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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 1996
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-722
THE BROOKLYN UNION GAS COMPANY
(Exact name of Registrant as specified in its charter)
New York 11-0584613
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
ONE METROTECH CENTER, BROOKLYN, NEW YORK 11201-3850
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code 718-403-2000
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange on
Title of Each Class Which Registered
Common Stock-$.33 1/3 par value New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements
for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein, and
will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K. (X)
Aggregate market value of registrant's voting Common Stock
held by non-affiliates as of December 16, 1996 was approximately
$1.5 billion.
On December 18, 1996 the Company had 49,993,378 shares of
Common Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Part of
Documents Form 10-K
Prospectus/Proxy Statement dated December 20, 1996 Part III
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PART I
Item 1. Business
The Company 2
Gas Supply 4
Regulation and Rate Matters 5
Competition 6
Environmental Matters 8
Research and Development 8
Subsidiaries 8
Employees 11
Item 2. Properties 11
Item 3. Legal Proceedings 12
Item 4. Submission of Matters to a Vote of Security
Holders 12
PART II
Item 5. Market for the Registrant's Common Stock and
Related Security Holder Matters 12
Item 6. Selected Financial Data 14
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 15
Item 8. Financial Statements and Supplementary Data 25
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 50
PART III
Item 10. Directors and Executive Officers of the
Registrant 50
Item 11. Executive Compensation 50
Item 12. Security Ownership of Certain Beneficial Owners
and Management 50
Item 13. Certain Relationships and Related Transactions 50
Part IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 51
Signatures 58
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Part I
Item 1. Business
The Company
The Brooklyn Union Gas Company (Company) was incorporated in
the State of New York in 1895 as a combination of existing
companies, the first of which was granted a franchise in 1849. The
Company distributes natural gas at retail, primarily in a territory
of approximately 187 square miles, which includes the Boroughs of
Brooklyn and Staten Island and two-thirds of the Borough of Queens,
all in New York City. The population of the territory served is
approximately 4,000,000. As of September 30, 1996, the Company had
approximately 1,126,000 active meters, of which approximately
1,089,000 were residential. The Company is subject to the
regulatory jurisdiction of the New York State Public Service
Commission (PSC). Its subsidiaries participate and own investments
in gas and oil exploration, production and processing, gas pipeline
transportation and storage, cogeneration, marketing and other
energy-related services. Gas exploration and production
investments are fully consolidated. Other investments are
accounted for on the equity method. The Company's executive
offices are located at One MetroTech Center, Brooklyn, New York
11201-3850. Its telephone number is (718)403-2000. Financial and
other information is also available through the World Wide Web at
http://www.bug.com.
The Company's gas distribution business is influenced by
seasonal weather conditions. Annual revenues are substantially
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. Accordingly, results of
operations historically are most favorable in the second quarter
(the three months ended March 31) of the Company's fiscal year,
with results of operations being next most favorable in the first
quarter. Results for the third quarter are marginally
unprofitable, and losses are usually incurred in the fourth
quarter. The Company's tariff contains a weather normalization
adjustment that provides for recovery from or refund to firm
customers of material shortfalls or excesses of firm net revenues
during a heating season due to variations from normal weather. (See
Item 1., "Business - Regulation and Rate Matters" and Part II, Item
7., "Management's Discussion and Analysis of Financial Condition
and Results of Operations - 'Rate and Regulatory
Matters' ").
The heating capacity of gas is measured in therms. One therm
equals 100,000 BTUs, the heat content of approximately 100 cubic
feet of natural gas. The heat content of approximately 1,000,000
cubic feet of gas represents 10,000 therms or 1 MDTH. Accordingly,
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one billion cubic feet (BCF) of gas equals approximately 1,000
MDTH.
For the fiscal year ended September 30, 1996, utility firm gas
sales were 141,948 MDTH, of which 75% were residential, 13%
commercial, 8% governmental and 4% industrial. Other utility gas
sales and transportation deliveries to off-system and interruptible
on-system customers amounted to 42,950 MDTH.
In September 1996, the New York State Public Service
Commission (PSC) granted the Company's petition to restructure into
a holding company, to be named KeySpan Energy Corporation
(KeySpan). If the Company's common shareholders approve the
restructuring at its Annual Meeting in February 1997, KeySpan would
become the parent holding company of Brooklyn Union and its
subsidiaries (which would become subsidiaries of KeySpan). This
would be completed through a share exchange whereby the Company's
common shareholders would receive KeySpan common stock on a share
for share basis, thus becoming the owners of KeySpan. The PSC by
order also approved a settlement agreement that contains
restrictions and limitations on certain investments by KeySpan,
limitations on the level of dividend payments from Brooklyn Union
to KeySpan under certain circumstances, prohibitions on certain
intercompany loans, guarantees and pledges, and restrictions on
transactions among the affiliated holding company group. For
further information, see Part II, Item 7., "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and
Item 1., "Business - Competition".
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Gas Supply
General
Changes in regulatory policies and market forces have shifted
the industry from traditional cost-based regulation involving gas
sales, transportation, storage and other related services on a
bundled basis by the interstate pipelines toward market-based sales
on an unbundled basis. These policy changes have made the market
more competitive with respect to gas supply and related services.
Accordingly, the PSC has set forth a policy framework and has
issued an order on May 1, 1996 regarding utility compliance tariff
filings, including the Company's, in line with market objectives of
providing utility customers with wider choices in gas supply and
related services at the local level. As a result of the order, all
customers who choose to do so can arrange to purchase their gas
directly from qualified marketers. The Company continues to serve
as the transporter of gas within its local distribution network,
and the related rates provide full margin recovery of all costs of
service. (See Part II, Item 7., "Management's Discussion and
Analysis of Financial Condition and Results of Operations - 'Rate
and Regulatory Matters'.")
In 1996, 66% of gas supply was purchased from domestic sources
under long-term contracts, 21% from Canadian sources under long-
term contracts and 13% from spot market sources.
The Company opened the first New York-based market hub for
buyers and sellers of natural gas in the Northeast in fiscal 1994.
With interconnections and access to several major pipelines, the
New York Market Hub offers transportation, balancing and exchange
services to utilities, municipalities, marketers and large-volume
customers. In 1996, the Hub placed 29,638 MDTH of gas for delivery
to customers in 14 states and one Canadian province.
Long-Term Sources of Supply
Under long-term contracts and regulatory certificates
applicable to gas supply and pipeline transportation and storage
services, the Company's suppliers are authorized and obligated to
provide maximum firm daily total deliveries of 992 MDTH of gas for
the 1996-97 winter. This supply consists of 375 MDTH per day of
firm gas supply from U.S. sources, 100 MDTH per day of firm
Canadian gas supply, 492 MDTH per day of storage and winter
services related to U.S. sources, and 25 MDTH of on-system peaking
supply.
The Company's major providers of interstate pipeline capacity
and related services are: Transcontinental Gas PipeLine
Corporation, Texas Eastern Transmission Corporation, Iroquois Gas
Transmission System, Tennessee Gas Pipeline Company, CNG
<PAGE>
Transmission Corporation and Texas Gas Transmission Company, which
provide unbundled firm transportation and storage services. These
pipelines are the conduit for the delivery of U.S. and Canadian
supplies purchased from natural gas sellers to the Company's
market.
Peak-day Supply
The Company plans for peak-day demand on the basis of an
average temperature of 0oF. Gas demand on such a design peak-day
is estimated at 1,122 MDTH during the 1996-97 winter. The highest
24-hour firm sendout experienced by the Company was 1,022 MDTH on
January 19, 1994, when the average temperature was 4oF.
For the 1996-97 winter, the Company has the capability to
provide a maximum peak-day supply of 1,284 MDTH, consisting of firm
flowing supply, pipeline storage supply, seasonal winter supply,
and vaporized liquefied natural gas (LNG). The Company's LNG plant
has a storage capacity of 1,660 MDTH and peak-day sendout capacity
of 291 MDTH, or 23% of peak-day supply. Effective November 1,
1996, a new winter peaking service, the Brooklyn Navy Yard Peaking
Supply, was added to the Company's gas supply portfolio. It can
provide a maximum daily quantity of 25 MDTH and a total available
seasonal quantity of 480 MDTH.
Gas Costs
The average cost of gas purchased for firm customers was $3.49
per DTH in 1996, $3.12 per DTH in 1995 and $3.55 per DTH in 1994.
Regulation and Rate Matters
The agreement reached in the holding company filing included
a new multi-year rate plan that became effective on October 1,
1996. After an initial rate reduction of approximately $3.0 million
in fiscal 1997, the non-gas component in customer bills will be
under specific price caps. Hence, the total amount for this
component in rates that the Company can charge customers, in the
aggregate, will remain constant for the subsequent five years,
although rates in certain customer classes may be increased in
order to reflect cost responsibility more appropriately. The
Company also will be permitted to charge for various ancillary
services.
Utility retail sales, which include sales of gas,
transportation and balancing services by the Company, are made
primarily under rate schedules and tariffs filed with and subject
to the jurisdiction of the PSC. Amendments have been made to rate
schedules and tariffs to reflect the conditions and rates under
which delivery and other services are provided to customers who
opt to have their gas supplied by third parties. Rate schedules
also have been established governing the provision of certain
<PAGE>
services to such marketers. In general, the schedules provide for
block rates that result in reductions in the unit price as use
increases. They contain gas cost adjustment provisions that permit
the Company to pass on to firm customers increases and decreases in
the cost of gas currently in billings to firm customers through the
operation of a tariff provision, the Gas Adjustment Clause (GAC).
Revenue requirements to establish utility rates are based on tariff
sales to customers. Net revenues from off-system gas sales and
tariff gas balancing services and capacity release credits are
refunded to firm customers subject to sharing provisions in the
Company's tariff. Prior to October 1, 1996, net revenues from
tariff sales for gas and transportation services to on-system
customers made on an interruptible basis were refunded to firm
customers subject to sharing provisions. The GAC provision
requires an annual reconciliation of recoverable gas costs with GAC
revenues. Any difference is deferred pending recovery from or
refund to firm customers during a subsequent twelve-month period.
For information regarding the status of rate settlements and
other regulatory proceedings, including the Company's rate order
that became effective in October 1996, see Part II, Item 7.,
"Management's Discussion and Analysis of Financial Condition and
Results of Operations - 'Sales, Gas Costs and Net Revenues' and
'Rate and Regulatory Matters'." Also, for additional information
on the effects of rate regulation, see Part II, Item 8., "Financial
Statements and Supplementary Data, 'Summary of Significant
Accounting Policies and Basis for Financial Statement Presentation-
Regulatory Assets'."
Competition
Within its utility service territory, the Company competes
with suppliers of oil, electricity and other fuels for cooking,
heating, air conditioning and other purposes. Regulatory changes
have resulted in the unbundling of services in the natural gas
industry. Beginning on May 1, 1996, customers in the Company's
small-volume market have the option to purchase their gas supplies
from sources other than the Company. Large volume customers have
had this option for a number of years. Regardless of whether the
Company's customers purchase gas from the Company or other
suppliers, the customers pay the Company for transporting the gas.
(See Part II, Item 7., "Management's Discussion and Analysis of
Financial Condition and Results of Operations - 'Sales, Gas Costs
and Net Revenues' and 'Rate and Regulatory Matters'.")
The Company has expanded existing markets and is developing
new ones to increase gas sales. In the residential heating market,
gas is sold in competition with No. 2 grade fuel oil. During the
year, gas at the burner tip was generally competitive with
alternate grades of fuel oil. Conversions from oil to gas heat
continued during fiscal 1996. Approximately 78% of one- and
two-family homes in the Company's service area now use gas for
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space heating.
The Company's share of the multi-family market is
approximately 46%. In this market, gas service under large-volume
rates is competitively priced with alternate grades of fuel oil.
In the commercial and industrial markets, the Company offers
special area development and business incentive gas rates to
businesses that move to or expand operations in designated areas in
the Company's territory.
The Company continues to be committed to obtaining greater
operational efficiencies through aggressive cost-containment
programs, continuous reviews of business processes and the use of
advanced technologies.
Further, as a result of deregulation, a significant market for
off-system gas sales, transportation and other services has
developed. Competition is expected to intensify in this market as
deregulation is more widely implemented in the Northeast.
Moreover, many in the energy industry, including the Company,
believe that the increasingly deregulated and more competitive
environment may lead to industry consolidation, vertical
integration and other strategic alliances as energy companies seek
to offer a broader range of energy services to compete more
effectively in attracting and retaining customers. For example,
affiliations with other operating utilities could potentially
result in economies and synergies, and vertical integration could
provide a means to offer customers a more complete range of energy
services. The Company believes that its proposed holding company
structure, if approved by shareholders, would further expansion and
diversification in energy-related businesses through investments,
acquisitions and strategic alliances. The Company has been
studying, and in some cases has held discussions regarding, utility
and energy-related investments and transactions. The Company is
unable to predict whether its activities will lead to investments
and transactions that will result in enhanced competitive
capabilities in the changing industry environment.
In early December 1995, New York's Governor George Pataki
endorsed a proposal to dismantle the Long Island Lighting Company
(LILCO). Among other things, the proposal contemplates that the
Long Island Power Authority (LIPA) would issue and sell tax-exempt
bonds to purchase LILCO's electric transmission and distribution
system and regulatory assets, and would assume a portion of LILCO's
debt; LILCO's electric generating facilities and its gas business
would be sold to other companies; and an energy company would
contract with LIPA to manage the transmission and distribution of
electricity to LILCO's customers. The Company has been following
developments, and has had discussions and explored alternatives
regarding the possibility of the Company participating in a
combination or other transaction involving LILCO's gas and electric
<PAGE>
businesses and assets. The Company is unable to predict the course
of developments or whether or how the Company might be involved
should there be a transaction.
Environmental Matters
For information regarding environmental matters affecting the
Company, see Part II, Item 7., "Management's Discussion and
Analysis of Financial Condition and Results of Operations -
'Environmental Matters'," and Part II, Item 8., "Financial
Statements and Supplementary Data," Note 9., "Environmental
Matters."
Research and Development
In fiscal 1996, the Company spent $12.8 million on research
and development (R&D) programs. Of this amount, $2.4 million was
spent to support programs of the Gas Research Institute. The
Company also provided $2.1 million to other research associations,
including the New York State Energy Research and Development
Authority (NYSERDA) and the New York Gas Group. The balance of
$8.3 million was devoted primarily to the Company's internal R&D
programs relating to efficient gas utilization and operations
technologies. These programs covered cogeneration, power stations,
refrigeration, fuel cells, as well as natural gas refueling
stations. In addition, the Company continues to make significant
efforts to develop innovative operation systems which reduce
utility costs.
Subsidiaries
The Company's principal non-utility subsidiaries participate
and own investments in gas exploration, production and processing;
gas pipeline transportation and storage; cogeneration; marketing
and other energy-related services. In fiscal 1996, earnings from
subsidiaries were $40.5 million, or 82 cents per share, which
included non-recurring gains from initial public offerings of $33.5
million and a reorganization charge of $7.8 million. Earnings
excluding these non-recurring items were $14.8 million, or 30 cents
per share. The Company's total investment in these businesses,
computed in accordance with PSC specifications as a percentage of
consolidated capitalization, was 13.4%, 14.2% and 12.8% as of
September 30, 1996, 1995 and 1994, respectively. For further
information regarding the subsidiaries, see Part II, Item 7.,
"Management's Discussion and Analysis of Financial Condition and
Results of Operations", Part II, Item 8., "Financial Statements and
Supplementary Data", Note 3., " The Houston Exploration Company",
Note 8., "Investment in Iroquois Pipeline" and Note 10.,
"Supplemental Gas and Oil Disclosures".
If the Company's common shareholders approve the holding
company restructuring at the Company's Annual Meeting in February
1997, these non-utility subsidiaries will become subsidiaries of
the
<PAGE>
holding company, KeySpan, and will no longer be subsidiaries of the
Company.
Gas Exploration, Production and Processing
The Houston Exploration Company ("THEC") is an independent
natural gas and oil company 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 Texas, the Arkoma Basin and West
Virginia. In contemplation of the initial public offering (IPO)
of THEC's common stock, the Company implemented a reorganization of
its exploration and production subsidiaries' assets and liabilities
by transferring to THEC certain onshore producing properties and
acreage not previously owned by THEC. As a result , all U. S. oil
and gas properties of Fuel Resources Inc. ( FRI), a wholly owned
subsidiary of the Company, were transferred to THEC. In September
1996, THEC completed the initial public offering of 7,130,000
shares of its common stock at an offering price of $15.50 per share
and two smaller stock issuances, which reduced the Company's
ownership from 100% to approximately 66%. The Company recorded a
$35.4 million gain ($23.0 million after tax) as a result of these
stock issuances and the related net increase in book value of the
Company's investment in THEC. The proceeds to THEC from the IPO,
after deductions for commissions and offering expenses, were
approximately $101 million and were used to repay a portion of
THEC's short-term borrowings incurred as a result of two major
acquisitions in 1996 of properties and proved gas reserves in South
Texas and the Gulf of Mexico for $84.7 million. In connection with
the reorganization of the exploration and production properties, a
reorganization charge of $7.8 million, net of federal income taxes,
was recorded by THEC in fiscal 1996. (See Part II, Item 8.,
"Financial Statements and Supplementary Data," Note 3., "The
Houston Exploration Company.") Total gas production was
approximately 27.3 BCFe (one billion cubic feet of gas including
oil equivalent volumes) during fiscal 1996 and net proved gas
reserves at September 30, 1996 were approximately 322 BCFe. For
information concerning the gas and oil exploration, development and
producing activities of the Company's subsidiaries, see Part II,
Item 8., "Financial Statements and Supplementary Data," Note 10.,
"Supplemental Gas and Oil Disclosures".
Solex Development Energy Company, a subsidiary of FRI,
completed a public offering of trust units in the Taylor gas-
processing plant in British Columbia, Canada, and realized a gain
of $10.5 million, after taxes. This plant had been purchased in
April 1995 and was sold to realize its value. The Company's
subsidiary, KeySpan Energy Canada, Ltd., has an option to
participate in the planned expansion of the plant.
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Investments in Energy Services
Pipeline and Storage
North East Transmission Co., Inc. (NETCO) increased its
ownership interest by 8.0% in fiscal 1996 and as a result owns a
19.4% interest in the Iroquois Gas Transmission System L.P.
(Iroquois), a 375-mile pipeline that currently transports
approximately 860 MDTH of Canadian gas supply daily to markets in
the northeastern United States. The Company currently receives up
to 70 MDTH of gas per day through Iroquois. For information
regarding the resolution of governmental investigations involving
the Iroquois project, see Part II, Item 8., "Financial Statements
and Supplementary Data," Note 8., "Investment in Iroquois
Pipeline."
Through a subsidiary, the Company has equity investments in
two gas storage facilities located in New York State.
Cogeneration
Gas Energy Inc. (GEI) participates in the development,
operation and ownership of cogeneration projects. A GEI subsidiary
is a 50% partner in a 100-megawatt facility at John F. Kennedy
International Airport (JFK) in Queens, New York. This facility
commenced operations in 1995. GEI owns an 11.3% interest in a
174-megawatt gas cogeneration plant located in Lockport, New York.
An affiliate is a 50% partner in a 40-megawatt facility that serves
the State University of New York at Stony Brook, Long Island, which
commenced operations in 1995, and is a 45% partner in a 50-megawatt
gas cogeneration plant that has been producing heat and power at a
Northrop Grumman facility located in Bethpage, Long Island, New
York.
The scope of cogeneration activities also includes providing
fuel-management services. GEI subsidiaries provide such services
to the JFK, Stony Brook and Northrop Grumman facilities and to
another 50-megawatt facility. In 1996, these subsidiaries, as fuel
managers, provided 15,000 MDTH of gas to these cogeneration
projects.
Marketing
BRING Gas Services Corp., FRI's marketing subsidiary, in
September 1996, sold its 50% interest in PennUnion Energy Services,
L.L.C. to its partner, Pennzoil Gas Marketing Company, an affiliate
of Pennzoil Company.
KeySpan Energy Services Inc. (KES), formed in April 1996,
sells natural gas both inside and outside the Company's utility
service territory to large commercial and industrial customers, as
well as groups of residential and small commercial customers. It
<PAGE>
has been authorized by the Federal Energy Regulatory Commission to
market electricity interstate.
KeySpan Energy Management Inc.(KEM), formed in October 1996,
develops energy-related projects and provides a variety of
technical and maintenance services for commercial and industrial
customers. KEM has formed a strategic alliance with South Jersey
Industries to develop energy projects in the mid-Atlantic region.
Employees
The Company and its subsidiaries employed 3,336 people at
September 30, 1996, compared to 3,378 at September 30, 1995.
In November 1995, a new labor agreement was ratified by the
membership of Local 101 of the Transport Workers Union, which
represents approximately 1,900 utility employees. The agreement
provides for total wage increases of approximately 9.3% over its
three-year term. The agreement also provides certain productivity
savings and a gainsharing incentive tied to attainment of certain
corporate goals. A similar agreement applicable to 200 utility
employees represented by Local 3 of the International Brotherhood
of Electrical Workers was ratified in August 1995.
Item 2. Properties
In fiscal 1996, consolidated capital expenditures were $ 302.3
million, of which $110.8 million was primarily for utility property
additions and $191.5 million was for subsidiaries. Consolidated
capital expenditures are estimated to be approximately $195 million
for each of fiscal years 1997 and 1998.
The Company holds franchises to lay gas mains in the streets,
highways and public places in the Boroughs of Brooklyn and Staten
Island, and the former Second and Fourth Wards of the Borough of
Queens. The Company has consents and permits which, with
immaterial exceptions, give it the right to carry on its utility
operations, substantially as now carried on, in the territory
served. The Company's franchises are unlimited in duration, except
that a franchise to transmit and distribute gas in the former Fifth
Ward of the Borough of Staten Island expires in 2006. Gas sales
revenues in the former Fifth Ward are approximately 2.4% of the
total gas sales revenues of the Company.
As of September 30, 1996, the Company's distribution pipeline
system consisted of approximately 1,987 miles of cast iron main,
1,677 miles of steel main and 288 miles of mains with plastic
inserts, with requisite accessory compressor and regulating
stations, and one gas storage holder having a capacity of 15 MDTH.
The distribution system for the most part is located under public
streets.
<PAGE>
The Company owns and operates a liquefied natural gas (LNG)
plant, located at its Greenpoint Energy Center in Brooklyn, to
liquefy and store gas during the summer months for vaporization and
use during the winter months. This plant has a storage capacity of
1,660 MDTH of natural gas in liquid form and a vaporization
capacity of 291 MDTH per day.
The Company leases its corporate headquarters at One MetroTech
Center in downtown Brooklyn. The lease agreement has a remaining
term of 15 years and renewal options. The Company and its
subsidiaries own or lease certain other buildings and facilities
for use in the conduct of their business. The Company's gross
lease payments are approximately $14.1 million per year.
Principal consolidated properties of subsidiaries and their
affiliates include gas and oil leasehold interests, producing wells
and related equipment and structures. For information concerning
the gas exploration, production and processing activities of the
Company's subsidiaries, see Part II, Item 8., "Financial Statements
and Supplementary Data," Note 10., "Supplemental Gas and Oil
Disclosures."
Item 3. Legal Proceedings
For information regarding the resolution of governmental
investigations involving the Iroquois project, see Part II, Item
8., "Financial Statements and Supplementary Data," Note 8.,
"Investment in Iroquois Pipeline." For information regarding
environmental matters affecting the Company, see Part II, Item 7.,
"Management's Discussion and Analysis of Financial Condition and
Results of Operations - Environmental Matters," and Part II, Item
8., "Financial Statements and Supplementary Data," Note 9.,
"Environmental Matters."
Item 4. Submission of Matters to a Vote of Security Holders
There was no matter submitted to a vote of security holders
during the fourth quarter of the fiscal year covered by this report
through solicitation of proxies or otherwise.
Part II
Item 5. Market for the Registrant's Common Stock and Related
Security Holder Matters
The following is information regarding the Company's common
stock. For additional information required by this item, see Part
II, Item 6., "Selected Financial Data" and Part II, Item 8.,
"Financial Statements and Supplementary Data," Note 5.,
"Capitalization."
<PAGE>
Stock Listings
The Company's common stock is traded on the New York Stock
Exchange (NYSE) under the trading symbol BU. The Houston
Exploration Company (THEC) common stock is traded on the NYSE under
the trading symbol THX. Daily stock reports are carried by most
major newspapers under the heading BklyUG and HoustEX,
respectively.
Dividends
Quarterly dividends on the Company's common stock have been
payable on the first of February, May, August and November;
preferred dividends are payable on the first of March, June,
September and December. All dividends paid by the Company are
taxable as ordinary income. The PSC's holding company order
contains limitations on the level of dividend payments from
Brooklyn Union to KeySpan under certain circumstances, should the
holding company restructuring be approved by shareholders.
Annual Meeting
The next annual meeting of shareholders will be held at the
Company's General Office at 10:00 a.m. on Thursday, February 6,
1997.
Transfer Agent and Registrar of Stock
First Chicago Trust Company of New York
P.O. Box 2500
Jersey City, N.J. 07303-2500
(800)328-5090
Independent Public Accountants
Arthur Andersen LLP
1345 Avenue of the Americas
New York, NY 10105
(212)708-4000
<PAGE>
Item 6. Selected Financial Data
<TABLE>
<CAPTION>
For the Year Ended September 30, 1996 1995 1994 1993 1992
(Thousands of Dollars Except Per Share Data)
<S> <C> <C> <C> <C> <C>
Income Summary
Operating revenues
Utility sales $1,351,821 $1,152,331 $1,279,638 $1,145,315 $1,038,061
Gas production and other 80,181 63,953 58,992 60,189 36,799
- ------------------------------------------------------------------------------------------------
Total operating revenues 1,432,002 1,216,284 1,338,630 1,205,504 1,074,860
Operating expenses
Cost of gas 610,053 446,559 560,657 466,573 402,137
Operation and maintenance 428,977 385,654 384,734 366,706 336,156
Depreciation and depletion 79,610 72,020 69,611 64,779 73,930
General taxes 143,296 134,718 150,743 144,827 135,549
Federal income tax 39,508 41,989 40,556 41,413 30,052
- -------------------------------------------------------------------------------------------------
Operating income 130,558 135,344 132,329 121,206 97,036
Income (loss) from energy services
investments 13,523 9,458 5,689 1,150 (1,041)
Gain on sale of investment in
Canadian properties 16,160 - - 20,462 -
Gain on sale of subsidiary stock 35,437 - - - -
Write-off of investment in propane
company - - - (17,617) -
Other, net (1,188) 151 700 (465) 5,107
Federal income tax (expense) benefit (19,861) (51) (142) (70) 833
Interest charges 51,721 53,067 51,192 48,103 42,062
- -------------------------------------------------------------------------------------------------
Net income 122,908 91,835 87,384 76,563 59,873
Dividends on preferred stock 323 337 351 364 2,078
- -------------------------------------------------------------------------------------------------
Income available for common stock $122,585 $91,498 $87,033 $76,199 $57,795
=================================================================================================
Financial Summary
Common stock information
Per share
Earnings ($) 2.48 1.90 1.85 1.73 1.35
Cash dividends declared ($) 1.42 1.39 1.35 1.32 1.29
Book value, year-end ($) 18.17 16.94 16.27 15.55 14.56
Market value, year-end ($) 27 7/8 24 5/8 24 7/8 25 3/4 22 3/8
Average shares outstanding (000) 49,365 48,211 46,980 44,042 42,882
Shareholders 33,320 33,669 35,233 30,925 31,367
Daily average shares traded 64,500 49,100 42,100 33,100 26,900
Capital expenditures ($) 302,280 214,006 199,572 204,514 173,467
Total assets ($) 2,289,603 2,116,922 2,029,074 1,897,847 1,748,027
Common equity ($) 905,808 826,290 774,236 721,076 632,254
Preferred stock, redeemable ($) 6,600 6,900 7,200 7,500 7,800
Long-term debt ($) 712,013 720,569 701,377 689,300 682,031
Total capitalization ($) 1,624,421 1,553,759 1,482,813 1,417,876 1,322,085
Earnings to fixed charges (times) 3.99 3.17 3.21 3.19 2.86
Utility Operating Statistics
Gas data (MDTH)
Firm sales 141,948 123,356 133,513 128,972 122,476
Other gas and transportation sales 42,950 49,910 42,392 25,032 23,706
Maximum daily capacity, year-end 1,284 1,256 1,256 1,258 1,199
Maximum daily sendout 994 963 1,022 915 904
Total active meters (000) 1,126 1,125 1,122 1,119 1,117
Heating customers (000) 461 454 446 441 436
Degree days 5,170 4,240 4,974 4,802 4,659
Colder (Warmer) than normal (%) 7.7 (11.2) 3.1 - (4.0)
</TABLE>
<PAGE>
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations
Earnings and Dividends
In fiscal 1996, consolidated income available for common stock
was $122.6 million, or $2.48 per share, compared to $91.5 million,
or $1.90 per share, in 1995, and $87.0 million, or $1.85 per share,
in 1994. This was the fourth consecutive year of record earnings.
Consolidated earnings for the last three fiscal years are
summarized below:
<TABLE>
<CAPTION>
__________________________________________________________________________
1996 1995 1994
__________________________________________________________________________
(Thousands of Dollars)
<S> <C> <C> <C>
Income Available for Common Stock
Utility $ 82,090 $78,677 $76,665
_________________________________________________________________________
Gas exploration and production
Operations (before reorganization
charge) 7,627 7,843 5,707
Reorganization charge (7,800) - -
Gain on sale of subsidiary stock 23,034 - -
Gain on sale of Canadian plant 10,505 - -
_________________________________________________________________________
33,366 7,843 5,707
_________________________________________________________________________
Energy services
Pipeline and storage 5,319 979 3,358
Cogeneration 414 2,670 1,303
Marketing 1,396 1,329 -
_________________________________________________________________________
7,129 4,978 4,661
_________________________________________________________________________
Consolidated $122,585 $91,498 $87,033
_________________________________________________________________________
</TABLE>
In 1996, regulated utility operations provided an equity
return of 12.80%. The return, which included incentives authorized
by the New York State Public Service Commission (PSC), was higher
than the allowed rate of 10.65%. The Company has earned at or
above its allowed return on utility common equity in 17 of the last
18 years.
In the last three years, income available for common stock
from utility operations has benefited from additions of new firm
gas heating customers, principally as a result of customer
<PAGE>
conversions from oil to gas for space heating in homes and
buildings, as well as earnings incentives provided under rate
stipulations (see "Rate and Regulatory Matters"). In 1996, such
incentive-based earnings were related largely to higher margins on
sales to large-volume and off-system customers and attaining a 93%
customer satisfaction rating in benchmarks used by the PSC. The
effect on utility revenues of variations in weather largely was
offset by the weather normalization adjustment included in the
Company's tariff. Utility operating margins have improved due to
ongoing cost reduction efforts.
In 1996, earnings from gas exploration, production and
processing operations decreased, primarily due to a reorganization
charge of $7.8 million, net of federal income taxes, recorded by
the U.S. exploration and production subsidiary, The Houston
Exploration Company (THEC). Excluding this charge, operating
results were comparable in 1996 and 1995. However, earnings in
1996 also included an after-tax gain of $23.0 million on the
issuance by THEC of 34% of its common stock in September 1996 (see
Note 3 to the Consolidated Financial Statements, "The Houston
Exploration Company" for additional information). Neither the
Company, nor THEC, has plans for any further issuances of THEC
stock, nor the stock of any of the Company's other subsidiaries -
except for issuances under ongoing stock plans . Further, earnings
included a gain of $10.5 million on the sale in July 1996 of an
investment in a Canadian gas processing plant, which was sold to
realize the substantial value embodied in the investment at the
time. In 1995, earnings from gas exploration, production and
processing operations increased, primarily due to higher U.S.
natural gas production.
Earnings from investments in energy services are attributable
to various operations. In April 1996, a Company subsidiary
increased its equity interest in the Iroquois Gas Transmission
System, L.P. (Iroquois) by 8.0% to 19.4%, resulting in higher
earnings during the year from Iroquois. In addition, earnings from
pipeline and storage operations in all periods reflect higher
throughput on Iroquois. In 1995, earnings were reduced by a
provision for the Company's proportionate share of estimated costs
of legal matters involving Iroquois. With respect to cogeneration
investments, higher fuel prices caused earnings from these
investments to decrease in 1996. In 1995, the increase in earnings
reflected equity income from the start of operations at John F.
Kennedy International Airport (JFK) and the campus of the State
University of New York at Stony Brook.
Earnings from gas marketing in 1996 were $1.4 million, similar
to last year. Looking toward the future, the Company expects
revenue growth as a result of the rationalization and refocusing of
these operations. New wholly-owned subsidiaries have been formed
to operate effectively as part of the Company's holding company
strategy. One of these business units sells gas and expects to
sell electricity inside and outside the traditional utility
<PAGE>
territory. The other will provide a variety of technical and
maintenance management services for commercial and industrial
customers. The initial focus will be conducted both independently
and through strategic alliances. As an integral part of this
marketing realignment, a Company subsidiary sold its 50% interest
in the gas-marketing venture, PennUnion Energy Services, L.L.C., to
the other partner.
The consolidated rate of return on average common equity was
13.6% in 1996, 10.9% in 1995, and 11.0% in 1994.
In December 1995, the Board of Directors authorized an
increase in the annual dividend on common stock to $1.42 per share
from $1.39 per share. This increase became effective on February
1, 1996, when the quarterly dividend was raised to 35 1/2 cents per
share from 34 3/4 cents per share. Common dividends have been
increased in 20 consecutive years and paid continuously for 48
years.
Sales, Gas Costs and Net Revenues
Firm utility gas sales volumes in fiscal 1996 were 141,948
MDTH compared to 123,356 MDTH in 1995 and 133,513 MDTH in 1994.
Measured by annual degree days, weather was 7.7% colder than normal
in 1996, 11.2% warmer than normal in 1995 and 3.1% colder than
normal in 1994. Sales growth in all markets resulted primarily
from conversions to natural gas from oil for space heating,
especially by large apartment buildings. In 1996, the growth in
firm sales normalized for weather was 2.4%, similar to that
experienced in recent years.
<TABLE>
<CAPTION>
_________________________________________________________________
1996 1995 1994
_________________________________________________________________
(Thousands of Dollars)
<S> <C> <C> <C>
Utility sales $ 1,351,821 $ 1,152,331 $ 1,279,638
Cost of gas (610,053) (446,559) (560,657)
_________________________________________________________________
Net revenues $ 741,768 $ 705,772 $ 718,981
_________________________________________________________________
Gas production
and other $ 80,181 $ 63,953 $ 58,992
_________________________________________________________________
</TABLE>
In 1996, higher utility sales primarily reflected higher
billings due to colder weather. In 1995, the opposite occurred as
lower utility sales primarily reflected lower billings for gas
costs due to warm weather. For additional information regarding
utility sales and net revenues in the last three years, see "Rate
and Regulatory Matters."
During the year, gas at the burner tip was competitive with
alternative grades of fuel oil. Residential heating sales in
<PAGE>
markets where the competing fuel is No. 2 grade fuel oil and sales
to other small-volume customers were approximately 75% of firm
sales volume in 1996. Demand in these markets is less sensitive to
periodic differences between gas and oil prices. In large-volume
heating markets, gas service is provided under rates that are set
to compete with prices of alternative fuel, including No. 6 grade
heating oil. There is substantial sales potential in these
markets, which include large apartment houses, government buildings
and schools. Competition with other gas suppliers is expected to
continue to increase as a result of deregulation.
Moreover, a significant market for off-system gas sales,
transportation and other services has developed as a result of
deregulation. These sales or services reflect optimal use of
available pipeline capacity as affected by weather and the
Company's New York Market Hub in balancing on-system requirements
to core customers with off-system services to increase total
margins. In colder-than-normal winters, such as 1996, sales to on-
system customers are higher whereas off-system services are
comparatively lower. As a result, in 1996 gas and transportation
sales and services to off-system and interruptible customers
amounted to 42,950 MDTH compared with 49,910 MDTH in 1995.
The Company and its gas exploration and production subsidiary
employ derivative financial instruments, such as natural gas and
oil futures, options and swaps, for the purpose of managing
exposures to commodity price risk. In connection with utility
operations, the Company primarily uses derivative financial
instruments to fix margins on sales to large-volume customers to
which gas is sold at a price indexed to the prevailing price of
oil, their alternate fuel. Derivative financial instruments are
used by the Company's gas exploration and production subsidiary to
manage the risk associated with fluctuations in the price received
for natural gas production in order to achieve a more predictable
cash flow. Hedging strategies have been managed independently.
(See Note 7B to the Consolidated Financial Statements, "Derivative
Financial Instruments," for additional information.)
The cost of gas, $610.1 million in 1996, was $163.5 million or
36.6% higher than in 1995. The higher cost reflects higher heating
sales due to colder weather and higher average gas costs. The cost
of gas in 1994 was $560.7 million reflecting higher volumes sold
and higher average prices, both of which were primarily the result
of cold weather in that year as compared to volumes and prices in
1995. The cost of gas for firm customers was $3.49 per DTH (one
DTH equals 10 therms) in 1996, compared to $3.12 per DTH in 1995
and $3.55 per DTH in 1994. For the year ended September 30, 1996,
the utility's cost of gas included hedging losses of $1.7 million
related to its margin fixing strategy.
The increase in revenues from gas production and other in 1996
is due primarily to the acquisition of additional natural gas
properties (see Note 3 to the Consolidated Financial Statements,
<PAGE>
"The Houston Exploration Company", for additional information) and
increased production from the gas processing plant located in
British Columbia, Canada, which was purchased in April 1995 and was
sold in July 1996. In 1996, gas production, including oil
equivalents, was approximately 27.3 billion cubic feet (BCFe), or
4.6 BCFe above the level of production last year. In 1996,
wellhead prices averaged approximately $2.11 per MCF compared with
$1.47 per MCF last year. The realized price (average wellhead
price received for production including recognized hedging gains
and losses) was $1.82 per MCF in 1996 compared with $1.77 per MCF
in 1995. Hence, the Company's hedging strategy stabilized the
weather-related volatility inherent in the wellhead price which
showed an increase on average of 64 cents per MCF in 1996 compared
to 1995. The effective price increased 5 cents in 1996 compared to
1995. The effective price in 1996 included a hedging loss of $7.7
million while the effective price in 1995 included a hedging gain
of $6.6 million. (See Note 10 to the Consolidated Financial
Statements, "Supplemental Gas and Oil Disclosures", for additional
information.)
Expenses, Other Income and Preferred Dividends
The increase in operation and maintenance expense in 1996
reflects the effects of colder weather compared to last year and
the reorganization charge incurred by the U.S. exploration and
production subsidiaries. The reorganization charge of $12.0
million reflects remuneration that certain former employees of the
Company's other exploration and production subsidiary were paid as
the result of the increase in the value of the gas and oil
properties transferred to THEC. The decrease in 1995 reflected
warmer weather and various cost reduction efforts. In 1994, severe
winter weather caused higher utility gas distribution operation
expense. The benefit of ongoing cost reduction programs
substantially outweighed the adverse effects of generally higher
labor and material costs. Moreover, consolidated operation expense
in 1996 and 1995 included costs related to Canadian gas processing
operations, which ceased in July 1996 when the plant was sold.
The increase in depreciation and depletion expense in 1996
reflects higher depletion charges of subsidiaries due to increased
gas production and higher utility depreciation expense due to
property additions.
General taxes principally include state and city taxes on
utility revenues and property. The applicable property base
generally has increased, although the Company has been able to
realize significant savings by the aggressive pursuit of reductions
in property value assessments. Taxes based on revenues reflect the
variations in utility revenues each year.
Federal income tax expense reflects changes in pre-tax income.
The increase in earnings from energy services investments in
<PAGE>
1996 is primarily due to the increase in earnings from Iroquois
offset by lower cogeneration earnings, as previously discussed.
Other income also includes pre-tax gains on the sale of the
Canadian plant and on the issuance of 34% of THEC's common stock.
Interest charges on long-term debt in each of the last three
fiscal years generally reflect higher average subsidiary
borrowings. In fiscal 1996, interest charges reflected lower
utility interest costs due to debt refunding. Other interest
expense primarily reflects accruals of carrying charges related to
regulatory settlement items.
Dividends on preferred stock reflect reductions in the level
of preferred stock outstanding due to sinking fund redemptions.
Capital Expenditures
Consolidated capital expenditures were $302.3 million in 1996,
$214.0 million in 1995 and $199.6 million in 1994.
Capital expenditures related to utility operations were $110.8
million in 1996, $108.7 million in 1995 and $103.8 million in 1994.
Utility expenditures in all years principally were for the renewal
and replacement of mains and services.
Capital expenditures related to gas exploration, production
and processing activities were $169.0 million in 1996, $83.0
million in 1995 and $71.3 million in 1994. Expenditures in 1996
reflect two major acquisitions totaling $84.7 million for gas and
oil reserves in South Texas and the Gulf of Mexico, as well as on-
going exploration and development activities. Expenditures in 1996
primarily reflect increased off-shore development activities. Net
proved gas reserves at September 30, 1996 were approximately 322
BCFe. These reserves are located off-shore in the Gulf of Mexico
and on-shore in Texas, the Arkoma Basin and West Virginia.
Capital expenditures related to energy services investments
were $22.5 million in 1996, $22.3 million in 1995 and $24.5 million
in 1994. Expenditures in 1996 primarily were for the acquisition
of the additional interest in Iroquois. Also, in 1996 the
cogeneration plant at JFK was refinanced and cash flows from
investing activities include a return of capital from the proceeds.
In 1995 and 1994, expenditures were primarily related to the
construction of the JFK cogeneration project and, in 1995, also
included $5.6 million related to the Stony Brook cogeneration
plant. In 1994, capital expenditures also included the acquisition
of an interest in a cogeneration plant located in Lockport, New
York.
Consolidated capital expenditures for fiscal years 1997 and
1998 are estimated to be approximately $195 million in each year,
including $85 million per year related to non-utility activities.
The level of such expenditures is reviewed on an ongoing basis and
<PAGE>
can be affected by timing, scope and changes in investment
opportunities.
Financing
Cash provided by operating activities continues to be strong
and is a substantial source for financing ongoing capital
expenditures. In 1996, cash flow from utility operations was
reduced by the timing of budget plan billing settlements related to
cold weather.
In September 1996, THEC issued 7,130,000 shares of its common
stock in an initial public offering, providing net proceeds of
$101.0 million, which were used to pay down debt and to complete
the financing of gas reserve acquisitions and property additions
discussed previously.
In addition, proceeds from common stock issued through the
Company's employee and shareholder stock purchase plans have
provided the Company approximately $27.4 million in 1996, $28.0
million in 1995 and $29.8 million in 1994. The Company issued
1,800,000 new shares of common stock on October 6, 1993, providing
net proceeds of $44.9 million.
In March 1996, the Company refunded $153.5 million of Gas
Facilities Revenue Bonds, including a $98.5 million series of 9%
bonds and a $55 million series of 8.75% bonds. Both series were
called for redemption at optional redemption prices equal to 102%
of the face amount per bond plus accrued interest. The $153.5
million refunding series, which matures in 2021, was issued on
January 29, 1996, with a coupon rate of 5.5% at a price of 99% of
the principal amount of the bonds. The Company expects to initiate
a call of its Gas Facilities Revenue Bonds, 7 1/8% Series 1985 I
and 7% Series 1985 II, which are callable on December 1, 1996 at
102% of face amount per bond plus accrued interest to the call
date. If authorization is received from government agencies, the
bonds would be called early in calendar year 1997.
At September 30, 1996, the consolidated annualized cost of
long-term debt was 6.3%, compared to 7.1% in 1995 and 6.9% in 1994.
Financial Flexibility and Liquidity
At September 30, 1996, the Company had cash and temporary cash
investments of $41.9 million and available bank lines of credit of
$75 million, which lines are available to secure the issuance of
commercial paper. The lines of credit can be increased to $150
million by December 1996. Related borrowings primarily are used to
finance seasonal working capital requirements, which in recent
years have not been significant. At September 30, 1996, there were
no borrowings outstanding. In addition, subsidiaries have lines of
credit totaling $150 million, which for the most part support
<PAGE>
borrowings under revolving loan agreements. (See Note 5C to the
Consolidated Financial Statements, "Other Long-Term Debt", for
additional information.)
At September 30, 1996, the common equity component of the
Company's capitalization was 55.8%.
Fixed charge coverage ratios were 3.99 times in 1996, 3.17
times in 1995 and 3.21 times in 1994.
Rate and Regulatory Matters
Rate Settlement Matters and Holding Company Agreement
In September 1996, the New York State Public Service Commission
(PSC) granted the Company's petition to restructure into a holding
company, to be named KeySpan Energy Corporation. If the Company's
shareholders approve the restructuring at its Annual Meeting in
February 1997, KeySpan would become the parent holding company of
Brooklyn Union and its subsidiaries (which would become
subsidiaries of KeySpan) through a share exchange whereby the
Company's common shareholders would receive KeySpan common stock,
thus becoming the owners of KeySpan. The PSC's holding company
order approved a settlement agreement among Brooklyn Union, the
Staff of the Department of Public Service and several intervenor
parties. This agreement contains restrictions and limitations on
certain investments by KeySpan, limitations on the level of
dividend payments from Brooklyn Union to KeySpan under certain
circumstances, prohibitions on certain intercompany loans,
guarantees and pledges, and restrictions on transactions among the
affiliated holding company group.
The agreement reached in the holding company filing included a new
multi-year rate plan that became effective on October 1, 1996.
After an initial rate reduction of approximately $3.0 million in
fiscal 1997, the non-gas component in customer bills will be under
specific price caps. Hence, the total amount for this component in
rates that the Company can charge customers, in the aggregate, will
remain constant for the subsequent five years, although rates in
certain customer classes may be increased in order to reflect cost
responsibility more appropriately. The Company also will be
permitted to charge for various ancillary services.
During the six-year term of the rate plan, the costs of gas
purchased by the Company for its customers will be recovered
currently in billed firm revenues through the operation of a tariff
provision, the Gas Adjustment Clause (GAC). Further, in addition
to recovering its specific gas costs in applicable rates, the
Company's rates for transporting gas within its local distribution
system provide for full margin recovery of its cost of service.
(See Notes to Consolidated Financial Statements, "Summary of
Significant Accounting Policies and Basis for Financial Statement
Presentation -- Regulatory Assets".)
<PAGE>
Although there is no specific authorized rate of return on common
equity, the rate plan includes provisions for rate changes if
certain conditions applicable to inflation, exogenous costs or
changes in financial condition occur. Under the agreement the
Company generally is not subject to any earnings cap or provisions
to share with customers any level of earnings from utility
operations. However, incentive provisions remain for retention of
20% of margins on sales to off-system customers and capacity
release credits, and expenditures related to remediation of the
sites of former gas manufacturing plants are subject to a provision
enabling the Company to retain any savings, while requiring it to
absorb any costs, to the extent that expenditures vary by 10%
compared with estimates. The agreement includes a customer service
quality performance plan with a maximum forty basis-point pre-tax
return penalty if service quality diminishes in certain categories
over the term of the agreement. Also, the weather normalization
adjustment was modified to provide that the Company may recover or
be required to refund 87.5% of all margin shortfalls or surpluses
resulting from weather that is warmer or colder-than-normal.
In September 1995, the PSC approved the Company's second stage rate
filing covering fiscal 1996. The approval provided for no base
rate increase; however, $7.5 million in deferred credits were
amortized to income in 1996. The authorized rate of return on
utility common equity was set at 10.65% for fiscal 1996.
In October 1994, the PSC approved a three-year rate settlement
agreement which provided for no base rate increase in fiscal 1995;
however, the Company amortized to income, as permitted,
approximately $1.3 million of deferred credits in that year. The
third year of this agreement was superseded by the PSC order in the
holding company proceeding of September 1996 mentioned above.
Restructuring Proceeding
The PSC has set forth a policy framework to guide the transition of
New York State's gas distribution industry in the deregulated gas
industry environment. In March 1996, the PSC issued an order on
utility compliance tariff filings, including the Company's, related
to this framework.
Pursuant to this order, beginning on May 1, 1996, customers in the
Company's small-volume market have the option to purchase their gas
supplies from sources other than the Company, which would serve as
gas transporter. Large-volume customers have had this option for
a number of years. Small-volume customers can be grouped together
by marketers if their combined minimum threshold usage reaches
50,000 therms of gas per year, which approximates the usage of 35
homes. The PSC approved the Company's methodology of recovering
the cost of pipeline capacity and storage service provided to
marketing firms and transportation customers. In addition to
transporting gas that customers purchase from marketers, utilities
such as the Company will provide billing, meter reading and other
<PAGE>
services for aggregate rates that closely approximate the
distribution charge reflected in otherwise applicable sales rates
to supply these customers. The PSC order placed a limit on the
amount of gas the Company would be obligated to transport in its
core market under aggregation programs to 5% of total core sales in
each of the next three years, with no more than 25% of any one
service class permitted to convert to transportation service.
Environmental Matters
The Company is subject to various Federal, state and local
laws and regulatory programs related to the environment. These
environmental laws govern both the normal, ongoing operations of
the Company as well as the cleanup of historically contaminated
properties. Ongoing environmental compliance activities, which
historically have not been material, are integrated with the
Company's operations and maintenance activities. As of September
30, 1996, the Company had an accrued liability of $28.8 million
representing costs associated with investigation and remediation at
former manufactured gas plant sites. (See Note 9 to the
Consolidated Financial Statements, "Environmental Matters," for
additional information.)
<PAGE>
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 solely 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.
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To The Brooklyn Union Gas Company:
We have audited the accompanying Consolidated Balance Sheet and
Consolidated Statement of Capitalization of The Brooklyn Union Gas
Company (a New York corporation) and subsidiaries as of September
30, 1996 and 1995, and the related Consolidated Statements of
Income, Retained Earnings and Cash Flows for each of the three
years in the period ended September 30, 1996. 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 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 and
capitalization of The Brooklyn Union Gas Company and subsidiaries
as of September 30, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the
period ended September 30, 1996, 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
October 23, 1996
New York, New York
<PAGE>
Summary of Significant Accounting Policies and Basis for Financial
Statement Presentation
Principles of Consolidation
The Consolidated Financial Statements reflect the accounts of the
Company and its subsidiaries. All significant intercompany
transactions are eliminated. All other adjustments are of a
normal, recurring nature and certain reclassifications have been
made to amounts in prior periods to conform them with the current
period presentation.
Further, 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.
Utility Gas 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.
Depreciation is provided on a straight-line basis in amounts
equivalent to composite rates on average depreciable property of
3.4% in 1996 and 1995, and 3.3% in 1994.
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.
Gas Exploration and Production Property - Depletion
and Depreciation
The Company's gas exploration and production subsidiary follows the
full cost method of accounting. All productive and nonproductive
costs identified with acquisition, exploration and development are
capitalized. Provisions for depletion are based on the units-of-
production method and, when necessary, include provisions related
to the asset ceiling test limitations required by the regulations
of the Securities and Exchange Commission. Costs of unevaluated
gas and oil properties are excluded from the amortization base
until proved reserves are established or an impairment is
determined.
Provisions for depreciation of all other non-utility property
are computed on a straight-line basis over useful lives of three to
<PAGE>
fifteen years.
Investments in Energy Services
Certain subsidiaries own as their principal assets investments
representing ownership interests of 50% or less in energy-related
businesses that are accounted for under the equity method.
Revenues
Utility customers generally are billed bi-monthly on a cycle basis.
Revenues include unbilled amounts related to the estimated gas
usage that occurred from the last meter reading to the end of each
month.
Revenue requirements to establish utility rates are based on
sales to customers. Gas costs are recovered currently in billed
firm revenues through the operation of a tariff provision, the Gas
Adjustment Clause (GAC). Net revenues from off-system gas sales
and tariff gas balancing services and capacity release credits are
refunded to firm customers subject to certain limited sharing
provisions in the Company's tariff. Prior to October 1, 1996, net
revenues from tariff sales for gas and transportation services to
on-system customers made on an interruptible basis were refunded to
firm customers subject to sharing provisions. 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.
Derivative Financial Instruments
The Company and THEC use derivative financial instruments primarily
to hedge exposures in cash flows due to fluctuations in the price
of natural gas and fuel oil, which in certain markets may strongly
influence the Company's selling price for natural gas. Gains and
losses on these instruments are recognized concurrently with the
recognition of the related physical transactions.
The Company regularly assesses the relationship between natural gas
commodity prices in "cash" and futures markets. The correlation
between prices in these markets has been well within a range
generally deemed to be acceptable. If correlation were not to
remain in an acceptable range, the Company would account for its
financial instrument positions as trading activities.
Federal Income Tax
Prior to the adoption in 1994 of SFAS-109, "Accounting for Income
Taxes", pursuant to PSC policy, deferred taxes were not provided
for certain construction costs incurred before fiscal 1988 and for
bases differences related to differences between tax and book
<PAGE>
depreciation methods. In accordance with SFAS-109, the Company
recorded a regulatory asset for the net cumulative effect of having
to provide deferred Federal income tax expense on all differences
between the tax and book bases of assets and liabilities at the
current tax rate.
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 life of the related property.
Regulatory Assets
The Company is subject to the provisions of Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation". Regulatory assets arise from the
allocation of costs and revenues to accounting periods for utility
ratemaking purposes differently from bases generally applied by
nonregulated companies. Regulatory assets are recognized in
accordance with SFAS-71. With the exception of net tax regulatory
assets all other significant assets and liabilities created by the
ratemaking process, including the $33.2 million recorded for
environmental remediation costs as of September 30, 1995, have been
reflected in utility rates pursuant to the agreement approved by
the PSC in its September 25, 1996 holding company order.
Accordingly, at September 30, 1996 the Company had only a net tax
regulatory asset of $74,885,000 compared to a regulatory asset of
$109,636,000 related to taxes and environmental costs at September
30, 1995.
In the event that it were no longer subject to the provisions
of SFAS-71, the Company estimates that the write-off of this net
regulatory tax asset could result in a charge to net income of
approximately $48,675,000 which would be classified as an
extraordinary item.
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
stock by subsidiaries.
Research and Development Costs
All research and development costs are expensed as incurred.
For the years ended September 30, 1996, 1995 and 1994, these costs
were $12.8 million, $11.9 million and $11.9 million, respectively.
<PAGE>
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
=====================================================================================
For the Year Ended September 30, 1996 1995 1994
=====================================================================================
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Revenues
Utility sales $ 1,351,821 $1,152,331 $1,279,638
Gas production and other 80,181 63,953 58,992
----------------------------------------------------------------------------------------
1,432,002 1,216,284 1,338,630
----------------------------------------------------------------------------------------
Operating Expenses
Cost of gas 610,053 446,559 560,657
Operation and maintenance 428,977 385,654 384,734
Depreciation and depletion 79,610 72,020 69,611
General taxes 143,296 134,718 150,743
Federal income tax (See Note 1) 39,508 41,989 40,556
----------------------------------------------------------------------------------------
Operating Income 130,558 135,344 132,329
Other Income
Income from energy services investments 13,523 9,458 5,689
Gain on sale of investment in Canadian plant 16,160 - -
Gain on sale of subsidiary stock (See Note 3) 35,437 - -
Other, net (1,188) 151 700
Federal income tax (See Note 1) (19,861) (51) (142)
-----------------------------------------------------------------------------------------
Income Before Interest Charges 174,629 144,902 138,576
Interest Charges
Long-term debt 46,803 47,939 46,900
Other 4,918 5,128 4,292
----------------------------------------------------------------------------------------
Net Income 122,908 91,835 87,384
Dividends on Preferred Stock 323 337 351
----------------------------------------------------------------------------------------
Income Available for Common Stock $ 122,585 $ 91,498 $ 87,033
========================================================================================
Earnings Per Share of Common Stock
(Average shares outstanding of 49,365,435,
48,211,220 and 46,979,597, respectively) $ 2.48 $ 1.90 $ 1.85
========================================================================================
</TABLE>
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
<TABLE>
<CAPTION>
=======================================================================================
For the Year Ended September 30, 1996 1995 1994
---------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Balance at Beginning of Year $ 303,709 $ 279,466 $ 255,979
Income Available for Common Stock 122,585 91,498 87,033
----------------------------------------------------------------------------------------
426,294 370,964 343,012
Less:
Cash dividends declared ($1.42, $1.39 and $1.35
per common share, respectively) 70,291 67,229 63,652
Other adjustments 30 26 (106)
-----------------------------------------------------------------------------------------
Balance at End of Year $ 355,973 $ 303,709 $ 279,466
=========================================================================================
The accompanying Summary of Significant Accounting Policies and Basis for Financial Statement
Presentation and Notes to Consolidated Financial Statements are integral parts of these statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
===============================================================================================
CONSOLIDATED BALANCE SHEET
September 30, 1996 1995
(Thousands of Dollars)
<S> <C> <C>
Assets
Property
Utility, at cost $ 1,782,440 $ 1,690,193
Accumulated depreciation (429,476) (393,263)
Gas exploration and production, at cost (See Note 3) 510,568 353,847
Accumulated depletion (165,414) (138,136)
------------------------------------------------------------------------------------------------
1,698,118 1,512,641
------------------------------------------------------------------------------------------------
Investments in Energy Services (See Note 8) 115,529 121,023
------------------------------------------------------------------------------------------------
Current Assets
Cash 18,524 15,992
Temporary cash investments 23,397 24,550
Accounts receivable 172,843 146,018
Allowance for uncollectible accounts (15,616) (13,730)
Gas in storage, at average cost 91,813 88,810
Materials and supplies, at average cost 12,089 13,203
Prepaid gas costs 11,945 15,725
Other 38,888 19,856
------------------------------------------------------------------------------------------------
353,883 310,424
------------------------------------------------------------------------------------------------
Deferred Charges 122,073 172,834
------------------------------------------------------------------------------------------------
$ 2,289,603 $ 2,116,922
================================================================================================
Capitalization and Liabilities
Capitalization (See accompanying statement and Note 5)
Common equity $ 905,808 $ 826,290
Preferred stock, redeemable 6,600 6,900
Long-term debt 712,013 720,569
------------------------------------------------------------------------------------------------
1,624,421 1,553,759
------------------------------------------------------------------------------------------------
Current Liabilities
Accounts payable 143,561 103,705
Dividends payable 18,229 17,536
Taxes accrued 10,905 3,635
Customer deposits 21,881 22,252
Customer budget plan credits 8,892 24,790
Interest accrued and other 37,244 39,438
------------------------------------------------------------------------------------------------
240,712 211,356
------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Federal income tax 282,041 247,882
Unamortized investment tax credits 20,007 20,948
Other 43,573 82,977
------------------------------------------------------------------------------------------------
345,621 351,807
------------------------------------------------------------------------------------------------
Minority Interest in Subsidiary Company (See Note 3) 78,849 -
------------------------------------------------------------------------------------------------
$ 2,289,603 $ 2,116,922
================================================================================================
The accompanying Summary of Significant Accounting Policies and Basis for Financial Statement
Presentation and Notes to Consolidated Financial Statements are integral parts of these statements.
</TABLE>
<PAGE>
CONSOLIDATED STATEMENT OF CAPITALIZATION
<TABLE>
<CAPTION>
=========================================================================================
September 30, 1996 1995
-----------------------------------------------------------------------------------------
<S> <C> <C>
(Thousands of Dollars)
Common Equity
Common stock, $.33 1/3 par value, authorized 70,000,000 shares;
outstanding 49,857,448 and 48,788,320 shares,
respectively $ 549,835 $ 522,581
Retained earnings (See accompanying statement) 355,973 303,709
------------------------------------------------------------------------------------------
905,808 826,290
------------------------------------------------------------------------------------------
Preferred Stock, Redeemable
$100 par value, cumulative, authorized 900,000 shares
4.60% Series B, 69,000 and 72,000 shares outstanding, respectively 6,900 7,200
Less: Current sinking fund requirements 300 300
------------------------------------------------------------------------------------------
6,600 6,900
------------------------------------------------------------------------------------------
Long-term Debt
Gas facilities revenue bonds (issued through New York
State Energy Research and Development Authority)
9% Series 1985A due May 2015 - 98,500
8 3/4% Series 1985 due July 2015 - 55,000
6.368% Series 1993A and Series 1993B due April 2020 75,000 75,000
7 1/8% Series 1985 I due December 2020 62,500 62,500
7% Series 1985 II due December 2020 62,500 62,500
5.5% Series 1996 due January 2021 153,500 -
6.75% Series 1989A due February 2024 45,000 45,000
6.75% Series 1989B due February 2024 45,000 45,000
5.6% Series 1993C due June 2025 55,000 55,000
6.95% Series 1991A and Series 1991B due July 2026 100,000 100,000
5.635% Series 1993D-1 and Series 1993D-2 due July 2026 50,000 50,000
-----------------------------------------------------------------------------------------
648,500 648,500
Unamortized premium - Long-term debt (1,489) -
Subsidiary borrowings 65,002 72,069
-----------------------------------------------------------------------------------------
712,013 720,569
-----------------------------------------------------------------------------------------
$ 1,624,421 $ 1,553,759
=========================================================================================
The accompanying Summary of Significant Accounting Policies and Basis for Financial Statement
Presentation and Notes to Consolidated Financial Statements are integral parts of these statements.
</TABLE>
<PAGE>
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
==============================================================================================================
For the Year Ended September 30, 1996 1995 1994
--------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 122,908 $ 91,835 $ 87,384
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation and depletion 83,006 77,696 75,386
Deferred Federal income tax 25,985 11,037 10,897
Gain on sale of investment in Canadian operations (16,160) - -
Gain on sale of subsidiary stock (35,437) - -
Income from energy services investments (13,523) (9,458) (5,689)
Dividends received from energy services investments 11,031 3,595 4,392
Change in accounts receivable, net (24,939) 44,712 31,906
Change in accounts payable 39,856 (29,283) (34,121)
Gas inventory and prepayments 777 6,208 5,498
Other 8,863 14,439 18,474
---------------------------------------------------------------------------------------------------------------
Cash provided by operating activities 202,367 210,781 194,127
---------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Sale of common stock 27,407 27,974 29,828
Proceeds from sale of subsidiary stock 101,041 - -
Common stock proceeds receivable - - 44,910
Issuance of long-term debt 153,500 19,192 12,077
Repayments of long-term debt and preferred stock (160,867) (300) (300)
Dividends paid (70,614) (67,566) (64,003)
----------------------------------------------------------------------------------------------------------------
Cash provided by (used for)financing activities 50,467 (20,700) 22,512
----------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (excluding allowance
for equity funds used during construction) (301,307) (212,732) (197,496)
Proceeds from sale of investment in Canadian plant 26,938 - 11,691
Partnership distribution 1996 and other 22,914 9,702 1,398
----------------------------------------------------------------------------------------------------------------
Cash used in investing activities (251,455) (203,030) (184,407)
----------------------------------------------------------------------------------------------------------------
Change in Cash and Temporary Cash Investments 1,379 (12,949) 32,232
Cash and Temporary Cash Investments at Beginning of Year 40,542 53,491 21,259
----------------------------------------------------------------------------------------------------------------
Cash and Temporary Cash Investments at End of Year $ 41,921 $ 40,542 $ 53,491
================================================================================================================
Temporary cash investments are short-term marketable securities purchased with maturities of three months or
less that are carried at cost which approximates their fair value.
Supplemental disclosures of cash flows
Income taxes $ 37,053 $ 36,000 $ 36,900
Interest $ 53,210 $ 53,047 $ 50,872
================================================================================================================
The accompanying Summary of Significant Accounting Policies and Basis for Financial Statement
Presentation and Notes to Consolidated Financial Statements are integral parts of these statements.
</TABLE>
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
1. FEDERAL INCOME TAX
Income tax expense (benefit) is reflected as follows in the
Consolidated Statement of Income:
Year Ended September 30, 1996 1995 1994
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Expenses
Current $ 27,766 $ 31,676 $ 38,403
Deferred 11,742 10,313 2,153
39,508 41,989 40,556
Other Income
Current 6,559 379 (7,528)
Deferred 14,243 724 8,744
Amortization of investment
tax credits (941) (1,052) (1,074)
19,861 51 142
Total Federal income tax $ 59,369 $ 42,040 $ 40,698
</TABLE>
The components of the Company's net deferred income tax liability
reflected as Deferred Credits and Other Liabilities - Federal
income tax in the Consolidated Balance Sheet are as follows:
<TABLE>
<CAPTION>
September 30, 1996 1995
(Thousands of Dollars)
<S> <C> <C>
Utility property $ 176,565 $ 180,708
Gas production and other property 69,488 49,402
Net tax regulatory asset 26,210 28,214
Other 9,778 (10,442)
Net deferred income tax liability $ 282,041 $ 247,882
</TABLE>
<PAGE>
The following is a reconciliation between reported income tax and
tax computed at the statutory rate of 35%:
<TABLE>
<CAPTION>
Year Ended September 30, 1996 1995 1994
(Thousands of Dollars)
<S> <C> <C> <C>
Computed at statutory rate $ 63,797 $ 46,856 $ 44,828
Adjustments related to:
Gas production tax credits (1,962) (2,730) (1,303)
Nontaxable interest income (678) (870) (556)
Amortization of investment
tax credits (941) (1,052) (1,074)
Other, net (847) (164) (1,197)
Total Federal income tax $ 59,369 $ 42,040 $ 40,698
Effective income tax rate 33% 31% 32%
</TABLE>
2. POSTRETIREMENT BENEFITS
A. Pension: The Company has a noncontributory defined benefit
pension plan covering substantially all employees. Benefits are
based on years of service and compensation. The Company's funding
policy for pensions is in accordance with requirements of Federal
law and regulations. There were no pension contributions in 1996,
1995 and 1994. Special retirement programs were initiated in 1995
and 1994.
The calculation of net periodic pension cost follows:
<TABLE>
<CAPTION>
Year Ended September 30, 1996 1995 1994
(Thousands of Dollars)
<S> <C> <C> <C>
Service cost, benefits earned
during the year $ 15,160 $ 11,533 $ 15,100
Special retirement charge - 5,416 8,465
15,160 16,949 23,565
Interest cost on projected
benefit obligation 37,128 35,128 29,511
Return on plan assets (78,930) (82,626) (12,430)
Net amortization and deferral 31,745 34,786 (32,798)
Total pension cost $ 5,103 $ 4,237 $ 7,848
</TABLE>
<PAGE>
The following table sets forth the plan's funded status and
amounts recognized in the Company's Consolidated Balance Sheet.
Plan assets principally are investment grade common stock and
fixed income securities:
<TABLE>
<CAPTION>
September 30, 1996 1995
(Thousands of Dollars)
<S> <C> <C>
Actuarial present value of
benefit obligations:
Vested $(414,988) $(401,159)
Accumulated $(439,278) $(423,434)
Projected $(563,852) $(545,825)
Plan assets at fair value $ 608,080 $ 555,906
Plan assets in excess of
projected benefit obligation $ 44,228 $ 10,081
Unrecognized net loss (gain)
from past experience different
from that assumed and from
changes in assumptions (32,755) 10,880
Unrecognized transition asset (27,914) (32,566)
Accrued pension liability $ (16,441) $ (11,605)
Assumptions:
Obligation discount 7.25% 7.00%
Asset return 7.75% 7.50%
Average annual increase
in compensation 5.50% 5.50%
</TABLE>
B. Other - Retiree Health Care and Life Insurance: The Company
sponsors noncontributory defined benefit plans under which it
provides 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 a
Voluntary Employee Beneficiary Association (VEBA) trust.
Contributions to VEBA trusts are tax deductible, subject to
limitations contained in the Internal Revenue Code. The Company's
policy is to fund the cost of postretirement benefits in a tax
effective manner as part of its overall strategy to manage the
costs of its benefit programs for employees.
<PAGE>
Net periodic other postretirement benefit cost included the
following components:
<TABLE>
<CAPTION>
Year Ended September 30, 1996 1995
(Thousands of Dollars)
<S> <C> <C>
Service cost, benefits earned
during the year $ 3,178 $ 2,590
Interest cost on accumulated
postretirement benefit obligation 10,673 9,958
Return on plan assets (9,382) (6,746)
Net amortization and deferral 10,961 6,752
Other postretirement benefit cost $15,430 $12,554
</TABLE>
The following table sets forth the plans' funded status, reconciled
with amounts recognized in the Company's Consolidated Balance
Sheet:
<TABLE>
<CAPTION>
September 30, 1996 1995
(Thousands of Dollars)
<S> <C> <C>
Actuarial present value of accumulated
postretirement benefit obligation
Retirees $ (88,278) $ (87,022)
Fully eligible active plan
participants (18,271) (10,980)
Other active plan participants (63,762) (56,157)
$(170,311) $(154,159)
Plan assets at fair value, primarily
stocks and bonds $ 93,452 $ 72,638
Accumulated postretirement benefit
obligation in excess of plan assets $ (76,859) $ (81,521)
Unrecognized net loss from past
experience different from that assumed
and from changes in assumptions 29,285 25,345
Unrecognized transition obligation 64,015 67,781
Prepaid other postretirement benefit $ 16,441 $ 11,605
Assumptions:
Obligation discount 7.25% 7.00%
Asset return 7.75% 7.50%
</TABLE>
The measurement also assumes a health care cost trend rate of 8.5%
annually decreasing to 5.0% by the year 2007 and remaining at that
level thereafter. A 1.0% increase in the health care cost trend
rate would have the effect of increasing the accumulated
postretirement benefit obligation as of September 30, 1996 and the
net periodic SFAS-106 expense by approximately $23,825,000 and
$1,935,000, respectively.
<PAGE>
3. THE HOUSTON EXPLORATION COMPANY (THEC)
Certain former employees of Fuel Resources Inc., the subsidiary of
the Company that previously owned certain onshore natural gas and
oil producing properties and acreage, were entitled to receive
remuneration for the increase in the value of these properties
should these properties be sold or transferred. These former
employees were paid, and a reorganization charge of $12.0 million
was recorded in operation and maintenance expense in the
accompanying Consolidated Statement of Income as a result of the
transfer of these properties to THEC in 1996.
In September, 1996, THEC completed an initial public offering (the
IPO) of 7,130,000 shares of its common stock at an offering price
of $15.50 per share. The cash proceeds to THEC from the IPO, after
deductions for commissions and offering expenses, were $101.0
million and were used to repay a portion of THEC's short-term
borrowings incurred as a result of two major acquisitions in 1996
of properties and proved gas reserves for $84.7 million. One of
these acquisitions also required THEC to issue, in conjunction with
the IPO, 762,387 shares (the number of shares being determined by
the IPO price) of its common stock as consideration for the $11.8
million portion of the acquisition's purchase price that was to be
funded with THEC's stock.
Further, in September 1996, THEC issued, also in conjunction with
the IPO, 145,161 shares of its common stock to its President for
certain of his working interests, valued at $2.3 million, in
properties owned by THEC. As a result of these three stock
issuances, the Company's ownership in THEC was reduced from 100% to
approximately 66% and the Company recorded a $35.4 million gain
($23.0 million after tax) in recognition of the net increase in the
book value of the Company's investment in THEC.
4. FIXED OBLIGATIONS
A. Leases: Lease costs included in operation expense were
$13,894,000 in 1996, $14,706,000 in 1995 and $15,547,000 in 1994.
The future minimum lease payments under the Company's various
leases, all of which are operating leases, are approximately
$14,143,000 per year over the next five years and $149,547,000 in
the aggregate for years thereafter.
The Company has a lease agreement with a remaining term of 15 years
for its corporate headquarters.
B. Fixed Charges Under Firm Contracts: The Company has entered
into various contracts for gas delivery and supply services. The
contracts have remaining terms that cover from one to seventeen
years. Certain of these contracts require payment of monthly
charges in the aggregate amount of approximately $4.3 million per
month in all events and regardless of the level of service
available. Such charges are recovered as gas costs.
<PAGE>
5. CAPITALIZATION
A. Common and Preferred Stock: In 1996 and 1995, the Company
issued 1,069,128 and 1,198,305 shares of common stock for
$27,407,000 and $27,974,000, respectively, under the Dividend
Reinvestment and Stock Purchase Plan, the Discount Stock Purchase
Plan for Employees, and the Employee Savings Plan. At September 30,
1996, 2,355,942 unissued shares of common stock were reserved for
issuance under these plans. Other changes to common stock reflect
the amortization of premiums paid on preferred stock redeemed in
prior years which were deferred in order to reflect the ratemaking
treatment. Annual amortization was approximately $155,000 in each
of the past two years.
The 4.60% Series B preferred stock is subject to an annual sinking
fund requirement of 3,000 shares at par value.
B. Gas Facilities Revenue Bonds and Other: The Company 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 by the Company to finance qualified
expenditures.
There are no sinking fund requirements for any Gas Facilities
Revenue Bonds. The Company's 7 1/8% Series 1985 I and 7% Series
1985 II Gas Facilities Revenue Bonds became callable on December 1,
1996, at the optional redemption price of 102% of par value plus
accrued interest. The Company is seeking authorization of
government agencies for the call and refunding of these bond
issues.
C. Other Long-Term Debt: THEC has a $150 million unsecured line
of credit which for the most part 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 September 30, 1996, borrowings of $65 million were
outstanding under this line of credit and $1.6 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, or
based on the prime rate. The interest rate on this debt was 6.5%
per annum at fiscal year-end. 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.
6. STOCK OPTIONS AND AWARDS
On November 15, 1995, the Company implemented the Long-Term
Performance Incentive Compensation Plan and granted 202,800
nonqualified stock options and 13,000 performance shares to
officers. The number of shares of Common Stock reserved for
<PAGE>
issuance under this Plan is 1,500,000 in the aggregate; however, no
more than 750,000 shares will be available for issuance pursuant to
the exercise of the stock options.
The stock options were awarded at an exercise price of $27.00 (the
fair market value on the grant date). They vest ratably over a
three-year period from the grant date with a ten-year exercise
period. The stock options were not exercisable as of September 30,
1996. The performance shares granted represent the target number of
shares, as defined under the Plan, that will vest at the end of a
three-year performance period ending on September 30, 1998. The
actual number of performance shares to be earned is contingent upon
achieving target levels of total shareholder return in relation to
the Standard & Poor's Utilities Index. The actual awards will range
from 0 to 200% of the target number of shares.
In October 1995, the FASB issued Statement No. 123, "Accounting for
Stock-Based Compensation". This statement requires companies to
either recognize compensation costs attributable to employee stock
options (or similar equity instruments) in net income or, in the
alternative, provide pro forma footnote disclosure on net income
and earnings per share. Implementation of this statement is
required in the Company's 1997 fiscal year. The Company does not
anticipate that the provisions of this statement will have a
material effect on the Company's net income.
7. FINANCIAL INSTRUMENTS
A. Fair Value of Financial Instruments: The Company's long-term
debt consists primarily of publicly traded Gas Facilities Revenue
Bonds, the fair value of which is estimated based on quoted market
prices for the same or similar issues. The fair value of these
bonds at September 30, 1996 and 1995 was $660,499,600 and
$673,408,300, respectively, and the carrying value was $648,500,000
in both years. Subsidiary debt is carried at an amount
approximating fair value because its interest rate is based on
current market rates.
The fair value of the Company's redeemable preferred stock is
estimated based on quoted market prices for similar issues. At
September 30, 1996 and 1995, the fair value of this stock was
$4,958,300 and $5,228,800, respectively, and the carrying value was
$6,600,000 and $6,900,000, respectively.
All other financial instruments included in the Consolidated
Balance Sheet are stated at amounts that approximate fair values.
B. Derivative Financial Instruments: The Company and THEC employ
derivative financial instruments - natural gas futures, options and
swaps - for the purpose of managing commodity price risk.
The utility tariff applicable to certain large-volume customers
permits gas to be sold at prices established monthly within a
<PAGE>
specified range expressed as a percentage of prevailing alternate
fuel oil prices. The Company uses derivatives, primarily futures,
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 that are capped by
options over the same time period. 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. The Company has developed a strong sense of the
relationship between gas and oil prices in the target markets, and
the implementation of its strategy has satisfactorily hedged its
exposure to the loss of profit margins on the desired portion of
anticipated sales.
With respect to natural gas production operations, THEC generally
uses swaps and standard New York Mercantile Exchange futures
contracts or options to hedge the price risk related to known
production plans and capabilities. These instruments include a
fixed price/volume and the swaps are structured as both straight
and participating swaps. In all cases, THEC pays the other parties
the amount by which the floating variable price (settlement price)
exceeds the fixed price and receives the amount by which the
settlement price is below the fixed price.
Two participating swap contracts covering 1,860,000 and 930,000 Mcf
in 1997 and 1998, respectively, are priced at $1.98 and $2.05. The
volumes under these two swaps are reduced by 50% in each month
where the NYMEX prices for that month exceed the fixed price under
the swap contract.
<PAGE>
The following table summarizes the notional amounts and related
fair values of the Company's derivative financial instrument
positions outstanding at September 30, 1996. Fair values are based
on quotes for the same or similar instruments. Differences between
the notional contract amounts and fair values represent implicit
gains on gas contracts representing long positions or losses on oil
contracts representing short positions if the instruments were
settled at market.
__________________________________________________________________
<TABLE>
<CAPTION>
Gas
Type of Fiscal Year Fixed Price Volume Notional Fair
Instrument of Maturity per Mcf (Mcf) Amount Value
(in thousands)
<S> <C> <C> <C> <C>
Futures contracts 1997 $1.97-$2.39 13,630,000 $30,447 $30,613
Options 1997 $2.30-$3.00 3,020,000 $ - $ 964
Swap contracts 1997 $1.53-$2.09 16,858,000 $32,219 $32,165
1998 $1.53-$2.09 4,280,000 $ 8,054 $ 8,166
</TABLE>
<TABLE>
<CAPTION>
Oil
Type of Fiscal Year Fixed Price Volume Notional Fair
Instrument of Maturity per Gallon (Gallons) Amount Value
(in thousands)
<S> <C> <C> <C> <C>
Futures contracts 1997 $0.49-$0.58 122,556,000 $66,297 $81,530
1998 $0.52 6,342,000 $ 3,315 $ 3,592
Options 1997 $0.13-$0.22 63,672,000 $ 211 $ 1,018
__________________________________________________________________
</TABLE>
Futures contracts expire and are renewed monthly. As of September
30, 1996, no such contract extended beyond January 1998. Further,
swaps contracts are settled monthly and extend through March 1998.
Margin deposits with brokers at September 30, 1996 and 1995
amounted to $23,619,000 and $1,662,400, respectively, and are
recorded in Other in the current assets section of the balance
sheet. Deferred gains (losses) on closed positions were $1,330,000
and ($748,000) at September 30, 1996 and 1995, respectively.
The Company and THEC are exposed to credit risk in the event of
nonperformance by counterparties to derivative contracts, as well
as nonperformance by the counterparties 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 the
Company's overall business risk.
8. INVESTMENT IN IROQUOIS PIPELINE
A Company subsidiary, North East Transmission Co., Inc. (NETCO),
owns a 19.4% partnership interest in Iroquois Gas Transmission
System, L.P. (Iroquois). Iroquois owns a 375-mile pipeline
extending from Canada to the Northeast United States. NETCO's
<PAGE>
investment in Iroquois was $35.4 million at September 30, 1996.
In 1992 Iroquois was informed that Federal criminal and civil
investigations of the construction of certain of its pipeline
facilities had been commenced. The investigations were to
determine whether Iroquois violated various environmental and other
laws in the construction of such facilities. In addition,
beginning in late 1993, Iroquois was informed by the Federal Energy
Regulatory Commission (FERC), the Army Corps of Engineers, the U.S.
Department of Transportation (DOT) and the New York State Public
Service Commission that each of these agencies had also commenced
investigations regarding the construction of pipeline facilities.
On May 23, 1996, as part of a comprehensive resolution of these
investigations, Iroquois Pipeline Operating Company (IPOC), the
operator of the pipeline, pleaded guilty to four felony violations
of the Clean Water Act and entered into consent decrees under the
Clean Water Act in four federal judicial districts. Although not
a named defendant, Iroquois signed the plea agreement and consent
decrees and is bound by their terms. Iroquois also entered into a
related settlement with the State of New York. Under these various
agreements, Iroquois and IPOC agreed to pay $22 million in fines
and penalties, agreed to remediate 27 wetlands along the length of
the pipeline, and agreed to implement under FERC and DOT orders two
ten-year plans to address certain ground stability and pipeline
safety concerns. Iroquois also entered into a separate settlement
with the FERC. In September 1995, a provision was made in the
Company's Consolidated Statement of Income for NETCO's share of the
estimated settlement costs. This provision was adequate to account
for NETCO's share of the above costs.
9. ENVIRONMENTAL MATTERS
Historically, the Company, or predecessor entities to the Company,
owned or operated several former manufactured gas plant (MGP)
sites. These sites have been identified for the New York State
Department of Environmental Conservation (DEC) for inclusion on
appropriate waste site inventories. In certain circumstances,
former MGP sites can give rise to environmental cleanup
responsibilities for the Company.
Two MGP sites are under active consideration by the Company. One
site, which is located on property still owned by the Company, is
the former Coney Island MGP facility located in Brooklyn, New York.
This site is the subject of continuing interim remedial action
under the direction of the U.S. Coast Guard. The Company executed
a consent order with the DEC addressing the overall remediation of
the Coney Island site in accordance with state law. A schedule of
investigative and cleanup activities is being developed, leading to
a cleanup over the next several years. The other site currently is
owned by the City of New York (City). The Company and the City are
discussing a mutual approach to sharing potential environmental
responsibility for this site. The Company believes it is likely
that, at a minimum, investigative costs will be incurred by the
<PAGE>
Company with respect to that site.
Based upon the Coney Island site consent order and the estimated
costs of investigation of the City site, the Company believes that
the minimum cost of MGP-related environmental cleanup will be
approximately $34 million, based upon current information,
primarily for the Coney Island site. The Company's actual MGP-
related costs may be substantially higher, depending upon
remediation experience, eventual end use of the sites, and
environmental conditions not addressed in the consent order or
current investigative plans. Such potential additional costs are
not subject to estimation at this time.
As of September 30, 1996, the Company had an unpaid liability of
$28.4 million. By order issued February 16, 1995, the PSC approved
the Company's July 1993 petition to defer the costs associated with
environmental site investigation and remediation incurred in 1993
and thereafter. Recovery of these costs began in fiscal year 1995,
and is conditioned upon absence of a PSC determination that such
costs have not been reasonably or prudently incurred. In addition,
the Company must demonstrate that it has taken all reasonable steps
to obtain cost recovery from all available funding sources,
including other responsible parties and insurance sources.
Moreover, the rate agreement that became effective on October 1,
1996, described in "Rate and Regulatory Matters" of Management's
Discussion and Analysis of Results of Operations and Financial
Condition, provides, among other things, that if the total cost of
investigating and remediating the Coney Island site plus the cost
of investigating the City site varies from the amount originally
accrued for these activities, the Company will retain or absorb 10%
of the variation. Under the rate agreement, similar ratemaking
treatment will be available for any additional accrued liabilities
for other MGP sites, should such accrual be required.
<PAGE>
NOTE 10. SUPPLEMENTAL GAS AND OIL DISCLOSURES (Unaudited)
This information includes amounts attributable to a 34% minority
interest in THEC at September30, 1996. In addition, gas and oil
operations, and reserves, were predominantly located in the United
States in all years.
<TABLE>
<CAPTION>
CAPITALIZED COSTS RELATING TO GAS AND OIL PRODUCING ACTIVITIES
- ---------------------------------------------------------------------------
September 30, 1996 1995
- ----------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Unproved properties not being amortized $60,137 $35,082
Properties being amortized-productive and nonproductive 441,024 299,398
- ---------------------------------------------------------------------------
Total capitalized costs 501,161 334,480
Accumulated depletion (160,128) (132,809)
- ---------------------------------------------------------------------------
Net capitalized costs $341,033 $201,671
- ---------------------------------------------------------------------------
At September 30, 1996 and 1995, the Company had an immaterial deficiency
in its asset ceiling test; however, such deficiency was eliminated by
subsequent increases in the price of natural gas.
</TABLE>
<TABLE>
<CAPTION>
The following is a break-out of the costs (in thousands of dollars) which
are excluded from the amortization calculation as of September 30, 1996,
by year of acquisition: 1996-$36,557; 1995-$13,312; and prior years-$10,268.
The Company cannot accurately predict when these costs will be included in
the amortization base, but it is expected these costs will be evaluated
within the next five years.
COSTS INCURRED IN PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT
ACTIVITIES
- -------------------------------------------------------------------
1996 1995 1994
- -------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Acquisition of properties-
Unproved properties $24,577 $10,996 $11,022
Proved properties 89,828 14,983 28,370
Exploration 20,828 5,907 18,961
Development 31,005 37,953 9,781
- ------------------------------------------------------------------
Total costs incurred $166,238 $69,839 $68,134
- ------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
RESULTS OF OPERATIONS FROM GAS AND OIL PRODUCING ACTIVITIES
- ------------------------------------------------------------------
1996 1995 1994
- ------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Revenues from gas and oil
producing activities-
Sales to unaffiliated parties $50,431 $40,810 $41,185
Sales to affiliates - - 2,023
- ------------------------------------------------------------------
Revenues 50,431 40,810 43,208
- ------------------------------------------------------------------
Production and lifting costs 8,860 5,762 5,360
Depletion 27,368 22,906 24,978
- ------------------------------------------------------------------
Total expenses 36,228 28,668 30,338
- ------------------------------------------------------------------
Income before taxes 14,203 12,142 12,870
Income taxes 3,037 1,957 3,306
- ------------------------------------------------------------------
Results of gas and oil producing
activities (excluding corporate
overhead and interest costs) $11,166 $10,185 $9,564
==================================================================
</TABLE>
<PAGE>
10. SUPPLEMENTAL GAS AND OIL DISCLOSURES (CONTINUED)
The gas and oil reserves information is based on estimates of
proved reserves attributable to the Company's interest as of
September 30 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
Company's proved reserves, except for those reserves devoted to
future production that is hedged. These reserves are priced at
their respective hedged amount. The standardized measure does not
purport, nor should it be interpreted, to present the fair value of
the Company'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.
<TABLE>
<CAPTION>
RESERVE QUANTITY INFORMATION
Natural Gas (MMcf)
- ---------------------------------------------------------------
1996 1995 1994
- ---------------------------------------------------------------
<S> <C> <C> <C>
Proved Reserves-
Beginning of Year 195,055 142,858 108,847
Revisions of previous estimates (354) 13,539 (2,297)
Extensions and discoveries 13,139 38,985 25,890
Production (26,435) (21,822) (22,814)
Purchases of reserves in place 134,325 21,495 34,931
Sales of reserves in place (1,189) - (1,699)
- ---------------------------------------------------------------
Proved Reserves-
End of Year 314,541 195,055 142,858
- ---------------------------------------------------------------
Proved Developed Reserves-
Beginning of Year 151,594 110,225 100,454
- ---------------------------------------------------------------
End of Year 222,522 151,594 110,225
===============================================================
</TABLE>
<TABLE>
<CAPTION>
Crude Oil, Condensate and Natural Gas Liquids (MBbls)
- ---------------------------------------------------------------
1996 1995 1994
- ---------------------------------------------------------------
<S> <C> <C> <C>
Proved Reserves-
Beginning of Year 1,162 807 443
Revisions of previous estimates (148) 245 (140)
Extensions and discoveries 182 155 155
Production (136) (148) (96)
Purchases of reserves in place 294 103 495
Sales of reserves in place (106) - (50)
- ---------------------------------------------------------------
Proved Reserves-
End of Year 1,248 1,162 807
- ---------------------------------------------------------------
Proved Developed Reserves-
Beginning of Year 974 543 407
- ---------------------------------------------------------------
End of Year 1,040 974 543
- ---------------------------------------------------------------
</TABLE>
<PAGE>
10. SUPPLEMENTAL GAS AND OIL DISCLOSURES (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED GAS AND OIL RESERVES
<TABLE>
<CAPTION>
- ---------------------------------------------------------------
1996 1995
- ---------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Future cash flows $554,798 $314,627
Future costs-
Production (89,303) (57,941)
Development (60,926) (29,948)
- ---------------------------------------------------------------
Future net inflows
before income tax 404,569 226,738
Future income taxes (59,623) (43,705)
- ---------------------------------------------------------------
Future net cash flows 344,946 183,033
10% discount factor (85,688) (49,512)
- ---------------------------------------------------------------
Standardized measure of
discounted future net
cash flows $259,258 $133,521
- ---------------------------------------------------------------
</TABLE>
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
FROM PROVED RESERVE QUANTITIES
<TABLE>
<CAPTION>
- ----------------------------------------------------------------
1996 1995 1994
- ----------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Standardized measure-
beginning of year $133,521 $108,134 $110,406
Sales and transfers, net of
production costs (41,571) (35,048) (37,848)
Net change in sales and
transfer prices, net of
production costs 44,719 (2,786) (25,005)
Extensions and discoveries and
improved recovery, net of
related costs 18,894 28,868 15,536
Changes in estimated future
development costs (4,798) (2,351) (1,016)
Development costs incurred
during the period that reduced
future development costs 15,056 10,360 6,381
Revisions of quantity estimates (2,338) 13,858 (2,917)
Accretion of discount 16,880 11,763 12,397
Net change in income taxes 21,026 (7,856) 4,001
Purchases of reserves in place 94,945 15,176 27,561
Sales of reserves in place - - (2,110)
Changes in production rates
(timing) and other (37,076) (6,597) 748
- ------------------------------------------------------------------
Standardized measure-end
of year $259,258 $133,521 $108,134
- ------------------------------------------------------------------
</TABLE>
<PAGE>
10. SUPPLEMENTAL GAS AND OIL DISCLOSURES (CONTINUED)
<TABLE>
<CAPTION>
Average Sales Prices and Production Costs - Per Unit
- ------------------------------------------------------------------
For the year ended September 30, 1996 1995 1994
- ------------------------------------------------------------------
<S> <C> <C> <C>
Average Sales Price*
Natural Gas ($/MCF) 2.11 1.47 1.97
Oil, Condensate and Natural
Gas Liquid ($/Bbl) 19.21 16.92 15.63
Production Cost Per
Equivalent MCF ($) .32 .25 .23
- ------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Acreage
- ------------------------------------------------------------------
As of September 30, 1996 Gross Net
- ------------------------------------------------------------------
<S> <C> <C>
Producing 258,798 160,154
Undeveloped 111,087 88,554
- ------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Number of Producing Wells
- ------------------------------------------------------------------
As of September 30, 1996 Gross Net
- ------------------------------------------------------------------
<S> <C> <C>
Gas Wells 1,114 678
Oil Wells 11 3
- ------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Drilling Activity (Net)
- ------------------------------------------------------------------
For the year ended September 30,
1996 1995 1994
Pro- Pro- Pro-
ducing Dry Total ducing Dry Total ducing Dry Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Net Develop-
mental Wells 10.1 0.8 10.9 10.0 3.4 13.4 6.6 - 6.6
Net Explora-
tory Wells 2.1 3.4 5.5 1.4 0.4 1.8 2.5 1.2 3.7
- -------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Wells in Process
As of September 30, 1996 Gross Net
<S> <C> <C>
Exploratory 4.0 1.1
Developmental 2.0 1.1
- -------------------------------------------------------------------
</TABLE>
* Represents the cash price received which excludes the effect of
any hedging transactions.
<PAGE>
SUPPLEMENTARY INFORMATION (UNAUDITED)
QUARTERLY INFORMATION
SUMMARY OF QUARTERLY INFORMATION
The following is a table of financial data for each quarter of fiscal
1996 and 1995. The Company's business is influenced by seasonal weather
conditions and the timing of approved base utility tariff rate changes.
The effect on utility earnings of variations in revenues caused by
abnormal weather is largely mitigated by operation of a weather
normalization adjustment contained in the Company's tariff.
<TABLE>
<CAPTION>
=========================================================================
First Second Third Fourth
Quarter Quarter Quarter Quarter
=========================================================================
(Thousands of Dollars Except Per Share Data)
<S> <C> <C> <C> <C>
1996
Operating revenues 398,083 595,438 254,311 184,170
Operating income(loss) 57,400 88,505 5,495 (20,842)(a)
Gains on sale of subsidiary
stock and Canadian plant
(after taxes) - - - 33,539
Income (loss) applicable
to common stock 44,624 74,413 (4,561) 8,109
Per common share:
Earnings (loss) (b) 0.91 1.51 (0.09) 0.16
Dividends declared 0.3550 0.3550 0.3550 0.3550
- --------------------------------------------------------------------------
1995
Operating revenues 358,348 481,615 217,696 158,625
Operating income(loss) 54,580 85,364 5,650 (10,250)
Income (loss) applicable
to common stock 42,753 73,555 (6,188) (18,622)
Per common share:
Earnings (loss) (b) 0.90 1.53 (0.13) (0.38)
Dividends declared 0.3475 0.3475 0.3475 0.3475
=========================================================================
</TABLE>
(a) Includes a subsidiary reorganization charge of $7.8 million after
taxes.
(b) Quarterly earnings per share are based on the average number of
shares outstanding during the quarter. Because of the increasing
number of common shares outstanding in each quarter, the sum of
quarterly earnings per share does not equal earnings per share
for the year.
<TABLE>
<CAPTION>
SUMMARY OF QUARTERLY STOCK INFORMATION
============================================================================
First Second Third Fourth
Quarter Quarter Quarter Quarter
============================================================================
<S> <C> <C> <C> <C>
1996
High 29 5/8 29 7/8 27 1/2 28 1/8
Low 24 5/8 25 3/4 24 7/8 24 7/8
Close 29 1/4 26 3/4 27 1/4 27 7/8
Shares Traded (000) 3,710 3,884 5,121 3,592
- ----------------------------------------------------------------------------
1995
High 25 3/8 24 3/4 26 3/8 26 3/8
Low 21 1/2 22 23 3/4 23 1/4
Close 22 1/4 24 1/8 26 1/4 24 5/8
Shares Traded (000) 2,695 3,977 2,543 3,219
============================================================================
</TABLE>
<PAGE>
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
There have been no changes in accountants. In addition, there
have been no disagreements between the Company and its independent
public accountants concerning any matter of accounting principles
or practices or financial disclosure required to be disclosed by
this item.
Part III
Item 10. Directors and Executive Officers of the Registrant
Information regarding the Company's directors is incorporated
herein by reference to pages 33 through 39 of the Company's
Prospectus/Proxy Statement, dated December 20, 1996, for its Annual
Meeting of Shareholders to be held on February 6, 1997.
Information regarding the Company's executive officers, who
are elected annually by the directors, is found on page 52 hereof.
Item 11. Executive Compensation
Information regarding compensation of the Company's executive
officers is incorporated herein by reference to pages 39 through 47
of the Company's Prospectus/Proxy Statement, dated December 20,
1996, for its Annual Meeting of Shareholders to be held on February
6, 1997.
Item 12. Security Ownership of Certain Beneficial Owners and
Management
Information regarding beneficial ownership and management
ownership is incorporated herein by reference to "Proposal (2) -
Election of Directors of Brooklyn Union" in the Company's
Prospectus/Proxy Statement, on pages 37 and 38, dated December 20,
1996, for its Annual Meeting of Shareholders to be held on February
6, 1997.
Item 13. Certain Relationships and Related Transactions
There are no transactions, or series of similar transactions,
or contemplated transactions which have occurred since the
beginning of the last fiscal year of the Company which exceed
$60,000 and involve any director or executive officer of the
Company.
No executive officer or director of the Company was indebted
to the Company or its subsidiaries at any time since the beginning
of the last fiscal year of the Company in an amount in excess of
$60,000.
<PAGE>
Part IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K
(a) 1. All Financial Statements
Page in
Form 10-K
Report of Independent Public Accountants 26
Summary of Significant Accounting Policies and
Basis of Financial Statement Presentation 27
Consolidated Statement of Income for the Years
Ended September 30, 1996, 1995 and 1994 30
Consolidated Statement of Retained Earnings for
the Years Ended September 30, 1996, 1995
and 1994 30
Consolidated Balance Sheet at September 30, 1996
and 1995 31
Consolidated Statement of Capitalization at
September 30, 1996 and 1995 32
Consolidated Statement of Cash Flows for the
Years Ended September 30, 1996, 1995 and 1994 33
Notes to Consolidated Financial Statements 34
(a) 2. Financial Statement Schedules
The following additional data should be read in conjunction with
the financial statements included in Part II, Item 8. Schedules
not included herein have been omitted because they are not
applicable or the required information is shown in such financial
statements or notes thereto.
<PAGE>
Executive Officers of the Registrant
- ------------------------------------
All Executive Officers serve one-year terms.
<TABLE>
<CAPTION>
Age as of
Sept. 30, Period Served
<S> <C> <C> <C>
Name and Position 1996 In Such Capacity Business Experience in Past 5 Years
Robert B. Catell, Chairman 59 1996 to Present Chairman and Chief Executive Officer
and Chief Executive Officer 1991 to 1996 President and Chief Executive Officer
1990 to 1991 President and Chief Operating Officer
Craig G. Matthews, President 53 1996 to Present President and Chief Operating Officer
and Chief Operating Officer 1994 to 1996 Executive Vice President
1991 to 1994 Executive Vice President and Chief
Financial Officer
1988 to 1991 Group Senior Vice President and Chief
Financial Officer
Helmut W. Peter 64 1996 to Present Vice Chairman
Vice Chairman 1992 to 1996 Executive Vice President
1991 to 1992 Executive Vice President and Chief
Engineer
1988 to 1991 Group Senior Vice President and
Chief Engineer
Anthony J. DiBrita 55 1992 to Present Senior Vice President
Senior Vice President 1989 to 1992 Vice President
Vincent D. Enright, Senior Vice 52 1994 to Present Senior Vice President and Chief
President and Chief Financial Financial Officer
Officer 1992 to 1994 Senior Vice President
1984 to 1992 Vice President
William K. Feraudo 46 1994 to Present Senior Vice President
Senior Vice President 1989 to 1994 Vice President
Wallace P. Parker, Jr. 47 1994 to Present Senior Vice President
Senior Vice President 1990 to 1994 Vice President
Lenore F. Puleo 43 1994 to Present Senior Vice President
Senior Vice President 1990 to 1994 Vice President
Maurice K. Shaw, Senior Vice 57 1993 to Present Senior Vice President and Corporate
President and Corporate Affairs Officer Affairs Officer
1987 to 1993 Senior Vice President and Chief
Marketing Officer
Edward J. Sondey 58 1992 to Present Senior Vice President
Senior Vice President 1981 to 1992 Vice President
Tina G. Barber, Vice President 47 1994 to Present Vice President and Chief
and Chief Information Officer Information Officer
1992 to 1994 Vice President
Richard M. Desmond, Vice 62 1992 to Present Vice President, Comptroller and
President, Comptroller and Chief Accounting Officer
Chief Accounting Officer 1984 to 1992 Vice President and Comptroller
Robert H. Preusser, Vice President 59 1992 to Present Vice President and Chief Engineer
and Chief Engineer 1987 to 1992 Vice President
Roger J. Walz, Vice President 51 1990 to Present Vice President and General Auditor
and General Auditor
Robert R. Wieczorek, Vice President, 54 1994 to Present Vice President, Secretary
Secretary and Treasurer and Treasurer
1989 to 1994 Vice President, Treasurer, and
Assistant Secretary
</TABLE>
<PAGE>
(a) 3. Exhibits
(3) Articles of incorporation and by-laws
By-laws of the Company, dated February 1, 1996, duly filed in
December 1996 as Exhibit 3(b) on KeySpan Energy Corporation's
Form S-4.
Restated Certificate of Incorporation of the Company filed
August 1, 1989, and Certificate of Amendment filed
July 2, 1993; incorporated by reference from Exhibit 4(b) to
Form S-3 Registration Statement No. 33-50249.
(4) Instruments defining the rights of security holders, including
indentures:
Official Statement, dated December 4, 1985, respective of
$125,000,000 of New York State Energy Research and Development
Authority Variable Rate Gas Facilities Revenue Bonds Series
1985 I and 1985 II, incorporated by reference from Form 10-K
for the year ended September 30, 1985.
Participation Agreement, dated as of December 1, 1985, between the
New York State Energy Research and Development Authority and
The Brooklyn Union Gas Company relating to the Variable Rate
Gas Facilities Revenue Bonds Series 1985 I and 1985 II,
incorporated by reference from Form 10-K for the year ended
September 30, 1985.
Indenture of Trust, dated December 1, 1985, between New York
State Energy Research and Development Authority and Chemical
Bank, as Trustee, relating to the Variable Rate Gas Facilities
Revenue Bonds Series 1985 I and 1985 II, incorporated by
reference from Form 10-K for the year ended September 30, 1985.
Official Statement, dated February 23, 1989, respective of
$90,000,000 of the New York State Research and Development
Authority Adjustable Rate Gas Facilities Revenue Bonds Series
1989A and Series 1989B, incorporated by reference from Form S-8
Registration Statement No. 33-29898.
Participation Agreement, dated as of February 1, 1989, between the
New York State Energy Research and Development Authority and
The Brooklyn Union Gas Company relating to the Adjustable Rate
Gas Facilities Revenue Bonds Series 1989A, incorporated by
reference from Form 10-K for the year ended September 30, 1989.
Participation Agreement, dated as of February 1, 1989, between the
New York State Energy Research and Development Authority and
The Brooklyn Union Gas Company relating to the Adjustable Rate
Gas Facilities Revenue Bonds Series 1989B, incorporated by
reference from Form 10-K for the year ended September 30, 1989.
<PAGE>
Indenture of Trust, dated February 1, 1989, between the
New York State Energy Research and Development Authority and
Manufacturers Hanover Trust Company, as Trustee, relating to
the Adjustable Rate Gas Facilities Revenue Bonds Series 1989A,
incorporated by reference from Form 10-K for the year ended
September 30, 1989.
Indenture of Trust, dated February 1, 1989, between the
New York State Energy Research and Development Authority and
Manufacturers Hanover Trust Company, as Trustee, relating to
the Adjustable Rate Gas Facilities Revenue Bonds Series 1989B,
incorporated by reference from Form 10-K for the year ended
September 30, 1989.
Official Statement, dated July 24, 1991, respective of
$50,000,000 of the New York State Research and Development
Authority Gas Facilities Revenue Bonds Series 1991A and
$50,000,000 of the New York State Research and Development
Authority Gas Facilities Revenue Bonds Series 1991B,
incorporated by reference from Form 10-K for the year ended
September 30, 1991.
Participation Agreement, dated as of July 1, 1991,between the New
York State Energy Research and Development Authority and The
Brooklyn Union Gas Company relating to the Gas Facilities
Revenue Bonds Series 1991A and 1991B, incorporated by reference
from Form 10-K for the year ended September 30, 1991.
Indenture of Trust, dated as of July 1, 1991, between the
New York State Energy Research and Development Authority and
Manufacturers Hanover Trust Company, as Trustee, relating to
the Gas Facilities Revenue Bonds Series 1991A and 1991B,
incorporated by reference from Form 10-K for the year ended
September 30, 1991.
Official Statement, dated July 23, 1992, respective of
$37,500,000 of the New York State Energy Research and
Development Authority Gas Facilities Revenue Bonds Series 1993A
and $37,500,000 of the New York State Energy Research and
Development Authority Gas Facilities Revenue Bonds Series 1993B,
incorporated by reference from Form 10-K for the year ended
September 30, 1992.
Participation Agreement, dated as of July 1, 1992, between the New
York State Energy Research and Development Authority and The
Brooklyn Union Gas Company relating to the Gas Facilities
Revenue Bonds Series 1993A and 1993B, incorporated by reference
from Form 10-K for the year ended September 30, 1992.
<PAGE>
Indenture of Trust, dated as of July 1, 1992, between the New York
State Energy Research and Development Authority and Chemical
Bank, as Trustee, relating to the Gas Facilities Revenue Bonds
Form Series 1993A and 1993B, incorporated by reference from Form
10-K for the year ended September 30, 1992.
Official Statement, dated April 29, 1992, respective of
$90,000,000 of the New York State Energy Research and
Development Authority, 6.75% Gas Facilities Revenue Bonds,
replacing $45,000,000 Series 1989A and $45,000,000 Series 1989B,
incorporated by reference from Form 10-K for the year ended
September 30, 1992.
First Supplemental Participation Agreement dated as of May 1, 1992
to Participation Agreement dated February 1, 1989 between the
New York State Energy Research and Development Authority and The
Brooklyn Union Gas Company relating to Adjustable Rate Gas
Facilities Revenue Bonds, Series 1989A & B, incorporated by
reference from 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 the New York State
Energy Research and Development Authority and Manufacturers
Hanover Trust Company, as Trustee, relating to Adjustable Rate
Gas Facilities Revenue Bonds, Series 1989A & B, incorporated by
reference from Form 10-K for the year ended September 30, 1992.
Official Statement, dated July 15, 1993, respective of
$25,000,000 of the New York State Energy Research and
Development Authority Gas Facilities Revenue Bonds Series D-1
and $25,000,000 of the New York State Energy Research and
Development Authority Gas Facilities Revenue Bonds Series D-2,
incorporated by reference from Form S-8 Registration Statement
No. 33-66182.
Participation Agreement, dated July 15, 1993, between the New York
State Energy Research and Development Authority and The Brooklyn
Union Gas Company relating to the Gas Facilities Revenue Bonds
Series D-1 1993 and Series D-2 1993, incorporated by reference
from Form S-8 Registration Statement No. 33-66182.
Indenture of Trust, dated July 15, 1993, between The New York State
Energy Research and Development Authority and Chemical Bank as
Trustee, relating to the Gas Facilities Revenue Bonds Series D-1
1993 and Series D-2 1993, incorporated by reference from Form
S-8 Registration Statement No. 33-60182.
<PAGE>
Official Statement, dated July 8, 1993, respective of $55,000,000
of the New York State Energy Research and Development Authority
Gas Facilities Revenue Bonds Series C, incorporated by reference
from Form 10-K for the year ended September 30, 1993.
First Supplemental Participation Agreement dated as of July 1, 1993
to Participation Agreement dated as of June 1, 1990, between the
New York State Energy Research and Development Authority and The
Brooklyn Union Gas Company relating to Gas Facilities Revenue
Bonds Series C, incorporated by reference from 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 the New
York State Energy Research and Development Authority and
Chemical Bank, as Trustee, relating to Gas Facilities Revenue
Bonds Series C, incorporated by reference from Form 10-K for the
year ended September 30, 1993.
Official Statement, dated January 15, 1996, respective of
$153,500,000 of the New York State Energy Research and
Development Authority, 5 1/2% Gas Facilities Revenue Bonds
Series 1996, replacing $98,500,000 Series 1985A and $55,000,000
Series 1985.
Participation Agreement, dated January 1, 1996, between the New
York Energy Research and Development Authority and The Brooklyn
Union Gas Company relating to the Gas Facilities Revenue Bonds
Series 1996.
Indenture of Trust, dated January 1, 1996, between The New York
State Energy Research and Development Authority and Chemical
Bank, as Trustee, relating to the Gas Facilities Revenue
Bonds Series 1996.
(10) Material contracts
Deferred Compensation Plan Preamble, dated, December 17, 1986,
incorporated by reference from Form 10-K for the year ended
September 30, 1987.
Corporate Incentive Compensation Plan Description,
incorporated by reference from Form 10-K for the year ended
September 30, 1989.
Marketing Incentive Compensation Plan Description,
incorporated by reference from Form 10-K for the year ended
September 30, 1989.
<PAGE>
Deferral Plan for Incentive Awards Description, incorporated
by reference from Form 10-K for the year ended September 30,
1989.
Agreement of Lease between Forest City Jay Street Associates and
The Brooklyn Union Gas Company dated September 15, 1988,
incorporated by reference from Form 10-K for the year ended
September 30, 1990.
Long-Term Performance Incentive Compensation Plan, dated November
15, 1995.
(11) Statement re: Computation of per share earnings. See Part
II, Item 8., "Financial Statements and Supplementary Data-
Consolidated Statement of Income for the Years Ended
September 30, 1995, 1994 and 1993," for information required
by this item.
(12) Statement re: Computation of consolidated ratio of earnings to
fixed charges
(21) Subsidiaries of the registrant
(23) Consents of experts
(27) Financial data schedule
(b) Reports on Form 8-K:
There were no reports filed on Form 8-K during the quarter ended
September 30, 1996.
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange
Act of 1934, this report has been signed by the following persons
on behalf of the registrant, and in the capacities indicated on
December 11, 1996.
THE BROOKLYN UNION GAS COMPANY
Signature Title
s/Robert B. Catell Chairman and Chief Executive
(Robert B. Catell) Officer
s/Craig G. Matthews President and Chief Operating
(Craig G. Matthews) Officer
s/Vincent D. Enright Senior Vice President and
(Vincent D. Enright) Chief Financial Officer
s/Richard M. Desmond Vice President, Comptroller
(Richard M. Desmond) and Chief Accounting
Officer
s/Kenneth I. Chenault Director
(Kenneth I. Chenault)
s/Andrea S. Christensen Director
(Andrea S. Christensen)
s/Donald H. Elliott Director
(Donald H. Elliott)
s/Alan H. Fishman Director
(Alan H. Fishman)
s/James L. Larocca Director
(James L. Larocca)
s/Edward D. Miller Director
(Edward D. Miller)
s/James Q. Riordan Director
(James Q. Riordan)
s/Charles Uribe Director
(Charles Uribe)
Exhibit 12
<TABLE>
THE BROOKLYN UNION GAS COMPANY AND SUBSIDIARIES
Computation of Consolidated Ratio of Earnings to Fixed Charges
Fiscal Year Ended September 30,
1996 1995 1994 1993 1992
_________ _________ _________ _________ _________
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Earnings
Net Income $ 122,908 $ 91,835 $ 87,384 $ 76,563 $ 59,873
Federal Income Tax 59,369 42,040 40,698 41,483 29,219
Interest on Long-Term Debt 46,803 47,939 48,084 46,353 40,990
Other Interest Charges 4,918 5,128 2,787 2,617 2,046
Portion of Rentals Representing
Interest 4,626 4,883 5,196 4,256 5,310
Adjustment Related to Equity
Investments (1,005) 174 (601) 729 3,239
Earnings Available to Cover --------- --------- --------- --------- ---------
Fixed Charges $ 237,619 $ 191,999 $ 183,548 $ 172,001 $ 140,677
========= ========= ========= ========= =========
Fixed Charges
Interest on Long-Term Debt* $ 50,067 $ 50,521 $ 49,280 $ 47,017 $ 41,766
Other Interest Charges 4,918 5,128 2,787 2,617 2,046
Portion of Rentals Representing
Interest 4,626 4,883 5,196 4,256 5,310
--------- --------- --------- --------- ---------
Total Fixed Charges $ 59,611 $ 60,532 $ 57,263 $ 53,890 $ 49,122
========= ========= ========= ========= =========
Ratio of Earnings to Fixed
Charges 3.99 3.17 3.21 3.19 2.86
========= ========= ========= ========= =========
* Includes capitalized interest of $3,264,000 in 1996, $2,582,000 in 1995, $1,196,000 in 1994
$664,000 in 1993 and $776,000 in 1992.
</TABLE>
Exhibit 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our report included in this Form 10-K into the
Company's previously filed Registration Statements Nos. 33-66182,
333-04863, 333-03441, 333-06257 and 333-18025.
ARTHUR ANDERSEN LLP
December 18, 1996
New York, New York
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000014525
<NAME> BROOKLYN UNION GAS CO.
<MULTIPLIER> 1
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> SEP-30-1996
<PERIOD-START> OCT-01-1995
<PERIOD-END> SEP-30-1996
<EXCHANGE-RATE> 1
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,352,964,000
<OTHER-PROPERTY-AND-INVEST> 460,683,000
<TOTAL-CURRENT-ASSETS> 353,883,000
<TOTAL-DEFERRED-CHARGES> 122,073,000
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,289,603,000
<COMMON> 16,619,000
<CAPITAL-SURPLUS-PAID-IN> 533,216,000
<RETAINED-EARNINGS> 355,973,000
<TOTAL-COMMON-STOCKHOLDERS-EQ> 905,808,000
0
6,600,000
<LONG-TERM-DEBT-NET> 712,013,000
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 0
300,000
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 664,882,000
<TOT-CAPITALIZATION-AND-LIAB> 2,289,603,000
<GROSS-OPERATING-REVENUE> 1,432,002,000
<INCOME-TAX-EXPENSE> 39,508,000
<OTHER-OPERATING-EXPENSES> 1,261,936,000
<TOTAL-OPERATING-EXPENSES> 1,301,444,000
<OPERATING-INCOME-LOSS> 130,558,000
<OTHER-INCOME-NET> 44,071,000
<INCOME-BEFORE-INTEREST-EXPEN> 174,629,000
<TOTAL-INTEREST-EXPENSE> 51,721,000
<NET-INCOME> 122,908,000
323,000
<EARNINGS-AVAILABLE-FOR-COMM> 122,585,000
<COMMON-STOCK-DIVIDENDS> 70,291,000
<TOTAL-INTEREST-ON-BONDS> 44,038,000
<CASH-FLOW-OPERATIONS> 202,367,000
<EPS-PRIMARY> 2.48
<EPS-DILUTED> 2.48
</TABLE>
