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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[ ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934
OR
[X] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from April 1, 1998 to December 31, 1998
Commission File Number 1-14161
MARKETSPAN CORPORATION
(Exact name of registrant as specified in its charter)
NEW YORK 11-3431358
(State or other jurisdiction of incorporation or (I.R.S. employer
organization) identification no.)
175 EAST OLD COUNTRY ROAD, HICKSVILLE, NEW YORK 11801
ONE METROTECH CENTER, BROOKLYN, NEW YORK 11201
(Address of principal executive offices) (Zip code)
(516) 755-6650 (HICKSVILLE)
(718) 403-1000 (BROOKLYN)
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
Title of each class Name of each exchange on which
registered
Common Stock, $.01 par value New York Stock Exchange
Pacific Stock Exchange
Series AA Preferred Stock, $25 par value New York Stock Exchange
Pacific Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
None
(Title of class)
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes. X No.
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. |_|
As of March 22, 1999, the aggregate market value of the common stock
held by non-affiliates (139,173,954 shares) of the registrant was $3,601,126,073
(based on the closing price, on such date, of $25.88 per share).
As of March 22, 1999, there were 142,868,154 shares of common stock,
$.01 par value, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Proxy Statement dated on or about April 7, 1999 is incorporated by reference
into Part III hereof.
MARKETSPAN CORPORATION
D/B/A KEYSPAN ENERGY
INDEX TO FORM 10-K
Page
PART I
Item 1. Business................................................................ 1
Item 2. Properties.............................................................. 29
Item 3. Legal Proceedings....................................................... 29
Item 4. Submission of Matters to a Vote of Security Holders..................... 31
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters... 31
Item 6. Selected Financial Data................................................. 32
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations........................................................... 33
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.............. 53
Item 8. Financial Statements and Supplementary Data............................. 55
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure.............................................................. 101
PART III
Item 10. Directors and Executive Officers of the Registrant...................... 101
Item 11. Executive Compensation.................................................. 101
Item 12. Security Ownership of Certain Beneficial Owners and Management.......... 101
Item 13. Certain Relationships and Related Transactions.......................... 101
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K......... 102
PART I
ITEM 1. BUSINESS
OVERVIEW
KeySpan Energy ("KeySpan" or the "Company") provides a range of
energy-related services through operations and investments in selected areas of
the energy industry. The Company is the fourth largest gas utility in the United
States with approximately 1.6 million customers in the New York City
metropolitan area. The Company competes in five principal lines of business,
including natural gas distribution, electric services, gas exploration and
production, energy-related investments, and energy-related services.
The Company was formed to facilitate the combination (the
"Combination"), completed on May 28, 1998, of KeySpan Energy Corporation ("KSE")
and its principal subsidiary The Brooklyn Union Gas Company ("Brooklyn Union")
and the non-nuclear electric generation and natural gas distribution businesses
of the Long Island Lighting Company ("LILCO"). To effect the Combination, all of
the assets used by LILCO in connection with its gas distribution business, its
non-nuclear electric generation business and the assets common to its prior
operations (the "Transferred Assets") were transferred to the Company. The Long
Island Power Authority ("LIPA") then acquired all of the common stock of LILCO
for approximately $2.5 billion in cash and the direct or indirect assumption of
certain liabilities. The Company sold to the former holders of LILCO common
stock, shares of the Company's common stock and then acquired KSE by merger with
a wholly-owned subsidiary of the Company in exchange for shares of the Company's
common stock. Upon completion of these transactions, former LILCO and KSE
shareholders owned approximately 68% and 32% of the Company's common stock,
respectively.
The assets of LILCO not transferred to the Company (the "Retained
Assets") were retained by LIPA and primarily consist of LILCO's electric
transmission and distribution system located on Long Island (the "T&D System"),
its 18% ownership interest in Nine Mile Point Nuclear Power Station, Unit 2
("NMP2"), located in upstate New York, and certain of LILCO's regulatory assets
and liabilities associated with its electric business.
The Company was organized under New York law in 1998. Brooklyn Union
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 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.
As used herein, the "Company" or "KeySpan" refers to MarketSpan
Corporation d/b/a KeySpan Energy ("KeySpan Energy"), Brooklyn Union and KeySpan
Gas East Corporation d/b/a Brooklyn Union of Long Island ("Brooklyn Union of
Long Island"), its two principal gas distribution subsidiaries, and its other
subsidiaries, individually and in the aggregate. In 1998, the Company 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 that LILCO is deemed to be the acquiring company
in the Combination for financial reporting purposes. Unless otherwise specified,
other information contained in Part I hereof has been compiled on a combined
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basis ("Combined Company Basis") to aggregate the information shown for both KSE
and LILCO and is presented for the twelve month periods ended December 31, 1998,
1997 and 1996, as indicated. Additional information about the Company's industry
segments is contained in "Note 10. Business Segments" of the Notes to the
Consolidated Financial Statements 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 which 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 Risk"
relating to the Company's 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: 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 the Company to successfully reduce
its cost structure; the successful integration of the Company's subsidiaries;
the degree to which the Company develops unregulated business ventures; the
ability of the Company to identify and make complementary acquisitions, as well
as the successful integration of such acquisitions; inflationary trends and
interest rates; the ability of the Company and its significant vendors to modify
their computer software, hardware and databases to accommodate the year 2000;
and other risks detailed from time to time in other reports and other documents
filed by the Company and its predecessors with the Securities and Exchange
Commission (the "SEC"). For any of these statements, the Company 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 Risk" contained in the Annual Report on Form 10-K.
The Company'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.
INDUSTRY AND COMPETITION
The electric and natural gas sectors of the regulated energy industry
are undergoing significant changes, as market forces are replacing or
supplementing rate regulation as a means of controlling prices for natural gas
and electricity. The exposure of utilities to competition places pressures on
them to maintain market share and profits and manage the costs of providing
services as their customers gain access to lower cost supplies of natural gas
and electricity. Competition also presents utilities with greater opportunities
to manage the cost of their natural gas and electric supplies, to earn
unregulated profits on energy sales and to expand their business activities.
2
Historically, government regulation served both to control prices in
the natural gas and electric sectors of the energy industry and to substantially
shield industry participants from competition. The natural gas sector was
segmented into three regulated parts: production; interstate transportation; and
franchised retail sales and local distribution. The electric sector featured
vertically integrated utilities providing generation, transmission and
distribution services for their franchised service territories. Under
traditional rate regulation, utilities were provided the opportunity to earn a
fair, but regulated, return on invested capital in exchange for a commitment to
serve all customers within a franchised service territory. An extensive and
complex regime for the regulation of public utility companies and public utility
holding companies limited natural gas and electric utilities' opportunities for
geographic expansion and business diversification.
Between the 1930's and the late 1970's, federal and state energy
regulatory policies remained relatively stable, and the structure of the
regulated energy industry changed little. However, after the energy crises in
the 1970's, new legislation and changes in regulatory policy set in motion
competitive forces that are reshaping the energy industry, dramatically
increasing business opportunities for natural gas and electric companies.
Beginning in 1978 with federal legislation that authorized the phased
deregulation of wellhead natural gas prices and the establishment of unregulated
electric generation companies, competition has been increasingly introduced into
segments of the regulated energy industry. To foster competition, federal
regulators adopted "open access" rules which required interstate natural gas
pipelines and electric transmission systems to "unbundle" retail sales, I.E.,
the sale of gas or electricity, from transportation and transmission services.
Open access also required interstate gas pipelines and electric utilities, for
the first time, to provide transportation and transmission service on a
non-discriminatory basis to all qualified customers. Recent initiatives would
also permit market forces, rather than regulation, to establish rates charged
under short-term contracts for interstate natural gas transportation and to
determine the allocation of increased electricity costs that result when
electric transmission constraints prevent lower priced electricity from reaching
electric customers. By enabling natural gas producers and electric generators to
reach new markets, open access policies led to intensified competition in
wholesale markets and began to alter the geographic character of the industry.
No longer typified by isolated local companies, the natural gas and electric
sectors in many parts of the country today include a growing number of firms
with regional, national and international dimensions.
Parallel changes in the regulation of retail electric and gas markets
are being implemented by many state public utility commissions, including the
Public Service Commission of the State of New York ("NYPSC"). On a
state-by-state basis, initially in the Northeast, Mid-Atlantic and California,
and now spreading to other regions, local franchised utilities are being
required to separate their marketing and retail sales businesses from the
physical distribution of natural gas and electricity through pipes and wires.
Just as at the federal level, distribution services are increasingly required to
be unbundled from retail sales, and made available on a non-discriminatory open
access basis to all qualified retail customers. Retail natural gas and
electricity marketers are being permitted to compete for energy customers in
what were formerly exclusive service territories of electric and natural gas
utilities. However, natural gas and electric utilities are likely to remain
exclusive providers of unbundled distribution services through pipes and wires,
and may remain obligated to continue to sell natural gas or electricity to
customers who do not select other suppliers.
3
In New York State, large-volume retail customers have been able to
purchase natural gas supplies directly from non-utility vendors for more than
ten years, while direct sales to aggregations of small customers have been
permitted since 1996. New York regulators are commencing new initiatives to
further enhance retail competition in the state. Similarly, the NYPSC has been
encouraging the development of retail competition in the electric sector in New
York. In the past two years, electric utilities have begun to unbundle electric
sales from retail distribution services, open their franchised territories to
competitors, transfer control over their transmission systems to an independent
system operator, and divest many of their generating plants.
The introduction of competition for retail electricity sales may
threaten the ability of electric utilities to recover their past investments in
electric generating plants (and, in some cases, related transmission facilities)
to the extent that the cost of producing electricity from those generating
plants exceeds the competitive market price for electricity. In consideration
for opening franchise service territories to retail competition, many electric
utilities are being permitted to recover potentially "stranded" investments in
electric generation and associated transmission through charges to all customers
receiving distribution and transmission services. In many cases, the market
value of electric generating plants and the amount of stranded investment is
being determined through the divestiture of electric generating plants in
well-publicized auctions. The sale of generating plants and recovery of stranded
costs (to the extent they remain after divestiture) is providing electric
utilities with substantial cash infusions which, in some cases, are being used
to repurchase stock or to finance acquisition of other energy assets, often in
different regions of the country or internationally. Many utilities are
attempting to diversify their lines of business, while some are choosing to
concentrate on one or two industry segments, such as natural gas or electric
distribution or electric generation. Several New York investor-owned utilities
have commenced the sale of their non-nuclear generating plants. The Company's
pending purchase of the Ravenswood generating plant, as discussed below, results
from a plan under which Consolidated Edison Company of New York, Inc. ("Con
Edison") is divesting a substantial portion of its non-nuclear generating
capacity. See "The Company - Electric Services."
A significant number of natural gas and electric utilities have
reacted to the changing structure of the regulated 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 electric and natural gas operations. The
Combination and related transactions which resulted in the formation of the
Company shares many of these attributes.
The transformation of the energy industry is an ongoing process.
Larger regional, national and international companies are being formed through
acquisitions and mergers. The remaining legal barriers to interregional natural
gas and electric distribution companies, which have been relaxed as the result
of regulatory decisions, are the subject of legislative proposals calling for
repeal or substantial modifications. The advent of industry restructuring has
meant that regional, national and international companies are increasingly
offering energy consumers a wide array of choices as to the supply, type,
quality and cost of natural gas and electric services. For the Company, industry
restructuring means increased opportunities to enter new markets and pressures
to manage its costs of doing business.
4
BUSINESS STRATEGY
The Company seeks to become a premier energy company with operations
focused in the Northeastern United States, the Gulf of Mexico and Western
Canadian supply basins as well as selected international areas where the Company
identifies opportunities for growth in those energy-related lines of business in
which the Company has developed recognized expertise. The Company intends to
grow through acquisitions and selected energy-related investments; by expanding
its gas distribution business, particularly on Long Island; by emphasizing
superior customer service; and by taking advantage of the increasing trend
towards deregulation and competition to offer an expanded array of services to
its customers.
Key elements of the Company's business strategy include:
ENERGY-RELATED INVESTMENTS. In recent years, the Company has made
a number of acquisitions and energy-related investments designed to
enhance its presence in the Northeastern United States. The Combination
transformed the Company into the leading natural gas company in the
Northeast, with approximately 1.6 million gas customers in two
contiguous gas distribution service territories. The Combination also
gave the Company one of the largest power generation capabilities in the
region, with over 4,000 megawatts of generation capacity. Subsequent to
December 31, 1998, the Company entered into a definitive agreement,
subject to regulatory approvals, to acquire a 2,168 megawatt electric
generating facility in New York City from Con Edison. Upon consummation
of that transaction, the Company's power generation capacity will
approximate 6,200 megawatts. Consistent with the Company's long-standing
investment in the Iroquois pipeline, the Company recently acquired a 25%
interest in the proposed Cross Bay pipeline, which will transport gas
from interstate pipelines in New Jersey to New York and Long Island. In
addition, the Company has expanded the business of its unregulated
energy services operations, through the acquisition of Philip Fritze and
Sons, one of the largest heating, ventilation and air conditioning
contractors in New Jersey.
The Company has also made significant investments beyond its core
market area. In 1998, for example, the Company acquired a 50% interest
in certain midstream natural gas assets of Gulf Canada Resources
Limited, creating a partnership known as Gulf Midstream Services. The
Company also purchased an additional 25.5% interest in Premier Transco
Ltd. (resulting in an aggregate 50% interest), which transports natural
gas through an 84-mile pipeline from southwest Scotland to Northern
Ireland.
These acquisitions and investments reflect the Company's
commitment to enhancing its presence as an energy company focused
primarily on the Northeastern United States, with additional
complementary interests in the Gulf of Mexico and Western Canadian
supply basins, as well as Northern Ireland. The Company anticipates that
it will continue to target other acquisitions and investments that also
provide it with opportunities to increase its penetration of selected
energy markets in those core geographic areas.
5
EXPANDED GAS DISTRIBUTION SERVICES. The Company has achieved a
high degree of penetration in its Brooklyn Union service territory, with
approximately 79% of all one-and two-family homes currently using
natural gas for space heating. In contrast, only 30% of one-and
two-family homes in the Brooklyn Union of Long Island service territory
currently use natural gas for space heating. The Company believes there
is significant opportunity for increased penetration of the Long Island
service territory and intends to make capital expenditures to expand its
gas distribution infrastructure in order to support long-term growth. In
addition, the Company expects to focus marketing efforts throughout both
service territories. Examples of such marketing efforts include efforts
to convert customers from oil to gas heat and to target new
construction, small to medium commercial businesses and large volume
dual-fuel customers.
SUPERIOR CUSTOMER SERVICE. The Company's utility operations have
an outstanding reputation for customer service and have received
consistently excellent marks for customer loyalty and satisfaction, as
measured by independent customer-satisfaction specialists. In 1998, the
Company was the recipient of the Emergency Response Award of the Edison
Electric Institute, which honored the Company for restoring electric
power for LIPA after a severe thunderstorm on Long Island last
September. Similarly, Brooklyn Union was awarded the 1998 Brand Keys
Customer Loyalty Award as the U.S. energy provider that had achieved the
highest level of success in anticipating and exceeding customer
expectations. The Company intends to continue to emphasize superior
customer service, both to differentiate itself from competitors as
markets become increasingly deregulated and to take advantage of
cross-selling opportunities available in complementary energy-related
services such as appliance repair and energy system installation and
management.
EXPANDED SERVICES. With its strong market presence in the
metropolitan New York City area, the Company believes it is
well-positioned to provide customers with an expanding array of
energy-related services. In recent years, the Company has begun to offer
gas and electric marketing services throughout New York, Connecticut,
New Jersey, Maryland, Pennsylvania and Ohio and appliance repair and
related services and energy management services for residential,
commercial and industrial customers throughout the metropolitan New York
City area. The Company believes that continuing trends towards
deregulation and competition, coupled with growth in its customer base,
will afford it opportunities to expand those services both within and
outside its traditional service territories. The Company also owns a
250-mile fiber optic telecommunications network on Long Island and is
currently exploring various business opportunities to take commercial
advantage of that network.
THE COMPANY
GAS DISTRIBUTION
OVERVIEW
The Company sells, distributes and transports natural gas in two
separate, but contiguous service territories of approximately 1,417 square miles
in the aggregate in the New York City metropolitan area. The Company owns and
6
operates gas distribution, transmission and storage systems that consist of
approximately 10,036 miles of distribution pipelines, 578 miles of transmission
pipelines and two gas storage facilities. The Company serves approximately 1.6
million customers, of which approximately 1.5 million, or 94%, are residential.
Gas is offered for sale to residential customers on a "firm" basis, and to
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. The Company also participates in the 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 the
Company's service territories, by connecting to the Company's facilities or one
of its transporter's facilities, at a point of delivery agreed to by the Company
and the customer. The Company purchases its natural gas for sale to its
customers under long-term supply contracts and short-term spot contracts. Such
gas is transported under both firm and interruptible transportation contracts.
In addition, the Company has commitments for the provision of gas storage
capability and peaking supplies.
During 1998, on a Combined Company Basis, gas revenues were $1.760
billion, or 54% of the Company's revenues, and gas operating income was $218.8
million, excluding special charges related to the Combination.
The gas operations of the Company 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. However, the Company's gas utility
tariffs contain weather normalization adjustments that provide for recovery from
or refund to firm customers of material shortfalls or excesses of firm net
revenues (revenues less applicable gas costs, if any) during a heating season
due to variations from normal weather. See "Regulation and Rate Matters."
SALES AND DISTRIBUTION
The Company is the fourth largest gas distribution company in the
United States, providing, through its gas distribution subsidiaries, natural gas
sales and transportation services to customers in the New York City boroughs of
Brooklyn, Queens and Staten Island and the Long Island counties of Nassau and
Suffolk.
7
Gas sales and revenues for 1998 on a Combined Company Basis by class
of customer are set forth below:
Sales Revenues Revenues
Customer (MDTH) (thousands of (% of Total)
$)
- --------------------------------------------- ----------- ---------------- ---------------
FIRM
Residential house heating................ 95,821 $ 971,987 55.22%
Residential (other than house heating)... 10,176 199,944 11.36
Temperature-Controlled heating........... 30,899 128,703 7.31
Commercial/Industrial.................... 28,434 245,005 13.92
----------- ---------------- ---------------
Total Firm........................... 165,330 1,545,639 87.80
FIRM TRANSPORTATION...................... 13,974 60,540 3.44
----------- ---------------- ---------------
Total Firm Gas Sales and Transportation 179,304 1,606,179 91.24
INTERRUPTIBLE............................ 11,861 40,276 2.29
OFF-SYSTEM SALES......................... 24,465 59,556 3.38
TRANSPORTATION........................... 29,156 18,289 1.04
----------- ---------------- ---------------
Total Gas Sales and Transportation.... 244,786 1,724,300 97.95
Other Retail Services.................... N/A 36,020 2.05
=========== ================ ===============
Total sales and revenues*............. 244,786 $1,760,320 100%
=========== ================ ===============
- -----------------------
*Excludes lost, unaccounted for and interdepartmental gas.
Set forth below is information, on a Combined Company Basis,
concerning certain operating statistics applicable to the Company's gas sales
and distribution business:
1998 1997 1996
-------------- -------------- -------------
Revenues ($000)........................... 1,760,320 1,991,793 2,073,851
Net Income ($000)......................... 133,685* 134,403 119,639
Firm Gas Sales and Transportation (MDTH).. 179,304 203,587 202,377
Other Deliveries (MDTH)................... 65,482 73,132 59,139
Heating customers......................... 665,465 657,433 651,750
Degree Days, % cooler (warmer) than normal (17.5) 0.2 4.8
Capital Expenditures...................... 181,700 178,651 190,403
- -----------------------
*Excludes special charges and tax benefits associated with the Combination.
The Company sells gas to its firm gas customers at the Company's cost
for such gas, plus a charge designed to recover the costs of distribution
(including a return of and a return on invested capital). The Company shares
with its firm gas customers net revenues (operating revenues less the cost of
gas purchased for resale) from off-system sales and, in addition, Brooklyn Union
of Long Island credits its firm gas customers all net revenues from
interruptible gas sales, thereby reducing its rates to these firm customers.
All of the Company's retail gas customers became eligible in 1996 to
purchase gas directly from suppliers other than the Company's gas utility
subsidiaries. At December 31, 1998, approximately 32,900 residential, commercial
and industrial customers, with annual requirements of approximately 19,500 MDTH,
or 10% of the Company's annual firm gas system requirements, purchased their gas
supply from sources other than the Company. If a customer decides to purchase
gas from another supplier, the supplier obtains the gas and transports it to the
Company's distribution system. The Company then delivers the gas to the
customer's premises through the Company's system of distribution mains and
service lines. In addition to delivering gas that customers purchase from other
suppliers, the Company has been providing metering, billing and other services
8
for aggregate rates that are comparable to the distribution charge reflected in
otherwise applicable sales rates to supply comparable customers.
On a Combined Company Basis, actual firm gas sales and transportation
quantities from gas distribution operations in 1998 were 179,304 MDTH compared
to 203,587 MDTH in 1997 and 202,377 MDTH in 1996. (An MDTH is 10,000 therms and
reflects the heating content of approximately one million cubic feet of gas. A
therm reflects the heating content of approximately 100 cubic feet of gas.)
These major variations in quantities are primarily due to weather. Measured in
annual degree days, weather was 17.5% warmer than normal in 1998, normal in 1997
and 4.8% colder than normal in 1996. After normalizing for weather, firm volumes
in 1998 were approximately the same as 1997.
On a Combined Company Basis, on-system interruptible volumes,
off-system sales (sales made to customers outside of the Company's service
territories) and related transportation in 1998 were 65,482 MDTH compared to
73,132 MDTH in 1997 and 59,139 MDTH in 1996. The decrease in total gas
throughput during 1998 reflects the effects of warmer weather and the fact that
Brooklyn Union discontinued its off-system sales program beginning April 1, 1998
and replaced it with a management agreement with Enron Capital and Trade
Resources Corp. and its parent company, Enron Corp. (collectively, "Enron"), in
which Enron pays the Company a fixed fee in exchange for the right granted Enron
to earn revenues based upon its management of Brooklyn Union's gas supply
requirements, storage arrangements, and off-system capacity.
During 1998, the Company continued to grow in its existing service
territories and to expand into new markets. In the Company's service area of the
New York City boroughs of Brooklyn, Queens and Staten Island, approximately 79%
of one- and two- family homes currently use gas for space heating, while
approximately 48% of the multi-family market and 63% of the commercial market
use gas for space heating. In these areas, the Company intends to seek growth
with an aggressive marketing effort designed to encourage conversions of
residential and multi-family homes and businesses from fuel oil to natural gas
heating. In the Company's service area of the Long Island counties of Nassau and
Suffolk and the Rockaway peninsula of Queens County, approximately 30% of one-
and two-family homes currently use natural gas for space heating, while
approximately 17% of the multi-family market and 57% of the commercial market
use gas for space heating. In these service areas, the Company will seek growth
through the expansion of its distribution system as well as through the
conversion of residential homes and the pursuit of opportunities to grow
multi-family, industrial and commercial markets. The Company also offers special
area development and incentive gas rates to multi-family, commercial and
industrial businesses that move to or expand operations in designated areas of
the Company's service territories.
SUPPLY AND STORAGE
The Company has contracts for the purchase of firm long-term
transportation and storage services. The Company's 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 the Company's 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
9
marketers and then contract with the Company for local transportation, balancing
and other unbundled services. Since these customers are no longer reliant on the
Company for sales service, the quantity of gas that the Company must obtain to
meet remaining sales customers' requirements has been reduced. This trend is
likely to continue as state regulators implement policies designed to encourage
customers to purchase their gas from suppliers other than the traditional gas
utilities.
PEAK-DAY CAPABILITY. The design criteria for the Company's gas system
assumes an average temperature of 0(0)F for peak-day demand. Under such
criteria, the Company estimates that the requirements to supply its firm gas
customers would amount to approximately 1,754 MDTH of gas for a peak-day during
the 1998/99 winter season and that the gas available to the Company on such a
peak-day amounts to approximately 2,033 MDTH. For the 1999/2000 winter season,
the Company estimates that the peak-day requirements would amount to
approximately 1,789 MDTH and that the gas available to the Company amounts to
approximately 2,033 MDTH. As of March 1, 1999, the 1998/99 winter peak-day
throughput to the Company's customers was 1,511 MDTH, which occurred on January
14, 1999, at an average temperature of 22(degree)F, representing 74% of the
Company's peak-day capability at that time. The Company expects that it will
have sufficient gas available to meet the projected requirements for firm gas
customers for the 1999/2000 winter season. The Company's firm gas peak-day
capability is summarized in the following table:
Source MDTH per day % of Total
- ------------------------------------------------------ ----------------- -----------------
Producers.......................................... 750 37
Underground Storage................................ 779 38
Peaking Supplies................................... 504 25
================= =================
Total.......................................... 2,033 100
================= =================
PRODUCERS. The Company purchases natural gas for sale to its
customers under contracts with suppliers located in domestic and Canadian supply
basins and arranges for its transportation to the Company's facilities under
firm long-term contracts with interstate pipeline companies. During 1998, about
78% of the Company's natural gas supply was available from domestic sources and
22% from Canadian sources. The Company has available under firm contract 750
MDTH per day of year-round and seasonal pipeline transportation capacity to its
facilities in the New York City metropolitan area. Major providers of interstate
pipeline capacity and related services to the Company include: Transcontinental
Gas Pipe Line Corporation, Texas Eastern Transmission Corporation, Iroquois Gas
Transmission System, Tennessee Gas Pipeline Company, CNG Transmission
Corporation and Texas Gas Transmission Company.
STORAGE. In order to meet higher winter demand, the Company also has
long-term contracts with Transcontinental Gas Pipe Line Corporation, Texas
Eastern Transmission Corporation, Tennessee Gas Pipeline Company, CNG
Transmission Corporation, Equitrans, Inc., Hattiesburg First Reserve and Honeoye
Storage Corporation, for underground storage capacity of 58,935 MDTH for the
winter season, with 779 MDTH per day maximum deliverability.
PEAKING SUPPLIES. In addition to the pipeline and storage supply, the
Company supplements its winter supply with peaking supplies which are available
on the coldest days of the year to enable the Company to meet the increased
requirements of its heating customers economically. The Company's peaking
supplies include gas provided by the Company's two liquefied natural gas ("LNG")
10
plants and under peaking supply contracts with four cogeneration
facilities/independent power producers located in its franchise area. For the
1998/99 winter season, the Company has the capability to provide a maximum
peak-day supply of 504 MDTH on excessively cold days. The LNG plants have a
storage capacity of approximately 2,053 MDTH and peak-day throughput capacity of
394 MDTH, or 19% of peak-day supply. The Company also has contract rights with
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.
GAS SUPPLY MANAGEMENT. During 1998, the Company entered into a
one-year arrangement with Enron whereby Enron provides gas supply asset
management services for Brooklyn Union. Under the terms of this agreement, Enron
is responsible for managing certain aspects of Brooklyn Union's interstate
pipeline transportation, gas supply and storage. Enron also is responsible for
satisfying certain of the Company's gas supply requirements; however, the
Company remains contractually obligated to its gas suppliers and has not
terminated any of its supply and delivery contracts. Pursuant to this
arrangement, Enron paid the Company a fee in 1998, a portion of which was
credited to the Company's gas ratepayers, and obtained the right to earn
revenues based upon its management of the Company's gas supply requirements,
storage arrangements and off-system capacity.
In 1998, the Company entered into a one-year alliance with Coral
Energy Resources, L.P., a division of Shell Oil Company ("Coral"), whereby Coral
assists the Company in the origination, structuring, valuation and execution of
energy-related transactions relating to Brooklyn Union of Long Island and the
Company's energy-management services undertaken on behalf of LIPA. A sharing
agreement exists between the gas ratepayers and the Company for off-system gas
transactions and between the Company and LIPA for off-system electric
transactions. The Company's share of the profits on such transactions is then
shared with Coral. The Company also shares in revenues arising from certain
transactions initiated by Coral.
The arrangements with Enron and Coral are short-term agreements. The
Company will continue to evaluate the effectiveness of these arrangements and
ultimately determine the most effective management approach in light of the
Company's growth objectives. This approach could be an outsourcing of this
management function, entering into a strategic alliance with a third party to
jointly manage this activity, or internalizing the entire function.
GAS COSTS. On a Combined Company Basis, gas costs for 1998 were
$702.7 million and reflect warmer than normal weather during the year.
Variations in gas costs have little impact on operating results of the Company
since its current gas rate structures include gas adjustment clauses whereby
variations between actual gas costs and gas cost recoveries are deferred and
subsequently refunded to or collected from customers.
ELECTRIC SERVICES
OVERVIEW
The Company's electric services primarily consist of (i) the
ownership and operation of oil- and gas-fired generating facilities located on
Long Island and the delivery of the power generated by these facilities to LIPA;
(ii) the management and operation of LIPA's T&D System; and (iii) the management
of LIPA's fuel and electric energy purchases and any off-system sales.
11
As more fully described below, the Company (i) provides to LIPA all
operation, maintenance and construction services relating to the Retained Assets
through a Management Services Agreement (the "MSA"); (ii) supplies LIPA with
capacity and energy through a Power Supply Agreement (the "PSA") in order to
allow LIPA to provide electricity to its customers on Long Island; and (iii)
manages all aspects of the fuel supply for the Generating Facilities (as defined
below) as well as all aspects of the capacity and energy owned by or under
contract to LIPA through an Energy Management Agreement (the "EMA").
Collectively, the MSA, PSA and EMA are referred to herein as the "Operating
Agreements."
In addition, on January 28, 1999, the Company entered into a
definitive agreement with Con Edison to purchase, for approximately $597
million, subject to adjustment, the 2,168-megawatt Ravenswood electric
generating facilities located in Long Island City, Queens, New York.
Consummation of this transaction is subject to various regulatory approvals, the
timing of which cannot be determined.
During 1998, on a Combined Company Basis, electric revenues were
$1.294 billion or 40% of the Company's revenues and electric operating income
was $264.2 million, excluding special charges related to the Combination. For
the period following completion of the LIPA Transaction and ending December 31,
1998, electric revenues were $408.3 million and electric operating income was
$10.7 million, excluding special charges related to the Combination. On a
Combined Company Basis, electric revenues were $2.481 billion and $2.466 billion
for 1997 and 1996, respectively, and electric operating income was $645 million
and $642 million for 1997 and 1996, respectively.
GENERATION
GENERATING FACILITY OPERATIONS. The Company owns and operates an
aggregate of 53 electric generation units throughout Long Island (the
"Generating Facilities"), 20 of which can be powered either by oil or natural
gas at the Company's election. In recent years, the Company has reconfigured
several of its facilities to enable them to burn either oil or natural gas, thus
enabling the Company to switch periodically between fuel alternatives based upon
cost and seasonal environmental requirements.
The following table indicates the 1998 summer capacity of the
Company's steam generation facilities and internal combustion ("IC") Units as
reported to the New York Power Pool ("NYPP"):
---------------------- ---------------------- ---------------- ---------------- --------------
LOCATION OF UNITS DESCRIPTION FUEL UNITS MW
---------------------- ---------------------- ---------------- ---------------- --------------
Northport, L.I. Steam Turbine Dual* 3 1,156
Northport, L.I. Steam Turbine Oil 1 381
Port Jefferson, L.I. Steam Turbine Dual* 2 386
Glenwood, L.I. Steam Turbine Gas 2 228
Island Park, L.I. Steam Turbine Dual* 2 390
Far Rockaway, L.I. Steam Turbine Dual* 1 108
Throughout L.I. IC Units Dual* 12 291
Throughout L.I. IC Units Oil 30 1,078
====================== ====================== ================ ================ ==============
Total 53 4,018
====================== ====================== ================ ================ ==============
*Dual - Oil or natural gas.
12
The maximum demand on the T&D System was 4,208 megawatts ("MW") on
July 22, 1998, representing 84% of the total available capacity of 4,993 MW on
that day, which included 769 MW of firm capacity purchased from other sources.
By agreement with the NYPP, the Company is required to maintain, on a monthly
and annual basis, an installed and contracted firm power reserve generating
capacity equal to at least 18% of its actual peak demand. The Company expects
that it will be able to continue to meet this NYPP requirement. However, as
demand for capacity on Long Island increases, the Company anticipates that it
will seek to meet such demand through the acquisition or construction of
additional generation facilities.
POWER SUPPLY AGREEMENT. The PSA provides for the sale to LIPA by the
Company of all of the capacity and, to the extent LIPA requests, energy from the
Generating Facilities. Capacity refers to the ability to generate energy and,
pursuant to NYPP requirements, must be maintained at specified levels (including
reserves) regardless of the source and amount of energy consumption. By
contrast, energy refers to the electricity actually generated for consumption by
customers. Such sales of capacity and energy from the Generating Facilities are
made at cost-based wholesale 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 Generating
Facilities; and (iii) reasonably incurred expenses that are outside the control
of the Company.
The PSA provides incentives and penalties for the Company to maintain
the output capability of the 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 1998 the Company earned approximately $3.3 million in
incentives under the PSA.
The PSA provides LIPA with all of the capacity from the Generating
Facilities. However, LIPA has no obligation to purchase energy from the
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 T&D 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 Generating Facilities. A variable
maintenance charge is imposed for each unit of energy actually acquired from the
Generating Facilities. The term of the PSA is 15 years 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 the Company beginning in year
seven of the PSA, in accordance with agreed-upon schedules. In years seven
through ten of the PSA, if LIPA elects to ramp-down, the Company is entitled to
receive payment for 100 percent 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, the Company 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
the Company 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. Capacity and energy sold by the
Company from ramped-down capacity must be transported over the T&D System, and
the Company will be required to pay LIPA's standard transmission (and, if
applicable, distribution) rates for the service. The PSA will be terminated in
13
the event that LIPA exercises its right to purchase, at fair market value, all
of the Generating Facilities in the twelve-month period beginning in May 2001.
The Company 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 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 revenue is kept by the Company and the other 67% is
credited to LIPA. LIPA also has a right of first refusal on any potential
emission allowance sales. Additionally, the Company is bound by a memorandum of
understanding with the New York State Department of Environmental Conservation
which prohibits the sale of SO2 allowances into certain states and requires the
purchaser to be bound by the same restriction, which may affect the allowances'
market value.
TRANSMISSION AND DISTRIBUTION MANAGEMENT
MANAGEMENT SERVICES AGREEMENT. Under the MSA, the Company performs
day-to-day operations and maintenance of the T&D 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. The Company
furnishes such services as an independent contractor and does not have any
ownership or leasehold interest in the T&D System.
In exchange for providing these services, the Company is 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 the Company 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. The total cost budget for the
twelve month period ended December 31, 1998 was approximately $385.2 million.
The Company also is required to absorb any total cost budget overruns up to a
maximum of $15 million in each contract year.
In addition to the foregoing cost-based incentives and penalties, the
Company is eligible for incentives for performance above certain threshold
target levels and subject to disincentives for performance below certain other
threshold levels, with an intermediate band of performance in which neither
incentives nor disincentives will apply, for system reliability, worker safety,
and customer satisfaction.
The term of the MSA is eight years and requires that LIPA solicit
bids in the sixth year of the term for a new management services agreement
beginning after the eighth year. Generally, the Company is eligible to submit a
bid for such new management services agreement.
OTHER OPERATING AGREEMENTS
ENERGY MANAGEMENT AGREEMENT. Pursuant to the EMA, the Company (i)
procures and manages fuel supplies for LIPA to fuel the 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
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
14
electricity sales arranged by the Company. The term for the service provided in
(i) above is fifteen years, and the term for the service provided in (ii) and
(iii) above is eight years.
In exchange for these services, the Company 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 by the Company. Fuel
and electricity purchase prices will be compared to regional price indices and
the Company will receive a payment from LIPA, or be obligated to make a 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.
For the period ended December 31, 1998, the Company earned an aggregate of $3.4
million in incentives under the EMA as well as revenue from off-system sales.
OTHER RIGHTS. Pursuant to other agreements between LIPA and the
Company, 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 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, the Company will have the right
to sell or lease property on or adjoining the Generating Facilities to third
parties. 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.
The Company 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 agreements described
above. The Company 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 T&D
System. The Company has 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 ten-year
period attributed to the Combination (estimated to be approximately $1 billion),
which savings are incorporated into the cost structure under the Operating
Agreements; and (iii) not to commence any tax certiorari case (until termination
of the PSA) challenging certain property tax assessments relating to the
Generating Facilities.
GUARANTEES AND INDEMNITIES. The Company and LIPA also have 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 Transferred Assets have been assumed by the
Company and liabilities associated with the Retained Assets are borne by LIPA,
subject to certain specified exceptions. The Company 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 Generating
Facilities and all liabilities traceable to the business and operations
conducted by LIPA after completion of the Combination.
An agreement also provides for an allocation of liabilities that are
not traceable to either the business or operations to be conducted by LIPA or
15
the Company after completion of the Combination which relate to the assets that
were common to the operations of LILCO and/or shared services. LIPA bears 53.6%
of the costs associated therewith and the Company bears the remainder.
GAS EXPLORATION & PRODUCTION
Through its 64% equity interest in The Houston Exploration Company
("THEC"), an independent natural gas and oil company, the Company is engaged in
the exploration, development and acquisition of domestic natural gas and oil
properties. THEC's offshore properties are located in the Gulf of Mexico, and
its onshore properties are located in South Texas, South Louisiana, the Arkoma
Basin of Oklahoma and Arkansas, East Texas and West Virginia.
THEC was organized by the Company 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 22, 1999, its aggregate market
capitalization was approximately $451.0 million (based upon the closing price on
the New York Stock Exchange on that date of $18.875).
Information with respect to net proved reserves, production,
productive wells and acreage, undeveloped acreage, drilling activities, present
activities and drilling commitments is contained in "Note 14. Supplemental Gas
and Oil Disclosures" of the Notes to the Consolidated Financial Statements
included herein.
During 1998, on a Combined Company Basis, gas exploration and
production revenues were $127.1 million, and gas exploration and production
operating income was $15.3 million, excluding an impairment charge on its proved
gas reserves. Set forth below is certain selected information with respect to
THEC:
THEC Operating Statistics
- -------------------------
1998 1997 1996
----------- ----------- -----------
Net Proved Reserves (Mmcfe)...................... 480,347 337,063 327,260
Production of Natural Gas and Oil (MMcfe)........ 62,829 51,336 31,923
Average Realized Price of Natural Gas ($/per Mcf) 2.02 2.25 2.00
Average Unhedged Price of Natural Gas ($/per Mcf) 1.96 2.45 2.35
Capital Expenditures ($000)...................... 302,837 145,175 177,774
THEC has achieved significant growth in net proved reserves,
production and revenues over the past five years. It has increased net proved
reserves at a compound annual rate of 41% from 121 Bcfe at December 31, 1993 to
480 Bcfe at December 31, 1998. During this period, annual production increased
at a compound annual rate of 28% from 23 Bcfe in 1994 to 63 Bcfe in 1998. At the
close of 1998, daily production averaged 190 MMcfe per day. THEC's oil and gas
revenues have increased from $41.8 million in 1994 to $127.1 million in 1998.
THEC focuses its 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 its operations enables it to manage a
comparatively large asset base with relatively few employees and to add and
operate production at relatively low incremental costs. THEC seeks to balance
its offshore and onshore activities so that the lower risk and more stable
16
production typically associated with onshore properties complement the high
potential exploratory projects in the Gulf of Mexico by balancing risk and
reducing volatility. THEC'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 its offshore and onshore properties and by making selective
opportune acquisitions.
OFFSHORE PROPERTIES. THEC holds interests in 86 lease blocks,
representing 439,896 gross (355,129 net) acres, in federal and state waters in
the Gulf of Mexico, of which 27 have current operations. THEC operates 21 of
these blocks, accounting for approximately 82% of THEC's offshore production.
Over the past five years, THEC has drilled 19 successful exploratory wells and
14 successful development wells in the Gulf of Mexico, representing a historical
success rate of 65%. During 1998, THEC drilled two successful exploratory wells
and one successful development well on its Gulf of Mexico properties. During the
same period, THEC drilled five exploratory wells and one development well that
were not successful. THEC plans to drill approximately 10 exploratory wells,
along with limited development drilling, in the Gulf of Mexico in 1999.
ONSHORE PROPERTIES. THEC owns onshore natural gas and oil properties
representing interests in 1,179 gross (764 net) wells, approximately 84% of
which THEC is the operator of record, and 174,513 gross (125,595 net) acres.
Over the past five years, THEC has drilled or participated in the drilling of 83
successful development wells and 7 successful exploratory wells onshore,
representing a historical success rate of 78%. During 1998, THEC drilled or
participated in the drilling of 23 successful development wells and one
successful exploratory well on its onshore properties. During the same period,
THEC drilled or participated in the drilling of four development wells that were
not successful.
THEC plans to drill approximately 25 wells onshore in 1999.
In November 1998, the Company extended a $150 million revolving
credit line to THEC (the "THEC Facility"). The THEC Facility matures January 1,
2000 and is convertible to equity if borrowings remain outstanding at maturity.
The THEC Facility is subordinated to THEC's bank credit facility and pari passu
to THEC's senior subordinated notes. As of December 31, 1998, THEC had $80
million outstanding under the THEC Facility.
On November 30, 1998, THEC acquired from Chevron U.S.A., Inc.
offshore producing properties and facilities in the Mustang Island area of the
Gulf of Mexico. The newly acquired properties are comprised of three adjacent
blocks, with nine producing wells and three platforms. The acquired properties
neighbor 19 undeveloped lease blocks and five producing blocks held by THEC. The
net purchase price of $84.9 million was paid in cash and financed by borrowings
under the THEC Facility. THEC plans both exploratory and development drilling in
1999 on those properties.
On March 15 1999, the Company and THEC entered into a joint
exploration agreement (the "THEC Joint Venture") to explore for natural gas and
oil over a term of three years expiring December 31, 2001. The THEC Joint
Venture may be terminated at the option of either party at the end of a given
year. Under the terms of this agreement, THEC will contribute all of its
currently undeveloped offshore leases to the THEC Joint Venture and the Company
will acquire 45% of THEC's working interest in all prospects to be drilled under
the THEC Joint Venture and will commit up to $100 million per calendar year to
explore and develop these leases. THEC will retain a 55% interest in the leases
and will commit its proportionate share of the funds per calendar year necessary
for such year's exploration and development drilling program. Revenues generated
17
from this joint program will be shared between the Company and THEC according to
the respective working interest ownership of each entity. THEC plans to drill
approximately 8-10 offshore exploratory wells under the terms of the THEC Joint
Venture during 1999.
The Company intends to continue to grow its exploration and
production investments in the Gulf region. KeySpan anticipates that THEC will
have capital expenditures of approximately $82 million in 1999. In addition, the
Company anticipates that it will invest approximately $45 million additionally
in exploration and production activities in 1999. Such amounts are expected to
consist primarily of contributions to the THEC Joint Venture.
ENERGY-RELATED INVESTMENTS
OVERVIEW
The Company has investments in energy-related businesses, including
natural gas pipelines, midstream natural gas processing and gathering facilities
and gas storage facilities in the Northeast region of the United States and in
Canada and the United Kingdom.
During 1998, on a Combined Company Basis, net after-tax loss from
energy-related investments was $6.1 million, and the Company's capital
expenditures in energy-related investments were $239.8 million, which was
significantly higher than past years primarily due to the Company's $189 million
investment in certain midstream natural gas assets, as discussed below.
The Company owns an approximately 20% interest in Iroquois Gas
Transmission System L.P. ("Iroquois"), the partnership that owns a 374-mile
pipeline which currently transports 892 MDTH of Canadian gas supply daily to
markets in the Northeastern United States. The Company is also a shipper on
Iroquois and currently transports up to 135 MDTH of gas per day on the pipeline.
The Company owns a 24.5% interest in Phoenix Natural Gas ("Phoenix")
in Belfast, Northern Ireland and, in December 1998, increased its interest in
The Premier Transco Pipeline ("Premier") from 24.5% to 50%. Phoenix is a newly
established gas distribution system serving the City of Belfast, which is in its
early stages of development pursuant to an eight-year program of capital
development and line extensions. Premier is an 84-mile pipeline to Northern
Ireland from southwest Scotland that currently transports approximately 300 MDTH
of gas supply daily to markets in Northern Ireland.
The Company has equity investments in two gas storage facilities in
the State of New York.
In August 1998, the Company acquired a 25% interest in a venture to
develop the Cross Bay pipeline. Upon completion, Cross Bay will transport gas
from interstate pipelines in New Jersey to New York City and Long Island,
including supplying customers served by the Company. The new system is scheduled
to begin operating in November 2000.
In December 1998, the Company acquired a 50% interest in certain
midstream natural gas assets owned by Gulf Canada Resources Limited ("Gulf
Canada") located in Western Canada. The purchased assets include interests in 14
processing plants and associated gathering systems which can process
18
approximately 1.4 Bcfe of natural gas daily, and associated natural gas liquids
fractionation, storage and transportation facilities. The Company paid Gulf
Canada $189 million for the equity interest and agreed to provide a three-year,
$65 million loan to Gulf Canada.
The Company's business strategy with respect to its energy-related
investments is to acquire and maintain interests in natural gas and natural gas
liquid gathering, processing, transmission and storage facilities near areas of
rapid reserve development or growing consumer markets. It is anticipated that
approximately $85 million will be invested in energy-related businesses in 1999,
a level of investment that could rise significantly in future years based on the
numerous potential domestic and international projects currently being pursued.
ENERGY-RELATED SERVICES
OVERVIEW
The Company has formed non-regulated subsidiaries to market and
manage natural gas, electricity, and consumer products and services to
residential, commercial and industrial customers, including those within the
Company's traditional service territories. These non-regulated subsidiaries
which are currently in the start-up phase, had revenues of $88.4 million and an
operating loss of $10.2 million in 1998, on a Combined Company Basis. The
Company expects to invest approximately $57 million in 1999 in these
non-regulated subsidiaries.
ENERGY MARKETING. The Company buys, sells and markets gas and
electricity and arranges for transportation and related services to over 30,000
customers throughout the northeastern United States, including those in the gas
service territories of the Company. In 1998, the Company established a joint
venture with Enron to market gas supply management services to gas distribution
companies throughout the Northeastern United States.
ENERGY MANAGEMENT. The Company owns, designs and/or operates energy
systems for commercial and industrial customers and provides energy-related
services to clients in the New York City metropolitan area. Revenues have been
enhanced through the continued integration of an engineering firm.
APPLIANCE SERVICES. The Company provides various technical and
maintenance services to customers throughout the New York City metropolitan
area, including maintaining and repairing heating equipment, water heaters,
central air conditioners and other appliances. With over 100,000 service
contracts, the Company is the largest provider of these services in the State of
New York. In November 1998, the Company purchased Philip Fritze and Sons, one of
the largest heating, ventilation and air conditioning contractors in the State
of New Jersey.
The Company's energy-related services businesses 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. The Company's energy-related services subsidiaries are
expected to enable the Company to take advantage of emerging deregulated energy
markets for both gas and electricity and the Company anticipates that it will
19
continue to target other acquisitions which also provide it with opportunities
to expand those services both within and outside its traditional service
territories.
REGULATION AND RATE MATTERS
OVERVIEW
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 service commissions, such as the NYPSC, regulate the
provision of retail services, including the distribution and sale of natural gas
and electricity to consumers. The Federal Energy Regulatory Commission ("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 the Public Utility Holding
Company Act of 1935 ("PUHCA") and, to some extent, by state commissions, through
the regulation of corporate, financial and affiliate activities of public
utilities.
PUBLIC UTILITY HOLDING COMPANY REGULATION. KeySpan Energy is a public
utility holding company, although it is exempt from most regulation under PUHCA
because of the predominately intrastate character of its public utility
subsidiaries. The only provision of PUHCA from which KeySpan Energy is not
exempt is the requirement that any person must obtain advance SEC approval for
the acquisition of 5% or more of voting securities issued by any public utility
company or public utility holding company. KeySpan Energy is also subject to
indirect regulation by the NYPSC in the form of conditions attached to NYPSC
orders authorizing the formation of the Company, among other matters. Those
conditions address the manner in which KeySpan Energy interacts with its two
NYPSC-regulated natural gas distribution subsidiaries, Brooklyn Union and
Brooklyn Union of Long Island.
NYPSC REGULATION
NATURAL GAS UTILITIES. The NYPSC is the principal agency in the State
of New York which regulates, as "gas corporations," companies that own, operate
or manage pipelines and other facilities used to distribute or sell natural gas.
The NYPSC regulates the construction, use and maintenance of intrastate natural
gas facilities, the retail rates, terms and conditions of service offered by gas
corporations, as well as matters relating to the quality, reliability and safety
of service. The NYPSC also regulates the corporate, financial and affiliate
activities of gas corporations. Both Brooklyn Union and Brooklyn Union of Long
Island are gas corporations subject to the full scope of NYPSC regulation.
Beginning in the mid-1980's, the NYPSC has taken a number of steps to
require the "unbundling" of natural gas sales and other services from the
distribution of natural gas through pipelines, in order to encourage competition
among gas sellers and energy service providers. In 1985, the NYPSC ordered the
major gas utilities in the state to offer transportation service for large
volume customers who choose to purchase natural gas from other suppliers.
Subsequently, the NYPSC required that transportation service be made available
to all customers beginning on May 1, 1996. Brooklyn Union of Long Island has
been providing a transportation service option to all its customers since April
1996. Brooklyn Union has been providing a transportation option to all its
customers since May 1996.
20
In April 1997, the NYPSC ordered gas utilities to cease providing
non-safety related appliance repair service by no later than May 1, 2000.
Brooklyn Union stopped providing these services in April 1998; Brooklyn Union of
Long Island will cease providing non-emergency appliance repair services on July
1, 1999. Utility affiliates can provide this service, and the Company does so
through a subsidiary.
In November 1998, the NYPSC issued a policy statement that
anticipated that natural gas utilities would cease sales of gas, and become
transportation-only providers, within three to seven years. Marketers which are
affiliated with the natural gas utilities are permitted to compete for retail
natural gas sales. The NYPSC's policy statement envisions proceedings to
restructure the operations of natural gas utilities in order to facilitate the
achievement of the objectives articulated in the policy statement. The Company
is evaluating the policy statement and anticipates making specific proposals to
the NYPSC in 1999.
Brooklyn Union of Long Island is currently operating under a
three-year rate plan. The rate plan applies to the period December 1, 1997
through November 30, 2000. Under the plan, if Brooklyn Union of Long Island's
earnings exceed 11.10%, it must credit back to certain customers 60% of earnings
up to 100 basis points above the 11.10% and 50% of any earnings in excess of a
12.10% return. Both a customer service and a safety and reliability incentive
performance program became effective on December 1, 1997, with maximum pre-tax
return on equity penalties of 40 and 12 basis points, respectively, if Brooklyn
Union of Long Island fails to achieve certain performance standards in these
areas.
Brooklyn Union is currently operating under a multi-year rate plan
that ends on September 30, 2002. Brooklyn Union, like Brooklyn Union of Long
Island, is subject to an earnings sharing provision, under which it will be
required to credit to certain customers 60% of any utility earnings up to 100
basis points above specified equity return levels (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 13.75%
for fiscal year 1998, 13.50% for fiscal years 1999, 2000 and 2001; and 13.25%
for fiscal year 2002. A safety and reliability incentive mechanism provides a
maximum 12 basis point pre-tax penalty return on common equity if Brooklyn Union
fails to achieve certain safety and reliability performance standards, and a
customer service incentive performance program with a maximum 40 basis point
pre-tax penalty return on equity. With the exception of the simplification of
the customer service performance standards and the imposition of the earnings
sharing provisions, the Brooklyn Union rate plan approved by the NYPSC in 1996
remains unchanged.
As part of the settlement agreement approved by the NYPSC in
connection with its approval of the Combination (the "Stipulation"), Brooklyn
Union and Brooklyn Union of Long Island are subject to certain affiliate
transaction restrictions, cost allocation and financial integrity conditions and
a code of conduct governing affiliate relationships. These restrictions and
conditions eliminate or relax many restrictions previously applicable to
Brooklyn Union in such areas as affiliate transactions, use of the name and
reputation of Brooklyn Union by unregulated affiliates, common officers of the
Company, the utility subsidiaries and unregulated subsidiaries, dividend payment
restrictions, and the composition of the Board of Directors of Brooklyn Union.
The Stipulation provides that, in order to achieve forecasted synergy
savings resulting from the Combination, one or more shared services subsidiaries
of the Company may be formed to provide to both regulated and unregulated
operating subsidiaries, functions common to both utilities and their affiliates,
such as accounting, finance, human resources, legal and information systems and
technology.
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ELECTRIC UTILITIES. KeySpan Generation LLC ("KeySpan Generation"),
KeySpan's electric generation subsidiary, is not subject to NYPSC rate
regulation because its sales of electricity are made exclusively at wholesale;
however, KeySpan Generation is subject to NYPSC financial, reliability and
safety regulation. As a wholesale generator, KeySpan Generation qualifies for
"lightened" regulatory treatment, I.E. certain financial regulations are waived
or applied with less scrutiny than would be the case for fully-regulated
electric utilities.
FEDERAL REGULATION
NATURAL GAS COMPANIES. The FERC 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 Brooklyn
Union and Brooklyn Union of Long Island and certain related intrastate gas
transportation functions are not subject to FERC jurisdiction. However, to the
extent that Brooklyn Union and Brooklyn Union of Long Island sell gas for resale
in interstate commerce, such sales are subject to FERC jurisdiction and have
been authorized by the FERC.
The Company also owns an approximately 20% interest in Iroquois, an
interstate natural gas pipeline extending from the Canadian border to Long
Island, and 52% and 18.6% of the Honeoye and Steuben gas storage facilities,
respectively. Iroquois, Honeoye and Steuben are fully regulated by the FERC as
natural gas companies.
ELECTRIC UTILITIES. The FERC regulates the sale of electricity at
wholesale and the transmission of electricity in interstate commerce, as well as
certain corporate and financial activities of companies that are engaged in such
activities.
KeySpan Generation is subject to FERC regulation based on its sales of
electricity at wholesale to LIPA under the PSA. On October 1, 1997, a rate
application was filed with the FERC which proposed rates that were designed for
KeySpan Generation to recover $327.6 million from LIPA for the first year of an
approximately five-year rate plan with various adjustments, and to set the rates
for the remainder of the multi-year rate period. In December 1997, KeySpan
Generation and LIPA agreed jointly to propose to FERC rates that would recover
$301.8 million in the first year of the multi-year rate period and adjustments
to set rates for the remaining years. LIPA, KeySpan Generation, and the Staff of
FERC eventually stipulated to setting rates designed to recover $300.5 million
in the first year with agreed-upon adjustments to set rates for the remainder of
the multi-year rate period. The only party opposed to this stipulation is the
County of Suffolk. Parties submitted initial briefs to a FERC Administrative Law
Judge ("ALJ") on December 8, 1998 and reply briefs on January 15, 1999. The
Company has not yet received the decision of the ALJ or a final decision of
FERC. Until such final decision, rates are in effect subject to adjustment and
refund. The FERC retains the ability in future proceedings, either on its own
motion or upon a complaint filed with the FERC, to modify KeySpan Generation's
rates, either upward or downward, if the FERC finds that the public interest
requires it to do so.
22
REGULATION IN OTHER COUNTRIES
The Company's 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.
The Company's midstream natural gas processing facilities in Canada
are subject to regulation by Canadian provincial authorities. Such regulatory
authorities license the operations of the facilities and regulate safety matters
and certain changes in such facilities' operations.
ENVIRONMENTAL MATTERS
OVERVIEW
The Company'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
authorities, including the United States Environmental Protection Agency (the
"EPA") and the New York State Department of Environmental Conservation ("DEC").
These requirements govern both the normal, ongoing operations of the Company and
the remediation of contaminated properties historically used in utility
operations. Potential liabilities associated with the Company's historical
operations may be imposed without regard to fault, even if the activities were
lawful at the time they occurred.
Ensuring continuing compliance with environmental requirements may
require significant expenditures for capital improvements or modifications in
some areas. Total capital expenditures for environmental improvements and
related studies amounted to approximately $1.6 million for the year ended
December 31, 1998, and are expected to be $2.3 million for the year ending
December 31, 1999.
Except as set forth below, no material proceedings relating to
environmental matters have been commenced or, to the knowledge of the Company,
are contemplated by any federal, state or local agency against the Company, and
the Company is not a defendant in any material litigation with respect to any
matter relating to the protection of the environment. The Company believes that
its 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 the Company. The Company believes that all material costs
incurred with respect to environmental requirements will be recoverable from its
customers. The Company is 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
23
dioxide. The Company has 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 the Company's electric
generating facilities with the exception of the Far Rockaway facility, which is
pending. The permits allow the Company's electric generating plants to continue
to operate without any additional significant expenditures, except as described
below.
The Company's 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. The Company's investments in boiler
combustion modifications and the use of natural gas firing at its steam electric
generating stations has enabled the Company to achieve the NOx emission
reductions required under Phase I and II in a cost-effective manner. In
addition, software and equipment upgrades of approximately $1 million for
continuous emissions monitors ("CEM") may be required in 1999-2000 to meet EPA
requirements for the NOx allowance tracking/trading program and certain other
regulatory changes affecting the operation of CEM systems. The Company currently
estimates that it may be required to spend between $10 million and $35 million
by the year 2003 for additional pollution control equipment to achieve the OTC
Phase III NOx reduction requirements and/or new requirements imposed under the
EPA NOx state implementation plan, depending on the actual level of NOx emission
reductions which are required when pending regulations are implemented by the
State of New York.
WATER. The Company possesses permits for its generating units which
authorize discharges from cooling water circulating systems and chemical
treatment systems. Several of these permits are being renewed; one or more of
the new permits are expected to require biological monitoring to determine if
the cooling water intake structures meet the best available technology
requirements of the Federal Clean Water Act ("CWA") for the protection of marine
life.
On behalf of LIPA, the Company provides 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 ("DEP") 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.
REMEDIATION OF CONTAMINATED PROPERTY
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 its
business operations, the Company generates materials which are subject to these
laws. From time to time, the Company has received notices under these laws
concerning possible claims with respect to sites at which hazardous substances
generated by the Company and other potentially responsible parties ("PRPs")
allegedly were disposed.
24
The DEC has notified the Company, pursuant to the State Superfund
program, that the Company may be responsible for the disposal of hazardous
substances at the Huntington/East Northport Site, a municipal landfill property.
The DEC investigation is in its preliminary stages, and the Company currently is
unable to estimate its share, if any, of the costs required to investigate and
remediate this site.
MANUFACTURED GAS PLANT SITES. The Company or its predecessor
entities, including Brooklyn Union and LILCO, historically owned or operated
several former MGP sites. 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 have been identified to the DEC for inclusion on appropriate waste
site inventories. In certain circumstances, former MGP sites can give rise to
environmental cleanup responsibilities for the Company.
The Company has several former MGP sites that will require
investigation and/or remediation. In 1995, the Company executed an ACO with the
DEC which addressed the investigation and remediation of the Brooklyn Borough
Works site in Coney Island, Brooklyn. In 1998, the Company executed an ACO for
the investigation and remediation of the Clifton MGP site in Staten Island. Both
of these properties are owned by the Company. The City of New York has notified
the Company that a property now owned by the City which was formerly owned and
operated by a Brooklyn Union predecessor, the Citizen's Site, should be
investigated. The Company has submitted an investigation study plan and
requested cost sharing for this property with the City. The Company is awaiting
the City's response. Finally, the DEC notified the Company in 1998 that two MGP
sites previously owned by LILCO would require remediation under the State's
Superfund program; pending discussions with DEC on those and four additional
former LILCO sites are expected to result in the issuance of additional ACOs in
the near future.
The final end uses for these sites and acceptable remediation goals
have not been determined in the ACOs. In addition, investigation may be required
at other former MGP sites before determinations can be made regarding the need
for or scope of potential remediation at these locations. Based upon activities
conducted to date, the Company estimates the minimum cost of its MGP-related
environmental cleanup activities will be approximately $130 million; that amount
has been accrued by the Company as an environmental liability. The actual
MGP-related costs may be substantially higher, depending upon remediation
experience, selected end use for each site, and actual environmental conditions
encountered.
The NYPSC-approved rate plans for Brooklyn Union and Brooklyn Union
of Long Island provide for the recovery of such costs. The Brooklyn Union 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 Brooklyn Union will retain or absorb up
to 10% of the variation. Under prior rate orders, Brooklyn Union has already
recovered costs associated with certain MGP sites. The Brooklyn Union of Long
Island rate plan provides for the complete recovery of investigation and
remediation costs. At December 31, 1998, the Company has reflected a remaining
regulatory asset of $100 million of which $18 million is associated with
Brooklyn Union sites and $82 million is associated with Brooklyn Union of Long
Island sites. Expenditures incurred to date by Brooklyn Union and Brooklyn Union
of Long Island with respect to MGP-related activities total $8.7 million and $5
million, respectively.
25
Periodic discussions by the Company with insurance carriers and third
parties for reimbursement of some portion of MGP site investigation and
remediation costs continue. 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 outcome of this proceeding
cannot yet be determined. In addition, Brooklyn Union is in discussions with
insurance carriers regarding the possible resolution of coverage claims related
to MGP site investigation and remediation activities.
EMPLOYEE MATTERS
On December 31, 1998, the Company had approximately 7,950 full-time
employees. Of that total, approximately 5,113 employees are covered under
collective bargaining agreements; 1,603 employees belong to Local 101, Utility
Division, of the Transport Workers Union of America, 175 employees belong to
Local 3 of the International Brotherhood of Electrical Workers (the "IBEW"),
2,119 employees belong to Local 1049 of the IBEW and 1,216 employees belong to
Local 1381 of the IBEW.
The Company maintains collective bargaining agreements covering each
of the four collective bargaining units detailed above, all of which expire in
2001. The Company has not experienced any work stoppage during the past five
years and considers its relationship with employees, including those covered by
collective bargaining agreements, to be good.
EXECUTIVE OFFICERS OF THE COMPANY
Certain information regarding the Company's Executive Officers, all
of whom serve at the will of the Board of Directors, is set forth below:
ROBERT B. CATELL
Mr. Catell, age 61, has been a Director of the Company since its creation in May
1998 and served as its President and Chief Operating Officer from May 1998-July
1998. He was elected Chairman of the Board and Chief Executive Officer in July
1998. Mr. Catell joined Brooklyn Union 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
KSE.
ANTHONY J. DIBRITA
Mr. DiBrita, age 58, has been Senior Vice President of Gas Operations for the
Company since its creation in May 1998. He joined Brooklyn Union in 1962. Since,
then he has held various engineering positions. In 1989, he was elected Vice
President in charge of Brooklyn Union's Gas Distribution, Materials Management,
and Research and Development Operations. From 1991 to 1992, he oversaw the Rate
Recovery, Budgeting and Forecasting, and Financial and Strategic Planning areas.
Mr. DiBrita was promoted to Senior Vice President of Brooklyn Union's
Engineering and Customer Field Services in 1994.
26
LAWRENCE S. DRYER
Mr. Dryer, age 39, was elected Vice President of Internal Audit for the Company
in September 1998. Mr. Dryer joined LILCO in 1992 as Director of Internal Audit
and has been responsible for providing independent appraisals and
recommendations to improve management controls and increase operational
efficiency.
ROBERT J. FANI
Mr. Fani, age 45, has been Senior Vice President of Gas Marketing and Sales for
the Company since its creation in May 1998. Mr. Fani joined Brooklyn Union 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 Brooklyn Union.
WILLIAM K. FERAUDO
Mr. Feraudo, age 48, has been Senior Vice President of the Company since its
creation in May 1998. He oversees the KeySpan Energy Marketing Group and is
responsible for the Company's four unregulated domestic subsidiaries providing
energy-related services. Mr. Feraudo began his career at Brooklyn Union 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 of Brooklyn Union in 1994.
RONALD S. JENDRAS
Mr. Jendras, age 50, was named Vice President, Controller and Chief Accounting
Officer of the Company in August 1998. He joined Brooklyn Union 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 Brooklyn
Union's Rate and Regulatory Affairs area and, in 1997, was named general manager
of the Accounting Division.
FREDERICK M. LOWTHER
Mr. Lowther, age 55, was elected to the position of General Counsel in September
1998. He is also a partner in the law firm Dickstein Shapiro Morin & Oshinsky
LLP, Washington D.C., with which he has been associated since 1973. Mr. Lowther
has devoted his career principally to the development of large energy and
natural resource projects in the United States and abroad. He has served as
project counsel for a number of important U.S. energy projects, including the
Iroquois Gas Transmission System.
CRAIG G. MATTHEWS
Mr. Matthews, age 55, has been President and Chief Operating Officer of the
Company since January 1999. He has also been Chief Financial Officer of the
Company since May 1998. He served as Executive Vice President of the Company
from May 1998 to January 1999. Mr. Matthews joined Brooklyn Union in 1965 and
held various management positions in the corporate planning, financial,
marketing, and 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 Brooklyn
Union's financial, gas supply, information systems, and strategic planning
functions, as well as Brooklyn Union's energy-related investments. In 1996, Mr.
Matthews was promoted to President and Chief Operating Officer of Brooklyn
Union.
27
ANTHONY NOZZOLILLO
Mr. Nozzolillo, age 50, became Senior Vice President of the Company's Electric
Business Unit in January 1999. He previously served as Senior Vice President of
Finance since the Company's creation in May 1998. 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.
WALLACE P. PARKER, JR.
Mr. Parker, age 49, has served as the Company's Senior Vice President of Human
Resources since August 1998. He joined Brooklyn Union in 1971 and served in a
wide variety of management positions. In 1987 he was named Assistant Vice
President for marketing and advertising and was elected Vice President in 1990.
In 1994 Mr. Parker was promoted to Senior Vice President of Human Resources.
DAVID L. PHILLIPS
Mr. Phillips, age 42, has served as the Company's Senior Vice President of
Strategic Planning & Corporate Development since the Company's creation in May
1998. Previously, he held the same position with Brooklyn Union. He joined
Brooklyn Union in 1996 and was a consultant to the merger process. Prior to
joining Brooklyn Union, Mr. Phillips had been a consultant to both the Bush and
Clinton Administrations. From the mid 1980s through late 1991, Mr. Phillips was
Vice President and General Counsel to the Houston-based Eastex Energy Inc., a
diversified energy company. From 1991 to 1995, he was an executive with
Equitable Resources, Inc., a diversified utility company operating in
Pittsburgh, Pennsylvania. Hired as General Counsel, he was promoted to president
of its unregulated companies, and in 1994, became a member of its Executive
Committee.
LENORE F. PULEO
Ms. Puleo, age 45, has served as the Company's Senior Vice President of Customer
Relations since its creation in May 1998. She joined Brooklyn Union in 1974 and
worked in management positions in Brooklyn Union'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 Customer Relations in 1995
for Brooklyn Union.
CHERYL SMITH
Ms. Smith, age 47, joined the Company in November 1998 as Senior Vice President
and Chief Information Officer. She comes to the Company from Bell Atlantic where
she most recently served as Vice President of Strategic Billing and Corporate
Systems. Prior to Bell Atlantic, she worked at Honeywell Federal Systems Inc. as
the Director of MIS. Ms. Smith brings to the Company more than 25 years of
information systems technology experience.
MICHAEL J. TAUNTON
Mr. Taunton, age 43, has been the Company's Vice President of Investor Relations
since September 1998. He joined Brooklyn Union in 1975 and has worked in various
management positions in Marketing and Sales, Corporate Planning, Corporate
Finance and Accounting. Most recently he co-managed the day-to-day transition
process of the Combination on behalf of Brooklyn Union and LILCO. Before that,
Mr. Taunton was general manager of the Business Process Improvement for Brooklyn
Union.
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ROBERT R. WIECZOREK
Mr. Wieczorek, age 56, has been the Company's Vice President, Secretary and
Treasurer since August 1998. Mr. Wieczorek joined Brooklyn Union as the General
Auditor in 1976 and held a variety of financial-related positions. In 1981 he
was named Treasurer and, subsequently, Vice President, Secretary and Treasurer
responsible for all cash management activities and for overseeing pension fund
investments and retirement administration, pension manager evaluation, long-term
debt and equity financing, investor relations, and shareholder records.
STEVEN L. ZELKOWITZ
Mr. Zelkowitz, age 49, joined the Company 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.
ITEM 2. PROPERTIES
Information with respect to the Company'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, the Company owns or
leases a variety of office space used for administrative operations of the
Company. In the case of leased office space, the Company anticipates no
significant difficulty in leasing alternative space at reasonable rates in the
event of the expiration, cancellation or termination of a lease relating to the
Company's leased properties.
ITEM 3. LEGAL PROCEEDINGS
From time to time, the Company is subject to various legal
proceedings arising out of the ordinary course of its business. Except as
described below, the Company does not consider any of such proceedings to be
material to its business or likely to result in a material adverse effect on its
results of operations or financial condition.
Subsequent to the closing of the Combination, former shareholders of
LILCO commenced 13 class action lawsuits in the New York State Supreme Court,
Nassau County, against the Company and each of the former officers and directors
of LILCO. These actions were consolidated in August 1998. The consolidated
action alleges that, in connection with certain payments LILCO had determined
were payable in connection with the Combination to LILCO's chairman, and to
former officers of LILCO (the "Payments"): (i) the named defendants breached
their fiduciary duty owed to LILCO and KSE former and/or current Company
shareholders as a result of the Payments; (ii) the named defendants intended to
defraud such shareholders by means of manipulative, deceptive and wrongful
conduct, including materially inaccurate and incomplete news reports and filings
with the SEC; and (iii) the named defendants recklessly and/or negligently
failed to disclose material facts associated with the Payments.
29
In addition, three shareholder derivative actions have been commenced
pursuant to which such shareholders seek the return of the Payments or damages
resulting from among other things, an alleged breach of fiduciary duty on the
part of the former LILCO officers and directors. One action was brought on
behalf of LILCO in federal court. The Company moved to dismiss this action in
September 1998. The other two actions were brought on behalf of the Company in
New York State Supreme Court, Nassau County. In one of these state court
actions, the Company's directors and the recipients of the Payments are also
named as defendants.
Finally, two class action securities suits were filed in federal
court alleging that certain officers and directors of LILCO violated the federal
securities laws by failing to properly disclose that the Combination would
trigger the Payments. These actions were consolidated in October 1998.
On March 17, 1999, the Company signed a Memorandum of Understanding
to settle the above-referenced actions, except the federal court derivative
action, in exchange for (i) $7.9 million to be distributed (less plaintiffs'
attorneys fees) to former LILCO and KSE shareholders and (ii) the Company's
agreement to implement certain corporate governance and executive compensation
procedures. The entire $7.9 million settlement commitment will be funded from
insurance. The parties intend to submit the settlement to the Nassau County
Supreme Court for its review and approval. If that Court approves the
settlement, the parties will then make an application to the federal court for
an order and final judgment, dismissing the three federal court actions,
including the federal court derivative action, based, among other things, on the
binding effect of the state court judgment.
In addition to the above-mentioned actions, a class action lawsuit
has also been filed in the New York State Supreme Court, Suffolk County, by the
County of Suffolk against LILCO's former officers and/or directors. The County
of Suffolk alleges that the Payments were improper, and seeks to recover the
Payments for the benefit of Suffolk County ratepayers. The Company moved to
consolidate this action with the above-mentioned consolidated action in October
1998.
In October 1998, the County of Suffolk and the Towns of Huntington
and Babylon commenced an action against LIPA, the Company, 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, the plaintiffs amended their complaint. The
amended complaint contains allegations relating to the Payments and adds the
recipients of the Payments as defendants. In January 1999, the Company was
served with the amended complaint.
Finally, certain other proceedings have been commenced relating to
the Payments and disclosures made by LILCO with respect thereto. These
proceedings include investigations by the New York State Attorney General, the
NYPSC and LIPA, joint hearings conducted by two committees of the New York State
Assembly, and an informal, non-public inquiry by the SEC. In December 1998, the
Company settled with LIPA and the NYPSC. The agreement includes a payment of
$5.2 million by the Company to LIPA that will be used by LIPA to supply
postage-paid bill return envelopes to customers for the next three years. The
Company also agreed to fully reimburse and indemnify LIPA for costs incurred by
30
LIPA, amounting to approximately $765,000, for attorneys and other consultants
involved in the investigation. Such amounts are not covered by insurance. The
Company is cooperating fully with the investigations of the New York State
Attorney General and the SEC. To date, no action has been taken either by the
New York State Attorney General or the SEC.
At this time the Company is unable to determine the outcome of the
ongoing proceedings, or any of the remaining lawsuits described above.
In May 1995, eight participants of LILCO's Retirement Income Plan
("RIP") filed a lawsuit against LILCO, the RIP and Robert X. Kelleher, the Plan
Administrator, in the United States District Court for the Eastern District of
New York (Becher, et al. v. Long Island Lighting Company, et al.). In January
1996, the Court ordered that this action be maintained as a class action. This
proceeding arose in connection with the plaintiffs' withdrawal, approximately 25
years ago, of contributions made to the RIP, thereby resulting in a reduction of
their pension benefits. The plaintiffs are now seeking, among other things, to
have these reduced benefits restored to their pension accounts. In November
1997, the Company filed a motion for partial summary judgment with the District
Court. On April 28, 1998, the Court denied the Company's motion and permitted
the Company to file a further motion for partial summary judgment on additional
grounds. On January 27, 1999, the Company entered a stipulation of settlement
which was filed with the Court pursuant to which the Company will pay
approximately $8 million, a substantial portion of which is recoverable from
LIPA. The settlement is subject to court approval.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the Company's security holders
during the last quarter of the nine-month period ended December 31, 1998.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company'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 22,
1999, there were 98,901 record holders of the Company's common stock. The
following table sets forth, for the quarters indicated, the high and low sales
prices since consummation of the Combination on May 28, 1998 and dividends
declared per share for the periods indicated:
1998 High Low Dividends Per Share
- ------------------------------------------ ---------- ----------- ---------------------
Second Quarter (beginning May 28, 1998) 34 3/16 29 1/8 $0.445
Third Quarter 30 3/4 25 3/8 $0.445
Fourth Quarter 32 1/4 28 11/16 $0.445
31
ITEM 6. SELECTED FINANCIAL DATA
(In Thousands of Dollars, Except Per Share Data)
====================================================================================================================================
NINE MONTHS 12 Months 12 Months
ENDED Ended Ended Year Ended Year Ended
DECEMBER 31, 1998 March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995
- ------------------------------------------------------------------------------------------------------------------------------------
INCOME SUMMARY
OPERATING REVENUES
Gas distribution $849,543 $645,659 $672,705 $684,260 $591,114
Gas exploration and production 70,812 - - - -
Electric services 408,305 - - - -
Electric distribution 330,011 2,478,435 2,464,957 2,466,435 2,484,014
Other 63,181 - - - -
- -------------------------------------------------------------------------------------------------------------------------------
TOTAL OPERATING REVENUES 1,721,852 3,124,094 3,137,662 3,150,695 3,075,128
OPERATING EXPENSES
Purchased gas 318,703 299,469 308,400 322,641 264,282
Fuel and purchased power 91,762 658,338 646,448 640,610 570,697
Operation and maintenance 848,671 511,165 489,868 499,211 511,393
Depreciation, depletion and amortization 294,864 169,770 154,921 171,681 145,357
Electric regulatory amortization (40,005) 13,359 121,694 97,698 195,936
General taxes 257,124 466,326 469,561 472,076 447,507
Federal income taxes (62,506) 237,371 210,610 210,197 208,338
- -------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 13,239 768,296 736,160 736,581 731,618
OTHER INCOME AND DEDUCTIONS
Transaction related expenses
(net of $99,701 income tax) (107,912) - - - -
Interest income and other- net 37,314 (1,583) 21,468 27,512 43,703
Minority interest 29,141 - - - -
Interest charges (138,715) (404,473) (435,219) (447,629) (472,035)
- -------------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) (166,933) 362,240 322,409 316,464 303,286
Dividends on preferred stock 28,604 51,813 52,113 52,216 52,620
- -------------------------------------------------------------------------------------------------------------------------------
EARNINGS (LOSS) FOR COMMON STOCK ($195,537) $310,427 $270,296 $264,248 $250,666
Foreign currency adjustment (952) - - - -
===============================================================================================================================
COMPREHENSIVE INCOME (LOSS) ($196,489) $310,427 $270,296 $264,248 $250,666
===============================================================================================================================
FINANCIAL SUMMARY
Common stock information
Per share
Earnings ($) (1.34) 2.56 2.24 2.20 2.10
Cash dividends declared ($) 1.19 1.78 1.78 1.78 1.78
Book value, year-end ($) 20.90 21.88 21.07 20.89 20.50
Market value, year-end ($) 31.00 31.50 24.00 22.13 16.38
Shareholders 103,239 78,314 77,691 86,607 93,088
Capital expenditures ($) 676,563 297,230 294,943 291,618 314,175
Total assets ($) 6,895,102 1,900,725 11,849,574 12,209,679 12,527,597
Common equity ($) 3,022,908 2,662,447 2,549,049 2,523,369 2,452,953
Long term-debt ($) 1,619,067 4,381,949 4,457,047 4,456,772 4,706,600
Total capitalization ($) 5,089,948 7,606,996 7,708,194 7,682,305 7,863,037
===============================================================================================================================
UTILITY OPERATING STATISTICS
Gas data ( MDTH)
Firm gas and transportation sales 87,179 58,304 60,276 62,375 58,704
Other sales 38,088 21,025 19,838 16,588 18,028
Maximum daily capacity, year end 2,033,000 745,000 772,000 771,995 717,035
Total active gas meters 1,610,202 464,563 458,910 457,809 453,529
Gas heating customers 665,000 295,000 289,000 286,000 280,000
===============================================================================================================================
32
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
MarketSpan Corporation d/b/a KeySpan Energy (the "Company") is the successor to
Long Island Lighting Company ("LILCO") as a result of a transaction with the
Long Island Power Authority ("LIPA") (the "LIPA Transaction") and following the
acquisition (the "KeySpan Acquisition") of KeySpan Energy Corporation ("KSE").
Both transactions occurred on May 28, 1998. (See Note 2 to the Consolidated
Financial Statements, "Sale of LILCO Assets, Acquisition of KeySpan Energy
Corporation and Transfer of Assets and Liabilities to the Company" for
additional information.) The Company is a "predominately intrastate" public
utility holding company exempt from most of the provisions of the Public Utility
Holding Company Act of 1935, as amended.
Further, subsequent to these events, the Company changed its fiscal year end
from March 31 to December 31. Current period consolidated results of operations,
therefore, are reported for 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 prior to the LIPA Transaction and KeySpan Acquisition; and
(ii) the period May 29, 1998 through December 31, 1998, which represents the
results of the fully consolidated Company, which includes all KSE acquired
companies, KeySpan Gas East Corporation d/b/a Brooklyn Union of Long Island
("Brooklyn Union of Long Island"), which provides gas distribution services on
Long Island and other subsidiaries providing services to LIPA under various
services agreements with LIPA. As required under purchase accounting rules, the
results for periods prior to May 29, 1998 reflect results of LILCO only, and do
not include results of KSE.
As discussed in more detail below, the Transition Period being reported is not
comparable either in time frame or composition of the Company's operations to
any prior historical period. The analysis that follows is an explanation of
consolidated results of operations during the Transition Period and an
explanation of results of operations applicable to the operations of LILCO for
the twelve month periods ended March 31, 1998 and 1997 and December 31, 1996.
Further, the results of operations reported herein are not indicative of future
results or operating trends.
EARNINGS
Consolidated results for the Transition Period reflected a loss of $195.5
million, or $1.34 per share. During the Transition Period, the Company incurred
substantial non-recurring charges associated with the LIPA Transaction. These
non-recurring charges principally reflected the following: taxes associated with
the sale of assets (the "Transferred Assets") to the Company by LIPA; the
write-off of certain regulatory assets that were no longer recoverable under the
various LIPA agreements; and other transaction costs incurred to consummate the
LIPA Transaction. These charges were partially offset 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, and tax benefits recognized on the
funding of certain postretirement benefits. These non-recurring charges
associated with the
33
LIPA Transaction were $107.9 million after-tax, or $0.74 per share.
Further, during the Transition Period, the Company also incurred special charges
amounting to $83.5 million after-tax, or $0.57 per share. These items were: (i)
a $42 million after-tax, or $0.29 per share, charge for an early retirement
program implemented in December 1998 in which approximately 600 employees
participated; and (ii) a $41.5 million after-tax, or $0.28 per share, charge
associated with the write-off of a customer-billing system that was in
development.
Also, in December 1998, the Company made a $20 million donation ($13 million
after-tax, or $0.09 per share) to establish the KeySpan Foundation, a
not-for-profit philanthropic foundation that will make donations to local
charitable community organizations. Earnings also reflected an after-tax
non-cash impairment charge recorded in December 1998 of $54.1 million, or $0.37
per share, which represents the Company's share of the impairment charge
recorded by its gas exploration and production subsidiary, The Houston
Exploration Company ("THEC"), to recognize the effect of low wellhead prices on
its valuation of proved gas reserves.
Consolidated income available for common stock, excluding the non-recurring and
special charges discussed above, by reporting segment, for the Transition Period
and for the twelve months ended March 31, 1998 and 1997 and December 31, 1996 is
set forth in the following summary:
(IN THOUSANDS OF DOLLARS)
- --------------------------------------------------------------------------------------------------------
For the Transition Period For the Twelve Months Ended
- --------------------------- --------------------------------------- --------------------------------
Prior to the Subsequent to
Acquisition the Acquisition Total 3/31/98 3/31/97 12/31/96
- --------------------------- ----------- -------------- ----------- -- ---------- ---------- ----------
Income (Loss) Available for
Common Stock:
Gas Distribution $(4,659) $ 13,241 $ 8,582 $ 33,815 $ 41,621 $ 38,471
Electric Services 45,141 11,978 57,119 276,612 228,675 225,777
Gas Exploration and Production - 2,218 2,218 - - -
Energy Related Investments - (4,186) (4,186) - - -
Energy Related Services - (3,708) (3,708) - - -
Other - 2,959 2,959 - - -
Total Consolidated $40,482 $22,502 $62,984 $310,427 $270,296 $264,248
- --------------------------- ----------- -------------- ----------- -- ---------- ---------- ----------
The Gas Distribution segment consists of The Brooklyn Union Gas Company
("Brooklyn Union") and Brooklyn Union of Long Island, the Company's two gas
distribution subsidiaries. These subsidiaries provide natural gas to customers
in the New York City boroughs of Brooklyn, Queens and Staten Island and the Long
Island counties of Nassau and Suffolk and the Rockaway Peninsula of Queens
County, respectively. Gas Distribution segment earnings, excluding special
charges for the Transition Period, reflected the fact that gas utility customers
received the benefit of synergy savings-related rate reductions, authorized by
the Public Service Commission of the State of New York ("NYPSC"), before synergy
savings could begin to be achieved through cost reduction measures. The Company
expects that the effect of these rate reductions will begin to be offset in
34
fiscal 1999 as synergy savings are realized through cost reduction measures,
principally the early retirement program implemented in December 1998. Most
importantly, earnings for the Transition Period do not include earnings from
heating season operations (months of January through March) when the Company
realizes the major portion of its gas related earnings.
The Electric Services segment consists of subsidiaries that: (i) own and operate
oil and gas-fired generating facilities located on Long Island and deliver the
power generated by these facilities to LIPA; (ii) manage and operate LIPA's
transmission and distribution ("T&D") system; and (iii) manage LIPA's fuel and
electric purchases and any off-system sales. Earnings for the Electric Services
segment for the period May 29, 1998 through December 31, 1998, excluding special
charges, reflected service-fees under various service contracts with LIPA. The
Company's operating margins under such arrangements are lower than those
experienced prior to the LIPA Transaction, reflecting the change in the nature
of the Company's Electric Services business.
Earnings for Electric Services for the period April 1, 1998 through May 28, 1998
were positively impacted by a change in the method of recording the monthly Rate
Moderation Component ("RMC") amortization. As a result of this change, for the
period April 1, 1998 through May 28, 1998, the Company recorded $51.5 million
more of non-cash RMC credits to income, or $33.5 million after-tax, than it
would have under the previous method. For a further discussion, see "Operating
Expenses."
The Gas Exploration and Production segment consists of the Company's 64% equity
interest in THEC, an independent natural gas and oil exploration company with
properties located in the Gulf of Mexico, Texas, the Arkoma Basin of Oklahoma
and Arkansas, South Louisiana and West Virginia. Earnings associated with Gas
Exploration and Production, excluding special charges, were significantly
affected by low gas prices during the Transition Period and increased operating
expenses due primarily to increased production activity. See "Revenues - Gas
Exploration and Production" for further discussion.
The Energy Related Investments segment primarily consists of the Company's 20%
investment in the Iroquois Gas Transmission System LP, investments in The
Premier Transco Pipeline and Phoenix Natural Gas in Northern Ireland and
investments in certain midstream natural gas assets in Western Canada owned
jointly with Gulf Canada Resources Limited. The Company recently has increased
its investment in The Premier Transco Pipeline, a gas pipeline extending from
Scotland to Northern Ireland, from a 24.5% interest to a 50% interest. In
addition, the Company has a 24.5% interest in Phoenix Natural Gas, which is
expanding and refurbishing the gas distribution system that serves the City of
Belfast in Northern Ireland. Results from these investments reflect the start-up
nature of their operations, while results relating to the Company's investment
in the Iroquois Gas Transmission System LP are consistent with management's
expectations. The Company completed its acquisition of a 50% interest in certain
midstream natural gas assets in Western Canada in December 1998, and therefore,
earnings from this investment will begin to be realized in 1999. (See "Liquidity
and Capital Resources" for additional information.) Results also reflected costs
of approximately $5.2 million after-tax to settle certain contracts associated
with the sale of the
35
Company's domestic cogeneration investments and fuel management operations,
which took place in 1997.
The Company's Energy Related Services segment primarily includes KeySpan Energy
Management Inc. ("KEM"), KeySpan Energy Services Inc. ("KES") and KeySpan Energy
Solutions, LLC ("KESol"). KEM provides a variety of technical and maintenance
services to customers that operate commercial and industrial facilities located
primarily within the New York City metropolitan area. Results from operations of
KEM were profitable during the Transition Period and reflected the continued
integration of companies acquired during the past two years. KES markets gas and
electricity, and arranges transportation and related services, largely to retail
customers, including those served by the Company's two gas distribution
subsidiaries. KES incurred losses related to the start-up nature of its
operations during the Transition Period. Results from operations of KESol, which
provides appliance repair service to residential customers primarily within the
Company's service territory, were also unprofitable during the Transition
Period. The Company will continue to realign these non-utility operations to
maximize earnings potential, and where appropriate, possibly discontinue
non-profitable activities.
Results reflected in the Other segment, excluding special charges, include
interest income earned on investments from the proceeds of the LIPA Transaction,
offset, in part, by costs incurred by the corporate and administrative areas of
the Company that have not been allocated to the various business segments.
Gas Distribution results were affected by warmer than normal weather for the
twelve months ended March 31, 1998 and 1997. Gas Distribution results for the
year ended December 31, 1996 were positively affected by colder than normal
weather, a 3.2% rate increase which became effective December 1, 1995 and
increased off-system sales. Results from electric operations for the year ended
March 31, 1998 were positively affected by the change in the method of
amortizing the RMC to eliminate the effects of seasonality on monthly operating
income (See "Operating Expenses" for additional details on the RMC). Earnings
for the twelve months ended March 31, 1997 and for the year ended December 31,
1996 were favorably affected by the benefits derived from increased investment
in electric plants, continued efforts to reduce operations and maintenance
expenses and the use of cash generated by operations to retire maturing debt.
36
REVENUES
Set forth below are the Company's revenues for the Transition Period and for the
twelve months ended March 31, 1998 and 1997 and December 31, 1996:
(IN THOUSANDS OF DOLLARS)
- ------------------------------------------------------------------------------------------------------
For the Transition Period For the Twelve Months Ended
- --------------------- ----------------------------------------- ----------------------------------
Prior to the Subsequent to
Acquisition the Acquisition Total 3/31/98 3/31/97 12/31/96
- --------------------- ------------ --------------- ------------ - ---------- ---------- ----------
Operating revenues:
Gas distribution $ 79,979 $ 769,564 $ 849,543 $ 645,659 $ 672,705 $ 684,260
Gas exploration and - 70,812 70,812 - - -
Production
Electric services - 408,305 408,305 - - -
Electric distribution 330,011 - 330,011 2,478,435 2,464,957 2,466,435
Other - 63,181 63,181 - - -
$409,990 $1,311,862 $1,721,852 $3,124,094 $3,137,662 $3,150,695
- --------------------- ------------ --------------- ------------ - ---------- ---------- ----------
GAS DISTRIBUTION
Gas Distribution revenues for the Transition Period were impacted by rate
reductions which were reflected at the time of the KeySpan Acquisition. Brooklyn
Union reduced rates to its core customers by $23.9 million on an annual basis
effective May 29, 1998 and Brooklyn Union of Long Island 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. Gas Distribution
revenues for the Transition Period do not include revenues from heating season
operations (January through March). In addition, revenues of Brooklyn Union are
not reflected for periods prior to the KeySpan Acquisition. The effects of
weather on gas distribution revenues are largely mitigated by the weather
normalization adjustment included in the tariffs of both gas distribution
utilities. The weather normalization adjustment contained in Brooklyn Union's
tariff provides for the Company to retain or absorb 12.8% of differences between
actual margin revenues and margin revenues that would be produced under normal
weather conditions. The weather normalization adjustment contained in Brooklyn
Union of Long Island's tariff requires the Company to retain or absorb
variations in margin revenues to the extent that actual heating degree days
experienced during a billing cycle vary from normal heating degree days for that
cycle by 2.2%.
Gas Distribution revenues for the twelve months ended March 31, 1998 and 1997
and December 31, 1996 reflected the continued growth in the number of gas
heating customers in all periods. However, Gas Distribution revenues for the
twelve months ended March 31, 1998 and 1997 were affected by warmer than normal
weather during both periods. Revenues for the twelve months ended December 31,
1996 reflected the effects of colder than normal weather during that time period
as well as the growth in the number of gas heating customers. Gas Distribution
revenues for the twelve months ended December 31, 1996 also reflected a 3.2% gas
rate increase that became effective on December 1, 1995.
37
GAS EXPLORATION AND PRODUCTION
Gas Exploration and Production revenues reflected the continued development of
natural gas properties acquired by THEC during the past three years. The
benefits derived from increased production levels, however, were offset by
decreases in average realized prices. In 1998, production was approximately 62.8
billion cubic feet (BCFe), or 11.5 BCFe above the level of production for 1997.
In 1998, wellhead prices averaged approximately $1.96 per MCF compared with
$2.45 per MCF in 1997. The effective price realized (average wellhead price
received for production including recognized hedging gains and losses) was $2.02
per MCF in 1998 compared with $2.25 per MCF in 1997.
ELECTRIC SERVICES
Revenues for the Transition Period are derived from service agreements with LIPA
for the period May 29, 1998 through December 31, 1998. Prior to the LIPA
Transaction, LILCO provided fully integrated electric service to its customers.
Included within rates charged to customers was the return on the capital
investment in the generation and T&D assets, as well as recovery of the electric
business costs to operate the system. Upon completion of the LIPA Transaction,
the nature of the Company's electric business has changed from that of owner of
an electric generation and T&D system, with significant capital investment, to a
new role as owner of the non-nuclear generation facilities and as manager of the
T&D system now owned by LIPA. In its new role, the Company's capital investment
is significantly reduced and accordingly, its revenues under the LIPA contracts
reflect that reduction. Revenues after May 28, 1998 reflect the impact of the
LIPA agreements which contribute marginally to earnings.
Revenues realized under the Management Services Agreement ("MSA") were $226.3
million for the period May 29, 1998 through December 31, 1998. These revenues
were derived from the performance of the day-to-day operation and maintenance of
LIPA's T&D system, management of construction additions to the T&D system, and
the management of LIPA's interest in the Nine Mile Point Nuclear Power Station,
Unit 2 ("NMP2").
Revenues under the Power Supply Agreement ("PSA"), including incentives earned,
were $178.3 million for the period May 29, 1998 through December 31, 1998 and
were derived from the sale of capacity and energy to LIPA from the Company's
generating facilities at rates approved by the Federal Energy Regulatory
Commission.
Revenues under the Energy Management Agreement ("EMA"), including incentives
earned, were $3.7 million for the period May 29, 1998 through December 31, 1998
and resulted from the management of fuel supplies for LIPA to fuel the Company's
generating facilities and the management of energy purchases on a least-cost
basis to meet LIPA's needs.
See "Electric Services-LIPA Agreements" for a more detailed description of each
of these agreements.
38
ELECTRIC DISTRIBUTION
Electric revenues for the period April 1, 1998 through May 28, 1998 fluctuated
mainly as a result of system growth, and variations in weather and fuel costs.
However, these variations had no impact on earnings due to the electric rate
structure in effect at that time, which included a revenue reconciliation
mechanism to eliminate the impact on earnings caused by sales volumes that were
above or below adjudicated levels. Base electric rates were unchanged since
December 1993.
OTHER REVENUES
Other revenues for the Transition Period primarily included revenues of the
Company's energy management subsidiary, KEM, and the Company's marketing
subsidiary, KES. KEM provides a variety of services in all facets of energy
management services to customers that operate commercial and industrial
facilities, primarily within the New York City metropolitan area. Revenues have
been enhanced through the continued integration of an engineering firm, and
heating, ventilation and air conditioning companies purchased during the past
two years. KES markets gas and electricity, and arranges transportation and
related services, largely to retail customers, and has been expanding its
customer base.
OPERATING EXPENSES
GAS PURCHASED
Variations in gas costs have little impact on operating results as the current
gas rate structure of each of the Company's two gas distribution utilities
include a gas adjustment clause pursuant to which variations between actual gas
costs and gas cost recoveries are deferred and subsequently refunded to, or
collected from customers.
The cost of gas for the Transition Period was $318.7 million, reflecting the
inclusion of gas costs for KSE subsequent to May 28, 1998, offset, in part, by
warmer than normal weather and the fact that the Transition Period covers only
nine months. The cost of gas for the twelve months ended March 31, 1998 and 1997
was $299.5 million and $308.4 million, respectively, and reflected warmer than
normal weather in both periods. The cost of gas for the year ended December 31,
1996 was $322.6 million and reflected colder than normal weather during that
time period. The average cost of gas has decreased in 1998 as compared to
increases in 1997 and 1996.
FUEL AND PURCHASED POWER
Electric fuel expense for the period April 1, 1998 through May 28, 1998 was
$91.8 million. In accordance with the EMA, LIPA is responsible for paying
directly the costs of fuel and purchased power and, as a result, the Company,
since May 29, 1998, no longer incurs any electric fuel expense.
Electric fuel expenses for the twelve months ended March 31, 1998 and 1997 and
December 31, 1996 were $658.3 million, $646.4 million and $640.6 million,
respectively. Electric fuel expense in all periods reflected growing system
sales quantities in each period and increased cost of fuel and purchased power
each year. Variations in fuel and purchased power costs had little impact on
39
operating results during these periods as LILCO's electric rate structure
included a mechanism that provided for the recovery or refund of actual fuel
costs which varied from the level collected in rates.
OPERATIONS AND MAINTENANCE EXPENSE
Operations and maintenance expense for the Transition Period was $848.7 million
and included $63.8 million of costs associated with the write-off of a customer
billing system that was in development. Additionally, in December 1998 the
Company completed an early retirement program in which approximately 600
employees elected early retirement and a related expense of $64.6 million was
charged to operations. Moreover, for the Transition Period, operations and
maintenance expense included the costs associated with the management of the T&D
assets acquired by LIPA. Prior to the LIPA Transaction, all T&D related capital
costs were capitalized and charged to depreciation expense over the estimated
useful life of the related asset. Since the LIPA Transaction, all T&D related
costs are expensed when incurred and recovered from LIPA through monthly
billings.
Operation and maintenance expense for the twelve months ended March 31, 1998 and
1997 and December 31, 1996 was $511.2 million, $489.9 million and $499.2
million, respectively. Reflected in all periods were the on-going cost
containment programs implemented by LILCO which resulted in reductions to
maintenance, distribution, and administrative and general expenses. However, for
the twelve months ended March 31, 1998, operation and maintenance expense also
reflected the recognition of higher performance-based employee incentives and
certain other charges for employee benefits.
ELECTRIC REGULATORY AMORTIZATIONS
Prior to the LIPA Transaction, the RMC included within electric regulatory
amortizations represented the difference between LILCO's revenue requirements
under conventional ratemaking and the revenues provided by its electric rate
structure. The RMC was adjusted for the operation of the Fuel Moderation
Component ("FMC") mechanism and the difference between LILCO's share of actual
operating costs at NMP2 and amounts provided for in electric rates.
In April 1998, the NYPSC authorized a revision, effective December 1, 1997, to
LILCO's method of recording its monthly RMC amortization from a straight-line
levelized basis over LILCO's rate year, to a monthly amortization based upon
each month's forecasted revenue requirement, which more closely aligned such
amortization with LILCO's cost of service. As a result of this change, for the
period April 1, 1998 through May 28, 1998, LILCO recorded $51.5 million more of
non-cash RMC credits to income (representing accretion of the RMC balance), or
$33.5 million after-tax, than it would have under the previous method. In
addition, for the year ended March 31, 1998, LILCO recorded approximately $65.1
million more of non-cash RMC credits to income, or $42.5 million after-tax, than
it would have under the previous method. In connection with the LIPA
Transaction, which included the sale of electric related regulatory assets, the
RMC and all other electric regulatory amortizations were discontinued. Had the
RMC amortization continued, the total RMC amortization for the rate year ended
November 30, 1998, would have been equal to the amount that would have been
provided for under the previous method.
40
OTHER OPERATING EXPENSES
Depreciation and depletion expense reflected gas utility property and electric
generation property additions for all periods and electric T&D property
additions for the periods prior to the LIPA Transaction. In addition, for the
period May 29, 1998 through December 31, 1998, depreciation and depletion
expense reflected the gas production activities of the Company's gas exploration
and production subsidiary. This subsidiary 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 applicable to gas exploration and development operations
accounted for under the full cost method. Offsetting these increases is the
effect on depreciation expense from the sale of T&D assets and nuclear
generation assets to LIPA.
Operating taxes principally included state and local taxes on utility revenues
and property. The applicable property base and tax rates generally have
increased in all periods. However, significant property related assets were sold
to LIPA as part of the LIPA Transaction and, as a result, subsequent to May 28,
1998, property taxes on the sold assets are no longer incurred by the Company.
For the twelve months ended March 31, 1998, operating taxes reflected the
expiration of a temporary corporate surcharge on revenues previously imposed by
New York State.
Federal income tax expense in all years reflected changes in pre-tax income.
Pre-tax income and the related federal income tax expense for the Transition
Period were significantly affected by the write-off of a customer billing
system, charges related to the early retirement program, charges related to the
LIPA Transaction, and the write-down of proved gas reserves. (See Note 3 to the
Consolidated Financial Statements, "Federal Income Tax.")
OTHER INCOME AND DEDUCTIONS
Other income and deductions for the Transition Period primarily reflected the
non-recurring charges associated with the LIPA Transaction of $107.9 million
after-tax and a $13 million after-tax charge for the funding of the KeySpan
Foundation. (See Note 11 to the Consolidated Financial Statements, "Costs
Related to the LIPA Transaction and Special Charges.") These charges were
offset, in part, by earnings of $49.2 million from the investment of the
proceeds from the LIPA Transaction and earnings from the Company's equity
investment in the Iroquois Gas Transmission System LP.
Other income and deductions for the twelve months ended March 31, 1998 primarily
included a charge of $31 million with respect to certain benefits earned by
former officers of LILCO offset by carrying charges on certain of the Company's
electric regulatory assets resulting from electric ratemaking mechanisms. Other
income and deductions for the year ended December 31, 1996 consisted primarily
of non-cash carrying charge income associated with regulatory assets.
INTEREST EXPENSE
As part of the LIPA Transaction, LIPA has assumed substantially all of the
outstanding debt of LILCO. The Company, in connection with the LIPA Transaction,
issued promissory notes to LIPA
41
for its continuing obligation to pay principal and interest on certain series of
debt that has been assumed by LIPA . (See Note 7 to the Consolidated Financial
Statements, "Long Term Debt," for additional information.) Interest expense of
$138.7 million for the Transition Period reflected the significantly reduced
level of outstanding debt resulting from the LIPA Transaction.
Interest expense for the twelve months ended March 31, 1998 and 1997 was $404.5
million and $435.2 million, respectively. Interest expense in both periods
reflected the lower outstanding debt level resulting from the retirement of $250
million of indebtness in February 1997. For the twelve months ended December 31,
1996, interest expense was $447.6 million reflecting increased letter of credit
and commitment fees associated with a change in LILCO's credit rating in 1996.
LIQUIDITY AND CAPITAL RESOURCES
LIQUIDITY
At December 31, 1998, the Company had cash and temporary cash investments of
$942.8 million. Effective January 1, 1999, the Company has available unsecured
bank lines of credit of $300 million.
In addition, THEC also has an available line of credit of $150 million with a
commercial bank. At December 31, 1998, $133 million was outstanding under this
facility. Moreover, in March 1998, THEC issued $100 million of 8.625% Senior
Subordinated Notes due 2008 that are subordinate to borrowings under THEC's line
of credit. (See Note 7 to the Consolidated Financial Statements, "Long Term
Debt," for additional information.)
Prior to the LIPA Transaction, LILCO had available, through October 1, 1998,
$250 million under its Revolving Credit Agreement, of which $100 million was
borrowed for interim financing. In addition, LILCO had a bridge loan of $250
million to fund certain obligations for postretirement benefits other than
pensions. A portion of the proceeds from the LIPA Transaction was used to repay
the $350 million of borrowings and the Revolving Credit Agreement was
terminated.
During 1998, KSE had an available bank line of credit of $150 million, which was
available to finance commercial paper for Brooklyn Union. This line of credit
applied jointly to KSE and Brooklyn Union. Effective December 31, 1998, this
line of credit terminated. There were no outstanding borrowings on this line
from May 29, 1998 through December 31, 1998.
As a result of the LIPA Transaction, the Company has a significant amount of
cash which it has used and intends to continue to use for, among other things,
the repurchase of shares of its common stock on the open market (as discussed in
greater detail below) and the expansion of its operations through one or more of
the following types of transactions: mergers with or acquisitions of other
utilities; investments in new gas pipelines (and related assets such as storage
fields and processing plants) and gas exploration; or the purchase and/or
construction of additional electric power plants. However, no assurance can be
given that any of the foregoing types of transactions will occur or that such
transactions, if completed, will be integrated with the Company's operations or
prove to be profitable.
42
In August 1998, the Company announced that the Board of Directors authorized the
purchase of up to 10 percent of the Company's outstanding common stock, or
approximately 15 million shares, through open market purchases. In addition, on
October 30, 1998, the Company announced that the Board of Directors authorized
using up to an additional $500 million of cash for the purchase of common shares
in addition to the Board's previous authorization. Purchases from the initial
authorization commenced on August 17, 1998. As of February 28, 1999, the Company
repurchased 15.9 million of its common shares for $472.5 million.
In December 1998, the Company acquired, through a subsidiary a 50% interest in
certain midstream natural gas assets owned by Gulf Canada Resources Limited
("Gulf Canada") in western Canada and formed a partnership with Gulf Canada
called Gulf Midstream Services Partnership ("GMS"). The Company paid Gulf Canada
$189 million and has provided a three-year $64.8 million loan on commercial
terms that, at Gulf Canada's option, can be repaid or exchanged for an
additional 19.7% interest in GMS. In connection with this investment, the
Company has agreed to fund capital expenditures of GMS for the next three years
up to a maximum of $36 million including Gulf Canada's share, in exchange for a
proportionately increased share of GMS's cash flow.
In December 1998, the Company, through a subsidiary, paid $32 million to
increase its investment in The Premier Transco Pipeline from 24.5% to 50%. In
addition, during the quarter ended December 31, 1998 the Company provided THEC
with a $150 million line of credit. As of December 31, 1998 THEC had borrowed
$80 million under this facility, which was used to fund a substantial portion of
the acquisition of three producing offshore blocks in the Mustang Island region
of the Gulf of Mexico. Further, in December 1998, the Company made a $20 million
donation to establish the KeySpan Foundation, a not-for-profit philanthropic
foundation that will make donations to various charitable organizations.
In May 1998, LILCO reached a settlement with the Internal Revenue Service
resolving all audit issues on federal income tax returns filed for the years
1981 through 1989. The settlement required the payment of taxes and interest of
$9 million and $35 million, respectively. Adequate reserves for the payment of
such taxes and interest were provided in prior fiscal years.
The negative cash flow from operating activities for the Transition Period is
due primarily to the fact that significant positive cash flows that arise from
revenues generated during a heating season have not been reflected in the
Transition Period. Approximately 75% of total annual gas revenues are realized
during the heating season (November 1 to April 30) as a result of the large
proportion of heating sales, primarily residential, compared to total sales.
Moreover, during the Transition Period, the Company funded an additional $250
million into Voluntary Employee's Beneficiary Association trusts (see Note 4 to
the Consolidated Financial Statements, "Postretirement Benefits"). Annual cash
flow from core utility operations has remained strong and should continue to
provide the Company with a substantial source of funds.
43
CAPITAL RESOURCES
Consolidated capital expenditures for the Transition Period were $676.5 million
and are estimated to be $1.2 billion for the year ended December 31, 1999.
Capital expenditures related to the Gas Distribution segment were $128.4 million
during the Transition Period and were primarily for the renewal and replacement
of mains and services and expansion of the gas distribution system on Long
Island. Gas Distribution capital expenditures are estimated to be $205.7 million
for 1999.
Capital expenditures related to Electric Services were $54.1 million during the
Transition Period and were primarily for the renewal and replacement of electric
lines prior to May 28, 1998. Capital expenditures for 1999 are estimated to be
$684.4 million including approximately $597 million related to the Company's
January 1999 agreement with Consolidated Edison Company of New York, Inc. to
purchase the 2,168 megawatt Ravenswood electric generating facility. This
facility, located in Long Island City, Queens, includes the 1,753 megawatt
Ravenswood Generating Station and the 415 megawatt Ravenswood Gas Turbines.
Common plant capital expenditures were $51.1 million during the Transition
Period and are estimated to be $28.4 million for 1999.
Capital expenditures related to Gas Exploration and Production were $182.7
million for the Transition Period. These capital expenditures reflected, in
part, costs related to development of additional properties acquired in Southern
Louisiana and properties acquired in the Gulf of Mexico and costs related to the
continued development of property additions acquired in 1997 and 1996. Capital
expenditures for 1999 are estimated to be $126.6 million, which includes $81.9
million related to the Company's share of costs for developmental and
exploratory drilling and $44.7 million related to the Company's March 1999 joint
venture agreement with THEC to explore for natural gas and oil over a term of
three years. Under the terms of this agreement, the Company will acquire 45% of
THEC's interest in certain offshore undeveloped leases and will commit up to
$100 million per year to explore and develop these leases.
Capital expenditures related to equity investments in Energy Related Investments
during the Transition Period were $231.8 million. These capital expenditures
included $42 million of equity investments primarily to increase the Company's
interest in The Premier Transco Pipeline. The Company also has a 24.5% interest
in a gas distribution system in Northern Ireland that is being refurbished and
expanded. Also included in capital expenditures for the Transition Period is
$189 million of equity investments related to the formation of a partnership
with Gulf Canada, discussed previously. Capital expenditures for 1999 are
estimated to be $84.7 million, including the Company's share of capital
expenditures in GMS of $12 million and costs related to the first stage of a
joint venture with Duke Energy Corporation and the Williams Companies in
developing the Cross Bay(sm) pipeline, which will transport gas from existing
interstate pipelines in New Jersey to New York City and Long Island.
Capital expenditures of $28.4 million for the Transition Period related to
Energy Related Services reflected primarily the acquisition of a heating,
ventilating and air-conditioning ("HVAC") company.
44
The HVAC company, located in New Jersey, designs, builds, installs and services
HVAC systems for commercial and residential customers. Through this acquisition
the Company will be able to expand its management and marketing activities into
the middle-market segment. The balance is related to expansion of ongoing
operations of subsidiaries within this segment. Capital expenditures for fiscal
1999 are estimated to be $57.4 million relating to acquisitions and expansion of
ongoing operations.
The level of future capital expenditures is reviewed on an ongoing basis and can
be affected by timing, scope and changes in investment opportunities.
FINANCING
Proceeds from common stock issued through employee and shareholder stock
purchase plans have provided equity of $10.2 million during the Transition
Period.
Prior to the LIPA Transaction, all of the outstanding shares of the following
preferred stock series were called for redemption: Series UU, Series GG, Series
QQ, Series CC, Series B, Series D, Series E, Series F, Series H, Series
I-Convertible, Series L and Series NN. These preferred stock series were
redeemed at an aggregate cost of $363.2 million, including $25.2 million of call
premiums and accrued dividends. On May 28, 1998, LIPA reimbursed the Company
$339.1 million for the preferred stock series that were redeemed. (See Note 5 to
the Consolidated Financial Statements, "Capital Stock," for additional
information.)
Upon consummation of the LIPA Transaction, all of the outstanding long-term
debt, except for the 1997 Series A Electric Facilities Revenue Bonds due
December 1, 2027, was transferred to LIPA. The Company issued promissory notes
to LIPA for $1.048 billion, which represented an amount equivalent to the sum
of: (i) the principal amount of 7.3% Series Debentures due July 15, 1999 and
8.2% 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 to the debt referred to in items (i) and (ii) above.
On November 3, 1998, the Company extinguished a portion of its obligation of the
promissory notes relating to certain series of bonds that were called by LIPA on
December 1, 1998. The Company's obligation for these bonds of $2.1 million
consisted of the principal amount and the interest accrued and unpaid. An
additional portion of the promissory notes was also extinguished on December 1,
1998 due to the mandatory sinking fund redemption of $1 million on a certain
series of Authority Financing Notes.
On March 1, 1999, LIPA converted all of the transferred long-term debt
outstanding at variable rates to fixed rates of 5.15% and 5.30% per annum. As of
March 1, 1999, the remaining debt instruments that include variable rate
features had a carrying value of $149.9 million. If interest rates were to
change on this variable rate debt by 100 basis points, interest expense, net of
tax, would change by less than a million dollars. The rates of each of the
Company's gas utilities reflect the recovery of
45
a fixed level of interest expense and, in addition, the LIPA agreements also
include recovery of a base level of interest expense. (See Note 7 to the
Consolidated Financial Statements, "Long Term Debt" for additional information
on debt obligations.)
In December 1998, the Company purchased a portfolio of securities representing
direct purchase obligations of the U.S. Government. These securities were placed
in trust, irrevocably dedicated to the repayment of certain Gas Facilities
Revenue Bonds ("GFRB"), thereby effecting an in-substance defeasance of
approximately $8.9 million including interest. The in-substance defeasance
represents $4 million of outstanding bonds of each of the 6.75% Series 1989A due
February 2024 and the 6.75% Series 1989B due February 2024. The Company has not
been relieved of its obligation to service the debt and remains the primary
obligor. As a result, the liability is not considered extinguished under
Statement of Financial Accounting Standards ("SFAS") No. 125, "Accounting for
Transfers and Servicing of Financial Assets and Extinguishment of Liabilities."
(See Note 7 to the Consolidated Financial Statements, "Long Term Debt" for
additional information on debt obligations.)
The Company intends to use a combination of existing cash balances and
internally generated cash from operations to the maximum extent practicable to
satisfy stock dividends and on-going enhancements to its gas distribution
system. The Company expects to access the financial markets during 1999 to
satisfy approximately $400 million of maturing debt obligations. With respect to
the acquisition of the Ravenswood facilities discussed previously, the Company
intends to use some form of project financing for approximately $425 million of
the purchase price. To the extent necessary, the Company can issue short-term
commercial paper to finance seasonal working capital requirements and if need
be, the Company has the ability to issue tax-exempt bonds through the New York
State Energy Research and Development Authority.
DIVIDENDS
The Company is currently paying a dividend at an annual rate of $1.78 per common
share. The Company's 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.
Common stock dividends are payable on February 1, May 1, August 1, and November
1. In addition, the Company pays an annual dividend at the rate of $1.9875 per
share on the 7.95% Preferred Stock Series AA. Common and preferred stock
dividend payments made by the Company after June 17, 1998 were a return of
capital for Federal income tax purposes for 1998.
Pursuant to the NYPSC's orders dated February 5, 1998 and April 14, 1998
approving the KeySpan Acquisition, Brooklyn Union's and Brooklyn Union of Long
Island's ability 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
46
is incurred under the customer service performance program. At the end of
Brooklyn Union's and Brooklyn Union of Long Island's rate years, the ratio of
debt to total utility capitalization was 44% and 50%, respectively.
GAS DISTRIBUTION - RATE MATTERS
By orders dated February 5, 1998 and April 14, 1998 the NYPSC approved a
Stipulation Agreement ("Stipulation") 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 Brooklyn Union and
Brooklyn Union of Long Island. Under the Stipulation, $1 billion of efficiency
savings, excluding gas costs, attributable to operating synergies that are
expected to be realized over the 10 year period following the combination, are
to be allocated to ratepayers net of transaction costs.
Under the Stipulation, effective May 29, 1998, Brooklyn Union's base rates to
core customers were reduced by $23.9 million annually. In addition, Brooklyn
Union 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 13.75% for the rate year ended September 30,
1998, 13.50% for the rate years 1999 through 2001, and 13.25% for the rate year
2002. A safety and reliability incentive mechanism was implemented on May 29,
1998, with a maximum 12 basis point pre-tax return on equity penalty if Brooklyn
Union fails to achieve certain safety and reliability performance standards.
The Stipulation also required Brooklyn Union of Long Island 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. Brooklyn Union of Long
Island 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%. Both a customer
service and a safety and reliability incentive performance mechanism were
implemented effective December 1, 1997 with maximum pre-tax return on equity
penalties of 40 and 12 basis points, respectively, if Brooklyn Union of Long
Island fails to achieve certain performance standards in these areas.
As a result of the Stipulation, synergy savings have been reflected in base
rates before they actually will be realized by the Company. As part of an
overall plan to realize the synergy savings, the Company initiated an early
retirement program in December 1998 in which approximately 600 employees
participated. The Company is committed to realizing the $1 billion of operating
synergy savings over a 10-year period through an on-going combination of cost
reductions and increased operating efficiencies. However, no assurance can be
given as to what savings may be obtained from these efforts.
47
ELECTRIC SERVICES - LIPA AGREEMENTS
The Company, through certain of its subsidiaries, provides services to LIPA
under the following agreements:
MANAGEMENT SERVICES AGREEMENT ("MSA")
A Company 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, the Company 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 its performance.
Annual service incentives or penalties exist under the MSA if certain targets
are achieved or not achieved. In addition, the Company 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 the Company 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, the Company 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, the Company has
performed its obligations under the MSA within the agreed to budget guidelines
and the Company is 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 Company subsidiary sells to LIPA all of the capacity and, to the extent
requested, energy from the Company's existing oil and gas-fired generating
plants. Sales of capacity and energy are made with 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 the control of the Company. 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 the Company 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. The Company must, therefore,
operate its generating facilities in a manner such that the Company can remain
competitive with other producers of energy. To date, the Company has 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.
48
In addition, three years after the LIPA Transaction is consummated, LIPA will
have the right for a one-year period to acquire all of the Company's generating
assets included in the PSA at the fair market value at the time of the exercise
of the right, which value will be determined by independent appraisers.
ENERGY MANAGEMENT AGREEMENT ("EMA")
The EMA provides for a Company 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 the Company earns an annual fee of $1.5
million. In addition, the Company will 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 covers a period
of eight years for off-system management services.
ENVIRONMENTAL
The Company will be required to complete the investigation and undertake an
appropriate level of remediation at manufactured gas plant ("MGP") sites
formerly operated by Brooklyn Union (or its predecessors) and LILCO (or its
predecessors). With respect to the Brooklyn Union MGP sites, the Company has
recently completed a Focused Feasibility Study ("FFS") for the Brooklyn Borough
Works Site in Coney Island in accordance with the terms of its Administrative
Order on Consent ("ACO") with the New York State Department of Environmental
Conservation ("DEC"). The FFS identified remedial action alternatives consistent
with potential future commercial re-use of the property in the future; the
Company anticipates finalizing and implementing its choice of a remedial action
alternative in the near future. At the Clifton site in Staten Island, the
Company is in the early stage of its investigation pursuant to its ACO. With
respect to the Citizens site, the Company is waiting for a response from the
City of New York regarding a cost-sharing agreement for the investigation of
that site; although there is no current legal obligation to address this site,
the Company anticipates that a site investigation will likely be undertaken in
the future. Although the Company has identified other former Brooklyn Union MGP
sites to governmental authorities, based upon current information, the Company
does not believe that an obligation to investigate and/or remediate these
properties is likely.
With respect to six of the former LILCO MGP sites, it is anticipated that two
ACO's with the New York DEC will be finalized in the near future. These ACO's
will establish an obligation to investigate and remediate these six properties.
After the execution of the ACO for these six sites, the Company anticipates that
it will enter into further negotiations with the DEC with respect to the
preliminary investigation of other former LILCO MGP sites not currently owned by
the Company.
49
Although it is likely that such a preliminary investigation will be undertaken
in the future, it is not currently known whether there will be an obligation to
remediate any of these properties.
The Company estimates the minimum cost of its MGP-related environmental cleanup
activities will be $130.3 million and has recorded a related liability for such
amount. Further, as of December 31, 1998, the Company has expended $13.7
million.
The Company is awaiting final development of state and federal regulatory
programs with respect to NOX reduction requirements for its existing power
plants. The Company's compliance strategy may be composed of fuel choice
decisions, acquisition of pollution credits, and/or installation of pollution
control equipment. Although the Company is currently considering its
alternatives, final decisions cannot be made until the regulatory requirements
are clarified. Expenditures to implement a final strategy are not expected to
begin until 2001.
Additional capital expenditures associated with the renewal of the surface water
discharge permits for the Company's power plants may be required by the DEC.
Until the final permits are issued, the Company cannot determine what the
monitoring obligations will be, the results of any such monitoring, or the
impact that any required equipment upgrades would have on Company operations.
YEAR 2000 ISSUES
The Company has evaluated the extent to which modifications to its computer
software, hardware and databases will be necessary to accommodate the year 2000.
The Company's computer applications are generally based on two digits and do
require some additional programming to recognize the start of the new
millennium.
System Readiness
A corporate-wide program has been established to review Company software,
hardware, embedded systems and associated compliance plans. The program includes
both information technology ("IT") and non-IT systems. Non-IT systems are
basically vendor supplied embedded systems that are critical to the daily
operations of the Company. These systems are generally in the areas of electric
production, distribution, transmission, gas distribution and communications. The
readiness of suppliers and vendor systems is also under review. The project is
under the direction of the Year 2000 Program Office, chaired by the Vice
President, Technology Operations and Corporate Y2K Officer.
The critical areas of operations are being addressed through a business process
review methodology. Each of the Company's critical business processes is being
reviewed to: identify and inventory sub- components; assess for year 2000
compliance; establish repair plans as necessary; and test in a year 2000
environment. The inventory phase for both the IT systems and non-IT systems is
complete. The total assessment phase is 100% complete for the IT systems, and as
of December 31, 1998, over 90% complete for non-IT systems.
50
Hardware, software and embedded systems are being tested and certified to be
year 2000 ready. As of December 31, 1998, repair and testing was 70% complete
for the IT systems and 22% complete for the non-IT systems. Components needed to
support the critical business processes and associated business contingency
plans are expected to be year 2000 ready by July 1, 1999.
Vendors and business partners needed to support the critical business processes
are also being reviewed for their year 2000 readiness. At this time, none of
these vendors have indicated to the Company that they will be materially
adversely affected by the year 2000 problem.
Risk Scenarios and Contingency Plans
The Company has analyzed each of the critical business processes to identify
possible year 2000 risks. Each critical business process will be certified by
the responsible corporate officer as being year 2000 ready. However, the most
reasonably likely worst case scenarios are also being identified. Business
operating procedures are being reviewed to ensure that risks are minimized when
entering the year 2000 and other high risk dates. Contingency plans are being
developed to address possible failure points in each critical business process,
and are scheduled to be completed by July 1999.
While the Company must plan for the following possible worst case scenarios,
management believes that these events are improbable:
LOSS OF GAS PIPELINE DELIVERY
The Company's gas utility subsidiaries receive gas delivery from multiple
national and international pipelines and therefore the effects of a loss in any
one pipeline can be mitigated through the use of other pipelines. Complete loss
of all the supply lines is not considered a reasonable scenario. Nevertheless,
the impact of the loss of any one pipeline is dependent on temperature and
vaporization rate. Should gas supply be decreased due to the loss of a pipeline,
each of the Company's gas utility subsidiaries also has a local liquefied
natural gas facility under its direct control that stores sufficient gas to
offset the temporary loss of any one pipeline. The partial loss of gas supply
will not affect the Company's ability to supply electricity since most of the
plants have the ability to operate on oil.
LOSS OF ELECTRIC GENERATION OR ELECTRIC TRANSMISSION AND DISTRIBUTION
Electric utilities are physically connected on a regional basis to manage
electric load. This is often referred to as the regional grid. Presently the
Company is working, on behalf of LIPA, with other regional utilities to develop
a coordinated operating plan. Should there be an instability in the grid, the
Company has the ability to remove LIPA's facilities and operate independently.
Certain electric system components such as individual generating units, T&D
control facilities, and the electric energy management system have the potential
to be affected by the year 2000 problem. The Company has inventoried both its
and LIPA's electric system components and developed a plan to certify mission
critical processes as year 2000 ready. As manager of the T&D facilities, the
Company is responsible for ensuring that these facilities operate properly and
that related systems
51
are year 2000 ready. Under the terms of the various LIPA contracts, LIPA will
reimburse the Company for certain year 2000 costs incurred by the Company for
these facilities. Contingency plans are being developed, where appropriate, for
loss of critical system elements. The Company presently estimates that
contingency plans regarding its electric facilities should be completed by July
1999.
LOSS OF TELECOMMUNICATIONS
The Company has a substantial dependency on many telecommunication systems and
services for both internal and external communication providers. External
communications with the public and the ability of customers to contact the
Company in cases of emergency response is essential. The Company intends to
coordinate its emergency response efforts with the offices of emergency
management of the various local governments within its service territory.
Internally, there are a number of critical processes in both the gas and
electric operating areas that rely on external communication providers.
Contingency plans will address methods for manually monitoring these functions
and/or utilizing alternative communication methods. These contingency plans
should be finalized by July 1999.
In addition to the above, the Company is also planning for the following
scenarios: short term reduction in system power generating capability;
limitation to fuel oil operations; reduction in quality of power output; loss of
automated meter reading; loss of ability to read customer meters, prepare bills
and collect and process customer payments; and loss of the purchasing/materials
management system.
The Company believes that, with modifications to existing software and
conversions to new hardware and software, the year 2000 issue will not pose
significant operational problems for its computer systems. However, if such
modifications and conversions are not made, or are not completed on time, and
contingency plans fail, the year 2000 issue could have a material adverse impact
on the operations of the Company, the extent of which cannot currently be
determined.
Cost of Remediation
The Company expects to spend a total of approximately $32 million to address the
year 2000 issue. As of December 31, 1998, $15.8 million had been expended on the
project. The largest percentage expended is attributable to the assessment,
repair and testing of corporate IT supported computer software and in-house
written applications, which total $12.3 million. In 1999, the IT year 2000 costs
are expected to be 8.3% of the IT budget. The year 2000 issue has not directly
resulted in delaying any IT projects. Presently, the Company expects that cash
flow from operations and cash on-hand will be sufficient to fund the year 2000
project expenditures.
52
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK
The Company and its subsidiaries are subject to various risk exposures and
uncertainties associated with their operations. The primary risk exposures are
related to firm gas contracts, financial instruments, various regulatory
initiatives of the NYPSC and FERC, the increasingly competitive energy
environment, and to a lesser extent foreign currency fluctuations. Set forth
below is a description of these exposures and an explanation as to how the
Company and its subsidiaries have managed and, to the extent possible, sought to
reduce these risks.
FIXED CHARGES UNDER FIRM CONTRACTS
The Company's gas utility subsidiaries have entered into various long-term
contracts for gas delivery, storage and supply services in order to provide
sufficient supply for their customers. The contracts have remaining terms that
cover from one to fourteen years. Certain of these contracts require payment of
monthly charges (demand charges) in the aggregate amount of $5.1 million per
month in all events regardless of the level of service available. At this time,
the Company's exposure is minimal since these charges are currently recovered as
gas cost under the respective gas adjustment clauses contained in the tariffs of
the Company's gas utility subsidiaries. The Company does not expect rate
regulation to change in the immediate future regarding recovery of demand
charges; however, the Company is unable to predict the evolution of rate
regulation. In addition, Company subsidiaries have entered into agreements with
Enron Corporation and Coral Energy Resources, LP which provide for these
companies to engage in overall gas supply management arrangements with and on
behalf of the Company.
DERIVATIVE FINANCIAL INSTRUMENTS
The Company's gas utility subsidiaries, marketing and gas exploration and
production subsidiaries employ, from time to time, derivative financial
instruments, such as natural gas and oil futures, options and swaps, for the
purpose of hedging exposure to commodity price risk. At December 31, 1998, the
value at risk of the related positions as measured by the maximum adverse price
movement in a single day was not material.
Whenever hedge positions are in effect, the Company's subsidiaries 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. The Company believes 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 the Company's overall business
risk. (See Note 8 to the Consolidated Financial Statements, "Contractual
Obligations, Financial Instruments and Contingencies.")
REGULATORY ISSUES AND THE COMPETITIVE ENVIRONMENT
The energy industry continues to undergo fundamental changes as regulators,
elected officials and customers seek lower energy prices. These changes, which
may have a significant impact on the future financial performance of utilities,
are being driven by a number of factors including a
53
regulatory environment in which traditional cost-based regulation is seen as a
barrier to lower energy prices.
Over the past few 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 the Company's two gas utility subsidiaries. Large-volume customers
have had this option for a number of years. In addition to transporting gas that
customers purchase from marketers, the Company's 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 ("LDC's") 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. LDC's 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.
The NYPSC has acknowledged that each utility has operating circumstances unique
to its service territory and therefore separation of the merchant and
distributions functions should be done on a utility-by-utility basis. With this
in mind, the NYPSC will institute individual proceedings for each regulated
natural gas utility so that the parties can determine the most effective means
of achieving the NYPSC's goals. In addition, the NYPSC will also institute
generic proceedings to examine reliability and other issues.
The Company conceptually supports the vision articulated in the policy
statement. However, in the Company's view, any transition to a new industry
structure must adequately address a number of unresolved issues to ensure that
separating the merchant and distribution functions is in the best interest of
natural gas customers and is equitable to LDC's. Such issues include: system
reliability, recovery of prudently incurred costs, the obligation to provide
service to all firm customers, tax disparity among suppliers, administrative
overheads, customer acceptance and the obligation to be "supplier of last
resort." Further, the Company will also pursue legislative changes where needed.
The Company currently is not able to determine what effect these changes, if
implemented, may have on its operations.
FOREIGN CURRENCY FLUCTUATIONS
The Company follows the principles of SFAS No. 52, "Foreign Currency
Translation" for recording its investments in foreign affiliates. At December
31, 1998, the foreign currency translation adjustment was immaterial. However,
due to the Company's recent purchase of certain Canadian interests and its
continued and possibly expanded activities internationally, foreign currency
translation adjustments in the future could become material, the magnitude of
which cannot be predicted at this time. (See Note 1 to the Consolidated
Financial Statements, "Summary of Significant Accounting Policies.")
54
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
FINANCIAL STATEMENT RESPONSIBILITY
The Consolidated Financial Statements of the Company and its subsidiaries were
prepared by management in conformity with generally accepted accounting
principles.
The Company'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 the Company. The Company'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, 1998 March 31, 1998
====================================================================================================================
ASSETS
PROPERTY
Electric $ 1,109,199 $ 4,102,166
Gas 3,257,726 1,246,432
Common 345,007 343,341
Accumulated depreciation (1,480,038) (1,877,858)
Gas exploration and production, at cost 994,104 -
Accumulated depletion (447,733) -
- --------------------------------------------------------------------------------------------------------------------
3,778,265 3,814,081
- --------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------
EQUITY INVESTMENTS AND OTHER 341,346 50,816
- --------------------------------------------------------------------------------------------------------------------
CURRENT ASSETS
Cash and temporary cash investments 942,776 180,919
Customer accounts receivable 142,307 321,372
Accrued revenues 178,529 124,464
Other accounts receivable 230,479 43,744
Allowance for uncollectible accounts (20,026) (23,483)
Special deposits 145,684 95,790
Gas in storage, at average cost 145,277 14,634
Fuel oil, at average cost - 32,142
Materials and supplies, at average cost 74,193 54,883
Other 72,818 13,807
- --------------------------------------------------------------------------------------------------------------------
1,912,037 858,272
- --------------------------------------------------------------------------------------------------------------------
DEFERRED CHARGES
Regulatory assets
Electric related - 6,768,148
Other 279,524 163,765
Goodwill 201,887 -
Other 382,043 245,643
- --------------------------------------------------------------------------------------------------------------------
863,454 7,177,556
- --------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 6,895,102 $ 11,900,725
====================================================================================================================
The Notes to Consolidated Financial Statements are an integral part of these
statements.
55
CONSOLIDATED BALANCE SHEET
(In Thousands of Dollars)
====================================================================================================================
DECEMBER 31, 1998 March 31, 1998
====================================================================================================================
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock $ 2,973,388 $ 1,707,559
Retained earnings 474,188 956,092
Accumulated foreign currency adjustment (952) -
Treasury stock purchased (423,716) (1,204)
- --------------------------------------------------------------------------------------------------------------------
Total common shareholders' equity 3,022,908 2,662,447
Preferred stock 447,973 562,600
Long-term debt 1,619,067 4,381,949
- --------------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION 5,089,948 7,606,996
- --------------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES
Current maturities of long-term debt 398,000 101,000
Current redemption requirements of preferred stock - 139,374
Accounts payable and accrued expenses 519,288 318,701
Dividends payable 66,232 58,748
Taxes accrued 69,742 34,753
Customer deposits 29,774 28,627
Interest accrued 19,965 146,607
- --------------------------------------------------------------------------------------------------------------------
1,103,001 827,810
- --------------------------------------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES
Regulatory liabilities
Electric related - 358,363
Other 53,137 31,068
Deferred federal income tax 71,549 2,539,364
Postretirement benefits, claims & other reserves 457,459 467,655
Other 50,457 69,469
- --------------------------------------------------------------------------------------------------------------------
632,602 3,465,919
- --------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------
MINORITY INTEREST IN SUBSIDIARY COMPANY 69,551 -
- --------------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES $ 6,895,102 $ 11,900,725
====================================================================================================================
The Notes to Consolidated Financial Statements are an integral part of these
statements.
56
CONSOLIDATED STATEMENT OF INCOME
(In Thousands of Dollars, Except Per Share Amounts)
- ------------------------------------------------------------------------------------------------------------------------------------
NINE MONTHS Twelve Months Three Months
ENDED Ended Ended Year Ended
DECEMBER 31, 1998 March 31, 1998 March 31, 1997 December 31, 1996
- ------------------------------------------------------------------------------------------------------------------------------------
REVENUES
Gas distribution $ 849,543 $ 645,659 $ 293,391 $ 684,260
Gas exploration and production 70,812 - - -
Electric services 408,305 - - -
Electric distribution 330,011 2,478,435 557,791 2,466,435
Other 63,181 - - -
- ------------------------------------------------------------------------------------------------------------------------------------
Total Revenues 1,721,852 3,124,094 851,182 3,150,695
- ------------------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Purchased gas 318,703 299,469 136,727 322,641
Fuel and purchased power 91,762 658,338 165,140 640,610
Operations 734,957 400,045 95,673 381,076
Maintenance 113,714 111,120 29,340 118,135
Depreciation, depletion and amortization 294,864 169,770 39,820 171,681
Electric regulatory amortizations (40,005) 13,359 19,966 97,698
Operating taxes 257,124 466,326 117,513 472,076
Federal income taxes (credit) (62,506) 237,371 57,002 210,197
- ------------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 1,708,613 2,355,798 661,181 2,414,114
- ------------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 13,239 768,296 190,001 736,581
- ------------------------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND (DEDUCTIONS)
Transaction related expenses (107,912) - - -
(net of $99,701 income tax )
Interest and other-net 37,314 (1,583) 3,574 27,512
Minority interest 29,141 - - -
- ------------------------------------------------------------------------------------------------------------------------------------
Total Other Income and (Deductions) (41,457) (1,583) 3,574 27,512
- ------------------------------------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE INTEREST CHARGES (28,218) 766,713 193,575 764,093
- ------------------------------------------------------------------------------------------------------------------------------------
Interest charges 138,715 404,473 105,878 447,629
- ------------------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) (166,933) 362,240 87,697 316,464
Preferred stock dividend requirements 28,604 51,813 12,969 52,216
- ------------------------------------------------------------------------------------------------------------------------------------
EARNINGS (LOSS) FOR COMMON STOCK $ (195,537) $ 310,427 $ 74,728 $ 264,248
- ------------------------------------------------------------------------------------------------------------------------------------
Foreign currency adjustment (952) - - -
====================================================================================================================================
COMPREHENSIVE INCOME (LOSS) $ (196,489) $ 310,427 $ 74,728 $ 264,248
====================================================================================================================================
Average common shares outstanding (000) 145,767 121,415 120,995 120,360
BASIC AND DILUTED EARNINGS (LOSS) PER COMMON SHARE $ (1.34) $ 2.56 $ 0.62 $ 2.20
====================================================================================================================================
57
CONSOLIDATED STATEMENT OF CASH FLOWS
(In Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------------------------------
NINE MONTHS Twelve Months Three Months
ENDED Ended Ended Year Ended
DECEMBER 31, 1998 March 31, 1998 March 31, 1997 December 31, 1996
- ------------------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net Income (Loss) $ (166,933) $ 362,240 $ 87,697 $ 316,464
ADJUSTMENTS TO RECONCILE NET INCOME TO NET
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES
Depreciation, depletion and amortization 294,864 169,770 39,820 171,681
Regulatory amortization and other (40,005) (10,273) 14,047 72,439
Deferred federal income tax (85,936) 146,859 32,835 167,060
Income from equity investments (5,842) - - -
Dividends from equity investments 4,219 - - -
CHANGES IN ASSETS AND LIABILITIES (NET OF ACQUISITION)
Accounts receivable and accrued revenues (81,024) 8,334 (26,817) 92,334
Pensions and other postretirement benefits (283,774) - - -
Materials and supplies, fuel oil and gas in storage (63,195) 14,391 67,242 (34,531)
Accounts payable and accrued expenses 132,028 (54,835) (69,958) (13,826)
Interest accrued (151,268) (2,624) 16,632 (2,289)
Special deposits (41,040) (58,159) 635 25,146
Other 27,618 98,381 (2,566) 97,835
- ------------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by (Used in) Operating Activities (460,288) 674,084 159,567 892,313
- ------------------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Capital expenditures (676,563) (297,230) (62,479) (291,618)
Net cash from KeySpan Acquisition 165,168 - - -
Net proceeds from LIPA Transaction 2,314,588 - - -
Miscellaneous investment 13,466 (31,987) 160 (4,806)
- ------------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by (Used in) Investing Activities 1,816,659 (329,217) (62,319) (296,424)
- ------------------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Proceeds from sale of common stock 10,170 43,218 4,640 18,837
Treasury stock purchased (423,716) - - -
Issuance of preferred stock 84,973 - - -
Issuance of long-term debt 112,535 - - -
Redemption of long-term debt (103,000) (2,050) (250,000) (419,800)
Preferred stock dividends paid (28,604) (51,833) (12,969) (52,264)
Common stock dividends paid (210,177) (215,790) (53,749) (213,753)
Other (36,695) (2,032) (624) (369)
- ------------------------------------------------------------------------------------------------------------------------------------
Net Cash (Used in) Financing Activities (594,514) (228,487) (312,702) (667,349)
- ------------------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 761,857 116,380 (215,454) (71,460)
====================================================================================================================================
Cash and cash equivalents at beginning of period $ 180,919 $ 64,539 $ 279,993 $ 351,453
Net increase (decrease) in cash and cash equivalents 761,857 116,380 (215,454) (71,460)
- ------------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 942,776 $ 180,919 $ 64,539 $ 279,993
====================================================================================================================================
Interest paid $125,914 $364,864 $112,981 $404,663
Federal income tax paid $94,680 $108,980 - $45,050
The Notes to Consolidated Financial Statements are an integral part of these
statements.
58
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
(In Thousands of Dollars)
==============================================================================================================================
DECEMBER 31, 1998 March 31, 1998 March 31, 1997 December 31, 1996
==============================================================================================================================
Balance at beginning of period $ 956,092 $ 861,751 $ 840,867 $ 790,919
Net income (loss) for period (166,933) 362,240 87,697 316,464
- ------------------------------------------------------------------------------------------------------------------------------
789,159 1,223,991 928,564 1,107,383
- ------------------------------------------------------------------------------------------------------------------------------
Deductions
Cash dividends declared on common stock 214,012 216,086 53,844 214,255
Cash dividends declared on preferred stock 28,604 51,813 12,969 52,240
Other, primarily write-off of 72,355 - - 21
capital stock expense
- ------------------------------------------------------------------------------------------------------------------------------
Balance at end of period $ 474,188 $ 956,092 $ 861,751 $ 840,867
- ------------------------------------------------------------------------------------------------------------------------------
The Notes to Consolidated Financial Statements are an integral part of these
statements.
59
CONSOLIDATED STATEMENT OF CAPITALIZATION
==================================================================================================================================
Shares Issued (In Thousands of Dollars)
- ----------------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1998 March 31, 1998 DECEMBER 31, 1998 March 31, 1998
- ----------------------------------------------------------------------------------------------------------------------------------
COMMON SHAREHOLDERS' EQUITY
Common stock, $0.01 par value 144,628,654 $ 1,446 $ -
$5.00 par value 121,727,040 - 608,635
Premium on capital stock 2,971,942 1,098,924
Retained earnings 474,188 956,092
Accumulated foreign currency adjustment (952) -
Treasury stock, at cost 14,209,000 46,281 (423,716) (1,204)
- ----------------------------------------------------------------------------------------------------------------------------------
TOTAL COMMON SHAREHOLDERS' EQUITY 3,022,908 2,662,447
- ----------------------------------------------------------------------------------------------------------------------------------
PREFERRED STOCK - REDEMPTION REQUIRED
Par value $100 per share
7.40% Series L - 150,500 - 15,050
7.66% Series CC - 570,000 - 57,000
Less - Series called for redemption - - - 15,050
- ----------------------------------------------------------------------------------------------------------------------------------
- 57,000
- ----------------------------------------------------------------------------------------------------------------------------------
Par value $25 per share
7.95% Series AA 14,520,000 14,520,000 363,000 363,000
$1.67 Series GG - 880,000 - 22,000
$1.95 Series NN - 1,554,000 - 38,850
7.05% Series QQ - 3,464,000 - 86,600
6.875% Series UU - 2,240,000 - 56,000
Less - Series called for redemption - - - 38,850
Less - Mandatory redemption of preferred stock - - - 22,000
- ----------------------------------------------------------------------------------------------------------------------------------
363,000 505,600
- ----------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - Redemption Required 363,000 562,600
- ----------------------------------------------------------------------------------------------------------------------------------
PREFERRED STOCK - NO REDEMPTION REQUIRED
Par value $100 per share
7.07% Series B - private placement 553,000 - 55,300 -
7.17% Series C - private placement 197,000 - 19,700 -
6.00% Series A - private placement 99,727 - 9,973 -
5.00% Series B - 100,000 - 10,000
4.25% Series D - 70,000 - 7,000
4.35% Series E - 200,000 - 20,000
4.35% Series F - 50,000 - 5,000
5 1/8% Series H - 200,000 - 20,000
5 3/4% Series I - Convertible - 14,743 - 1,474
Less - Series called for redemption - - - 63,474
- ----------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - No Redemption Required 84,973 -
- ----------------------------------------------------------------------------------------------------------------------------------
TOTAL PREFERRED STOCK $ 447,973 $ 562,600
- ----------------------------------------------------------------------------------------------------------------------------------
The Notes to Consolidated Financial Statements are an integral part of these
statements.
60
CONSOLIDATED STATEMENT OF CAPITALIZATION (CONTINUED)
==================================================================================================================================
(In Thousands of Dollars)
Long-Term Debt Interest Rate Series DECEMBER 31, 1998 March 31, 1998
- ----------------------------------------------------------------------------------------------------------------------------------
GENERAL AND REFUNDING BONDS
April 15, 1998 through July 1, 2024 9 5/8% - 7 5/8% various $ - $ 1,286,000
- ----------------------------------------------------------------------------------------------------------------------------------
Total General and Refunding Bonds - 1,286,000
- ----------------------------------------------------------------------------------------------------------------------------------
DEBENTURES
July 15, 1999 through March 15, 2023 9.00% - 6.25% various - 2,270,000
- ----------------------------------------------------------------------------------------------------------------------------------
Total Debentures - 2,270,000
- ----------------------------------------------------------------------------------------------------------------------------------
AUTHORITY FINANCING NOTES
INDUSTRIAL DEVELOPMENT REVENUE BONDS
December 1, 2006 7.50% 1976 A,B - 2,000
POLLUTION CONTROL REVENUE BONDS
December 1, 2006 through March 1, 2016 8.25% - 3.58% various - 213,675
ELECTRIC FACILITIES REVENUE BONDS
September 1, 2019 through August 1, 2025 7.15% - 3.70% various - 724,880
December 1, 2027 variable 1997 A 24,880 -
- ----------------------------------------------------------------------------------------------------------------------------------
Total Authority Financing Notes 24,880 940,555
- ----------------------------------------------------------------------------------------------------------------------------------
PROMISSORY NOTES TO LIPA
DEBENTURES
July 15, 1999 7.30% 397,000 -
March 15, 2023 8.20% 270,000 -
POLLUTION CONTROL REVENUE BONDS
December 1, 2006 7.50% 1976 A 26,375 -
December 1, 2009 7.80% 1979 B 19,100 -
March 1, 2016 variable 1985 A 58,022 -
March 1, 2016 variable 1985 B 50,000 -
ELECTRIC FACILITIES REVENUE BONDS
September 1, 2019 7.15% 1989 B 35,030 -
June 1, 2020 7.15% 1990 A 73,900 -
December 1, 2020 7.15% 1991 A 26,560 -
February 1, 2022 7.15% 1992 B 13,455 -
August 1, 2022 6.90% 1992 D 28,060 -
November 1, 2023 variable 1993 B 29,600 -
October 1, 2024 variable 1994 A 2,600 -
August 1, 2025 variable 1995 A 15,200 -
- ----------------------------------------------------------------------------------------------------------------------------------
Total Promissory Notes to LIPA 1,044,902 -
- ----------------------------------------------------------------------------------------------------------------------------------
GAS FACILITIES REVENUE BONDS
April 1, 2020 6.368% 1993 A,B 75,000 -
January 1, 2021 5.50% 1996 153,500 -
February 1, 2024 6.75% 1989 A 45,000 -
February 1, 2024 6.75% 1989 B 45,000 -
June 1, 2025 5.60% 1993 C 55,000 -
July 1, 2026 6.95% 1991 A, B 100,000 -
July 1, 2026 5.635% 1993 D-1, D-2 50,000 -
December 1, 2020 variable 1997 125,000 -
- ----------------------------------------------------------------------------------------------------------------------------------
Total Gas Facilities Revenue Bonds 648,500 -
- ----------------------------------------------------------------------------------------------------------------------------------
Unamortized Discount on Debt (1,750) (13,606)
- ----------------------------------------------------------------------------------------------------------------------------------
Total 1,716,532 4,482,949
Less Current Maturities 398,000 101,000
Other Subsidiary Debt 300,535 -
- ----------------------------------------------------------------------------------------------------------------------------------
TOTAL LONG-TERM DEBT 1,619,067 4,381,949
- ----------------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION $ 5,089,948 $ 7,606,996
==================================================================================================================================
The Notes to Consolidated Financial Statements are an integral part of these
statements.
61
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. REORGANIZATION
MarketSpan Corporation d/b/a KeySpan Energy (the "Company") is the successor to
Long Island Lighting Company ("LILCO"), as a result of a transaction with the
Long Island Power Authority ("LIPA") (the "LIPA Transaction") and following the
acquisition (the "KeySpan Acquisition") of KeySpan Energy Corporation ("KSE").
The Company is a "predominately intrastate" public utility holding company
exempt from most of the provisions of the Public Utility Holding Company Act of
1935, as amended. As a result of the transaction with LIPA, LILCO became a
wholly-owned subsidiary of LIPA, a public authority and a political subdivision
of New York State. KSE, a wholly-owned subsidiary of the Company and also an
exempt utility holding company under the Public Utility Holding Company Act of
1935, as amended, is no longer a registrant under the Securities Act of 1933, as
amended, and the Securities Exchange Act of 1934, as amended.
On May 28, 1998, the Company completed two business combinations as a result of
which it (i) became the successor operator of the non-nuclear electric
generating facilities, gas distribution operations and common plant formerly
owned by LILCO and entered into long-term service agreements to operate the
electric transmission and distribution system acquired by LIPA; and (ii)
acquired KSE, the parent company of The Brooklyn Union Gas Company ("Brooklyn
Union"). (See Note 2, "Sale of LILCO Assets, Acquisition of KeySpan Energy
Corporation and Transfer of Assets and Liabilities to the Company.")
With the exception of a small portion of Queens County, the Company's
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. Brooklyn Union provides gas distribution services to
customers in the New York City boroughs of Brooklyn, Queens and Staten Island,
and KeySpan Gas East d/b/a Brooklyn Union of Long Island ("Brooklyn Union of
Long Island"), a Company subsidiary, provides gas distribution services to
customers in the Long Island counties of Nassau and Suffolk and the Rockaway
Peninsula of Queens County.
On September 10, 1998, the Company's Board of Directors authorized filings to
permit the Company to conduct its business under the name KeySpan Energy. The
Company will propose a formal name change for shareholder approval at its 1999
Annual Meeting of Shareholders. On October 20, 1998 the Company's symbol for its
common stock and preferred stock Series AA listed on the New York and Pacific
Stock Exchanges was changed to "KSE."
B. BASIS OF PRESENTATION
The Consolidated Financial Statements presented herein reflect the accounts of
the Company and its subsidiaries. Subsidiaries comprising the Gas Exploration
and Production reportable segment
62
and the Energy Related Services reportable segment are fully consolidated in the
financial information presented. All other subsidiary investments are accounted
for on the equity method as the Company does not have a controlling voting
interest or otherwise have control over the management of 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.
For financial reporting purposes, LILCO is deemed the acquiring company pursuant
to a purchase accounting transaction, in which KSE was acquired. Consequently,
financial results of the Company prior to May 29, 1998 reflect those of LILCO
only. Since the acquisition of KSE was accounted for as a purchase, related
accounting adjustments, including goodwill, have been reflected in the financial
statements herein. Further, the financial statements presented reflect the
results of operations of LILCO from April 1, 1998 through May 28, 1998 and of
the fully consolidated entity from May 29, 1998 through December 31, 1998. In
September 1998, the Company changed its fiscal year end to December 31. Further,
in April 1997, LILCO changed its year end from December 31 to March 31. As a
result, the financial statements presented herein include the nine month
transition period April 1, 1998 through December 31, 1998 (the "Transition
Period"), the twelve months ended March 31 1998, the three months ended March
31, 1997 and the twelve months ended December 31, 1996.
The weighted average number of common shares outstanding used in the calculation
of earnings per share for the nine months ended December 31, 1998 reflected the
issuance of common stock to consummate the KeySpan Acquisition and the reduction
associated with repurchases of common stock subsequent to August 17, 1998. (See
Note 5, "Capital Stock.") Further, as of December 31, 1998, the Company had
outstanding 921,066 unexercised common stock options held by key Company
employees. These options have not been considered in measuring diluted earnings
per share, since inclusion of these options in the calculation would have
resulted in an antidilutive effect for the Transition Period.
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.
63
C. ACCOUNTING FOR THE EFFECTS OF RATE REGULATION
The Company's accounting records for its two regulated gas utilities and its
generation subsidiary are maintained in accordance with the Uniform System of
Accounts prescribed by the Public Service Commission of the State of New York
("NYPSC") and the Federal Energy Regulatory Commission ("FERC"), respectively.
The Company's financial statements reflect the ratemaking policies and actions
of these regulators in conformity with generally accepted accounting principles
for rate- regulated enterprises.
The Company's two regulated gas utilities and its electric generation subsidiary
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, the Company records these future economic
benefits and obligations as regulatory assets and regulatory liabilities,
respectively.
The Company's regulatory assets of $279.5 million at December 31, 1998 are
primarily comprised of regulatory tax assets, certain environmental remediation
and investigation costs, postretirement benefits other than pensions and costs
associated with the KeySpan Acquisition.
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 the Company to recover its costs in the future, all or a portion
of the Company's 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
the Company's existing regulatory assets and liabilities could result. If the
Company had been unable to continue to apply the provisions of SFAS No. 71 at
December 31, 1998, the Company would have applied the provisions of SFAS No. 101
"Regulated Enterprises - Accounting for the Discontinuation of Application of
FASB Statement No. 71." The Company estimates that the write-off of its net
regulatory asset (regulatory assets less regulatory liabilities) could result in
a charge to net income of $147.2 million or $1.01 per share of common stock,
which would be classified as an extraordinary item. In management's opinion, the
Company's regulated subsidiaries will be subject to SFAS No. 71 for the
foreseeable future.
As part of the LIPA Transaction, the Company has entered into various service
agreements with LIPA that prescribe the conduct of the Company's electric
operations. These agreements allow the Company to recover its costs, subject to
negotiation, incurred to service the agreements and potentially allow the
Company to earn a certain level of profit. The Company's electric operations,
other than the generation function which is FERC regulated, are no longer
subject to NYPSC rate regulation and as a result the Company no longer applies
SFAS No. 71 to its electric operations. As a result of the LIPA Transaction, all
regulatory assets and liabilities outstanding as of May 28, 1998 associated with
the Company's electric operations have been either sold or written-off and
therefore, are no longer recorded in the accounts of the Company. In addition,
certain issues relating to prior
64
electric operations, such as nuclear plant decommissioning and nuclear plant
insurance are no longer applicable to the Company since these assets were sold
to LIPA. The net regulatory assets that were sold to LIPA as part of the LIPA
Transaction amounted to $6.3 billion. See Note 13, "Disaggregated Condensed
Balance Sheet (Unaudited)" for additional information.
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 is recovered as incurred when billed to firm customers through
the operation of the gas adjustment clause ("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 during a subsequent twelve-month period. Further, net revenues from
tariff gas balancing services, off-system sales and certain on-system
interruptible sales are refunded to firm customers subject to certain sharing
provisions.
The gas utility tariffs contain a weather normalization adjustment that largely
offsets shortfalls or excesses of firm net revenues (revenues less gas costs)
during a heating season due to variations from normal weather.
Electric revenues since the LIPA Transaction are primarily 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 the Company, 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. Costs in excess of budgeted levels are assumed by the Company 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 charged to LIPA include fixed
and variable components. The variable component is billed to LIPA on a monthly
basis and is dependent on the amount of megawatt hours dispatched. In addition,
billings related to transmission, distribution and delivery services are based,
in part, on negotiated budgeted levels.
Prior to the LIPA Transaction, electric revenues were comprised of cycle
billings rendered to residential, commercial and industrial customers and the
accrual of electric revenues for services rendered to customers not billed at
month-end. In addition, LILCO's rate structure provided for a revenue
reconciliation mechanism which eliminated the impact on earnings of electric
sales that were above or below the levels reflected in rates. Moreover, LILCO's
electric tariff included a fuel cost adjustment ("FCA") clause which provided
for the disposition of the difference between actual
65
fuel costs and the fuel costs allowed in base tariff rates (base fuel costs).
LILCO deferred these differences to future periods for recovery from or refund
to customers, except for base electric fuel costs in excess of actual electric
fuel costs, which were credited to the Rate Moderation Component as incurred.
E. UTILITY PROPERTY - DEPRECIATION AND MAINTENANCE
Utility gas property is stated at original cost of construction, which includes
allocations of overheads and taxes and an allowance for funds used during
construction. Mass properties associated with gas operations, such as meters,
are accounted for on an average unit cost basis by year of installation. Prior
to the LIPA Transaction, electric T&D mass properties, such as poles and wire,
were accounted for on an average unit cost basis by year of installation. As
part of the LIPA Transaction, all T&D assets were sold to LIPA, and as a result,
all costs associated with the maintenance of the T&D system subsequent to May
28, 1998 are expensed and charged to LIPA.
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
------ -------- ---
9 Months Ended 12/31/98 2.40% 1.75%
12 Months Ended 3/31/98 3.07% 2.04%
3 Months Ended 3/31/97 .78% .51%
12 Months Ended 12/31/96 3.00% 2.00%
F. GAS EXPLORATION AND PRODUCTION PROPERTY- DEPLETION AND DEPRECIATION
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 depreciation, depletion and amortization)
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. At December 31, 1998, The Houston
Exploration Company ("THEC"), the Company's 64% owned gas and oil exploration
and production subsidiary, recorded a $130 million write-down to its investment
in its proved gas reserves, which
66
is reflected in the accompanying financial statements. As permitted under
generally accepted accounting principles, THEC utilized February 1999 prices to
measure the write-down. If THEC had utilized December 1998 prices to measure the
write-down, the write-down would have been $66.6 million less.
Provisions for depreciation of all other non-utility property are computed on a
straight line basis over useful lives of three to ten years.
G. DERIVATIVE FINANCIAL INSTRUMENTS
The Company's utility, marketing and gas and oil exploration and production
subsidiaries employ, from time to time, derivative financial instruments to
hedge exposure in cash flows due to fluctuations in the price of natural gas.
Utility hedging activities also involve use of derivatives related to fuel oil,
which in certain markets strongly influence the selling price for natural gas.
The Company's 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.
The subsidiaries 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.
H. 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. Goodwill, at December
31, 1998, was $52.2 million for certain investments in Canada and Northern
Ireland. The amortization period for the goodwill is over 15 and 40 years.
I. FEDERAL INCOME TAX
In accordance with SFAS No. 109, "Accounting for Income Taxes" and NYPSC policy,
certain of the Company's regulated subsidiaries recorded a regulatory asset for
the net cumulative effect of having to provide deferred federal 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 in operating expense and are amortized as a reduction of
federal income tax in other income over the estimated lives of the related
property.
67
J. SUBSIDIARY COMMON STOCK ISSUANCES TO THIRD PARTIES
The Company follows an accounting policy of income statement recognition for
parent company gains or losses from issuances of common stock by subsidiaries.
K. Foreign Currency Translation
The Company follows the principles of SFAS No. 52, "Foreign Currency
Translation," for recording its investments in foreign affiliates. Under this
statement, all elements of 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, 1998, the foreign
currency translation adjustment was included in a separate component of
shareholders' equity.
L. GOODWILL
At December 31, 1998, the Company has recorded goodwill in the amount of $201.9
million, representing the excess of acquisition cost over the fair value of net
assets acquired related to its purchases of certain consolidated subsidiaries.
Goodwill is amortized over 20 to 40 years. The Company recorded goodwill of
approximately $177.4 million net of accumulated amortization of $2.5 million
relating to the KeySpan Acquisition and approximately $24.5 million related to
the acquisition of a heating, ventilating, and air-conditioning company and the
acquisition of an engineering firm.
M. RECENT ACCOUNTING PRONOUNCEMENTS
COMPREHENSIVE INCOME
The Company has adopted SFAS No. 130 "Comprehensive Income." Comprehensive
income is the change in the equity of a company, not including those changes
that result from shareholder transactions. All components of comprehensive
income are required to be reported in a new financial statement that is
displayed with equal prominence as existing financial statements.
SEGMENT DISCLOSURES
At December 31, 1998, the Company adopted SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information." SFAS No. 131 establishes
standards for additional disclosure about operating segments for interim and
annual financial statements. More specifically, it requires financial
information to be disclosed for segments whose operating results are reviewed by
the chief operating decision-maker for decisions on resource allocation. It also
requires related disclosures about products and services, geographic areas and
major customers. The Company's segments are based on how management internally
analyzes the business and allocates resources. (See Note 10, "Business Segments"
for additional information.)
68
PENSION AND OTHER POSTRETIREMENT BENEFIT DISCLOSURES
At December 31, 1998, the Company adopted SFAS No 132, "Employers' Disclosure
about Pensions and Other Postretirement Benefits." This statement revises
employers' disclosure about pensions and other postretirement benefit plans. It
does not change the measurement or recognition of those plans. The statement
standardizes the disclosure requirements for pensions and other postretirement
benefits, requires additional information on changes in the benefit obligations
and fair values of plan assets that will facilitate financial analysis, and
eliminates certain disclosures that are no longer considered useful.
DERIVATIVE INSTRUMENTS
In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities." This
Statement establishes accounting and reporting standards for derivative
instruments and for hedging activities. It 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. The Company will adopt
SFAS No. 133 in the first quarter of fiscal year 2000. The Company does not
expect any material earnings effect from adoption of this statement as it
presently utilizes derivatives for hedging activities.
NOTE 2. SALE OF LILCO ASSETS, ACQUISITION OF KEYSPAN ENERGY CORPORATION AND
TRANSFER OF ASSETS AND LIABILITIES TO THE COMPANY
On May 28, 1998, pursuant to the Agreement and Plan of Merger, dated as of June
26, 1997 as amended, by and among the Company, LILCO, LIPA, and LIPA Acquisition
Corp. (the "Merger Agreement"), LIPA acquired all of the outstanding common
stock of LILCO for $2.4975 billion in cash and thereafter directly or indirectly
assumed certain liabilities including approximately $3.4 billion in debt. In
addition, LIPA reimbursed LILCO $339.1 million related to certain series of
preferred stock which were redeemed by LILCO prior to May 28, 1998. 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 the Company and
transferred to wholly-owned subsidiaries of the Company at the Company's
direction.
The consideration for the Transferred Assets consisted of (i) 3,440,625 shares
of the common stock of the Company (ii) 553,000 shares of the Series B preferred
stock of the Company, (iii) 197,000 shares of the Series C preferred stock of
the Company, and (iv) the assumption by the Company of certain liabilities of
LILCO. In connection with the transfer and prior to the effectiveness of the
LIPA Transaction, LILCO sold Series B and C preferred stock for $75 million in a
private placement.
69
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 the Company, was assumed by LIPA. In accordance with the
LIPA Transaction, the Company issued promissory notes to LIPA amounting to
$1.048 billion which represented an amount equivalent to the sum of (i) the
principal amount of 7.3% Series Debentures due July 15, 1999 and 8.2% 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.
(See Note 7, "Long-Term Debt" for additional information.)
On May 28, 1998, immediately subsequent to the LIPA Transaction, KSE was merged
with and into a subsidiary of the Company, pursuant to an Agreement and Plan of
Exchange and Merger, dated as of December 29, 1996, between LILCO and Brooklyn
Union. This agreement was amended and/or restated as of February 7, 1997, June
26, 1997, and September 29, 1997, to reflect certain technical changes and the
assignment by Brooklyn Union of all of its rights and obligations under the
agreement to KSE. On September 29, 1997, KSE became the parent company of
Brooklyn Union when Brooklyn Union reorganized into a holding company structure.
As a result of these transactions, holders of KSE common stock received one
share of the Company'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
the Company's 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 the Company'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, the
Company recorded goodwill in the amount of $179.9 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.
The following is the comparative unaudited proforma combined condensed financial
information for the nine months ended December 31, 1998 and the twelve months
ended March 31, 1998. The proforma disclosures are intended to reflect the
results of operations as if the KeySpan Acquisition was consummated on the first
day of each of the reporting periods below. The effects of the LIPA Transaction
have been reflected for the period May 29, 1998 through December 31, 1998. These
disclosures may not be indicative of future results.
70
Nine Months Twelve Months
Proforma Results Ended Ended
(in thousands of dollars except per share amounts): December 31, 1998 March 31, 1998
- -------------------------------------------------- ------------------- -----------------
Revenues $ 1,907,129 $ 4,554,093
Operating Income $ 4,416 $ 914,272
Net Income (Loss) $ (212,424) $ 436,794
Basic and Diluted Earnings (Loss) per Share $ (1.38) $ 2.78
The decrease in revenues for the Transition Period as compared to the twelve
months ended March 31, 1998 is due primarily to the LIPA Transaction consummated
on May 28, 1998. Electric revenues for the Transition Period are derived from
service agreements with LIPA for the period May 29, 1998 through December 31,
1998. For the period April 1, 1998 through May 28, 1998, and for the twelve
months ended March 31, 1998, revenues reflected fully integrated electric
service to customers. Included within rates charged to customers, prior to the
LIPA Transaction, was the return on the capital investment in the generation and
T&D assets required to operate the system as well as recovery of the electric
business costs to operate the system. Upon completion of the LIPA Transaction,
the nature of the Company's electric business has changed from that of an owner
of an electric generation and T&D system, with significant capital investment,
to a new role as owner of the non-nuclear generation facilities and as manager
of the T&D system now owned by LIPA. In its new role, the Company's capital
investment is significantly reduced and accordingly, its revenues under the LIPA
contracts reflect that reduction. Revenues after May 28, 1998 reflect the impact
of the LIPA agreements which contribute marginally to earnings.
Gas distribution revenues for the Transition Period do not include revenues from
heating season operations (January through March) when the Company realizes the
major portion of its gas revenues. Gas distribution revenues during the
Transition Period were also impacted by rate reductions which were reflected at
the time of the KeySpan Acquisition. Brooklyn Union reduced rates to its core
customers by $23.9 million annually effective May 29, 1998 and Brooklyn Union of
Long Island 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.
Net income for the Transition Period also reflected substantial non-recurring
charges associated with the LIPA Transaction of $107.9 million after-tax,
special charges related to the KeySpan Acquisition of $83.5 million after-tax
and a $13 million after-tax donation made by the Company to establish the
KeySpan Foundation. See Note 11, "Costs Related to the LIPA Transaction and
Special Charges" for additional details.
71
NOTE 3. FEDERAL INCOME TAX
Income tax expense (benefit) is reflected as follows in the Consolidated
Statement of Income:
(IN THOUSANDS OF DOLLARS)
- ------------------------------------------------------------------------------------------------------
Nine Months Twelve Months Three Months Year
Ended Ended Ended Ended
December 31, 1998 March 31, 1998 March 31, 1997 December 31, 1996
- ------------------------------------------------------------------------------------------------------
Operating Expenses
Current $ 20,144 $ 86,388 $ 23,378 $ 42,197
Deferred (82,650) 150,983 33,624 168,000
(62,506) 237,371 57,002 210,197
Other Income
Current 5,998 (594) - -
Deferred (3,286) (4,124) (789) (940)
2,712 (4,718) (789) (940)
Transaction Related (99,701) - - -
Total Federal Income Tax $(159,495) $232,653 $ 56,213 $209,257
The components of deferred tax assets and liabilities reflected in the
Consolidated Balance Sheet are as follows:
(IN THOUSANDS OF DOLLARS)
- --------------------------------------------------------------------------------
December 31, 1998 March 31, 1998
- --------------------------------------------------------------------------------
Deferred Tax Assets
Property related differences $ 151,430 $ 10,559
Benefits of tax loss carryforwards 52,157 65,176
Reserves not currently deductible 44,263 39,667
Other items - net 52,629 261,729
Total Deferred Tax Assets $ 300,479 $ 377,131
- --------------------------------------------------------------------------------
Deferred Tax Liabilities
1989 Settlement $ - $2,169,909
Property related differences 179,583 650,562
Regulatory tax asset 69,277 -
Other items - net 123,168 96,024
Total Deferred Tax Liabilities $ 372,028 $2,916,495
- --------------------------------------------------------------------------------
Net Deferred Tax Liabilities $ 71,549 $2,539,364
- --------------------------------------------------------------------------------
72
The following is a reconciliation between reported income tax and tax computed
at the statutory rate of 35%:
(IN THOUSANDS OF DOLLARS)
- ---------------------------------------------------------------------------------------------------------
Nine Months Twelve Months Three Months Year
Ended Ended Ended Ended
December 31, March 31, March 31, December 31,
1998 1998 1997 1996
- ---------------------------------------------------------------------------------------------------------
Computed at the statutory rate $(114,249) $208,213 $50,369 $184,002
Adjustments related to:
Net benefit from LIPA Transaction (1) (31,503) - - -
Tax credits (1,809) (2,464) (940) (4,383)
Excess of book over tax depreciation 2,859 17,912 4,356 18,339
Minority interest in THEC (10,220) - - -
Other items - net (4,573) 8,992 2,428 11,299
- ---------------------------------------------------------------------------------------------------------
Total Federal income tax $(159,495) $232,653 $56,213 $209,257
=========================================================================================================
Effective income tax rate (49%) 39% 39% 40%
- ---------------------------------------------------------------------------------------------------------
(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 the Company by LIPA which taxes are to be paid by the
Company.
The Company currently has federal income tax loss carryforwards of approximately
$149.1 million that expire in twenty years or in 2017, representing losses
incurred by the Company for the nine months ended December 31, 1998.
In 1990 and 1992, LILCO received an Internal Revenue Service Agents' Report
disallowing certain deductions and credits claimed by LILCO on its federal
income tax returns for the years 1981 through 1989. A settlement resolving all
audit issues was reached between LILCO and the Internal Revenue Service in May
1998. The settlement required the payment of taxes and interest of $9 million
and $35 million, respectively, which the Company made in May 1998. Adequate
reserves to cover such taxes and interest were previously provided.
73
NOTE 4. POSTRETIREMENT BENEFITS
PENSION PLANS: The following information represents consolidated results for the
Company and its subsidiaries (Brooklyn Union, Brooklyn Union of Long Island and
the former LILCO), whose noncontributory defined benefit pension plans 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 the Company's regulated subsidiaries, which were the only
subsidiaries with defined benefit plans. The Company is in the process of
examining the feasibility of integrating these plans into a more unified form
within the holding company structure.
The amounts presented are consolidated for periods subsequent to May 28, 1998.
Prior to that date the amounts pertain solely to the plan of LILCO. Brooklyn
Union of Long Island is subject to certain deferral accounting requirements
mandated by the NYPSC for pension costs and other postretirement benefit costs.
Amounts included herein also include accruals pertaining to supplemental plans
of the Company for obligations arising subsequent to May 28, 1998.
The calculation of net periodic pension cost follows:
(In Thousands of Dollars)
- ---------------------------------------------------------------------------------------------------------------------
Nine Months Ended Twelve Months Ended Three Months Ended Year Ended
December 31,1996 March 31, 1998 March 31, 1997 December 31, 1996
- ---------------------------------------------------------------------------------------------------------------------
Service cost, benefits earned
during the period $ 24,608 $ 21,114 $ 4,645 $ 17,384
Interest cost on projected
benefit obligation 66,341 56,379 12,494 47,927
Return on plan assets (51,745) (196,300) (3,500) (81,165)
Special termination charge (1) 61,558 - - -
Net amortization and deferral (33,942) 147,713 (9,640) 33,541
Total pension cost $ 66,820 $ 28,906 $ 3,999 $ 17,687
- ---------------------------------------------------------------------------------------------------------------------
(1) Early retirement plan completed in December 1998.
74
The following table sets forth the pension plans' funded status at December 31,
1998 and March 31, 1998. Plan assets principally are common stock and fixed
income securities:
(IN THOUSANDS OF DOLLARS)
- --------------------------------------------------------------------------------
December 31,1998 March 31, 1998
- --------------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation at beginning of period $ (825,159) $ (807,703)
Benefit obligation of KSE (674,100) -
Service cost (24,608) (21,114)
Interest cost (66,341) (56,379)
Actuarial (loss) gain (61,929) 16,737
Special termination benefits (1) (61,558) -
Total benefits paid 63,575 43,300
- --------------------------------------------------------------------------------
Benefit obligation at end of period (1,650,120) (825,159)
- --------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of
period 919,100 744,400
Fair value of KSE plan assets 754,127 -
Actual return on plan assets 51,745 196,300
Employer contribution 13,500 18,000
Benefits paid from trust (62,868) (39,600)
- --------------------------------------------------------------------------------
Fair value of plan assets at end of period 1,675,604 919,100
- --------------------------------------------------------------------------------
Funded status 25,484 93,941
Unrecognized net (gain) from past experience
different from that assumed and from changes
in assumptions (158,103) (163,034)
Unrecognized prior service cost 54,234 -
Unrecognized transition obligation 4,138 62,652
- --------------------------------------------------------------------------------
Net accrued pension cost reflected
on consolidated balance sheet $ (74,247) $ (6,441)
================================================================================
(1) Early retirement plan completed in December 1998.
- -------------------------------------------------------------------------------------------------------------------
Nine Months Twelve Months Three Months
Ended Ended Ended Year Ended
December 31,1998 March 31, 1998 March 31, 1997 December 31, 1996
- -------------------------------------------------------------------------------------------------------------------
Obligation discount 6.50% 7.00% 7.00% 7.25%
Asset return 8.50% 8.50% 7.50% 7.50%
Average annual increase in compensation 5.00% 4.50% 5.00% 5.00%
75
INFORMATION ON THE LILCO SUPPLEMENTAL PLAN
The Supplemental Plan in effect prior to May 28, 1998 provided supplemental
death and retirement benefits for officers and other key executives without
contribution from such employees. The Supplemental Plan was a non-qualified plan
under the Internal Revenue Code of 1986, as amended (the "Code"). The provision
for plan benefits totaled $0.7 million for the three months ended March 31, 1997
and $2.7 million for the year ended December 31, 1996. For the twelve months
ended March 31, 1998, a charge of $31 million was recorded relating to certain
benefits earned by former officers of LILCO relating to the termination of their
annuity benefits earned through the supplemental retirement plan and other
executive retirement benefits. This charge, which was borne by LILCO, and not
recovered from ratepayers, resulted from provisions in the employment contracts
of LILCO officers.
OTHER POSTRETIREMENT BENEFITS - RETIREE HEALTH CARE AND LIFE INSURANCE: The
following information represents consolidated results for the Company and its
subsidiaries (Brooklyn Union, Brooklyn Union of Long Island and the former
LILCO) who sponsor noncontributory defined benefit plans under which is provided
certain health care and life insurance benefits for retired employees. The
Company has 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 Code. Prior to the KeySpan Acquisition other postretirement
benefits had been managed separately by the Company's regulated subsidiaries,
which were the only subsidiaries with defined benefit plans. The Company is in
the process of examining the feasibility of integrating these plans into a more
unified form within the holding company structure.
The amounts presented herein are consolidated for periods subsequent May 28,
1998. Prior to that date the amounts pertain solely to the plan of LILCO.
Net periodic other postretirement benefit cost included the following
components:
(IN THOUSANDS OF DOLLARS)
- --------------------------------------------------------------------------------------------------------
Nine Months Twelve Months Three Months
Ended Ended Ended Year Ended
December 31, 1998 March 31, 1998 March 31, 1997 December 31, 1996
- --------------------------------------------------------------------------------------------------------
Service cost, benefits earned
during the period $ 9,569 $ 12,204 $ 2,821 $ 10,690
Interest cost on accumulated post-
retirement benefit obligation 26,414 27,328 6,642 25,030
Return on plan assets (13,857) (6,164) (628) (3,046)
Special termination charge (1) 3,073 - - -
Net amortization and deferral (14,665) (10,468) (3,409) (12,175)
- --------------------------------------------------------------------------------------------------------
Other postretirement benefit cost $ 10,534 $ 22,900 $ 5,426 $ 20,499
- --------------------------------------------------------------------------------------------------------
(1) Early retirement plan completed in December 1998.
76
The following table sets forth the plan's funded status at December 31, 1998 and
March 31, 1998. Plan assets principally are common stock and fixed income
securities:
(IN THOUSANDS OF DOLLARS)
- ----------------------------------------------------------------------------------------
December 31, 1998 March 31, 1998
- ----------------------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation at beginning of period $ (358,941) $ (415,672)
Benefit obligation of KSE (226,645) -
Service cost (9,569) (12,204)
Interest cost (26,414) (27,328)
Plan participants' contributions (900) -
Actuarial (loss) gain (121,228) 83,793
Special termination benefits (1) (3,073) -
Total benefits paid 18,515 12,470
- ----------------------------------------------------------------------------------------
Benefit obligation at end of period (728,255) (358,941)
- ----------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of period 108,165 80,533
Fair value of KSE plan assets 113,917 -
Actual return on plan assets 13,857 6,164
Employer contribution 250,000 21,592
Plan participants' contributions - -
Benefits paid from trust (7,161) (124)
- ----------------------------------------------------------------------------------------
Fair value of plan assets at end of period 478,778 108,165
- ----------------------------------------------------------------------------------------
Funded status (249,477) (250,776)
Unrecognized net loss (gain) from past experience
different from that assumed and from changes in
assumptions 145,834 (102,346)
Unrecognized prior service cost 166 175
- ----------------------------------------------------------------------------------------
Accrued benefit cost reflected on
consolidated balance sheet $ (103,477) $ (352,947)
- ----------------------------------------------------------------------------------------
(1) Early retirement plan completed in December 1998.
- --------------------------------------------------------------------------------------------------
Nine Months Twelve Months Three Months
Ended Ended Ended Year Ended
December 31, 1998 March 31, 1998 March 31, 1997 December 31, 1996
- --------------------------------------------------------------------------------------------------
Assumptions:
Obligation discount 6.50% 7.00% 7.00% 7.25%
Asset return 8.50% 8.50% 7.50% 7.50%
Average annual increase in 5.00% 4.50% 5.00% 5.00%
compensation
77
The measurement of plan liabilities also assumes a health care cost trend rate
of 6% annually. 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, 1998 by $103.8 million and the net periodic health care expense by
$7.9 million. A 1% decrease in the health care cost trend rate would have the
effect of decreasing the accumulated postretirement benefit obligation as of
December 31, 1998 by $82.3 million and the net periodic health care expense by
$6.2 million.
In 1993, LILCO adopted the provisions of SFAS No. 106, "Employer's Accounting
for Post- Employment Benefits Other Than Pensions," and recorded an accumulated
postretirement benefit obligation and a corresponding regulatory asset of $376.0
million. LIPA will reimburse the Company for costs related to postretirement
benefits of the electric business unit employees; therefore, the Company has
reclassified the regulatory asset for postretirement benefits to a receivable
from LIPA.
In 1994, LILCO established VEBA trusts for union and non-union employees for the
funding of costs collected in rates for postretirement benefits. The trusts were
funded with contributions of $21.0 million for the twelve months ended March 31,
1998, $5.0 million for the three months ended March 31, 1997 and $18.0 million
for the year ended December 31, 1996. In May 1998, an additional $250.0 million
was funded into the trusts.
NOTE 5. CAPITAL STOCK
COMMON STOCK: Currently the Company has 450,000,000 shares of authorized common
stock. In the nine month period ended December 31, 1998 the Company issued
396,570 shares for $10.2 million under the Dividend Reinvestment and Stock
Purchase Plan, the Discount Stock Purchase Plan for Employees, and the Employee
Savings Plan. In October 1998, the Company announced that the Board of Directors
authorized using up to $500 million for the purchase of common shares in
addition to the Board's previous authorization to purchase up to 15 million
common shares. As of December 31, 1998, the Company had repurchased 14.2 million
common shares for $423.7 million.
PREFERRED STOCK: The Company has the authority to issue 100,000,000 shares of
preferred stock with the following classifications: 16,000,000 shares of
preferred stock, par value $25 per share, 1,000,000 shares of preferred stock,
par value $100 per share and 83,000,000 shares of preferred stock, par value
$.01 per share.
At December 31, 1998, 14,520,000 redeemable shares of 7.95% Preferred Stock
Series AA par value $25 was outstanding totaling $363.0 million, which has a
mandatory redemption requirement on June 1, 2000. The Company also had 553,000
shares outstanding of private placement 7.07% Preferred Stock Series B par value
$100 and 197,000 shares outstanding of private placement 7.17% Preferred Stock
Series C par value $100 totaling $75.0 million. In addition, during the year the
Company issued, in a private placement, 99,727 nonredeemable shares totaling
approximately $10.0
78
million of 6% Preferred Stock Series A par value $100 to employees as incentive
compensation. Preferred Stock Series A, B and C were privately issued and are
not publicly traded.
On April 17, 1998, LILCO exercised its option to redeem the callable preferred
stock and called for redemption on May 19, 1998 all of the outstanding shares of
preferred stock Series B, Series D, Series E, Series F, Series H, Series
I-Convertible, Series L and Series NN. These preferred stock series were
redeemed for $117.5 million, including accrued and unpaid dividends, plus $4.5
million of call premiums. In addition, pursuant to the LIPA Transaction each
share of non-redeemable preferred stock Series CC, Series GG, Series QQ and
Series UU was canceled and converted to cash in the amount of the present value
plus accrued and unpaid dividends. The non-redeemable preferred stock was
converted for $223.2 million, including accrued and unpaid dividends, plus $18
million of call premiums. On May 28, 1998, LIPA reimbursed the Company $339.1
million for the preferred stock series that were redeemed.
Dividends on preferred stock are paid in preference to dividends on common stock
or any other stock ranking junior to preferred stock.
NOTE 6. NONQUALIFIED STOCK OPTIONS
At December 31, 1998, the Company had stock-based compensation plans that are
described below. Moreover, under a separate plan, THEC has issued 2,124,438
stock options to key THEC employees. The Company and THEC 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 123,
"Accounting for Stock-Based Compensation," the Company's net loss and loss per
share would have been increased to the proforma amounts indicated below:
- --------------------------------------------------------------------------------
Nine Months Ended
December 31, 1998
- --------------------------------------------------------------------------------
Income (loss) available for common stock (000): As reported $(195,537)
Proforma $(198,996)
Primary earnings (loss) per share: As reported $(1.34)
Proforma $(1.37)
- --------------------------------------------------------------------------------
Prior to the KeySpan Acquisition, KSE had reserved for issuance 1,500,000 shares
of nonqualified stock options and had issued 426,000, 363,500 and 202,800
nonqualified stock options in November 1997, 1996 and 1995, respectively. These
options have remained outstanding and, under the terms
79
of the Merger Agreement, all options vested upon consummation of the KeySpan
Acquisition. Holders are now permitted to exercise vested options for Company
common stock.
The fair values of grants issued in November 1997, 1996 and 1995 were $4.62,
$4.27 and $2.78, respectively. All grants were estimated on the date of grant
using the Black-Scholes option-pricing model. The following weighted-average
assumptions were used for grants issued in November 1997, 1996 and 1995:
dividend yield of 5.00%, 4.66% and 5.57%; expected volatility of 16.24%, 16.56%
and 16.879%; risk free interest rate of 6.00%, 6.00% and 6.28%; and expected
lives of 6 years, respectively. The exercise prices are $32.63, $30.50 and
$27.00, respectively.
A summary of the status of the Company's fixed stock option plans as of December
31, 1998 and changes during the period is presented below:
Nine Months Ended December 31, 1998
- --------------------------------------------------------------------------------
Weighted Avg.
Fixed Options Shares Exercise Price
- --------------------------------------------------------------------------------
Outstanding at beginning of period 992,300 $30.70
Exercised (13,631) $28.67
Forfeited (57,603) $29.45
Outstanding and exercisable at end of period 921,066 $30.80
- --------------------------------------------------------------------------------
Options Outstanding and Exercisable
- --------------------------------------------------------------------------------
Number Weighted Avg.
Outstanding Remaining Weighted Avg.
Exercise Price at 12/31/98 Contractual Life Exercise Price
- --------------------------------------------------------------------------------
$27.00 168,066 7 years $27.00
$30.50 344,000 8 years $30.50
$32.63 409,000 9 years $32.63
- --------------------------------------------------------------------------------
921,066
- --------------------------------------------------------------------------------
At the 1999 Annual Meeting of Shareholders, the Company will seek shareholder
approval of its Long-Term Performance and Compensation Plan ("Plan"). This Plan,
if approved, will allow the Company to issue to key employees stock options and
incentive stock options, as well as restricted stock awards and performance
stock awards. The total shares to be issued under this Plan will not exceed
10,500,000 shares.
80
NOTE 7. LONG-TERM DEBT
Gas Facilities Revenue Bonds: Brooklyn Union 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 the Company's Gas Facilities Revenue Bonds. At
December 31, 1998, Brooklyn Union 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 2.48% to 4.23% through December 31, 1998,
at which time the average rate was 3.90%.
In December 1998, the Company purchased a portfolio of securities representing
direct purchase obligations of the United States Government. These securities
were placed in trust, irrevocably dedicated to the repayment of certain Gas
Facilities Revenue Bonds, thereby effecting an in-substance defeasance of
approximately $8.9 million including interest. The in-substance defeasance
represented $4 million of outstanding bonds of each of the 6.75% Series 1989A
due February 1, 2024 and 6.75% Series 1989B due February 1, 2024. The Company
has not been relieved of its obligation and remains the primary obligor for this
debt. Based on the accounting requirements of SFAS No. 125, "Accounting for
Transfers and Servicing of Financial Assets and the Extinguishment of
Liabilities," the liability is not considered extinguished and is recognized on
the accompanying Consolidated Balance Sheet.
AUTHORITY FINANCING NOTES: The Company's electric generation subsidiary can also
issue tax-exempt bonds through the New York State Energy Research and
Development Authority. At December 31, 1998, $24.9 million of Authority
Financing Notes were outstanding. The interest rate on these notes is variable
and ranged from 2.65% to 4.75% through December 31, 1998 at which time the
average rate was 4.10%.
PROMISSORY NOTES: At March 31, 1998, total long-term debt outstanding was $4.497
billion. In accordance with the LIPA Agreement, LIPA has assumed substantially
all of the outstanding long-term debt of LILCO except for the 1997 Series A
Electric Facilities Revenue Bonds due December 1, 2027 which were assigned to
the Company. In accordance with the LIPA Agreement, the Company issued
promissory notes to LIPA for $1.048 billion which represented an amount
equivalent to the sum of: (i) the principal amount of 7.3% Series Debentures due
July 15, 1999 and 8.2% 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.
On November 3, 1998, the Company extinguished a portion of its obligation of the
promissory notes to LIPA relating to certain series of bonds that were called by
LIPA on December 1, 1998. The Company's obligation for these bonds of $2.1
million consisted of the principal amount and the interest accrued and unpaid.
In addition, on December 1, 1998, the Company extinguished a portion
81
of its obligation of the promissory notes on a certain series of bonds due to a
mandatory sinking fund redemption payment of $1 million. The carrying value of
the promissory notes at December 31, 1998 was $1.045 billion.
The promissory notes issued to LIPA included an allocation for certain of the
Authority Financing Notes. Authority Financing Notes Series 1993B due November
1, 2023, Series 1994A due October 1, 2024 and Series 1995A due August 1, 2025
have variable interest rate features in which the interest rate is reset on a
weekly basis. The interest rates for these notes ranged from 2.30% to 4.35%
during the nine months ended December 31, 1998 at which time the average rate
was 4.10%. Authority Financing Notes Series 1985A due March 1, 2016 and Series
1985B due March 1, 2016 have variable interest rate features in which the
interest rate is reset on an annual basis. The interest rate for these notes at
December 31, 1998 was 3.58%. On March 1, 1999, LIPA converted the variable rate
features of these notes to fixed interest rates. Series 1993B, Series 1994A and
Series 1995A were converted to a fixed rate of 5.30% and Series 1985A and Series
1985B were converted to a fixed rate of 5.15%.
GENERAL & REFUNDING ("G&R") MORTGAGE BONDS: Upon consummation of the LIPA
Transaction, all of the series of G&R Bonds have been assumed and redeemed by
LIPA resulting in the termination of the G&R Mortgage.
OTHER LONG-TERM DEBT: THEC has an available line of credit of $150 million which
supports borrowings under a revolving loan agreement. Up to $5 million of this
line is available for the issuance of letters of credit to support performance
guarantees. This credit facility matures on July 1, 2000. At December 31, 1998,
borrowings of $133 million were outstanding under this line of credit and $0.4
million was committed under outstanding letter of credit obligations. Borrowings
under this facility bear interest, at THEC's option, at rates indexed at a
premium to the Federal Funds rate or LIBOR rate, or based on the prime rate. The
weighted average interest rate on this debt was 6.44% at December 31, 1998.
Covenants related to this line of credit require the maintenance of certain
financial ratios and involve other restrictions regarding cash dividends, the
purchase or redemption of stock and the pledging of assets. Moreover, at
December 31, 1998, THEC had $100 million of 8.625% Senior Subordinated Notes due
2008 outstanding. These notes were issued in a private placement in March 1998
and are subordinate to borrowings under THEC's line of credit.
A subsidiary of the Energy Related Investment segment had borrowings of $67.5
million outstanding at December 31, 1998, at an interest rate of 5.25%. Gulf
Midstream Services Partnership ("GMS") was then provided with a loan of $64.8
million that bears interest on commercial terms.
DEBT MATURITY SCHEDULE: The total long-term debt maturing in each of the next
five years ending December 31 is as follows: 1999, $398 million; 2000, $1.0
million; 2001, $1.0 million; 2002, $3.5 million; and 2003, $3.5 million.
82
NOTE 8. CONTRACTUAL OBLIGATIONS, FINANCIAL INSTRUMENTS AND CONTINGENCIES:
FIXED OBLIGATIONS: Lease costs included in operation expense were $28.9 million
in 1998. The future minimum lease payments under various leases, all of which
are operating leases, are $22.1 million per year over the next five years and
$119.2 million, in the aggregate, for all years thereafter.
FIXED CHARGES UNDER FIRM CONTRACTS: The Company's 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 monthly charges in the aggregate
amount of $5.1 million per month in all events regardless of the level of
service available. Such charges are recovered from utility customers as gas
costs.
FAIR VALUE OF FINANCIAL INSTRUMENTS: The fair value of the Company's preferred
stock at December 31, 1998 was $471.6 million and the carrying value was $448.0
million.
The Company's long-term debt consists primarily of publicly traded Gas
Facilities Revenue Bonds, Authority Financing Notes and Debentures, the fair
value of which is estimated on quoted market prices for the same or similar
issues. The Authority Financing Notes and Debentures are included in the
promissory notes to LIPA. (See Note 2, "Sale of LILCO Assets, Acquisition of
KeySpan Energy Corporation and Transfer of Assets and Liabilities to the
Company" and Note 7, "Long-Term Debt" for additional information.)
The carrying amounts and fair values of the Company's long-term debt at December
31, 1998 and March 31, 1998 were as follows:
FAIR VALUE (IN THOUSANDS OF DOLLARS)
- --------------------------------------------------------------------------------
DECEMBER 31, 1998 March 31, 1998
- --------------------------------------------------------------------------------
Gas facilities revenue bonds 687,863 -
General and refunding bonds - 1,288,470
Debentures - 2,407,178
Authority financing notes 24,880 987,646
Promissory notes 1,097,226 -
- --------------------------------------------------------------------------------
Total 1,809,969 4,683,294
================================================================================
CARRYING AMOUNT (IN THOUSANDS OF DOLLARS)
- --------------------------------------------------------------------------------
DECEMBER 31, 1998 March 31, 1998
- --------------------------------------------------------------------------------
Gas facilities revenue bonds 648,500 -
General and refunding bonds - 1,286,000
Debentures - 2,270,000
Authority financing notes 24,880 940,555
Promissory notes 1,044,902 -
- --------------------------------------------------------------------------------
Total 1,718,282 4,496,555
================================================================================
83
At December 31, 1998, THEC's $100 million 8.625% Senior Subordinated Notes due
2008 had a fair market value of $98 million. All other THEC debt and 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.
DERIVATIVE FINANCIAL INSTRUMENTS: The Company's utility, marketing and gas
exploration and production subsidiaries employ derivative financial instruments,
such as natural gas and oil futures, options and swaps, for the purpose of
hedging exposure to commodity price risk.
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. The Company uses standard
New York Mercantile Exchange ("NYMEX") futures contracts to fix profit margins
on specified portions of the sales to this market in line with pricing
objectives. Implementation of the strategy involves establishment of long (buy)
positions in gas futures contracts with offsetting short (sell) positions in oil
futures contracts of equivalent energy value. The long gas futures position
follows, generally within a range of 80% to 120%, the cost of gas to serve this
market while the short oil futures position correspondingly replicates, within
the same range, the selling price of gas.
KeySpan Energy Services ("KES"), the Company's gas and electric marketing
subsidiary, sells gas at fixed annual rates 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, KES pays the other parties the amount
by which the floating variable price (settlement price) is below the fixed price
and receives the amount by which the settlement price exceeds the fixed price.
THEC utilizes derivative commodity instruments 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.
Hedging instruments used include swaps, collars and options. With respect to any
particular swap transaction, the counter party is required to make a payment to
THEC in the event that the settlement price for any settlement period is less
than the swap price for such transaction, and THEC is required to make payment
to the counter party in the event that the settlement price for any settlement
period is greater than the swap price for such transaction. For any particular
collar transaction, the counter party is required to make a payment to THEC if
the settlement price for any settlement period is below the floor price for such
transaction, and THEC 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 THEC if the settlement price for any settlement period is
below the floor price for such transaction. THEC is not required to make any
payment in connection with a floor transaction. For option contracts, THEC has
the option, but not the obligation, to buy contracts up to the day before the
last trading day for that NYMEX contract.
84
The following table summarizes the notional amounts and related fair values of
the derivative financial instrument positions outstanding at December 31, 1998.
Fair values are based on quotes for the same or similar instruments.
- ----------------------------------------------------------------------------------------------
Gas: Type of Fiscal Year of Fixed Price Per Volume Notional
Contracts Maturity Mcf (Mcf) Amount Fair Value
- --------------- ----------- ------------- ----------- ----------- ------------
(In Thousands of Dollars)
Futures 1999/2000 $1.90-$2.55 12,270,000 $28,295 $24,190
Collars 1999
Ceiling $2.90 280,000 $812 -
Floor $2.40 280,000 $672 $126
Swaps 1999 $2.50 755,000 $1,887 $534
- ----------------------------------------------------------------------------------------------
Oil: Type of Fiscal Year of Fixed Price Per Volume Notional
Contracts Maturity Gallon (Gallons) Amount Fair Value
- --------------- ----------- ------------- ----------- ----------- ------------
(In Thousands of Dollars)
Futures 1999 $0.56-$0.58 4,284,000 $476 $1,474
- ----------------------------------------------------------------------------------------------
As of December 31, 1998, no futures contract extended beyond May 2000. Margin
deposits with brokers at December 31, 1998 of $10.7 million were recorded in
Other in the Current Assets section of the Consolidated Balance Sheet. Deferred
losses on closed positions were $4.0 million at December 31, 1998. Such
deferrals are generally recorded in net income within one month.
The Company's subsidiaries 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. The Company believes 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.
In addition to the derivative instruments discussed above, at December 31, 1998,
THEC had one interest rate swap agreement to exchange the differential between a
fixed rate of 6.025% and a market LIBOR rate using an aggregate notional
principal of $30.0 million over various 90-day periods from November 1998
through November 1999.
LEGAL MATTERS: From time to time, the Company is subject to various legal
proceedings arising out of the ordinary course of its business. Except as
described below, the Company does not consider any of such proceedings to be
material to its business or likely to result in a material adverse effect on its
results of operations or financial condition.
85
Subsequent to the LIPA Transaction and KeySpan Acquisition, former shareholders
of LILCO commenced 13 class action lawsuits in the New York State Supreme Court,
Nassau County, against each of the former officers and directors of LILCO and
the Company. These actions were consolidated in August 1998. The consolidated
action alleges that in connection with certain payments LILCO had determined
were payable in connection with the LIPA Transaction and KeySpan Acquisition to
LILCO's chairman, and to former officers of LILCO ("Payments"): (i) the named
defendants breached their fiduciary duty owed to LILCO and KSE former and/or
current Company shareholders as a result of the Payments; (ii) the named
defendants intended to defraud such shareholders by means of manipulative,
deceptive and wrongful conduct, including materially inaccurate and incomplete
news reports and filings with the Securities and Exchange Commission ("SEC");
and (iii) the named defendants recklessly and/or negligently failed to disclose
material facts associated with the Payments.
In addition, three shareholder derivative actions have been commenced pursuant
to which such shareholders seek the return of the Payments or damages resulting
from among other things, an alleged breach of fiduciary duty on the part of the
former LILCO officers and directors. One action was brought on behalf of LILCO
in federal court. The Company moved to dismiss this action in September 1998.
The other two actions were brought on behalf of the Company in New York State
Supreme Court, Nassau County. In one of these state court actions, the Company's
directors and the recipients of the Payments are also named as defendants.
Finally, two class action securities suits were filed in federal court alleging
that certain officers and directors of LILCO violated the federal securities
laws by failing to properly disclose that the LIPA Transaction and KeySpan
Acquisition would trigger the Payments. These actions were consolidated in
October 1998.
On March 17, 1999, the Company signed a Memorandum of Understanding to settle
the above-referenced actions, except the federal court derivative action, in
exchange for (i) $7.9 million to be distributed (less plaintiffs' attorneys
fees) to former LILCO and KSE shareholders and (ii) the Company's agreement to
implement certain corporate governance and executive compensation procedures.
The entire $7.9 million settlement commitment will be funded from insurance. The
parties intend to submit the settlement to the Nassau County Supreme Court for
its review and approval. If that Court approves the settlement, the parties will
then make an application to the federal court for an order and final judgment,
dismissing the three federal court actions, including the federal court
derivative action, based, among other things, on the binding effect of the state
court judgment.
In addition to the above mentioned actions, a class action lawsuit has also been
filed in the New York State Supreme Court, Suffolk County, by the County of
Suffolk against LILCO's former officers and/or directors. The County of Suffolk
alleges that the Payments were improper, and seeks to recover the Payments for
the benefit of Suffolk County ratepayers. The Company moved to consolidate this
action with the above-mentioned consolidated action in October 1998.
86
In October 1998, the County of Suffolk and the Towns of Huntington and Babylon
commenced an action against LIPA, the Company, 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, the plaintiffs amended their complaint. The
amended complaint contains allegations relating to the Payments and adds the
recipients of the Payments as defendants. In January 1999, the Company was
served with the amended complaint.
Finally, certain other proceedings have been commenced relating to the Payments
and disclosures made by LILCO with respect thereto. These proceedings include
investigations by the New York State Attorney General, the NYPSC and LIPA, joint
hearings conducted by two committees of the New York State Assembly, and an
informal, non-public inquiry by the SEC. In December 1998, the Company settled
with LIPA and the NYPSC. The agreement included a payment of $5.2 million by the
Company to LIPA that will be used by LIPA to supply postage-paid bill return
envelopes to customers for the next three years. The Company also agreed to
fully reimburse and indemnify LIPA for costs incurred by LIPA, amounting to
approximately $765,000, for attorneys and other consultants involved in the
investigation. Such amounts are not covered by insurance. The Company is
cooperating fully with the investigations of the New York State Attorney General
and the SEC. To date, no action has been taken either by the New York State
Attorney General or the SEC.
At this time the Company is unable to determine the outcome of the ongoing
proceedings, or any of the remaining lawsuits described above.
THE CLASS SETTLEMENT: The Class Settlement, which became effective in June 1989,
resolved a civil lawsuit against LILCO brought under the federal Racketeer
Influenced and Corrupt Organizations Act. The lawsuit, which the Class
Settlement resolved, had alleged that LILCO made inadequate disclosures before
the NYPSC concerning the construction and completion of nuclear generating
facilities. The Class Settlement provided electric customers with rate
reductions of $390.0 million that were being reflected as adjustments to their
monthly electric bills over a ten-year period which began on June 1, 1990. Upon
its effectiveness, a liability was recorded for the Class Settlement on a
present value basis at $170.0 million. The Class Settlement obligation of
approximately $75.0 million at December 31, 1998 reflects the present value of
the remaining reductions to be refunded to customers. The reduction in the
present value of this liability has been included in the accompanying
Consolidated Income Statement. As a result of the LIPA Transaction, LIPA will
reimburse the remaining balance to its electric customers as an adjustment to
their monthly electric bills. The Company will then, in turn, reimburse LIPA on
a monthly basis for such reductions on the customer's monthly bill. The Company
remains ultimately obligated for the refund of the Class Settlement.
87
ENVIRONMENTAL MATTERS: The Company has recorded a $130.3 million liability
associated with investigation and remedial obligations with respect to nine of
the Company's former manufactured gas plants ("MGP"). Three of these MGP sites
are associated with Brooklyn Union's operations or its predecessors; six MGP
sites are associated with the operations of Brooklyn Union of Long Island or its
predecessors. With respect to the former Brooklyn Union MGP sites, a total of
$48.3 million has been accrued representing the best estimate of remedial costs
for one site and the minimum range of an estimate for the investigation and/or
remediation of the other sites. With respect to Brooklyn Union of Long Island
MGP sites, a total of $82 million has been reserved as a minimum of an estimated
range of costs for the six sites which will be investigated/remediated pursuant
to upcoming Administrative Orders on Consent ("ACO's") with the New York State
Department of Environmental Conservation ("DEC"). As the Company continues its
investigations and makes remedial decisions pursuant to its ACO obligations, the
environmental conditions at each site will be clarified and the Company's total
remedial obligations are likely to be higher.
Under prior rate orders, the NYPSC has allowed recovery of investigation costs
related to certain Brooklyn Union MGP sites. Therefore, at December 31, 1998,
the Company had reflected a total remaining regulatory asset of approximately
$100.5 million. The Company believes that current rate plans in effect provide
for recovery of environmental costs.
NOTE 9. KSE AND SUBSIDIARIES
The following is the condensed consolidated statement of income for KSE and its
subsidiaries for the eight months ended May 28, 1998. As a result of purchase
accounting, such amounts have been excluded from the financial statements of the
Company and are disclosed here for informational purposes. The financial
statements for KSE's most recent fiscal year end were as of September 30, 1997.
KSE AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENT OF INCOME
FOR THE PERIOD OCTOBER 1, 1997 - MAY 28, 1998
(In Thousands of Dollars)
Eight Months Ended
May 28, 1998
-----------------------------------------------------
Operating revenues $ 1,173,052
Operating expenses 1,029,981
Operating income 143,071
Other income 7,385
Interest charges 30,495
-----------------------------------------------------
Income available for common stock $ 119,961
-----------------------------------------------------
Earnings per share $ 2.35
-----------------------------------------------------
88
Consolidated earnings for the eight months ended May 28, 1998 were $120.0
million, or $2.35 per share. Core utility operations contributed $136.7 million
or $2.68 per share. THEC contributed $12.5 million or $0.24 per share to
earnings, while Energy Related Investments had a loss of $6.2 million or $0.12
per share and Energy Related Services showed a loss of $6.5 million or $0.13 per
share, reflecting the effect of various costs related to market development.
Utility results reflected the favorable effect of gas heating sales during the
prime heating months of November through April when total annual gas revenues
are substantially realized. Losses are incurred for the period May through
September and have not been reflected in these results. In addition, $16.5
million or $0.32 per share of primarily merger related expenses were recorded by
KSE's administrative and service area and were not allocated to KSE's
subsidiaries. Cash provided by operating activities for the eight months ended
May 28, 1998 was $253.6 million and cash provided by financing activities was
$5.5 million. For the eight months ended May 28, 1998 cash used in investing
activities was $130.9 million and at May 28, 1998 KSE had cash and temporary
cash investments of $165.2 million.
NOTE 10. BUSINESS SEGMENTS
SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Company
Information," requires the reporting of certain financial information by
business segments. The Company has six reportable segments: Gas Distribution,
Electric Services, Gas Exploration and Production, Energy Related Investments,
Energy Related Services and Other. The Gas Distribution reportable segment
consists of the two gas distribution companies serving customers in the New York
City boroughs of Brooklyn, Staten Island and Queens and the Long Island counties
of Nassau and Suffolk. The Electric Services reportable segment consists of
subsidiaries that own and operate oil and gas fired generating plants, and
through long term contracts, manage the electric T&D system, the fuel and
electric purchases, and the off-system sales for LIPA. The Gas Exploration and
Production reportable segment, consisting of THEC, is engaged in gas and oil
exploration and production, and the development and acquisition of domestic
natural gas and oil properties. Subsidiaries included in the Energy Related
Investments segment have investments in natural gas pipelines, midstream natural
gas processing and gathering facilities and gas storage facilities. The Energy
Related Services segment consists of subsidiaries that primarily provide gas and
electric marketing and related energy systems installation, appliance service
contracts and management services to customers primarily in the New York City
metropolitan area. The Other reportable segment represents unallocated
administrative expenses of the Company.
89
The accounting policies of the segments are the same as those described in the
summary of significant accounting policies. The Company's reportable segments
are strategic business units that are managed separately because of their
different operating and regulatory environments. The reportable segment
information is as follows:
Energy Energy
Gas Electric Gas Exploration Related Related Reconciling
Distribution Services and Production Investments Services Other Eliminations Consolidated
---------------------------------------------------------------------------------------------------------------
9 MONTHS ENDED (IN THOUSANDS OF DOLLARS)
DECEMBER 31, 1998
Revenues 851,656 753,636 70,812 117 62,435 171,414 (188,218) 1,721,852
Depreciation and
amortization 57,351 45,900 177,114 216 1,117 13,166 - 294,864
Interest income - - - - - 49,200 - 49,200
Interest expense 60,678 69,953 3,870 - - 58,682 (54,468) 138,715
Income (loss) before
special charges 8,582 57,119 2,218 (4,186) (3,708) 2,959 - 62,984*
Loss from equity method
subsidiaries - - - (5,842) - - - (5,842)
Total assets 3,919,311 1,456,094 569,454 428,746 116,940 12,151,745 (11,747,188) 6,895,102
Investment in equity
method subsidiaries - - - 341,346 - - - 341,346
Capital expenditures 128,405 54,090 182,729 231,791 28,421 51,127 - 676,563
*Excludes special charges of $258.5 million after-tax. See Note 11 -
Costs Related to the LIPA Transaction ges. and Special Charges.
Electric Services revenues from LIPA, its only customer, of $408.3
million for the nine months ended December 31, 1998 represents
approximately 24% of the Company's consolidated revenue during that
period.
Reconciling items include intercompany revenues and intercompany
interest expense and the elimination of intercompany ownership
interests within the affiliated entities.
90
Energy Energy
Gas Electric Gas Exploration Related Related Reconciling
Distribution Services and Production Investments Services Other Eliminations Consolidated
---------------------------------------------------------------------------------------------------------------
12 MONTHS ENDED (IN THOUSANDS OF DOLLARS)
MARCH 31, 1998
Revenues 645,659 2,478,435 - - - - - 3,124,094
Depreciation and
amortization 38,584 131,186 - - - - - 169,770
Interest expense 52,409 352,064 - - - - - 404,473
Net income 33,815 276,612 - - - - - 310,427
Total assets 1,444,745 10,455,980 - - - - - 11,900,725
Capital expenditures 78,897 218,333 - - - - - 297,230
Energy Energy
Gas Electric Gas Exploration Related Related Reconciling
Distribution Services and Production Investments Services Other Eliminations Consolidated
---------------------------------------------------------------------------------------------------------------
3 MONTHS ENDED (IN THOUSANDS OF DOLLARS)
MARCH 31, 1997
Revenues 293,391 557,791 - - - - - 851,182
Depreciation and
Amortization 7,827 31,993 - - - - - 39,820
Interest Expense 13,708 92,170 - - - - - 105,878
Net Income 46,925 27,803 - - - - - 74,728
Total Assets 1,267,600 10,582,400 - - - - - 11,850,000
Capital Expenditures 15,804 46,675 - - - - - 62,479
Energy Energy
Gas Electric Gas Exploration Related Related Reconciling
Distribution Services and Production Investments Services Other Eliminations Consolidated
---------------------------------------------------------------------------------------------------------------
12 MONTHS ENDED (IN THOUSANDS OF DOLLARS)
DECEMBER 31, 1996
Revenues 684,260 2,466,435 - - - - - 3,150,695
Depreciation and
amortization 43,147 128,534 - - - - - 171,681
Interest expense 54,811 392,818 - - - - - 447,629
Net income 38,471 225,777 - - - - - 264,248
Total assets 1,460,600 10,749,400 - - - - - 12,210,000
Capital expenditures 76,938 214,680 - - - - - 291,618
91
NOTE 11. COSTS RELATED TO THE LIPA TRANSACTION AND SPECIAL CHARGES
Special charges for the nine months ended December 31, 1998 were $258.5 million
after-tax. These charges reflected, in part, non-recurring charges associated
with the LIPA Transaction of $107.9 million after-tax. Costs relating to the
LIPA Transaction principally reflected taxes associated with the sale of assets
(the "Transferred Assets") to the Company 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
post-employment benefits for employees of the successor company.
Further, the Company incurred charges related to the KeySpan Acquisition of
$83.5 million after-tax. These charges reflected a $42.0 million after-tax
charge for an early retirement program initiated by the Company in December 1998
in which approximately 600 employees participated, and a $41.5 million after-tax
charge for the write-off of a customer billing system that was in development.
Also, in December 1998, the Company made a $20.0 million donation ($13.0 million
after-tax) to establish the KeySpan Foundation, a not-for-profit philanthropic
foundation that will make donations to local charitable community organizations.
Special charges also reflected an after-tax impairment charge of $54.1 million,
which represented the Company's share of the impairment charge, recorded by the
Company's gas and oil exploration and production subsidiary to reduce the value
of its proved gas reserves in accordance with the asset ceiling test limitations
of the Securities and Exchange Commission applicable to gas exploration and
development operations accounted for under the full cost method.
NOTE 12. SUPPLEMENTAL DISCLOSURE OF KSE AND SUBSIDIARIES (UNAUDITED)
For the twelve months ended December 31, 1998 net income of the consolidated
entities comprising KSE was $12.5 million compared to $126.3 million for the
1997 corresponding period. Net income in 1998 was affected by rate reductions to
gas utility customers; significantly warmer than normal weather during the
period; certain special charges associated with the KeySpan Acquisition of $23.5
million after-tax, including charges associated with the early retirement
program; and an impairment charge of $54.1 million after-tax to reduce the value
of proved gas reserves. Energy Related Investment earnings for the twelve months
ended December 31, 1997 reflected the sale of certain subsidiary properties for
$15.2 million after-tax. Consolidated net income together with the effect of
special charges, is set forth in the following table:
KSE AND SUBSIDIARIES
Twelve Months Twelve Months
Results of Operations Ended Ended
(In Thousands of Dollars) December 31, 1998 December 31, 1997
- ------------------------------ ---------------- -----------------
Gas Distribution $99,406 $93,205
Gas Exploration and Production 8,995 15,774
Energy Related Investments (6,098) 21,669
Energy Related Services (9,119) (3,896)
Other (3,136) (487)
Income before special charges 90,048 126,265
Special charges (77,591) -
- ------------------------------ ---------------- -----------------
Consolidated net income $12,457 $126,265
============================== ================ =================
Earnings from Gas Distribution operations for the twelve months ended December
31, 1998 were impacted by synergy savings-related rate reductions of $23.9
million effective May 29, 1998. Brooklyn Union core customers have received the
benefits of these reductions before actual savings
92
could be achieved. Moreover, in 1998 results were affected by significantly
warmer than normal weather. Weather was 18% warmer than normal in 1998 as
compared to normal weather experienced in 1997. The effects of weather on Gas
Distribution revenues is largely mitigated by the weather normalization
adjustment included in Brooklyn Union's tariff; nevertheless, significant
fluctuations in normal weather will affect revenues collected from heating
customers. The effects of the rate reduction and the significantly warmer winter
heating season reduced net revenues, revenues less gas costs, by $24.2 million
for the twelve months ended December 31, 1998 as compared to the corresponding
period last year.
The aforementioned variations in net revenues were totally offset by cost
reduction measures and re-engineering processes employed by KSE during the past
few years. Further, operation and maintenance expense was lower in 1998 due to
the exceptionally warm weather experienced. Earnings from gas utility operations
provided an equity return, including discrete incentives, of 13.6% for the rate
year ending September 30, 1998 as compared to 13.5% for the rate year ending
September 30, 1997.
Earnings from Gas Exploration and Production activities in 1998 and 1997
reflected the continued expansion of operations, primarily in Texas and the Gulf
of Mexico, by THEC. Earnings in 1998, however, were significantly affected by
low gas production prices. Included in special charges above, is an after-tax
charge of $54.1 million representing the Company's share of an impairment charge
recorded by THEC to reduce the value of its investment in proved gas reserves in
accordance with the asset ceiling test limitations of the Securities and
Exchange Commission.
Revenues from gas production activities increased in 1998 as compared to 1997 by
approximately 9% due primarily to the continued development of additional
natural gas properties acquired by THEC during the past three years. The
benefits derived from increased production levels, however, were partially
offset, by decreases in average realized prices. In 1998, production was 62.8
billion cubic feet (BCFe), or 11.5 BCFe above the level of production last year.
In 1998, wellhead prices averaged $1.96 per MCF compared with $2.45 per MCF in
1997. The effective price realized (average wellhead price received for
production including recognized hedging gains and losses) was $2.02 per MCF in
1998 compared with $2.25 per MCF in 1997. Further, operating expenses,
including, depreciation, depletion and amortization expense, increased by
approximately 30% for the year ended December 31, 1998 as compared with the year
ended December 31, 1997 due primarily to increased production activity.
Earnings from the Energy Related Investments segment consists of results from
the Company's 20% interest in the Iroquois Gas Transmission System LP ,
investments in The Premier Transco Pipeline and Phoenix Natural Gas in Northern
Ireland and investments in midstream natural gas assets in Western Canada owned
jointly with Gulf Canada Resources Limited. Results from these investments, for
the year ended December 31, 1998, reflected the start-up nature of their
operations, while results relating to the investment in the Iroquois Gas
Transmission System for 1998 and 1997 were consistent with management's
expectations and reflected after-tax earnings of $6.5 million. The Company
completed its acquisition of midstream natural gas assets in Western Canada in
93
December 1998, and therefore, earnings from this investment will begin to be
realized in fiscal year 1999. Results also reflected costs to settle certain
contracts associated with the sale of the Company's domestic cogeneration
investments and fuel management operations, which took place in 1997. Earnings
in 1997 primarily reflected the sale of certain Canadian properties and the sale
of domestic cogeneration investments and fuel management operations.
Subsidiaries comprising the Energy Related Services segment incurred losses for
the past two years reflecting the start-up nature of their operations. Included
in this business segment are operations which market gas and electricity and
arrange transportation and related services, largely to retail customers,
including those served by the Company's gas distribution subsidiaries. In
addition, these subsidiaries provide a variety of technical and maintenance
services to customers that operate commercial and industrial facilities and
provide appliance repair service to residential customers, all located within
the New York City metropolitan area. During the past two years, the Company has
acquired an engineering firm, and major heating, ventilation and air
conditioning contractors and has integrated these operations into its strategies
for future growth.
Results from the Other segment reflected certain costs associated with corporate
and administrative functions that were not allocated to various business
segments.
94
NOTE 13. DISAGGREGATED CONDENSED BALANCE SHEET (UNAUDITED)
Set forth below is LILCO's condensed balanced sheet at May 28, 1998, which has
been disaggregated to reflect the effects of the LIPA Transaction. The assets,
capitalization and liabilities attributable to KeySpan subsidiaries represent
LILCO's transfer of its gas and generation business to KeySpan subsidiaries. The
assets, capitalization and liabilities attributable to LIPA represent those
items that have been acquired or assumed by LIPA through its acquisition of
LILCO's common stock. All such amounts exclude the proceeds from the sale of
common stock to LIPA. For a further discussion of the LIPA Transaction, see Note
2, "Sale of LILCO Assets, Acquisition of KeySpan Energy Corporation and Transfer
of Assets and Liabilities to the Company."
(In Millions of Dollars)
- ------------------------------------------------------------------------------------
Allocation of Assets/Liabilities
--------------------------------
KeySpan
LILCO Subsidiaries LIPA
- ------------------------------------------------------------------------------------
ASSETS
Total net utility plant $ 3,853.6 $ 1,798.0 $ 2,055.6
- ------------------------------------------------------------------------------------
Regulatory assets
Shoreham related 4,692.4 - 4,692.4
Regulatory tax asset 1,660.9 - 1,660.9
Other 681.4 445.9 235.5
- ------------------------------------------------------------------------------------
Total regulatory assets 7,034.7 445.9 6,588.8
Nonutility property and other investments 52.1 33.1 19.0
Current assets 1,083.1 397.0 686.1
Deferred charges 87.2 33.2 54.0
- ------------------------------------------------------------------------------------
Total assets $ 12,110.7 $ 2,707. $ 9,403.5
====================================================================================
CAPITALIZATION AND LIABILITIES
Capitalization
Long-term debt, including current
maturities $ 4,383.1 $ 24.4 $ 4,358.7
Promissory notes - 1,047.9 (1,047.9)
Preferred stock, including current 659.6 438.0 221.6
maturities
Common shareholders' equity $ 2,682.6 181.8 2,500.8
- ------------------------------------------------------------------------------------
Total capitalization 7,725.3 1,692.1 6,033.2
Regulatory liabilities 380.7 68.4 312.3
Current liabilities 1,103.8 752.3 351.5
Deferred credits 2,708.7 1.5 2,707.2
Operating reserves 192.2 192.9 ( 0.7)
- ------------------------------------------------------------------------------------
Total capitalization and liabilities $ 12,110.7 $ 2,707.2 $ 9,403.5
====================================================================================
95
Note 14. Supplemental Gas and Oil Disclosures (Unaudited)
This information includes amounts attributable to a 36% minority interest in
THEC at December 31, 1998 and a 34% minority interest in 1997 and 1996. 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, 1998 1997
- -----------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
Unproved properties not being amortized $145,317 $104,075
Properties being amortized - productive and nonproductive 828,168 566,868
- -----------------------------------------------------------------------------------------------------------
Total capitalized costs 973,485 670,943
Accumulated depletion (438,974) (229,776)
- -----------------------------------------------------------------------------------------------------------
Net capitalized costs $534,511 $441,167
- -----------------------------------------------------------------------------------------------------------
The following is a break-out of the costs (in thousands of dollars) which are
excluded from the amortization calculation as of December 31, 1998, by year of
acquisition: 1998 - $68,931 1997 - $34,259 and prior years $42,127 . The Company
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, 1998 1997 1996
- ---------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
Acquisition of properties-
Unproved properties $33,803 $16,613 $23,317
Proved properties 162,083 24,007 94,774
Exploration 55,611 44,119 27,398
Development 51,046 59,244 31,243
- ---------------------------------------------------------------------------------------------------
Total costs incurred $302,543 $143,983 $176,732
- ---------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS FROM GAS AND OIL PRODUCING ACTIVITIES
- -----------------------------------------------------------------------------------------------------------
Year Ended December 31, 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------
(In Thousands of Dollars)
Revenues from gas and oil
producing activities-
Sales to unaffiliated parties $127,124 $116,349 $64,864
- ----------------------------------------------------------------------------------------------------------
Revenues 127,124 116,349 64,864
- ----------------------------------------------------------------------------------------------------------
Production and lifting costs 21,166 18,379 12,201
Depletion 209,838 59,081 33,732
- ----------------------------------------------------------------------------------------------------------
Total expenses 231,004 77,460 45,933
- ----------------------------------------------------------------------------------------------------------
Income before taxes (103,880) 38,889 18,931
Income taxes (37,410) 12,397 5,192
- ----------------------------------------------------------------------------------------------------------
Results of gas and oil producing
activities (excluding corporate
overhead and interest costs) ($66,470) $26,492 $13,739
- ----------------------------------------------------------------------------------------------------------
96
NOTE 14. SUPPLEMENTAL GAS AND OIL DISCLOSURES (CONTINUED)
The gas and oil reserves information is based on estimates of proved reserves
attributable to THEC's interest 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.
The standardized measure of discounted future net cash flows was prepared by
applying year-end prices of gas and oil to the proved reserves, except for those
reserves devoted to future production that is hedged. Such reserves are priced
at their respective hedged amounts. The standardized measure does not purport,
nor should it be interpreted, to present the fair value of THEC's gas and oil
reserves. An estimate of fair value would also take into account, among other
things, the recovery of reserves not presently classified as proved, anticipated
future changes in prices and costs and a discount factor more representative of
the time value of money and the risks inherent in reserve estimates.
Reserve Quantity Information
Natural Gas (MMcf)
At December 31, 1998 1997 1996
- --------------- ---- ---- ----
Proved reserves-
Beginning of year 330,601 320,474 195,946
Revisions of previous estimates (4,656) (18,743) (8,665)
Extensions and discoveries 67,272 75,651 21,445
Production (61,479) (50,310) (31,215)
Purchases of reserves in place 139,994 3,778 143,688
Sales of reserves in place (1,285) (249) (725)
Proved reserves-
End of year 470,447 330,601 320,474
Proved developed reserves-
Beginning of year 256,632 236,544 162,784
End of year 369,931 256,632 236,544
Crude Oil, Condensate and Natural Gas Liquids (MBbls)
At December 31, 1998 1997 1996
- --------------- ---- ---- ----
Proved reserves-
beginning of year 1,077 1,131 889
Revisions of previous estimates (105) (62) (157)
Extensions and discoveries 249 184 198
Production (225) (171) (118)
Purchases of reserves in place 665 1 361
Sales of reserves in place (11) (6) (42)
Proved reserves-
end of year 1,650 1,077 1,131
Proved developed reserves-
Beginning of year 914 1,013 774
End of year 1,498 914 1,013
97
Note 14. Supplemental Gas and Oil Disclosures (continued)
Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Gas and Oil Reserves
At December 31, 1998 1997
- --------------- ---- ----
(In Thousands of Dollars)
Future cash flows $878,448 $781,336
Future costs-
Production (153,567) (135,437)
Development (103,915) (84,658)
Future net inflows
before income tax 620,966 561,241
Future income taxes (89,032) (124,510)
Future net cash flows 531,934 436,731
10% discount factor (135,874) (121,351)
Standardized measure of
discounted future net
cash flows $396,060 $315,380
Changes in Standardized Measure of Discounted Future Net Cash Flows from
Proved Reserve Quantities
Year Ended December 31, 1998 1997 1996
- ----------------------- ---- ---- ----
(In Thousands of Dollars)
Standardized measure -
beginning of year $315,380 $452,582 $171,459
Sales and transfers, net of
production costs (105,958) (97,968) (52,663)
Net change in sales and
transfer prices, net of
production costs (104,137) (223,169) 145,385
Extensions and discoveries and
improved recovery, net of
related costs 72,333 114,893 46,616
Changes in estimated future
development costs (6,656) (20,499) (14,068)
Development costs incurred
during the period that reduced
future development costs 15,891 16,154 19,594
Revisions of quantity estimates (4,982) (23,156) (19,132)
Accretion of discount 37,706 57,700 20,652
Net change in income taxes 44,812 62,733 (89,353)
Net purchases of reserves in place 155,259 1,855 250,990
Changes in production rates
(timing) and other (23,588) (25,745) (26,898)
Standardized measure -
end of year $396,060 $315,380 $452,582
98
Note 14. Supplemental Gas and Oil Disclosures (continued)
AVERAGE SALES PRICES AND PRODUCTION COSTS PER UNIT
- ------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1998 1997 1996
- ------------------------------------------------------------------------------------------------------------------------------
Natural gas ($/MCF) 1.96 2.45 2.35
Oil, condensate and natural gas liquid ($/Bbl) 12.18 18.33 21.53
Production cost per equivalent MCF ($) 0.26 0.28 0.34
- ------------------------------------------------------------------------------------------------------------------------------
ACREAGE
- ------------------------------------------------------------------------------------------------------------------------------
At December 31, 1998 Gross Net
- ------------------------------------------------------------------------------------------------------------------------------
Producing 297,360 197,902
Undeveloped 317,049 282,822
- ------------------------------------------------------------------------------------------------------------------------------
NUMBER OF PRODUCING WELLS
- ------------------------------------------------------------------------------------------------------------------------------
At December 31, 1998 Gross Net
- ------------------------------------------------------------------------------------------------------------------------------
Gas wells 1,239 803
Oil wells 8 3
- ------------------------------------------------------------------------------------------------------------------------------
DRILLING ACTIVITY (Net)
- ------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1998 1997 1996
- ------------------------------------------------------------------------------------------------------------------------------
Producing Dry Total Producing Dry Total Producing Dry Total
- ------------------------------------------------------------------------------------------------------------------------------
Net developmental wells 19.2 4.6 23.8 29.3 8.5 37.8 7.0 1.0 8.0
Net exploratory wells 1.6 4.2 5.8 3.8 2.9 6.7 4.3 4.4 8.7
- ------------------------------------------------------------------------------------------------------------------------------
WELLS IN PROCESS
- ------------------------------------------------------------------------------------------------------------------------------
At December 31, 1998 Gross Net
- ------------------------------------------------------------------------------------------------------------------------------
Exploratory 2.0 0.7
Developmental 3.0 0.6
- ------------------------------------------------------------------------------------------------------------------------------
*Represents the cash price received which excludes the effect of any
hedging transactions.
99
Supplementary Information (Unaudited)
Summary of Quarterly Information
The following is a table of financial data for each quarter of the Company's
nine month period ended December 31, 1998.
(In Thousands of Dollars, Except Per Share Data)
Quarter End Quarter End Quarter Ended
6/30/98 9/30/98 12/31/98
- --------------------------------------------------------------------------------
Operating revenues (a) 568,986 426,258 726,608
Operating income (loss) 184,236 (8,530) (162,467)
Net income (loss) 37,250 (17,656) (186,527)(b)
Earnings (loss) for common stock 26,034 (26,350) (195,221)
Basic and diluted earnings (loss)
per common share (c) 0.19 (0.17) (1.34)
Dividends declared 0.300 (d) 0.445 0.445
- --------------------------------------------------------------------------------
(a)Includes revenues from various LIPA service agreements for the period May 29,
1998 through December 31, 1998 and electric distribution revenues for the
period April 1, 1998 through May 28, 1998.
(b)Reflects the following after-tax charges: LIPA Transaction charges of $97.6
million; KeySpan Acquisition charges of $83.5 million; an impairment charge
of $54.1 million to write-down the value of proved gas reserves; and a charge
of $13.0 million to establish the KeySpan Foundation. (See Note 11 to the
Consolidated Financial Statements,"Costs Related to the LIPA Transaction and
Special Charges.")
(
c)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.
(d) Prorated portion for approximately two months of a dividend of $1.78 per
share annually.
Summarized quarterly financial data of LILCO for 1998 and 1997
(In Thousands of Dollars, Except Per Share Data)
- --------------------------------------------------------------------------------------------------------
3 Months Ended Fiscal Year Ended March 31, 1998
-------------- --------------------------------
3/31/97 6/30/97 9/30/97 12/31/97 3/31/98
------- ------- ------- -------- -------
Operating revenues 851,182 664,488 852,408 779,622 827,576
Operating income 190,001 144,079 242,611 171,969 209,637
Net income 87,697 45,161 144,384 56,756 115,939
Earnings for common stock 74,728 32,193 131,435 43,807 102,992
Basic and diluted earnings per .62 .26 1.09 .36 .85
common share
========================================================================================================
100
REPORT OF ARTHUR ANDERSEN LLP, INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of MarketSpan Corporation d/b/a
KeySpan Energy:
We have audited the accompanying Consolidated Balance Sheet and Consolidated
Statement of Capitalization of MarketSpan Corporation (a New York corporation)
and subsidiaries as of December 31, 1998 and the related Consolidated Statements
of Income, Retained Earnings and Cash Flows for the nine months ended December
31, 1998. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audit.
We conducted our audit in accordance with generally accepted auditing standards.
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position and capitalization of MarketSpan
Corporation and subsidiaries as of December 31, 1998 and the results of their
operations and their cash flows for the nine months ended December 31, 1998, in
conformity with generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on the basic
consolidated financial statements taken as a whole. The schedule listed in Item
14 is the responsibility of the Company'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 consolidated financial statements. This schedule has been
subjected to the auditing procedures applied in the audits of the basic
consolidated 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 consolidated financial statements taken as a whole.
ARTHUR ANDERSEN LLP
February 12, 1999
New York, New York
101
REPORT OF ERNST & YOUNG LLP, INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Long Island Lighting Company:
We have audited the accompanying Balance Sheet of Long Island Lighting Company
and the related Statement of Capitalization as of March 31, 1998 and the related
Statements of Income, Retained Earnings and Cash Flows for the twelve months
ended March 31, 1998, the three months ended March 31, 1997 and the year ended
December 31, 1996. Our audits also included the financial statement schedule
listed in the index at Item 14(a). These financial statements and schedule are
the responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. 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 of Long Island Lighting Company at
March 31, 1998 and the results of its operations and its cash flows for the
twelve months ended March 31, 1998, the three months ended March 31, 1997 and
the year ended December 31, 1996, in conformity with generally accepted
accounting principles. Also, in our opinion, the related financial statement
schedule, when considered in relation to the basic financial statements taken as
a whole, presents fairly in all material respects the information set forth
therein.
During the year ended March 31, 1998 the Company changed its method of
accounting for revenues provided for under the Rate Moderation Component.
ERNST & YOUNG LLP
May 22, 1998
Melville, New York
102
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 is expected to be filed with the SEC on
or about April 7, 1999 (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
"Transactions with Management and Others" in the Proxy Statement, which
information is incorporated herein by reference thereto.
103
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
1. FINANCIAL STATEMENTS
The following consolidated financial statements of the Company 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 nine months ended December
31, 1998, twelve months ended March 31, 1998, three months ended
March 31, 1997 and year ended December 31, 1996
Consolidated Statement of Retained Earnings for the nine months ended
December 31, 1998, twelve months ended March 31, 1998, three
months ended March 31, 1997 and year ended December 31, 1996
Consolidated Balance Sheet at December 31, 1998 and March 31, 1998
Consolidated Statement of Capitalization at December 31, 1998 and
March 31, 1998
Consolidated Statement of Cash Flows for the nine months ended
December 31, 1998, twelve months ended March 31, 1998, three
months ended March 31, 1997 and year ended December 31, 1996
Notes to Consolidated Financial Statements
2. FINANCIAL STATEMENTS SCHEDULES
Consolidated Schedule of Valuation and Qualifying Accounts for the
nine months ended December 31, 1998, the twelve months ended
March 31, 1998, three months ended March 31, 1997 and the year
ended December 31, 1996
All other schedules are omitted because they are not applicable or
the required information is shown in the financial statements or notes thereto.
104
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, and Amendment to Certificate of
Incorporation of the Company effective June 1, 1998 (filed as
Exhibit 3 to the Company's Form 10-Q for the quarterly period
ended June 30, 1998)
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 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)
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)
4.2 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)
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)
4.3 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)
First Supplemental Trust Indenture dated as of May 1, 1992 to
Trust Indenture dated February 1, 1989 between NYSERDA and
Manufacturers Hanover Trust Company, as Trustee, relating to
Adjustable Rate GFRBs, Series 1989A & B (filed as Exhibit 4 to The
Brooklyn Union Gas Company Form 10-K for the year ended September
30, 1992)
4.4 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)
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)
4.5 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)
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)
105
4.6 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)
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)
4.7 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)
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)
4.8 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)
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)
4.9 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)
Participation Agreement dated as of December 1, 1997 by and
between NYSERDA and Long Island Lighting Company relating to the
1997 EFRBs, Series A (filed as Exhibit 10(a) to the Company's Form
10-Q for the quarterly period ended September 30, 1998)
10.1 Agreeement of Lease between Forest City Jay Street Associates and
The Brooklyn Union Gas Company dated September 15, 1988 (filed as
an exhibit to The Brooklyn Union Gas Company Form 10-K for the
year ended September 30, 1996)
10.2 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 Company, 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)
106
10.3 Credit Agreement dated as of July 2, 1996 among The Houston
Exploration Company and Texas Commerce Bank National Association,
as Agent, and the other Banks signatory thereto (filed as Exhibit
10.16 to The Houston Exploration Company's Registration Statement
on Form S-1 (Registration No. 333-4437))
10.4 First Amendment, dated August 30, 1996, to the Credit Agreement
among The Houston Exploration Company and Texas Commerce Bank
National Association, as Agent, and the other Banks signatory
thereto (filed as Exhibit 10.11 to The Houston Exploration
Company's Annual Report on Form 10-K for the year ended December
31, 1997 (001-11899))
*10.5 Employment Agreement effective as of January 1, 1997 by and
between The Brooklyn Union Gas Company and David L. Phillips
10.6 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)
10.7 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)
10.10 Amended 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)
10.11 Second Amendment, dated August 4, 1997, to the Credit Agreement
among The Houston Exploration Company and Texas Commerce Bank
National Association, as Agent, and the other Banks signatory
thereto (filed as Exhibit 10.1 to The Houston Exploration
Company's Quarterly Report on Form 10-Q for the quarterly period
ended September 30, 1997 (File No. 001-11899)
10.12 Amendment, Assignment and Assumption Agreement dated as of
September 29, 1997 by and among The Brooklyn Union Gas Company,
Long Island Lighting Company and KeySpan Energy Corporation (filed
as Exhibit 2.5 to Schedule 13D by Long Island Lighting Company on
October 24, 1997)
*10.13 Employment Agreement dated as of December 5, 1997 between KeySpan
Energy Development Corporation and H. Neil Nichols
107
10.14 Third Amendment to Credit Agreement among The Houston Exploration
Company and Chase Bank of Texas National Association, dated
February 12, 1998 (filed as Exhibit 10.1 to The Houston
Exploration Company's Quarterly Report on Form 10-Q for the
quarter ended March 31, 1998 (File No. 001-11899))
10.15 Indenture, dated as of March 2, 1998, between The Houston
Exploration Company and The Bank of New York, as Trustee, with
respect to the 8 5/8% Senior Subordinated Notes Due 2008
(including form of 8 5/8% Senior Subordinated Note Due 2008)
(filed as Exhibit 4.1 to The Houston Exploration Company's
Registration Statement on Form S-4 (No. 333-50235))
*10.16 Directors' Deferred Compensation Plan of MarketSpan Corporation
d/b/a KeySpan Energy effective July 1, 1998
10.17 Retirement Agreement between the Company and William J.
Catacosinos dated July 31, 1998 (filed as Exhibit 10 to the
Company's Form 10-Q for the quarterly period ended June 30, 1998)
*10.18 Corporate Annual Incentive Compensation Plan effective as of
September 10, 1998
10.19 Employment Agreement dated September 10, 1998, between the Company
and Robert B. Catell (filed as Exhibit 10(b) to the Company's Form
10-Q for the quarterly period ended September 30, 1998)
*10.20 Senior Executive Change of Control Severance Plan effective as
of October 30, 1998
*10.21 Amendment to Employment Agreement effective as of October 30,
1998 by and between The Brooklyn Union Gas Company, KeySpan
Energy Corporation, MarketSpan Corporation and David L. Phillips
10.22 Subordination Agreement dated November 25, 1998 entered into by
and among MarketSpan Corporation d/b/a KeySpan Energy, The Houston
Exploration Company and Chase Bank of Texas, National Association
(filed as Exhibit 10.30 to The Houston Exploration Company's Form
10-K for the year ended December 31, 1998))
10.23 Subordinated Loan Agreement dated November 30, 1998 by and between
The Houston Exploration Company and MarketSpan Corporation d/b/a
KeySpan Energy (filed as Exhibit 10.31 to The Houston Exploration
Company's Form 10-K for the year ended December 31, 1998))
108
*21 Subsidiaries of the registrant
*23.1 Consent of Arthur Andersen LLP, Independent Auditors
*23.2 Consent of Ernst and Young LLP, Independent Auditors
*24.1 Powers of Attorney executed by Directors and Officers of the Company
*24.2 Certified copy of Resolution of Board of Directors authorizing
signature pursuant to power of attorney
*27 Financial Data Schedule on Schedule U-T for the fiscal year ended
December 31, 1998
4. REPORTS ON FORM 8-K
None.
- --------
*Filed herewith.
109
SCHEDULE OF VALUATION AND QUALIFYING ACCOUNTS
(In Thousands of Dollars)
- ---------------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
- ---------------------------------------------------------------------------------------------------------------------------
Additions
--------------------------
Adjustment
Balance at Charged to for the KeySpan Balance at
beginning costs and Acquisition and end of
Description of period expenses LIPA Transaction Deductions (1) period
- ----------------------------------------------------------------------------------------------------------------------------
Nine months ended December 31, 1998
Deducted from asset accounts:
Allowance for doubtful accounts $23,483 $11,064 $3,777 $18,298 $20,026
Twelve months ended March 31, 1998
Deducted from asset accounts:
Allowance for doubtful accounts $23,675 $23,239 - $23,431 $23,483
Three months ended March 31, 1997
Deducted from asset accounts:
Allowance for doubtful accounts $25,000 $4,821 - $6,146 $23,675
Year ended December 31, 1996
Deducted from asset accounts:
Allowance for doubtful accounts $24,676 $23,119 - $22,795 $25,000
(1) Uncollectible accounts written off, net of recoveries
110
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.
MARKETSPAN CORPORATION
d/b/a KeySpan Energy
March 29, 1999 By: /s/ Craig G. Matthews
------------------------------------------
Craig G. Matthews
President and Chief Operating 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 29, 1999.
* Chairman of the Board and Chief Executive
________________________ Officer (Principal executive officer)
Robert B. Catell
* President and Chief Operating Officerpal
/s/ Craig G. Matthews (Principal financial officer)
----------------------
Craig G. Matthews
Vice President, Controller and
Chief Accounting Officer
/s/ Ronald S. Jendras (Principal accounting officer)
----------------------
Ronald S. Jendras
* Director
------------------------
Lilyan H. Affinito
* Director
------------------------
George Bugliarello
* Director
------------------------
Howard R. Curd
* Director
------------------------
Richard N. Daniel
* Director
------------------------
Donald H. Elliott
* Director
------------------------
Alan H. Fishman
* Director
------------------------
James R. Jones
* Director
------------------------
Stephen W. McKessy
* Director
------------------------
Edward D. Miller
* Director
------------------------
Basil A. Paterson
* Director
------------------------
James Q. Riordan
* Director
------------------------
Frederic V. Salerno
* Director
------------------------
Vincent Tese
By: /s/ Craig G. Mathews
------------------------
Craig G. Matthews
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.