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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the period from January 1, 2000 to December 31, 2000
Commission File Number 1-14161
KEYSPAN CORPORATION
(Exact name of registrant as specified in its charter)
NEW YORK 11-3431358
(State or other jurisdiction of (I.R.S. employer identification no.)
incorporation or organization)
One MetroTech Center, Brooklyn, New York 11201
175 East Old Country Road, Hicksville, New York 11801
(Address of principal executive offices) (Zip code)
(718) 403-1000 (Brooklyn)
(516) 755-6650 (Hicksville)
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of each class Name of each exchange on which registered
------------------- -----------------------------------------
Common Stock, $.01 par value New York Stock Exchange
Pacific Stock Exchange
Series AA Preferred Stock, $25 par value New York Stock Exchange
Pacific Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None
(Title of class)
Indicate by check mark whether the registrant: (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes. X No.
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. X
As of March 1, 2001, the aggregate market value of the common stock
held by non-affiliates (133,745,586 shares) of the registrant was $5,165,254,531
based on the closing price, on such date, of $38.62 per share).
As of March 1, 2001, there were 137,014,409 shares of common stock,
$.01 par value, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Proxy Statement dated March 23, 2001 is incorporated by
reference into Part III hereof.
KEYSPAN CORPORATION
INDEX TO FORM 10-K
Part I Page
Item 1. Business.........................................................................................................2
Item 2. Properties......................................................................................................33
Item 3. Legal Proceedings...............................................................................................33
Item 4. Submission of Matters to a Vote of Security Holders.............................................................33
Part II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters...........................................34
Item 6. Selected Financial Data.........................................................................................35
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.............................................................................................36
Item 7A. Quantitative and Qualitative Disclosures About Market Risk .....................................................36
Item 8. Financial Statements and Supplementary Data ....................................................................36
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure......................................................................................36
Part III
Item 10. Directors and Executive Officers of the Registrant..............................................................36
Item 11. Executive Compensation..........................................................................................36
Item 12. Security Ownership of Certain Beneficial Owners and Management..................................................36
Item 13. Certain Relationships and Related Transactions..................................................................36
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.................................................37
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PART I
Item 1. Business
Overview
KeySpan Corporation ("KeySpan"), a New York corporation, is a member of the
Standard and Poor's 500 Index and a registered holding company under the Public
Utility Holding Company Act of 1935, as amended ("PUHCA"). KeySpan was formed in
May 1998, as a result of the business combination of KeySpan Energy Corporation,
the parent of The Brooklyn Union Gas Company, and certain businesses of the Long
Island Lighting Company ("LILCO"). On November 8, 2000, we acquired Eastern
Enterprises ("Eastern"), a Massachusetts business trust, that primarily owns
three gas utilities operating in Massachusetts, as well as EnergyNorth, Inc.
("ENI"), the parent of a gas utility operating principally in central New
Hampshire. As used herein, "KeySpan," "we," "us" and "our" refers to KeySpan,
its six principal gas distribution subsidiaries, and its other regulated and
unregulated subsidiaries, individually and in the aggregate.
Our core business is gas distribution, 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 2.4 million customers. In New York, The Brooklyn Union Gas Company
d/b/a 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 d/b/a 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 Company distributes natural gas in eastern
and central Massachusetts; Colonial Gas Company distributes natural gas in Cape
Cod and eastern Massachusetts; and Essex Gas Company distributes natural gas in
eastern Massachusetts. In New Hampshire, EnergyNorth Natural Gas, Inc.
distributes gas to customers principally located in central New Hampshire. Our
newly acquired New England gas companies are all doing business as KeySpan
Energy Delivery New England ("KEDNE").
KEDNY was formed in 1895 through the consolidation of several existing
companies, the oldest of which commenced operations in 1849, providing gas
distribution services throughout the New York City Boroughs of Brooklyn, Staten
Island and most of Queens, New York. LILCO, the original owner of KEDLI's gas
assets, was organized in 1910 to provide electric and gas services in the Long
Island Counties of Nassau and Suffolk and the Rockaway peninsula in the Borough
of Queens, all in New York. KEDLI, was formed on May 7, 1998 and on May 28,
1998, acquired substantially all of the LILCO gas assets and provides gas
distribution services in Nassau, Suffolk and the Rockaway peninsula in Queens.
Boston Gas Company has been wholly-owned by Eastern since 1929 and has been in
business for 177 years, making it the second oldest gas company in the United
States. Essex Gas Company has been in business for 146 years and was acquired by
Eastern in September 1998. Colonial Gas Company has been in business for 150
years and was acquired by Eastern in August 1999.
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We are also a major, and growing, generator of electricity. We own and operate
five large generating plants and 42 smaller facilities in Nassau and Suffolk
Counties on Long Island and the Rockaway peninsula and Queens. In addition, we
own, lease and operate a major generating facility in Queens County in New York
City. Under contractual arrangements, we provide power, electric transmission
and distribution services, billing and other customer services for approximately
one million electric customers of the Long Island Power Authority ("LIPA").
Our other subsidiaries are involved in gas and oil exploration and production;
gas storage; wholesale and retail gas and electric marketing; appliance service;
heating, ventilation and air conditioning ("HVAC") installation and services;
large energy-system ownership, installation and management; engineering
services; fiber optic services; energy-related internet activities; fuel cells;
and marine transportation, including the barge hauling of fuel and other cargo.
We also invest in, and participate in the development of, pipelines and other
energy-related projects, domestically and internationally.
As a result of the acquisition of Eastern and ENI, we became a registered
holding company under PUHCA. Therefore, our corporate and financial activities
and those of our subsidiaries, including their ability to pay dividends to us,
are subject to regulation by the Securities and Exchange Commission ("SEC").
Under our holding company structure, we have no independent operations or source
of income of our own and conduct substantially all of our operations through our
subsidiaries and, as a result, we depend on the earnings and cash flow of, and
dividends or distributions from, our subsidiaries to provide the funds necessary
to meet our debt and contractual obligations. Furthermore, a substantial portion
of our consolidated assets, earnings and cash flow is derived from the
operations of our regulated utility subsidiaries, whose legal authority to pay
dividends or make other distributions to us is subject to regulation by state
regulatory authorities.
For additional information concerning regulation by the SEC under PUHCA see the
discussion under the heading "Securities and Exchange Commission Regulation"
contained in Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations" contained herein.
KeySpan reports its operations in six business segments: Gas Distribution,
Electric Services, Energy Services, Gas Exploration and Production, Energy
Investments and Other.
The Gas Distribution segment consists of our six gas distribution subsidiaries
described earlier, which operate in New York, Massachusetts and New Hampshire
and serve approximately 2.4 million customers.
The Electric Services segment consists of subsidiaries that operate the electric
transmission and distribution ("T&D") system owned by LIPA; provide energy
conversion services for LIPA from our generating facilities located on Long
Island; and manage fuel supplies for LIPA to fuel our Long Island generating
facilities. The electric services segment also includes subsidiaries that own,
lease and operate the 2,200 megawatt Ravenswood electric generation facility
(the "Ravenswood facility"), located in Queens County in New York City.
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The Gas Exploration and Production segment is engaged in natural gas and oil
exploration and production, and the development and the acquisition of domestic
natural gas and oil properties primarily in the Gulf of Mexico and Southern
Texas. This segment consists of our approximate 70% equity interest in The
Houston Exploration Company ("Houston Exploration") and KeySpan Exploration and
Production, LLC ("KeySpan Exploration"), our wholly owned subsidiary engaged in
a joint venture with Houston Exploration.
The Energy Services segment primarily provides energy-related services to
customers located within the New York City metropolitan area, New Jersey,
Connecticut, Massachusetts, New Hampshire, Rhode Island and Pennsylvania through
various subsidiaries which operate under the following principal four lines of
business: (i) home energy services, which provides residential and small
commercial customers with service and maintenance of energy systems and
appliances, as well as the competitive retail supply of natural gas and
electricity to residential and small commercial customers; (ii) business
solutions, which provides engineering, consulting and construction services,
services related to the design, construction, installation, operation,
maintenance and management of heating, cooling and power production equipment
and systems, including ventilating, air conditioning, electrical power, motors,
pumps, lighting, water, wastewater, plumbing, piping, fire suppression systems,
for commercial and industrial customers, as well as the competitive retail
supply of natural gas and electricity to large commercial, institutional and
industrial customers . Certain subsidiaries within this line of business also
engage or may engage in the financing and ownership of cogeneration, small power
production, thermal energy, chilled water and related equipment and facilities;
(iii) commodity procurement, which provides management and procurement services
for fuel supply and management of energy sales, primarily for and from the
Ravenswood facility, as well as provides wholesale gas and electric purchasing
and management services for the home energy services and business solutions; and
(iv) fiber optic services, which provides fiber optic related construction,
leasing and exchange services.
Subsidiaries in the Energy Investments segment hold a 20% equity interest in the
Iroquois Gas Transmission System, LP ("Iroquois"), a pipeline that transports
Canadian gas supply to markets in the Northeastern United States; a 50% interest
in the Premier Transco Pipeline and a 24.5% interest in Phoenix Natural Gas
Limited, both in Northern Ireland; investments of natural gas processing plans
and related facilities in Western Canada, principally through KeySpan Canada,
formerly Gulf Midstream Services and hold minor investments in certain other
domestic pipeline projects.
The Other segment represents primarily unallocated administrative and general
expenses, interest income earned on temporary cash investments, and preferred
stock dividends. Further, this segment includes our marine transportation
subsidiary, Midland Enterprises, that was acquired as part of the Eastern
acquisition. We are required by the SEC to sell this subsidiary by November 8,
2003 as its operations were determined not to be functionally related to our
core utility operations as required by PUHCA. These operations do not contribute
significantly to our consolidated results of operations or cash flows.
In 1998, KeySpan changed its fiscal year end from March 31 to December 31. For
financial reporting purposes, financial statements included, or incorporated by
reference, herein for the period ending December 31, 1998 are for the nine
months then ended and have been prepared on the basis
-4-
that LILCO was deemed the acquiring company in the 1998 KeySpan transaction.
Additional information about KeySpan's industry segments is contained in Note 2
to the Consolidated Financial Statements, "Business Segments" included herein
and incorporated by reference thereto.
Certain statements contained in this Annual Report on Form 10-K concerning
expectations, beliefs, plans, objectives, goals, strategies, future events or
performance and underlying assumptions and other statements that are other than
statements of historical facts, are "forward-looking statements" within the
meaning of Section 21E of the Securities Exchange Act of 1934, as amended.
Without limiting the foregoing, all statements under the captions "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Item 7A. Quantitative and Qualitative Disclosures About Market
Risk" relating to our future outlook, anticipated capital expenditures, future
cash flows and borrowings, pursuit of potential future acquisition opportunities
and sources of funding, are forward-looking statements. Such forward-looking
statements reflect numerous assumptions and involve a number of risks and
uncertainties and actual results may differ materially from those discussed in
such statements. Among the factors that could cause actual results to differ
materially are: general economic conditions, especially in the Northeast United
States; available sources and cost of fuel; federal and state regulatory
initiatives that increase competition, threaten cost and investment recovery,
and impact rate structures; the ability of KeySpan to successfully reduce its
cost structure; the successful integration of KeySpan's subsidiaries, including
Eastern, ENI and their subsidiaries; the degree to which KeySpan develops
unregulated business ventures, as well as federal and state regulatory policies
affecting KeySpan's ability to retain and operate such business ventures; the
ability of KeySpan to identify and make complementary acquisitions, as well as
the successful integration of such acquisitions; inflationary trends and
interest rates; and other risks detailed from time to time in other reports and
other documents filed by KeySpan with the SEC. For any of these statements,
KeySpan claims the protection of the safe harbor for forward-looking information
contained in the Private Securities Litigation Reform Act of 1995, as amended.
For additional discussion on these risks, uncertainties and assumptions, see
"Item 1. Business," "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations" and "Item 7A. Quantitative and Qualitative
Disclosures About Market Risk" contained herein.
KeySpan's principal executive offices are located at One MetroTech Center,
Brooklyn, New York 11201 and 175 East Old Country Road, Hicksville, New York
11801 and its telephone numbers are (718) 403-1000 (Brooklyn) and (516) 755-6650
(Hicksville). Financial and other information is also available through the
World Wide Web at http://www.keyspanenergy.com.
Business Strategy
KeySpan's vision is to be the premier energy company in the Northeastern United
States. To help us achieve that goal, we have acquired the operations of Eastern
and ENI, establishing KeySpan as the largest gas distribution company in the
Northeast and the fifth largest in the United States. The increased size and
scope of the company should enable us to provide enhanced cost-effective
customer service; offer our existing customers an array of other services and
products by implementing innovative marketing techniques and building upon our
existing relationships with
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them; and capitalize on the above-average growth opportunities for natural gas
expansion in the Northeast by expanding our infrastructure on Long Island and in
New England.
A key element of KeySpan's business strategy is the continued focus and growth
of our core businesses of gas distribution, electric services and energy
services. In order provide the greatest shareholder value, we may consider the
sale of some or all of our non-core assets which include the businesses
conducted in our Gas Exploration and Production, Energy Investments and our
Other business segments. Any proceeds from such sales would, in all likelihood,
be used to retire a portion of our outstanding indebtedness.
Gas Distribution Services. KeySpan has achieved a high degree of penetration in
KEDNY's service territory, with approximately 79% of all one and two family
homes currently using natural gas for space heating. In contrast, less than 40%
of one and two family homes in KEDLI's service territory and less than 50% of
one and two family homes in KEDNE's service territories currently use natural
gas for space heating. During 2000, we continued the implementation of our
innovative marketing techniques focused on oil to gas space heating conversions
and the conversion of our existing non- heating natural gas customers to gas
heating. In our New York markets, this approach resulted in 24,000
installations, concentrated primarily in our Long Island service territory.
We also implemented the same marketing programs in our newly acquired New
England service territories, resulting in 19,000 new installations. Our strategy
is to continue these marketing efforts primarily on Long Island and in New
England. We believe that more than half of our gas sales growth will come from
our KEDNE service territories where there are more than 650,000 potential
customers, mostly homeowners who heat their homes with oil. Of these potential
customers, more than 100,000 already use gas for cooking or water heating and
another 160,000 are in close proximity to a gas main. Converting these customers
to gas heat will require minimal capital investment.
Additionally, we are also committed to expanding our gas distribution systems on
Long Island and in New England. During 2000, we installed more than 1,000,000
feet of new gas main in our KEDLI service territory, twice as much as in any
previous year. Expanding our gas distribution systems allows us to add new
customers, providing a broader customer base to expand our markets for
additional products and services.
Electric Services. Our electric services segment contributed significantly to
earnings in 2000, largely attributable to sales of capacity, energy, and
ancillary services from our Ravenswood facility. We are planning on expanding
the Ravenswood facility by adding a 250-megawatt, gas-fired co- generation unit
that is expected to come on line in 2003. We are also considering expanding
capacity on Long Island by building a combined-cycle generating unit.
Over the last year, we also focused our efforts on improving our plant
efficiencies to increase generating capacity. Through innovative technological
approaches, such as adding water spray to smaller units, we increased installed
capacity on Long Island and New York City by 37 megawatts, and we instituted a
program to reduce nitrogen oxides for improved environmental performance.
Reliability improvements at our Ravenswood facility reduced our forced outage
rate from 35% two years ago to just 5% in 2000. Decreasing the amount of time
our generating units are offline for
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repairs allows us to increase sales and thus increase earnings. Our goal is to
continue improving our plants through new technologies that improve efficiencies
and reliability.
Energy Services. With our strong market presence in the Northeast centered on
our gas distribution services and by taking advantage of the increasing trend
towards deregulation and competition, KeySpan believes it is well positioned to
provide our customers with an expanded array of energy products and services
through our unregulated energy services companies. Our goal is to become one of
the top regional service providers in the Northeast.
During 2000, KeySpan expanded its energy services operations through the
acquisition of four additional companies located in the New York City
metropolitan area. The newly acquired companies specialize in
engineering-consulting, plumbing and mechanical contracting and HVAC
contracting. Additionally, Eastern and ENI each have unregulated energy services
operations in Massachusetts and New Hampshire, thereby expanding our energy
services operations further into the Northeast. The Energy Services segment now
has more than 3,000 employees and 100,000 contracts for the sale of gas and
electricity at retail on an unregulated basis.
Additionally, our fiber optic services continue to enhance our Energy Services
segment. Our 450 miles, or 57,000 fiber miles, of fiber optics located on Long
Island are strategically situated in one of the most attractive communication
markets in the United States. We construct fiber optic systems and facilities,
and own and lease fiber optic cable to local, long distance trans-Atlantic and
internet service providers. Our goal is to continue to expand this business by
broadening our customer base and creating strategic alliances with other
telecommunication companies. To this end, we entered into an agreement with FLAG
Atlantic 1, a British telecommunications joint venture, to establish a high
speed telecommunications link between London, Paris and New York.
Gas Exploration & Production. The shortages in energy supply and high gas prices
created the opportunity for significant net income and shareholder value from
this segment. Further, in March 2000, we converted approximately $80 million in
debt owed by Houston Exploration to us into additional common equity, increasing
our ownership from approximately 64% to 70%.
Energy Investments. Consistent with KeySpan's strategy to make investments in
certain select energy related businesses, focused primarily in the Northeast and
Canada, we purchased the remaining 50% interest in KeySpan Canada from Gulf
Canada Resources Limited. KeySpan also entered into a joint venture to construct
the Islander East Pipeline, which will bring 250 MDTH of gas capacity daily from
Nova Scotia, Canada to Long Island, New York and will also provide an additional
connection to gas supply for our New England marketplace. The Islander East
Pipeline is scheduled to become operational in 2003.
Other. As we previously discussed, we are required by the SEC to sell our marine
transportation subsidiary, Midland Enterprises, that was acquired as part of the
Eastern acquisition since its operations were determined not to be functionally
related to our core utility operations.
New Lines of Business. During 2000, we launched the myHomeKey.com portal.
MyHomeKey provides customers with the ability to electrically manage numerous
household tasks by linking them
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with service providers, allowing on-line scheduling of home repairs and
maintenance, convenient shopping for home appliances, one-stop shopping for
utility services and access to energy saving equipment and systems, as well as
individualized community information.
In addition to using internet applications to enhance customer contact with
KeySpan, we are also using e-business solutions to operate more efficiently and
reduce our costs. In 2000, KeySpan entered into a supply chain venture called
Enporion. Enporion is an open, global supply chain e- marketplace for the energy
industry, linking suppliers and buyers through the internet. Through Enporion,
we have been able to simplify business purchasing processes, make operations
more effective and efficient, and reduce the purchase costs of materials and
supplies.
KeySpan is also engaged in alternative generation technologies such as
microturbines, reciprocating engines, fuel cells, photovoltaic, and wind power.
We believe that distributed generation methods such as these will be a growth
area in the next few years. In 2000, we successfully installed the first
microturbine unit on Long Island at the Atlantis Marine World Aquarium. The
unit, which runs on natural gas, produces up to 28 kilowatts of electricity for
the aquarium and uses its exhaust heat to provide hot water to the facility's
shark tank.
The Company
Gas Distribution
Overview
KeySpan sells, distributes and transports natural gas in six service territories
located in three states, New York, Massachusetts and New Hampshire. We are the
fifth largest gas distribution company in the United States and the largest in
the Northeast. In New York there are two separate, but contiguous service
territories served by KEDNY and KEDLI, comprising approximately 1,417 square
miles, and 1.6 million customers. In Massachusetts, Boston Gas Company, Colonial
Gas Company and Essex Gas Company, each doing business as KEDNE serve three
contiguous service territories consisting of 1,934 square miles and
approximately 758,000 customers. In New Hampshire, EnergyNorth Natural Gas, Inc.
d/b/a KEDNE has a service territory that is contiguous to Colonial Gas Company's
and is within 30 to 85 miles of the greater Boston area. EnergyNorth Natural Gas
services approximately 74,000 customers over a service area of approximately 922
square miles. Collectively, KeySpan owns and operates gas distribution,
transmission and storage systems that consist of approximately 21,000 miles of
gas mains and distribution pipelines and 576 miles of transmission pipelines, as
well as two major gas storage facilities. Our service areas cover 4,273 square
miles, and we serve approximately 2.4 million customers in the aggregate.
Gas is offered for sale to residential and small commercial customers on a
"firm" basis, and to most large commercial and industrial customers on a "firm"
or "interruptible" basis. "Firm" service is offered to customers under schedules
or contracts which anticipate no interruptions, whereas "interruptible" service
is offered to customers under schedules or contracts which anticipate and permit
interruption on short notice, generally in peak-load seasons. Gas is available
at any time of the year on an interruptible basis, if the supply is sufficient
and the supply system is adequate.
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KeySpan also participates in interstate markets by releasing pipeline capacity
or bundling pipeline capacity with gas for "off-system" sales. An "off-system"
customer consumes gas at facilities located outside of KeySpan's service
territories by connecting to our facilities or another transporter's facilities
at a point of delivery agreed to by us and the customer. KeySpan purchases
natural gas for sale to customers under long-term supply contracts and
short-term spot contracts. Such gas is transported under both firm and
interruptible transportation contracts. In addition, KeySpan has commitments for
the provision of gas storage capability and peaking supplies.
KeySpan sells gas to firm gas customers at its cost for such gas, plus a charge
designed to recover the costs of distribution (including a return of and a
return on capital invested in its distribution facilities). We share with our
firm gas customers net revenues (operating revenues less the cost of gas) from
off-system sales. Further, net revenues from tariff gas balancing services and
certain on- system sales are refunded, for the most part, to firm customers
subject to certain sharing provisions. The majority of interruptible profits
earned by the KEDNE companies are also refunded to firm gas customers.
Our gas operations can be significantly affected by seasonal weather conditions.
Traditionally, annual revenues are substantially realized during the heating
season as a result of higher sales of gas due to cold weather. Accordingly,
operating results historically are most favorable in the first and fourth
calendar quarters. KEDNY and KEDLI operate under a utility tariff that contains
a weather normalization adjustment that provides for recovery from or refund to
firm customers of material shortfalls or excesses of firm net revenues (revenues
less applicable gas costs) during a heating season due to variations from normal
weather. However, the utility tariffs for our four KEDNE gas distribution
companies do not contain such a weather normalization adjustment and, therefore,
fluctuations in seasonal weather conditions between years may have a significant
effect on results of operations and cash flows for these four subsidiaries. For
additional discussion, see Item 7, Management's Discussion and Analysis of
Financial Condition and Results of Operations, "Regulation and Rate Matters".
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Gas sales and revenues for 2000 by class of customer are set forth below:
Sales Revenues Revenues
Customer (MDTH) (thousands of $) (% of Total)
- ----------------------------------------------------------- ---------------- ---------------------- --------------
Firm
Residential Heating........................................ 127,467 1,352,215 52.91
Residential Non-Heating.................................... 11,214 226,592 8.87
Temperature-Controlled heating............................. 33,490 224,792 8.80
Commercial/Industrial...................................... 43,829 389,620 15.24
------------ ---------------------- -----------------
Total Firm................................................. 216,000 2,193,219 85.82
------------ ---------------------- -----------------
Firm Transportation........................................ 40,655 34,709 1.36
Transportation - Electric Generation....................... 49,854 10,253 .40
------------ ---------------------- -----------------
Total Firm Transportation.................................. 90,509 44,962 1.76
------------ ---------------------- -----------------
Total Firm Gas Sales and Transportation.................. 306,509 2,238,181 87.58
Interruptible.............................................. 8,016 46,849 1.83
Off-System Sales........................................... 32,640 122,967 4.81
Transportation............................................. 50,750 121,996 4.77
------------ ---------------------- -----------------
Total Gas Sales and Transportation....................... 397,915 2,529,993 98.99
Other Retail Services...................................... - 25,792 1.01
------------ ---------------------- -----------------
Total Sales and Revenues................................. 397,915 2,555,785 100.00
============ ====================== =================
Further information and statistics regarding our Gas Distribution segment is
contained in Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations, "Gas Distribution."
Supply and Storage
KeySpan has contracts for the purchase of firm long-term transportation and
storage services. Our gas supplies are purchased under long-term contracts and
on the spot market and are transported by interstate pipelines from domestic and
Canadian sources. Storage and peaking supplies are available to meet system
requirements during winter periods.
Regulatory actions, economic factors and changes in customers and their
preferences continue to reshape our gas operations markets. A number of
multi-family, commercial and industrial customers and a growing number of
residential customers currently purchase their gas supplies from natural gas
marketers and then contract with us for local transportation, balancing and
other unbundled services. This trend is likely to continue as state regulators
in all of our service territories have implemented policies designed to
encourage customers to purchase their gas from suppliers other than the
traditional gas utilities, such as marketers.
New York Gas Distribution Systems
Peak-Day Capability. The design criteria for KeySpan's New York gas systems
assumes an average temperature of 0(0)F for peak-day demand. Under such
criteria, KEDNY and KEDLI estimated that
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their requirements to supply firm gas customers would be approximately 1,940
MDTH of gas for a peak-day during the 2000/2001 winter season and that gas
available to KEDNY and KEDLI on such a peak-day would amount to approximately
1,999 MDTH. For the 2001/2002 winter season, KEDNY and KEDLI estimate that their
peak-day requirements will amount to 1,982 MDTH and that the gas supplies
available to KEDNY and KEDLI on such a peak-day will amount to approximately
1,999 MDTH.
For the 2000/2001 winter season, the highest daily throughput to our customers
was 1,597 MDTH, which occurred on December 25, 2000 at an average temperature of
17(degree)F, representing 80% of our capability at that time. KEDNY and KEDLI
had sufficient gas available to meet the requirements of their firm gas
customers for the 2000/2001 winter gas season and anticipate they will have
sufficient quantities for the 2001/2002 winter season. KEDNY and KEDLI's firm
gas peak-day capability is summarized in the following table:
MDTH
Source per day % of Total
- ----------------------------- ----------------------- -----------------
Pipeline.................. 716 36
Underground Storage....... 779 39
Peaking Supplies.......... 504 25
----------------------- -----------------
Total..................... 1,999 100
======================= =================
Pipelines and Storage. KEDNY and KEDLI purchase natural gas for sale to their
customers under contracts with suppliers located in domestic and Canadian supply
basins and arranged for transportation to their facilities under firm long-term
contracts with interstate pipeline companies. During the 2000/2001 winter
season, approximately 76% of KEDNY's and KEDLI's natural gas supply was
available from domestic sources and 24% from Canadian sources. KEDNY and KEDLI
had available under firm contract 716 MDTH per day of year-round and seasonal
pipeline transportation capacity to their facilities in the New York City
metropolitan area. Major providers of interstate pipeline capacity and related
services to KEDNY and KEDLI include: Transcontinental Gas Pipe Line Corporation
("Transco"), Texas Eastern Transmission Corporation ("TETCO"), Iroquois,
Tennessee Gas Pipeline Company ("Tennessee"), CNG Transmission Corporation
("CNG") and Texas Gas Transmission Company ("Texas").
Additionally, KEDNY and KEDLI have long-term contracts with Transco, TETCO,
Tennessee, CNG, Equitrans, Inc., Hattiesburg First Reserve and Honeoye Storage
Corporation for underground storage capacity of 58,954 MDTH, with 779 MDTH per
day, maximum deliverability.
Peaking Supplies. In our New York service territories, in addition to pipeline
and storage supply, KEDNY and KEDLI supplement their winter supply with peaking
supplies which are available on the coldest days of the year to enable them to
economically meet the increased requirements of their heating customers. KEDNY
and KEDLI's peaking supplies include gas provided by two of KeySpan's liquefied
natural gas ("LNG") plants. These LNG plants have an aggregate storage capacity
of approximately 2,053 MDTH and peak-day throughput capacity of 394 MDTH, or 20%
of peak-day supply. Additionally, KEDNY and KEDLI have peaking supply contracts
with four
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cogeneration facilities/independent power producers located in their franchise
areas: Trigen Services Corporation, Brooklyn Navy Cogeneration Partners, LP,
Nissequogue Cogen Partners and the New York Power Authority to purchase peaking
supplies with a maximum daily capacity of 110 MDTH and total available peaking
supplies during the winter season of 3,349 MDTH. For the 2000/2001 winter
season, KEDNY and KEDLI had the capability to provide a maximum peak-day supply
of 504 MDTH on excessively cold days.
Gas Supply Management. Commencing April 1, 2000, we entered into a two-year
agreement with Coral Resources, L.P. ("Coral"), in which Coral assists our
wholly owned subsidiary, KeySpan Energy Trading Services LLC, in providing
energy supply management services for KEDNY and KEDLI. This agreement expires on
March 31, 2002. Additionally, KeySpan Energy Trading Services LLC also provides
energy-management services undertaken on behalf of LIPA.
New England Gas Distribution Systems
Peak-Day Capability. The design criteria for KeySpan's New England gas systems
assumes an average temperature of -6(0)F for peak-day demand. Under such
criteria, the KEDNE companies estimated that the requirements to supply their
firm gas customers would amount to approximately 1,217 MDTH of gas for a
peak-day during the 2000/2001 winter season and that the gas available to the
KEDNE companies on such a peak-day would amount to approximately 1,321 MDTH. For
the 2001/2002 winter season, the KEDNE companies estimate that their peak-day
requirements will amount to 1,240 MDTH and that the gas supplies available to
them on such a peak-day will amount to approximately 1,321 MDTH.
For the 2000/2001 winter season, the highest daily throughput to our New England
customers was 980 MDTH, which also occurred on December 25, 2000 at an average
temperature of 19(degree)F, representing 74% of the KEDNE companies' capability
at that time. The KEDNE companies had sufficient gas available to meet the
requirements of their firm gas customers for the 2000/2001 winter gas season and
anticipate that they will have sufficient quantities for the 2001/2002 winter
season. The firm gas peak day capability of the KEDNE companies is summarized in
the following table:
MDTH
Source per day % of Total
- --------------------------------------- ------------------- --------------
Pipeline and Underground Storage.... 708 54
Peaking Supplies.................... 613 46
------------------- -------------
Total............................... 1,321 100
=================== =============
Pipelines and Storage. The KEDNE companies also purchase natural gas for sale to
their customers under contracts with suppliers located in domestic and Canadian
supply basins and arrange for transportation to their facilities under firm
long-term contracts with interstate pipeline companies. During the 2000/2001
winter season, approximately 77% of the KEDNE companies' natural gas supply was
available from domestic sources and 23% from Canadian sources. The KEDNE
companies have available under firm contract 708 MDTH per day of year-round and
seasonal
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transportation and underground storage capacity to their facilities in New
England. Major providers of interstate pipeline capacity and related services to
the KEDNE companies include: TETCO, Iroquois, Maritimes and Northeast Pipeline,
Tennessee, Algonquin Gas Transmission Company and Portland Natural Gas
Transmission System. Moreover, the KEDNE companies have long-term contracts with
TETCO, Tennessee, Dominion, National Fuel Gas Supply Corporation and Honeoye
Storage Corporation for underground storage capacity of 23,742 MDTH.
In our New England service territory, in addition to pipeline and storage
supply, the KEDNE companies supplement their winter supply with peaking supplies
that are available on the coldest days of the year to enable them to
economically meet the increased requirements of their heating customers. Peaking
supplies include gas provided by both LNG and propane air plants located
throughout the distribution systems of the KEDNE companies, as well as two
leased facilities outside of their distribution systems located in Providence,
Rhode Island and Everett, MA. For the 2000/2001 winter season, the KEDNE
companies had the capability to provide a peak-day supply of 613 MDTH on
excessively cold days or 46% of peak-day supply.
Gas Supply Management. Effective November 1, 1999, the Massachusetts based gas
distribution subsidiaries entered into a three-year portfolio management
contract with El Paso Energy Marketing, Inc. ("El Paso"). El Paso provides the
majority of the city gate supply requirements to the three Massachusetts
companies at market prices and manages upstream capacity, underground storage
and term supply contracts. The Massachusetts Department of Telecommunications
and Energy ("DTE") approved the contract in October 1999. The annual fee paid by
El Paso to manage the KEDNE companies' portfolio is, for the most part, returned
to firm customers.
Gas Costs. Fluctuations in utility gas costs have little impact on the operating
results of KEDNY, KEDLI and KEDNE companies, since the current gas rate
structure of each of these companies includes a gas adjustment clause whereby
variations between actual gas costs and gas cost recoveries are deferred and
subsequently refunded to or collected from customers.
For additional information concerning the gas distribution segment, see the
discussion on "Gas Distribution" in Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations" contained herein.
Electric Services
Overview
KeySpan's Electric Services segment primarily consist of (i) the ownership and
operation of gas and oil fired generating facilities located on Long Island and
New York and the delivery of the power generated from these facilities to LIPA
and the New York Independent System Operator ("NYISO"); (ii) the management and
operation of LIPA's transmission and distribution system; and (iii) the
management of LIPA's fuel and electric energy purchases and off-system sales.
As more fully described below, we (i) provide to LIPA all operation, maintenance
and construction services relating to the Long Island electric T&D system
through a management services agreement (the "MSA"); (ii) supply LIPA with
energy conversion and ancillary services through a power supply
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agreement (the "PSA") to allow LIPA to provide electricity to its customers on
Long Island; and (iii) manage all aspects of the fuel supply for the Long Island
generating facilities, as well as all aspects of the capacity and energy owned
by or under contract to LIPA through an energy management agreement (the "EMA").
Each of the MSA, PSA and EMA became effective on May 28, 1998 and are
collectively referred to herein as the "LIPA Agreements."
On June 18, 1999, KeySpan completed its acquisition of the then rated 2,168
megawatt Ravenswood facility located in New York City from Consolidated Edison
Company of New York, Inc. ("Consolidated Edison") for approximately $597
million. As a means of financing this acquisition, we entered into a lease
agreement with a special purpose, unaffiliated financing entity that acquired a
portion of the Ravenswood facility directly from Consolidated Edison and leased
it to a wholly owned KeySpan subsidiary under a ten-year lease. We have
guaranteed all payment and performance obligations of this subsidiary under the
lease. Another subsidiary provides all operating, maintenance and construction
services for the Ravenswood facility. The lease program was established in order
to reduce our cash requirements by $425 million. The lease qualifies as an
operating lease for financial reporting purposes while preserving our ownership
of the facility for federal and state income tax purposes. The balance of the
funds needed to acquire the Ravenswood facility were provided from cash on hand.
The Ravenswood facility has contributed significantly to earnings in 2000,
selling capacity, energy and ancillary services into the NYISO at market-based
rates, subject to mitigation. The plant, which provides approximately 25% of the
in-city capacity available to serve residents and businesses during a period of
economic growth, underscores the value of electric generation assets for our
company. We are in the process of expanding the Ravenswood facility by adding a
250-megawatt state-of-the- art gas-fired co-generation unit at the site which is
expected to come on line by 2003.
We currently sell the energy, capacity and ancillary services produced by the
Ravenswood facility by bidding into an auction process conducted by the NYISO.
See Note 8 to the Consolidated Financial Statements "New York State Independent
System Operator Matters" for further information.
Generating Facility Operations
KeySpan owns and operates an aggregate of 73 electric generation units
throughout Long Island and Queens, 40 of which can be powered either by natural
gas or oil. In recent years, we have reconfigured several of our facilities to
enable them to burn either natural gas or oil, thus enabling us to switch
periodically between fuel alternatives based upon cost and seasonal
environmental requirements. Through other innovative technological approaches
such as adding water spray to smaller units, we increased installed capacity in
our generating facilities by 37 megawatts, and we instituted a program to reduce
nitrogen oxides for improved environmental performance. Reliability improvements
at our Ravenswood facility reduced the forced outage rate for that facility from
35% two years ago to just 5% in 2000. Decreasing the amount of time our
generating units are offline for repair allows us to increase sales and thus
increase earnings.
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The following table indicates the 2000 summer capacity of our steam generation
facilities and internal combustion ("IC") units as reported to the NYISO:
Location of Units Description Fuel Units MW
- ------------------------------- -------------------------------- ------------------------ ------------------------ --------------
Long Island City Steam Turbine Dual* 3 1,736
Northport, L.I. Steam Turbine Dual* 3 1,166
Northport, L.I. Steam Turbine Oil 1 382
Port Jefferson, L.I. Steam Turbine Dual* 2 386
Glenwood, L.I. Steam Turbine Gas 2 231
Island Park, L.I. Steam Turbine Dual* 2 388
Far Rockaway, L.I. Steam Turbine Dual* 1 106
Long Island City IC Units Dual* 17 464
Throughout L.I. IC Units Dual* 12 290
Throughout L.I. IC Units Oil 30 1,088
- ------------------------------------------------------------------------------------------------------------------------------------
Total 73 6,237
=============================== ================================ ======================== ======================== ==============
*Dual - Oil or natural gas.
LIPA Agreements
Power Supply Agreement. The PSA provides for the sale to LIPA of all of the
capacity and, to the extent LIPA requests, energy from the Long Island
generating facilities. Capacity refers to the ability to generate energy and,
pursuant to NYISO requirements, must be maintained at specified levels
(including reserves) regardless of the source and amount of energy consumption.
By contrast, energy conversion services refers to the electricity actually
generated for consumption by consumers. Such sales of capacity and energy
conversion services from the Long Island generating facilities are made at rates
regulated by the Federal Energy Regulatory Commission ("FERC"). These rates may
be modified in the future in accordance with the terms of the PSA for (i) agreed
upon labor and expense indices applied to the base year; (ii) a return of and on
the capital invested in the Long Island generating facilities; and (iii)
reasonably incurred expenses that are outside of our control.
The PSA provides incentives and penalties for us to maintain the output
capability of the Long Island generating facilities, as measured by annual
industry-standard tests of operating capability, and plant availability and
efficiency. These combined incentives and penalties may total as much as $4
million annually. In 2000, KeySpan earned approximately $3 million in incentives
under the PSA.
The PSA provides LIPA with all of the capacity from the Long Island generating
facilities. However, LIPA has no obligation to purchase energy conversion
services from the Long Island generating facilities and is able to purchase
energy on a least-cost basis from all available sources consistent with existing
transmission interconnection limitations of the transmission and distribution
system. Under the terms of the PSA, LIPA is obligated to pay for capacity at
rates which reflect a large percentage of the overall fixed cost of maintaining
and operating the Long Island generating facilities. A variable maintenance
charge is imposed for each unit of energy actually generated by the Long Island
generating facilities. The PSA expires on May 28, 2013 and is renewable on
similar terms. However, the PSA provides LIPA the option of electing to reduce
or "ramp-down" the capacity it purchases from us in accordance with agreed-upon
schedules. In years 7 through 10 of the PSA, if LIPA elects to ramp-down, we are
entitled to receive payment for 100% of the present value of the capacity
charges otherwise payable over the remaining term of the PSA. If LIPA ramps-
down the generation capacity in years 11 through 15 of the PSA, the capacity
charges otherwise payable by LIPA will be reduced in accordance with a formula
established in the PSA. If LIPA exercises its ramp-down option, KeySpan may use
any capacity released by LIPA to bid on new LIPA capacity requirements or to bid
on LIPA's capacity requirements to replace other ramped-down capacity. If
KeySpan continues to operate the ramped-down capacity, the PSA requires it to
use reasonable efforts to market the capacity and energy from the ramped-down
capacity and to share any profits with LIPA. Any capacity and energy sold by us
from ramped-down capacity must be transported over the T&D system, and we will
be required to pay LIPA's standard transmission (and, if applicable,
distribution) rates for the service. The PSA will be terminated in the event
that LIPA exercises its right to purchase, at fair market value, all of the Long
Island generating facilities. This purchase option commences on May 28, 2001 and
continues for one year. LIPA has initiated a process to review whether to
exercise its right to purchase the Long Island generating facilities and has
begun soliciting proposals for the management, operation and maintenance of the
Long Island generating facilities in the event it exercises its option.
KeySpan has an inventory of sulfur dioxide ("SO2") and nitrogen oxide ("NOx")
emission allowances that may be sold to third party purchasers. The amount of
allowances varies from year to year relative to the level of emissions from the
Long Island generating facilities which is greatly dependent on the mix of
natural gas and fuel oil used for generation and the amount of purchased power
that is imported onto Long Island. In accordance with the PSA, 33% of emission
allowance sales revenues attributable to the Long Island generating facilities
is retained by KeySpan and the other 67% is credited to LIPA. LIPA also has a
right of first refusal on any potential emission allowance sales of the Long
Island generating facilities. Additionally, KeySpan is bound by a memorandum of
understanding with the New York State Department of Environmental Conservation
("DEC"), which memorandum prohibits the sale of SO2 allowances into certain
states and requires the purchaser to be bound by the same restriction, which may
affect the market value of the allowances.
Management Services Agreement. Under the MSA, KeySpan performs day-to-day
operation and maintenance services and capital improvements for LIPA's
transmission and distribution system including, among other functions,
transmission and distribution facility operations, customer service, billing and
collection, meter reading, planning, engineering, and construction, all in
accordance with policies and procedures adopted by LIPA. KeySpan furnishes such
services as an independent contractor and does not have any ownership or
leasehold interest in the transmission and distribution system.
In exchange for providing these services, KeySpan is reimbursed its budgeted
costs and entitled to earn an annual management fee of $10 million and may also
earn certain incentives, or be responsible for certain penalties, based upon its
performance. The incentives provide for KeySpan to retain 100% of the first $5
million of cost reductions and 50% of any additional cost reductions up to 15%
of the total cost budget. Thereafter, all savings accrue to LIPA. KeySpan is
also required to absorb any total cost budget overruns up to a maximum of $15
million in any contract year.
In addition to the foregoing cost-based incentives and penalties, KeySpan is
eligible for incentives for performance above certain threshold target levels
and subject to disincentives for performance
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below certain other threshold levels, with an intermediate band of performance
in which neither incentives nor disincentives will apply, for system
reliability, worker safety, and customer satisfaction. In 2000, KeySpan earned
$7.4 million in non-cost performance incentives.
The MSA continues in effect until May 28, 2006. Beginning in 2004, LIPA will
commence a competitive process to solicit a new management services agreement.
Generally, KeySpan will be eligible to submit a bid for any new management
services agreement.
Energy Management Agreement. Pursuant to the EMA, KeySpan (i) procures and
manages fuel supplies for LIPA to fuel the Long Island generating facilities,
(ii) performs off-system capacity and energy purchases on a least-cost basis to
meet LIPA's needs, and (iii) makes off-system sales of output from the Long
Island generating facilities and other power supplies either owned or under
contract to LIPA. LIPA is entitled to two-thirds of the profit from any
off-system electricity sales arranged by us. The term for the service provided
in (i) above is fifteen years, and the term for the services provided in (ii)
and (iii) above is eight years.
In exchange for these services, KeySpan earns an annual fee of $1.5 million,
plus an allowance for certain costs incurred in performing services under the
EMA. The EMA further provides incentives for control of the cost of fuel and
electricity purchased on behalf of LIPA. Fuel and electricity purchase prices
are compared to regional price indices and we receive payment from LIPA, or are
obligated to make payment to LIPA, for fuel and/or purchased electricity costs
which are below or above, respectively, specified tolerance bands. The total
fuel purchase incentive or disincentive can be no greater than $5 million
annually and the electricity purchase incentive or disincentive can be no
greater than $2 million annually (subject to an overall cap including certain
non-cost performance incentives under the MSA). For the year ended December 31,
2000, KeySpan earned an aggregate of $5 million in incentives under the EMA.
Other Rights. As described above, under a "Generation Purchase Rights Agreement"
entered into as part of the LIPA Transaction, LIPA has the right to purchase, at
fair market value, all of our Long Island based generating assets during the
twelve month period beginning on May 28, 2001. Fair market value is to be
determined pursuant to an appraisal process conducted by independent investment
banking firms. During the fourth quarter of 2000, LIPA began an initial due
diligence review of the feasibility of purchasing these assets and has recently
solicited proposals from interested parties to operate the generating facilities
should they purchase them. At this point in time, we can not predict whether
LIPA will exercise its right to purchase the assets, nor can we estimate the
effect on our financial condition, results of operations and cash flows if LIPA
were to exercise such right.
Pursuant to other agreements between LIPA and us, certain future rights have
been granted to LIPA. Subject to certain conditions, these rights include the
right for 99 years to lease or purchase, at fair market value, parcels of land
and to acquire unlimited access to, as well as appropriate easements at, the
Long Island generating facilities for the purpose of constructing new electric
generating facilities to be owned by LIPA or its designee. Subject to this right
granted to LIPA, KeySpan has the right to sell or lease property on or adjoining
the Long Island generating facilities to third parties.
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In addition, LIPA has the right to acquire a parcel at the Shoreham Nuclear
Power Station site suitable as the terminus for a potential transmission cable
under Long Island Sound or the potential site of a new gas-fired combined cycle
generating facility.
KeySpan owns the common plant (such as administrative office buildings and
computer systems) formerly owned by LILCO and recovers LIPA's allocable share of
the carrying costs of such plant through the MSA. KeySpan has agreed to provide
LIPA, for a period of 99 years, the right to enter into leases at fair market
value for common plant or sub-contract for common services which it may assign
to a subsequent manager of the transmission and distribution system. We have
also agreed: (i) for a period of 99 years not to compete with LIPA as a provider
of transmission or distribution service on Long Island; (ii) that LIPA will
share in synergy (i.e., efficiency) savings over a 10-year period attributed to
the 1998 KeySpan/LILCO transaction (estimated to be approximately $1 billion),
which savings are incorporated into the cost structure under the LIPA
Agreements; and (iii) not to commence any tax certiorari case (until termination
of the PSA) challenging certain property tax assessments relating to the Long
Island generating facilities.
Guarantees and Indemnities. KeySpan and LIPA have also entered into agreements
providing 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. KeySpan has assumed all liabilities
arising from all manufactured gas plant ("MGP") operations of LILCO and its
predecessors, and LIPA has assumed certain liabilities relating to the Long
Island generating facilities and all liabilities traceable to the business and
operations conducted by LIPA after completion of the 1998 KeySpan/LILCO
transaction. An agreement also provides for an allocation of liabilities which
relate to the assets that were common to the operations of LILCO and/or shared
services and are not traceable directly to either the business or operations
conducted by LIPA or KeySpan.
For additional information concerning the Electric services segment, see the
discussion on "Electric Services" in Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations" contained herein.
Gas Exploration & Production
KeySpan is engaged in the exploration and production of domestic natural gas and
oil, through our approximate 70% equity interest in Houston Exploration, as of
the date hereof, and through our wholly owned subsidiary, KeySpan Exploration.
Houston Exploration was organized by KeySpan in 1985 to conduct natural gas and
oil exploration and production activities. It completed an initial public
offering in 1996 and its shares are currently traded on the New York Stock
Exchange under the symbol "THX." At March 1, 2001, its aggregate market
capitalization was approximately $898.7 million (based upon the closing price on
the New York Stock Exchange on that date of $29.97). At March 1, 2001, Houston
Exploration had approximately 29,987,041 shares of common stock, $.01 par value,
outstanding. More detailed
-17-
information concerning the operations of Houston Exploration is contained in the
annual, quarterly and periodic reports filed by Houston Exploration with the
SEC.
KeySpan Exploration was organized in 1999, as a Delaware corporation,
principally to form a joint venture with Houston Exploration. Effective January
1, 1999, KeySpan Exploration and Houston Exploration entered into a joint
exploration agreement (the "Joint Venture") to explore for natural gas and oil
over a term of three years and expiring on December 31, 2001, subject to earlier
termination at the option of either party. Houston Exploration contributed all
of its then undeveloped offshore leases to the Joint Venture, and KeySpan
Exploration acquired a 45% working interest in all prospects to be drilled under
the Joint Venture. Houston Exploration retained a 55% interest in the leases,
and the revenues generated from this joint program are shared between KeySpan
Exploration and Houston Exploration on a 45% and 55% basis, respectively.
Effective December 31, 2000, KeySpan Exploration and Houston Exploration
mutually agreed that KeySpan Exploration will no longer participate in future
offshore exploration prospects. Under the terms of the Joint Venture agreement,
KeySpan Exploration will continue to maintain its working interest in all wells
previously drilled under the Joint Venture and will continue the development of
its current working interests in prospects on which discovery wells have been
drilled. In that regard, KeySpan Exploration has agreed to commit approximately
$17 million during 2001 for the development of prospects successfully drilled by
the Joint Venture during 1999 and 2000.
In February 2000, after completing a review of strategic alternatives for
Houston Exploration, we concluded that we would, at this time, retain our equity
interest in that company. However, as previously indicated, we consider our gas
and oil exploration and production activities to be non-core operations and a
future disposition of these assets, for appropriate consideration, is possible.
As previously mentioned, On March 31, 2000, under a pre-existing credit
arrangement, approximately $80 million in debt owed by Houston Exploration to us
was converted into additional common equity in Houston Exploration. Upon such
conversion, our common equity ownership interest increased from 64% to
approximately 70%.
Our gas exploration and production subsidiaries focus their operations offshore
in the Gulf of Mexico and onshore in South Texas, South Louisiana, the Arkoma
Basin, East Texas and West Virginia. The geographic focus of these operations
enables our subsidiaries to manage a comparatively large asset base with
relatively few employees and to add and operate production at relatively low
incremental costs. Our gas exploration and production subsidiaries seek to
balance their offshore and onshore activities so that the lower risk and more
stable production typically associated with onshore properties complement the
high potential exploratory projects in the Gulf of Mexico by balancing risk and
reducing volatility. Houston Exploration's business strategy is to seek to
continue to increase reserves, production and cash flow by pursuing internally
generated prospects, primarily in the Gulf of Mexico, by conducting development
and exploratory drilling on our offshore and onshore properties and by making
selective opportune acquisitions.
Offshore Properties. We hold interests in 106 lease blocks, representing 543,816
gross (442,548 net) acres, in federal and state waters in the Gulf of Mexico, of
which 32 have current operations. Houston Exploration operates 22 of these
blocks, accounting for approximately 80% of our offshore
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production. Over the past five years, we have drilled 28 successful exploratory
wells and 17 successful development wells in the Gulf of Mexico, representing a
historical success rate of 69%. During 2000, Houston Exploration drilled 8
successful exploratory wells and 6 successful development wells on its Gulf of
Mexico properties. The Joint Venture participated in 10 of the successful wells,
all 8 exploratory wells and 2 of the development wells.
Onshore Properties. We also own onshore natural gas and oil properties
representing interests in 1,242 gross (844.1 net) wells, approximately 85% of
which Houston Exploration is the operator of record, and 175,320 gross (109,657
net) acres. Over the past five years, we have drilled or participated in the
drilling of 140 successful development wells and 7 successful exploratory wells
onshore, representing a historical success rate of 84%, through our interest in
Houston Exploration. During 2000, Houston Exploration participated in the
drilling of 44 successful development wells and 1 successful exploratory well on
its onshore properties. During the same period, Houston Exploration drilled or
participated in the drilling of 4 development wells that were not successful.
We did not acquire any onshore properties during 2000. Houston Exploration plans
to drill 4 onshore exploratory wells and 40 onshore development wells in 2001.
For additional information concerning the Gas Exploration and Production
segment, see the discussion on "Gas Exploration and Production" in Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" and for information with respect to net proved reserves, production,
productive wells and acreage, undeveloped acreage, drilling activities, present
activities and drilling commitments see Note 17 to the Consolidated Financial
Statements, "Supplemental Gas and Oil Disclosures," included herein.
Energy Services
As part of our business strategy, we will continue to develop and grow our
energy services activities through our non-regulated subsidiaries. The Energy
Services segment provides services to customers located within the New York City
metropolitan area, New Jersey, Connecticut, Massachusetts, New Hampshire, Rhode
Island and Pennsylvania through various subsidiaries which operate under the
following four principal lines of business: (i) home energy services, which
provides residential and small commercial customers with service and maintenance
of energy systems and appliances, as well as the competitive retail supply of
natural gas and electricity to residential and small commercial customers; (ii)
business solutions, which provides engineering, consulting and construction
services, services related to the design, construction, installation, operation,
maintenance and management of heating, cooling and power production equipment
and systems, including ventilating, air conditioning, electrical power, motors,
pumps, lighting, water, wastewater, plumbing, piping, fire suppression systems,
for commercial and industrial customers, as well as the competitive retail
supply of natural gas and electricity to large commercial, institutional and
industrial customers. Certain subsidiaries within this line of business also
engage or may engage in the financing and ownership of cogeneration, small power
production, thermal energy, chilled water and related equipment and facilities;
(iii) commodity procurement, which provides management and procurement services
for fuel supply and management of energy sales, primarily for and from the
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Ravenswood facility, as well as provides wholesale gas and electric purchasing
and management services; and (iv) fiber optic services in which we construct
fiber optic systems and facilities and own and lease fiber optic cable to local,
long distance, and trans-Atlantic carriers, as well as internet service
providers.
Other energy services that we are engaged in include energy related internet
activities, microturbines and fuel cells.
Internet Activities. During 2000, we launched the myHomeKey.com portal. Through
our exclusive arrangement with myHomeKey.com, we created alliances with other
businesses to create a source for a wide array of home products and services, as
well as individualized community information. MyHomeKey provides customers with
the ability to electrically manage a myriad of household tasks by linking them
with quality service providers, allowing on-line scheduling of home repairs and
maintenance, convenient shopping for home appliances, one-stop shopping for
utility services and access to energy saving equipment and systems.
Alternative Generation Technologies. KeySpan is also engaged in alternative
generation technologies such as microturbines. In 2000, we successfully
installed the first microturbine unit on Long Island at the Atlantis Marine
World Aquarium. The unit, which runs on natural gas, produces up to 28 kilowatts
of electricity for the aquarium and uses its exhaust heat to provide hot water
to the facility's shark tank.
KeySpan expanded its energy services operations through the acquisition of four
additional companies located in the New York City metropolitan area. The newly
acquired companies specialize in engineering-consulting, plumbing and mechanical
contracting and HVAC contracting. Additionally, Eastern and ENI each had
unregulated energy services operations in Massachusetts and New Hampshire which
have expanded our energy services operations further into the Northeast. The
Energy Services segment now has more than 3,000 employees, 100,000 commodity
contracts and is the number one oil to gas conversion contractor in its service
territories.
KeySpan's energy services operations compete with the marketing and management
operations of both independent and major energy companies in addition to
electric utilities, independent power producers, local distribution companies
and various energy brokers. As a result of the continuing efforts to deregulate
both the natural gas and electric industries, the relative energy cost
differences among different forms of energy are expected to be reduced in the
future. Competition is based largely upon pricing, availability and reliability
of supply, technical and financial capabilities, regional presence and
experience. With our strong market presence in the Northeast centered on our gas
distribution services and by taking advantage of the increasing trend towards
deregulation, KeySpan believes it is well positioned to provide our customers
with an expanded array of energy products and services through our unregulated
energy service companies.
For additional information concerning the Energy Services segment, see the
discussion on "Energy Services" in Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations" contained herein.
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Energy Investments
As one of our complementary non-core lines of business, KeySpan has investments
in certain energy related businesses, including natural gas pipelines, gas
storage facilities and midstream natural gas processing and gathering facilities
in the Northeast region of the United States, Canada and Northern Ireland.
Natural Gas Pipelines. KeySpan owns a 20% interest in Iroquois Gas Transmission
System, L.P., the partnership that owns a 375-mile pipeline that currently
transports 946 MDTH of Canadian gas supply daily from the New York-Canadian
border to markets in the Northeastern United States. KeySpan is also a shipper
on Iroquois and currently transports up to 137 MDTH of gas per day on the
pipeline.
KeySpan also is participating in two intra-regional pipeline projects, the Cross
Bay Pipeline and the Islander East Pipeline. The Cross Bay Pipeline Company,
LLC, is a joint venture among Duke Energy Corporation, The Williams Companies
and KeySpan to transport 125 MDTH of gas from two existing interstate pipelines
located in New Jersey to customers located in New York City and Long Island.
KeySpan has a 25% interest in this project. Additionally, in 2000, KeySpan
entered into another joint venture with Duke to construct the Islander East
Pipeline. KeySpan and Duke each hold a 50% interest in Islander East Pipeline
Company, LLC, which will bring 250 MDTH of gas from Nova Scotia, Canada to Long
Island, New York and will provide an additional connection to supplies in our
New England market. The Islander East Pipeline is scheduled to become
operational in 2003.
KeySpan also owns a 50% interest in Premier Transco Pipeline and a 24.5%
interest in Phoenix Natural Gas Limited both in Northern Ireland. Premier is an
84-mile pipeline to Northern Ireland from southwest Scotland that has planned
transportation capacity of approximately 300 MDTH of gas supply daily to markets
in Northern Ireland. Phoenix is a gas distribution system serving the City of
Belfast, Northern Ireland.
Gas Storage Facilities. KeySpan has equity investments in two gas storage
facilities in the State of New York. Honeoye Storage Corporation and Steuben Gas
Storage Company. We own a 52% interest in Honeoye, an underground gas storage
facility which provides up to 4.8 billion cubic feet of storage service to New
York and New England. We also own 34% of a partnership that has a 50% interest
in the Steuben facility which provides up to 6.2 billion cubic feet of storage
service to New Jersey and Massachusetts.
Natural Gas Processing and Gathering Facilities. KeySpan also owns 100% of
KeySpan Canada, a company with natural gas processing plants and gathering
facilities located in Western Canada. In October 2000, KeySpan purchased the
remaining 50% interest in KeySpan Canada from Gulf Canada Resources Limited. The
assets include interests in 14 processing plants and associated gathering
systems that can process approximately 1.5 BCFe of natural gas daily, and
associated natural gas liquids fractionation. Additionally, KeySpan owns a 37%
interest in the Paddle River processing plant in Western Canada and an interest
in the Younger NGL Extraction plant in British
-21-
Columbia, Canada. In 2000, KeySpan sold its interest in the Nipisi oil property
in Western Canada, and realized an after-tax gain of approximately $1.3 million
from the sale.
For additional information concerning the Energy Investments segment, see the
discussion on "Energy Investments" in Item 7, Management's Discussion and
Analysis of Financial Condition and Results of Operations" contained herein.
The Industry, Regulation and Rate Matters
The Industry
The natural gas and electric sectors of the regulated energy industry are
undergoing significant change as market forces are moving towards replacing or
supplementing rate regulation by introducing competition. Competition can
present utilities with greater opportunities to manage the cost of their natural
gas and electric supplies, as well as earn profits on energy sales and expand
their business activities, through unregulated affiliates.
A significant number of natural gas and electric utilities have 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 have engaged in two such combinations,
the KeySpan/LILCO transaction in 1998 and our recent acquisitions of Eastern and
ENI. For further information regarding the gas and electric industry, see Item
7A, Quantitative and Qualitative Disclosure About Market Risk.
Regulation and Rate Matters
Gas and electric public utility companies, and corporations which own gas and
electric public utility companies (i.e., public utility holding companies) may
be subject to either or both state and federal regulation. In general, state
public utility commissions, such as the NYPSC, DTE and NHPUC regulate the
provision of retail services, including the distribution and sale of natural gas
and electricity to consumers. FERC regulates interstate natural gas
transportation and electric transmission, and has jurisdiction over certain
wholesale natural gas sales and wholesale electric sales. Public utility holding
companies, especially those with operations in several states, are regulated by
the SEC under PUHCA and to some extent by state utility commissions through the
regulation of corporate, financial and affiliate activities of public utilities.
KeySpan and its subsidiaries are subject to regulation by the NYPSC, DTE, NHPUC,
FERC and the SEC. The NYPSC regulates KEDNY and KEDLI, and indirectly KeySpan
itself, through conditions which were attached to the NYPSC order authorizing
the 1998 KeySpan/LILCO transaction. The NYPSC also regulates the safety and
reliability of KeySpan's generating facilities on Long Island and at Ravenswood
under a lightened regulatory standard. Those conditions addressed the manner
-22-
in which KeySpan may interact with KEDNY and KEDLI. Similarly, we are now
subject to regulation by the DTE and NHPUC for our KEDNE subsidiaries.
For information regarding the NYPSC, DTE and SEC, see the discussion in Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations, "Regulation and Rate Matters."
FERC regulates the sale of electricity at wholesale and the transmission of
electricity in interstate commerce as well as certain corporate and financial
activities of companies that are engaged in such activities. The Long Island
generating facilities and the Ravenswood facility are subject to FERC regulation
based on their wholesale energy transactions. LIPA, KeySpan and the Staff of
FERC stipulated a five-year rate plan for the Long Island generating facilities
with agreed-upon yearly adjustments, which has been approved by FERC. Our
Ravenswood facility's rates are based on a market-based rate application
approved by FERC. The rates that our Ravenswood facility may charge are subject
to mitigation measures due to market power concerns of FERC. FERC retains the
ability in future proceedings, either on its own motion or upon a complaint
filed with FERC, to modify the Ravenswood facility's rates, either upward or
downward, if FERC concludes that it is in the public interest to do so.
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, KEDNE purchase or sell gas for resale
in interstate commerce, such transactions are subject to FERC jurisdiction and
have been authorized by the FERC.
Our interests in Iroquois, Honeoye and Steuben are also fully regulated by FERC
as natural gas companies.
KeySpan's electric operations in New York City are also subject to oversight by
the FERC approved NYISO. KeySpan currently bids and sells the energy capacity
and ancillary services from the Ravenswood facility through the energy market
operated by the NYISO. For information concerning the NYISO, see Note 8 to the
Consolidated Financial Statements, "New York Independent System Operator
Matters."
KeySpan's foreign operations in Northern Ireland, conducted through Premier and
Phoenix, are subject to licensing by the Northern Ireland Department of Economic
Development and regulation by the U.K. Department of Trade and Industry (with
respect to the subsea and on-land portions of the Premier pipeline) and the
Northern Ireland Director General, Office for the Regulation of Electricity and
Gas (with respect to the Northern Ireland portion of the Premier pipeline and
Phoenix's operations generally). The licenses establish mechanisms for the
establishment of rates for the conveyance and transportation of natural gas, and
generally may not be revoked except upon long- term notice. Charges for the
supply of gas by Phoenix are largely unregulated unless a determination is made
of an absence of competition.
-23-
KeySpan's assets in Canada are subject to regulation by Canadian federal and
provincial authorities. Such regulatory authorities license various aspects of
the facilities and pipeline systems as well as regulate safety, operational and
environmental matters and certain changes in such facilities' and pipelines'
capacities and operations.
Environmental Matters
Overview
KeySpan's ordinary business operations subject it to various federal, state and
local laws, rules and regulations dealing with the environment, including air,
water, and hazardous waste, and its business operations are regulated by various
federal, regional, state and local. These requirements govern both our normal,
ongoing operations and the remediation of contaminated 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 9 to the Consolidated Financial Statements
"Contractual Obligations and Contingencies - Environmental Matters", no material
proceedings relating to environmental matters have been commenced or, to our
knowledge, are contemplated by any federal, state or local agency against
KeySpan, and we are not a defendant in any material litigation with respect to
any matter relating to the protection of the environment. We believe that our
operations are in substantial compliance with environmental laws and that
requirements imposed by environmental laws are not likely to have a material
adverse impact upon us. We believe that all prudently incurred costs not
recoverable through insurance or some other means with respect to environmental
requirements will be recoverable from our customers. We are also pursuing claims
against insurance carriers and potentially responsible parties which seek the
recovery of certain costs associated with the investigation and remediation of
contaminated properties.
Air. Federal, state and local laws currently regulate a variety of air emissions
from new and existing electric generating plants, including SO2, NOx, opacity
and particulate matter and, in the future, may also regulate emissions of fine
particulate matter, hazardous air pollutants, and carbon dioxide. We have
submitted timely applications for permits in accordance with the requirements of
Title V of the 1990 amendments to the Federal Clean Air Act ("CAA"). Final
permits have been issued for all of our electric generating facilities. The
permits allow our electric generating plants to continue to operate without any
additional significant expenditures, except as described below.
Our generating facilities are located within a CAA severe ozone non-attainment
area, and are subject to the Phase I, II, and III NOx reduction requirements
established under the Ozone Transportation Commission ("OTC") memorandum of
understanding. Our investments in boiler combustion modifications and the use of
natural gas firing at our steam electric generating stations have enabled us to
achieve the NOx emission reductions required under Phase I and II in a
cost-effective manner. We are awaiting final development of state and federal
regulatory programs with respect to NOx reduction requirements for our existing
power plants. Our compliance strategy may be composed of fuel choice decisions,
acquisition of emission credits, and installation of emission control
-24-
equipment. The extent of development of new generation in the region will also
impact our compliance strategy. Although we are evaluating our alternatives,
final decisions cannot be made until pending regulatory requirements and new
generation decisions are clarified. Expenditures to address emission reduction
requirements through the year 2004 are expected to be between $10 million and
$15 million.
Water. We possess permits for our generating units which authorize discharges
from cooling water circulating systems and chemical treatment systems. These
permits are renewed from time to time, as required by regulation. Additional
capital expenditures associated with the renewal of the surface water discharge
permits for our power plants may be required by the DEC. Until our monitoring
obligations are completed and changes to the Environmental Protection Agency
regulations under Section 316 of the Clean Water Act are promulgated, the need
for and the cost of equipment upgrades cannot be determined.
On behalf of LIPA, we provide management and operations support for the
LIPA-Connecticut Light and Power Company electric transmission cable system
located under the Long Island Sound (the "Sound Cable"). The Connecticut
Department of Environmental Protection and the DEC separately have issued
Administrative Consent Orders ("ACOs") in connection with releases of insulating
fluid from the Sound Cable. The ACOs require the submission of a series of
reports and studies describing cable system condition, operation and repair
practices, alternatives for cable improvements or replacement, and environmental
impacts associated with prior leaks of fluid into the Long Island Sound.
Compliance activities associated with the ACOs are ongoing and are recoverable
from LIPA under the MSA.
In addition, we will be responsible for environmental obligations relating to
the Ravenswood facility operations other than liabilities arising from
pre-closing disposal of waste at off-site locations and any monetary fines
arising from Consolidated Edison's pre-closing conduct.
Superfund Sites. Federal and New York State Superfund laws impose liability,
regardless of fault, upon generators of hazardous substances for costs
associated with remediating contaminated property. In the course of our business
operations, we generate materials which are subject to these laws. From time to
time, we have received notices under these laws concerning possible claims with
respect to sites at which hazardous substances generated by KeySpan and other
potentially responsible parties allegedly were disposed.
For further information concerning environmental matters and a discussion on our
MGP sites, see Note 9 to the Consolidated Financial Statements, "Contractual
Obligations and Contingencies - Environmental Matters."
Employee Matters
On December 31, 2000, KeySpan and its wholly owned subsidiaries had
approximately 13,000 employees. Of that total, approximately 6,5602 employees in
our regulated companies are covered under collective bargaining agreements.
KeySpan has not experienced any work stoppage during
-25-
the past five years and considers its relationship with employees, including
those covered by collective bargaining agreements, to be good.
Executive Officers of the Company
Certain information regarding executive officers of KeySpan and certain of its
subsidiaries is set forth below:
Robert B. Catell
Mr. Catell, age 64, 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 served as President and Chief Executive
Officer from 1991 to 1996, when he was elected Chairman and Chief Executive
Officer. In 1997, Mr. Catell was elected Chairman, President and Chief Executive
Officer of the KEDNY and its parent KSE.
Joseph A. Bodanza
Mr. Bodanza, age 53, was elected Senior Vice President and Chief Financial
Officer of KEDNE in November 2000, upon the acquisition of Eastern and ENI. Mr.
Bodanza previously served as Senior Vice President of Finance and Management
Information Systems and Treasurer of Eastern's Gas Distribution Operations. Mr.
Bodanza joined Boston Gas in 1972 and held a variety of positions in the
financial and regulatory areas before becoming Treasurer in 1984. He was elected
Vice President and Treasurer in 1988.
Lawrence S. Dryer
Mr. Dryer, age 41, was elected Vice President of Internal Audit for KeySpan in
September 1998. Mr. Dryer had been with the LILCO since 1992 as Director of
Internal Audit and was responsible for providing independent appraisals and
recommendations to improve management controls and increase operational
efficiency. Prior to joining LILCO, Mr. Dryer was an Audit Manager with Coopers
& Lybrand.
Robert J. Fani
Mr. Fani, age 47, was elected Executive Vice President of Strategic Services in
February 2000. Mr. Fani joined KEDNY in 1976, and held a variety of management
positions in distribution, engineering, planning, marketing, and business
development. He was elected Vice President in 1992. In 1997, Mr. Fani was
promoted to Senior Vice President of Marketing and Sales for KEDNY. In 1998, he
assumed the position of Senior Vice President of Marketing and Sales for the
merged KeySpan/LILCO company. On September 1, 1999, he became Senior Vice
President for Gas Operations until assuming his current position in February
2000.
-26-
William K. Feraudo
Mr. Feraudo, age 51, was elected Executive Vice President of the KeySpan
Services Group in February 2000. KeySpan Services Group, is the group of
non-regulated companies that engage in our energy services business and focus on
gas and electric marketing, energy management, telecommunications and fuel
procurement. Since its founding in 1996, the KeySpan Services Group has grown to
more than 3,000 employees, serving customers in the Northeast. Mr. Feraudo began
his career at KEDNY in 1971 and rose through a succession of positions in
Information Systems, Engineering, Customer Operations, Sales, Marketing, and
Product Development before being named Senior Vice President in 1994. He served
as Senior Vice President of Energy Services for KeySpan prior to his promotion
to Executive Vice President.
Ronald S. Jendras
Mr. Jendras, age 53, was named Vice President, Controller and Chief Accounting
Officer of KeySpan in August 1998. He joined KEDNY in 1969 and held a variety of
positions in the Accounting Department before being named budget director in
1973. In 1983, Mr. Jendras was promoted to manager of KED's Rate and Regulatory
Affairs area, and in 1997, was named general manager of the Accounting Division.
Gerald Luterman
Mr Luterman, age 57, has served as Senior Vice President and Chief Financial
Officer since July 1999. He formerly served as Chief Financial Officer of
barnesandnoble.com and Senior Vice President and Chief Financial Officer of
Arrow Electronics, Inc., a distributor of electronic components and computer
products. Prior to that, from 1985 through 1996, he held executive positions
with American Express, including Executive Vice President and Chief Financial
Officer of the Consumer Card Division from 1991-1996.
David J. Manning
Mr. Manning, age 50, was elected Senior Vice President of KeySpan Corporate
Affairs division 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, the source of approximately 14 percent of the natural gas supply serving
United States markets. 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.
Craig G. Matthews
Mr. Matthews, age 58, was elected as a Director and as Vice-Chairman effective
March 2001. He serves as Chief Operating Officer of KeySpan and KEDNY since
January 1999, and served as President of KeySpan until his recent promotion to
Vice Chairman. Mr. Matthews joined KEDNY in 1965 and held various management
positions in the corporate planning, financial, marketing, and
-27-
engineering areas. He has been an officer since 1977. He was elected Vice
President in 1981 and Senior Vice President in 1985. In 1991, Mr. Matthews was
named Executive Vice President with responsibilities for KEDNY's financial, gas
supply, information systems, and strategic planning functions, as well as
KEDNY's energy-related investments. In 1996, Mr. Matthews was promoted to
President and Chief Operating Officer. He also served as Executive Vice
President and Chief Financial Officer of KeySpan from May 1998 through August
1999.
Chester R. Messer
Mr. Messer, age 59, was elected Executive Vice President in November 2000, upon
the acquisition of Eastern and ENI. He also serves as President of each of the
KEDNE companies. Mr. Messer joined Boston Gas Company as a management trainee in
1963 and rose through a succession of positions and was elected President in
November 1988.
H. Neil Nichols
Mr. Nichols, age 63, was elected Senior Vice President of KeySpan's Corporate
Development & asset Management division in March 1999. He also serves as
President of KeySpan Energy Development Corporation (KEDC), a position to which
he was elected in March 1998. KEDC is a wholly owned subsidiary of KeySpan
responsible for our Energy Investments group that engages in energy-related
investment project development efforts, both domestically and internationally.
Since February 1999, Mr. Nichols also has responsibility for KeySpan Energy
Trading Services, LLC, which provides fuel procurement management and energy
trading services for KEDNY, KEDLI and LIPA. Mr. Nichols joined KeySpan in 1997
as a broad-based negotiator and business strategist with comprehensive finance
and treasury experience in domestic and international markets. Prior to joining
KeySpan, Mr. Nichols was an owner and president of Corrosion Interventions, Ltd.
in Toronto, Canada. He also served as Chief Financial Officer and Executive Vice
President with TransCanada.
Anthony Nozzolillo
Mr. Nozzolillo, age 52, 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. He served as Senior Vice President of
Finance of KeySpan from May 1998 to December 1998. He also serves as a Director
to the Long Island Museum of Science and Technology.
Wallace P. Parker Jr.
Mr. Parker, age 51, was elected Executive Vice President of Gas Operations in
February 2000. He previously served as KeySpan's Senior Vice President of Human
Resources from August 1998 to January 2000. He joined KEDNY in 1971 and served
in a wide variety of management positions.
-28-
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.
Lenore F. Puleo
Ms. Puleo, age 47, was elected Executive Vice President of Shared Services in
February 2000. She previously served as Senior Vice President of Customer
Relations for KEDNY from May 1994 to 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.
Richard A. Rapp, Jr.
Mr. Rapp, age 42, was elected Vice President and Deputy General Counsel in
February 2000 and in June 2000, he assumed the additional responsibility of
Secretary. He joined LILCO in 1984 and has held various positions in the Legal
Departments of LILCO, and since 1998, KeySpan, including Assistant General
Counsel. Mr. Rapp received a Bachelor of Science degree in Accounting from
Boston College's Carroll School of Management's Honors Program, and he holds a
Juris Doctor degree from Fordham University's School of Law.
Cheryl T. Smith
Ms. Smith, age 49, joined KeySpan in November 1998. She serves as Senior Vice
President and Chief Information Officer of KeySpan's Information technology
division. She came to KeySpan from Verizon (Bell Atlantic) where she served as
Vice President of Strategic Systems and Corporate Systems from 1995 through
1998. Prior to Bell Atlantic, she worked at Honeywell Federated Systems Inc. as
the Director of MIS for Honeywell Federal Systems, Inc. Ms. Smith brings to
KeySpan more than 25 years of information systems technology experience.
Michael J. Taunton
Mr. Taunton, age 45, has been KeySpan's Vice President and Treasurer since June
2000. Prior to that time, he served as Vice President of Investor Relations
since September 1998. He joined KEDNY in 1975 and has worked in various
management positions in Marketing and Sales, Corporate Planning, Corporate
Finance and Accounting. During the transition process of the KeySpan/LILCO
merger, he co-managed the day-to-day operations of the merger. Before that, Mr.
Taunton was General Manager of the Business Process Improvement teams that were
organized to improve the organization's strategic focus.
Colin P. Watson
Mr. Watson, age 49, was named Senior Vice President of KeySpan's Strategic
Marketing and E-Business division effective March 1, 2000. He previously served
as Vice President of Strategic
-29-
Marketing from May 1998 until his promotion to Senior Vice President. Mr Watson
joined KEDNY in 1997 as Vice President of Strategic Marketing. From 1973 to
1997, he held several positions at NYNEX, including Vice President and Managing
Director of worldwide operations.
Elaine Weinstein
Ms. Weinstein, age 46, was named Senior Vice President of KeySpan's Human
Resources division in November 2000. She previously served as Vice President of
Staffing Organizational Development since September 1998. Prior to that time,
Ms. Weinstein was General Manager of Employee Development since joining KeySpan
in 1995. Prior to 1995, Ms. Weinstein was Vice President of Training and
Organizational Development at Merrill Lynch.
Steven L. Zelkowitz
Mr. Zelkowitz, age 51, was elected Senior Vice President and General Counsel of
KeySpan in February 2000. He joined KeySpan as Senior Vice President and Deputy
General Counsel in October 1998. Before joining the Company, Mr. Zelkowitz
practiced law with Cullen and Dykman in Brooklyn, New York and had been a
partner since 1984. He served on the firm's Executive Committee and was head of
its Corporate/Energy Department. Mr. Zelkowitz specialized in energy and utility
law and represented investor-owned and municipal gas and electric utilities in
New York, New Jersey and Vermont.
-30-
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 oil and gas properties, held under long-term mineral leases. In addition
to the information set forth therein with respect to properties utilized by each
business segment, KeySpan owns or leases a variety of office space used for its
administrative operations. In the case of leased office space, we anticipate no
significant difficulty in leasing alternative space at reasonable rates in the
event of the expiration, cancellation or termination of a lease relating to our
leased properties.
Item 3. Legal Proceedings
See Note 9 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, 2000.
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
KeySpan's common stock is listed and traded on the New York Stock Exchange and
the Pacific Stock Exchange under the symbol "KSE." As of March 1, 2001, there
were approximately 88,640 registered record holders of KeySpan's common stock.
The following table sets forth, for the quarters indicated, the high and low
sales prices and dividends declared per share for the periods indicated:
2000 High Low Dividends Per Share
- -------------------------- --------------- --------------------- -------------------------
First Quarter 27.188 20.188 $0.445
Second Quarter 32.688 26.000 $0.445
Fourth Quarter 43.625 33.500 $0.445
1999 High Low Dividends Per Share
- ------------------------- ---------------- --------------------- -------------------------
First Quarter 31.313 25.125 $0.445
Second Quarter 27.690 24.250 $0.445
Third Quarter 31.060 26.380 $0.445
Fourth Quarter 29.690 22.630 $0.445
Item 6. Selected Financial Data
(In Thousands of Dollars, Except Per Share Amounts)
- ------------------------------------------------------------------------------------------------------------------------------------
Nine Months Twelve Months
Year Ended Year Ended Ended Year Ended Ended
December 31, 2000 December 31, 1999 December 31, 1998 March 31, 1998 March 31, 1997
- ------------------------------------------------------------------------------------------------------------------------------------
Income Summary
Revenues
Gas Distribution $ 2,555,785 $ 1,753,132 $ 856,172 $ 645,659 $ 672,705
Electric Services 1,444,711 861,582 408,305 - -
Electric Distribution - - 330,011 2,478,435 2,464,957
Gas Exploration and Production 274,209 150,581 70,812 - -
Energy Services and Other 846,785 189,318 63,181 - -
- ------------------------------------------------------------------------------------------------------------------------------------
Total revenues 5,121,490 2,954,613 1,728,481 3,124,094 3,137,662
Operating expenses
Purchased gas 1,408,621 744,432 331,690 299,469 308,400
Fuel and purchased power 460,900 17,252 91,762 658,338 646,448
Operation and maintenance 1,695,507 1,091,166 777,678 511,165 489,868
Depreciation, depletion and
amortization 335,106 253,440 254,859 183,129 276,615
Early retirement and
severance charges 65,175 - 64,635 - -
General taxes 424,318 366,154 257,124 466,326 469,561
- ------------------------------------------------------------------------------------------------------------------------------------
Operating income 731,863 482,169 (49,267) 1,005,667 946,770
Other income (deductions) (11,430) 46,555 (36,727) (6,301) 22,191
- ------------------------------------------------------------------------------------------------------------------------------------
Income (loss) before interest
charges and income taxes 720,433 528,724 (85,994) 999,366 968,961
Interest charges 203,350 133,751 140,733 404,473 435,219
Income taxes (credits) 216,276 136,362 (59,794) 232,653 211,333
- ------------------------------------------------------------------------------------------------------------------------------------
Net income (loss) 300,807 258,611 (166,933) 362,240 322,409
Preferred stock dividends 18,113 34,752 28,604 51,813 52,113
- ------------------------------------------------------------------------------------------------------------------------------------
Earnings (loss) for common stock $ 282,694 $ 223,859 $ (195,537) $ 310,427 $ 270,296
- ------------------------------------------------------------------------------------------------------------------------------------
Financial Summary
Earnings (loss) per share ($) 2.10 1.62 (1.34) 2.56 2.24
Cash dividends declared per share ($) 1.78 1.78 1.19 1.78 1.78
Book value per share, year-end ($) 20.65 20.26 20.90 21.88 21.07
Market value per share, year-end ($) 42.38 23.19 31.00 31.50 24.00
Shareholders 86,900 90,500 103,239 78,314 77,691
Capital expenditures ($) 925,257 725,670 676,563 297,230 294,943
Total assets ($) 11,550,121 6,730,691 6,895,102 11,900,725 11,849,574
Common equity ($) 2,815,816 2,712,325 3,022,908 2,662,447 2,549,049
Redeemable preferred stock ($) - 363,000 - 562,600 638,500
Preferred stock ($) 84,205 84,339 447,973 - 63,598
Long term debt ($) 4,274,938 1,682,702 1,619,067 4,381,949 4,457,047
Total capitalization ($) 7,174,959 4,479,366 5,089,948 7,606,996 7,708,194
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Utility Operating Statistics
Firm gas and transportation
sales (MDTH) 306,509 275,771 87,179 58,304 60,276
Other sales (MDTH) 91,406 54,661 38,088 21,025 19,838
Total active gas meters 2,483,730 1,628,497 1,610,202 464,563 458,910
Gas heating customers 1,260,000 677,000 665,000 295,000 289,000
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
KeySpan Corporation (referred to in this Management's Discussion and Analysis of
Financial Condition and Results of Operations as "KeySpan", "we", "us", and
"our") is a registered holding company under the Public Utility Holding Company
Act of 1935, as amended. We operate six utilities that distribute natural gas to
approximately 2.4 million customers in New York City, Long Island, Massachusetts
and New Hampshire making us the fifth largest gas distribution company in the
United States and the largest in the Northeast. We also own and operate
generating plants in Nassau and Suffolk Counties on Long Island and in Queens
County in New York City. Under contractual arrangements, we provide power,
electric transmission and distribution services, billing and other customer
services for approximately one million electric customers of the Long Island
Power Authority ("LIPA"). Our other subsidiaries are involved in gas and oil
exploration and production; gas storage; wholesale and retail gas and electric
marketing; appliance service; heating, ventilation and air conditioning
installation and services; large energy-system ownership, installation and
management; engineering services; fiber optic services; energy-related internet
activities; fuel cells; marine transportation, including the barge hauling of
fuel and other cargo; and providing meter reading equipment and services to
municipal utilities. We also invest in, and participate in the development of,
pipelines and other energy-related projects, domestically and internationally.
(See Note 2 to the Consolidated Financial Statements, "Business Segments" for
additional information on each operating segment.)
KeySpan was formed on May 28, 1998 in connection with a transaction between Long
Island Lighting Company ("LILCO") and LIPA (the "LIPA Transaction") and
immediately prior to the acquisition (the "KeySpan Acquisition") of KeySpan
Energy Corporation ("KSE") and its subsidiaries (collectively, the "KSE-acquired
companies"). (See Note 15 to the Consolidated Financial Statements, "Sale of
LILCO Assets, Acquisition of KeySpan Energy Corporation and Transfer of Assets
and Liabilities to KeySpan" for additional information.)
Further, on November 8, 2000, KeySpan acquired all of the common stock of
Eastern Enterprises ("Eastern") and EnergyNorth, Inc. ("ENI"). The transactions
were accounted for as a purchase, with KeySpan being the acquiring company.
Eastern is a Massachusetts business trust that owns primarily Boston Gas
Company, Colonial Gas Company, Essex Gas Company and Midland Enterprises, Inc.
ENI is a holding company that owns primarily EnergyNorth Natural Gas, a provider
of gas distribution services to customers in New Hampshire. In the aggregate,
our newly acquired subsidiaries provide natural gas distribution service to
approximately 800,000 customers in Massachusetts and New Hampshire. (See Note 12
to the Consolidated Financial Statements, "Eastern/EnergyNorth Acquisition" for
further details.)
1
Current period consolidated results of operations reflect the results of
operations for Eastern and ENI for the period November 8, 2000 through December
31, 2000. As required under purchase accounting, reported results of operations
for all periods prior to November 8, 2000 do not reflect the operating results
of Eastern and ENI.
In 1998, KeySpan changed its fiscal year end from March 31 to December 31.
Therefore, results of operations for the period ended December 31, 1998 reflect
the nine month transition period April 1, 1998 to December 31, 1998 (the
"Transition Period"). The Transition Period consists of the following: (i) the
period April 1, 1998 through May 28, 1998, which reflects the results of LILCO
only prior to the LIPA Transaction and KeySpan Acquisition; and (ii) the period
May 29, 1998 through December 31, 1998, which represents fully consolidated
results, including the KSE-acquired companies, i.e. The Brooklyn Union Gas
Company d/b/a KeySpan Energy Delivery New York ("KEDNY") and subsidiaries
comprising the Gas Exploration and Production, Energy Services and Energy
Investment segments. As required under purchase accounting, the results of
operations for all periods prior to May 29, 1998 reflect results of LILCO only,
and do not include results of KSE, since for accounting purposes, LILCO acquired
KSE as of May 29, 1998.
Due to the change in the composition of our operations and the change in our
fiscal year, both occurring in 1998, results of operations for the Transition
Period are not comparable to the results of operations for the years ended
December 31, 2000 and December 31, 1999. Also, since the Transition Period
reflects results for the period April 1, 1998 through December 31, 1998,
earnings from gas heating-season operations are not reflected in Transition
Period results. Approximately 80% of our gas distribution-related earnings, or
approximately 40% of our consolidated earnings, are realized during the months
of January through March, due to the large percentage of gas heating sales to
total gas sales.
Since the Transition Period is not comparable to the years ended December 31,
2000 and December 31, 1999, we have provided operating results for the full
twelve months ended December 31, 1998 in our discussions of operating results
for each business segment. The intent of this additional disclosure is to
provide a better explanation of the variations in operating results between
comparable twelve month periods for our on-going business activities. (See
"Segment Review of Operations - Combined Company Comparison.")
The commentary that follows should be read in conjunction with the Notes to the
Consolidated Financial Statements.
2
Consolidated Review of Results
- ------------------------------
Earnings Summary
Consolidated income (loss) available for common stock by reporting segment is
set forth in the following table for the periods indicated:
(In Thousands of Dollars)
- ----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2000 April 1, 1998 through December 31, 1998
--------------------------------------------- ---------------------------------------------
Before Early
Retirement Early After Early
and Retirement Retirement and Year Ended Before Early Early After Early
Severance and Severance Severance December 31, Retirement Retirement Retirement
Charges Charges Charges 1999 Charge Charge Charge
- --------------------- --------------- --------------- ------------------------------- --------------- ------------- ----------------
Gas Distribution $ 187,342 $ 27,164 $ 160,178 $ 151,217 $ 8,582 $ 8,724 $ (142)
Electric Services 122,188 191 121,997 77,099 57,119 13,525 43,594
Gas Exploration
and Production 58,211 - 58,211 15,772 2,218 - 2,218
Energy Services 40,946 - 40,946 (2,528) (3,212) - (3,212)
Energy Investments 13,929 - 13,929 8,543 (4,186) - (4,186)
Other (98,850) 13,717 (112,567) (26,244) (52,036) 19,763 (71,799)
- -----------------------------------------------------------------------------------------------------------------------------------
Consolidated $ 323,766 $ 41,072 $ 282,694 $ 223,859 $ 8,485 $ 42,012 $ (33,527)
Special Charges (162,010)
- -----------------------------------------------------------------------------------------------------------------------------------
Consolidated $ (195,537)
- --------------------- --------------- --------------- ------------------------------- --------------- ------------- ----------------
Consolidated earnings for 2000 were $2.10 per share compared to $1.62 per share
in 1999. Consolidated results for 2000 reflect a charge of $41.1 million
after-tax, or $0.31 per share, associated with early retirement and severance
programs that were implemented upon the successful completion of the Eastern and
ENI acquisitions. Excluding these charges, consolidated earnings for 2000 were
$2.41 per share. Our average common shares outstanding were approximately three
percent lower for the year ended December 31, 2000 compared to the year ended
December 31, 1999 due to a stock repurchase program in 1999. The lower shares
outstanding had a favorable affect on earnings per share of approximately $0.06.
Consolidated results for the Transition Period reflect a loss of $1.34 per
share. During the Transition Period, we: (i) incurred a charge of $42.0 million
after-tax, or $0.29 per share, associated with implementing an early retirement
program; (ii) incurred substantial non-recurring charges associated with the
LIPA Transaction of $107.9 million after-tax, or $0.74 per share, principally
reflecting taxes associated with the sale of assets to KeySpan by LIPA and the
write- off of certain regulatory assets that were no longer recoverable under
various LIPA agreements; and (iii) recorded an after-tax non-cash impairment
charge of $54.1 million, or $0.37 per share, representing our share of the
impairment charge recorded by our gas exploration and production subsidiary, The
Houston Exploration Company ("Houston Exploration") to recognize the effect of
lower wellhead prices on its valuation of proved gas reserves. (See Note 16 to
the Consolidated Financial Statements, "Costs Related to the LIPA Transaction
and Special Charges" for further details of these charges.) Excluding these
early retirement and special charges, earnings for the Transition Period were
$8.5 million, or $0.06 per share.
The increase in earnings for 2000 over 1999, and for 1999 over the Transition
Period resulted from solid performance across all of our business segments.
Further, as has been previously noted, earnings for the Transition Period
include only seven months of results of operations for the KSE- acquired
companies and do not reflect heating season operations (months of January
through March) when approximately 80% of our gas related earnings are realized.
The increase in earnings from the Gas Distribution segment for 2000, compared to
last year reflects revenue benefits from continued gas sales growth, favorable
gas prices compared to oil prices for most of the year and earnings from our
newly acquired gas distribution companies. Since the date of acquisition, the
combined gas distribution operations of Eastern and ENI added $22.3 million to
consolidated earnings. The increase in Gas Distribution earnings in 1999
compared to the Transition Period reflects, primarily the addition of KEDNY for
a full twelve month period and earnings generated for an entire heating season.
Earnings growth in both 2000 and 1999 associated with our Electric Service
segment reflects primarily the operations associated with our investment in the
2,200 megawatt Ravenswood electric generation facility, ("Ravenswood facility")
located in Queens, New York. The Ravenswood facility was acquired in June 1999
and therefore, earnings for 2000 reflect a full year of operations, while 1999
reflects less than seven full months of operations. Earnings from our Energy
Services segment in 2000 were derived largely from inter-company fuel
procurement and energy management services provided to the Ravenswood facility,
as well as earnings from our recently acquired companies that provide
energy-related services.
Consolidated earnings for 2000 compared to 1999 were further enhanced through
improved performance from our Gas Exploration and Production segment and Energy
Investments segment. Gas exploration and production operations benefitted from
significantly higher realized gas prices and increased production volumes in
2000. In addition, on March 31, 2000 we increased our ownership in Houston
Exploration from 64% to 70%. Results of operations in 1999 reflect gas
exploration and production operations for a full twelve months compared to seven
months for the Transition Period, as well as the benefit from the combined
effect of increases in both gas production volumes and gas prices. Energy
Investments reflect the continued development and integration of companies
acquired over the past few years.
The Other segment reflects preferred stock dividends, general expenses incurred
by our corporate and administrative areas that have not been allocated to our
various business segments, and interest income earned on temporary cash
investments. The significant increase in the loss incurred by the Other segment
in 2000 compared to 1999 reflects the following: (i) additional contributions to
the KeySpan Foundation, a not-for-profit philanthropic foundation that makes
3
donations to local charitable community organizations; (ii) charges related to
certain rate settlement issues; (iii) losses incurred with our investment in
certain technology-related activities; (iv) branding expenses and other charges
related to the integration of the Eastern and ENI companies into KeySpan
operations; (v) an increase in interest expense associated with higher levels of
commercial paper outstanding; and (vi) lower interest income on temporary cash
investments. The Other segment showed a smaller loss in 1999 compared to the
Transition Period. Transition Period results reflected a donation to establish
the KeySpan Foundation and a charge to write-off a customer-billing system that
was in development.
Revenues
Consolidated revenues are derived primarily from our two core operating segments
- - Gas Distribution and Electric Services. In 2000, these two core segments
accounted for approximately 78% of consolidated revenues. For 2000 consolidated
revenues were $5.1 billion, compared to $3.0 billion for 1999, an increase of
$2.1 billion or 73%. The increase was due primarily to: (i) an increase in
revenues from the Ravenswood facility of $534.8 million; (ii) an increase in Gas
Distribution revenues of $802.7 million; and (iii) an increase of $585.3 million
from the Energy Services segment.
Revenues from the Ravenswood facility benefitted from the sale of energy,
capacity and ancillary services to the New York Independent System Operator
("NYISO") at competitive market prices. Prior to the start of the NYISO on
November 19 1999, all of the energy and capacity from the Ravenswood facility
was sold to Consolidated Edison Company of New York, Inc. ("Consolidated
Edison") on a cost recovery and fixed fee basis. Further, revenues for 2000
reflect a full year of operations. Revenues from the Gas Distribution segment
benefitted from continued gas sales growth, favorable gas prices as compared to
oil prices for most of 2000 and the acquisition of Eastern's and ENI's gas
distribution operations. Revenues from the Gas Distribution segment also include
recovery of gas costs, which have been significantly higher in 2000 compared to
1999. The increase in revenues from the Energy Services segment resulted from
recent acquisitions of companies providing various energy-related services
throughout the New York City metropolitan area, Rhode Island and Pennsylvania,
and sales growth related to our gas and electric marketing subsidiary.
The increase in consolidated revenues of $1.2 billion, or 71%, in 1999, compared
to the Transition Period, reflects primarily revenues from gas heating sales.
For the months of January 1999 through March 1999, gas distribution revenues
were $718.3 million. The Transition Period, which reflects the period April 1,
1998 through December 31, 1998, does not include revenues from heating season
operations for the months of January through March. Further, revenues in 1999
reflect a full twelve month period for all segments, whereas the Transition
Period reflects revenues for only seven months from the KSE- acquired companies.
Revenues in 1999 also include $150.8 million of revenues from the Ravenswood
facility and were further enhanced through the acquisition of companies in the
Energy Services segment.
4
Operating Expenses
Consolidated operating expenses were $4.4 billion in 2000, compared to $2.5
billion last year, an increase of $1.9 billion, or 78%. The increase in
operating expenses was primarily the result of higher gas and purchased fuel
costs, and higher operations and maintenance expenses. Consolidated operating
expenses were $1.8 billion during the Transition Period. The increase in
operating expenses in 1999 compared to the Transition Period of $694.7 million,
or 39%, is due, in part, to the increased reporting time frame and to an
increase of $248.9 million in operations and maintenance expense reflecting,
primarily the addition of the KSE-acquired companies for a full twelve month
period.
Purchased Gas for Resale
The increase in gas costs for 2000 compared to last year resulted from gas sales
growth associated with our two New York gas distribution subsidiaries and our
gas and electric marketing subsidiary, significantly higher gas prices, and the
addition of the Eastern and ENI gas distribution operations which added $180.6
million to gas costs in 2000. The increase in gas costs for 1999 compared to the
Transition Period is due to changes in gas quantities and prices, and the
differences in the reporting periods presented. Fluctuations in utility gas
costs have little or no impact on operating results as the current gas rate
structure of each of our gas distribution utilities includes a gas adjustment
clause, pursuant to which variations between actual gas costs incurred and gas
cost recoveries are deferred and refunded to or collected from customers in a
subsequent period. Fluctuations in gas costs, however, can affect earnings of
our gas and electric marketing subsidiary. To mitigate this potential
volatility, this subsidiary employs derivative financial instruments to hedge a
portion of the risk associated with future gas cost prices. (See Note 10 to the
Consolidated Financial Statements "Hedging, Derivative Financial Instruments,
and Fair Values".)
Fuel and Purchased Power
Fuel and purchased power expense in 2000 was $460.9 million and reflects
expenses associated with the operation of the Ravenswood facility, as well as
expenses associated with our gas and electric marketing subsidiary which has
been making retail electric sales to residential, small commercial, and
industrial customers since January 2000. Fuel expense for the operation of the
Ravenswood facility was $315.1 million in 2000. Fuel and purchased power expense
for 1999 was $17.3 million and reflects expenses associated with the operation
of the Ravenswood facility only. In 1999, the prior owner of the Ravenswood
facility, Consolidated Edison, owned and supplied the fuel necessary to operate
the Ravenswood facility from June 19, 1999 until the start of the NYISO's
operations on November 19, 1999. Further, during this time, all of the energy
generated by the Ravenswood facility was supplied to Consolidated Edison.
Electric fuel expense was $91.8 million during the Transition Period. In
accordance with the energy management agreement ("EMA") between KeySpan and
LIPA, LIPA is responsible for paying directly the costs of fuel, as well as
purchased power to satisfy the energy needs of LIPA's customers. As a result,
since May 29, 1998, we no longer incur any electric fuel expense for Long Island
generation.
5
Operations and Maintenance
Operations and maintenance expense increased by $669.5 million or 61%, in 2000
compared to last year, primarily as a result of: (i) recent acquisitions of
companies providing various energy- related services which increased operating
expenses in 2000 by 32%; (ii) the operations of the Ravenswood facility for a
full twelve months which increased operating expenses in 2000 by 13%; and (iii)
the recent acquisition of Eastern and ENI which added $89.9 million to
operations and maintenance expense in 2000. Further, we incurred a $65.2 million
charge in 2000 for early retirement and severance programs.
Operations and maintenance expense increased by $248.9 million or 30%, in 1999
compared to the Transition Period. The increase was due primarily to the
addition of the KSE-acquired companies for a full twelve month period and the
increased reporting time frame generally. Operations and maintenance expense for
the KSE-acquired companies was $483.6 million for 1999 and $284.1 million for
the Transition Period. Further, the increase in comparative operations and
maintenance expense in 1999 was due, in part, to the operations of the
Ravenswood facility, which added $61.3 million to expense. Operations and
maintenance expense for the Transition Period included $63.8 million of costs
associated with the write-off of a customer billing system that was in
development and a charge of $64.6 million associated with an early retirement
program.
Other Operating Expenses
Depreciation, depletion and amortization expense reflects primarily gas utility
property and electric generation property additions, as well as depletion
expense associated with our gas exploration and production activities. Property
additions and gas production activities have increased in 2000 compared to 1999,
resulting in higher depreciation, depletion and amortization expense.
Depreciation, depletion and amortization expense also reflects goodwill
amortization which increased in 2000 compared to 1999 primarily due to the
amortization of goodwill associated with the acquisitions of Eastern and ENI.
The goodwill associated with these acquisitions amounted to $1.5 billion and the
amortization for the period November 8, 2000 through December 31, 2000 was
approximately $6.5 million. (See Note 1 to the Consolidated Financial Statements
"Summary of Significant Accounting Policies" for a description of goodwill.)
The decrease in depreciation, depletion and amortization expense in 1999
compared to the Transition Period is due primarily to the fact that Houston
Exploration recorded an impairment charge of $130 million in December 1998 to
reduce the value of its proved gas reserves in accordance with the asset ceiling
test limitations of the Securities and Exchange Commission ("SEC") applicable to
gas exploration and development operations accounted for under the full cost
method. Excluding this impairment charge, depreciation expense increased in 1999
due to property additions, the addition of the KSE-acquired companies for a full
twelve month period and the increased reporting period generally.
6
Operating taxes principally include state and local taxes on utility revenues
and property. The applicable property base and tax rates generally have
increased in all periods. Further, the increase in operating taxes in 2000
compared to 1999 is also due to a full twelve months of operations of the
Ravenswood facility and the addition of Eastern and ENI. Operating taxes for the
Ravenswood facility in 2000 were $46.6 million compared to $19.6 million in
1999. Eastern and ENI added $8.6 million to operating taxes in 2000.
The increase in operating taxes in 1999, compared to the Transition Period,
reflects the addition of the KSE- acquired companies for a full twelve month
period, and operating taxes associated with the Ravenswood facility. Operating
taxes associated with the KSE-acquired companies were $140.8 million in 1999 and
$69.8 million during the Transition Period.
Other Income and Deductions
Other income includes equity income from subsidiaries comprising the Energy
Investments segment, primarily our investments in Canada. In addition, other
income includes interest income from temporary cash investments, certain
non-operating expenses and the effect on net income from the minority interest
associated primarily with Houston Exploration. In October 2000, we increased our
investment in Gulf Midstream Services Partnership ("Gulf Midstream"), located in
Alberta Canada, from 50% to 100% and renamed these operations "KeySpan Canada."
As a result, since October 2000 the results of operations of KeySpan Canada have
been reported on a consolidated basis and are no longer reported in equity
income.
The decrease in other income in 2000 compared to 1999 reflects primarily an
increase in non- operating charges and lower interest income. During 2000 we
made a $10 million donation to the KeySpan Foundation and recorded an impairment
charge of $15.5 million on our equity investment in certain technology-related
activities. Interest income has been decreasing as we have utilized our cash
during the past two years to make acquisitions, repurchase shares of our common
stock, and retire maturing debt.
Other income and deductions in 1999 reflects twelve months of results for our
Canadian investments compared to seven months of results for the Transition
Period. Further, our 50% interest in Gulf Midstream was acquired in December
1998 and, therefore, there are no equity earnings associated with Gulf Midstream
for the Transition Period. We recognized equity earnings of $12.9 million for
1999 from our Canadian investments, including $5.8 million from Gulf Midstream.
Interest income decreased in 1999, compared to the Transition Period, as we
utilized our cash to make acquisitions, repurchase shares of our common stock,
and retire maturing debt. Other income and deductions for the Transition Period
reflects non-recurring charges associated with the LIPA Transaction of $107.9
million after-tax and a $20 million charge for the funding of the KeySpan
Foundation. (See Note 16 to the Consolidated Financial Statements, "Costs
Related to the LIPA Transaction and Special Charges.")
7
Interest Expense
Interest expense was $203.4 million, or 52% higher in 2000, compared to last
year reflecting higher levels of debt outstanding, primarily related to: (i)
$1.65 billion of long-term debt and $308.6 million of commercial paper issued to
finance the acquisitions of Eastern and ENI; (ii) $400 million of medium term
notes issued in February 2000; (iii) debt associated with our Canadian
investments; as well as (iv) higher commercial paper borrowings to satisfy our
seasonal working capital needs. Interest expense relating to the acquisition
financing of Eastern and ENI amounted to approximately $17.5 million in 2000.
(See Note 7 to the Consolidated Financial Statements "Long-Term Debt.")
The decrease in interest expense in 1999 compared to the Transition Period
primarily reflects the then reduced level of outstanding debt resulting from the
LIPA Transaction. Upon consummation of the LIPA Transaction, LIPA assumed
substantially all of the outstanding debt of LILCO. KeySpan, in return, issued
promissory notes to LIPA for its continuing obligation to pay principal and
interest on certain series of bonds that were assumed by LIPA. Outstanding debt
at December 31, 1999 was $1.7 billion, compared to $4.5 billion (LILCO only)
prior to the LIPA Transaction. In addition, interest expense in 1999 also
reflects the repayment of $397 million of promissory notes due LIPA that matured
in June 1999. The reduction in interest expense in 1999 from the lower levels of
debt outstanding was offset, in part, by the interest expense from the
KSE-acquired companies for the full twelve months.
Income Taxes
Income tax expense generally reflects the higher level of pre-tax income in 2000
compared to last year. Further, during the last quarter of 2000, the basis for
computing certain local income taxes was changed which also contributed to the
increase in income tax expense in 2000.
Income tax expense for 1999 reflects an adjustment to deferred tax expense and
current tax expense for the utilization of previously deferred net operating
loss carryforwards recorded in 1998. In 1998, we recorded, as a deferred tax
asset, a benefit of $71.1 million for net operating loss carryforwards. We
estimated that $57.4 million of the benefits from the net operating loss
carryforwards from 1998 would be realized in our consolidated 1999 federal and
state income tax returns and, accordingly, we applied the net operating loss
benefits in our 1999 federal and state tax provisions. Pre-tax income and the
related deferred income tax expense for the Transition Period were significantly
affected by charges related to the LIPA Transaction, the write-off of a customer
billing system, charges related to the early retirement program, and the
impairment charge associated with the write-down of proved gas reserves. (See
Note 3 to the Consolidated Financial Statements, "Income Tax.")
8
Consolidated Outlook for 2001
Results of operations for 2000 reflect strong results from our core investments
- - gas distribution, electric services and energy services. Our marketing efforts
have added approximately 21,000 new gas heating customers in our New York and
Long Island service territories in 2000, as well as contributing to our gas
sales growth of approximately 5%, after normalizing for weather variations. Our
June 1999 acquisition of the Ravenswood facility provided us with significant
earnings enhancement. Further, our energy services operations posted positive
earnings results in 2000 due to the successful integration of companies
purchased during the past two years. These operations are expected to form the
basis for additional enhancements to consolidated earnings in future years.
Moreover, our non-core assets, specifically our gas and oil exploration and
production operations, posted impressive results for 2000.
For 2001, we anticipate that consolidated earnings will grow approximately 10%
over the level we achieved in 2000, and we forecast earnings in the range of
$2.60 to $2.65 per share. We believe this growth will come primarily from our
energy services operations as we continue the successful integration of
companies acquired during the past few years. We also anticipate significant
earnings growth from our gas and oil exploration and production activities
resulting from the anticipated high price for natural gas during 2001, augmented
by our current hedging strategies. Further, we have completed our resource
allocation process for 2001 and are encouraged that we will achieve the synergy
savings projected to result from the Eastern and ENI acquisitions.
The Financial Accounting Standards Board ("FASB") recently issued a revision to
its Exposure Draft ("ED") on "Business Combinations and Intangible Assets". In
the new ED, the FASB concluded that the amortization of goodwill will no longer
be required. Instead, companies will need to perform yearly impairment tests on
the recorded amount of goodwill and determine whether an impairment charge is
necessary. We believe the FASB will finalize its deliberations on goodwill
amortization in the third or fourth quarter of 2001, but are unable to predict
the ultimate outcome of its deliberations. If we are required to discontinue the
amortization of goodwill we may realize higher earnings in 2001, compared to our
current earnings projections, although such enhancement to earnings will not
affect cash flow.
As a result of the acquisition of Eastern and ENI, we are now subject to the
jurisdiction of the SEC under the Public Utility Holding Company Act of 1935, as
amended ("PUHCA"). The rules and regulations under PUHCA generally limit the
operations of a registered holding company to a single integrated public utility
system, and non-utility businesses that are reasonably incidental, or
economically necessary or appropriate to the system's utility business. In
addition, as part of the regulatory provisions of PUHCA, the SEC can regulate
certain transactions among affiliates within a holding company system. In
accordance with the regulations of PUHCA, we have established service companies
that provide: (i) traditional corporate and administrative services; (ii) gas
and electric transmission and distribution systems planning, marketing, and gas
supply planning and procurement; and (iii) engineering and surveying services to
subsidiaries. Revised methodologies approved by the SEC will be used to allocate
service company costs to affiliates and may result in more or less costs being
charged to the affiliates than in previous years. However, it is anticipated
that the consolidated results
9
will not be impacted by the allocations. (See Regulation and Rate Matters,
"Securities and Exchange Commission Regulation" for additional details on PUHCA
regulations.)
Finally, we adopted Statement of Financial Accounting Standards ("SFAS") No.133
"Accounting for Derivative Instruments and Hedging Activities" on January 1,
2001. Currently all of our derivative instruments expire prior to the end of
2001 and therefore we do not expect SFAS No. 133 to have a material effect on
our net income for the year ended December 31, 2001. However, SFAS No. 133 may
have a significant effect on other comprehensive income because of fluctuations
in the market value of the derivatives we employ. Further, depending on the
quarterly measurement of hedging effectiveness, SFAS No.133 may have a material
effect on our reported quarterly earnings, (See Note 10, "Hedging, Derivative
Financial Instruments, and Fair Values" for additional information.)
10
Segment Review of Operations
- ----------------------------
The segment review that follows reflects the operations of our newly acquired
companies, Eastern and ENI, for the period November 8, 2000 through December 31,
2000 and excludes after-tax charges of $41.1 million recorded in 2000 associated
with our early retirement and severance programs. Also, as previously mentioned,
due to the change in the structure of our business as a result of the LIPA
Transaction and the requirements of purchase accounting applicable to the
KeySpan Acquisition, results of operations for the Transition Period are not
comparable to the results of operations for 2000 and 1999. Therefore, for
comparative purposes, we have combined the results of operations, excluding
non-recurring and special charges, of KSE and LILCO for the entire twelve month
period ended December 31, 1998. This combined presentation is intended to
reflect our results as if the KeySpan Acquisition occurred on January 1, 1998.
This "combined company basis" format will also be used to explain variations in
operating results, for each business segment, between the twelve months ended
December 31, 1999 and 1998.
Consolidated income (loss) available for common stock, excluding early
retirement and severance charges recorded in 2000 and early retirement and
special charges incurred in 1998, by reporting segment is set forth in the
following table for the periods indicated:
(In Thousands of Dollars)
- ---------------------------------------------------------------------------------------------------------------------------------
Year Ended Year Ended "Combined Company"
December 31, December 31, Twelve Months Ended
2000 1999 December 31, 1998
- ------------------------------------------ ---------------------- -------------------------- -----------------------------------
Income (Loss ) Available for
Common Stock:
Gas Distribution $ 187,342 $ 151,217 $ 133,685
Electric Services 122,188 77,099 120,568*
Gas Exploration and Production 58,211 15,772 8,995
Energy Services 40,946 (2,528) (8,623)
Energy Investments 13,929 8,543 (6,098)
Other (98,850) (26,244) (53,221)
- ---------------------------------------------------------------------------------------------------------------------------------
$ 323,766 $ 223,859 $ 195,306
- ------------------------------------------ ---------------------- -------------------------- -----------------------------------
* Reflects results of operations under the LIPA service agreements for the
period May 29, 1998 through December 31, 1998 and electric operations of
the former LILCO for the period January 1, 1998 through May 28, 1998.
11
Gas Distribution
With the exception of a small portion of Queens County, our gas distribution
subsidiaries are the only providers of gas distribution services in the New York
City counties of Kings, Richmond and Queens and the Long Island counties of
Nassau and Suffolk. KEDNY provides gas distribution services to customers in the
New York City boroughs of Brooklyn, Queens and Staten Island, and KeySpan Gas
East Corporation d/b/a 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. Our newly acquired gas
distribution subsidiaries, Boston Gas Company, Colonial Gas Company, Essex Gas
Company, and EnergyNorth Natural Gas, each doing business under the name KeySpan
Energy Delivery New England ("KEDNE"), provide gas distribution services to
customers in Massachusetts and New Hampshire.
The table below highlights certain significant financial data and operating
statistics for the Gas Distribution segment for the periods indicated.
(In Thousands of Dollars)
- -----------------------------------------------------------------------------------------------------------------------------------
Year Ended Year Ended "Combined Company"
December 31, December 31, Twelve Months Ended
2000 1999 December 31, 1998
- -----------------------------------------------------------------------------------------------------------------------------------
Revenues $ 2,555,785 $ 1,753,132 $ 1,766,949
Cost of gas 1,303,514 702,044 702,669
Revenue taxes 117,811 108,488 109,194
- -----------------------------------------------------------------------------------------------------------------------------------
Net Revenues 1,134,460 942,600 955,086
- -----------------------------------------------------------------------------------------------------------------------------------
Operating expenses
Operations and maintenance 458,082 415,888 464,296
Depreciation and amortization 143,335 102,997 91,438
Operating taxes 131,854 115,305 106,891
- -----------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 733,271 634,190 662,625
- -----------------------------------------------------------------------------------------------------------------------------------
Operating Income $ 401,189 $ 308,410 $ 292,461
- -----------------------------------------------------------------------------------------------------------------------------------
Earnings for Common Stock $ 187,342 $ 151,217 $ 133,685
- -----------------------------------------------------------------------------------------------------------------------------------
Firm gas sales (MDTH) 216,000 172,019 165,331
Firm transportation (MDTH) 40,655 21,249 13,974
Transportation -
Electric Generation (MDTH) 49,854 82,503 40,614
Other sales (MDTH) 91,406 54,661 65,482
Degree days 4,902 4,296 3,940
(Colder) Warmer than normal (2.1%) 10.0% 17.5%
Heating customers (000) 1,260 677 665
- -----------------------------------------------------------------------------------------------------------------------------------
An MDTH is 10,000 therms (British Thermal Units) 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.
12
Net Revenues
Net gas revenues (revenues less the cost of gas and associated revenue taxes)
increased by $191.9 million or 20% in 2000 compared to 1999, due to the addition
of the gas distribution operations of Eastern and ENI which contributed $126.6
million to net revenues, continued gas sales growth and favorable gas prices
compared to oil prices during most of the year.
Net gas revenues decreased in 1999 compared to 1998 by $12.5 million, or 1.3%,
due primarily to rate reductions associated with the KeySpan Acquisition. KEDNY
reduced rates to its core customers by $23.9 million on an annual basis
effective May 29, 1998 and KEDLI reduced its rates to core customers by $12.2
million annually effective February 5, 1998 and by an additional $6.3 million
annually effective May 29, 1998. For the year ended December 31, 1999, rate
reductions affected revenues by approximately $19.2 million compared to 1998.
Firm net gas revenues grew approximately $154.2 million in 2000, over 1999. The
gas distribution operations of Eastern and ENI added $126.6 million to net firm
revenues, while our New York based gas distribution operations added $27.6
million to firm net revenues through the addition of new gas customers and oil
to gas conversions, primarily in the Long Island market, as well as from the
benefits of colder weather. Long Island has a low natural gas saturation rate
for space heating use and significant gas sales growth opportunities are
believed to be available. We estimate that on Long Island less than 40% of the
residential and multi- family markets, and approximately 55% of the commercial
market currently use natural gas for space heating. Further, we believe
significant gas sales growth opportunities exist in the New England market due
to the relatively low penetration of customers using gas for space heating use.
We estimate that in our New England service territories less than 50% of the
residential and multi-family markets, and approximately 30% of the commercial
market currently use natural gas for space heating. In both our Long Island and
New England service areas, we will continue to seek growth through the expansion
of our gas distribution system, as well as through the conversion of residential
homes from oil-to-gas for space heating purposes and the pursuit of
opportunities to grow multi-family, industrial and commercial markets. Firm net
gas revenues grew approximately $14 million in 1999 over 1998 due to the
addition of new gas customers and oil to gas conversions, primarily on Long
Island, as well as from the benefits of colder weather.
In the large volume heating markets and other interruptible (non-firm) markets,
which include large apartment houses, government buildings and schools, gas
service is provided under rates that are set to compete with prices of
alternative fuel, including No. 2 and No. 6 grade heating oil. While the price
of both heating grade fuel oil and natural gas increased significantly in 2000,
gas generally sold at a slight discount to heating oil during the year. We
increased sales in these markets by $21.9 million in 2000 compared to last year,
through aggressive unit pricing and the addition of two large commercial and
industrial customers. The majority of interruptible profits earned by Eastern
and ENI are refunded to firm customers. During 1999, gas generally sold at a
premium to heating oil. Nevertheless, we increased sales in this market in 1999
compared to 1998, by approximately $6 million, through aggressive unit pricing
and the addition of new customers.
13
Net revenues in 2000 were also favorably affected by recovery of previously
deferred property taxes. Contributing to the reduction in comparative net
revenues in 1999 compared to 1998 was a decrease in certain regulatory
incentives, and since April 1998 net revenues no longer reflect revenues derived
by KEDNY from certain appliance and repair services which were "spun-off" to a
subsidiary in the Energy Services segment.
KEDNY and KEDLI each operate under a utility tariff that contains a weather
normalization adjustment that largely offsets shortfalls or excesses of firm net
revenues during a heating season due to variations from normal weather. The gas
distribution operations of our New England based subsidiaries do not have a
weather normalization adjustment. As a result, fluctuations in weather between
years may have a significant effect on results of operations for these
subsidiaries.
Sales, Transportation and Other Quantities
Firm gas sales quantities increased by 20% in 2000 compared to 1999 reflecting
firm sales from our newly acquired New England gas distribution operations, the
addition of new gas customers as discussed above, and the benefits derived from
colder weather. Weather normalized sales quantities increased by approximately
5% in 2000 compared to 1999 in our New York and Long Island service territories,
while the addition of the New England gas distribution operations increased firm
sales by 12%. The 4% increase in gas sales quantities for 1999 compared to 1998
reflects an increase of 2.4% in weather normalized firm sales quantities
resulting from customer additions and oil-to-gas conversions and colder weather
in 1999.
Firm gas transportation quantities increased in all periods, as we continue our
natural gas deregulation initiatives. At December 31, 2000, approximately
126,500 residential, commercial and industrial customers in our New York and
Long Island service territories purchased their gas supply from third party
suppliers compared to approximately 46,000 customers in 1999 and 32,900
customers in 1998. The New England gas distribution subsidiaries also offer
unbundled services to all commercial and industrial customers. As of December
31, 2000, these subsidiaries had approximately 4,000 firm transportation
customers. Unbundled service to Massachusetts residential customers was
effective November 1, 2000. Our net revenues are currently not affected by
customers opting to purchase their gas supply from other sources, since delivery
rates charged to transportation customers are generally the same as the delivery
component of the total rates charged to full sales service customers.
Transportation quantities related to electric generation reflect the
transportation of gas to our electric generating facilities located on Long
Island. Net revenues from these services are not material.
Other sales quantities include on-system interruptible quantities, off-system
sales quantities (sales made to customers outside of our service territories)
and related transportation. Effective April 1, 2000, we entered into an
agreement with Coral Resources, L.P. ("Coral"), a subsidiary of Shell Oil
Company. Coral assists in the origination, structuring, valuation and execution
of energy-related transactions. Under our New York Public Service Commission
("NYPSC") approved rate plans, net revenues realized from off-system gas
transactions are shared between
14
gas customers and KEDNY and KEDLI. A portion of the net revenues on such
transactions accruing to KEDNY and KEDLI are then shared with Coral. KEDNY and
KEDLI also share in net revenues arising from certain transactions initiated by
Coral. Prior to this agreement with Coral, KEDNY had an agreement with Enron
Capital and Trade Resources Corp., a subsidiary of Enron Corp., which expired on
March 31, 2000. Pursuant to that agreement, Enron provided gas supply and asset
management services to KEDNY for a fee, and obtained the right to earn revenues
based upon its management of KEDNY's gas supply requirements, storage
arrangements and interstate pipeline capacity rights. As a result of this
agreement, KEDNY did not report any off-system sales quantities in 1999.
Effective November 1, 1999, the Massachusetts based gas subsidiaries entered
into a three-year portfolio management contract with El Paso Energy Marketing,
Inc. El Paso provides all of the city gate supply requirements to the three
Massachusetts companies at market prices and manages certain of the companies'
upstream capacity, underground storage and term supply contracts. The
Massachusetts Department of Telecommunications and Energy ("DTE") approved the
contract in October 1999. The annual fee paid by El Paso to manage the
companies' portfolio is, for the most part, returned to firm customers.
Operating Expenses
Operating expenses increased by $99.1 million, or 16%, in 2000 compared to last
year due primarily to the addition of Eastern's and ENI's gas distribution
operations. Eastern and ENI collectively added $69.8 million to operating
expenses in 2000. This amount includes operations and maintenance costs of $42.0
million, depreciation and amortization charges of $21.9 million and general
taxes of $5.9 million. Included in the depreciation and amortization charge, is
an expense of approximately $5.9 million primarily representing two months
amortization of goodwill associated with the acquisition of Eastern and ENI that
was assigned to gas distribution operations. The remaining increase in
depreciation and amortization expense reflects continued property additions, and
the amortization of certain costs previously deferred and now being recovered
through revenue recovery mechanisms. Further, operating taxes, which include
state and local taxes on property have increased as the applicable property base
and tax rates generally have increased.
Operating expenses decreased in 1999 compared to 1998 by $28.4 million, or 4.3%.
During 1999, we realized significant reductions in operations and maintenance
expense reflecting, primarily the benefits derived from cost reduction measures
and operating efficiencies employed in prior years. Such measures included, but
were not limited to, the early retirement program completed in 1998. In
addition, KEDNY's "spin-off" of non-safety related appliance repair services to
an Energy Services subsidiary in April 1998 contributed to the reduction in
operations and maintenance expense for this segment. KEDLI discontinued
providing non-safety related appliance repair services on July 1, 1999, further
reducing operating expenses for this segment.
The increase in depreciation and amortization expense in 1999 compared to 1998
reflects continued property additions and the amortization of previously
deferred merger related expenses. As provided for in the settlement agreement
approved by the NYPSC, by which the NYPSC authorized the KeySpan Acquisition,
KEDNY and KEDLI deferred certain merger
15
related costs at the time of the merger. These costs are being amortized over a
ten year period. (See Gas Distribution - Rate Matters for further details on the
Stipulation Agreement.)
Earnings
In addition to the matters discussed earlier, earnings available for common
stock also reflect interest expense and income tax provisions. Interest expense
for 2000 was $21.3 million higher compared to last year due to $16.6 million of
interest expense associated with the gas distribution operations of Eastern and
ENI and the issuance of $400 million of medium term notes in February 2000 by
KEDLI. Included in interest expense is $9.4 million associated with the debt
incurred to acquire Eastern and ENI. Further, we incurred an increase in our
income tax provision due to a change in our basis for computing certain local
income taxes.
The increase in earnings in 1999 compared to 1998 reflects primarily the net
result of the items mentioned above. In addition, earnings were favorably
affected by carrying charges on certain regulatory deferrals previously
mentioned as well as lower interest expense.
Future Developments
We believe there remains significant growth opportunities in our Long Island and
New England gas distribution service areas. The Northeast region represents a
significant portion of the country's population and energy consumption. As our
gas distribution operations evolve within the new deregulated gas environment,
gas sales growth will remain a critical core strategy. Customer additions are
and will remain critical to our earnings enhancement in the future. We intend to
continue our gas growth initiatives on Long Island and in the New England
region. The beneficial effect of these initiatives, however, may not be fully
realized in the short-term since we will make incremental investments in our gas
distribution network and expand our promotional campaigns to optimize the
long-term growth opportunities in our territories. Our current forecast for
capital expenditures in 2001 is $404 million and reflects anticipated
expenditures for our gas expansion initiatives on Long Island and in New
England.
To take advantage of the anticipated gas sales growth opportunities in the New
York City metropolitan area, we recently announced that we have formed Islander
East Pipeline, L.L.C., a limited liability company in which a KeySpan subsidiary
and a subsidiary of Duke Energy Corporation each own a 50% equity interest. It
is anticipated that Islander East will design, construct, own and operate a
natural gas pipeline facility consisting of approximately 40 miles of 24-inch
and 30-inch diameter pipeline extending from Algonquin Gas Transmission
Company's facilities in Connecticut, across the Long Island Sound and connect
with KEDLI's facilities on Long Island. This pipeline, which is expected to
begin operating in the last quarter of 2003, will initially transport 250,000
dth of gas capacity daily to the Long Island and New York City energy markets.
16
Electric Services
The Electric Services segment primarily consists of subsidiaries that own and
operate oil and gas fired electric generating plants in Queens and Long Island,
through long-term contracts, and manage the electric transmission and
distribution ("T&D") system, the fuel and electric purchases, and the off-system
electric sales for LIPA. Prior to the LIPA Transaction, LILCO provided fully
integrated electric distribution services to over one million customers on Long
Island.
Selected financial data for the Electric Services segment is set forth in the
table below for the periods indicated.
(In Thousands of Dollars)
- ---------------------------------------------------------------------------------------------------------------------------------
Year Ended Year Ended "Combined Company"
December 31, December 31, Twelve Months Ended
2000 1999 December 31, 1998
- ------------------------------------------- ------------------------- ------------------------ ------------------------
Revenues
LIPA service agreements $ 758,251 $ 708,002 $ 408,305
Ravenswood facility 685,605 150,836 -
Electric distribution - - 885,693
Other 855 2,744 -
- ------------------------------------------- ------------------------- ------------------------ ------------------------
Total Revenues 1,444,711 861,582 1,293,998
Purchased fuel 315,139 17,252 257,786
- ------------------------------------------- ------------------------- ------------------------ ------------------------
Net Revenues 1,129,572 844,330 1,036,212
- ------------------------------------------- ------------------------- ------------------------ ------------------------
Operating expenses
Operations and maintenance 682,196 527,729 461,903
Depreciation 49,278 44,334 79,404
Regulatory amortizations - - (79,874)
Operating taxes 158,886 132,327 218,418
- ------------------------------------------- ------------------------- ------------------------ ------------------------
Total Operating Expenses 890,360 704,390 679,851
- ------------------------------------------- ------------------------- ------------------------ ------------------------
Operating Income $ 239,212 $ 139,940 $ 356,361
- ------------------------------------------- ------------------------- ------------------------ ------------------------
Earnings for Common Stock $ 122,188 $ 77,099 $ 120,568
- ------------------------------------------- ------------------------- ------------------------ ------------------------
Electric sales (MWH)* 4,952,613 2,995,970 -
Cooling degree days* 1,165 1,416 -
Capacity (MW)* 2,200 2,168 -
- ------------------------------------------- ------------------------- ------------------------ ------------------------
*Reflects the operations of the Ravenswood facility only.
17
Revenues
Net revenues increased by $285.2 million, or 34%, in 2000 compared to last year
due primarily to a full year of operations of the Ravenswood facility. Revenues
from the Ravenswood facility benefitted from the sale of energy, capacity and
ancillary services to the NYISO at competitive market prices, and from effective
hedging strategies. Prior to the start of operations of the NYISO on November
19, 1999, all of the energy and capacity from the Ravenswood facility was sold
to Consolidated Edison on a cost recovery and fixed fee basis. Further, there
were no sales of ancillary services in 1999.
Due to the volatility in the market-clearing price for electricity and certain
ancillary services in the NYISO energy markets, the sales prices for both energy
sales and the sale of certain ancillary services to the NYISO are now subject to
price caps and other price mitigation measures. Certain price mitigation
measures are currently being finalized, and the final resolution of these issues
and their effect on our financial position and results of operations can not be
determined at this point in time. (See Note 8 to the Consolidated Financial
Statements, "New York State Independent System Operator Matters" for a further
discussion of these matters.)
Purchased fuel expense in 2000 and 1999 represents costs to operate the
Ravenswood facility. In 1999, Consolidated Edison owned and supplied the fuel
necessary to operate the facility from June 19, 1999 until the NYISO commenced
operations. As a result, we did not incur any fuel expense prior to November 19,
1999.
Revenues from our service agreements with LIPA were $50.2 million higher in 2000
compared to last year. The increase is largely due to the construction of an
underground transmission line to reinforce the electric system capacity on the
southfork of Long Island. The project was performed under a fixed fee contract
with LIPA, as part of the management services agreement. Further, revenues in
2000 include $16.5 million of off-system sales from our Long Island electric
generation units. Under the terms of the energy management agreement, we are
entitled to one- third of the profit from any off-system electricity sales
arranged by us on LIPA's behalf. In addition, in 2000 we earned $15.4 million
associated with non-cost performance incentives provided for under these
agreements, compared to $15.8 million earned last year. (For a description of
the LIPA service agreements, see "LIPA Agreements.")
Revenues related to the LIPA service contracts increased in 1999, compared to
the Transition Period, due primarily to the fact that 1999 reflects a full year
of operations under these contracts. In addition, as previously mentioned, we
earned $15.8 million associated with non-cost performance incentives provided
for under these agreements. Revenues were further enhanced in 1999 by the
operations of the Ravenswood facility. However, net revenues in 1999 decreased
by $191.9 million, or 19%, compared to 1998. As a result of the change in the
nature of our electric operations due to the LIPA Transaction, our electric
capital investment has been significantly reduced and accordingly, our revenues
and margins under the LIPA contracts reflect that reduction.
Purchased fuel expense decreased by $240.5 million in 1999 compared to 1998,
reflecting primarily the discontinuance of fuel and purchased power expense
associated with the generating
18
facilities located on Long Island. In accordance with the energy management
agreement, LIPA is responsible for paying directly the costs of fuel, as well as
purchased power to satisfy its customers. As a result, since May 29, 1998, we no
longer incur any electric fuel expense for Long Island generation or purchased
power expense.
Operating Expenses
Operating expenses in 2000 increased by $186.0 million or 26% compared to 1999.
The increase in operating expenses in 2000 reflects the operations of the
Ravenswood facility for a full year. Operating expenses associated with the
Ravenswood facility increased by $143.7 million in 2000 compared to 1999.
Included in operating expenses for the Ravenswood facility are charges of $63.9
million for fuel management services provided by one of our subsidiaries within
the Energy Services segment. There were no comparable charges in 1999. Operating
expenses incurred under LIPA service agreements increased by $42.3 million in
2000 compared to last year due primarily to costs incurred to install the new
electric transmission line discussed above.
Operating expenses increased slightly in 1999 compared to 1998. The increase in
operations and maintenance expense was offset, in large measure, by a decrease
in depreciation expense and operating taxes. Since the LIPA Transaction,
operations and maintenance expense includes the costs associated with the
management of the T&D assets acquired by LIPA. All T&D related costs are
expensed when incurred and recovered from LIPA through monthly billings in
accordance with the terms of the management services agreement. Prior to the
LIPA Transaction, all T&D related construction costs were capitalized and
charged to depreciation expense over the estimated useful life of the related
asset. Depreciation expense and operating taxes decreased in 1999 due to the
sale of significant property related assets to LIPA as a result of the LIPA
Transaction.
Earnings
In addition to the matters discussed above, earnings available for common stock
also reflect interest expense, as well as city, state and federal income tax
provisions. During 2000, the basis for computing certain local income taxes was
changed and, as a result, we recorded higher taxes in 2000 compared to 1999.
Earnings in 1999 compared to 1998 were favorably affected by a decrease of
$135.3 million in interest expense reflecting the then significantly reduced
level of outstanding debt resulting from the LIPA Transaction. Further, prior to
the KeySpan Acquisition, approximately $18.2 million of preferred stock
dividends were allocated to electric operations. Partially offsetting these
benefits was the elimination of carrying charges on certain electric regulatory
assets resulting from electric ratemaking mechanisms that have been discontinued
due to the LIPA Transaction.
Future Developments
During 2000, we filed an application with the NYPSC to build a new 250 MW
cogeneration facility at the Ravenswood facility site. We recently received the
preliminary permits and are moving forward with the licensing effort. The
facility, which will generate electricity and
19
steam, is expected to commence service in 2003. Further, we continue to evaluate
the electric needs on Long Island and may, if economic circumstances and energy
needs warrant, proceed with strategies to add additional electric capacity on
Long Island. As discussed, in greater detail under the heading Regulation and
Rate Matters "Securities and Exchange Commission Regulation," our ability to
invest in electric generating facilities is subject to certain restrictions
imposed by the SEC.
Under a "Generation Purchase Rights Agreement" entered into as part of the LIPA
Transaction, LIPA has the right to purchase, at fair market value, all of our
Long Island based generating assets during the twelve month period beginning on
May 28, 2001. During the fourth quarter of 2000, LIPA began an initial due
diligence review of the feasibility of purchasing these assets and has recently
expressed an intent to solicit proposals from interested parties to operate the
generating facilities should they purchase them. At this point in time, we can
not predict whether LIPA will exercise its right to purchase the assets, nor can
we estimate the effect on our financial condition or results of operations if
LIPA were to exercise such right.
Gas Exploration and Production
The Gas Exploration and Production segment is engaged in gas and oil exploration
and production, and the development and acquisition of domestic natural gas and
oil properties. This segment consists of our 70% equity interest in Houston
Exploration, as well as KeySpan Exploration and Production LLC, our wholly owned
subsidiary engaged in a joint venture with Houston Exploration. Effective
December 31, 2000, KeySpan and Houston Exploration mutually agreed that we will
no longer participate in Houston Exploration's future offshore exploration
prospects. We will, however, continue to maintain our working interest in all
wells drilled under the joint venture agreement. We also agreed to continue the
development of our working interests in prospects drilled under the drilling
program, and for the year 2001, we have agreed to commit approximately $17
million for the development of prospects successfully drilled during 1999 and
2000. On March 31, 2000, under a pre-existing credit arrangement, approximately
$80 million in debt owed by Houston Exploration to us was converted into Houston
Exploration common equity. Upon such conversion, our common equity ownership
interest in Houston Exploration increased from 64% to approximately 70%.
20
Selected financial data and operating statistics for the Gas Exploration and
Production segment are set forth in the following table for the periods
indicated.
(In Thousands of Dollars)
- ----------------------------------------------------------------------------------------------------------------------------
"Combined Company"
Year Ended Year Ended Twelve Months
December 31, December 31, Ended
2000 1999 December 31, 1998
- ----------------------------------------------------------------------------------------------------------------------------
Revenues $ 274,209 $ 150,581 $ 127,124
Depletion and amortization 95,364 74,051 79,839
Other operating expenses 44,435 28,000 27,250
- ---------------------------------------------------- ----------------- ----------------- -----------------
Operating Income $ 134,410 $ 48,530 $ 20,035
- ---------------------------------------------------- ----------------- ----------------- -----------------
Earnings for Common Stock $ 58,211 $ 15,772 $8,995*
- ---------------------------------------------------- ----------------- ----------------- -----------------
Natural gas and oil production (Mmcf) 80,415 71,227 62,829
Natural gas (per Mcf) realized $ 3.38 $ 2.10 $ 2.02
Natural gas (per Mcf) unhedged $ 3.97 $ 2.14 $ 1.96
Proved reserves at year-end (BCFe) 593 553 480
- ---------------------------------------------------- ----------------- ----------------- -----------------
Operating income above represents 100% of our gas exploration and
production subsidiaries' results for the periods indicated. Earnings,
however, are adjusted to reflect minority interest and, accordingly,
include 70% of Houston Exploration's results since April 1, 2000 and
64% of Houston Exploration's results for all prior periods. Gas
reserves and production are stated in BCFe and Mmcfe, which includes
equivalent oil reserves.
*Excludes an after-tax charge of $54.1 million representing our share
of an impairment charge to reduce the value of proved gas reserves.
Operating Income
Operating income increased by $85.9 million, or 177%, in 2000 compared to 1999.
The increase in operating income reflects a significant increase in revenues,
partially offset by increases in operating expenses. Revenues benefitted from
the combined effect of a 13% increase in production volumes and a 61% increase
in average realized gas prices (average wellhead price received for production
plus hedging gains and losses). The average realized gas price in 2000 was 85%
of the average unhedged natural gas price, resulting in revenues for 2000 that
were $46.3 million lower than the revenues Houston Exploration would have
achieved had derivative instruments not been in place during 2000. The average
realized price in 1999 was 98% of the average unhedged natural gas price,
resulting in revenues for 1999 that were $2.6 million lower than the revenues
that Houston Exploration would have achieved had derivative instruments not been
in place during 1999. The increase in operating expenses reflects the
significant increase in production volumes.
Operating income increased by $28.5 million, or 142%, in 1999 compared to 1998,
due to higher revenues and, to a lesser extent, a decrease in operating
expenses. Revenues in 1999 reflect the benefits derived from a 13% increase in
production volumes, combined with a 4% increase in average realized gas prices.
The comparative decrease in operating expenses in 1999 was largely due to a
lower depletion rate, resulting primarily from the ceiling test write down in
1998.
21
At December 31, 2000 our gas exploration and production subsidiaries had 593
BCFe of net proved reserves of natural gas, of which approximately 77% were
classified as proved developed.
Future Developments
Houston Exploration has entered into options that are designed to hedge
approximately 70% of its anticipated 2001 production. These options, which are
referred to as "cost free collars," have an average floor price between $3.63
per Mcf and $4.00 per Mcf and an average ceiling price of between $5.30 per Mcf
and $6.37 per Mcf. (See Note 10 to the Consolidated Financial Statements,
"Hedging, Derivative Financial Instruments, and Fair Values" for an explanation
of these derivative instruments.) In November, Houston Exploration announced a
major new offshore discovery. Based on initial test drilling, Houston
Exploration estimates that this site, located offshore Louisiana and Texas, has
potential reserves of twelve million barrels of oil. Additional undrilled fault
blocks offer unrisked exploration potential of an additional twelve million
barrels of oil. Houston Exploration is the operator of this site and has a 55%
working interest. Through our joint venture with Houston Exploration we own the
remaining 45% interest. Production from this site is not expected until late
fourth quarter 2001 or first quarter of 2002. We estimate that consolidated
capital expenditures to develop this site will be approximately $50 million.
We consider our gas and oil exploration and production activities to be non-core
assets. We have stated in the past that we may sell all or a portion of our
non-core assets if we receive what we consider to be fair value for these
assets. We anticipate that if we were to sell a portion or all of our non-core
assets, we would use the proceeds from the sale to retire a portion of our
outstanding debt.
Energy Services
The Energy Services segment primarily includes companies that provide services
through four lines of business to clients located within the New York City
metropolitan area, Rhode Island, Pennsylvania, Massachusetts and New Hampshire.
The lines of business are: home energy services; business solutions; energy
commodity procurement; and fiber optic services.
During 2000, the Energy Services segment acquired four additional companies
located in the New York City metropolitan area. The newly acquired companies
specialize in engineering- consulting, plumbing and mechanical contracting and
heating, ventilation and air conditioning contracting. Combined, these companies
have over 1,300 employees and revenues of approximately $260 million.
22
The table below highlights selected financial information for the Energy
Services segment.
(In Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------------------
"Combined Company"
Year Ended Year Ended Twelve Months
December 31, December 31, Ended
2000 1999 December 31, 1998
- -------------------------------------------------------------------------------------------------------------------------
Unaffiliated revenues $ 771,861 $ 186,529 $ 88,822
Intersegment revenues 63,912 - -
Cost of goods sold 652,138 152,460 82,496
- ---------------------------------------- ---------------- --------------- ------------------
Gross Profit Margin 183,635 34,069 6,326
Depreciation and amortization 10,511 3,548 1,509
Other operating expenses 95,319 35,164 19,115
- ---------------------------------------- ---------------- --------------- ------------------
Operating Income (Loss) $ 77,805 $ (4,643) $ (14,298)
- ---------------------------------------- ---------------- --------------- ------------------
Earnings (Loss) for
Common Stock $ 40,946 $ (2,528) $ (8,623)
- ---------------------------------------- ---------------- --------------- ------------------
The increase in earnings of the Energy Services segment in 2000 compared to
1999, reflects primarily fuel-management services provided to the Ravenswood
facility, which for 2000, resulted in inter-company profits of $33.7 million. A
subsidiary within this segment, KeySpan Energy Supply, provides the Ravenswood
facility with energy procurement advisory services and acts as an energy broker
for the sale of energy, capacity, and ancillary services. For these services,
KeySpan Energy Supply receives a management fee and shares in the operating
profit generated by the Ravenswood facility on the sale of energy, capacity, and
ancillary services. There was no energy procurement and fuel-management advisory
services agreement between KeySpan Energy Supply and the Ravenswood facility in
1999.
This segment also realized significantly greater gross profit margins in 2000,
compared to last year, for each of its other lines of business. These gross
margin enhancements resulted from recent acquisitions of companies providing
energy-related services and through customer additions related to energy sales.
These benefits to gross profit margins were partially offset by increases in
general and administrative expenses associated primarily with the operations of
the newly acquired companies.
The decrease in the loss in 1999 compared to 1998 was due to an increase in
revenues of 100%, offset, in part, by an increase in operating expenses of 85%.
The increase in comparative revenues reflects the benefits derived from
companies acquired during 1999 and 1998 and the growth in the number of
customers purchasing energy from our gas and electric marketing subsidiary. The
comparative increase in operating expenses was due primarily to the integration
of operations of companies acquired during 1999 and 1998, and increased
purchased gas costs of our gas and electric marketing subsidiary necessary to
serve a larger customer base. The formation and commencement of operations
associated with our appliance repair services in April 1998 also contributed to
the comparative increase in operating expenses in 1999.
23
Energy Investments
Earnings for this segment are derived from our 20% interest in the Iroquois Gas
Transmission System LP; our ownership of KeySpan Canada; our ownership interest
in certain oil producing properties in Alberta, Canada; and our 50% interest in
the Premier Transco Pipeline and 24.5% interest in Phoenix Natural Gas, both in
Northern Ireland. Premier is a natural gas transmission pipeline connecting
Scotland and Northern Ireland in the United Kingdom, and Phoenix is a natural
gas distribution company serving Belfast in Northern Ireland. In the fourth
quarter of 2000, we sold our interest in certain oil producing properties in
Alberta, Canada and recognized an after-tax gain of approximately $1.3 million
from the sale. Further, in the fourth quarter of 2000, we became the sole owner
of Gulf Midstream by acquiring the remaining 50% interest in this company. For
financial reporting purposes, the operations of Gulf Midstream d/b/a KeySpan
Canada have now been fully consolidated.
Earnings from this segment increased by $5.4 million, or 63%, in 2000 compared
to last year reflecting earnings growth from our Canadian investments. Results
of operations from Canadian gas and oil operations were enhanced through the
acquisition, in the fourth quarter of 1999, of the Paddle River Gas Plant and
certain oil producing properties in Alberta, Canada, more efficient operations
of KeySpan Canada and the additional ownership interest in that company. In
addition, Iroquois realized higher transportation sales quantities and revenues
from its interruptible customers during this period compared with the same
period last year. Earnings from our investments in Northern Ireland in 2000 are
essentially the same as earnings for last year. For much of the year, the
subsidiaries in this segment were primarily accounted for under the equity
method since our ownership interests were 50% or less. Accordingly, income from
these investments is reflected, primarily in other income and (deductions) in
the Consolidated Statement of Income.
Earnings from this segment increased by $14.6 million in 1999 reflecting
primarily earnings from our investment in Gulf Midstream, formed in December
1998, and more favorable results from investments in Northern Ireland. In
addition, in 1998 results of operations from this segment reflect after-tax
costs of $7.8 million to settle certain contracts associated with the sale, in
1997, of certain cogeneration investments and related fuel management
operations.
Future Developments
We consider this segment to be a non-core investment. As mentioned previously,
we may sell all or a portion of our non-core assets within the next few years.
At this point in time, we can not predict when we may sell any of our non-core
assets, or the effect such sale may have on our financial position, results of
operations, or cash flows.
24
Other
The Other segment reflects preferred stock dividends, general expenses incurred
by our corporate and administrative areas that have not been allocated to our
various business segments, and interest income earned on temporary cash
investments. Further, this segment includes results of operations related to our
in-land marine transportation subsidiary, Midland Enterprises, that was acquired
as part of the Eastern acquisition. The significant increase in the loss
incurred by the Other segment in 2000 compared to 1999 reflects the following:
(i) an after-tax charge of $6.5 million for an additional contribution to the
KeySpan Foundation; (ii) an after-tax charge of $6.0 related to certain rate
settlement issues; (iii) a loss of $15.1 million, after tax, associated with our
investment in certain technology-related activities; (iv) branding expenses and
other costs related to the integration of the Eastern and ENI companies into our
operations of $16 million; and (v) an increase in interest expense of $23.8
million associated with higher levels of commercial paper outstanding. Further,
we realized $9.0 million less in interest income, after- tax, on temporary cash
investments as we utilized cash to finance certain acquisitions, repurchase
shares of our common stock, and retire maturing debt during the past two years.
Pursuant to an order of the SEC issued under PUHCA by which the SEC approved the
Eastern and ENI acquisitions, we are required to divest our interest in Midland
Enterprises by no later than November 8, 2003 because its operations are not
functionally related to our core utility operations.
The Other segment incurred a loss of $26.2 million in 1999 compared to a loss of
$52.0 million in 1998. In 1999 we recognized $15 million less in interest
income, after-tax, on temporary cash investments due to the utilization of cash
to finance certain acquisitions, repurchase shares of our common stock, and
retire maturing debt. In 1998 the Other segment recorded an after-tax charge of
$41.5 million to write-off a customer billing system that was in development.
Further, we made a $20 million donation, $13 million after-tax, to the KeySpan
Foundation.
Liquidity
Cash flow from operations for 2000 reflects stable growth from our gas
distribution operations, as well as positive contributions from our electric
operations. The decrease in cash flow from operations in 2000 compared to last
year however, reflects working capital requirements primarily as a result of the
rising price of natural gas in the later part of 2000. As a result of the
seasonal nature of our gas distribution operations, we incur significant cash
expenditures during the summer and early fall to fill our storage facilities
with natural gas that is used by our customers during the winter heating season.
We recover these costs in subsequent periods as the gas is removed from storage
and sold to our customers primarily for space heating purposes. Significant cash
flows are generated during the first and second quarters of the subsequent
fiscal year as we receive payments from customers for such use. Cash flow from
operations also reflects a decrease in interest income, and an increase in
interest payments due to increased levels of outstanding debt. Further, in 1999
cash flow from operations reflects the cash utilization of a $57.4 million net
operating loss carryforward on income tax payments for 1999, as previously
discussed.
25
The increase in cash flow from operations in 1999 compared to the Transition
Period reflects the significant positive cash flows realized from revenues
generated during the heating season, continued strong results from core utility
operations, cash generated from the Ravenswood facility, and the benefits
derived from the integration of KSE-acquired companies for an entire twelve
month period. Results from gas-heating season operations are not reflected in
the Transition Period, as previously explained. Further, as indicated above,
cash flow from operations in 1999 reflects the utilization of a $57.4 million
net operating loss carryforward on income tax payments for 1999. Moreover,
during the Transition Period, $250 million was funded into Voluntary Employee
Beneficiary Trusts to fund certain employee postretirement welfare benefits and,
as a result, cash flow from operations for the Transition Period was adversely
affected.
At December 31, 2000, we had cash and temporary cash investments of $94.5
million. In addition, we have two revolving credit agreements, with a commercial
bank syndicate totaling $1.4 billion. These agreements expire in September 2001,
and our current intention is to renew these agreements. These credit facilities
are used to support our $1.4 billion commercial paper program. At December 31,
2000, $1.3 billion of commercial paper was outstanding at a weighted average
annualized interest rate of 7.01%. We had available borrowing of $99.7 million
at December 31, 2000. Commercial paper was issued during 2000 to: (i) finance
approximately $309 million of the approximately $2.0 billion purchase price
associated with the acquisitions of Eastern and ENI; (ii) redeem our preferred
stock 7.95% Series AA for $363 million; and (iii) support ongoing working
capital needs.
Houston Exploration has an unsecured available line of credit with a commercial
bank that provides for a maximum commitment of $250 million, subject to certain
conditions. During 2000, Houston Exploration borrowed $32 million under its
credit facility and repaid $68 million; at December 31, 2000, $145.0 million
remained outstanding at a weighted average annualized interest rate of 7.90%. At
December 31, 2000, Houston Exploration had available borrowing of $65 million.
Also, a subsidiary included in the Energy Investments segment has two revolving
loan agreements with financial institutions in Canada. Borrowings under these
agreements during 2000 were $83.6 million, including the financing for the
purchase of the remaining 50% interest in Gulf Midstream. At December 31, 2000,
$171 million was outstanding at a weighted average annualized interest rate of
6.43%. The Energy Investments segment currently has available borrowing of $46
million. (See Note 7 to the Consolidated Financial Statements, "Long-Term Debt"
for further information on these agreements.)
We satisfy our seasonal working capital requirements primarily through
internally generated funds and the issuance of commercial paper. In addition, we
utilize Treasury Stock to satisfy the requirements of our common stock plans. We
believe that these sources of funds are sufficient to meet our seasonal working
capital needs.
26
Capital Expenditures and Financing
Construction Expenditures
The table below sets forth our construction expenditures by segment for the
periods indicated:
(In Thousands of Dollars)
- --------------------------------------------------------------------------------
Actual Estimated
Year Ended Year Ended
December 31, 2000 December 31, 2001
- --------------------------------------------------------------------------------
Gas Distribution $ 274,941 $ 404,000
Electric Services 69,921 59,000
Gas Exploration and Production 243,799 245,000
Energy Services 17,362 18,000
Energy Investments and Other 27,012 66,000
------------- -------------------
$ 633,035 $ 792,000
- --------------------------------------- ------------- -------------------
Construction expenditures related to the Gas Distribution segment are primarily
for the renewal and replacement of mains and services and for the expansion of
the gas distribution system on Long Island and in New England. Construction
expenditures for 2000 include costs associated with the gas distribution
operations of Eastern and ENI for two months. Construction expenditures for the
Electric Services segment reflect primarily costs to maintain our electric
generating facilities. Construction expenditures related to the Gas Exploration
and Production segment reflect, in part, costs related to the development of
properties acquired in Southern Louisiana and in the Gulf of Mexico in 1999 and
costs related to the continued development of other properties previously
acquired. Expenditures also include development costs associated with our joint
venture with Houston Exploration. Energy Investments and Other construction
expenditures reflect, primarily costs related to Canadian affiliates.
The amount of future construction expenditures is reviewed on an ongoing basis
and can be affected by timing, scope and changes in investment opportunities.
Equity Investments
During 2000, we made a number of significant equity investments. As previously
mentioned, we acquired Eastern and ENI in November, and we acquired the
remaining 50% in Gulf Midstream during the last quarter of 2000. In addition,
during 2000, the Energy Services segment acquired four additional companies
located in the New York City metropolitan area. The newly acquired companies
specialize in engineering-consulting, plumbing and mechanical contracting, and
heating, ventilation and air conditioning contracting. Combined, these companies
have over 1,300 employees and revenues of approximately $260 million.
27
Financing
In connection with our acquisition of Eastern and ENI, we issued $1.65 billion
of long-term debt. The debt was issued in three different maturities ranging
from five to thirty years in the following denominations: (i) $700 million 7.25%
Notes due 2005; (ii) $700 million 7.625% Notes due 2010; and (iii) $250 million
8.00% Notes due 2030. The interest on the notes is payable on a semi-annual
basis on May 15 and November 15 of each year, beginning May 15, 2001. The total
purchase price for the Eastern and ENI acquisitions was $1.959 billion and, as
previously indicated, we issued approximately $309 million of commercial paper
for additional financing. (See Note 12 to the Consolidated Financial Statements,
"Eastern/EnergyNorth Acquisitions" for further details on the transactions.)
In anticipation of the issuance of long-term debt securities to finance the
Eastern and ENI acquisitions, we entered into forward starting swap agreements
during 2000 to hedge a portion of the risk that the cost of the future issuance
of fixed-rate debt may be adversely affected by increases in interest rates.
Under the forward starting swaps, we agreed to pay or receive an amount equal to
the difference between the net present value of the cash flows for a notional
amount of indebtedness based on the existing yield of a hedging instrument at
the date of the agreement and at the date the agreement is settled. These
derivative instruments were settled at the closing of the Eastern and ENI
transactions.
KEDLI had an effective shelf registration statement on file with the SEC for the
issuance of up to $600 million of medium term notes. On February 1, 2000, KEDLI
issued $400 million 7.875% Notes due February 1, 2010. The net proceeds from
this issuance were used to reimburse our treasury for costs in paying $397
million of promissory notes to LIPA that matured in June 1999. In January 2001,
KEDLI issued an additional $125 million of medium term notes at 6.9% due January
15, 2008. The medium term notes issued are fully and unconditionally guaranteed
by us. We intend to use the proceeds from this financing to fund our gas
expansion initiatives on Long Island. (See Note 7 to the Consolidated Financial
Statements, "Long-Term Debt" for more information regarding outstanding debt.)
In June 2000, we redeemed, at maturity, preferred stock 7.95% Series AA through
the utilization of internally generated funds and the proceeds from the issuance
of commercial paper. Our obligation of $370.2 million included the mandatory
redemption price of $25 per share totaling $363.0 million and a dividend payable
totaling $7.2 million. We anticipate issuing preferred stock during 2001 to
replace this series that matured.
In 1998, our Board of Directors authorized the repurchase of up to 10 percent of
our then outstanding stock, or approximately 15 million common shares. A second
authorization permitted us to use up to an additional $500 million of cash for
the purchase of common shares. In 1999, we completed this program and now
utilize Treasury Stock to satisfy the requirements of our common stock plans. At
December 31, 2000, we had 22.5 million shares, or $650.7 million, of Treasury
Stock remaining.
28
During 2001, we will continue to evaluate our capital structure and debt and
equity levels.Further, we will manage our balance sheet to maintain strong
ratings at each of our rated entities. We believe that our sources of funding,
i.e. anticipated preferred stock issuances, reissuing common stock from Treasury
Stock and the availability of commercial paper borrowings will be sufficient to
meet our anticipated cash needs. Further, as mentioned previously, we may sell
all or a portion of our non-core assets. At December 31, 2000 our ratio of debt,
including commercial paper, to total capitalization was approximately 66%.
However, if we divest of certain non-core assets, we believe that we can achieve
a debt to capitalization ratio of approximately 55% within the next several
years. As a registered holding company, we are subject to certain financing
restrictions. See the discussion under the heading "Securities and Exchange
Commission Regulation" for additional information.
In the fourth quarter of 2000, Moody's Investor Service confirmed the rating on
KeySpan's long- term debt at A3 and confirmed the rating on KEDNY's and Boston
Gas Company's long-term debt at A2. The rating on Midland Enterprises' long-term
debt was confirmed at A3 and the ratings on KEDLI's and Colonial Gas Company's
long-term debt were confirmed at A2. Standard and Poor's rating agency has
confirmed the long-term debt rating on KeySpan, KeySpan Generation, Boston Gas
Company and Colonial Gas Company at A. KEDNY's and KEDLI's long-term debt was
confirmed at A+.
Dividends
We are currently paying a dividend at an annual rate of $1.78 per common share.
Our dividend policy is reviewed annually by the Board of Directors. The amount
and timing of all dividend payments is subject to the discretion of the Board of
Directors and will depend upon business conditions, results of operations,
financial conditions and other factors.
Pursuant to the NYPSC's orders dated February 5, 1998 and April 14, 1998
approving the KeySpan Acquisition, the ability of KEDNY and KEDLI to pay
dividends to the parent company is conditioned upon maintenance of a utility
capital structure with debt not exceeding 55% and 58%, respectively, of total
utility capitalization. In addition, the level of dividends paid by both
utilities may not be increased from current levels if a 40 basis point penalty
is incurred under the customer service performance program. At the end of
KEDNY's and KEDLI's rate years (September 30, 2000 and November 30, 2000,
respectively), the ratio of debt to total utility capitalization was 44% and
46%, respectively. Our corporate and financial activities and those of each of
our subsidiaries (including their ability to pay dividends to us) are also
subject to regulation by the SEC. For additional information, see the discussion
under the heading "Securities and Exchange Commission Regulation" .
Regulation and Rate Matters
Gas Distribution
By orders dated February 5, 1998 and April 14, 1998 the NYPSC approved a
settlement agreement among Brooklyn Union, LILCO, the Staff of the Department of
Public Service and six other parties that in effect approved the KeySpan
Acquisition and established gas rates for both KEDNY and KEDLI. Under the
agreement, $1 billion of efficiency savings, excluding gas
29
costs, attributable to operating synergies that are expected to be realized over
the 10 year period following the combination, were allocated to customers net of
transaction costs.
Under the settlement agreement, effective May 29, 1998, KEDNY's base rates to
core customers were reduced by $23.9 million annually. In addition, KEDNY is now
subject to an earnings sharing provision pursuant to which it will be required
to credit core customers with 60% of any utility earnings up to 100 basis points
above certain threshold return on equity levels over the term of the rate plan
(other than any earnings associated with discrete incentives) and 50% of any
utility earnings in excess of 100 basis points above such threshold levels. The
threshold levels are 13.50% for the rate years ended September 30, 2000 and
2001, and 13.25% for the rate year 2002. KEDNY exceeded the threshold return on
equity by 123 basis points for the rate year ended September 30, 2000.
The settlement agreement also required KEDLI to reduce base rates to its
customers by $12.2 million annually effective February 5, 1998 and by an
additional $6.3 million annually effective May 29, 1998. KEDLI is subject to an
earnings sharing provision pursuant to which it is required to credit to firm
customers 60% of any utility earnings in any rate year up to 100 basis points
above a return on equity of 11.10% and 50% of any utility earnings in excess of
a return on equity of 12.10%. KEDLI did not earn above its threshold return
level in its rate year ended November 30, 2000. On November 30, 2000, KEDLI's
rate agreement with the NYPSC expired. Under the terms of the agreement, current
gas distribution rates will remain in effect for 2001 unless either KEDLI or the
NYPSC initiate a rate proceeding. We do not intend to initiate such a proceeding
and at this time we have no reason to believe that the NYPSC will initiate a
proceeding. Therefore, we expect current gas distribution rates for our New York
and Long Island based gas distribution utilities to remain in effect through
2001.
Boston Gas Company's gas rates for local distribution service are governed by a
five-year performance-based rate plan approved by the DTE in 1996 (the "Plan").
Under the Plan, Boston Gas Company's rates for local distribution are
recalculated annually to reflect inflation for the previous 12 months, and
reduced by a productivity factor of 1%. The productivity factor has been the
subject of a remand proceeding at the DTE as discussed below. The plan also
calls for penalties if Boston Gas Company fails to meet specified service
quality measures, with a maximum potential expense of $1 million, which has also
been a subject in the DTE's remand proceeding. There is a margin sharing
mechanism, whereby 25% of earnings in excess of a 15% return on equity are
passed back to customers. Similarly, ratepayers absorb 25% of any shortfall
below a 7% return on equity.
With respect to the appeal by Boston Gas Company of the Plan, the Massachusetts
Supreme Judicial Court issued an order vacating: (i) the "accumulated
inefficiencies" component of the productivity factor, thereby reducing the
productivity factor from 1.50% to .50%; and (ii) the expansion of the service
quality penalty beyond $1 million, and remanded these matters to the DTE for
further proceedings, which actions were requested by the DTE in its motion for
discharge of report and remand. On January 16, 2001, the DTE issued an order in
the remand proceeding. The order imposes a 0.5% accumulated inefficiencies
factor, thereby increasing the productivity factor from 0.5% to 1% and sets the
maximum service quality adjustment at $1
30
million. The order requires the accumulated inefficiencies factor be implemented
retroactively as of November 1, 1999. On January 30, 2001, Boston Gas Company
filed a Petition for Appeal and Motion for a Stay with the Massachusetts Supreme
Judicial Court, and on February 16, 2001, the court granted the stay pending the
appeal. We are unable to predict the ultimate outcome of this proceeding.
Securities and Exchange Commission Regulation
KeySpan and its subsidiaries are subject to the jurisdiction of the SEC under
PUHCA. The rules and regulations under PUHCA generally limit the operations of a
registered holding company to a single integrated public utility system, plus
additional energy-related businesses. In addition, the principal regulatory
provisions of PUHCA: (i) regulate certain transactions among affiliates within a
holding company system including the payment of dividends by such subsidiaries
to a holding company; (ii) govern the issuance, acquisition and disposition of
securities and assets by a holding company and its subsidiaries; (iii) limit the
entry by registered holding companies and their subsidiaries into businesses
other than electric and/or gas utility businesses; and (iv) require SEC approval
for certain utility mergers and acquisitions.
The SEC's order issued on May 8, 2000, in connection with our acquisition of
Eastern and ENI, provides us with, among other things, authorization to do the
following through December 31, 2003 (the "Authorization Period"): (a) subject to
an aggregate amount of $5.1 billion, (i) maintain existing financing agreements,
(ii) issue and sell up to $1.5 billion of additional securities in compliance
with certain defined parameters, (iii) issue additional guarantees and other
forms of credit support in an aggregate amount of $2.0 billion at any time in
addition to any such securities, guarantees and credit support outstanding or
existing as of November 8, 2000, and (iv) amend, review, extend, supplement or
replace any of the foregoing; (b) issue shares of common stock or reissue shares
of common stock held in treasury under dividend reinvestment and stock-based
management incentive and employee benefit plans; (c) maintain existing and enter
into additional hedging transactions with respect to outstanding indebtedness in
order to manage and minimize interest rate costs; (d) invest up to 250% of our
consolidated retained earnings in exempt wholesale generators and foreign
utility companies; and (e) pay dividends out of capital and unearned surplus as
well as paid-in-capital with respect to certain subsidiaries, subject to certain
limitations.
In addition, we have committed that during the Authorization Period, our common
equity will be at least 30% of our consolidated capitalization and each of our
utility subsidiaries' common equity will be at least 30% of such entity's
capitalization.
31
Electric Services - Revenue Mechanisms
LIPA Agreements
KeySpan, through certain of its subsidiaries, provides services to LIPA under
the following agreements:
Management Services Agreement ("MSA")
A KeySpan subsidiary manages the day-to-day operations, maintenance and capital
improvements of the T&D system. LIPA will exercise control over the performance
of the T&D system through specific standards for performance and incentives. In
exchange for providing the services, we will earn a $10 million annual
management fee and will be operating under an eight-year contract which provides
certain incentives and imposes certain penalties based upon our performance.
Annual service incentives or penalties exist under the MSA if certain targets
are achieved or not achieved. In addition, we can earn certain incentives for
cost reductions associated with the day-to-day operations, maintenance and
capital improvements of LIPA's T&D system. These incentives provide for us to
(i) retain 100% of cost reductions on the first $5 million in reductions, and
(ii) retain 50% of additional cost reductions up to 15% of the total cost
budget, thereafter all savings will accrue to LIPA. With respect to cost
overruns, we will absorb the first $15 million of overruns, with a sharing of
overruns above $15 million. There are certain limitations on the amount of cost
sharing of overruns. To date, we have performed our obligations under the MSA
within the agreed upon budget guidelines and we are committed to providing
on-going services to LIPA within the established cost structure. However, no
assurances can be given as to future operating results under this agreement.
Power Supply Agreement ("PSA")
A KeySpan subsidiary sells to LIPA all of the capacity and, to the extent
requested, energy from our existing Long Island based oil and gas-fired
generating plants. Sales of capacity and energy are made under rates approved by
the Federal Energy Regulatory Commission ("FERC"). The rates may be modified in
the future in accordance with the terms of the PSA for (i) agreed upon labor and
expense indices applied to the base year, (ii) a return of and on net capital
additions required for the generating facilities, and (iii) reasonably incurred
expenses that are outside our control. Rates charged to LIPA include a fixed and
variable component. The variable component is billed to LIPA on a monthly basis
and is dependent on the amount of megawatt hours dispatched. LIPA has no
obligation to purchase energy from us and is able to purchase energy on a
least-cost basis from all available sources consistent with existing
interconnection limitations of the T&D system. We must, therefore, operate our
generating facilities in a manner such that we can remain competitive with other
producers of energy. To date, we have dispatched to LIPA and LIPA has accepted
the level of energy generated at the agreed to price per megawatt hour. However,
no assurances can be given as to the level and price of energy to be dispatched
to LIPA in the future. The PSA provides incentives and penalties that can total
$4 million annually for the maintenance of the output capability of the
generating facilities. The PSA runs for a term of fifteen years.
32
As discussed previously, beginning on May 28, 2001, LIPA will have the right for
a one-year period to acquire all of our Long Island based generating assets at
the fair market value at the time of the exercise of the right, which value
would be determined by independent appraisers.
Energy Management Agreement ("EMA")
The EMA provides for a KeySpan subsidiary to procure and manage fuel supplies
for LIPA to fuel the generating facilities under contract to it and perform
off-system capacity and energy purchases on a least-cost basis to meet LIPA's
needs. In exchange for these services we earn an annual fee of $1.5 million. In
addition, we arrange for off-system sales on behalf of LIPA of excess output
from the generating facilities and other power supplies either owned or under
contract to LIPA. LIPA is entitled to two-thirds of the profit from any
off-system energy sales. In addition, the EMA provides incentives and penalties
that can total $7 million annually for performance related to fuel purchases and
off-system power purchases. The EMA covers a period of fifteen years for the
procurement of fuel supplies and eight years for off-system management services.
Ravenswood Facility
At the time of our purchase of the Ravenswood facility, KeySpan and Consolidated
Edison entered into transition energy and capacity contracts. The energy
contract provided Consolidated Edison with 100% of the energy produced by the
Ravenswood facility and covered a period of time from the date of closing, June
18, 1999, through November 18, 1999. With the start-up of the NYISO, the
electricity market in New York City began a transition to a competitive market
for capacity, energy and ancillary services. Starting on November 18, 1999, we
began selling the energy produced by the Ravenswood facility through bidding
into the NYISO energy markets on a day ahead or real time basis. We also have
the option to enter into bilateral transactions to sell all or a portion of the
energy produced by the Ravenswood facility to Load Serving Entities ("LSE"),
i.e. entities that sell to end-users or to brokers and marketers. At this point
in time, we have sold energy exclusively through the NYISO. The capacity
contract, which provided Consolidated Edison with 100% of the available capacity
of the Ravenswood facility expired on April 30, 2000. Since that date, the
available capacity of the Ravenswood facility has been bid into on the auction
process conducted by the NYISO. We also have the option to sell the capacity
through bilateral contracts. It is anticipated that in 2001, approximately 50%
of earnings from the Ravenswood facility will be derived from capacity sales
through either the auction process associated with the NYISO or contracts with
LSEs.
Environmental Matters
KeySpan is subject to various federal, state and local laws and regulatory
programs related to the environment. Ongoing environmental compliance
activities, which have not been material, are charged to operation and
maintenance activities. We estimate that the remaining cost of our manufactured
gas plant ("MGP") related environmental cleanup activities, including costs
associated with the Ravenswood facility and costs associated with Eastern and
ENI MGP sites, will be approximately $137.5 million and we have recorded a
related liability for such amount. Eastern has recorded an additional $20
million liability representing the estimated environmental
33
cleanup costs related to a former coal tar processing facility. Further, as of
December 31, 2000, we have expended a total of $29.1 million, including
expenditures made by Eastern and ENI since acquisition. (See Note 9 to the
Consolidated Financial Statements, "Contractual Obligations and Contingencies.")
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are subject to various risk exposures and uncertainties associated with our
operations. The most significant contingency involves the evolution of the gas
distribution industry toward a more competitive and deregulated environment.
Most important to KeySpan, is the evolution of regulatory policy as it pertains
to our historical gas merchant role. In addition, we are exposed to commodity
price risk, interest rate risk and, to a much less degree, foreign currency
translation risk. Set forth below is a description of these exposures and an
explanation as to how we have managed and, to the extent possible, sought to
reduce these risks.
Regulatory Issues and the Competitive Environment
The Gas Industry
The energy industry continues to undergo fundamental changes, which may have a
significant impact on the future financial performance of utilities, as
regulatory authorities, elected officials and customers seek lower energy prices
and broader choices.
New York
Over the past several years, the NYPSC has been formulating a policy framework
to guide the transition of New York State's gas distribution industry in the
deregulated gas industry environment. Since 1996, customers in the small-volume
market have been given the option to purchase their gas supplies from sources
other than our two New York gas utility subsidiaries. Large-volume customers had
this option for a number of years prior to 1996. In addition to transporting gas
that customers purchase from marketers, our utilities have been providing
billing, meter reading and other services for aggregate rates that match the
distribution charge reflected in otherwise applicable sales rates to supply
these customers.
In November 1998, the NYPSC issued a policy statement setting forth its vision
for furthering competition in the natural gas industry. Under this vision,
regulated natural gas utilities or local distribution companies ("LDCs") would
plan to exit the business of purchasing gas for and selling gas to customers
(the merchant function) over the next three to seven years. LDCs would remain
the operators of the gas system (the distribution function) and the provider of
last resort of natural gas supplies during that period and until alternatives
are developed. The NYPSC's goal is to encourage more competition at the local
level by separating the merchant function from the distribution function.
As required by the NYPSC's policy statement, our two New York gas distribution
subsidiaries filed a joint restructuring proposal with the NYPSC in October
1999. Settlement discussions
34
with the Staff of the NYPSC and other interested parties were held regarding the
joint restructuring proposal. Those discussions resulted in an Interim Gas
Restructuring Agreement which the NYPSC approved in its Order Establishing
Interim Rate Plan ("Interim Agreement"), issued on December 26, 2000. The
Interim Agreement as approved provided that, among other things: (i) present
base rates will remain unchanged; (ii) heating customers will receive a one-
time bill credit of $50 to offset gas commodity prices during the winter of
2001; and (iii) marketers will receive an incentive payment equal to 8% of the
delivery charges marketers incur to serve firm customers to encourage marketers
to provide gas commodity sales to our customers. Both the $50 credit and the 8%
incentive payment will be deferred, and the formula for recovery of potential
stranded capacity costs will be modified to maintain a more stable allocation of
fixed costs between sales and transportation services. The term of the Interim
Agreement expires on June 30, 2001, and also provides that the parties will
resume negotiations on issues that were not resolved, including, daily
balancing, a migration program for cooking- only customers, a low income
customer aggregation program, and a back out credit to be applied to rates
charged to customers who migrate to a non-utility energy supplier. We, the Staff
of the NYPSC and other interested parties have begun discussions to address the
issues remaining in the case.
New England
In July 1997, the DTE directed Massachusetts gas distribution companies to
undertake a collaborative process with other stakeholders to develop common
principles under which comprehensive gas service unbundling might proceed. A
settlement agreement by the LDC's and the marketer group regarding model terms
and conditions for unbundled transportation service was approved by the DTE in
November 1998. In February 1999, the DTE issued its order on how unbundling of
natural gas service will proceed. For a five year transition period, the DTE
determined that LDC contractual commitments to upstream capacity will be
assigned on a mandatory, pro rata basis to marketers selling gas supply to the
LDC's customers. The approved mandatory assignment method eliminates the
possibility that the costs of upstream capacity purchased by the LDCs to serve
firm customers will be absorbed by the LDC or other customers through the
transition period. The DTE also found that, through the transition period, LDCs
will retain primary responsibility for upstream capacity planning and
procurement to assure that adequate capacity is available to support customer
requirements and growth. Last fall, the DTE approved the LDCs Terms and
Conditions of Distribution Service that conform to the settled upon model terms
and conditions. Effective November 1, 2000, all Massachusetts gas customers have
the option to purchase their gas supplies from third party sources other than
the LDCs.
We believe that the actions described above strike a balance among competing
stakeholder interests in order to most effectively make available the benefits
of the unbundled gas supply market to all customers.
35
The Electric Industry in New York and Long Island
As previously mentioned, our electric operations on Long Island are generally
governed by service agreements with LIPA. The agreements have terms of eight to
fifteen years and generally provide for recovery of virtually all costs of
production, operation and maintenance. At this time, we face minimal competitive
pressures associated with our electric operations on Long Island.
With our investment in the Ravenswood facility, we also have electric operations
in New York City. We currently sell the energy produced by the Ravenswood
facility, as well as its capacity, through daily and/or hourly bidding into the
NYISO energy markets. New York City local reliability rules currently require
that 80% of the electric capacity needs of New York City is to be provided by
"in-city" generators. At this time, there is a shortage of in-city capacity and
therefore, we anticipate that we can sell the capacity of the Ravenswood
facility at a level approaching the FERC mandated price cap. We expect that the
current local reliability rules will remain in effect at least through October
31, 2001. However, should new, more efficient electric power plants be built in
New York City and/or the requirement that 80% of in-city load be served by
in-city generators be modified, capacity and energy sales volumes could be
adversely affected. We cannot predict, however, when or if new power plants will
be built or the nature of future New York City requirements.
California Deregulation
In the late 1990's, the California Public Utilities Commission ("CPUC") ordered
the state's electric utilities to divest their generation assets, and purchase
their electricity supply from the California Power Exchange (PX) on a spot or
short term basis. In addition, the electric utilities were subjected to caps on
the prices they charged their customers at retail. No provisions were made in
the CPUC's orders or the restructuring agreements entered into by the utilities
and other parties to reopen the retail rate issue in the event the utilities'
financial integrity became jeopardized.
Within the last year, wholesale electricity supply levels have become
insufficient to meet demand, spot market prices have increased, and retail rates
are now insufficient to compensate the utilities for their wholesale supply
costs, causing severe financial disruptions for those utilities.
In contrast, our gas distribution subsidiaries maintain flexibility in their gas
procurement policies and practices and are not required to purchase gas
commodity or capacity in any specific manner as long as the purchases are made
on a least cost basis. Our gas distribution subsidiaries also operate under rate
regulated cost recovery mechanisms associated with their retail rates that
provide for recovery of costs on a current and deferred basis. In the event that
our gas distribution subsidiaries' financial integrity were jeopardized, there
is a provision in their currently effective rate plans that would allow for the
reexamination of their retail rate structure. With regards to our electric
service operations, as previously indicated, under our LIPA service agreements,
virtually all costs of production, operation and maintenance are being
recovered.
36
In addition, due to New York City local reliability rules, we anticipate that we
can sell a significant portion of the capacity associated with the Ravenswood
facility. Moreover, we are currently recovering 100% of our electric fuel costs
and expect to continue to recover these costs through sales into the NYISO.
Derivative Financial Instruments
As previously mentioned, and more fully detailed in Note 10 to the Consolidated
Financial Statements, "Hedging, Derivative Financial Instruments and Fair
Values," we employ derivative instruments to hedge a portion of our exposure to
commodity price risk and interest rate risk and to fix the selling price on a
portion of our peak electric energy capacity. All of our derivative financial
instruments, except for certain interest rate swaps, are and will continue to be
classified as cash-flow hedges and expire in 2001. As a result, Statement of
Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative
Instruments and Hedging Activities" is not expected to have a material effect on
our net income in 2001, but could have a significant effect on comprehensive
income because of fluctuations in the market value of the derivatives employed
for hedging certain risks. Under SFAS No. 133, periodic changes in market value
are recorded as comprehensive income, subject to effectiveness, and then
included in net income to match the underlying transactions.
Futures, Options and Swaps: We employ, from time to time, derivative financial
instruments, such as futures, options and swaps, for the purpose of hedging
exposure to commodity price risk and to fix the selling price on a portion of
our peak electric energy capacity.
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, as the instrument contracts are with major
investment grade financial institutions, and that reduction of the exposure to
price risk lowers our overall business risk.
Interest Rate Hedges: We continually monitor the cost relationship between fixed
and variable rate debt. In line with our objective to minimize capital costs, we
periodically enter into hedging transactions through interest rate swaps that
effectively convert the terms of the underlying debt obligations from fixed to
variable and/or variable to fixed. Swap agreements are only entered into with
creditworthy counter parties.
37
Foreign Currency Fluctuations
We follow the principles of SFAS No. 52, "Foreign Currency Translation" for
recording our investments in foreign affiliates. Due to our purchases of certain
Canadian interests and our continued activities in Northern Ireland, our
investment in foreign affiliates has been growing. At December 31, 2000, our net
assets in these affiliates was approximately $347.6 million and at December 31,
2000, the accumulated foreign currency translation debit was $2.3 million. (See
Note 1 to the Consolidated Financial Statements, "Summary of Significant
Accounting Policies.")
38
Item 8. Financial Statements and Supplementary Data
Financial Statement Responsibility
KeySpan's and its subsidiaries' Consolidated Financial Statements were prepared
by management in conformity with generally accepted accounting principles.
KeySpan's system of internal controls is designed to provide reasonable
assurance that assets are safeguarded and that transactions are executed in
accordance with management's authorizations and recorded to permit preparation
of financial statements that present fairly the financial position and operating
results of KeySpan. KeySpan's internal auditors evaluate and test the system of
internal controls. The Company's Vice President and General Auditor reports
directly to the Audit Committee of the Board of Directors, which is composed
entirely of outside directors. The Audit Committee meets periodically with
management, the Vice President and General Auditor and Arthur Andersen LLP to
review and discuss internal accounting controls, audit results, accounting
principles and practices and financial reporting matters.
CONSOLIDATED BALANCE SHEET
(In Thousands of Dollars)
December 31, 2000 December 31, 1999
- --------------------------------------------------------------------------------------------------------------------------------
ASSETS
Current Assets
Cash and temporary cash investments $ 94,508 $ 128,602
Customer accounts receivable 1,471,102 425,643
Other accounts receivable 300,198 235,156
Allowance for uncollectible accounts (49,478) (20,294)
Gas in storage, at average cost 282,654 144,256
Materials and supplies, at average cost 123,608 84,813
Other 180,651 159,777
------------------ -------------------
2,403,243 1,157,953
------------------ -------------------
Equity Investments and Other 199,196 391,731
------------------ -------------------
Property
Gas 5,346,799 3,449,384
Electric 1,412,839 1,346,851
Other 734,801 375,657
Accumulated depreciation (2,301,722) (1,589,287)
Gas exploration, production and refining 1,781,379 1,177,916
Accumulated depletion (615,799) (520,509)
------------------ -------------------
6,358,297 4,240,012
------------------ -------------------
Deferred Charges
Regulatory assets 385,116 319,167
Goodwill, net of amortizations 1,848,721 255,778
Other 355,548 366,050
------------------ -------------------
2,589,385 940,995
------------------ -------------------
------------------ -------------------
Total Assets $ 11,550,121 $ 6,730,691
================== ===================
See accompanying Notes to the Consolidated Financial Statements.
39
CONSOLIDATED BALANCE SHEET
(In Thousands of Dollars)
December 31, 2000 December 31, 1999
- ------------------------------------------------------------------------------------------------------------------------------------
LIABILITIES AND CAPITALIZATION
Current Liabilities
Current redemption of long-term debt $ 5,480 $ -
Current redemption of preferred stock - 363,000
Accounts payable and accrued expenses 1,429,267 645,347
Commercial paper 1,300,237 208,300
Dividends payable 62,218 61,306
Taxes accrued 74,614 50,437
Customer deposits 32,855 31,769
Interest accrued 69,402 28,093
---------------------- -------------------
2,974,073 1,388,252
---------------------- -------------------
Deferred Credits and Other Liabilities
Regulatory liabilities 34,486 26,618
Deferred income tax 451,721 188,930
Postretirement benefits and other reserves 662,866 501,603
Other 126,818 66,200
---------------------- -------------------
1,275,891 783,351
---------------------- -------------------
Capitalization
Common stock 2,985,022 2,973,388
Retained earnings 480,639 456,882
Other Comprehensive Income 825 5,014
Treasury stock purchased (650,670) (722,959)
---------------------- -------------------
Total common shareholders' equity 2,815,816 2,712,325
Preferred stock 84,205 84,339
Long-term debt 4,274,938 1,682,702
---------------------- -------------------
Total Capitalization 7,174,959 4,479,366
---------------------- -------------------
Minority Interest in Subsidiary Companies 125,198 79,722
---------------------- -------------------
Total Liabilities and Capitalization $ 11,550,121 $ 6,730,691
====================== ===================
See accompanying Notes to the Consolidated Financial Statements.
40
CONSOLIDATED STATEMENT OF INCOME
(In Thousands of Dollars, Except Per Share Amounts)
Year Year Nine Months
Ended Ended Ended
December 31, December 31, December 31,
2000 1999 1998
- ---------------------------------------------------------------- ------------------------- ---------------------- ------------------
Revenues
Gas Distribution $ 2,555,785 $ 1,753,132 $ 856,172
Electric Services 1,444,711 861,582 738,316
Gas Exploration and Production 274,209 150,581 70,812
Energy Services 771,861 186,529 63,064
Energy Investments and Other 74,924 2,789 117
--------------- ---------------- -------------
Total Revenues 5,121,490 2,954,613 1,728,481
--------------- ---------------- -------------
Operating Expenses
Purchased gas for resale 1,408,621 744,432 331,690
Fuel and purchased power 460,900 17,252 91,762
Operations and maintenance 1,695,507 1,091,166 777,678
Early retirement and severance charges 65,175 - 64,635
Depreciation, depletion and amortization 335,106 253,440 254,859
Operating taxes 424,318 366,154 257,124
--------------- ---------------- -------------
Total Operating Expenses 4,389,627 2,472,444 1,777,748
--------------- ---------------- -------------
Operating Income (Loss) 731,863 482,169 (49,267)
--------------- ---------------- -------------
Other Income and (Deductions)
Income from equity investments 20,010 15,347 5,841
Interest income 13,190 26,993 50,104
Transaction related expenses (net of $99,701 income tax) - - (107,912)
Minority interest (26,342) (11,141) 29,141
Other (18,288) 15,356 (13,901)
--------------- ---------------- -------------
Total Other Income (11,430) 46,555 (36,727)
--------------- ---------------- -------------
Income (Loss) Before Interest Charges
and Income Taxes 720,433 528,724 (85,994)
--------------- ---------------- -------------
Interest Charges 203,350 133,751 140,733
--------------- ---------------- -------------
Income Taxes
Current 169,823 26,618 26,142
Deferred 46,453 109,744 (85,936)
--------------- ---------------- -------------
Total Income Taxes 216,276 136,362 (59,794)
--------------- ---------------- -------------
Net Income (Loss) 300,807 258,611 (166,933)
Preferred stock dividend requirements 18,113 34,752 28,604
--------------- ---------------- -------------
Earnings (Loss) for Common Stock $ 282,694 $ 223,859 $ (195,537)
=============== ================ =============
Average Common Shares Outstanding (000) 134,357 138,526 145,767
$ $ $
Basic and Diluted Earnings (Loss) Per Common Share 2.10 1.62 (1.34)
=============== ================ =============
See accompanying Notes to the Consolidated Financial Statements.
41
CONSOLIDATED STATEMENT OF CASH FLOWS
(In Thousands of Dollars)
Nine Months
Year Ended Year Ended Ended
December 31, December 31, December 31,
2000 1999 1998
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net Income (Loss) $ 300,807 $ 258,611 $ (166,933)
Adjustments to reconcile net income to net
cash provided by (used in) operating activities
Depreciation, depletion and amortization 335,106 253,440 254,859
Early retirement and severance accruals 65,175 - 64,635
Deferred income tax 46,453 109,744 (85,936)
Income from equity investments (20,010) (15,347) (5,841)
Dividends from equity investments 21,507 9,368 4,219
Changes in assets and liabilities
Accounts receivable (800,033) (132,114) (81,024)
Materials and supplies, fuel oil and gas in storage (36,952) (9,789) (63,195)
Accounts payable and accrued expenses 452,076 83,493 132,028
Interest accrued 32,659 8,128 (151,268)
Special deposits 17,896 52,373 (41,040)
Other 35,221 (28,902) (320,792)
-------------------- ----------------- ------------------
Net Cash Provided by (Used in) Operating Activities 449,905 589,005 (460,288)
-------------------- ----------------- ------------------
Investing Activities
Construction expenditures (633,035) (671,845) (676,563)
Other Investments (292,222) (53,825) -
Acquisition of Eastern Enterprise and EnergyNorth, Inc. (1,946,043) - -
Net Proceeds from LIPA Transaction - - 2,314,588
Other (510) 30,006 178,634
-------------------- ----------------- ------------------
Net Cash (Used in) Provided by Investing Activities (2,871,810) (695,664) 1,816,659
-------------------- ----------------- ------------------
Financing Activities
Proceeds from sale of common stock - - 10,170
Treasury stock issued (purchased) 72,289 (299,243) (423,716)
Issuance of long-term debt 2,166,955 102,648 112,535
Issuance of commercial paper 1,300,237 208,300 -
Payment of commercial paper (364,865) - -
Payment of long-term debt (68,365) (442,475) (103,000)
Issuance of preferred stock - - 84,973
Payment of preferred stock (363,000) - -
Preferred stock dividends paid (20,261) (34,760) (28,604)
Common stock dividends paid (239,740) (249,567) (210,177)
Settlement on interest rate lock (59,490) - -
Other (35,949) 7,582 (36,695)
-------------------- ----------------- ------------------
Net Cash Provided by (Used in) Financing Activities 2,387,811 (707,515) (594,514)
-------------------- ----------------- ------------------
Net (Decrease) or Increase in Cash and Cash Equivalents $ (34,094) $ (814,174) $ 761,857
==================== ================= ==================
Cash and cash equivalents at beginning of period $ 128,602 $ 942,776 $ 180,919
Net (Decrease) or Increase in cash and cash equivalents (34,094) (814,174) 761,857
-------------------- ----------------- ------------------
Cash and Cash Equivalents at End of Period $ 94,508 $ 128,602 $ 942,776
==================== ================= ==================
Interest paid $ 165,020 $ 109,614 $ 125,914
Income tax paid $ 187,219 $ 38,700 $ 94,680
See accompanying Notes to the Consolidated Financial Statements.
42
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
(In Thousands of Dollars)
Nine Months
Year Ended Year Ended Ended
December 31, December 31, 1999 December 31, 1998
2000
- ----------------------------------------------------- ------------------------ -------------------------- ------------------------
Balance at Beginning of Period $ 456,882 $ 474,188 $ 956,092
Net Income (loss) for period 300,807 258,611 (166,933)
------------------------ -------------------------- ------------------------
757,689 732,799 789,159
Deductions:
Cash dividends declared on common stock 239,740 246,251 214,012
Cash dividends declared on preferred stock 20,298 34,752 28,604
Other, primarily write-off of
capital stock expense 17,012 (5,086) 72,355
------------------------ -------------------------- ------------------------
Balance at End of Period $ 480,639 $ 456,882 $ 474,188
- ----------------------------------------------------- ------------------------ -------------------------- ------------------------
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(In Thousands of Dollars)
Nine Months
Year Ended Year Ended Ended
December 31, 2000 December 31, 1999 December 31, 1998
- ------------------------------------------------------------------------------------------------------------------------------------
Net Income $ 300,807 $ 258,611 $ (166,933)
------------------ ---------------------- -------------------------
Other comprehensive income (loss), net of tax
Foreign currency translation adjustments (7,320) 5,633 (619)
Unrealized gains on securities 3,131 - -
------------------ ---------------------- -------------------------
Other comprehensive income (loss) (4,189) 5,633 (619)
------------------ ---------------------- -------------------------
Comprehensive income $ 296,618 $ 264,244 $ (167,552)
- ---------------------------------------------------------- ------------------ ---------------------- -------------------------
Related tax (benefit) expense
Foreign currency translation adjustments $ (3,941)$ 3,033 $ (333)
Unrealized gains on securities 1,686 - -
------------------ ---------------------- -------------------------
Total tax (benefit) expense $ (2,255)$ 3,033 $ (333)
- ---------------------------------------------------------- ------------------ ---------------------- -------------------------
See accompanying Notes to the Consolidated Financial Statements.
43
CONSOLIDATED STATEMENT OF CAPITALIZATION
Shares Issued (In Thousands of Dollars)
- -------------------------------------------------- --- -----------------------------------------------------------------------------
December 31, December 31, December 31, December 31,
2000 1999 2000 1999
- -------------------------------------------------- --- -----------------------------------------------------------------------------
Common Shareholder's Equity
Common Stock, $0.01 par value 158,837,654 158,837,654 $ 1,588 $ 1,588
Premium on capital stock 2,983,434 2,971,800
Retained Earnings 480,639 456,882
Other Comprehensive Income 825 5,014
Treasury Stock 22,474,628 24,971,577 (650,670) (722,959)
---------------- ------------------ ------------- --------------
Total Common Shareholder's Equity 136,363,026 133,866,077 2,815,816 2,712,325
---------------- ------------------ ------------- --------------
Preferred Stock - Redemption Required
Par Value $25 per share
7.95% Series AA - 14,520,000 - 363,000
Less - mandatory redemption of preferred stock - 363,000
------------- --------------
Total Preferred Stock - Redemption Required - -
------------- --------------
Preferred Stock - No Redemption Required
Par Value $100 per share
7.07% Series B-private placement 553,000 553,000 55,300 55,300
7.17% Series C-private placement 197,000 197,000 19,700 19,700
6.00% Series A-private placement 92,050 93,390 9,205 9,339
------------- --------------
Total Preferred Stock -
No Redemption Required 84,205 84,339
------------- --------------
- ------------------------------------------------------------------------------------------------------------------------------------
Long - Term Debt Interest Rate Maturity
----------------------------------------
First Mortgage Bonds 5.50% - 10.10% 2002-2028 322,872 -
------------------ ---------------
Notes
Medium Term Notes 6.80% - 9.75% 2005-2030 2,260,000 -
Senior Subordinated Notes 8.625% 2008 100,000 100,000
------------------ ---------------
Total Notes 2,360,000 100,000
------------------ ---------------
Gas Facilities Revenue Bonds Variable 2020 125,000 125,000
5.50% - 6.95% 2020-2026 523,500 523,500
------------------ ---------------
Total Gas Facilities Revenue Bonds 648,500 648,500
------------------ ---------------
Authority Financing Notes Variable 2027-2028 66,005 66,005
----------------- ---------------
Promissory Notes to LIPA
Debentures 8.20% 2023 270,000 270,000
Pollution Control Revenue Bonds 5.15% 2016 108,022 108,022
Electric Facilities Revenue Bonds 5.30% - 7.15% 2019-2025 224,405 224,405
----------------- ---------------
Total Promissory Notes to LIPA 602,427 602,427
---------------- ---------------
Other Subsidiary Debt 328,227 267,405
---------------- ---------------
Capital Leases 2008-2020 22,005 -
---------------- ---------------
Subtotal 4,350,036 1,684,337
Unamortized Interest Rate Hedge
and Debt Discount (69,618) (1,635)
Less Current Maturities 5,480 -
----------------- ----------------
Total Long Term Debt 4,274,938 1,682,702
----------------- ----------------
Total Capitalization $ 7,174,959 $ 4,479,366
================= ================
See accompanying Notes to the Consolidated Financial Statements.
44
Notes to the Consolidated Financial Statements
Note 1. Summary of Significant Accounting Policies
A. Organization of the Company
KeySpan Corporation, a New York corporation, was formed in May 1998, as a result
of the business combination of KeySpan Energy Corporation, the parent of The
Brooklyn Union Gas Company, and certain businesses of the Long Island Lighting
Company ("LILCO"). On November 8, 2000, we acquired Eastern Enterprises
("Eastern"), a Massachusetts business trust, and the parent of several gas
utilities operating in Massachusetts. Also on November 8, 2000, Eastern acquired
EnergyNorth, Inc. ("ENI"), the parent of a gas utility operating in central New
Hampshire. KeySpan Corporation will be referred to in these notes to the
Consolidated Financial Statements as "KeySpan", "we", "us" and "our."
Our core business is gas distribution, conducted by our six regulated gas
utility subsidiaries: The Brooklyn Union Gas Company d/b/a KeySpan Energy
Delivery New York ("KEDNY") and KeySpan Gas East Corporation d/b/a KeySpan
Energy Delivery Long Island ("KEDLI") distribute gas to customers in the
boroughs of Brooklyn, Queens and Staten Island in New York City and the counties
of Nassau and Suffolk on Long Island, respectively; Boston Gas Company, Colonial
Gas Company and Essex Gas Company, each doing business as KeySpan Energy
Delivery New England ("KEDNE"), distribute gas to customers in southern and
central Massachusetts; and EnergyNorth Natural Gas, Inc., d/b/a KeySpan Energy
Delivery New England distributes gas to customers in central New Hampshire.
Together, these companies distribute gas to approximately 2.4 million customers
throughout the Northeast.
We also own and operate generating plants on Long Island and in New York City.
Under contractual arrangements, we provide power, electric transmission and
distribution services, billing and other customer services for approximately one
million electric customers of the Long Island Power Authority ("LIPA"). (See
Note 2, "Business Segments" for additional information on each operating
segment.)
Our other subsidiaries are involved in gas and oil exploration and production;
gas storage; wholesale and retail gas and electric marketing; appliance service;
heating, ventilation and air conditioning installation and services; large
energy-system ownership, installation and management; fiber optic services;
energy-related internet activities; fuel cells; marine transportation, including
the barge hauling of fuel and other cargo; and providing meter reading equipment
and services to municipal utilities. We also invest in, and participate in the
development of, pipelines and other energy-related projects, domestically and
internationally.
We are a registered holding company under the Public Utility Holding Company Act
of 1935 ("PUHCA"), as amended. Therefore, our corporate and financial activities
and those of our subsidiaries, including their ability to pay dividends to us,
are subject to regulation by the Securities and Exchange Commission ("SEC").
Under our holding company structure, we have no
45
independent operations or source of income of our own and conduct substantially
all of our operations through our subsidiaries and, as a result, we depend on
the earnings and cash flow of, and dividends or distributions from, our
subsidiaries to provide the funds necessary to meet our debt and contractual
obligations. Furthermore, a substantial portion of our consolidated assets,
earnings and cash flow is derived from the operations of our regulated utility
subsidiaries, whose legal authority to pay dividends or make other distributions
to us is subject to regulation by state regulatory authorities.
B. Basis of Presentation
The Consolidated Financial Statements presented herein reflect the accounts of
KeySpan and its subsidiaries. Most of our subsidiaries are fully consolidated in
the financial information presented, except for certain subsidiary investments
in the Energy Investment segment which are accounted for on the equity method as
we do not have a controlling voting interest or otherwise have control over the
management of such investee companies. All significant intercompany transactions
have been eliminated.
Certain reclassifications were made to conform prior period financial statements
with the current period financial statement presentation.
The financial statements presented herein include the year ended December 31,
2000, the year ended December 31, 1999, and the nine month period April 1, 1998
through December 31, 1998 (the "Transition Period"). For financial reporting
purposes, LILCO was deemed the acquiring company pursuant to a purchase
accounting transaction, in which KeySpan Energy Corporation ("KSE") was acquired
("KeySpan Acquisition"). Consequently, our financial results prior to May 29,
1998 reflect those of LILCO only. Since the acquisition of KeySpan Energy
Corporation was accounted for as a purchase, related accounting adjustments,
including goodwill, have been reflected in the financial statements herein.
Further, in September 1998, we changed our fiscal year end from March 31 to
December 31. For additional information regarding the KeySpan acquisition. (See
Note 15. "Sale of LILCO Assets, Acquisition of KeySpan Energy Corporation and
Transfer of Assets and Liabilities to KeySpan.")
As noted, on November 8, 2000, we completed the acquisitions of Eastern
Enterprises ("Eastern") and EnergyNorth Inc. The transactions have been
accounted for using the purchase method of accounting for business combinations
and accordingly the accompanying consolidated financial statements include the
results of Eastern and ENI for the period November 8, 2000 through December 31,
2000.
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
46
C. Accounting for the Effects of Rate Regulation
The accounting records for our six regulated gas utilities are maintained in
accordance with the Uniform System of Accounts prescribed by the Public Service
Commission of the State of New York ("NYPSC"), the New Hampshire Public Utility
Commission, and the Massachusetts Department of Telecommunications and Energy
("DTE"). Our electric generation subsidiaries are not subject to state
regulation, but they are subject to Federal Energy Regulatory Commission
("FERC") regulation. Our financial statements reflect the ratemaking policies
and actions of these regulators in conformity with generally accepted accounting
principles for rate-regulated enterprises.
Four of our six regulated gas utilities (KEDNY, KEDLI, Boston Gas Company and
EnergyNorth Natural Gas, Inc.) and our electric generation subsidiaries are
subject to the provisions of Statement of Financial Accounting Standards
("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation."
This statement recognizes the ability of regulators, through the ratemaking
process, to create future economic benefits and obligations affecting
rate-regulated companies. Accordingly, we record these future economic benefits
and obligations as regulatory assets and regulatory liabilities, respectively.
In separate merger-related orders issued by the DTE, the base rates charged by
Colonial Gas Company and Essex Gas Company have been frozen at their current
levels for a ten-year period. Due to the length of this base rate freeze, the
Colonial and Essex Gas Companies have previously discontinued the application of
SFAS No. 71.
The following table presents our net regulatory assets at December 31, 2000 and
December 31, 1999.
(In Thousands of Dollars)
- -----------------------------------------------------------------------------------------------------------
December 31, 2000 December 31, 1999
- -------------------------------------------------------- -------------------- ----------------------------
Regulatory Assets
Regulatory tax asset $ 61,071 $ 65,462
Property taxes 51,948 40,434
Environmental costs 116,609 95,627
Postretirement benefits other than pensions 89,188 48,553
Costs associated with the KeySpan Acquisition 66,300 69,091
------------------ ----------------------
Total Regulatory Assets $ 385,116 $ 319,167
Regulatory Liabilities 34,486 26,618
------------------ ----------------------
Net Regulatory Assets $ 350,630 $ 292,549
- -------------------------------------------------------- ------------------ ----------------------
The regulatory assets above are not included in our rate base. However, we
record carrying charges on the property tax and costs associated with the
KeySpan Acquisition deferrals. We also record carrying charges on our regulatory
liability. The remaining regulatory assets represent, primarily, costs for which
expenditures have not yet been made, and therefore, carrying charges are not
47
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 $189.8 million and $1.2 million at December 31, 2000 and December
31, 1999, respectively are reflected in accounts receivable on the Consolidated
Balance Sheet.
We estimate that full recovery of our regulatory assets will not exceed 15
years, except for the tax regulatory asset which will be recovered over the
estimated lives of certain utility property.
Rate regulation is undergoing significant change as regulators and customers
seek lower prices for utility service and greater competition among energy
service providers. In the event that regulation significantly changes the
opportunity for us to recover costs in the future, all or a portion of our
regulated operations may no longer meet the criteria for the application of SFAS
No. 71. In that event, a write-down of all or a portion of our existing
regulatory assets and liabilities could result. If we had been unable to
continue to apply the provisions of SFAS No. 71 for any of our rate regulated
subsidiaries, we would have applied the provisions of SFAS No. 101 "Regulated
Enterprises - Accounting for the Discontinuation of Application of FASB
Statement No. 71." We estimate that the write-off of all our net regulatory
assets at December 31, 2000 could result in a charge to net income of $227.9
million or $1.70 per share, which would be classified as an extraordinary item.
In management's opinion, our regulated subsidiaries that are currently subject
to the provisions of SFAS No. 71 will continue to be subject to SFAS No. 71 for
the foreseeable future.
D. Revenues
Utility gas customers are billed monthly and 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 an annual reconciliation of recoverable gas costs and GAC
revenues. Any difference is deferred pending recovery from or refund to firm
customers. Further, net revenues from tariff gas balancing services, off-system
sales and certain on-system interruptible sales are refunded, for the most part,
to firm customers subject to certain sharing provisions.
The New York and Long Island gas utility tariffs contain weather normalization
adjustments that largely offset shortfalls or excesses of firm net revenues
(revenues less gas costs and revenue taxes) during a heating season due to
variations from normal weather. The New England gas utility rate structures
contain no weather normalization feature, therefore their net revenues are
subject to weather related demand fluctuations.
48
Electric revenues are derived from billings to LIPA for management of LIPA's
transmission and distribution ("T&D") system, electric generation, and
procurement of fuel. The agreements with LIPA include provisions for us to earn,
in the aggregate, approximately $11.5 million per year (plus up to an additional
$5 million per year if certain cost savings are achieved) in annual management
service fees from LIPA for the management of the LIPA T&D system and the
management of all aspects of fuel and power supply. Under a management service
agreement ("MSA") costs in excess of budgeted levels are assumed by us up to $15
million, while cost reductions in excess of $5 million from budgeted levels are
shared with LIPA. These agreements also contain certain non-cost incentive and
penalty provisions which could impact earnings. Billings associated with
generation capacity are based on pre-determined levels of supply to be
dispatched to LIPA on a yearly basis. Rates billed to LIPA on a monthly basis
include fixed and variable components. Billings related to transmission,
distribution and delivery services are based, in part, on negotiated budgeted
levels.
In addition, electric revenues are derived from our investment in the 2,200
megawatt Ravenswood electric generation facility ("Ravenswood facility"), which
we acquired in June 1999. (See Note 9, "Contractual Obligations and
Contingencies" for a description of the Ravenswood transaction.) We currently
realize revenues from our investment in the Ravenswood facility through the
wholesale sale of energy, capacity, and ancillary services to the New York
Independent System Operator ("NYISO"). Energy, capacity and ancillary services
are sold through a bidding process into the NYISO energy markets on a day ahead
or real time basis. Prior to the start of the NYISO on November 19, 1999,
however, KeySpan and Consolidated Edison Company of New York, Inc.
("Consolidated Edison") entered into transition energy and capacity contracts.
The energy contract provided Consolidated Edison with 100% of the energy
produced by the Ravenswood facility on a cost recovery basis. This contract
expired on November 19, 1999. The capacity contract provided Consolidated Edison
with 100% of the available capacity of the Ravenswood facility on a monthly
fixed-fee basis. This contract expired on April 30, 2000.
Revenues earned by our Energy Services segment for the design, building and
installation of heating, ventilation and air-conditioning systems are recognized
by the percentage of completion method. This method measures the percentage of
costs incurred and accrued to date for each contract to the estimated total
costs for each contract at completion. Provisions for estimated losses on
uncompleted contracts are made in the period such losses are determined. Changes
in job performance, job conditions and estimated profitability may result in
revisions to cost and income, which are recognized in the period the revisions
are determined.
E. Utility Property - Depreciation and Maintenance
Utility gas property is stated at original cost of construction, which includes
allocations of overheads, including taxes, and an allowance for funds used
during construction. Electric depreciation consists of depreciation of our
electric generating facilities, including the Ravenswood facility from June 19,
1999.
49
Depreciation is provided on a straight-line basis in amounts equivalent to
composite rates on average depreciable property. The cost of property retired,
plus the cost of removal less salvage, is charged to accumulated depreciation.
The cost of repair and minor replacement and renewal of property is charged to
maintenance expense. The composite rates on average depreciable property were as
follows:
Period Electric Gas
------ -------- ---
Year Ended December 31, 2000 3.68% 3.51%
Year Ended December 31, 1999 3.56% 2.85%
Nine Months Ended December 31, 1998 2.54% 2.07%
F. Gas Exploration and Production Property - Depletion
The full cost method of accounting is used for investments in natural gas and
oil properties. Under this 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 the ratio of current
production to total proved natural gas and oil reserves. To the extent that such
capitalized costs (net of accumulated depletion) less deferred taxes exceed the
present value (using a 10% discount rate) of estimated future net cash flows
from proved natural gas and oil reserves and the lower of cost or fair value of
unproved properties, such excess costs are charged to operations. If a
write-down is required, it would result in a charge to earnings but would not
have an impact on cash flows from operating activities. Once incurred, such
impairment of gas properties is not reversible at a later date even if gas
prices increase. In December 1998, The Houston Exploration Company ("Houston
Exploration"), our 70% owned gas and oil exploration and production subsidiary,
recorded a $130 million write-down to its investment in its proved gas reserves,
which is reflected in the accompanying financial statements.
As of December 31, 2000, Houston Exploration estimates, using prices in effect
as of such date, that the ceiling limitation imposed under full cost accounting
rules exceeded actual capitalized costs.
G. Goodwill
At December 31, 2000, we have goodwill in the amount of $1.8 billion,
representing the excess of acquisition cost over the fair value of net assets
acquired. Goodwill is amortized over 15 to 40 years. Our recorded goodwill, net
of accumulated amortizations, consists of approximately $1.5 billion relating to
the Eastern and ENI acquisitions, approximately $160 million relating to the
KeySpan Acquisition, and approximately $190 million related to the acquisitions
of energy-related services companies and to certain ownership interests of 50%
or less in energy-related investments in Northern Ireland which are accounted
for under the equity method.
H. Hedging and Derivative Financial Instruments
Commodity Derivatives: We employ, from time to time, derivative financial
instruments to hedge exposure in cash flows due to fluctuations in the price of
natural gas that is used to serve our large volume customers and used to fuel
50
our Ravenswood facility. Our hedging strategies meet the criteria for hedge
accounting treatment under SFAS No. 80, "Accounting for Futures Contracts."
Accordingly, gains and losses on these instruments are recognized concurrently
with the recognition of the related physical transactions. These derivatives are
considered cash-flow hedges.
We regularly assess the relationship between natural gas commodity prices in
"cash" and futures markets. The correlation between prices in these markets has
been within a range generally deemed to be acceptable. If the correlation were
not to remain in an acceptable range, the subsidiaries would account for
financial instrument positions as trading activities.
Electric Derivatives: We also utilize derivative instruments to fix the selling
price and "lock-in" a profit margin on a portion of our estimated electric sales
from the Ravenswood facility. We employ swap agreements in which we receive from
a counter party a fixed price per megawatt hour of electricity sold and pay the
counter party the then floating market price for electric supply. Further, we
have synthetic tolling arrangements in which we receive a fixed margin from a
counter party and then pay the counter party our actual profit margin on the
sale of electricity. These derivatives are considered cash-flow derivative
instruments.
Interest Rate Derivatives: We continually assess the cost relationship between
fixed and variable rate debt. In line with our objective to minimize capital
costs, we periodically enter into hedging transactions that effectively convert
the terms of underlying debt obligations from fixed to variable. Payments made
or received are recognized as an adjustment to interest expense as incurred.
Hedging transactions that effectively convert the terms of underlying debt
obligations from fixed to variable are considered fair-value hedges.
I. Equity Investments
Certain subsidiaries own as their principal assets investments, including
goodwill, representing ownership interests of 50% or less in energy-related
businesses that are accounted for under the equity method.
J. Income Tax
In accordance with SFAS No. 109, "Accounting for Income Taxes" and applicable
rate regulation, certain of our regulated subsidiaries record a regulatory asset
for the net cumulative effect of having to provide deferred income taxes on all
differences between tax and book bases of assets and liabilities at the current
tax rate which have not yet been included in rates to customers. Investment tax
credits, which were available prior to the Tax Reform Act of 1986, were deferred
and are generally amortized as a reduction of income tax over the estimated
lives of the related property.
K. Subsidiary Common Stock Issuances to Third Parties
We follow an accounting policy of income statement recognition for parent
company gains or losses from issuances of common stock by subsidiaries.
51
L. Foreign Currency Translation
We follow the principles of SFAS No. 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, 2000, the foreign currency
translation adjustment was included in other comprehensive income as a separate
component of shareholders' equity.
M. Recent Accounting Pronouncements
In June 1999, the Financial Accounting Standards Board ("FASB") issued SFAS No.
137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of
the Effective Date of SFAS No. 133." SFAS No. 137 defers the effective date of
SFAS No. 133 to fiscal years beginning after July 15, 2000. SFAS No. 133
establishes accounting and reporting standards for derivative instruments and
for hedging activities.
In June 2000, the FASB issued SFAS No. 138, "Accounting for Certain Derivative
Instruments and Certain Hedging Activities - An Amendment of FASB Statement No
133." SFAS No. 138 amends the accounting and reporting standards of SFAS No.133
for a number of transactions. The most significant amendment to SFAS No. 133 as
it relates to our operations is that the normal purchase and sales exception
found in SFAS No. 133 may now be applied to contracts that implicitly or
explicitly permit net settlement, and contracts that have a market mechanism to
facilitate net settlement for which physical delivery is probable. Therefore,
under SFAS No. 138 our present gas procurement contracts are not considered
derivative financial instruments.
All of our derivative financial instruments currently qualify for hedge
accounting and, except for an interest rate swap, are cash-flow hedges. SFAS No.
133 requires that an entity recognize all derivatives as either assets or
liabilities in the statement of financial position and measure those instruments
at fair value. Periodic changes in market value of derivatives which meet the
definition of a cash-flow hedge are recorded as comprehensive income, subject to
effectiveness, and then included in net income to match the underlying hedged
transactions. We adopted SFAS No. 133 on January 1, 2001 and recorded a charge
to comprehensive income of $48.4 million. Due to the transition requirements
under SFAS No. 133 we did not incur a significant charge to earnings for either
our cash flow hedges or fair value hedge upon initial application. Currently all
of our derivative instruments expire prior to the end of 2001 and therefore we
do not expect SFAS No. 133 to have a material effect on our net income for the
year ended December 31, 2001. However, SFAS No. 133 may continue to have a
significant effect on comprehensive income because of fluctuations in the market
value of the derivatives we employ. Further, depending on the quarterly
measurement of hedging effectiveness, SFAS No.133 may have a material effect on
our reported quarterly earnings. (See Note 10, "Hedging, Derivative Financial
Instruments, and Fair Values" for additional information.)
52
The FASB recently issued a revision to its Exposure Draft ("ED") on "Business
Combinations and Intangible Assets". In the ED, the FASB concluded that the
amortization of goodwill will no longer be required. Instead, companies will
need to perform yearly impairment tests on the recorded amount of goodwill and
determine whether an impairment charge is necessary. The comment deadline on the
ED is March 16, 2001 and we believe the FASB will finalize its deliberations on
goodwill amortization in the third or fourth quarter of 2001. Goodwill
amortization for 2001 is estimated to be approximately $52 million. Depending on
the timing of the final statement, we may realize a significant benefit to
earnings in 2001 if we are required to discontinue the amortization of goodwill.
Such enhancement to earnings will not affect cash flow.
Note 2. Business Segments
We have six reportable segments: Gas Distribution, Electric Services, Gas
Exploration and Production, Energy Services, Energy Investments and Other.
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, Queens and Staten Island. KEDLI provides gas distribution
services to customers in the Long Island counties of Nassau and Suffolk and the
Rockaway Peninsula of Queens County. KEDNE provides 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, all through long-term service contracts having remaining terms that
range from five to twelve years. The Electric Services segment also includes
subsidiaries that own, lease and operate the 2,200 megawatt Ravenswood electric
generation facility, located in Queens, New York. Our contract with Consolidated
Edison, which provided Consolidated Edison with 100% of the available capacity
of the Ravenswood facility on a fixed monthly fee, expired on April 30, 2000. We
now provide all of the energy, capacity and ancillary services related to the
Ravenswood facility to the NYISO. Currently, our primary electric generation
customers are LIPA and the NYISO energy markets.
The Gas Exploration and Production segment is engaged in gas and oil exploration
and production, and the development and acquisition of domestic natural gas and
oil properties. This segment consists of our 70% equity interest in Houston
Exploration, an independent natural gas and oil exploration company, as well as
KeySpan Exploration and Production, LLC, our wholly owned subsidiary engaged in
a joint venture with Houston Exploration. Effective December 31, 2000, KeySpan
and Houston Exploration mutually agreed that we will no longer participate in
Houston Exploration's future offshore exploration prospects. We will, however,
continue to maintain our working interest in all wells drilled under the joint
venture agreement. We also agreed to continue the development of our working
interests in prospects drilled under the drilling program, and for 2001, we have
agreed to commit approximately $17 million for the development of prospects
successfully drilled during 1999 and 2000. On March 31, 2000, under a
pre-existing credit
53
arrangement, approximately $80 million in debt owed by Houston Exploration to us
was converted into common equity of Houston Exploration. Upon such conversion,
our common equity ownership interest in Houston Exploration increased from 64%
to approximately 70%.
The Energy Services segment includes companies that provide energy-related
services to customers located within the New York City metropolitan area, Rhode
Island, Pennsylvania, and now Massachusetts and New Hampshire, through the
following four lines of business: (i) Home Energy Services provides residential
customers with service and maintenance of energy systems and appliances, as well
as the retail marketing of natural gas and electricity to residential and small
commercial customers; (ii) Business Solutions provides professional
engineering-consulting and design of energy systems for commercial and
industrial customers, including installation of plumbing, heating, ventilation
and air conditioning equipment; (iii) Commodity Procurement provides management
and procurement services for fuel supply and management of energy sales,
primarily for and from the Ravenswood facility; and (iv) Fiber Optic Services
provides various services to carriers of voice and data transmission on Long
Island and in New York City.
Subsidiaries in the Energy Investments 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; a 50% interest in the
Premier Transco Pipeline and a 24.5% interest in Phoenix Natural Gas, both in
Northern Ireland; and investments in certain midstream natural gas assets in
Western Canada through KeySpan Canada, formerly Gulf Midstream. With the
exception of KeySpan Canada, these subsidiaries are primarily accounted for
under the equity method. Accordingly, equity income from these investments is
reflected in other income and (deductions) in the Consolidated Statement of
Income. In October 2000, we sold our interest in certain oil producing
properties in Alberta, Canada. Further, also in October 2000, we acquired the
remaining 50% interest in Gulf Midstream, making us the sole owner, and for
financial reporting purposes, these operations are consolidated in our financial
statements.
The Other segment represents primarily unallocated administrative and general
expenses, interest income earned on temporary cash investments, and preferred
stock dividends. Further, this segment includes our marine transportation
subsidiary, Midland Enterprises, that was acquired as part of the Eastern
acquisition. We have been ordered by the SEC to sell this subsidiary by November
8, 2003 because its operations are not functionally related to our core utility
operations.
The accounting policies of the segments are the same as those described in the
summary of significant accounting policies. Our reportable segments are
strategic business units that are managed separately because of their different
operating and regulatory environments. As a result, among other things, of our
acquisitions of Eastern and ENI (and the "push-down" of goodwill and debt
associated with the acquisitions on the individual financial statements of the
companies acquired), we are currently reviewing the components of our strategic
business units and the related method of evaluating their performance by our
Chief Operating Officer and Board of Directors. Any changes in the components of
our business segments and/or the nature of reporting their operating results
from such current review will be effective with our reporting of first quarter
2001 results. The reportable segment information is as follows:
54
(In Thousands of Dollars)
Gas Electric Gas Exploration Energy Energy
Distribution Services and Production Services Investments Other Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2000
Unaffiliated Revenue 2,555,785 1,444,711 274,209 771,861 33,507 41,417 - 5,121,490
Intersegment Revenue - - - 63,912 - - (63,912) -
Depreciation, depletion
and amortization 143,335 49,278 95,364 10,511 6,422 30,196 - 335,106
Operating Income 359,399 238,891 134,410 77,805 1,055 (79,697) - 731,863
Income from equity
method subsidiaries - - - - 20,010 - - 20,010
Interest income 3,951 1,214 - 966 6,134 74,957 (74,032) 13,190
Interest charges 111,176 24,254 11,360 125 7,636 128,428 (79,629) 203,350
Earnings for Common Stock 160,178 121,997 58,211 40,946 13,929 (112,567) - 282,694
Basic and Diluted
Earnings Per Share $ 1.19 $ 0.91 $ 0.43 $ 0.31 $ 0.10 $ (0.84) $ - $ 2.10
Total assets 7,286,138 1,858,813 830,170 768,016 683,399 5,511,506 (5,387,921) 11,550,121
Investment in equity
method subsidiaries - - - 15,433 109,751 3,387 - 128,571
Construction expenditures 274,941 69,921 243,799 17,362 26,388 624 - 633,035
- -------------------------------------- ------------ ------------ ------------ ---------- -------------- ------------- ----------
Electric Services revenues from LIPA, Consolidated Edison and the New York
Independent System Operator of $1.4 billion for the year ended December 31, 2000
represents approximately 28% of our consolidated revenues during that period.
Eliminating Items include intercompany interest income and expense and the
elimination of certain intercompany accounts receivable.
55
(In Thousands of Dollars)
Gas Electric Gas Exploration Energy Energy
Distribution Services and Production Services Investments Other Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1999
Unaffiliated Revenue 1,753,132 861,582 150,581 186,529 2,789 - - 2,954,613
Depreciation, depletion and
amortization 102,997 44,334 74,051 3,548 1,308 27,202 - 253,440
Operating Income 308,410 139,940 48,530 (4,643) (6,784) (3,284) - 482,169
Income from equity
method subsidiaries - - - - 15,347 - - 15,347
Interest income 3,942 - - - 5,016 19,393 (1,358) 26,993
Interest charges 88,370 22,380 13,307 - 3,726 95,252 (89,284) 133,751
Earnings for Common Stock 151,217 77,099 15,772 (2,528) 8,543 (26,244) - 223,859
Basic and Diluted
Earnings Per Share $ 1.09 $ 0.56 $ 0.11 $ (0.02) $ 0.06 $ (0.18) $ - $ 1.62
Total assets 3,774,563 1,267,931 646,657 202,124 503,549 2,584,674 (2,248,807) 6,730,691
Investment in equity
method subsidiaries - - - 13,393 341,874 4,016 - 359,283
Construction expenditures 213,845 245,177 183,322 6,179 10,028 13,294 - 671,845
- ----------------------------- ------------- -------- ----------- ---------- ---------- ------------ ----------- --------
Electric Services revenues from LIPA, and Consolidated Edison of $859 million
for the year ended December 31, 1999 represents approximately 29% of our
consolidated revenues during that period.
Eliminating Items include intercompany interest income and expense and the
elimination of certain intercompany accounts receivable.
56
(In Thousands of Dollars)
Gas Electric Gas Exploration Energy Energy
Distribution Services and Production Services Investments Other Eliminations Consolidated
- ----------------------------- ------------------------------------------------------------------------------------------------------
Nine Months Ended December 31, 1998
Unaffiliated Revenue 856,172 738,316 70,812 63,064 117 - - 1,728,481
Depreciation, depletion and
amortization 57,351 5,895 177,114 256 1,117 13,126 - 254,859
Operating Income 57,753 132,016 7,446 (5,914) (3,890) (106,678) - 80,733*
Income from equity
method subsidiaries - - - - 5,841 - - 5,841
Interest income 1,328 - - - - 49,200 (424) 50,104
Interest charges 60,678 69,953 3,870 - - 60,700 (54,468) 140,733
Earnings for
Common Stock (142) 43,594 2,218 (3,212) (4,186) (71,799) - (33,527)**
Basic and Diluted
Earnings Per Share $ - $ 0.30 $ 0.02 $ (0.02) $ (0.03) $ (0.50) - $ (0.23)
Total assets 3,452,361 693,162 500,162 116,771 429,157 4,439,307 (2,735,818) 6,895,102
Investment in equity
method subsidiaries - - - - 289,193 - - 289,193
Construction expenditures 128,405 54,090 182,729 28,421 231,791 51,127 - 676,563
- --------------------------- ----------- ----------- ------------- -------------- ---------- ----------- ------------ ----------
*Excludes a charge of $130 million to write-down Houston Exploration's proved
gas reserves.
**Excludes special charges associated with the LIPA Transaction. See Note 16 -
Costs Related to the LIPA Transaction and Special Charges.
Electric Services revenues from LIPA of $408 million for the nine months ended
December 31, 1998 represents approximately 24% of our consolidated revenues
during that period.
Eliminating Items include intercompany interest income and expense and the
elimination of certain intercompany accounts receivable.
Note 3. Income Tax
For calendar year 1999, we began to file consolidated federal and state income
tax returns. A tax sharing agreement between ourselves and our subsidiaries
provides for the allocation of a realized tax liability or benefit based upon
separate return contributions of each subsidiary to the consolidated taxable
income or loss in the consolidated income tax returns.
Income tax expense in 1999 reflects an adjustment to deferred tax expense and
current tax expense for the utilization of previously deferred net operating
loss carryforwards recorded in 1998. In 1998, we recorded as a deferred tax
asset, a benefit of $71.1 million for net operating loss carryforwards. We
estimated that $57.4 million of the benefits from the net operating loss
carryforwards from 1998 would be realized in our consolidated 1999 federal and
state income tax returns and, accordingly, we applied the net operating loss
benefits in our 1999 federal and state tax provisions.
57
Income tax expense (benefit) is reflected as follows in the Consolidated
Statement of Income:
(In Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------------
Nine Months
Year Ended Year Ended Ended
December 31, 2000 December 31, 1999 December 31, 1998
- -------------------------------------------------------------------------------------------------------------------
Current income tax $ 169,823 $ 26,618 $ 26,142
Deferred income tax 46,453 109,744 (85,936)
------- ------- ---------
216,276 136,362 (59,794)
------- ------- ---------
Current - transaction related (1) - - 291,365
Deferred - transaction related (2) - - (391,066)
------- ------- ---------
- - (99,701)
------- ------- ---------
Total income tax (benefit) $ 216,276 $ 136,362 $ (159,495)
- ----------------------------------------------------------------------------------------------------------------
(1) Primarily represents income taxes associated with the sale of
assets (the "Transferred Assets") to us by LIPA, which taxes
were paid by us, partially offset by tax benefits recognized
upon funding of postretirement benefits.
(2) Primarily represents the deferred federal income taxes
necessary to account for the difference between the carryover
basis of the assets sold to us for financial reporting
purposes and the new increased tax basis.
The components of deferred tax assets and (liabilities) reflected in the
Consolidated Balance Sheet are as follows:
(In Thousands of Dollars)
December 31, 2000 December 31, 1999
- ------------------------------------------------------ ---------------------------- ----------------------------
Reserves not currently deductible $ 56,559 $ 35,569
Benefits of tax loss carryforwards 26,276 13,694
Property related differences (503,030) (155,063)
Regulatory tax asset (21,375) (22,912)
Property taxes (9,740) (49,172)
Other items - net (411) (11,046)
--------- ---------
Net deferred tax liability $ (451,721) $ (188,930)
- -----------------------------------------------------------------------------------------------------------------
58
The following is a reconciliation between reported income tax and tax computed
at the federal income tax statutory rate of 35%:
(In Thousands of Dollars)
Nine Months
Year Ended Year Ended Ended
December 31, December 31, December 31,
2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------------
Computed at the statutory rate $ 180,979 $ 138,241 $ (114,249)
Adjustments related to:
Net benefit from LIPA Transaction (1) - - (31,503)
Tax credits (1,181) (2,154) (1,809)
Minority interest in Houston
Exploration 8,768 3,105 (10,220)
State income tax 30,384 4,635 -
Other items - net (2,674) (7,465) (1,714)
-------------------- ---------------------- ------------------
Total income tax (benefit) $ 216,276 $ 136,362 $ (159,495)
- ------------------------------------------------------- -------------------- ---------------------- ------------------
Effective income tax rate (2) 42% 35% N/A
(1) Includes tax benefits relating to (a) the deferred federal income
taxes necessary to account for the difference between the carryover
basis of the Transferred Assets for financial reporting purposes and
the new increased tax basis and (b) certain credits for financial
reporting purposes, including tax benefits recognized on the funding
of postretirement benefits, partially offset by income taxes
associated with the sale of the Transferred Assets to us by LIPA which
taxes were paid by us.
(2) Reflects both federal as well as state income taxes.
59
Note 4. Postretirement Benefits
Pension Plans: The following information represents the consolidated results for
our noncontributory defined benefit pension plans which cover substantially all
employees. Benefits are based on years of service and compensation. Funding for
pensions is in accordance with requirements of federal law and regulations.
Prior to the KeySpan Acquisition, pension benefits had been managed separately
by our regulated subsidiaries, which were the only subsidiaries with defined
benefit plans. We are currently integrating our plans and allocations to
individual business segments. KEDLI is subject to certain deferral accounting
requirements mandated by the NYPSC for pension costs and other postretirement
benefit costs.
The calculation of net periodic pension cost is as follows:
(In Thousands of Dollars)
- ----------------------------------------------------------------------------------------------------------------------------
Year Ended Year Ended Nine Months Ended
December 31, 2000 December 31, 1999 December 31, 1998
- --------------------------------------- --------------------------- ------------------------- ----------------------------
Service cost, benefits earned
during the period $ 35,810 $ 38,372 $ 24,608
Interest cost on projected
benefit obligation 109,907 106,888 66,341
Expected return on plan assets (167,612) (138,436) (78,201)
Special termination charge (1) 45,838 - 61,558
Settlement Gain (2) (20,196) - -
Net amortization and deferral (54,881) (8,869) (7,486)
--------------------------- ------------------------- ----------------------------
Total pension cost $ (51,134) $ (2,045) $ 66,820
- --------------------------------------- --------------------------- ------------------------- ----------------------------
(1) See discussion of early retirement program at end of note.
(2) See discussion of pension plan settlement. Pension cost includes
expense and income for KEDNE for the period November 8, 2000 through December
31, 2000.
60
The following table sets forth the pension plans' funded status at December 31,
2000 and December 31, 1999. Plan assets are principally common stock and fixed
income securities.
(In Thousands of Dollars)
- -----------------------------------------------------------------------------------------------------------------
December 31, 2000 December 31, 1999
- -------------------------------------------------------- ------------------------- ----------------------------
Change in benefit obligation:
Benefit obligation at beginning of period $ (1,529,815) $ (1,650,120)
Benefit obligation of acquisitions (309,384) (11,700)
Service cost (35,810) (38,372)
Interest cost (109,907) (106,888)
Amendments (34,400) (31,350)
Actuarial gain (loss) (115,402) 205,798
Special termination benefits (45,838) -
Settlements 110,000 -
Benefits paid 97,691 102,817
---------------------- ----------------------
Benefit obligation at end of period (1,972,865) (1,529,815)
---------------------- ---------------------
Change in plan assets:
Fair value of plan assets at beginning of period 2,048,325 1,675,604
Fair value of acquired plan assets 301,998 -
Actual return on plan assets 69,489 457,529
Employer contribution 18,322 18,009
Settlements (110,410) -
Benefits paid (97,691) (102,817)
---------------------- ----------------------
Fair value of plan assets at end of period 2,230,033 2,048,325
---------------------- ----------------------
Funded status 257,168 518,510
Unrecognized net (gain) from past experience
different from that assumed and from
changes in assumptions (337,288) (667,652)
Unrecognized prior service cost 79,914 80,087
Unrecognized transition obligation 2,187 3,163
Net prepaid (accrued) pension cost reflected ---------------------- ----------------------
on consolidated balance sheet $ 1,981 $ (65,892)
- -------------------------------------------------------- ---------------------- ----------------------
Nine Months
Year Ended Year Ended Ended
December 31, 2000 December 31, 1999 December 31, 1998
- ------------------------------------------------- ------------------------ ------------------------- -------------------------
Assumptions:
Obligation discount 7.00% 7.50% 6.50%
Asset return 8.50% 8.50% 8.50%
Average annual increase in compensation 5.00% 5.00% 5.00%
- ------------------------------------------------- ------------------------ ------------------------- -------------------------
Pension Plan Settlement
We have settled certain participating contracts covering retiree pension plans
with MetLife. As required under SFAS No. 88, a gain of $20.2 million has been
recognized as part of our pension cost for the year ended December 31, 2000.
Other Postretirement Benefits: The following information represents the
consolidated results for our noncontributory defined benefit plans covering
certain health care and life insurance benefits for retired employees. We have
been funding a portion of future benefits over employees' active service lives
through Voluntary Employee Beneficiary Association ("VEBA") trusts.
Contributions to VEBA trusts are tax deductible, subject to limitations
contained in the Internal Revenue Code. Prior to the KeySpan Acquisition other
postretirement benefits had been managed separately by our regulated
subsidiaries, which were the only subsidiaries with defined benefit plans. We
are currently integrating our plans and allocations to individual business
segments.
Net periodic other postretirement benefit cost included the following
components:
(In Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------------------------------
Nine Months
Year Ended Year Ended Ended
December 31, 2000 December 31, 1999 December 31, 1998
- --------------------------------------------------- ------------------------------- --------------------------- -------------------
Service cost, benefits earned
during the period $ 14,793 $ 16,747 $ 9,569
Interest cost on accumulated post-
retirement benefit obligation 47,692 42,616 26,414
Expected return on plan assets (42,890) (36,842) (23,267)
Special termination charge (1) 5,590 - 3,073
Net amortization and deferral (9,291) 3,429 (5,255)
------------------------------- --------------------------- -------------------
Other postretirement benefit cost $ 15,894 $ 25,950 $ 10,534
- --------------------------------------------------- ------------------------------- --------------------------- -------------------
(1) See discussion of early retirement program at end of note.
Other post-retirement benefit costs include expense and income for KEDNE for
November 8, 2000 through December 31, 2000.
61
The following table sets forth the plan's funded status at December 31, 2000 and
December 31, 1999. Plan assets are principally common stock and fixed income
securities.
(In Thousands of Dollars)
- --------------------------------------------------------------------------------------------------------------------
December 31, 2000 December 31, 1999
- ------------------------------------------------------------ -------------------------- --------------------------
Change in benefit obligation:
Benefit obligation at beginning of period $ (602,053) $ (728,255)
Benefit obligation of acquisitions (123,450) (3,075)
Service cost (14,793) (16,747)
Interest cost (47,692) (42,616)
Plan participants' contributions (678) (716)
Amendments - 8,631
Actuarial gain (loss) (139,840) 148,126
Special termination benefits (5,590) -
Benefits paid 38,579 32,599
-------------------------- --------------------------
Benefit obligation at end of period (895,517) (602,053)
-------------------------- --------------------------
Change in plan assets:
Fair value of plan assets at beginning of period 548,850 478,778
Fair value of acquired plan assets 39,263 -
Actual return on plan assets 816 97,452
Employer contribution 3,838 4,503
Plan participants' contribution 678 716
Benefits paid (38,579) (32,599)
-------------------------- --------------------------
Fair value of plan assets at end of period 554,866 548,850
-------------------------- --------------------------
Funded status (340,651) (53,203)
Unrecognized net (gain) loss from past experience
different from that assumed and from changes in
assumptions 125,334 (66,318)
Unrecognized prior service cost (8,924) (8,477)
Accrued benefit cost reflected on -------------------------- --------------------------
consolidated balance sheet $ (224,241) $ (127,998)
- ------------------------------------------------------------ -------------------------- --------------------------
Year Ended Year Ended Nine Months Ended
December 31, 2000 December 31, 1999 December 31, 1998
- --------------------------------------------------------------------------------------------------------- --------------------------
Assumptions:
Obligation discount 7.00% 7.50% 6.50%
Asset return 8.50% 8.50% 8.50%
Average annual increase in compensation 5.00% 5.00% 5.00%
- --------------------------------------------------------------------------------------------------------- --------------------------
62
The measurement of plan liabilities also assumes a health care cost trend rate
of 8% grading down to 6% in 2005. 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, 2000 by $99.8 million and the net periodic health
care expense by $9.0 million. A 1% decrease in the health care cost trend rate
would have the effect of decreasing the accumulated postretirement benefit
obligation as of December 31, 2000 by $87.4 million and the net periodic health
care expense by $7.6 million.
In 1993, LILCO adopted the provisions of SFAS No. 106, "Employer's Accounting
for Postretirement Benefits Other Than Pensions," and recorded an accumulated
postretirement benefit obligation and a corresponding regulatory asset of $376
million. LIPA will reimburse us for costs related to postretirement benefits of
the electric business unit employees, therefore, we have reclassified the
regulatory asset for postretirement benefits associated with electric business
unit employees to a deferred asset.
In 1994, LILCO established VEBA trusts for union and non-union employees for the
funding of costs collected in rates for postretirement benefits. For the fiscal
year ended March 31, 1998, the trusts were funded with a contribution of $21
million. In May 1998, an additional $250 million was funded into the trusts.
Early Retirement Program
In December 2000, we completed an early retirement program for certain
management and union employees. The additional obligations for pensions and
other postretirement benefits are reflected at December 31, 2000. Included in
the pension and other postretirement benefits expense for the year ended
December 31, 2000 are charges of $45.8 million and $5.6 million, respectively
related to the early retirement program.
Note 5. Capital Stock
Common Stock: Currently we have 450,000,000 shares of authorized common stock.
In 1998, we initiated a program to repurchase a portion of our outstanding
common stock on the open market. At December 31, 2000 we had 22.5 million
shares, or approximately $650.7 million of Treasury Stock outstanding. We
completed this repurchase plan in 1999 and now utilize Treasury Stock to satisfy
our common stock plans. During 2000, we issued 2.5 million shares of Treasury
Stock for the dividend reinvestment feature of our Investor Program, the
Employee Stock Discount Purchase Plan for Employees, and the Employee Savings
Plan.
Preferred Stock: We have the authority to issue 100,000,000 shares of preferred
stock with the following classifications: 16,000,000 shares of preferred stock,
par value $25 per share; 1,000,000 shares of preferred stock, par value $100 per
share; and 83,000,000 shares of preferred stock, par value $.01 per share.
63
At December 31, 2000 we had 553,000 shares outstanding of 7.07% Preferred Stock
Series B par value $100; 197,000 shares outstanding of 7.17% Preferred Stock
Series C par value $100; and 92,050 shares outstanding of 6% Preferred Stock
Series A par value $100, in the aggregate totaling $84.2 million.
Boston Gas Company has 682,700 shares of 6.421% non-voting preferred stock par
value $25 per share outstanding at December 31, 2000. This issue of preferred
stock has a 5% annual sinking fund requirement. We have the option of increasing
the sinking fund payment up to 10% per year. This issue is callable beginning in
2003 and is reflected in deferred credits and other liabilities on the
Consolidated Balance Sheet.
On June 1, 2000, we redeemed, at maturity, all 14,520,000 outstanding shares of
our 7.95% Preferred Stock Series AA. Our obligation of $370.2 million included
the mandatory redemption price of $25 per share totaling $363.0 million and
dividends payable totaling $7.2 million.
Note 6. Nonqualified Stock Options
At December 31, 2000, we had stock-based compensation plans that are described
below. Moreover, under a separate plan, Houston Exploration has issued
approximately 2.3 million stock options to key Houston Exploration employees.
KeySpan and Houston Exploration apply APB Opinion 25, "Accounting for Stock
Issued to Employees," and related Interpretations in accounting for their plans.
Accordingly, no compensation cost has been recognized for these fixed stock
option plans in the Consolidated Financial Statements since the exercise prices
and market values were equal on the grant dates. Had compensation cost for these
plans been determined based on the fair value at the grant dates for awards
under the plans consistent with SFAS No. 123, "Accounting for Stock-Based
Compensation," our net income and earnings per share would have been decreased
to the proforma amounts indicated below:
Year Ended Year Ended Nine Months Ended
December 31, 2000 December 31, 1999 December 31, 1998
- ------------------------------------------------------------------------------------------------------------------------------------
Income (loss) available for
common stock (000): As reported $282,694 $223,859 ($195,537)
Proforma $276,167 $215,416 ($198,996)
Earnings (loss) per share: As reported $2.10 $1.62 ($1.34)
Proforma $2.06 $1.56 ($1.37)
- ------------------------------------------------------------------------------------------------------------------------------------
The weighted average fair value of grants issued in 2000 was $2.87. The weighted
average fair value of grants issued in 1999 was $3.65. All grants are estimated
on the date of the grant using the Black- Scholes option-pricing model. The
following weighted average assumptions were used for grants issued in 2000 and
1999 respectively: dividend yield of 8.22% and 6.58%; expected volatility of
24.00% and 23.43%; risk free interest rate of 6.54% and 5.72%; and expected
lives of 6 years. The weighted average exercise price is $22.69 and $27.58 for
the 2000 and 1999 grants, respectively. There were no grants issued in 1998.
64
A summary of the status of our fixed stock option plans and changes is presented
below for the periods indicated:
Year Ended Year Ended Nine Months Ended
December 31, 2000 December 31, 1999 December 31, 1998
- -------------------------------------- ---------------------------- -------------------------------- -------------------------------
Weighted Weighted Weighted
Fixed Options Average Average Average
Shares Exercise Price Shares Exercise Price Shares Exercise Price
- -------------------------------------- ---------------------------- ------------ ------------------- -------------------------------
Outstanding at beginning of period 4,968,398 $28.18 921,066 $30.80 992,300 $30.70
Granted during the year 3,165,822 $22.69 4,149,000 $27.58 -- --
Exercised (1,577,259) $27.82 (2,666) $27.75 (13,631) $28.67
Forfeited (100,334) $26.04 (99,002) $27.22 (57,603) $29.45
---------------------------- ------------ ------------------- -------------------------------
Outstanding at end of period 6,456,627 $25.61 4,968,398 $28.18 921,066 $30.80
- -------------------------------------- ---------------------------- ------------ ------------------- -------------------------------
Exercisable at end of period 2,759,599 $29.57 3,638,448 $28.53 921,066 $30.80
- ------------------------------------------------------------------------------------------------------------------------------------
Options Outstanding Remaining Weighted Average Options Exercisable
at December 31, 2000 Contractual Life Exercise Price at December 31, 2000
- ---------------------------------------------- --------------------------------------------------
65,000 5 years $27.00 65,000
277,993 6 years $30.29 277,993
338,410 7 years $32.57 338,410
1,681,108 8 years $27.86 1,509,068
1,089,935 9 years $26.81 561,058
3,004,181 10 years $22.72 8,070
--------- ---------
6,456,627 2,759,599
- ---------------------------------------------- --------------------------------------------------
Note 7. Long-Term Debt
Gas Facilities Revenue Bonds: KEDNY can issue tax-exempt bonds through the New
York State Energy Research and Development Authority. Whenever bonds are issued
for new gas facilities projects, proceeds are deposited in trust and
subsequently withdrawn to finance qualified expenditures. There are no sinking
fund requirements on any of our Gas Facilities Revenue Bonds. At December 31,
2000, KEDNY had $648.5 million of Gas Facilities Revenue Bonds outstanding. The
interest rate on the variable rate series due December 1, 2020 is reset weekly
and ranged from 3.40% to 4.90% through December 31, 2000, at which time the
average rate was 3.97%.
We have an interest rate swap agreement in which approximately $70 million of
our Gas Facility Revenue Bonds, 6.75% Series A and B, were effectively exchanged
for floating rate debt. (See Note 10, "Hedging, Derivative Financial Instruments
and Fair Values.")
Authority Financing Notes: Our electric generation subsidiary can also issue
tax-exempt bonds through the New York State Energy Research and Development
Authority. At December 31, 2000, $41.1 million of Authority Financing Notes 1999
Series A Pollution Control Revenue Bonds due October 1, 2028 were outstanding.
The interest rate on these notes is reset based on an auction procedure. The
interest rate during the year ranged from 3.40% to 5.25%, through December 31,
2000 at which time the rate was 4.00%.
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 2.80% to 5.85% through December 31, 2000 at
which time the average rate was 4.04%.
Promissory Notes: In accordance with the LIPA agreement, LIPA assumed all of the
outstanding long- term debt of LILCO at May 28, 1998 except for the 1997 Series
A Electric Facilities Revenue Bonds due December 1, 2027 which were assigned to
us. In accordance with the LIPA agreement, we issued promissory notes to LIPA
which represented an amount equivalent to the sum of: (i) the principal amount
of 7.30% Series Debentures due July 15, 1999 and 8.20% Series Debentures due
March 15, 2023 outstanding at May 28, 1998, and (ii) an allocation of certain of
the Authority Financing Notes. The promissory notes contain identical terms as
the debt referred to in items (i) and (ii) above. During 1999, we extinguished
our obligation under certain promissory notes to LIPA. Our obligation for these
promissory notes had a principal amount of $442.5 million.
Notes Payable: On February 1, 2000, KEDLI issued $400 million of 7.875 %
Medium-Term Notes due February 1, 2010. The net proceeds from the issuance of
these notes were used to reimburse our treasury for costs in extinguishing
certain promissory notes to LIPA, as previously noted. (For additional
information on this issuance see Note 11, "KeySpan Gas East Corporation Summary
Financial Data.")
65
In November 2000, we issued $1.65 billion of Medium-Term Notes, the net proceeds
of which were used to repay commercial paper that was issued to finance a
portion of the acquisition of Eastern and ENI. The notes were issued in three
series as follows: $700 million, 7.25% Notes due 2005; $700 million, 7.625%
Notes due 2010 and $250 million, 8.00% Notes due 2030.
Additionally, Boston Gas Company has outstanding $210 million of Medium-Term
Notes. These notes, which are not callable until maturity, have interest rates
ranging from 6.80% - 9.75% and mature in 2005-2025.
At December 31, 2000, Houston Exploration had outstanding $100 million of 8.625%
Senior Subordinated Notes due 2008. These notes were issued in a private
placement in March 1998 and are subordinate to borrowings under Houston
Exploration's line of credit. These notes are redeemable at the option of
Houston Exploration after January 1, 2003.
First Mortgage Bonds: Eastern and ENI and their respective subsidiaries, have
issued and outstanding approximately $323 million of first mortgage bonds.
Approximately $180 million of these bonds are secured by KEDNE gas utility
property and $143 million are secured by marine transportation equipment. The
first mortgage bond indentures include, among other provisions, limitations on:
(i) the issuance of long term debt; (ii) engaging in additional lease
obligations; and (iii) the payment of dividends from retained earnings.
Commercial Paper and Revolving Credit Agreements: We have two revolving credit
agreements with a commercial bank syndicate totaling $1.4 billion. These
agreements expire in September 2001, and our current intention is to renew both
of these agreements.
Pricing under both facilities is subject to a ratings-based grid with an annual
fee of .075% per annum on the balance of funds available. Borrowings will bear
interest at LIBOR plus 50 basis points. Borrowings in excess of more than 33% of
the total commitment will bear interest at LIBOR plus 62.5 basis points. The
credit facilities are used to support our $1.4 billion commercial paper program.
At December 31, 2000, $1.3 billion of commercial paper was outstanding at a
weighted average annualized interest rate of 7.01%; $99.7 million of commercial
paper was available for issuance.
Houston Exploration has an unsecured available line of credit with a commercial
bank that provides for a maximum commitment of $250 million subject to borrowing
base limitations. This credit facility supports borrowings under a revolving
loan agreement, and at December 31, 2000, the borrowing base was $210 million.
Up to $2 million of this line is available for the issuance of letters of credit
to support performance guarantees. This credit facility matures on March 1, 2003
and is unsecured. Houston Exploration borrowed $32 million under this facility
during 2000, and at December 31, 2000, borrowings of $145 million were
outstanding and $0.4 million was committed under outstanding letter of credit
obligations. Borrowings under this facility bear interest, at rates indexed at a
premium to the Federal Funds rate or LIBOR, or based on the prime rate depending
on amounts outstanding under the credit facility. The weighted average interest
rate on this debt was 7.90% at December 31, 2000.
66
KeySpan Canada has two revolving twelve month loan agreements with Canadian
banks. Under its agreement with the Bank of Canada, KeySpan Canada borrowed $47
million US dollars in 2000. At December 31, 2000, total borrowings under this
facility were $133 million US dollars. The weighted average interest rate on
these borrowings at December 31, 2000 was 6.42%. This credit facility has been
fully utilized. The second facility was negotiated in 2000 with the Bank of
Montreal. During the year, KeySpan Canada borrowed $37 million US dollars at a
weighted average interest rate of 6.46%. KeySpan Canada has $46 million US
dollars available for future borrowing under this facility. These borrowings
were used to acquire the remaining 50% interest in Gulf Midstream as well as to
fund capital expenditures associated with our Canadian activities.
Capital Leases: Our subsidiaries lease certain facilities and equipment under
long-term leases which expire on various dates through 2020. The weighted
average interest rate on these obligations was 7.68%.
Debt Maturity: Debt repayment requirements, including capitalized leases and
related maturities, are $5.4 million, $5.0 million, $11.1 million, $0.7 million,
and $13.5 million for the years 2001 through 2005, respectively and cumulatively
$4.3 billion thereafter.
Note 8. New York Independent System Operator Matters
We currently realize revenues from our investment in the Ravenswood facility
through the wholesale sale of energy, installed capacity and ancillary services
at FERC approved market based rates. Energy is a quantity of electricity that is
produced over a period of time and is measured in megawatt hours (MWh).
Installed capacity ("ICAP") is the capability to generate electrical power and
is measured in megawatts (MW). Ancillary services include 10-minute spinning and
non-spinning reserves available to replace energy that is unable to be delivered
due to the unexpected loss of a major energy source. The Ravenswood facility
currently sells its energy, installed capacity and ancillary services through
bidding into the NYISO energy markets. It also has the ability to sell these
services through bilateral transactions.
As a condition of FERC's approval of the Ravenswood facility's market based rate
authority, it is subject to certain mitigation measures associated with the sale
of its products, the most significant of which are the day ahead energy bid cap,
and installed capacity bid and price cap.
Currently, the Ravenswood facility's energy bids are evaluated against the
energy price at Indian Point 2 ("Indian Point"). If the Ravenswood facility's
bid prices become five percent greater than the price at Indian Point, the
Ravenswood facility's bid price is not used. Instead, its bid is capped
(mitigated) at the amount that the Ravenswood facility has bid during
unmitigated hours in the prior 90 days. With respect to installed capacity, the
Ravenswood facility, as a New York City supplier, is currently subject to an
$8.75 per kW-month ICAP bid and price cap.
67
Due to recent market activity and volatility in the New York energy markets, as
well as the projected increased demand for energy during the summer of 2001, the
NYISO, NYPSC and FERC have proposed, evaluated and implemented additional market
mitigation measures. Many of these mitigation measures will remain in effect
during 2001 and additional mitigation measures are expected to be proposed and
possibly implemented prior to the summer of 2001. These additional measures are
discussed below.
General Mitigation
On November 21, 2000, FERC granted NYISO's requested extension of its Temporary
Extraordinary Procedures ("TEP") authority until April 30, 2001. The TEP are
designed to address unanticipated market design flaws and transitional
abnormalities which occur during the start-up period of the NYISO. Under the
TEP, the NYISO may take Extraordinary Corrective Action in order to recalculate
energy prices, when possible with reasonable certainty, that are incorrect due
to market design flaws. The NYISO will once again request that FERC extend this
TEP authority through October 31, 2002.
In addition, on March 1, 2001, Consolidated Edison requested FERC to revise the
localized market power mitigation measures for generating units located in the
New York City service area. Specifically, Consolidated Edison requested that
existing bid mitigation measures be applied to the real-time market as well as
the day ahead market. Moreover, Consolidated Edison requested that the
mitigation measures apply to all existing and planned New York City generation
and not only the divested Consolidated Edison generation.
The NYISO has also been developing a Circuit Breaker mechanism which, according
to the NYISO, is intended to implement existing mitigation measures
automatically rather than on a one day lag. The NYISO is in the process of
implementing this automatic Circuit Breaker. It is not known if regulatory
approvals will be obtained nor the potential impact on revenues or earnings
associated with these measures.
Energy Mitigation
On July 26, 2000, FERC approved a $1,000 per MWh energy price bid cap. The July
26, 2000 order also required the NYISO to identify certain "market flaw
problems" and to report them to FERC by September 1, 2000. (See Reserves
Mitigation for further discussion). FERC has extended this cap through April 30,
2001, and the NYISO will once again request FERC extend this $1,000 per MWh
energy bid cap through October 31, 2002.
Reserves Mitigation
Due to volatility in the market-clearing price of 10-minute spinning and
non-spinning reserves during the first quarter of 2000, the NYISO requested that
FERC approve a bid cap on reserves as well as requiring a refunding of so-called
alleged "excess payments" received by sellers into the ancillary services
market, including the Ravenswood facility and LIPA. Other market participants,
68
including buyers of reserves and electric utilities as load serving entities
also filed complaints with FERC and intervened in the various FERC proceedings
related to reserves, and proposed alternative remedies.
On May 31, 2000, FERC issued an order on reserves that granted approval of a
$2.52 per MWh bid cap for 10 minute non-spinning reserves, which includes
payments for the opportunity cost of not making energy sales. FERC also required
the NYISO to submit additional information in a compliance filing. The other
requests, such as a bid cap for spinning reserves, retroactive refunds,
recalculation of reserve prices for March 2000, and convening a technical
conference and settlement proceeding , were rejected. However, the NYISO and
several other market participants have requested rehearing of the May 31, 2000
order. In response to the NYISO rehearing request, FERC has allowed the NYISO to
recalculate prices for reserves for the March 2000 period as if the bid cap
approved effective April 1, 2000 had been effective for March, pending its
review on the rehearing requests of the May 31, 2000 order. The final order on
the rehearing request is still pending.
On November 8, 2000, FERC issued an order extending the $2.52 per MWh plus
opportunity costs bid cap on 10-minute non-spinning reserves and the related
mandatory bidding requirement, until such time as FERC determines that the
non-spinning reserve markets are demonstrated to be workably competitive. A
technical conference regarding ancillary services was conducted by FERC in
January 2001. Market participants have provided comments to FERC including
opinions that the non-spinning reserve markets are not workably competitive and
accordingly the bid cap should continue. We have requested this bid cap be
removed because additional supply is now available. The proceeding is still
pending and it is not known if or when the bid cap will be removed or if other
market changes will be made.
Capacity Mitigation
The NYISO and market participants have been discussing the implementation of a
revised ICAP market. Currently, a generator may sell 100% of its dependable
maximum net capacity. The proposed revision would reduce this amount by taking
into account a generating unit's forced outage rate. At the same time it is
proposed to increase the $8.75 per kW bid cap. The magnitude of these changes
have not been agreed to nor approved by FERC and it is not known to what extent
these revisions will impact Ravenswood's revenues or earnings.
Note 9. Contractual Obligations and Contingencies
Lease Obligations: Lease costs included in operation expense were $69.3 million
in 2000 reflecting, primarily, the Ravenswood lease of $30.5 million and the
lease of our Brooklyn headquarters of $11.6 million. Lease costs also include
leases for other buildings, office equipment, vehicles and power operated
equipment. Lease costs for the year ended December 31, 1999 were $47.1 million.
Lease costs for the nine months ended December 31, 1998 were $28.9 million. The
future minimum lease payments under various leases, all of which are operating
leases, are $68.7 million per year over the next five years and $253.4 million,
in the aggregate, for all years thereafter.
69
We acquired the 2,200 megawatt Ravenswood facility located in Long Island City,
Queens, New York, from Consolidated Edison on June 18, 1999 for approximately
$597 million. In order to reduce our cash requirements, we entered into a lease
agreement with a special purpose, unaffiliated financing entity that acquired a
portion of the facility directly from Consolidated Edison and leased it to our
subsidiary under a ten year lease. We have guaranteed all payment and
performance obligations of our subsidiary under the lease. Another subsidiary
provides all operating, maintenance and construction services for the facility.
The lease relates to approximately $425 million of the acquisition cost of the
facility. The lease qualifies as an operating lease for financial reporting
purposes while preserving our ownership of the facility for federal and state
income tax purposes. The balance of the funds needed to acquire the facility
were provided from cash on hand.
Fixed Charges Under Firm Contracts: Our utility subsidiaries have entered into
various contracts for gas delivery, storage and supply services. The contracts
have remaining terms that cover from one to fourteen years. Certain of these
contracts require payment of annual demand charges in the aggregate amount of
approximately $415 million. We are liable for these payments regardless of the
level of service we require from third parties. Such charges are currently
recovered from utility customers as gas costs.
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 or
financial condition.
In October 1998, the County of Suffolk and the Towns of Huntington and Babylon
commenced an action against LIPA, KeySpan, the NYPSC and others in the United
States District Court for the Eastern District of New York (the "Huntington
Lawsuit"). The Huntington Lawsuit alleges, among other things, that LILCO
ratepayers (i) have a property right to receive or share in the alleged capital
gain that resulted from the transaction with LIPA (which gain is alleged to be
at least $1 billion); and (ii) that LILCO was required to refund to ratepayers
the amount of a Shoreham-related deferred tax reserve (alleged to be at least
$800 million) carried on the books of LILCO at the consummation of the LIPA
Transaction. In December 1998, and again in June 1999, the plaintiffs amended
their complaint. The amended complaint contains allegations relating to certain
payments LILCO had determined were payable in connection with the LIPA
Transaction and KeySpan Acquisition to LILCO's Chairman and certain former
officers and adds the recipients of the payments as defendants. In June 1999,
KeySpan was served with the second amended complaint. On June 16, 2000, KeySpan
filed a motion to dismiss the second amended complaint. On August 14, 2000, the
Court granted KeySpan's motion and dismissed the plaintiffs' second amended
complaint in its entirety. The plaintiffs have appealed that decision. At this
time, we are unable to determine the outcome of this appeal.
A class settlement, which became effective in June 1989 (County of Suffolk, et
al., v. Long Island Lighting Company, et al.), resolved a civil lawsuit against
LILCO brought under the federal Racketeer Influenced and Corrupt Organizations
Act, alleging that LILCO made inadequate disclosures before the NYPSC concerning
the construction and completion of nuclear generating facilities. The class
70
settlement provided electric customers with rate reductions of $390 million that
were being reflected as adjustments to their monthly electric bills over the
ten-year period June 1, 1990 through May 31, 2000.
In November 1999, class counsel for the LILCO ratepayers served a motion, in the
United States District Court for the Eastern District of New York, seeking an
order directing KeySpan to pay $42 million, in addition to the amounts remaining
to be paid under the class settlement. Class counsel contends that the required
rate reductions should have been exclusive of gross receipts taxes. KeySpan
filed its opposition in January 2000 and class counsel filed their reply papers
in February 2000. In their February papers, class counsel revised their demand
to seek an order directing KeySpan to pay approximately $22 million, plus
interest, in addition to the amounts remaining to be paid under the class
settlement. KeySpan filed its rebuttal papers March 1, 2000 and oral arguments
were held March 6, 2000. On March 9, 2000, an order was issued by the court
granting class counsel's motion. On June 20, 2000, KeySpan filed its appeal of
the District Court's order. On December 7, 2000, the United States Court of
Appeals for the second circuit heard oral arguments on the matter. At this time,
we are unable to determine the outcome of this appeal. However, we do not
believe that this proceeding will have a material adverse effect on our
financial position, cash flows or results of operations.
Environmental Matters - New York/Long Island
We have identified 26 manufactured gas plant ("MGP") sites which were
historically owned or operated by KEDNY or KEDLI (or such companies'
predecessors). Operations at these plants in the late 1800's and early 1900's
may have resulted in the release of hazardous substances. These former sites,
some of which are no longer owned by us, have been identified to both the New
York State Department of Environmental Conservation ("DEC") for inclusion on
appropriate waste site inventories and the NYPSC. The currently known conditions
of fourteen of these former MGP sites, their period and magnitude of operation,
generally observed cleanup requirements and costs in the industry, current land
use and ownership, and possible reuse have been considered in establishing
contingency reserves that are discussed below.
In 1995, Brooklyn Union executed an Administrative Order on Consent ("ACO") with
the DEC which addressed the investigation and remediation of a site in Coney
Island, Brooklyn. In 1998, Brooklyn Union executed an ACO for the investigation
and remediation of the Clifton MGP site in Staten Island. Further, the DEC
notified us in 1998 that the Sag Harbor and Rockaway Park MGP sites owned by
KEDLI would require remediation under New York State's Superfund program.
Accordingly, the Sag Harbor and Rockaway Park sites; as well as the Bay Shore,
Glen Cove, Halesite and Hempstead MGP sites; are the subject of two separate
ACOs, which we executed with the DEC in March 1999 and September 1999,
respectively. Field investigations and, in some cases, interim remedial
measures, are underway or scheduled to occur at each of these sites under the
supervision of the DEC and the New York State Department of Health.
71
We were also requested by the DEC to perform preliminary site assessments at the
Patchogue, Babylon, Far Rockaway, Garden City and Hempstead MGP sites, each of
which were formerly owned by LILCO, under a separate ACO entered into in
September 1999. Initial studies based on existing available documentation have
been completed for each such site and the DEC has requested that we collect
additional samples at each of the subject properties.
With the exception of the Coney Island site, which will be redeveloped for
commercial or industrial use, the final end uses for the sites identified above
and, therefore, acceptable remediation goals have not yet been determined. We
are required to prepare a feasibility study for the remediation of each such
site, based on cleanup levels derived from risk analyses associated with the
proposed or anticipated future use of the properties. The schedule for
completing this phase of the work under the ACOs for the identified sites
discussed above extends through 2002.
Thus, thirteen sites identified above are currently the subject of ACOs with the
DEC and one is subject to the negotiation of such an agreement. Our remaining
MGP sites may not become subject to ACOs in the future, and accordingly no
liability has been accrued for these sites. It is possible, based on future
investigation, that we may be required to undertake investigation and potential
remediation efforts at these, or other currently unknown former MGP sites.
However, we are currently unable to determine whether or to what extent such
additional costs may be incurred.
We believe that in the aggregate, the accrued liability for investigation and
remediation of the MGP sites identified above are reasonable estimates of likely
cost within a range of reasonable, foreseeable costs. Accordingly, we presently
estimate the remaining cost of our New York/Long Island MGP- related
environmental cleanup activities will be $111.1 million; which amount has been
accrued by us as our current best estimate of our aggregate environmental
liability for known sites. As previously indicated, the total New York/Long
Island MGP-related costs may be substantially higher, depending upon remediation
experience, selected end use for each site, and actual environmental conditions
encountered.
The KEDNY rate plan provides, among other things, that if the total cost of
investigation and remediation varies from that which is specifically estimated
for a site under investigation and/or remediation, then KEDNY will retain or
absorb up to 10% of the variation. The KEDLI rate plan also provides for the
recovery of investigation and remediation costs but with no consideration of the
difference between estimated and actual costs. Under prior rate orders, KEDNY
has offset certain monies due to ratepayers against its estimated environmental
cleanup costs for MGP sites. At December 31, 2000, we have reflected a
regulatory asset of $88.8 million. Expenditures incurred to date by us with
respect to MGP-related activities total $27.9 million.
In December 1996, LILCO filed a complaint in the United States District Court
for the Southern District of New York against fourteen insurance companies that
issued general comprehensive liability policies to LILCO. In January 1998, LILCO
commenced a similar action against the same, and additional, insurance companies
in New York State Supreme Court, and the federal court action subsequently was
dismissed. The state court action is being conducted by us on behalf of KEDLI.
72
The outcome of this proceeding cannot yet be determined. Periodic settlement
discussions with these insurance carriers and third parties for reimbursement of
some portion of MGP site investigation and remediation costs continue. In
addition, KEDNY is in discussions with insurance carriers regarding the possible
resolution of coverage claims related to its MGP site investigation and
remediation activities without litigation. We are not able to predict the
outcome of these discussions.
In addition, we will be responsible for environmental obligations relating to
the Ravenswood facility operations other than liabilities arising from
pre-closing disposal of waste at off-site locations and any monetary fines
arising from Consolidated Edison's pre-closing conduct. Based on information
currently available for environmental contingencies related to the Ravenswood
facility acquisition, we have accrued an additional $5 million liability.
We are awaiting final development of state and federal regulatory programs with
respect to NOx reduction requirements for our existing power plants. Our
compliance strategy may be composed of fuel choice decisions, acquisition of
emission credits, and installation of emission control equipment. The extent of
development of new generation in the region will also impact our compliance
strategy. Although we are evaluating our alternatives, final decisions cannot be
made until pending regulatory requirements and new generation decisions are
clarified. Expenditures to address emission reduction requirements through the
year 2004 are expected to be between $10 million and $15 million.
Additional capital expenditures associated with the renewal of the surface water
discharge permits for our power plants may be required by the DEC. Until our
monitoring obligations are completed and changes to the Environmental Protection
Agency regulations under Section 316 of the Clean Water Act are promulgated, the
need for and the cost of equipment upgrades cannot be determined.
Environmental Matters - New England
We are aware of certain non-utility sites, associated with former operations of
Eastern, for which we may have or share environmental remediation responsibility
or ongoing maintenance, the principal of which is a former coal tar processing
facility in Everett, Massachusetts (the "Facility"). The Facility, which was
located on a 10-acre parcel of land formerly owned by Eastern, was operated by a
predecessor of Honeywell International, Inc. from the early 1900s until 1937 and
by a predecessor of Beazer East, Inc. from 1937 until 1960, when it was shut
down. The Facility processed coal tar purchased from Eastern's adjacent
by-product coke plant, also shut down in 1960. Eastern, Beazer and Honeywell
have entered into an ACO with the Massachusetts Department of Environmental
Protection ("DEP") which requires that they jointly investigate and develop a
remedial response plan for the Facility, including any area where a release from
that site may have come to be located. Such companies have also entered into a
cost-sharing agreement under which each company has agreed to pay one-third of
the costs of compliance with the consent order, while preserving any claims it
may have against the other companies. The companies have completed preliminary
remedial measures, including abatement of seepage of materials into an adjacent
tidal river. The Coast Guard has been working with the DEP since July 1998 to
bring about a remedial solution that would abate the continuing sheening problem
in the river. Eastern, Beazer and Honeywell have proposed a remedial
73
solution, a major element of which is the utilization of a containment structure
with limited dredging. As of yet, however, no agreement has been reached with
the regulators as to the appropriate remedial solution. We are currently
recovering certain legal defense costs and may be entitled to recover
remediation costs (discussed below) from our insurers. In 1999 Eastern recovered
$2.5 million of prior defense costs from insurance carriers.
In addition, Boston Gas Company, Colonial Gas Company and Essex Gas Company may
have or share responsibility under applicable environmental laws for the
remediation of 28 MGP sites. A subsidiary of New England Electric System
("NEES") has assumed responsibility for remediating eleven of these sites,
subject to a limited contribution from Boston Gas Company.
We are aware of 31 other former MGP sites within the New England utility service
territories. The NEES subsidiary has provided full indemnification to Boston Gas
Company with respect to eight of these sites. At this time, there is substantial
uncertainty as to whether Boston Gas Company, Colonial Gas Company or Essex Gas
Company have or share responsibility for remediating any of these other sites.
No notice of responsibility has been issued to us for any of these sites from
any governmental environmental authority.
We presently estimate the remaining cost of our environmental cleanup
activities for the Facility and MGP-related sites will be approximately $20
million and $21.4 million, respectively, which amounts have been accrued by us
as our current best estimate of our aggregate environmental liability for these
sites. We believe that in the aggregate, the accrued liability for investigating
and remediating the Facility and the New England MGP sites referred to above are
reasonable estimates of likely cost within a range of reasonable, foreseeable
costs. However, the actual remediation cost for the Facility and MGP-related
sites may be substantially higher.
The DTE and New Hampshire Public Service Commission rate plans provide for the
recovery of site investigation and remediation costs, and accordingly, we have
reflected a regulatory asset of $27.8 million at December 31, 2000. Expenditures
incurred for the period of November 8, 2000 through December 31, 2000 totaled
$1.2 million.
Note 10. Hedging, Derivative Financial Instruments, and Fair Values
Futures, Options and Swaps: From time to time we utilize derivative financial
instruments, such as futures, options and swaps, for the purpose of hedging
exposure to commodity price risk and to fix the selling price on a portion of
our peak electric energy capacity.
Utility tariffs applicable to certain large-volume customers permit gas to be
sold at prices established monthly within a specified range expressed as a
percentage of prevailing alternate fuel oil prices. We use gas swap contracts,
with offsetting positions in oil swap contracts of equivalent energy value, with
third parties to fix profit margins on specified portions of gas sales to our
large-volume market. The "long" gas position follows, generally within a range
of 80% to 120%, the cost of gas to serve this
74
market while the offsetting oil swap position correspondingly replicates, within
the same range, the selling price of gas.
We have also engaged in the use of derivative swap instruments and gas futures
to fix the selling price on a portion of our estimated 2001 summer peak electric
energy sales from the Ravenswood facility to protect against a potential
degradation in market prices and to fix the purchase price on a portion of the
fuel used to generate electricity. Under these swap agreements, we will receive
from a counter party a fixed price per megawatt hour of electricity sold during
summer peak hours and pay the counter party the then current floating market
price for peak electric supply. We will receive the then current floating market
price of peak electric energy when the Ravenswood facility sells electric energy
to the NYISO. These derivatives are accounted for as cash-flow hedges. We also
have a tolling arrangement with two counter parties under which we have
"locked-in" a profit margin on 117,600 megawatt hours of 2001 summer season
sales and 96,000 megawatt hours of 2001 winter sales. Under these arrangements,
we will receive from counter parties a fixed margin and will then pay the
counter party, on a monthly basis, our actual profit margin from the sale of
electric energy. As a result of these hedging arrangements, we have hedged
approximately 7% of our estimated 2001 yearly electric sales. We have a stated
hedging policy that we will not hedge more than 50% of our daily peak sales.
Further, as stated, we employ gas future contracts to fix the purchase price of
a portion of the gas used to fuel our Ravenswood facility in association with
certain retail fixed fee electric sales.
Our gas and electric marketing subsidiary has a limited number of fixed rate gas
sales contracts for 2001 and utilizes standard NYMEX futures contracts and swaps
to fix profit margins. In the swap instruments, which are employed to hedge
exposure to basis risk, we pay the amount by which the floating variable price
(settlement price) is below the fixed price and receive the amount by which the
settlement price exceeds the fixed price. These derivative instruments will
expire by August 2001.
Houston Exploration utilizes collars to hedge future sales prices on a portion
of its natural gas production to achieve a more predictable cash flow, as well
as to reduce its exposure to adverse price fluctuations of natural gas. For any
particular collar transaction, the counter party is required to make a payment
to Houston Exploration if the settlement price for any settlement period is
below the floor price for such transaction, and Houston Exploration is required
to make payment to the counter party if the settlement price for any settlement
period is above the ceiling price for such transaction. For any particular floor
transaction, the counter party is required to make a payment to Houston
Exploration if the settlement price for any settlement period is below the floor
price for such transaction. Houston Exploration is not required to make any
payment in connection with a floor transaction. Houston Exploration has hedged
approximately 70% of its estimated 2001 yearly production.
75
The following tables set forth selected financial data associated with our
derivative financial instruments that were outstanding at December 31, 2000.
Year of Volumes
Type of Contract Maturity Mcf Floor Ceiling Fixed Price Current Price Fair Value
- ----------------------- ------------------------- ---------------- --------------- -------------- ---------------- ------------
Gas $ $ $ $ ($000)
Collars 2001 58,400 3.63 - 4.00 5.30 - 6.37 - 5.33 - 9.98 (75,069)
Futures 2001 13,360 - - 2.71 - 5.16 5.43 - 12.53 40,960
- ----------------------- ------------ ------------ -------------- --------------- ---------------- ----------------- ------------
Total Gas 71,760 (34,109)
- ------------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------------
Year of Volumes
Type of Contract Maturity Gallons Fixed Price Current Price Fair Value
- --------------------------- ------------------ ------------------ ------------------------ --------------------- ---------------
Oil $ $ ($000)
Swaps 2001 871,000 0.58 - 0.60 0.82 - 0.94 (10,936)
- --------------------------- ------------------ ------------------ ------------------------ --------------------- ---------------
Year of Fixed Margin / Estimated
Type of Contract Maturity MWh Price Current Price Margin Fair Value
- --------------------------- -------------- ------------- -------------------- ------------------ ------------------ ------------
Electricity $ $ $ ($000)
Tolling Arrangements 2001 213,600 25.00 - 62.00 - 9.72 - 91.54 (1,162)
Swaps 2001 168,000 115.00 - 126.13 133.00 - (2,209)
- --------------------------- -------------- ------------- -------------------- ------------------ ------------------ ------------
Total Electricity 381,600 (3,371)
- --------------------------- -------------- ------------- -------------------- ------------------ ------------------ ------------
As of December 31, 2000, no futures contract extended beyond 2001. Margin
deposits with brokers at December 31, 2000 of $0.6 million were recorded in the
current assets section of the Consolidated Balance Sheet. Deferred gains on
closed positions were $6.1 million at December 31, 2000.
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 contracts is no greater than that
associated with the primary contracts which they hedge, as these contracts are
with major investment grade financial institutions, and that elimination of the
price risk lowers overall business risk.
Interest Rate Swaps: We also have an interest rate swap agreement in which
approximately $70 million of our Gas Facilities Revenue Bonds, 6.75% Series A
and B, have been effectively exchanged for floating rate debt at The Bond Market
Association Swap Index. The interest rate swap agreement expires in twenty-five
years, but can be terminated earlier based on certain market and contract
conditions. For the term of the agreement, we will receive a fixed interest
76
payment of 5.54%. The variable interest rate is reset on a weekly basis. During
2000, the average variable interest rate that we were obligated to pay ranged
from 2.93% to 5.84%. Through the utilization of this interest rate swap we
reduced our recorded interest expense by $1.3 million in 2000. The interest rate
swap has a negative fair value to us of $539,000 at December 31, 2000,
reflecting the current interest rate we are required to pay to the counter party
and the fair value of certain embedded call option features.
Fair Values of Long-Term Debt
The fair values and carrying amounts of our long-term debt at December 31, 2000
and December 31, 1999 were as follows:
Fair Value (In Thousands of Dollars)
December 31, 2000 December 31, 1999
- ------------------------------------ -------------------------- --- -------------------------
First Mortgage Bonds $ 330,057 $ -
Notes 2,482,436 96,000
Gas Facilities Revenue Bonds 672,815 632,409
Authority Financing Notes 66,005 66,005
Promissory Notes 598,769 569,233
------------------- -------------------------
Total $ 4,150,082 $ 1,363,647
- ------------------------------------ ------------------- -------------------------
Carrying Amount (In Thousands of Dollars)
December 31, 2000 December 31, 1999
- ------------------------------------- ------------------------- --------------------------
First Mortgage Bonds $ 322,872 $ -
Notes 2,360,000 100,000
Gas Facilities Revenue Bonds 648,500 648,500
Authority Financing Notes 66,005 66,005
Promissory Notes 602,427 602,427
------------------------- --------------------------
Total $ 3,999,804 $ 1,416,932
- ------------------------------------- ------------------------- --------------------------
Other subsidiary debt is carried at an amount approximating fair value because
interest rates are based on current market rates. All other financial
instruments included in the Consolidated Balance Sheet are stated at amounts
that approximate fair values.
Note 11. KeySpan Gas East Corporation Summary Financial Data
KEDLI is a wholly owned subsidiary of KeySpan. KEDLI was formed on May 7, 1998
and on May 28, 1998 acquired substantially all of the assets related to the gas
distribution business of LILCO. KEDLI provides gas distribution services to
customers in the Long Island counties of Nassau and Suffolk and the Rockaway
peninsula of Queens county. KEDLI established a program for the issuance, from
time to time, of up to $600 million aggregate principal amount of Medium-Term
Notes, which will be fully and unconditionally guaranteed by us. On February 1,
2000, KEDLI issued $400 million of 7.875% Medium-Term Notes due 2010. In January
2001, KEDLI issued an additional $125 million of medium term notes at 6.9% due
January 15, 2008. These notes are also guaranteed by us. The following condensed
financial statements are those of KEDLI and KeySpan as guarantor of the Medium
Term Notes.
(In Thousands of Dollars)
--------------------------------------------------------------------
Balance Sheet December 31, 2000
--------------------------------------------------------------------
Guarantor KEDLI Eliminations Consolidated
---------------- --------------- ---------------- -------------
ASSETS
Current Assets
Cash and temporary cash investments $ 94,508 $ - $ - $ 94,508
Accounts receivable, net 2,002,412 277,632 (558,222) 1,721,822
Other current assets 493,071 93,842 - 586,913
---------------- --------------- ---------------- -------------
2,589,991 371,474 (558,222) 2,403,243
---------------- --------------- ---------------- -------------
Equity Investments 732,058 - (532,862) 199,196
---------------- --------------- ---------------- -------------
Property
Gas 3,845,803 1,500,996 - 5,346,799
Other 3,929,019 - - 3,929,019
Accumulated depreciation, depletion and
amortization (2,649,261) (268,260) - (2,917,521)
---------------- --------------- ---------------- -------------
5,125,561 1,232,736 - 6,358,297
---------------- --------------- ---------------- -------------
Deferred Charges 2,382,258 207,127 - 2,589,385
---------------- --------------- ---------------- -------------
Total Assets $ 10,829,868 $ 1,811,337 $ (1,091,084) $ 11,550,121
================ =============== ================ =============
LIABILITIES AND CAPITALIZATION
Current Liabilities
Accounts payable and accrued expenses $ 1,232,730 $ 196,537 $ - $ 1,429,267
Notes payable 1,300,237 - - 1,300,237
Other current liabilities 224,162 20,407 - 244,569
---------------- --------------- ---------------- -------------
2,757,129 216,944 - 2,974,073
---------------- --------------- ---------------- -------------
Intercompany Accounts payable, long-term - 382,318 (382,318) -
---------------- --------------- ---------------- -------------
Deferred Credits and Other Liabilities
Deferred income tax 477,815 (26,094) - 451,721
Other deferred credits and liabilities 711,931 112,239 - 824,170
---------------- --------------- ---------------- -------------
1,189,746 86,145 - 1,275,891
---------------- --------------- ---------------- -------------
Capitalization
Common shareholders' equity 2,798,652 550,026 (532,862) 2,815,816
Preferred stock 84,205 - - 84,205
Long-term debt 3,874,938 575,904 (175,904) 4,274,938
---------------- --------------- ---------------- -------------
Total Capitalization 6,757,795 1,125,930 (708,766) 7,174,959
---------------- --------------- ---------------- -------------
Minority Interest in Subsidiary Companies 125,198 - - 125,198
---------------- --------------- ---------------- -------------
Total Liabilities and Capitalization $ 10,829,868 $ 1,811,337 $ (1,091,084) $ 11,550,121
================ =============== ================ =============
(In Thousands of Dollars)
---------------------------------------------------------------------
Balance Sheet December 31, 1999
---------------------------------------------------------------------
Guarantor KEDLI Eliminations Consolidated
---------------- -------------- ---------------------------------
ASSETS
Current Assets
Cash and temporary cash investments $ 128,602 $ - $ - $ 128,602
Accounts receivable, net 1,236,171 278,722 (874,388) 640,505
Other current assets 309,153 79,693 - 388,846
---------------- -------------- --------------- ---------------
1,673,926 358,415 (874,388) 1,157,953
---------------- -------------- --------------- ---------------
Equity Investments 1,049,593 - (657,862) 391,731
---------------- -------------- --------------- ---------------
Property
Gas 2,055,851 1,393,533 - 3,449,384
Other 2,900,424 - - 2,900,424
Accumulated depreciation, depletion and
amortization (1,863,840) (245,956) - (2,109,796)
---------------- -------------- --------------- ---------------
3,092,435 1,147,577 - 4,240,012
---------------- -------------- --------------- ---------------
Deferred Charges 760,880 180,115 - 940,995
---------------- -------------- --------------- ---------------
Total Assets $ 6,576,834 $ 1,686,107 $ (1,532,250) $6,730,691
================ ============== =============== ===============
Guarantor KEDLI Eliminations Consolidated
---------------- -------------- --------------- ---------------
LIABILITIES AND CAPITALIZATION
Current Liabilities
Accounts payable and accrued expenses $ 502,866 $ 142,481 $ - $ 645,347
Notes payable 208,300 - - 208,300
Other current liabilities 525,755 405,850 (397,000) 534,605
---------------- -------------- --------------- ---------------
1,236,921 548,331 (397,000) 1,388,252
---------------- -------------- --------------- ---------------
Intercompany Accounts payable, long-term 43,405 258,079 (301,484) -
---------------- -------------- --------------- ---------------
Deferred Credits and Other Liabilities
Deferred income tax 240,995 (52,065) - 188,930
Other deferred credits and liabilities 491,637 102,784 - 594,421
---------------- -------------- --------------- ---------------
732,632 50,719 - 783,351
---------------- -------------- --------------- ---------------
Capitalization
Common shareholders' equity 2,717,113 653,074 (657,862) 2,712,325
Preferred stock 84,339 - - 84,339
Long-term debt 1,682,702 175,904 (175,904) 1,682,702
---------------- -------------- --------------- ---------------
Total Capitalization 4,484,154 828,978 (833,766) 4,479,366
---------------- -------------- --------------- ---------------
Minority Interest in Subsidiary Companies 79,722 - - 79,722
---------------- -------------- --------------- ---------------
Total Liabilities and Capitalization $ 6,576,834 $ 1,686,107 $ (1,532,250) $6,730,691
================ ============== =============== ===============
--------------------------------------------------------
Statement of Cash Flows Year Ended December 31, 2000
--------------------------------------------------------
Guarantor KEDLI Consolidated
------------------ -------------- -----------------
Operating Activities
Net Cash Provided by
Operating Activities $ 337,167 $ 112,738 $ 449,905
--------------- -------------- -----------------
Investing Activities
Capital expenditures (518,058) (114,977) (633,035)
Other (2,238,775) - (2,238,775)
--------------- -------------- -----------------
Net Cash (Used in) Provided by
Investing Activities (2,756,833) (114,977) (2,871,810)
--------------- -------------- -----------------
Financing Activities
Treasury stock issued 72,289 - 72,289
Receipt/payment of dividends 125,000 (125,000) -
Redemption of preferred stock (363,000) - (363,000)
Issuance of notes payable 1,300,237 - 1,300,237
Issuance of long-term debt 1,766,955 400,000 2,166,955
Payment of long-term debt (68,365) - (68,365)
Payment of notes payable (364,865) - (364,865)
Long-term debt received (paid) 397,000 (397,000) -
Preferred stock dividends paid (20,261) - (20,261)
Common stock dividends paid (239,740) - (239,740)
Settlement of rate lock (59,490) - (59,490)
Net Intercompany accounts payable (124,239) 124,239 -
Other (35,949) - (35,949)
--------------- -------------- -----------------
Net Cash Provided by
Financing Activities 2,385,572 2,239 2,387,811
--------------- -------------- -----------------
Net (Decrease) Increase in
Cash and Cash Equivalents $ (34,094) $ - $ (34,094)
=============== ============== =================
Cash and cash equivalents
at beginning of period $ 128,602 $ - $ 128,602
Net (Decrease) Increase in
Cash and Cash Equivalents $ (34,094) $ - $ (34,094)
Cash and cash equivalents
at End of Period --------------- -------------- -----------------
$ 94,508 $ - $ 94,508
=============== ============== =================
----------------------------------------------------------
Statement of Cash Flows Year Ended December 31, 1999
----------------------------------------------------------
Guarantor KEDLI Consolidated
----------------------------------------------------------
Operating Activities
Net Cash Provided by
Operating Activities $ 564,109 $ 24,896 $ 589,005
--------------- -------------- -------------------
Investing Activities
Capital expenditures (569,838) (102,007) (671,845)
Other (23,819) - (23,819)
--------------- -------------- -------------------
Net Cash (Used in) Provided by
Investing Activities (593,657) (102,007) (695,664)
--------------- -------------- -------------------
Financing Activities
Treasury stock issued / (purchased) (299,243) - (299,243)
Issuance of notes payable 208,300 - 208,300
Issuance of long-term debt 102,648 - 102,648
Payment of long-term debt (442,475) - (442,475)
Preferred stock dividends paid (34,760) - (34,760)
Common stock dividends paid (249,567) - (249,567)
Net Intercompany accounts payable (77,111) 77,111 -
Other 7,582 - 7,582
--------------- -------------- -------------------
Net Cash Provided by (Used in )
Financing Activities (784,626) 77,111 (707,515)
--------------- -------------- -------------------
Net (Decrease) Increase in
Cash and Cash Equivalents $ (814,174) $ - $ (814,174)
=============== ============== ===================
Cash and cash equivalents
at beginning of period $ 942,776 $ - $ 942,776
Net (Decrease) Increase in
Cash and Cash Equivalents $ (814,174) $ - $ (814,174)
Cash and cash equivalents
at End of Period --------------- -------------- -------------------
$ 128,602 $ - $ 128,602
=============== ============== ===================
-----------------------------------------------------------
Statement of Cash Flows Nine Months Ended December 31, 1999
-----------------------------------------------------------
Guarantor KEDLI Consolidated
--------------- --------------- --------------------
Operating Activities
Net Cash Provided by (Used in )
Operating Activities $ (401,797) $ (58,491) $ (460,288)
--------------- --------------- --------------------
Investing Activities
Capital expenditures (616,880) (59,683) (676,563)
Net proceeds from LIPA Transaction 2,314,588 - 2,314,588
Other 148,014 30,620 178,634
--------------- --------------- --------------------
Net Cash (Used in) Provided by
Investing Activities 1,845,722 (29,063) 1,816,659
--------------- --------------- --------------------
Financing Activities
Treasury stock issued / (purchased) (423,716) - (423,716)
Issuance of long-term debt 112,535 - 112,535
Issuance of preferred stock 84,973 - 84,973
Payment of long-term debt (103,000) - (103,000)
Preferred stock dividends paid (27,548) (1,056) (28,604)
Common stock dividends paid (210,177) - (210,177)
Net Intercompany accounts payable (86,885) 86,885 -
Other (26,525) - (26,525)
--------------- --------------- --------------------
Net Cash Provided by (Used in )
Financing Activities (680,343) 85,829 (594,514)
--------------- --------------- --------------------
Net (Decrease) Increase in
Cash and Cash Equivalents $ 763,582 $ (1,725) $ 761,857
=============== =============== ====================
Cash and cash equivalents
at beginning of period $ 179,194 $ 1,725 $ 180,919
Net (Decrease) Increase in
Cash and Cash Equivalents $ 763,582 $ (1,725) $ 761,857
Cash and cash equivalents
at End of Period --------------- --------------- --------------------
$ 942,776 $ - $ 942,776
=============== =============== ====================
(In Thousands of Dollars)
--------------------------------------------------------------------------------------------
Income Statement Year Ended Ended December 31, 2000
--------------------------------------------------------------------------------------------
Guarantor KEDLI Eliminations Consolidated
--------------------- -------------- ------------------ --------------------
Revenues $ 4,326,525 $ 794,965 $ - $ 5,121,490
--------------------- -------------- ------------------ --------------------
Operating Expenses
Purchased gas 1,000,534 408,087 - 1,408,621
Fuel and purchased power 460,900 - - 460,900
Operations and maintenance 1,632,902 127,780 - 1,760,682
Intercompany expense net (10,718) 10,718 - -
Depreciation and amortizations 289,089 46,017 - 335,106
Operating taxes 331,634 92,684 - 424,318
--------------------- -------------- ------------------ --------------------
Total Operating Expenses 3,704,341 685,286 - 4,389,627
--------------------- -------------- ------------------ --------------------
Operating Income 622,184 109,679 - 731,863
Other Income and (Deductions) 14,044 (707) (24,767) (11,430)
--------------------- -------------- ------------------ --------------------
Income (Loss) Before Interest
Charges and Income Taxes 636,228 108,972 (24,767) 720,433
Interest Expense 174,461 53,656 (24,767) 203,350
Income Taxes 197,914 18,362 - 216,276
--------------------- -------------- ------------------ --------------------
Net Income 263,853 36,954 - 300,807
Preferred Stock Dividends 18,113 - - 18,113
--------------------- -------------- ------------------ --------------------
Earnings for Common Stock $ 245,740 $ 36,954 $ - $ 282,694
===================== ============== ================== ====================
(In Thousands of Dollars)
-------------------------------------------------------------------------------------
Income Statement Year Ended Ended December 31, 1999
-------------------------------------------------------------------------------------
Guarantor KEDLI Eliminations Consolidated
----------------- --------------- -------------------- --------------------
Revenues $ 2,317,525 $ 637,088 $ - $ 2,954,613
----------------- --------------- -------------------- --------------------
Operating Expenses
Purchased gas 459,508 284,924 - 744,432
Fuel and purchased power 17,252 - - 17,252
Operations and maintenance 981,331 109,835 - 1,091,166
Intercompany expense net (10,793) 10,793 - -
Depreciation and amortizations 220,639 32,801 - 253,440
Operating taxes 282,521 83,633 - 366,154
----------------- --------------- -------------------- --------------------
Total Operating Expenses 1,950,458 521,986 - 2,472,444
----------------- --------------- -------------------- --------------------
Operating Income 367,067 115,102 - 482,169
Other Income and (Deductions) 96,884 159 (50,488) 46,555
----------------- --------------- -------------------- --------------------
Income (Loss) Before Interest
Charges and Income Taxes 463,951 115,261 (50,488) 528,724
Interest Expense 133,751 50,488 (50,488) 133,751
Income Taxes 113,106 23,256 136,362
----------------- --------------- -------------------- --------------------
Net Income 217,094 41,517 - 258,611
Preferred Stock Dividends 34,752 - - 34,752
----------------- --------------- -------------------- --------------------
Earnings for Common Stock $ 182,342 $ 41,517 $ - $ 223,859
================= =============== ==================== ====================
(In Thousands of Dollars)
-------------------------------------------------------------------------------
Income Statement Nine Months Ended December 31, 1998
-------------------------------------------------------------------------------
Guarantor KEDLI Eliminations Consolidated
-------------- --------------- ---------------- -----------------
Revenues $ 1,371,847 $ 356,634 $ - $ 1,728,481
-------------- --------------- ---------------- -----------------
Operating Expenses
Purchased gas 181,068 150,622 - 331,690
Operations & maintenance expenses 740,453 101,860 - 842,313
Intercompany expense, net (7,221) 7,221 - -
Depreciation and amortizations 236,599 18,260 - 254,859
Operating taxes 203,307 53,817 - 257,124
Fuel and purchased power 91,762 - - 91,762
-------------- --------------- ---------------- -----------------
Total Operating Expenses 1,445,968 331,780 - 1,777,748
-------------- --------------- ---------------- -----------------
Operating Income (74,121) 24,854 - (49,267)
Other Income and (Deductions) 6,387 (2,056) (41,058) (36,727)
-------------- --------------- ---------------- -----------------
Income (Loss) Before Interest
Charges and Income Taxes (67,734) 22,798 (41,058) (85,994)
Interest Expense 140,733 41,058 (41,058) 140,733
Income Taxes (53,425) (6,369) - (59,794)
-------------- --------------- ---------------- -----------------
Net Income (155,042) (11,891) - (166,933)
Preferred Stock Dividends 27,548 1,056 - 28,604
-------------- --------------- ---------------- -----------------
Earnings (Loss) for Common Stock $ (182,590) $ (12,947) $ - $ (195,537)
============== =============== ================ =================
Note 12. Eastern/EnergyNorth Acquisition
On November 8, 2000, we purchased all of the outstanding stock of Eastern for
$64.56 per share in cash and all of the outstanding common stock of ENI for
$61.46 per share in cash. The increased size of KeySpan should enable us to
provide enhanced cost-effective customer service and to capitalize on the
above-average growth opportunities for natural gas in the Northeast and provide
additional resources to our unregulated businesses. We expect annual pre-tax
cost savings of approximately $40 million, resulting from the elimination of
duplicate corporate administrative programs and operating efficiencies.
The transactions have been accounted for using the purchase method of accounting
for business combinations. Accordingly, the accompanying consolidated statements
of income include Eastern and ENI results commencing November 8, 2000. The
purchase price was allocated to the net assets acquired based upon their fair
value. The historical cost basis of Eastern's and ENI's assets and liabilities,
with minor exceptions, was determined to represent the fair value due to the
existence of regulatory-approved rate plans based upon the recovery of
historical costs and a fair return thereon. The excess of the purchase price
over the fair value of the net assets acquired, or goodwill, of approximately
$1.5 billion has been recorded as an asset and is being amortized over a period
of 20 to 40 years.
The following is the comparative unaudited proforma condensed financial
information for the years ended December 31, 2000 and 1999. The proforma
disclosures reflect the results of the operations of Eastern and ENI as if our
acquisitions were consummated on the first day of the reporting periods.
Year Ended Year Ended
December 31, 2000 December 31, 1999
- ----------------------- -------------------------- ---- ----------------------
(In Thousands of Dollars, Except Per Share Amounts)
Revenues 6,130,158 4,058,178
Operating Income 671,081 568,754
Net Income 114,393 174,923
Earnings Per Share $0.71 $1.01
- -------------------------------------------------------------------------------
78
Included in the 2000 proforma earnings, are merger related costs of $76.0
million, after-tax, recorded by Eastern and ENI in connection with our
acquisition of these companies. Excluding these costs, proforma earnings per
share for the year ended December 31, 2000 were $1.27. These proforma results
may not be indicative of future results. Further, the consolidated proforma
results for 2000 and 1999 do not take into account: (i) continued gas sales
growth throughout our service territories, especially on Long Island and in New
England; (ii) earnings enhancement from our gas exploration and production
operations; (iii) the continued successful integration of acquired companies
providing energy-related services within our Energy Services segment; and (iv)
anticipated before- tax synergy savings of $40 million annually starting in
2001.
Note 13. Workforce Reduction Programs
As a result of the Eastern and ENI acquisitions, we have implemented an early
retirement program and a severance program in an effort to reduce our workforce.
The early retirement program was completed in December 2000 and resulted in a
workforce reduction of over 200 employees. We recorded a charge of $51.4 million
in December 2000 to reflect the termination benefits for pension and other
postretirement benefits related to the employees who voluntarily elected early
retirement.
In addition, in December 2000, we recorded a $15.0 million liability associated
with a severance program. Eastern and ENI had previously recorded an additional
liability of $7.7 million associated with this severance program. This severance
program is targeted to reduce our workforce by an additional 500 employees. The
plan provides a severance allowance for certain targeted employees and will
continue through 2002.
Note 14. Shareholder Rights Plan
On March 30, 1999 our Board of Directors adopted a Shareholder Rights Plan (the
"Plan") designed to protect shareholders in the event of a proposed takeover.
The Plan creates a mechanism that would dilute the ownership interest of a
potential unauthorized acquirer. The Plan establishes one preferred stock
purchase "right" for each outstanding share of common stock to shareholders of
record on April 14, 1999. Each right, when exercisable, entitles the holder to
purchase 1/100th of a share of Series D Preferred Stock, at a price of $95.00.
The rights generally become exercisable following the acquisition of more than
20 percent of our common stock without the consent of the Board of Directors.
Prior to becoming exercisable, the rights are redeemable by the Board of
Directors for $0.01 per right. If not so redeemed, the rights will expire on
March 30, 2009.
Note 15. Sale of LILCO Assets, Acquisition of KeySpan Energy Corporation and
Transfer of Assets and Liabilities to KeySpan.
On May 28, 1998, LIPA acquired all of the outstanding common stock of LILCO for
$2.4975 billion in cash and thereafter directly or indirectly assumed certain
liabilities ("LIPA Transaction"). Moreover, all of LILCO's outstanding long-term
debt as of May 28, 1998, except for its 1997 Series A Electric Facilities
Revenue Bonds due December 1, 2027 which were assigned to KeySpan Corporation,
was assumed by LIPA. In accordance with the LIPA Transaction, we issued
79
promissory notes to LIPA amounting to $1.048 billion which represented an amount
equivalent to the sum of (i) the principal amount of 7.30% Series Debentures due
July 15, 1999 and 8.20% Series Debentures due March 15, 2023 outstanding as of
May 28, 1998, and (ii) an allocation of certain of the Authority Financing
Notes. The promissory notes contain identical terms to the debt referred to in
items (i) and (ii) above. Immediately prior to such acquisition, all of LILCO's
assets employed in the conduct of its gas distribution business and its
non-nuclear electric generation business, and all common assets used by LILCO in
the operation and management of its electric T&D business and its gas
distribution business and/or its non-nuclear electric generation business (the
"Transferred Assets") were sold to KeySpan Corporation and transferred to
certain of our wholly-owned subsidiaries.
On May 28, 1998, immediately subsequent to the LIPA Transaction, KSE was merged
with and into a subsidiary of KeySpan Corporation.
As a result of these transactions, holders of KSE common stock received one
share of KeySpan Corporation's common stock, par value $.01 per share, for each
share of KSE they owned and holders of LILCO common stock received 0.880 of a
share of KeySpan Corporation common stock for each share of LILCO they owned.
Upon the closing of these transactions, former holders of KSE and LILCO owned
32% and 68%, respectively, of KeySpan Corporation's common stock.
The purchase price of $1.223 billion for the acquisition of KSE has been
allocated to assets acquired and liabilities assumed based upon their estimated
fair values. The fair value of the utility assets acquired is represented by its
book value which approximates the value recognized by the NYPSC in establishing
rates for regulated utility services. The estimated fair value of KSE's
non-utility assets approximated their carrying values. At May 28, 1998, we
recorded goodwill in the amount of $170.9 million, representing primarily the
excess of the acquisition cost over the fair value of the net assets acquired;
the goodwill is being amortized over 40 years.
Note 16. Costs Related to the LIPA Transaction and Special Charges
Special charges for the nine months ended December 31, 1998 were $162.0 million
after-tax. These charges reflect, in part, non-recurring charges associated with
the LIPA Transaction of $107.9 million after-tax. Costs relating to the LIPA
Transaction principally reflect taxes associated with the sale of assets (the
"Transferred Assets") to us by LIPA; the write-off of certain regulatory assets
that were no longer recoverable under various LIPA agreements; and other
transaction costs incurred to consummate the LIPA Transaction. These charges
were offset, in part, by tax benefits relating to the deferred federal income
taxes necessary to account for the difference between the carryover basis of the
Transferred Assets for financial reporting purposes and the new increased tax
basis of the assets, and tax benefits recognized on the funding of
postretirement benefits for our employees.
Special charges also reflect an after-tax impairment charge of $54.1 million,
which represents our share of the impairment charge, recorded by Houston
Exploration to reduce the value of its proved
80
gas reserves in accordance with the asset ceiling test limitations of the SEC
applicable to gas exploration and development operations accounted for under the
full cost method
Note 17. Supplemental Gas and Oil Disclosures (Unaudited)
This information includes amounts attributable to 100% of Houston Exploration
and KeySpan Exploration and Production, LLC at December 31, 2000. Shareholders
other than KeySpan had a minority interest of approximately 30% in Houston
Exploration at December 31, 2000 and a 36% minority interest in 1999. Gas and
oil operations, and reserves, were predominantly located in the United States in
all years.
Capitalized Costs Relating To Gas and Oil Producing Activities
At December 31, 2000 1999
- ------------------------------------------------------------------------------- ------------------------- ----------------
(In Thousands of Dollars)
Unproved properties not being amortized $ 166,478 $ 176,876
Properties being amortized - productive and nonproductive 1,235,438 979,615
----------------- ------------------
Total capitalized costs 1,401,916 1,156,491
Accumulated depletion (577,240) (512,465)
----------------- -----------------
Net capitalized costs $ 824,676 $ 644,026
- ------------------------------------------------------------------------------- ----------------- ------------------
The following is a break-out of the costs which are excluded from the
amortization calculation as of December 31, 2000, by year of acquisition: 2000-
$46.5 million , 1999 - $28.3 million and prior years $91.5 million. We cannot
accurately predict when these costs will be included in the amortization base,
but it is expected that these costs will be evaluated within the next five
years.
Costs Incurred in Property Acquisition, Exploration and Development Activities
Year Ended December 31, 2000 1999 1998
- ---------------------------------------- ---------------------- ---------------------- ----------------------
(In Thousands of Dollars)
Acquisition of properties-
Unproved properties $ 7,992 $ 13,107 $ 33,803
Proved properties 40,960 42,573 162,083
Exploration 70,511 39,649 55,611
Development 111,078 87,965 51,046
---------------------- ---------------------- ----------------------
Total costs incurred $ 230,541 $ 183,294 $ 302,543
- ---------------------------------------- ---------------------- ---------------------- ----------------------
81
Results of Operations from Gas and Oil Producing Activities*
Year Ended December 31, 2000 1999 1998
- ------------------------------------------------------------ ----------------- -------------------- ------------------
(In Thousands of Dollars)
Revenues $ 274,209 $ 150,581 $ 127,124
----------------- -------------- ----------------------
Production and lifting costs 36,929 23,851 21,166
Depletion 95,364 74,051 209,838
----------------- -------------- ----------------------
Total expenses 132,293 97,902 231,004
----------------- -------------- ----------------------
Income before taxes 141,916 52,679 (103,880)
Income Taxes 48,790 17,477 (37,410)
----------------- -------------- ----------------------
Results of operations $ 93,126 $ 35,202 $ (66,470)
- ------------------------------------------------------------ ----------------- -------------- ----------------------
*(excluding corporate overhead and interest costs)
The gas and oil reserves information is based on estimates of proved reserves
attributable to the interest of Houston Exploration and KeySpan Exploration and
Production, LLC as of December 31 for each of the years presented. These
estimates principally were prepared by 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, 2000 1999 1998
- -------------------------------------------- ---- ---------------------- ---------------------- ---------------------
Proved reserves
Beginning of year 534,308 470,447 330,601
Revisions of previous estimates 4,479 45,510 (4,656)
Extensions and discoveries 77,643 70,741 67,272
Production (78,493) (69,679) (61,479)
Purchases of reserves in place 7,921 20,779 139,994
Sales of reserves in place - (3,492) (1,285)
----------------- --------------------- ---------------------
Proved reserves-
End of year (1) 545,858 534,306 470,447
- -------------------------------------------------- ----------------- ---------------------- ---------------------
Proved developed reserves-
Beginning of year 399,482 369,931 256,632
End of year (2) 431,536 399,482 369,931
- -------------------------------------------------- ----------------- ---------------------- ---------------------
(1) Includes minority interest of 167,730; 189,427; and 169,361; in 2000, 1999,
and 1998, respectively. (2) Includes minority interest of 133,271; 143,043; and
133,175; in 2000, 1999, and 1998, respectively.
82
Crude Oil, Condensate and Natural Gas Liquids (MBbls)
At December 31, 2000 1999 1998
- ---------------------------------------------- ----------------------- ---------------------- ----------------------
Proved reserves
Beginning of year 3,136 1,650 1,077
Revisions of previous estimates 108 237 (105)
Extensions and discoveries 4,326 1,574 249
Production (320) (258) (225)
Purchases of reserves in place 662 2 665
Sales of reserves in place - (69) (11)
----------------------- ---------------------- ----------------------
Proved reserves-
End of year (1) 7,912 3,136 1,650
- ---------------------------------------------- ----------------------- ---------------------- ----------------------
Proved developed reserves-
Beginning of year 2,059 1,498 914
End of year (2) 2,126 2,059 1,498
- ---------------------------------------------- ----------------------- ---------------------- ----------------------
(1) Includes minority interest of 1,695; 890; and 594; in 2000,1999, and 1998,
respectively. (2) Includes minority interest of 573; 647; and 539 in 2000,1999,
and 1998, respectively.
The standardized measure of discounted future net cash flows was prepared by
applying year-end prices of gas and oil to the proved reserves. The standardized
measure does not purport, nor should it be interpreted, to present the fair
value of gas and oil reserves of Houston Exploration or KeySpan Exploration and
Production LLC. An estimate of fair value would also take into account, among
other things, the recovery of reserves not presently classified as proved,
anticipated future changes in prices and costs, and a discount factor more
representative of the time value of money and the risks inherent in reserve
estimates.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Gas and Oil Reserves
At December 31, 2000 1999
- ----------------------------------------------------------------------- ------------------------ ----------------------
(In Thousands of Dollars)
Future cash flows $ 5,415,587 $ 1,146,966
Future costs -
Production (558,384) (194,527)
Development (182,242) (128,645)
------------------------ ----------------------
Future net inflows before income tax 4,674,961 823,794
Future income taxes (1,299,965) (160,940)
------------------------ ----------------------
Future net cash flows 3,374,996 662,854
10% discount factor (1,209,237) (182,222)
------------------------ ----------------------
Standardized measure of discounted future net cash flows (1) $ 2,165,759 $ 480,632
- ----------------------------------------------------------------------- ------------------------ ----------------------
(1) Includes minority interest of 653,046 and 168,921 in 2000 and 1999,
respectively.
83
Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserve Quantities
Year Ended December 31, 2000 1999 1998
- ---------------------------------------------------------------------- -------------------- ------------------- ------------------
(In Thousands of Dollars)
Standardized measure -
beginning of year $ 480,632 $ 396,060 $ 315,380
Sales and transfers, net of production costs (240,702) (126,730) (105,958)
Net change in sales and transfer prices,
net of production costs 2,142,932 47,330 (104,137)
Extensions and discoveries and improved
recovery, net of related costs 472,658 106,076 72,333
Changes in estimated future development costs (38,839) (25,730) (6,656)
Development costs incurred during the period
that reduced future development costs 77,197 40,563 15,891
Revisions of quantity estimates 24,650 51,375 (4,982)
Accretion of discount 54,460 41,293 37,706
Net change in income taxes (706,074) (47,097) 44,812
Net purchases of reserves in place 23,118 19,018 155,259
Changes in production rates (timing) and other (124,273) (21,526) (23,588)
-------- ------- -------
Standardized measure -
end of year $ 2,165,759 $ 480,632 $ 396,060
- ------------------------------------------------------------------------------------------------------------------------------------
Average Sales Prices and Production Costs Per Unit
Year Ended December 31, 2000 1999 1998
- -------------------------------------------------------------------------- ------------------- ------------------ ---------------
Average sales price* Natural gas ($/MCF) 3.97 2.14 1.96
Oil, condensate and natural gas liquid ($/Bbl) 27.29 16.41 12.18
Production cost per equivalent MCF ($) 0.55 0.26 0.26
- -------------------------------------------------------------------------- ------------------- ------------------ ---------------
*Represents the cash price received which excludes the effect of any hedging
transactions.
Acreage
At December 31, 2000 Gross Net
- ------------------------------------------------------------ ------------------- ------------------ ----------------
Producing 335,017 217,407
Undeveloped 384,119 334,798
- -----------------------------------------------------------------------------------------------------------------------
Number of Producing Wells
At December 31, 2000 Gross Net
- ------------------------------------------------------------ ------------------- ------------------ ----------------
Gas wells 1,307 889.6
Oil wells 8 3.4
- -------------------------------------------------------------------------------- ------------------- -----------------
Drilling Activity (Net)
Year Ended December 31, 2000 1999 1998
- -------------------------- ---------------------------------- ------------------------------------ ---------------------------------
Producing Dry Total Producing Dry Total Producing Dry Total
--------- --- ----- --------- --- ----- --------- --- -----
Net developmental wells 40.4 4.4 44.8 29.7 3.1 32.8 19.2 4.6 23.8
Net exploratory wells 5.1 1.7 6.8 2.9 1.0 3.9 1.6 4.2 5.8
- ------------------------------------------------------------------------------------------------------------------------------------
Wells in Process
At December 31, 2000 Gross Net
- ------------------------------------- ------------------ ----------------------
Exploratory 5 1.8
Developmental 5 4.3
- ------------------------------------- ------------------ ----------------------
84
Note 18. Summary of Quarterly Information (Unaudited)
The following is a table of financial data for each quarter of KeySpan's year
ended December 31, 2000.
(In Thousands of Dollars, Except Per Share Amounts)
Quarter Ended Quarter Ended Quarter Ended Quarter Ended
3/31/00 6/30/00 9/30/00 12/31/00 (a)
- -------------------------------------------------------------------------------------------------------------------------
Operating revenues 1,316,613 947,588 947,137 1,910,152
Operating income 296,506 133,524 92,078 209,755
Net income 172,244 53,366 14,630 60,567
Earnings for common stock 163,553 47,080 13,154 58,907
Basic and diluted earnings
per common share (b) 1.22 0.35 0.10 0.44
Dividends declared 0.445 0.445 0.445 0.445
- -------------------------------------------------------------------------------------------------------------------------
(a) Reflects an after-tax charge of $41.1 million relating to an early
retirement and severance program.
(b) Quarterly earnings per share are based on the average number of shares
outstanding during the quarter. Because of the changing number of common shares
outstanding in each quarter, the sum of quarterly earnings per share does not
equal earnings per share for the year.
The following is a table of financial data for each quarter of KeySpan's year
ended December 31, 1999.
(In Thousands of Dollars, Except Per Share Amounts)
Quarter Ended Quarter Ended Quarter Ended Quarter Ended
3/31/99 6/30/99 9/30/99 12/31/99
- -------------------------------------------------------------------------------------------------------------------------
Operating revenues 961,108 543,526 538,469 911,510
Operating income 242,226 61,211 36,783 141,949
Net income 143,221 22,989 9,016 83,385
Earnings for common stock 134,532 14,299 328 74,700
Basic and diluted earnings
per common share (a) 0.94 0.10 0.00 0.56
Dividends declared 0.445 0.445 0.445 0.445
- -------------------------------------------------------------------------------------------------------------------------
(a) Quarterly earnings per share are based on the average number of shares
outstanding during the quarter. Because of the changing number of common
shares outstanding in each quarter, the sum of quarterly earnings per share
does not equal earnings per share for the year.
85
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of KeySpan Corporation d/b/a/ KeySpan
Energy:
We have audited the accompanying Consolidated Balance Sheet and Consolidated
Statement of Capitalization of KeySpan Corporation (a New York corporation) and
subsidiaries as of December 31, 2000 and December 31, 1999 and the related
Consolidated Statements of Income, Retained Earnings, Comprehensive Income and
Cash Flows for the two years then ended and the nine months ended December 31,
1998. These financial statements are the responsibility of the KeySpan
Corporation's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position and capitalization of KeySpan
Corporation and subsidiaries as of December 31, 2000 and December 31, 1999 and
the results of their operations and their cash flows for the years then ended
and the nine months ended December 31, 1998, in conformity with accounting
principles generally accepted in the United States.
Our audit was made for the purpose of forming an opinion on the basic financial
statements taken as a whole. The schedule listed in Item 14 is the
responsibility of the KeySpan Corporation's management and is presented for the
purpose of complying with the Securities and Exchange Commission's rules and is
not part of the basic financial statements. This schedule has been subjected to
the auditing procedures applied in the audits of the basic financial statements
and, in our opinion, fairly states in all material respects the financial data
required to be set forth therein in relation to the basic financial statements
taken as a whole.
ARTHUR ANDERSEN LLP
January 25, 2001
New York, New York
86
SCHEDULE OF VALUATION AND QUALIFYING ACCOUNTS
(In Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
- -------------------------------------------------------------------------------------------------------------------
Additions
------------------------------
Balance at Charged to Balance at
beginning costs and Acquisitions and end of
Description of period expenses LIPA Transaction Net deductions period
- -------------------------------------------------------------------------------------------------------------------
Twelve months ended December 31, 2000
- -------------------------------------
Deducted from asset accounts:
Allowance for doubtful accounts $20,294 $26,455 $20,372 $17,643 $49,478
Additions to liability accounts:
Reserve for injuries and damages $36,385 $20,074 $14,228 $19,121 $51,566
Reserve for environmental expenditures $128,011 - $42,637 $13,141 $157,507
Twelve months ended December 31, 1999
- -------------------------------------
Deducted from asset accounts:
Allowance for doubtful accounts $20,026 $15,793 - $15,525 $20,294
Additions to liability accounts:
Reserve for injuries and damages $29,075 $25,930 - $18,620 $36,385
Reserve for environmental expenditures $130,278 $5,000 - $7,267 $128,011
Nine months ended December 31, 1998
- -------------------------------------
Deducted from asset accounts:
Allowance for doubtful accounts $23,483 $11,064 $3,777 $18,298 $20,026
Additions to liability accounts:
Reserve for injuries and damages $12,254 $8,690 $15,246 $7,115 $29,075
Reserve for environmental expenditures $33,080 $48,920* $48,278 - $130,278
*Recorded as a Regulatory Asset for Future Recovery
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
Part III
Item 10. Directors and Executive Officers of the Registrant
A definitive proxy statement was filed with the SEC on March 23, 2001 (the
"Proxy Statement"). The information required by this item is set forth under the
caption "Executive Officers of the Company" in Part I hereof and under the
captions "Election of Directors" and "Section 16(a) Beneficial Ownership
Reporting Compliance" contained in the Proxy Statement, which information is
incorporated herein by reference thereto.
Item 11. Executive Compensation
The information required by this item is set forth under the caption "Executive
Compensation" in the Proxy Statement, which information is incorporated herein
by reference thereto.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The information required by this item is set forth under the captions "Security
Ownership of Management" and "Security Ownership of Certain Beneficial Owners"
in the Proxy Statement, which information is incorporated herein by reference
thereto.
Item 13. Certain Relationships and Related Transactions
The information required by this item is set forth under the caption "Agreements
with Executives," "Legal Services," and "Involvement in Certain Proceedings" in
the Proxy Statement, which information is incorporated herein by reference
thereto.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
1. Financial Statements
The following consolidated financial statements of KeySpan and its subsidiaries
and report of independent accountants are filed as part of this Report:
Report of Independent Public Accountants
Consolidated Statement of Income for the year ended December 31,
2000, the year ended December 31, 1999, and the nine
months ended December 31, 1998.
Consolidated Statement of Retained Earnings for the year ended
December 31, 2000, the year ended December 31, 1999, and
the nine months ended December 31, 1998.
Consolidated Balance Sheet at December 31, 2000 and December 31, 1999.
Consolidated Statement of Capitalization at December 31, 2000 and December
31, 1999.
Consolidated Statement of Cash Flows for the year ended December
31, 2000, the year ended December 31, 1999, and the nine
months ended December 31, 1998.
Notes to Consolidated Financial Statements
2. Financial Statements Schedules
Consolidated Schedule of Valuation and Qualifying Accounts for the year ended
December 31, 2000, the year ended December 31, 1999, and the nine months ended
December 31, 1998.
All other schedules are omitted because they are not applicable or the required
information is shown in the financial statements or notes thereto.
3. Exhibits
Exhibits listed below which have been filed with the SEC pursuant to the
Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as
amended, and which were filed as noted below, are hereby incorporated by
reference and made a part of this report with the same effect as if filed
herewith.
3.1 Certificate of Incorporation of the Company effective April 16, 1998,
Amendment to Certificate of Incorporation of the Company effective May
26,1998, Amendment to Certificate of Incorporation of the Company
effective June 1, 1998, Amendment to the Certificate of Incorporation
of the Company effective April 7, 1999 and Amendment to the
Certificate of Incorporation of the Company effective May 20, 1999
(filed as Exhibit 3.1 to the Company's Form 10-Q for the quarterly
period ended June 30, 1999)
3.2 ByLaws of the Company In Effect on September 10, 1998, as amended
(filed as Exhibit 3.1 to the Company's Form 8-K/A, Amendment No. 2, on
September 29, 1998)
4.1 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 Form S-3 Registration
Statement No. 333-92003)
4.2 Form of Medium-Term Note issued in connection with the issuance of the
7 7/8% notes on February 1, 2000 (filed as Exhibit 4, to KeySpan Form
8-K on February 1, 2000)
4.3* Form of Medium-Term Note issued in connection with the issuance of the
6.9% notes on January 19, 2001.
4.4 Indenture, dated as of November 1, 2000, between KeySpan and the Chase
Manhattan Bank, as Trustee, with the respect to the issuance 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)
4.5 Form of Note issued in connection with the issuance of the 7.25% note
issued on November 20, 2000 (filed as Exhibit 4-b to KeySpan's Form
8-K on November 20, 2000)
4.6 Form of Note issued in connection with the issuance of the 7.625% note
issued on November 20, 2000 (filed as Exhibit 4-c to KeySpan's Form
8-K on November 20, 2000)
4.7 Form of Note issued in connection with the issuance of the 8.0% note
issued on November 20, 2000 (filed as Exhibit 4-d to KeySpan's Form
8-K on November 20, 2000)
4.8* Credit Agreement, dated as of September 22, 2000. among KeySpan, as
Borrower, the Several Lenders, Citibank, N.A. and ABN Amro Bank, N.V.
as Co-Documentation Agents, J.P. Morgan Securities Inc., as
Syndication Agent, and The Chase Manhattan Bank, as Administrative
Agent, for a $700,000,000 revolving credit loan.
4.9* Credit Agreement, dated as of October 30, 2000, among KeySpan, as
Borrower, the Several Lenders, Citibank, N.A., as Syndication Agent,
European American Bank, as Documentation Agent and The Chase Manhattan
Bank, as Administrative Agent, for a $700,000,000 revolving credit
loan.
4.10*Letter of Credit and Reimbursement Agreement, dated as of December 1,
200, by and between KeySpan Generation LLC and National Westminister
Bank PLC relating to the Electric Facilities Revenue Bonds ("EFRBs")
Series 1997A .
4.11-a Participation Agreements dated as of February 1, 1989, between
NYSERDA and The Brooklyn Union Gas Company relating to the Adjustable
Rate Gas Facilities Revenue Bonds ("GFRBs") Series 1989A and Series
1989B (filed as Exhibit 4 to The Brooklyn Union Gas Company Form 10-K
for the year ended September 30, 1989)
4.11-b Indenture of Trust, dated February 1, 1989, between NYSERDA and
Manufacturers Hanover Trust Company, as Trustee, relating to the
Adjustable Rate GFRBs Series 1989A and 1989B (filed as Exhibit 4 to
the Brooklyn Union Gas Company Form 10-K for the year ended September
30, 1989)
4.12-a Participation Agreement, dated as of July 1, 1991, between NYSERDA
and The Brooklyn Union Gas Company relating to the GFRBs Series 1991A
and 1991B (filed as Exhibit 4 to The Brooklyn Union Gas Company Form
10-K for the year ended September 30, 1991)
4.12-b Indenture of Trust, dated as of July 1, 1991, between NYSERDA and
Manufacturers Hanover Trust Company, as Trustee, relating to the GFRBs
Series 1991A and 1991B (filed as Exhibit 4 to The Brooklyn Union Gas
Company Form 10-K for the year ended September 30, 1991)
4.13-a First Supplemental Participation Agreement dated as of May 1, 1992
to Participation Agreement dated February 1, 1989 between NYSERDA and
The Brooklyn Union Gas Company relating to Adjustable Rate GFRBs,
Series 1989A & B (filed as Exhibit 4 to The Brooklyn Union Gas Company
Form 10-K for the year ended September 30, 1992)
4.13-b First Supplemental Trust Indenture dated as of May 1, 1992 to Trust
Indenture dated February 1, 1989 between NYSERDA and Manufacturers
Hanover
TrustCompany, as Trustee, relating to Adjustable Rate GFRBs, Series
1989A & B (filed as Exhibit 4 to The Brooklyn Union Gas Company Form
10-K for the year ended September 30, 1992)
4.14-a Participation Agreement, dated as of July 1, 1992, between NYSERDA
and The Brooklyn Union Gas Company relating to the GFRBs Series 1993A
and 1993B (filed as Exhibit 4 to The Brooklyn Union Gas Company Form
10-K for the year ended September 30, 1992)
4.14-b Indenture of Trust, dated as of July 1, 1992, between NYSERDA and
Chemical Bank, as Trustee, relating to the GFRBs Series 1993A and
1993B (filed as Exhibit 4 to The Brooklyn Union Gas Company Form 10-K
for the year ended September 30, 1992)
4.15-a First Supplemental Participation Agreement dated as of July 1, 1993
to Participation Agreement dated as of June 1, 1990, between NYSERDA
and The Brooklyn Union Gas Company relating to GFRBs Series C (filed
as Exhibit 4 to The Brooklyn Union Gas Company Form 10-K for the year
ended September 30, 1993)
4.15-b First Supplemental Trust Indenture dated as of July 1, 1993 to Trust
Indenture dated as of June 1, 1990 between NYSERDA and Chemical Bank,
as Trustee, relating to GFRBs Series C (filed as Exhibit 4 to The
Brooklyn Union Gas Company Form 10-K for the year ended September 30,
1993)
4.16-a Participation Agreement, dated July 15, 1993, between NYSERDA and
Chemical Bank as Trustee, relating to the GFRBs Series D-1 1993 and
Series D-2 1993 (filed as Exhibit 4 to The Brooklyn Union Gas Company
Form S-8 Registration Statement No. 33-66182)
4.16-b Indenture of Trust, dated July 15, 1993, between NYSERDA and
Chemical Bank as Trustee, relating to the GFRBs Series D-1 1993 and
D-2 1993 (filed as Exhibit 4 to The Brooklyn Union Gas Company Form
S-8 Registration Statement No. 33-66182)
4.17-a Participation Agreement, dated January 1, 1996, between NYSERDA and
The Brooklyn Union Gas Company relating to GFRBs Series 1996 (filed as
Exhibit 4 to The Brooklyn Union Gas Company Form 10-K for the year
ended September 30, 1996)
4.17-b Indenture of Trust, dated January 1, 1996, between NYSERDA and
Chemical Bank, as Trustee, relating to GFRBs Series 1996 (filed as
Exhibit 4 to The Brooklyn Union Gas Company Form 10-K for the year
ended September 30, 1996)
4.18-a Participation Agreement, dated as of January 1, 1997, between
NYSERDA and The Brooklyn Union Gas Company relating to GFRBs 1997
Series A
(filed as Exhibit 4 to KeySpan Energy Corporation Form 10-K for the
year ended September 30, 1997)
4.18-b Indenture of Trust, dated January 1, 1997, between NYSERDA and Chase
Manhattan Bank, as Trustee, relating to GFRBs 1997 Series A (filed as
Exhibit 4 to KeySpan Energy Corporation Form 10-K for the year ended
September 30, 1997)
4.19-a Participation Agreement dated as of December 1, 1997 by and between
NYSERDA and Long Island Lighting Company relating to the 1997 EFRBs,
Series A (filed as Exhibit 10(a) to KeySpan Form 10-Q for the
quarterly period ended September 30, 1998)
4.19-b Indenture of Trust dated as of December 1, 1997 by and between New
York State Energy Research and Development Authority (NYSERDA) and The
Chase Manhattan Bank, as Trustee, relating to the 1997 Electric
Facilities Revenue Bonds (EFRBs), Series A (filed as Exhibit 10(a) to
the Company's Form 10-Q for the quarterly period ended September 30,
1998)
4.20-a Participation Agreement, dated as of October 1, 1999, by and between
NYSERDA and KeySpan Generation LLC relating to the 1999 Pollution
Control Refunding Revenue Bonds, Series A (filed as Exhibit 4.10 to
KeySpan's Form 10-K for the year ended December 31, 1999)
4.20-b Trust Indenture, dated as of October 1, 1999, by and between New
York State Energy Research and Development Authority (NYSERDA) and The
Chase Manhattan Bank, as Trustee, relating to the 1999 Pollution
Control Refunding Revenue Bonds, Series A (filed as Exhibit 4.10 to
KeySpan's Form 10-K for the year ended December 31, 1999)
4.20-c First Supplemental Trust Indenture, dated as of January 1, 2000, by
and between New York State Energy Research and Development Authority
(NYSERDA) and The Chase Manhattan Bank, as Trustee, relating to the
GFRBs 1997 Series A (filed as Exhibit 4.11 to KeySpan's Form 10-K for
the year ended December 31, 1999)
4.21 Indenture dated as of December 1, 1989 between Boston Gas Company and
The Bank of New York, Trustee (Filed as Exhibit 4.2 to Boston Gas
Company's Form S-3 (File No. 33-31869)).
4.22 Agreement of Registration, Appointment and Acceptance dated as of
November 18, 1992 among Boston Gas Company, The Bank of New York as
Resigning Trustee, and The First National Bank of Boston as Successor
Trustee. (Filed as an exhibit to Boston Gas Company's S-3 Registration
S (File No. 33-31869))
4.23 Credit Agreement dated as of December 22, 1993 by and among Boston Gas
Company, Morgan Guaranty Trust Company of New York, National
Westminster Bank PLC, Shawmut Bank, N.A. and The First National Bank
of Boston. (Filed as Exhibit 10.17 to the Annual Report of Boston Gas
Company on Form 10-K for the year ended December 31, 1993)
4.24 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)
4.25 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)
4.26 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)
4.27 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)
4.28 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)
4.29 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)
4.30 Revolving Credit Agreement for Colonial Gas Company dated as of
September 12, 1997 (filed as Exhibit 4(e) to Colonial Gas Company's
Form 10-Q for the quarter ended September 30, 1997)
4.31 Revolving Credit Agreement between for Colonial Gas Company and
Massachusetts Fuel Inventory Trust dated as of September 12, 1997
(filed as Exhibit 4(f) to Colonial Gas Company's Form 10-Q for the
quarter ended September 30, 1997)
4.32 Trust Agreement dated as of June 22, 1990 between Colonial Gas Company
(as Trustor) and Shawmut Bank, N.A. (as Trustee) (filed as Exhibit
10(d) to Colonial Gas Company's Form 10-Q for the period ended June
30, 1990)
4.33 Gas Service, Inc. General and Refunding Mortgage Indenture, dated as
of June 30, 1987, as amended and supplemented by a First Supplemental
Indenture, dated as of October 1, 1988, and by a Second Supplemental
Indenture, dated as of August 31, 1989 (filed as Exhibit 4.1 to
EnergyNorth,
Inc.'s Form 10-K for the fiscal year ended September 30, 1989 (File
No. 0- 11035)
4.34 Third Supplemental Indenture, dated as of September 1, 1990, to Gas
Service, Inc. General and Refunding Mortgage Indenture, dated as of
June 30, 1987 (filed as Exhibit 4.2 to EnergyNorth, Inc.'s Form 10-K
for the fiscal year ended September 30, 1990 (File No. 0-11035)
4.35 Fourth Supplemental Indenture, dated as of January 10, 1992, to Gas
Service, Inc. General and Refunding Mortgage Indenture, dated as of
June 30, 1987 (filed as Exhibit 4.3 of EnergyNorth, Inc.'s Form 10-K
for the fiscal year ended September 30, 1992 (File No. 0-11035)
4.36 Fifth Supplemental Indenture, dated as of February 1, 1995, to Gas
Service, Inc. General and Refunding Mortgage Indenture, dated as of
June 30, 1987 (filed as Exhibit 4.4 to EnergyNorth, Inc.'s Form 10-K
for the fiscal year ended September 30, 1996 (File No. 1-11441)
4.37 Sixth Supplemental Indenture, dated as of September 15, 1997, to Gas
Service, Inc. General and Refunding Mortgage Indenture, dated as of
June 30, 1987 (filed as Exhibit 4.5 to EnergyNorth Natural Gas, Inc.'s
Amendment No. 1 to Registration Statement on Form S-1, No. 333-32949,
dated September 10, 1997)
10.1 Agreement and Plan of Merger dated November 4, 1999, between the
KeySpan, Eastern Enterprises and ACJ Acquisition LLC (filed as Exhibit
2 to KeySpan Form 8-K on November 5, 1999)
10.2 Amendment No. 1 to Agreement and Plan of Merger, dated January 26,
2000, between the KeySpan, Eastern Enterprises and ACJ Acquisition LLC
10.3 Agreement and Plan of Reorganization dated as of November 4,
1999,Eastern Enterprises, EE Acquisition Company, Inc. and
EnergyNorth, Inc., including Amendment No. 1 dated November 4, 1999
(filed as Exhibit 2.1 to Eastern's Form S-4 Registration Statement No.
333-95693)
10.4 Agreement and Plan of Merger dated as of June 26, 1997 by and among BL
Holding Corp., Long Island Lighting Company, Long Island Power
Authority and LIPA Acquisition Corp. (filed as Annex D to Registration
Statement on Form S-4, No. 333-30353 on June 30, 1997)
10.5 Agreement of Lease between Forest City Jay Street Associates and The
Brooklyn Union Gas KeySpan dated September 15, 1988 (filed as an
exhibit to The Brooklyn Union Gas KeySpan Form 10-K for the year ended
September 30, 1996)
10.6 Stipulation of Settlement of federal Racketeer Influenced and Corrupt
Organizations Act Class Action and False Claims Action dated as of
February 27, 1989 among the attorneys for Long Island Lighting
KeySpan, the ratepayer class, the United States of America and the
individual defendants named therein (filed as an exhibit to Long
Island Lighting Company's Form 10-K for the year ended December 31,
1988)
10.7 Management Services Agreement between Long Island Power Authority and
Long Island Lighting Company dated as of June 26, 1997 (filed as Annex
D to Registration Statement on Form S-4, No. 333-30353, on June 30,
1997)
10.8 Power Supply Agreement between Long Island Lighting Company and Long
Island Power Authority dated as of June 26, 1997 (filed as Annex D to
Registration Statement on Form S-4, No. 333-30353, on June 30, 1997)
10.9 Energy Management Agreement between Long Island Lighting Company and
Long Island Power Authority dated as of June 26, 1997 (filed as Annex
D to Registration Statement on Form S-4, No. 333-30353, on June 30,
1997)
10.10Amended and Restated Agreement and Plan of Exchange and Merger dated
June 26, 1997 between The Brooklyn Union Gas Company and Long Island
Lighting Company dated as of June 26, 1997 (filed as Annex A to
Registration Statement on Form S-4, No. 333-30353, on June 30, 1997)
10.11Amendment, 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)
10.12-a* Amendment dated as of February 24, 2000, to the Employment
Agreement dated September 10, 1998, between KeySpan and Robert B.
Catell
10.12-b Employment Agreement dated September 10, 1998, between KeySpan and
Robert B. Catell (filed as Exhibit (10)(b) to KeySpan's Form 10-Q for
the quarterly period ended September 30, 1998)
10.13* Employment Agreement effective as of March 1, 2001, between KeySpan
and Craig G. Matthews
10.14Employment Agreement effective as of July 29, 1999, between KeySpan
and Gerald Luterman (filed as Exhibit 10.10 to KeySpan's Form 10-K for
the year ended December 31, 1999).
10.15* Employment Agreement dated as of November 8, 2000, between KeySpan
and Chester R. Messer.
10.16Change of Control Agreement dated as of September 22, 1999, between
Eastern, Boston Gas Company and Chester R. Messer (filed as Exhibit
10.11.5 to Eastern's Form 10-Q for the quarterly period ended
September 30, 1999, File No. 1-2297).
10.17* Employment Agreement dated as of November 8, 2000 between KeySpan
and Joseph A. Bodanza.
10.18* Change of Control Agreement dated as of September 22, 1999,
between Eastern, Boston Gas Company and Joseph A. Bodanza
10.19* Directors' Deferred Compensation Plan dated as of December 21, 2000
10.20* 2000 Corporate Annual Incentive Compensation and Gainsharing Plan
effective January 1, 2000
10.21Senior Executive Change of Control Severance Plan effective as of
October 30, 1998 (filed as Exhibit 10.20 to KeySpan Form 10-K for the
year ended December 31, 1998)
10.22Long Term Performance Incentive Compensation Plan effective May 20,
1999 (filed as Exhibit 10.3 to KeySpan's Form 10-Q for the quarterly
period ended June 30, 1999).
10.23Rights Agreement dated March 30, 1999, between the KeySpan and the
Rights Agent (filed as Exhibit 4 to KeySpan Form 8-K, on March 30,
1999
10.24Generating Plant and Gas Turbine Asset Purchase and Sale Agreement
for Ravenswood for Ravenswood Generating Plants and Gas Turbines dated
January 28, 1999, between the KeySpan and Consolidated Edison Company
of New York, Inc. (filed as Exhibit 10(a) to KeySpan Form 10-Q for the
quarterly period ended March 31, 1999)
10.25Lease Agreement dated June 9, 1999, between KeySpan-Ravenswood, Inc.
and LIC Funding, Limited Partnership (filed as Exhibit 10.2 to KeySpan
Form 10-Q for the quarterly period ended June 30, 1999)
10.26Guaranty dated June 9, 1999, from the KeySpan in favor of LIC
Funding, Limited Partnership (filed as Exhibit 10.1 to KeySpan Form
10-Q for the quarterly period ended June 30, 1999)
10.27* Energy Management Agreement dated April 1, 2000, by and between
Keyspan Energy Trading Services LLC and Coral Energy Holding, L.P.
10.28Redacted Gas Resource Portfolio Management and Gas Sales Agreement
between Boston Gas Company, Colonial Gas Company, Essex Gas Company
(collectively, KEDNE) and El Paso Energy Marketing Company dated as of
September 14, 1999, as amended (filed as Exhibit 10.1 to Eastern
Enterprises Form 10-K for the period ended December 31, 1999)
10.29Indenture, dated as of March 2, 1998, between The Houston Exploration
Company and The Bank of New York, as Trustee, with respect to the 8
5/8% Senior Subordinated Notes Due 2008 (including form of 8 5/8%
Senior Subordinated Note Due 2008) (filed as Exhibit 4.1 to The
Houston Exploration Company's Registration Statement on Form S-4 (No.
333-50235))
10.30Subordinated Loan Agreement dated November 30, 1998 between The
Houston Exploration Company and MarketSpan Corporation d/b/a KeySpan
Energy Corporation (filed as Exhibit 10.30 to The Houston Exploration
Company's Annual Report on Form 10-K for the year ended December 31,
1998).
10.31Subordination Agreement dated November 25, 1998 entered into and
among MarketSpan Corporation d/b/a KeySpan Energy Corporation, The
Houston Exploration Company and Chase Bank of Texas, National
Association (filed as Exhibit 10.31 to The Houston Exploration
Company's Annual Report on Form 10-K for the year ended December 31,
1998 (File No. 001-11899)).
10.32First Amendment to Subordinated Loan Agreement and Promissory Note
between KeySpan Corporation and The Houston Exploration Company dated
effective as of October 27, 1999 (filed as Exhibit 10.14 to KeySpan's
Form 10-K for the year ended December 31, 1999).
10.33Restated Exploration Agreement between The Houston Exploration
Company and KeySpan Exploration and Production, L.L.C., dated June 30,
2000, (filed as Exhibit 10.1 to The Houston Exploration Company's
Quarterly Report on Form 10-Q for the quarter ended September 30,
2000, File No. 001-11899).
10.34-a First Amendment and Supplement to Amended and Restated Credit
Agreement dated May 4, 1999 by and among The Houston Exploration
Company and Chase Bank of Texas, National Association, as agent,
(filed as Exhibit 10.1 to The Houston Exploration Company's Quarterly
Report on Form 10-Q for the quarter ended June 30, 1999 (File No.
001-11899)).
10.34-b Second Amendment to Amended and Restated Credit Agreement between
The Houston Exploration Company and Chase Bank of Texas, National
Association, as agent, dated October 6, 1999, (filed as Exhibit 10.32
to The Houston Exploration Company's Quarterly Report on Form 10-Q for
the quarter ended September 30, 1999 (File No. 001-11899)).
10.34-c Third Amendment and Supplement to Amended and Restated Credit
Agreement between The Houston Exploration Company and Chase Bank of
Texas, National Association, as agent, dated December 9, 1999 (filed
as Exhibit 10.20 to KeySpan's Form 10-K for the year ended December
31, 1999)
10.35Indenture between Midland Enterprises and State Street Bank and Trust
Company dated as of April 2, 1990 (filed as Exhibit 2.2 to Midland
Enterprises Registration Statement No 333-21120)
10.36Indenture between Midland Enterprises and The Chase Manhattan Bank
dated as of September 29, 1998 (filed as Exhibit 4.2 to Midland
Enterprises Registration Statement (File No. 333-61137)
21* Subsidiaries of the Registrant
23.1* Consent of Arthur Andersen LLP, Independent Auditors
24.1*Power of Attorney executed by Lilyan H. Affinito on February 6, 2001;
which is substantially the same as Powers of Attorney made by Robert
B. Catell on February 12, 2001; Andrea S. Christensen on February 29,
2001; Howard R. Curd on February 27, 2001; Richard N. Daniel on
February 29, 2001; Donald H. Elliott on February 11, 2001, Alan H.
Fishman January 29, 2001, Vicki L. Fuller on February 16, 2001; J.
Atwood Ives on January 30, 2001; James R. Jones on February 1, 2001;
James L. Larocca on January 30, 2001; Craig G. Matthews on March 1,
2001; Stephen W. McKessy on January 31, 2001; Edward D. Miller on
February 8, 2001 and James Q. Riordan February 1, 2001.
24.2*Certified copy of the Resolution of the Board of Directors
authorizing signatures pursuant to power of attorney
* Filed herewith
4. Reports on Form 8-K
KeySpan filed Reports on Form 8-K on October 6, 2000, November 9, 2000, November
20, 2000, November 21, 2000, December 11, 2000 and January 25, 2001.
In our Report on Form 8-K, dated October 6, 2000, we filed historical financial
statements of Eastern for the purpose of incorporating such information.
In our Report on Form 8-K, dated November 9, 2000, we filed a copy of the press
release reporting the closing of our transaction with Eastern and EnergyNorth.
On November 20, 2000, we filed a Report on Form 8-K regarding our issuance of
$1.65 billion aggregate principal amount of notes. Additionally, on November 21,
2000, we filed a Report on Form 8- K to further describe the acquisition of
Eastern and EnergyNorth and to incorporate Eastern's Annual Report on Form 10-K,
for the period ended December 31, 1999.
On December 11, 2000, we filed a Report on Form 10-K, to include a press release
disclosing our expectations on future earnings. On January 25, 2001, we filed
another Report on Form 8- K, disclosing our consolidated earning for the fiscal
year ended December 31, 2000.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, as amended, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized.
KEYSPAN CORPORATION
March 30, 2001 By: /S/Gerald Luterman
----------------------
Gerald Luterman
Senior Vice President and
Chief Financial Officer
March 30, 2001 By: /S/Ronald S. Jendras
--------------------
Ronald S. Jendras
Vice President, Controller and
Chief Accounting Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated on March 30, 2001.
* Chairman of the Board and Chief Executive Officer
________________________ (Principal executive officer)
Robert B. Catell
Senior Vice-President and Chief Financial Officer
(Principal financial officer)
/S/Gerald Luterman
------------------
Gerald Luterman
Vice President, Controller and Chief Accounting Officer
/S/Ronald S. Jendras Principal accounting officer)
--------------------
Ronald S. Jendras
*
------------------------
Lilyan H. Affinito Director
*
------------------------
Andrea S. Christensen Director
*
------------------------
Howard R. Curd Director
*
------------------------
Richard N. Daniel Director
*
------------------------
Donald H. Elliott Director
*
________________________ Director
Alan H. Fishman
*
________________________ Director
Vicki L. Fuller
*
________________________ Director
J. Atwood Ives
*
________________________ Director
James R. Jones
*
________________________ Director
James L. Larocca
*
________________________ Director
Craig G. Matthews
*
________________________ Director
Stephen W. McKessy
*
________________________ Director
Edward D. Miller
*
________________________ Director
James Q. Riordan
By:/s/ Gerald Luterman
Attorney-in-Fact
* Such signature has been affixed pursuant to a Power of Attorney filed as an
exhibit hereto and incorporated herein by reference thereto.