
Intercompany expense - 4.8 (4.2) (0.6) -
Depreciation and amortization - 76.9 319.7 - 396.6
Operating taxes 0.1 65.9 341.0 - 407.0
---------------------------------------------------------------------------------------
Total Operating Expenses 22.1 1,244.1 5,505.3 (0.6) 6,770.9
---------------------------------------------------------------------------------------
Gain on sale of property - - 1.6 - 1.6
Income from equity investments - - 15.1 - 15.1
---------------------------------------------------------------------------------------
Operating Income (Loss) (21.5) 188.8 740.5 - 907.8
---------------------------------------------------------------------------------------
Interest charges (144.5) (61.9) (83.9) 21.0 (269.3)
Other income and (deductions) 523.8 2.9 (81.3) (446.0) (0.6)
---------------------------------------------------------------------------------------
Total Other Income and (Deductions) 379.3 (59.0) (165.2) (425.0) (269.9)
---------------------------------------------------------------------------------------
Income Taxes (Benefit) (32.4) 48.2 223.5 - 239.3
---------------------------------------------------------------------------------------
Earnings from Continuing Operations 390.2 81.6 351.8 (425.0) 398.6
Discontinued Operations - - (1.8) - (1.8)
Culmulative Change in Accounting Principal - (0.2) (6.4) - (6.6)
---------------------------------------------------------------------------------------
Net Income $ 390.2 $ 81.4 $ 343.6 $ (425.0) $ 390.2
=======================================================================================
159
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Income
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2004
(In Millions of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Revenues $ 0.6 $ 1,124.4 $ 5,526.1 $ (0.6) $ 6,650.5
----------------------------------------------------------------------------------------------
Operating Expenses
Purchased gas - 664.9 1,999.6 - 2,664.5
Fuel and purchased power - - 540.3 - 540.3
Operations and maintenance 5.3 137.8 1,423.9 - 1,567.0
Intercompany expense - 5.4 (5.4) - -
Depreciation and amortization - 79.9 471.9 - 551.8
Operating taxes - 65.7 338.4 - 404.1
Goodwill Impairment - - 41.0 - 41.0
----------------------------------------------------------------------------------------------
Total Operating Expenses 5.3 953.7 4,809.7 - 5,768.7
----------------------------------------------------------------------------------------------
Gain on sale of property - - 7.0 - 7.0
Income from equity investments - - 46.5 - 46.5
----------------------------------------------------------------------------------------------
Operating Income (Loss) (4.7) 170.7 769.9 (0.6) 935.3
----------------------------------------------------------------------------------------------
Interest charges (204.5) (61.5) (267.7) 202.4 (331.3)
Other income and (deductions) 635.4 0.8 423.9 (723.9) 336.2
----------------------------------------------------------------------------------------------
Total Other Income and (Deductions) 430.9 (60.7) 156.2 (521.5) 4.9
----------------------------------------------------------------------------------------------
Income Taxes (Benefit) (45.5) 35.8 335.2 - 325.5
----------------------------------------------------------------------------------------------
Earnings from Continuing Operations 471.7 74.2 590.9 (522.1) 614.7
Discontinued Operations - - (151.0) - (151.0)
----------------------------------------------------------------------------------------------
Net Income $ 471.7 $ 74.2 $ 439.9 $ (522.1) $ 463.7
==============================================================================================
- -----------------------------------------------------------------------------------------------------------------------------------
Statement of Income
- -----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2003
(In Millions of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- -----------------------------------------------------------------------------------------------------------------------------------
Revenues $ 0.5 $ 1,046.9 $ 5,488.6 $ (0.5) $ 6,535.5
---------------------------------------------------------------------------------------------
Operating Expenses
Purchased gas - 574.0 1,921.1 - 2,495.1
Fuel and purchased power - - 414.6 - 414.6
Operations and maintenance 11.3 137.2 1,474.1 - 1,622.6
Intercompany expense 5.3 3.6 (3.6) (5.3) -
Depreciation and amortization - 77.6 494.1 - 571.7
Operating taxes - 77.5 340.7 - 418.2
---------------------------------------------------------------------------------------------
Total Operating Expenses 16.6 869.9 4,641.0 (5.3) 5,522.2
---------------------------------------------------------------------------------------------
Gain on sale of property - 14.0 1.1 - 15.1
Income from equity investments 0.1 - 19.1 - 19.2
---------------------------------------------------------------------------------------------
Operating Income (Loss) (16.0) 191.0 867.8 4.8 1,047.6
---------------------------------------------------------------------------------------------
Interest charges (209.5) (63.0) (299.4) 264.2 (307.7)
Other income and (deductions) 621.1 (8.6) 54.3 (699.4) (32.6)
---------------------------------------------------------------------------------------------
Total Other Income and (Deductions) 411.6 (71.6) (245.1) (435.2) (340.3)
---------------------------------------------------------------------------------------------
Income Taxes (Benefit) (28.7) 40.8 269.2 - 281.3
---------------------------------------------------------------------------------------------
Earnings from Continuing Operations 424.3 78.6 353.5 (430.4) 426.0
Discontinued Operations - - (1.9) - (1.9)
Cumulative Change in Accounting
Principle - - (37.4) - (37.4)
---------------------------------------------------------------------------------------------
Net Income $ 424.3 $ 78.6 $ 314.2 $ (430.4) $ 386.7
=============================================================================================
160
- ------------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
- ------------------------------------------------------------------------------------------------------------------------------------
December 31, 2005
(In Millions of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash and temporary cash investments $ 79.6 $ 3.5 $ 41.4 $ 124.5
Accounts receivable, net 0.6 149.9 822.2 972.7
Other current assets 4.0 368.9 1,550.0 1,922.9
-------------------------------------------------------------------------------------
84.2 522.3 2,413.6 - 3,020.1
-------------------------------------------------------------------------------------
Investments and Other 4,571.0 0.7 128.2 (4,457.5) 242.4
Property -------------------------------------------------------------------------------------
Gas - - 7,275.9 7,275.9
Other - 2,111.3 981.5 3,092.8
Accumulated depreciation and depletion - (400.6) (2,631.2) (3,031.8)
Property of discontinued operations - - - -
-------------------------------------------------------------------------------------
- 1,710.7 5,626.2 - 7,336.9
-------------------------------------------------------------------------------------
Intercompany Accounts Receivable 2,813.6 44.6 95.6 (2,953.8) -
Deferred Charges 482.5 316.1 2,414.6 3,213.2
-------------------------------------------------------------------------------------
Total Assets $ 7,951.3 $ 2,594.4 $ 10,678.2 $ (7,411.3) $ 13,812.6
=====================================================================================
LIABILITIES AND CAPITALIZATION
Current Liabilities
Accounts payable $ 36.4 $ 149.7 $ 900.9 $ 1,087.0
Commercial paper 657.6 - - 657.6
Other current liabilities 196.2 128.5 85.9 410.6
-------------------------------------------------------------------------------------
890.2 278.2 986.8 - 2,155.2
-------------------------------------------------------------------------------------
Intercompany Accounts Payable 51.8 338.3 1,049.8 (1,439.9) -
-------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax 27.2 330.6 800.1 1,157.9
Other deferred credits and liabilities 634.0 225.3 1,240.0 2,099.3
-------------------------------------------------------------------------------------
661.2 555.9 2,040.1 - 3,257.2
-------------------------------------------------------------------------------------
Capitalization
Common shareholders' equity 4,485.4 897.0 3,539.3 (4,457.6) 4,464.1
Long-term debt 1,862.7 525.0 3,046.9 (1,513.8) 3,920.8
-------------------------------------------------------------------------------------
Total Capitalization 6,348.1 1,422.0 6,586.2 (5,971.4) 8,384.9
-------------------------------------------------------------------------------------
Minority Interest in Consolidated Companies 15.3 15.3
-------------------------------------------------------------------------------------
Total Liabilities and Capitalization $ 7,951.3 $ 2,594.4 $ 10,678.2 $ (7,411.3) $ 13,812.6
=====================================================================================
- ----------------------------------------------------------------------------------------------------------------------------------
161
- -----------------------------------------------------------------------------------------------------------------------------------
Balance Sheet
- -----------------------------------------------------------------------------------------------------------------------------------
December 31, 2004
(In Millions of Dollars) Guarantor KEDLI Other Subsidiaries Eliminations Consolidated
- -----------------------------------------------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash and temporary cash investments $ 580.7 $ (0.9) $ 342.2 $ - $ 922.0
Accounts receivable, net 0.8 223.6 1,087.6 - 1,312.0
Other current assets 4.5 146.5 650.7 - 801.7
Assets of discontinued operations - - 42.9 42.9
----------------------------------------------------------------------------------
586.0 369.2 2,123.4 - 3,078.6
----------------------------------------------------------------------------------
Investments and Other 4,567.3 2.0 169.1 (4,465.5) 272.9
----------------------------------------------------------------------------------
Property
Gas - 1,998.5 4,872.7 - 6,871.2
Other - - 2,987.8 - 2,987.8
Accumulated depreciation and depletion - (334.5) (2,465.3) - (2,799.8)
Property of discontinued operations - - 8.7 8.7
----------------------------------------------------------------------------------
- 1,664.0 5,403.9 - 7,067.9
----------------------------------------------------------------------------------
Intercompany Accounts Receivable 2,485.7 - 1,292.2 (3,777.9) -
Deferred Charges 381.3 221.4 2,342.0 - 2,944.7
----------------------------------------------------------------------------------
Total Assets $ 8,020.3 $ 2,256.6 $ 11,330.6 $ (8,243.4) $ 13,364.1
==================================================================================
LIABILITIES AND CAPITALIZATION
Current Liabilities
Accounts payable $ 48.4 $ 111.5 $ 746.7 $ - $ 906.6
Commercial paper 912.2 - - - 912.2
Other current liabilities 294.7 167.2 (62.6) - 399.3
Liabilities of discontinued operations - - 64.2 64.2
----------------------------------------------------------------------------------
1,255.3 278.7 748.3 - 2,282.3
----------------------------------------------------------------------------------
Intercompany Accounts Payable - 101.3 2,147.8 (2,249.1) -
----------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income tax (83.2) 298.1 909.2 - 1,124.1
Other deferred credits and liabilities 534.5 112.0 964.4 - 1,610.9
----------------------------------------------------------------------------------
451.3 410.1 1,873.6 - 2,735.0
----------------------------------------------------------------------------------
Capitalization
Common shareholders' equity 3,940.5 815.6 3,604.2 (4,465.5) 3,894.8
Preferred stock 19.7 - - - 19.7
Long-term debt 2,353.5 650.9 2,943.1 (1,528.8) 4,418.7
----------------------------------------------------------------------------------
Total Capitalization 6,313.7 1,466.5 6,547.3 (5,994.3) 8,333.2
----------------------------------------------------------------------------------
Minority Interest in Consolidated Companies - - 13.6 - 13.6
----------------------------------------------------------------------------------
Total Liabilities and Capitalization $ 8,020.3 $ 2,256.6 $ 11,330.6 $ (8,243.4) $ 13,364.1
==================================================================================
- -----------------------------------------------------------------------------------------------------------------------------------
162
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2005
------------------------------------------------------------------
(In Millions of Dollars) Guarantor KEDLI Other Subsidiaries Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net Cash (Used in) Provided by Continuing Operating Activities $ (327.7) $ 168.5 $ 562.5 $ 403.3
------------------------------------------------------------------
Investing Activities
Capital expenditures - (113.3) (426.2) (539.5)
Cost of removal - (2.6) (25.2) (27.8)
Proceeds from sale of property and investments - (2.1) 49.1 47.0
Derivative margin call - - (8.9) (8.9)
------------------------------------------------------------------
Net Cash (Used in) Provided by Continuing Investing Activities - (118.0) (411.2) (529.2)
------------------------------------------------------------------
Financing Activities
Treasury stock issued 41.2 - - 41.2
Common stock issued associated with MEDS conversion 460.0 - - 460.0
Issuance (payment) of debt, net (754.6) - (15.0) (769.6)
Redemption of preferred stock (75.0) - - (75.0)
Common and preferred stock dividends paid (308.4) - - (308.4)
Dividend paid to parent 375.0 - (375.0) -
Other (1.6) - (3.8) (5.4)
Net intercompany accounts 90.0 (46.1) (43.9) -
------------------------------------------------------------------
Net Cash Provided by (Used in) Continuing Financing Activities (173.4) (46.1) (437.7) (657.2)
------------------------------------------------------------------
Net Increase in Cash and Cash Equivalents $ (501.1) $ 4.4 $ (286.4) $(783.1)
Net Cash Flow from Discontinued Operations - - (14.4) (14.4)
Cash and Cash Equivalents at Beginning of Period 580.7 (0.9) 342.2 922.0
------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 79.6 $ 3.5 $ 41.4 $ 124.5
==================================================================
- ------------------------------------------------------------------------------------------------------------------------------------
163
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2004
---------------------------------------------------------------------------
(In Millions of Dollars) Guarantor KEDLI Other Subsidiaries Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net Cash (Used in) Provided by Operating Activities $ (88.7) $ 169.5 $ 669.3 $ 750.1
---------------------------------------------------------------------------
Investing Activities
Capital expenditures - (108.7) (641.6) (750.3)
Cost of removal - (7.1) (29.2) (36.3)
Proceeds from sale of property and investments - - 1,021.3 1,021.3
---------------------------------------------------------------------------
Net Cash (Used in) Provided by Investing Activities - (115.8) 350.5 234.7
---------------------------------------------------------------------------
Financing Activities
Treasury stock issued 33.4 - - 33.4
Issuance (payment) of debt, net (269.7) - (170.7) (440.4)
Redemption of preferred stock (8.5) - - (8.5)
Net proceeds from sale/leaseback transaction - - 382.0 382.0
Common and preferred stock dividends paid (291.1) - - (291.1)
Gain on interest rate swap 12.7 - - 12.7
Dividend paid to parent 447.6 (40.0) (407.6) -
Other 27.6 - 8.5 36.1
Net intercompany accounts 619.8 (16.2) (603.6) -
---------------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities 571.8 (56.2) (791.4) (275.8)
---------------------------------------------------------------------------
Net Increase in Cash and Cash Equivalents $ 483.1 $ (2.5) $ 228.4 $ 709.0
Net Cash Flow from Discontinued Operations - - 9.6 9.6
Cash and Cash Equivalents at Beginning of Period 97.6 1.6 104.2 203.4
---------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 580.7 $ (0.9) $ 342.2 $ 922.0
===========================================================================
- ------------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------------
Statement of Cash Flows
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2003
------------------------------------------------------------------------
(In Millions of Dollars) Guarantor KEDLI Other Subsidiaries Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net Cash (Used in) Provided by Operating Activities $ (547.5) $ 164.5 $ 1,606.4 $ 1,223.4
------------------------------------------------------------------------
Investing Activities
Capital expenditures - (130.3) (879.1) (1,009.4)
Cost of removal - (1.7) (29.4) (31.1)
Proceeds from the sale of property and subsidiary stock - 15.1 294.6 309.7
Investments in subsidiaries - - (211.3) (211.3)
Issuance of note receiveable (55.0) - - (55.0)
------------------------------------------------------------------------
Net Cash (Used in) Investing Activities (55.0) (116.9) (825.2) (997.1)
------------------------------------------------------------------------
Financing Activities
Proceeds from equity issuance 473.6 - - 473.6
Treasury stock issued 96.7 - - 96.7
Redemption of LIPA promissory notes (447.0) - (447.0)
(Payment) issuance of debt, net (133.8) - 110.2 (23.6)
Redemption of preferred stock - - (14.3) (14.3)
Common and preferred stock dividends paid (280.6) - - (280.6)
Other 28.9 - (13.9) 15.0
Net intercompany accounts 874.0 (52.6) (821.4) -
-
------------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities 611.8 (52.6) (739.4) (180.2)
------------------------------------------------------------------------
Net (Decrease) Increase in Cash and Cash Equivalents $ 9.3 $ (5.0) $ 41.8 $ 46.1
Net Cash from Discontinued Operations - - (13.3) (13.3)
Cash and Cash Equivalents at Beginning of Period 88.3 6.5 75.8 170.6
------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 97.6 $ 1.5 $ 104.3 $ 203.4
========================================================================
- ------------------------------------------------------------------------------------------------------------------------------------
164
Note 14. Supplemental Gas and Oil Disclosures (Unaudited)
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. Gas and oil operations, and reserves,
were located in the United States in 2003. 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 2005 or 2004.
Capitalized Costs Relating to Gas and Oil Producing Activities
- -----------------------------------------------------------------------------------------
(In Millions of Dollars)
- ----------------------------------------------------------------------------------------
At December 31, 2003
- ----------------------------------------------------------------------------------------
Unproved properties not being amortized $ 142.9
Properties being amortized - productive and nonproductive 2,429.9
- ----------------------------------------------------------------------------------------
Total capitalized costs 2,572.8
Accumulated depletion (1,159.5)
- ----------------------------------------------------------------------------------------
Net capitalized costs $1,413.3
- ----------------------------------------------------------------------------------------
Costs Incurred in Property Acquisition, Exploration and Development Activities
- -----------------------------------------------------------------------------
(In Millions of Dollars)
- -----------------------------------------------------------------------------
At December 31, 2003
- -----------------------------------------------------------------------------
Acquisition of properties -
Unproved properties $ 61.5
Proved properties 171.3
Exploration 66.3
Development 170.5
Asset retirement obligation 31.8
- ------------------------------------------------------------------------
Total costs incurred $ 501.4
- ------------------------------------------------------------------------
Costs included in development costs to develop proved undeveloped reserves for
the year ended December 31, 2003 were $49.4 million.
Results of Operations from Gas and Oil Producing Activities*
- ------------------------------------------------------------------------------
(In Millions of Dollars)
- ------------------------------------------------------------------------------
At December 31, 2003
- ------------------------------------------------------------------------------
Revenues $ 497.9
- ------------------------------------------------------------------------------
Production and lifting costs 63.6
Shipping and handling costs 10.4
Depletion 205.1
- ------------------------------------------------------------------------------
Total expenses 279.1
- ------------------------------------------------------------------------------
Income before taxes 218.8
Income taxes 76.6
- ------------------------------------------------------------------------------
Results of operations $ 142.2
- ------------------------------------------------------------------------------
* (Excluding corporate overhead and interest costs)
165
Summary of Production and Lifting Costs
- ---------------------------------------------------------------------------
(In Millions of Dollars)
- ---------------------------------------------------------------------------
At December 31, 2003
- ---------------------------------------------------------------------------
Pumping, gauging and other labor $ 11.0
Compressors and other rental equipment 5.1
Property taxes and insurance 7.2
Transportation 2.3
Processing fees 2.4
Workover and well stimulation 5.2
Repairs, maintenance and supplies 3.7
Fuel and chemicals 3.1
Environmental, regulatory and other 7.6
Severance taxes 16.0
- ---------------------------------------------------------------------------
Total production and lifting costs $ 63.6
- ---------------------------------------------------------------------------
For December 31, 2003 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
- ----------------------------------------------------------------
Proved Reserves
Beginning of year 614,734
Revisions of previous estimates (32,433)
Extensions and discoveries 140,632
Production (100,130)
Purchases of reserves in place 89,380
- ----------------------------------------------------------------
Proved reserves - End of year (1) 712,183
Proved developed reserves
Beginning of year 435,629
End of Year (2) 488,012
- ----------------------------------------------------------------
(1) Includes minority interest of 318,417.
(2) Includes minority interest of 218,190.
166
Crude Oil, Condensate and Natural Gas Liquids (MBbls)
- ------------------------------------------------------------------
At December 31, 2003
- ------------------------------------------------------------------
Proved reserves
Beginning of Year 9,548
Revisions of previous estimates (3,542)
Extension and discoveries 117
Production (1,514)
Purchases of reserves in place 3,753
- ------------------------------------------------------------------
Proved reserves - End of year (1) 8,362
Proved developed reserves
Beginning of year 2,413
End of year (2) 4,273
- ------------------------------------------------------------------
(1) Includes minority interest of 3,739.
(2) Includes minority interest of 1,910.
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. 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 Millions of Dollars)
- ---------------------------------------------------------------------------------------
At December 31, 2003
- ---------------------------------------------------------------------------------------
Future cash flows $ 4,375.8
Future costs-
Production (769.9)
Development (378.6)
- ---------------------------------------------------------------------------------------
Future net inflows before income tax 3,227.3
Future income taxes (853.4)
- ---------------------------------------------------------------------------------------
Future net cash flows 2,373.9
10% discount factor (853.4)
- ---------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows (1) $ 1,520.5
- ---------------------------------------------------------------------------------------
(1) Includes minority interest of $672,620.
167
Changes in Standardized Measure of Discounted Future Net
Cash Flows from Proved Reserve Quantities
- -------------------------------------------------------------------------------
(In Millions of Dollars)
- -------------------------------------------------------------------------------
At December 31, 2003
- -------------------------------------------------------------------------------
Standardized measure - beginning of year $ 1,103.9
Sales and transfers, net of production costs (492.3)
Net change in sales and transfer prices, net
of production costs 384.3
Extensions and discoveries and improved
recovery, net of related costs 434.3
Changes in estimated future development costs (9.4)
Development costs incurred during the period
that reduced future development costs 81.0
Revisions of quantity estimates (123.9)
Accretion of discount 142.3
Net change in income taxes (236.5)
Net purchases of reserves in place 254.0
Sales of reserves in place -
Changes in production rates (timing) and other (17.2)
- -------------------------------------------------------------------------------
Standardized measure - end of year $ 1,520.5
- -------------------------------------------------------------------------------
Average Sales Prices and Production Costs Per Unit
- -------------------------------------------------------------------------
Year Ended December 31, 2003
- -------------------------------------------------------------------------
Average Sales Price*
Natural gas ($/Mcf) 5.23
Oil, condensate and natural gas liquid ($/Bbl) 28.26
Production cost per equivalent Mcf ($) 0.58
- -------------------------------------------------------------------------
*Represents the cash price received which excludes the effect of any hedging
transactions.
Note 15. Summary of Quarterly Information (Unaudited)
The following is a table of financial data for each quarter of KeySpan's year
ended December 31, 2005.
Quarter Ended
- --------------------------------------------------------------------------------------------------------------------------------
(In Millions of Dollars, Except Per Share Amounts) 3/31/2005 6/30/2005 9/30/2005 12/31/2005
- --------------------------------------------------------------------------------------------------------------------------------
Operating Revenue 2,480.5 1,342.5 1,303.1 2,535.9
Operating Income 438.7 103.2 102.8 263.1
Earnings (loss) from continuing operations,
less preferred stock dividends 234.4 18.0 22.6 121.4
Cumulative change in accounting principles, net of tax - - - (6.6) (a)
Earnings (loss) from discontinued operations - (1.8) - -
Earnings (loss) for common stock 234.4 16.2 22.6 114.8
Basic earnings per common share from continuing operations
less preferred stock dividends 1.45 0.11 0.13 0.70
Basic earnings per common share from discontinued operations - (0.01) - -
Basic earnings per common share from cumulative change in accounting
principles - - - (0.04) (a)
Basic earnings per common share 1.45 0.10 0.13 0.66
Diluted earnings per common share 1.44 0.09 0.13 0.65
Dividends declared 0.455 0.455 0.455 0.455
- --------------------------------------------------------------------------------------------------------------------------------
(a) Cumulative change in accounting principles for implementation of FASB
Interpretation No. 47 ("FIN 47") "Accounting for Conditional Asset
Retirement Obligations."
168
The following is a table of financial data for each quarter of KeySpan's year
ended December 31, 2004.
Quarter Ended
- ---------------------------------------------------------------------------------------------------------------------------------
(In Millions of Dollars, Except Per Share Amounts) 3/31/2004 6/30/2004 9/30/2004 12/31/2004
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Revenue 2,510.6 1,277.8 975.6 1,886.5
Operating Income 487.6 122.2 (a) 87.6 (c) 237.9 (e)
Earnings (loss) from continuing operations,
less preferred stock dividends 246.6 128.5 (a)(b) (30.1) (c)(d) 264.1 (e)(f)
Earnings (loss) from discontinued operations (g) (0.4) 0.8 (87.0) (64.4)
Earnings (loss) for common stock 246.2 129.3 (117.1) 199.7
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 - - (0.54) (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 in Houston Exploration and 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 and 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 $151.0 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 $11.1 million.
169
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, 2005 and 2004, 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, 2005. Our audits also
included the financial statement schedules listed in the Index at Item 15. These
financial statements and financial statement schedules are the responsibility of
the Company's management. Our responsibility is to express an opinion on the
financial statements and financial statement schedules 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, 2005 and 2004, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2005, in conformity with accounting principles generally accepted
in the United States of America. Also, in our opinion, such financial statement
schedules, when considered in relation to the basic consolidated financial
statements taken as a whole, present fairly, in all material respects, the
information set forth therein.
As discussed in Note 1(P) to the consolidated financial statements, on December
31, 2003, the Company adopted Financial Accounting Standards Board
Interpretation No. ("FIN") 46 "Consolidation of Variable Interest Entities, an
Interpretation of ARB No. 51". As discussed in Notes 1(O), 1(P) and 7, on
December 31, 2005, the Company adopted FIN 47, "Accounting for Conditional Asset
Retirement Obligations, an interpretation of FASB Statement No. 143."
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, 2005, 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, 2006 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
- ------------------------
New York, New York
February 28, 2006
170
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, 2005. 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.
171
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, 2005. 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, 2005, 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, 2005, which is included herein.
172
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, 2005, 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.
173
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, 2005, 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, 2005, 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 schedules as of and for the year ended
December 31, 2005 of the Company and our report dated February 28, 2006
expressed an unqualified opinion on those financial statements and financial
statement schedules and included an explanatory paragraph regarding the adoption
of Financial Accounting Standards Board Interpretation No. 47, "Accounting for
Conditional Asset Retirement Obligations, an interpretation of FASB Statement
No. 143", referred to in Notes 1(O), 1 (P) and 7.
/s/Deloitte & Touche LLP
- ------------------------
New York, New York
February 28, 2006
174
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 23, 2006, following the recommendation of the Compensation and
Management Development Committee (the "Compensation Committee"), KeySpan's Board
of Directors set the 2006 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 2006 base salaries are as
follows: Mr. Catell - $1,140,000, Mr. Fani - $782,000, Mr. Parker - $625,000,
Mr. Zelkowitz - $625,000, and Mr. Luterman - $488,000. All 2006 base salary
increases are effective January 1, 2006, with the exception of Mr. Luterman. Mr.
Luterman's base salary increase is effective February 1, 2006.
Also on February 23, 2006, following the recommendation of the Compensation
Committee, the Board approved the performance-based incentive awards to be paid
to our executive officers for the year ending December 31, 2005 ("FY 2005")
under the KeySpan Corporate Annual Incentive Compensation Plan (the "Corporate
Plan"). The Corporate Plans provides for performance-based incentive awards as a
percentage of cumulative base salary paid during the calendar year. The
Compensation Committee had approved the target performance award levels
applicable to the Corporate Plan for FY 2005 in December 2004. In January 2005,
the Compensation Committee approved the performance goals relating to the FY
2005 Corporate Plan for the named executive officers based on financial and
performance measures, including goals relating to earnings per share, cash flow,
business unit operating income, diversity initiatives, customer satisfaction,
work place safety and other individual strategic goals and initiatives. Based
upon actual FY 2005 performance, an award payout for each of the named executive
officers was approved as follows: Mr. Catell - $1,400,000, Mr. Fani - $741,175,
Mr. Parker - $550,090, Mr. Zelkowitz - $513,129, and Mr. Luterman - $388,282.
In December 2005, the Board approved the compensation formulas for incentive
awards that may be paid to our executive officers for the year ending December
31, 2006 ("FY 2006") under the Corporate Plan. For FY 2006, the
performance-based target award levels for each of the named executive officers
will remain the same as last year. The target performance award levels are as
follows: Mr. Catell - 100%, Mr. Fani - 75%, Mr. Parker - 70%, Mr. Zelkowitz -
70% and Mr. Luterman - 65%.
Also in December 2005, the Compensation Committee approved the target award
levels for performance-based equity awards that may be granted to our executive
officers for FY 2006 under the KeySpan Long-Term Performance Incentive
Compensation Plan (the "Long-Term Incentive Plan"). The target award levels have
been modified from last year. The target award levels are designed to align with
industry benchmarks at 50th percentile levels. The FY 2006 target performance
award levels for the named executive officers are as follows: Mr. Catell - 240%,
Mr. Fani - 160%, Mr. Parker - 125%, Mr. Zelkowitz - 125% and Mr. Luterman -
110%.
175
On February 23, 2006, the Compensation Committee also approved the FY 2006
grants pursuant to the Long Term Incentive Plan. The Compensation Committee
awarded the following grants to the named executive officers based on actual
2005 performance as follows: Mr. Catell - 85,520 shares of restricted stock; Mr.
Fani - 38,930 performance shares; Mr. Parker - 24,320 performance shares; Mr.
Zelkowitz - 27,490 performance shares; and Mr. Luterman - 18,360 performance
shares.
Mr. Catell's restricted stock has a two year restriction period which shall
lapse on February 23, 2008 or the Compensation Committee has the ability to
accelerate vesting after one year based on certain goals being achieved. The
performance shares for the remaining four named executives will be measured over
the three year period beginning on January 1, 2006 through December 31, 2008,
with performance results linked to the percentage of improvement in Return on
Invested Capital ("ROIC") and Total Shareholder Return ("TSR"). The actual
number of shares to be awarded at the end of the performance period will be
determined using a sliding scale which encompasses both the ROIC and TSR
measures. The ROIC goal will act as the primary trigger. If the ROIC goal is
below threshold, all shares will be forfeited without payment regardless of the
performance of TSR.
For further information on executive compensation see "Item 11. Executive
Compensation" herein.
176
PART III
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ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
A definitive proxy statement will be filed with the SEC on or about March XXX,
2006 (the "Proxy Statement"). The information required by this item is set forth
under the caption "Executive Officers of KeySpan" 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) Beneficial Ownership Reporting Compliance" contained in the Proxy
Statement, which information is incorporated herein by reference thereto.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is set forth under the captions "Director
Compensation" and "Executive Compensation" in the Proxy Statement, which
information is incorporated herein by reference thereto.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
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 2006 Audit Firm Fee Summary" and "Report of the
Audit Committee" in the Proxy Statement, which information is incorporated
herein by reference thereto.
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:
177
o Consolidated Statement of Income for the year ended December 31, 2005, the
year ended December 31, 2004, and the year ended December 31, 2003
o Consolidated Statement of Retained Earnings for the year ended December 31,
2005, the year ended December 31, 2004, and the year ended December 31,
2003
o Consolidated Balance Sheet at December 31, 2005 and December 31, 2004
o Consolidated Statement of Capitalization at December 31, 2005 and December
31, 2004
o Consolidated Statement of Cash Flows for the year ended December 31, 2005,
the year ended December 31, 2004, and the year ended December 31, 2003
o Consolidated Statement of Comprehensive Income for the Year ended December
31, 2005, the year ended December 31, 2004 and the year ended December 31,
2003
o Notes to Consolidated Financial Statements
o Report of the Independent Registered Public Accounting Firm
178
2. Financial Statement Schedules
Consolidated Schedule of Valuation and Qualifying Accounts for the year ended
December 31, 2005, the year ended December 31, 2004, and the year ended December
31, 2003.
- -----------------------------------------------------------------------------------------------------------------------------
Balance at Charged to Balance at
Beginning of costs and Net End of
Descriptions Period expenses Deductions Period
- -----------------------------------------------------------------------------------------------------------------------------
(In Millions of Dollars)
Twelve Months Ended December 31, 2005
- -------------------------------------
Deducted from asset accounts:
Allowance for doubtful accounts $ 67.8 $ 96.8 $ 101.8 $ 62.8
Additions to liability accounts:
Reserve for injury and damages $ 9.4 $ 0.5 $ 0.6 $ 9.3
Reserve for environmental expenditures $ 256.8 $ 210.6 $ 43.7 $ 423.7
Twelve Months Ended December 31, 2004
- -------------------------------------
Deducted from asset accounts:
Allowance for doubtful accounts $ 75.7 $ 74.1 $ 82.0 $ 67.8
Additions to liability accounts:
Reserve for injury and damages $ 9.4 $ - $ - $ 9.4
Reserve for environmental expenditures $ 294.7 $ - $ 37.9 $ 256.8
Twelve Months Ended December 31, 2003
- -------------------------------------
Deducted from asset accounts:
Allowance for doubtful accounts $ 60.1 $ 82.1 $ 66.5 $ 75.7
Additions to liability accounts:
Reserve for injury and damages $ 25.8 $ 3.9 $ 20.3 $ 9.4
Reserve for environmental expenditures $ 232.1 $ 106.3 $ 43.7 $ 294.7
- -----------------------------------------------------------------------------------------------------------------------------
All other schedules are omitted because they are not applicable or the required
information is shown in the financial statements or notes thereto.
179
(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 KeySpan effective April 16, 1998,
Amendment to Certificate of Incorporation of KeySpan effective May 26,
1998, Amendment to Certificate of Incorporation of KeySpan effective
June 1, 1998, Amendment to the Certificate of Incorporation of KeySpan
effective April 7, 1999 and Amendment to the Certificate of
Incorporation of KeySpan effective May 20, 1999 (filed as Exhibit 3.1
to KeySpan's Form 10-Q for the quarterly period ended June 30, 1999)
3.2 By-Laws of KeySpan in effect as of June 25, 2003, as amended (filed as
Exhibit 3.1 to KeySpan's Form 10-Q for the quarterly period ended June
30, 2003)
4.1 Credit Agreement dated as of June 24, 2005 among KeySpan Corporation,
the several lenders, The Royal Bank of Scotland PLC and Citibank,
N.A., as Co-Syndication Agents, The Bank of New York and The Bank of
Nova Scotia, as Co-Documentation Agents, and JPMorgan Chase Bank,
N.A., as Administrative Agent (filed as Exhibit 4.1 to KeySpan's Form
8-K dated as of June 29, 2005)
4.2 Amended and Restated Credit Agreement dated as of June 24, 2005 among
KeySpan Corporation, the several lenders, The Royal Bank of Scotland
PLC and Citibank, N.A., as Co-Syndication Agents, The Bank of New York
and The Bank of Nova Scotia, as Co-Documentation Agents, and JPMorgan
Chase Bank, N.A., as Administrative Agent (filed as Exhibit 4.2 to
KeySpan's Form 8-K dated as of June 29, 2005)
4.3 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
KeySpan's Form 8-K on November 20, 2000)
4.4 Form of Note issued in connection with the issuance of the KeySpan
Corporation $700 million of 7.625% Notes due 2010 issued on November
20, 2000 (filed as Exhibit 4-c to KeySpan's Form 8-K on November 20,
2000)
4.5 Form of Note issued in connection with the issuance of the KeySpan
Corporation $250 million of 8.0% Notes due 2030 issued on November 20,
2000 (filed as Exhibit 4-d to KeySpan's Form 8-K on November 20, 2000)
180
4.6 Form of Note issued in connection with the issuance of the KeySpan
Corporation $150 million of 4.65% Notes issued on April 1, 2003 (filed
as Exhibit 4.1 to KeySpan's Form 8-K dated as of April 8, 2003)
4.7 Form of Note issued in connection with the issuance of the KeySpan
Corporation $150 million of 5.875% Notes issued on April 1, 2003
(filed as Exhibit 4.2 to KeySpan's Form 8-K dated as of April 8, 2003)
4.8 Form of Note issued in connection with the issuance of the KeySpan
Corporation $307.2 million of 5.803% Notes issued on March 29, 2005
(filed as Exhibit 4.1 to KeySpan's Form 8-K dated as of March 31,
2005)
4.9 Supplemental Remarketing Agreement dated as of March 21, 2005 among
KeySpan Corporation, J.P. Morgan Securities Inc. and JPMorgan Chase
Bank, N.A. in connection with the remarketing of the 4.9% Notes due
2008 (filed as Exhibit 99.1 to KeySpan's Form 8-K dated as of March
24, 2005)
4.10 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 KeySpan's and KeySpan Gas
East Corporation's Form S-3 Registration Statement No. 333-92003)
4.11 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 KeySpan's Form 8-K on February 1, 2000)
4.12 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 KeySpan's Form 10-K for the year ended
December 31, 2000)
4.13 Participation Agreement, dated as of July 1, 1991, between New York
State Energy Research and Development Authority ("NYSERDA") and The
Brooklyn Union Gas Company relating to the Gas Facilities Revenue
Bonds ("GFRBs") Series 1991A and 1991B (The Brooklyn Union Gas Company
Project) (filed as Exhibit 4 to The Brooklyn Union Gas Company's Form
10-K for the year ended September 30, 1991)
4.14 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 (The Brooklyn Union Gas Company Project) (filed
as Exhibit 4 to The Brooklyn Union Gas Company's Form 10-K for the
year ended September 30, 1991)
181
4.15 Participation Agreement, dated as of July 1, 1992, between NYSERDA and
The Brooklyn Union Gas Company relating to the GFRBs Series 1993A and
1993B (The Brooklyn Union Gas Company Project) (filed as Exhibit 4 to
The Brooklyn Union Gas Company's Form 10-K for the year ended
September 30, 1992)
4.16 Indenture of Trust, dated as of July 1, 1992, between NYSERDA and
Chemical Bank, as Trustee, relating to the GFRBs Series 1993A and
1993B (The Brooklyn Union Gas Company Project) (filed as Exhibit 4 to
The Brooklyn Union Gas Company Form 10-K for the year ended September
30, 1992)
4.17 Participation Agreement dated as of July 1, 1991 between NYSERDA and
The Brooklyn Union Gas Company relating to the GFRBs Series D (The
Brooklyn Union Gas Company Project) (filed as Exhibit 4 to The
Brooklyn Union Gas Company's Form 10-K for the year ended September
30, 1991)
4.18 First Supplemental Participation Agreement dated as of June 1, 1993
between NYSERDA and The Brooklyn Union Gas Company relating to GFRBs
Series D (The Brooklyn Union Gas Company Project) (filed as Exhibit 4
to The Brooklyn Union Gas Company's Form 10-K for the year ended
September 30, 1993)
4.19 Trust Indenture, dated as of July 1, 1991 between NYSERDA and
Manufacturers Hanover Trust Company relating to the GFRBs Series D
(filed as Exhibit 4 to The Brooklyn Union Gas Company's Form 10-K for
the year ended September 30, 1991)
4.20 First Supplemental Trust Indenture, dated as of June 1, 1993 between
NYSERDA and Chemical Bank (as successor to Manufacturers Hanover Trust
Company) relating to the GFRBs Series D (filed as Exhibit 4 to The
Brooklyn Union Gas Company's Form 10-K for the year ended September
30, 1993)
4.21 Participation Agreement, dated January 1, 1996, between NYSERDA and
The Brooklyn Union Gas Company relating to GFRBs Series 1996 (The
Brooklyn Union Gas Company Project) (filed as Exhibit 4 to The
Brooklyn Union Gas Company's Form 10-K for the year ended September
30, 1996)
4.22 Indenture of Trust, dated January 1, 1996, between NYSERDA and
Chemical Bank, as Trustee, relating to GFRBs Series 1996 (The Brooklyn
Union Gas Company Project) (filed as Exhibit 4 to The Brooklyn Union
Gas Company's Form 10-K for the year ended September 30, 1996)
182
4.23 Participation Agreement, dated as of January 1, 1997, between NYSERDA
and The Brooklyn Union Gas Company relating to GFRBs 1997 Series A
(The Brooklyn Union Gas Company Project) (filed as Exhibit 4 to The
Brooklyn Union Gas Company's Form 10-K for the year ended September
30, 1997)
4.24 Indenture of Trust, dated January 1, 1997, between NYSERDA and Chase
Manhattan Bank, as Trustee, relating to GFRBs 1997 Series A (The
Brooklyn Union Gas Company Project) (filed as Exhibit 4 to The
Brooklyn Union Gas Company's Form 10-K for the year ended September
30, 1997)
4.25 Supplemental Trust Indenture, dated as of January 1, 2000, by and
between NYSERDA and The Chase Manhattan Bank, as Trustee, relating to
the GFRBs 1997 Series A (The Brooklyn Union Gas Company Project)
(filed as Exhibit 4.11 to KeySpan's Form 10-K for the year ended
December 31, 1999)
4.26 Bond Purchase Agreement, dated as of October 26, 2005, among The
Brooklyn Union Gas Company and NYSERDA and Morgan Stanley & Co.
Incorporated, BNY Capital Markets, Inc., Sovereign Securities
Corporation, LLC and The Williams Capital Group, L.P., as Series A
Underwriters, for the issuance of $82 million aggregate principal
amount of 4.7% GFRBs, 2005, Series A. (The Brooklyn Union Gas Company
Project) (filed as Exhibit 10.1 to KeySpan's Form 8-K dated November
1, 2005)
4.27 Indenture of Trust, dated as of November 1, 2005, between NYSERDA and
Citibank, N.A., as Trustee, relating to the issuance of $82 million
GFRBs, 2005 Series A, 4.7% due February 2024 (The Brooklyn Union Gas
Company Project) (filed as Exhibit 10.1 to KeySpan's Form 10-Q for the
quarterly period ended September 30, 2005)
4.28 Participation Agreement, dated as of November 1, 2005, between NYSERDA
and The Brooklyn Union Gas Company relating to the issuance of $82
million GFRBs, 2005 Series A, 4.7% due February 2024 (filed as Exhibit
10.2 to KeySpan's Form 10-Q for the quarterly period ended September
30, 2005)
4.29 Promissory Note, dated as of November 1, 2005, executed by the
Brooklyn Union Gas Company for issuance of $82 million GFRBs, 2005
Series A, 4.7% due February 2024 (filed as Exhibit 10.3 to KeySpan's
Form 10-Q for the quarterly period ended September 30, 2005)
183
4.30 Bond Purchase Agreement, dated as of October 26, 2005, among The
Brooklyn Union Gas Company and NYSERDA and Goldman Sachs & Co., BNY
Capital Markets, Inc., Sovereign Securities Corporation, LLC and The
Williams Capital Group, L.P., as Series A Underwriters, for the
issuance of $55 million aggregate principal amount of GFRBs, 2005,
Series B (filed as Exhibit 10.2 to KeySpan's Form 8-K dated November
1, 2005)
4.31 Indenture of Trust, dated as of November 1, 2005, between NYSERDA and
Citibank, N.A., as Trustee, relating to the issuance of $55 million
GFRBs, 2005 Series B due June 2025 (filed as Exhibit 10.4 to KeySpan's
Form 10-Q for the quarterly period ended September 30, 2005)
4.32 Participation Agreement, dated as of November 1, 2005, between NYSERDA
and The Brooklyn Union Gas Company relating to the issuance of $55
million GFRBs, 2005 Series B, due February 2025 (filed as Exhibit 10.5
to KeySpan's Form 10-Q for the quarterly period ended September 30,
2005)
4.33 Promissory Note, dated as of November 1, 2005, executed by the
Brooklyn Union Gas Company for the issuance of $55 million GFRBs, 2005
Series B, due June 2025 (filed as Exhibit 10.6 to KeySpan's Form 10-Q
for the quarterly period ended September 30, 2005)
4.34 Letter of Credit and Reimbursement Agreement, dated December 9, 2003,
by and between KeySpan Generation LLC and Royal Bank of Scotland Bank
PLC (filed as Exhibit 4.34 to KeySpan's Form 10-K for the year ended
December 31, 2003)
4.35 Participation Agreement dated as of December 1, 1997 by and between
NYSERDA and Long Island Lighting Company relating to the 1997 Electric
Facilities Revenue Bonds (EFRBs), Series A (KeySpan Generation LLC)
(filed as Exhibit 10(a) to KeySpan's Form 10-Q for the quarterly
period ended September 30, 1998)
4.36 Indenture of Trust, dated as of December 1, 1997, by and between
NYSERDA and The Chase Manhattan Bank, as Trustee, relating to the 1997
EFRBs, Series A (KeySpan Generation LLC) (filed as Exhibit 10(a) to
KeySpan's Form 10-Q for the quarterly period ended September 30, 1998)
4.37 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 (PCRB's), Series A (filed as Exhibit
4.10 to KeySpan's Form 10-K for the year ended December 31, 1999)
184
4.38 Trust Indenture, dated as of October 1, 1999, by and between NYSERDA
and The Chase Manhattan Bank, as Trustee, relating to the 1999 PCRBs,
Series A (filed as Exhibit 4.10 to KeySpan's Form 10-K for the year
ended December 31, 1999)
4.39 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))
4.40 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)
4.41 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)
4.42 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)
4.43 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)
4.44 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)
4.45 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)
4.46 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)
4.47 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 KeySpan's
Form 10-K for the year ended December 31, 2003)
4.48 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 KeySpan's
Form 10-K for the year ended December 31, 2003)
185
4.49 Guaranty, dated as of November 26, 2003, from KeySpan Corporation to
the Suffolk County Industrial Development Agency (filed as Exhibit
4.14-c to KeySpan's Form 10-K for the year ended December 31, 2003)
4.50 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 KeySpan's Form 10-K for
the year ended December 31, 2003)
4.51 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 KeySpan's Form 10-K for
the year ended December 31, 2003)
4.52 Guaranty, dated as of November 26, 2003, from KeySpan Corporation to
the Nassau County Industrial Development Agency (filed as Exhibit
4.14-c to KeySpan's Form 10-K for the year ended December 31, 2003)
4.53 Lease Agreement, dated June 9, 1999, between KeySpan-Ravenswood, LLC
and LIC Funding, Limited Partnership (filed as Exhibit 10.2 to
KeySpan's Form 10-Q for the quarterly period ended June 30, 1999)
4.54 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 KeySpan's Form 10-K for the year ended December
31, 2002)
4.55 KeySpan Corporation Guaranty dated June 9, 1999, from KeySpan in favor
of LIC Funding, Limited Partnership (filed as Exhibit 10.1 to
KeySpan's Form 10-Q for the quarterly period ended June 30, 1999)
4.56 KeySpan Corporation Guaranty dated May 25, 2004, relating to the 250
MW Ravenswood Expansion (filed as Exhibit 10.1 to KeySpan's Form 10-Q
for the quarterly period ended June 30, 2004)
4.57 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(filed as Exhibit 10.2
to KeySpan's Form 10-Q for the quarterly period ended June 30, 2004)
4.58 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 (filed as Exhibit 10.3 to KeySpan's Form 10-Q for
the quarterly period ended June 30, 2004)
186
4.59 Site Sublease, dated as of May 25, 2004, between SE Ravenswood Trust
and KeySpan-Ravenswood, LLC relating to the 250 MW Ravenswood
Expansion (filed as Exhibit 10.4 to KeySpan's Form 10-Q for the
quarterly period ended June 30, 2004)
4.60 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)
10.1 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 the Joint
Registration Statement on Form S-4 of The Brooklyn Union Gas Company
and Long Island Lighting Company, Registration No. 333-30353 on June
30, 1997)
10.2 Management Services Agreement between Long Island Power Authority and
Long Island Lighting Company dated as of June 26, 1997 (filed as Annex
D to the Joint Registration Statement on Form S-4 of The Brooklyn
Union Gas Company and Long Island Lighting Company, Registration No.
333-30353 on June 30, 1997)
10.3 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 KeySpan's Form 10-K for the year ended December 31, 2002)
10.4 Management Services Agreement dated as of January 1, 2006 between the
Long Island Lighting Company ("LILCO") d/b/a LIPA and KeySpan Electric
Services LLC (filed as Exhibit 10.1 to KeySpan's Form 8-K filed on
February 6, 2005)
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
the Joint Registration Statement on Form S-4 of The Brooklyn Union Gas
Company and Long Island Lighting Company, Registration No. 333-30353
on June 30, 1997)
10.6 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)
187
10.7 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 KeySpan's Form 10-K for the year ended December 31, 2002)
10.8 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 KeySpan's Form 10-K for the year ended
December 31, 2001)
10.9 Amendment, dated as of March 29, 2002, to Generation Purchase Rights
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 KeySpan's Form 10-Q for the quarterly
period ended March 31, 2002)
10.10 Generation Purchase Right Extension Agreement between KeySpan and the
Long Island Power Authority dated as of March 28, 2005 (filed as
Exhibit 10.1 to KeySpan's Form 10-Q for the quarterly period ended
March 31, 2005)
10.11 Option Agreement dated as of January 1, 2006 between LILCO d/b/a LIPA
and KeySpan Electric Services LLC (filed as Exhibit 10.2 to KeySpan's
Form 8-K filed on February 6, 2005)
10.12 Settlement Agreement dated as of January 1, 2006 among KeySpan,
KeySpan Generation LLC, KeySpan Electric Services LLC, KeySpan Energy
Trading Services LLC and LIPA (filed as Exhibit 10.3 to KeySpan's Form
8-K filed on February 6, 2005)
10.13 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)
10.14 Second Amendment, dated as of March 24, 2005, to the Lease Agreement
dated as of September 15, 1998 between The Brooklyn Union Gas Company
and Forest City Jay Street Associates, L.P. (filed as Exhibit 10 to
KeySpan's Form 8-K dated as of March 30, 2005)
188
10.15 ISDA Master Agreement, dated as of January 18, 2006, between KeySpan
Corporation and Morgan Stanley Capital Group Inc. (filed as Exhibit
10.1 to KeySpan's Form 8-K dated January 24, 2006)
10.16 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 Form 10-Q
for the quarter ended September 30, 2000, File No. 001-11899)
10.17 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)
10.18 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)
10.19 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)
10.20 Share Sale and Purchase Agreement dated February 25, 2005 with BG
Energy Holdings Limited and Premier Transmission Financing Public
Limited Company (filed as Exhibit 10.37 to KeySpan's Form 10-K for the
year ended December 31, 2004)
10.21 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 (filed as Exhibit 10.35 to KeySpan's
Form 10-K for the year ended December 31, 2004)
10.22 Purchase Agreement, dated February 11, 2005, among WDF Holding Corp.,
WDF, Inc. and KeySpan Business Solutions, LLC (filed as Exhibit 10.36
to KeySpan's Form 10-K for the year ended December 31, 2004)
Compensation Agreements
-----------------------
10.23* Cash Compensation for Non-Management Directors of KeySpan
10.24* Base Salaries of Named Executive Officers of KeySpan in effect as of
February 23, 2006
189
10.25 Employment Agreement, dated February 24, 2005, between KeySpan and
Robert B. Catell (filed as Exhibit 10.10 to KeySpan's Form 10-K for
the year ended December 31, 2004)
10.26 Employment Agreement, dated January 1, 2005, between KeySpan and
Anthony Sartor (filed as Exhibit 10.01 to KeySpan's Form 8-K dated as
of January 4, 2005)
10.27 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)
10.28 Supplemental Retirement Agreement, dated July 1, 2002, between KeySpan
and Steven L. Zelkowitz (filed as Exhibit 10.12 to KeySpan's Annual
Report on Form 10-K for the year ended December 31, 2002)
10.29 Supplemental Retirement Agreement, dated July 1, 2002, between KeySpan
and Gerald Luterman (filed as Exhibit 10.11 to KeySpan's Annual Report
on Form 10-K for the year ended December 31, 2002)
10.30 Supplemental Retirement Agreement, dated July 1, 2002, between KeySpan
and David J. Manning (filed as Exhibit 10.13 to KeySpan's Annual
Report on Form 10-K for the year ended December 31, 2002)
10.31 Supplemental Retirement Agreement, dated July 1, 2002, between KeySpan
and Elaine Weinstein (filed as Exhibit 10.15 to KeySpan's Annual
Report on Form 10-K for the year ended December 31, 2002)
10.32 Directors' Deferred Compensation Plan effective April 2003 (filed as
Exhibit 10.16 to KeySpan's Annual Report on Form 10-K for the year
ended December 31, 2003)
10.33 Officers' Deferred Stock Unit Plan of KeySpan Corporation (filed as
Exhibit 10.17 to KeySpan's Annual Report on Form 10-K for the year
ended December 31, 2002)
10.34 Officers' Deferred Stock Unit Plan of KeySpan Services, Inc. (filed as
Exhibit 10.18 to KeySpan's Annual Report on Form 10-K for the year
ended December 31, 2002)
10.35 Corporate Annual Incentive Compensation and Gainsharing Plan (filed as
Exhibit 10.20 to KeySpan's Form 10-K for the year ended December 31,
2000)
10.36* Corporate Annual Incentive Compensation Plan Target Performance Award
Level for Fiscal Year 2006
10.37 Senior Executive Change of Control Severance Plan effective as of
October 29, 2003 (filed as Exhibit 10.20 to KeySpan's Form 10-K for
the year ended December 31, 2003)
190
10.38 KeySpan's Amended Long-Term Performance Incentive Compensation Plan
(filed as Exhibit A to KeySpan's 2001 Proxy Statement filed on March
23, 2001)
10.39* KeySpan's Long-Term Performance Incentive Compensation Plan
Performance Target Award Level for Fiscal 2006
14 Code of Ethics (filed as Exhibit 14 to KeySpan's Annual Report on 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
24.1* Power of Attorney executed by Andrea S. Christensen on February 22,
2006
24.2* Power of Attorney executed by Robert J. Fani on February 22, 2006
24.3* Power of Attorney executed by Alan H. Fishman on February 22, 2006
24.4* Power of Attorney executed by James R. Jones on February 22, 2006
24.5* Power of Attorney executed by James L. Larocca on February 22, 2006
24.6* Power of Attorney executed by Gloria C. Larson on February 22, 2006
24.7* Power of Attorney executed by Stephen W. McKessy on February 22, 2006
24.8* Power of Attorney executed by Edward D. Miller on February 22, 2006
24.9* Power of Attorney executed by Vikki L. Pryor on February 22, 2006
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
191
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
192
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
KEYSPAN CORPORATION
(Registrant)
Signature: Date:
By: /s/Gerald Luterman February 28, 2006
------------------
Gerald Luterman
Executive Vice President
and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signatures: Date:
By: /s/Robert B. Catell February 28, 2006
---------------------------
Robert B. Catell
Chairman of the Board of Directors
and Chief Executive Officer
By: /s/Gerald Luterman February 28, 2006
------------------
Gerald Luterman
Executive Vice President and
Chief Financial Officer
By: /s/Theresa A. Balog February 28, 2006
-------------------
Theresa A. Balog
Vice President and
Chief Accounting Officer
193
*
- ---------------------
Andrea S. Christensen
Director
*
- ---------------------
Robert J. Fani
President, Chief Operating Officer and Director
*
- ---------------
Alan H. Fishman
Director
*
- --------------
James R. Jones
Director
*
- ----------------
James L. Larocca
Director
*
- ----------------
Gloria C. Larson
Director
*
- ------------------
Stephen W. McKessy
Lead Director
*
- ----------------
Edward D. Miller
Director
*
- --------------
Vikki L. Pryor
Director
* Such signature has been affixed pursuant to a Power of Attorney filed as an
exhibit hereto and incorporated herein by reference thereto
194