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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, 1994
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 (Zip Code)
offices)
Registrant's telephone number, including area code 718-403-2000
--------------
Securities registered pursuant to Section 12(b) of the Act:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON 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. (_)
Aggregate market value of registrant's voting Common Stock held by
non-affiliates as of December 14, 1994 was $1,056,832,706.
On December 14, 1994 the Company had 47,766,450 shares of Common Stock
Outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
DOCUMENTS PART OF FORM 10-K
Definitive Proxy Statement dated Part III
December 29, 1994
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PART I PAGE
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Item 1. Business
The Company 2
Subsidiaries 3
Gas Supply 5
Regulation and Rate Matters 7
Competition 8
Research and Development 9
Employees 9
Environmental Matters 9
Item 2. Properties 10
Item 3. Legal Proceedings 11
Item 4. Submission of Matters to a Vote of Security
Holders 11
PART II
- - ---------
Item 5. Market for the Registrant's Common Stock and
Related Security Holder Matters 11
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 24
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 & 52
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 65
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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, 1994, the Company had approximately 1,122,000
active meters, of which approximately 1,082,000 were residential. The Company is
subject to the regulatory jurisdiction of the New York State Public Service
Commission (PSC). The Company's executive offices are located at One MetroTech
Center, Brooklyn, New York 11201-3850. Its telephone number is (718)403-2000.
The Company's 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 incurred in the fourth quarter. The
effect on utility earnings of variations in revenues caused by abnormal weather
during the heating season is largely offset by the operation of a Weather
Normalization Adjustment contained in the Company's tariff (see Item 1.
"Business-Regulation and Rates"). Also, results of operations are affected by
the timing and amounts of approved rate changes.
The Company's customers generally are billed bi-monthly on a cycle basis in
therms. One therm equals 100,000 BTUs, the heat content of approximately 100
cubic feet of gas. The heat content of approximately 1,000,000 cubic feet of gas
represents 10,000 therms or 1 MDTH. Accordingly, one billion cubic feet (BCF) of
gas equals 1,000 MDTH.
For the fiscal year ended September 30, 1994, utility firm gas sales were
133,513 MDTH, of which 76% were residential, 13% commercial, 8% governmental and
3% industrial. In addition, 26,642 MDTH of gas was distributed to interruptible
sales customers within the Company's service territory under gas service tariffs
and to certain customers off-system under specified contract terms, and 15,750
MDTH of gas was transported for third parties pursuant to utility transportation
and balancing service tariffs.
2
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SUBSIDIARIES
The Company's principal wholly owned subsidiaries have operations in gas
exploration and production, and investments in gas cogeneration and pipeline
projects. In fiscal 1994, earnings from subsidiaries were $10.4 million, or 22
cents per share, representing 11.9% of consolidated earnings. For further
information regarding operating results of the subsidiaries, see Part II, Item
7. "Management's Discussion and Analysis of Financial Condition and Results of
Operations".
The PSC has approved an agreement that authorizes the Company to invest up
to 20% of its consolidated capitalization in energy-related businesses through
fiscal 1995. This authorization is based upon the Company's cash investments
less dividends received. At September 30, 1994, the total investment in
subsidiaries computed on this basis was approximately 13% of capitalization.
GAS EXPLORATION AND PRODUCTION
- - ------------------------------
Fuel Resources Inc. (FRI) is engaged in gas exploration, development,
production and marketing. FRI operates in the Arkoma Basin and, through its
subsidiaries, operates in the Gulf of Mexico, West Virginia, East Texas and
Canada. In 1994, FRI increased domestic production over last year from 23,000
MDTH to 24,000 MDTH and also increased its U.S. net gas reserve base from 112
BCF to 148 BCF. This was accomplished mainly through the acquisition of 35.9 BCF
of net proved reserves located in the Arkoma Basin and increased exploration
activity in the Gulf of Mexico region. Additionally, FRI owns working interests
in 180 wells in the Arkoma Basin.
The Houston Exploration Company (formerly Brooklyn Union Exploration
Company, Inc.), a wholly owned subsidiary of FRI, continued its drilling and
production operations offshore in the Gulf of Mexico. During the year, Houston
Exploration drilled fourteen wells, five of which were successful development
wells. The other nine were exploration wells, with six resulting in successful
finds.
Fuel Resources Production and Development Company, Inc. (FRPD), also an FRI
subsidiary, owns working interests in 650 wells in West Virginia and 20 wells in
East Texas. FRPD is also participating in several small, onshore projects in the
Gulf Coast region.
BRING Gas Services Corp. (formerly Brooklyn Interstate Natural Gas Corp.),
FRI's marketing subsidiary, sells gas produced by third parties as well as other
FRI affiliates and arranges related transportation services. It placed 640 MDTH
of gas per day for delivery in 1994, an increase of 38% over last year's
delivery of 463 MDTH per day.
In fiscal 1993, FRI took advantage of high gas prices in
3
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Canada and sold its Canadian gas operations, which generated an after-tax gain
of $12.5 million. Headquartered in Calgary, the newly formed Solex Energy
Company Inc. will continue FRI's presence in western Canada.
Investment in Energy Services
- - -----------------------------
Cogeneration
- - ------------
Gas Energy Inc. (GEI) and Gas Energy Cogeneration Inc. (GECI) participate
in the development, operation and ownership of cogeneration projects. A GEI
subsidiary is a 50% partner in developing a 100-megawatt facility at John F.
Kennedy International Airport in Queens, New York. The plant is expected to come
on line in 1995. In October 1993, GEI purchased an 11.3% interest in a 174-
megawatt gas cogeneration plant located in Lockport, New York. The plant began
operating in December 1992 and its major customers under long-term sales
agreements include a General Motors production facility and New York State
Electric & Gas Corporation. GECI is a 50% partner in developing a 40-megawatt
facility that will serve the State University of New York at Stony Brook, Long
Island. The plant is also scheduled to be on line in 1995. GECI also 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 plant has been available for operation better than 98% of the time since
being placed in service in 1989.
The scope of cogeneration activities also includes providing fuel-
management services. GEI subsidiaries provide such services to the Northrop
Grumman facility and to another 50-megawatt facility which provides heating and
cooling to Nassau Veterans Memorial Coliseum and Nassau Community College. In
1994, these subsidiaries, as fuel managers, delivered 7,000 MDTH of gas to
cogeneration projects.
Pipeline and Other
- - ------------------
North East Transmission Co., Inc. (NETCO) owns an 11.4% interest in the
Iroquois Gas Transmission System (Iroquois), a 375-mile pipeline, which supplies
gas to much of the Northeast and into the New York metropolitan area through its
southern terminus on Long Island. Iroquois currently transports more than 700
MDTH of Canadian gas supply daily to 25 Northeastern local distribution
companies and power generators. The Company currently receives up to 70 MDTH of
gas per day of this supply. For information regarding governmental
investigations of alleged environmental, civil and criminal violations involving
the Iroquois partnership, see Part II, Item 8., "Financial Statements and
Supplementary Data," Note 6., "Investments in Energy Services".
The Company has agreed to participate with ANR Pipeline Company and
TransCanada PipeLines Ltd. in developing the Mayflower Gas Transmission System,
a 200-mile pipeline planned to connect
4
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with Iroquois and serve markets from Eastern New York State to Boston,
Massachusetts. The Company and its partners have postponed their plan to build
the Liberty Pipeline, which, when built, will connect from New Jersey to Queens,
New York.
The Company is no longer involved in the propane business, which did not
strategically fit with the Company's natural gas businesses. At the beginning of
the year, it completed its exit strategy from Star Gas Corporation by selling
its remaining equity. Also, during the year, the Company ceased the operations
of Advanced Energy Options, Inc. which sold natural gas space and water heating
equipment to residential gas customers. The Company determined that normal
distribution channels and trade allies are more effective in serving this
market.
GAS SUPPLY
General
- - -------
Based on information currently available, the Company's anticipated gas
supply is sufficient to meet the requirements of present and new firm customers.
In recent years, the gas industry has been undergoing structural changes in
response to the Federal Energy Regulatory Commission's (FERC) policies to
increase competition. In 1992, FERC issued Order 636 which established policies
to make the gas industry more competitive by requiring interstate gas pipelines
to "unbundle" their gas sales service from other regulated tariff services, such
as transportation and storage. Anticipating and responding to such changes and
policy directives, the Company has modified its gas purchasing arrangements to
attain its objective of purchasing gas supply and related transportation service
at the lowest cost consistent with long-term security of supply.
As of November 1, 1993, all interstate gas pipelines serving the Company
had completed the unbundling of their gas sales services pursuant to Order 636.
Consequently, all "bundled" gas sales services previously provided by the
interstate pipelines to the Company were replaced by the pipelines with
"unbundled" firm transportation and storage services. Further, the Company
contracted directly with non-pipeline suppliers for firm gas supply under long-
term agreements to replace the gas supply previously provided by the interstate
pipelines.
In addition, the Company believes that gas from Canada is a secure, long-
term source of supply and has been an active participant in projects that seek
to increase the flow of Canadian gas to the Northeast. Further, when
economically and contractually advantageous, the Company purchases gas on the
spot market. In 1994, 64% of gas supply was purchased from domestic sources
under long-term contracts, 22% from Canadian sources under long-term contracts
and 14% from spot market sources.
5
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Taking advantage of opportunities arising under Order 636, the Company
opened the first New York-based market hub for buyers and sellers of natural gas
in the Northeastern United States in fiscal 1994. With interconnections and
access to six major pipelines, the New York Market Hub offers transportation,
balancing and exchange services to a wide variety of customers, including
utilities, municipalities, marketers and large-volume customers. In 1994, the
Company delivered 42,392 MDTH of gas and related services to customers in 14
states, with revenues benefiting both firm customers and shareholders, primarily
through the operation of the New York Market Hub.
Long-Term Supply
- - ----------------
Under long-term contracts and regulatory certificates applicable to
pipeline and storage capacity and services, the Company's suppliers will provide
maximum firm daily total deliveries of 965 MDTH of gas for the 1994-95 winter,
consisting of 376 MDTH per day of firm flowing domestic gas supply, 100 MDTH per
day of firm flowing Canadian gas supply and 489 MDTH per day of domestic storage
and winter services.
The Company's major providers of interstate pipeline capacity and related
services are: Transcontinental Gas PipeLine Corporation (Transco), Texas Eastern
Transmission Corporation (Texas Eastern), Tennessee Gas Pipeline Company
(Tennessee), and CNG Transmission Corporation (CNG) which provide "unbundled"
firm transportation and storage services. These pipelines are the conduit for
the delivery of domestic supplies purchased from natural gas sellers to the
Company's market. Total maximum daily domestic supplies are 865 MDTH of gas.
Canadian supplies include 70 MDTH of gas per day purchased from western
Canadian suppliers and marketers transported by Iroquois and 30 MDTH of gas per
day purchased from the Boundary Gas Project and transported by Tennessee.
Canadian gas is produced primarily in the Province of Alberta, and is
transported within Canada primarily by TransCanada PipeLines, Ltd.
By the beginning of fiscal 1994, pursuant to Order 636, the Company had
replaced its remaining gas sales services provided by Texas Eastern and CNG with
firm long-term supply purchased directly from non-pipeline suppliers. In 1994,
the Company added three new gas suppliers to its supply portfolio: it entered
into a long-term contract with Fina Natural Gas Company for 34 MDTH per day of
firm supply, contracted with ICC Energy Corporation for 5 MDTH per day of firm
long-term supply, and entered into an agreement for 5 MDTH per day with Moore
Energy. The Company also increased purchases of gas supply from Amerada Hess
Corporation by executing a second long-term firm agreement for 38 MDTH per day.
Further, the Company entered into a second contract with Mobil Natural Gas Inc.
for an additional 14 MDTH per day of firm long-term supply.
6
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Spot Market Supply
- - ------------------
The Company continues to purchase gas on the spot market when contractually
and economically feasible. In fiscal 1994, spot purchases totaled 24,271 MDTH of
gas.
Peak-day Supply
- - ---------------
The Company plans for peak-day demand on the basis of an average
temperature of 0/o/F. Gas demand on such a design peak-day is estimated at 1,112
MDTH during the 1994-95 winter. The highest actual 24-hour firm sendout by the
Company was 1,022 MDTH on January 19, 1994, when the average temperature was
4/o/F.
For the 1994-95 winter, the Company has the capability to provide a maximum
peak-day supply of approximately 1,256 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.
Gas Costs
- - ---------
The average cost of gas purchased for firm customers was $3.55 per DTH in
fiscal 1994, $3.49 per DTH in 1993 and $3.29 per DTH in 1992. Gas prices were
competitive with costs of most other energy sources including alternate grades
of fuel oil, although it was priced at some premium to No. 2 grade fuel oil.
Since October 1993, the Company has been using financial instruments to fix
margins on certain off-system sales, with the PSC's approval. The Company is
also authorized by the PSC to hedge on-system supply prices and to include all
of these hedging transactions as part of gas costs.
REGULATION AND RATE MATTERS
Retail sales, which include sales of gas, transportation and balancing
services by the Company, are made under rate schedules and tariffs filed with
and subject to the jurisdiction of the PSC. 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 from levels
included in base rates. Revenue requirements for ratemaking purposes are
established on the basis of firm sales projections assuming normal weather. Net
revenues (revenues less gas costs) from tariff sales for gas, transportation and
balancing services on an interruptible basis, as well as from off-system gas
sales, are refunded to firm customers through the Gas Adjustment Clause (GAC).
Service is provided to large-volume customers, principally in the multi-
family and commercial markets, under a temperature controlled (TC) rate that is
competitive with the price of
7
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alternate grades of fuel oil. These large volume customers use gas for space and
water heating under the TC rate, except that when the temperature falls below a
specified level, then oil, the alternate fuel is used. Service is provided to
the small apartment house market under a similar rate.
In October 1993, the Company began offering negotiated "customized" rates
to large volume customers both within and outside its service territory. In
October 1994, the PSC authorized more pricing flexibility to the Company in the
TC market and allowed the Company to retain 20% of net revenues from off-system
sales and transportation services in excess of $1.8 million per year. Further,
the PSC allowed the Company to utilize financial instruments to protect margins
on these sales. ( See Part II, Item 8., "Financial Statements and Supplementary
Data," Note 5., "Financial Instruments.")
The Company's tariff contains a Weather Normalization Adjustment that
permits recovery from firm heating customers of firm net revenue shortfalls due
to warmer-than-normal weather during a heating season. In a colder-than-normal
heating season, the Company is required to refund to these customers net
revenues from firm gas sales in excess of those which would have been realized
under normal weather conditions.
For information regarding the status of rate settlements and other
regulatory proceedings, see Part II, Item 7., "Management's Discussion and
Analysis of Financial Condition and Results of Operations - 'Rate and Regulatory
Matters' and 'Restructuring Proceeding'." 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 - Effects of
Rate Regulation'."
COMPETITION
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 competitive with alternate grades of fuel oil, although it was priced at
some premium to No. 2 grade fuel oil. Conversions from oil to gas heat continued
during fiscal 1994. Approximately 76% of one-and two-family homes in the
Company's service area now use gas for space heating.
The Company's share of the multi-family market is approximately 45%. In
this market, gas service under the TC rate is competitively priced with
alternate grades of fuel oil. As discussed under "Regulation and Rate Matters"
above, the PSC has authorized more pricing flexibility to the Company in this
market. 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.
8
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The Company believes that there are promising new markets for use of
natural gas as a vehicle fuel as well as in cogeneration, air conditioning and
refrigeration applications.
The trend in rate regulation reflects movement from traditional cost-based
pricing towards market pricing, with added emphasis on price caps and wider use
of incentives. The Company continues to be committed to cost reduction efforts,
which include workforce reductions, achieved through normal attrition and
special early retirement programs, tax reduction efforts, advanced construction
methods and use of state-of-the-art computer technology. The Company is unique
among investor-owned utilities in that all of its outstanding long-term debt
used to finance utility plant additions is tax-exempt.
RESEARCH AND DEVELOPMENT
In fiscal 1994, the Company spent $11.9 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 $2.6 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 $6.9 million was devoted primarily to the Company's internal
R&D programs relating to efficient gas utilization and operations technologies.
These programs include the gas heat pump, fuel cells, new technologies to reduce
meter reading costs and vehicles powered by compressed natural gas. The Company
is demonstrating the feasibility of natural gas as a fuel well suited for mass
transit buses and fleet vehicles.
This year the Company and the gas industry brought to market the YORK
Triathlon heating and cooling system which can provide up to 30% lower operating
costs than conventional equipment used by commercial customers.
EMPLOYEES
The Company and its subsidiaries employed 3,506 people at September 30,
1994, compared to 3,711 at September 30, 1993. The decrease reflects normal
workforce reductions and the effect of a special early retirement program.
Three-year labor agreements with unions representing approximately 2,200
employees were signed in 1992. These agreements provide annual wage increases of
4.25% in each of the first two years and 4.5% in the third year.
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 7., "Environmental Matters."
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ITEM 2. PROPERTIES
- - ------------------
In fiscal 1994, consolidated capital expenditures were $199.6 million, of
which $103.8 million was primarily for utility property additions and $95.8
million was for subsidiaries. Consolidated capital expenditures are estimated to
be approximately $185 million for each of fiscal years 1995 and 1996.
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. Upon expiration, the fee payable to New York City for
such franchise is subject to redetermination. Gas sales revenues in the former
Fifth Ward are approximately 2.5% of the total gas sales revenues of the
Company.
As of September 30, 1994, the Company's distribution pipeline system
consisted of approximately 2,028 miles of cast iron main, 1,679 miles of steel
main and 230 miles of mains with plastic inserts, with requisite accessory
compressor and regulating stations, and two gas storage holders having a
capacity of 29 MDTH. The distribution system for the most part is located under
public streets.
The Company owns and operates an 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 has 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 17 years and
renewal options. The Company owns or leases certain other buildings and
facilities for use in the conduct of its business. The Company's gross lease
payments are approximately $14.2 million per year.
Principal consolidated properties of subsidiaries and their affiliates
include gas and oil leasehold interests, producing wells and related equipment.
For information required by this item concerning the gas and oil
exploration, development and producing activities of the Company's subsidiaries,
see "Part II, Item 8., "Financial
10
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Statements and Supplementary Data -Supplemental Gas and Oil Disclosures."
ITEM 3. LEGAL PROCEEDINGS
- - ---------------------------
For information regarding governmental investigations of alleged
environmental, civil and criminal violations involving Iroquois, see Part II,
Item 8., "Financial Statements and Supplementary Data," Note 6., "Investments in
Energy Services." 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 7.,
"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 4., "Capitalization."
STOCK LISTINGS
The Company's common stock and preferred stock are traded on the New York
Stock Exchange under the trading symbol BU. Daily stock reports are carried by
most major newspapers under the headings BklyUnGas for the common stock and BkUG
for the preferred stock.
DIVIDENDS
Quarterly dividends on common stock, are 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.
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 2, 1995.
11
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BOND AND PREFERRED STOCK RATINGS
Gas Facilities Revenue Bonds (Unsecured)
- - -Moody's A-1
- - -Standard & Poor's A
Preferred Stock
- - -Moody's A-2
- - -Standard & Poor's A
TRANSFER AGENT AND REGISTRAR OF STOCK
First Chicago Trust Company of New York
P.O. Box 2500
Jersey City, N.J. 07303-2500
(201)324-0498
INDEPENDENT PUBLIC ACCOUNTANTS
Arthur Andersen LLP
1345 Avenue of the Americas
New York, NY 10105
(212)708-4000
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QUARTERLY INFORMATION (UNAUDITED)
SUMMARY OF QUARTERLY INFORMATION
The following is a table of financial data for each quarter of fiscal 1994 and
1993. 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>
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First Second Third Fourth
Quarter Quarter Quarter Quarter
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(Thousands of Dollars Except Per Share Data)
<S> <C> <C> <C> <C>
1994
Operating revenues 371,478 548,970 240,661 177,521
Operating income(loss) 53,125 83,561 4,085 (6,467)
Income (loss) applicable
to common stock 42,073 73,465 (7,690) (20,815)
Per common share:
Earnings (loss) (a) 0.90 1.57 (0.16) (0.44)
Dividends declared 0.3375 0.3375 0.3375 0.3375
- - -----------------------------------------------------------------------------------------------------------------------------------
1993
Operating revenues 347,283 489,367 208,531 160,323
Operating income(loss) 49,412 84,728 6,723 (17,763)
Income (loss) applicable
to common stock 40,434 71,737 (6,744) (29,228)(b)
Per common share:
Earnings (loss) (a) 0.93 1.63 (0.15) (0.66)
Dividends declared 0.33 0.33 0.33 0.33
===================================================================================================================================
(a) 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.
(b) Includes an after-tax gain of $12.5 million on the sale of a subsidiary's
investment in a Canadian gas company and the write-off a subsidiary's
investment in a propane company, an after-tax charge of $11.5 million.
===================================================================================================================================
</TABLE>
SUMMARY OF QUARTERLY COMMON STOCK INFORMATION
<TABLE>
<CAPTION>
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First Second Third Fourth
Quarter Quarter Quarter Quarter
===================================================================================================================================
<S> <C> <C> <C> <C>
1994
High 27 1/2 28 7/8 25 1/8 25 3/4
Low 24 7/8 23 22 1/8 23 1/2
Close 27 3/8 23 3/4 24 3/8 24 7/8
Shares Traded (000) 3,978 2,542 2,206 1,931
- - -----------------------------------------------------------------------------------------------------------------------------------
1993
High 22 3/4 27 3/8 27 3/4 27 7/8
Low 21 3/8 21 1/2 24 5/8 25 1/2
Close 22 3/8 27 27 1/2 25 3/4
Shares Traded (000) 1,769 1,804 1,860 3,309
===================================================================================================================================
</TABLE>
13
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
- - ----------------------------------------------------------------------------------------------------------------------------------
For Years Ended September 30, 1994 1993 1992 1991 1990
- - ----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars Except Per Share Data)
<S> <C> <C> <C> <C> <C>
INCOME SUMMARY
Operating revenues
Utility sales $1,279,638 $1,145,315 $1,038,061 $951,711 $ 944,295
Gas production and other 58,992 60,189 36,799 25,550 49,564
- - ----------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 1,338,630 1,205,504 1,074,860 977,261 993,859
Operating expenses
Cost of gas 560,657 466,573 402,137 373,048 406,439
Operation and maintenance 381,696 363,792 333,984 302,171 299,611
Depreciation and depletion 69,611 64,779 73,930 42,644 48,644
General taxes 150,743 144,827 135,549 136,245 126,928
Federal income tax 41,619 42,433 30,812 27,017 18,969
- - ----------------------------------------------------------------------------------------------------------------------------------
Operating income 134,304 123,100 98,448 96,136 93,268
Income (loss) from energy services investments 5,689 1,150 (1,041) 136 229
Other, net (2,338) (3,379) 2,935 2,949 5,953
Gain on sale of investment in Canadian gas company - 20,462 - - -
Write-off of investment in propane company - (17,617) - - -
Federal income tax benefit 921 950 1593 3050 2087
Interest charges 51,192 48,103 42,062 40,462 45,101
- - ----------------------------------------------------------------------------------------------------------------------------------
Net income 87,384 76,563 59,873 61,809 56,436
Dividends on preferred stock 351 364 2,078 3,847 3,922
- - ----------------------------------------------------------------------------------------------------------------------------------
Income available for common stock 87,033 76,199 57,795 57,962 52,514
==================================================================================================================================
FINANCIAL SUMMARY
Common stock information
Per share
Earnings ($) 1.85 1.73 1.35 1.45 1.43
Cash dividends declared ($) 1.35 1.32 1.29 1.27 1.23
Book value, year-end ($) 16.27 15.55 14.56 14.37 13.69
Market value, year-end ($) 24 7/8 25 3/4 22 3/8 20 5/8 18 7/8
Average shares outstanding (000) 46,980 44,042 42,882 39,894 36,798
Shareholders of record 35,233 30,925 31,367 30,749 31,230
Daily average shares traded 42,100 33,100 26,900 30,500 20,700
Capital expenditures ($) 199,572 204,514 173,467 147,745 134,458
Total assets ($) 2,029,074 1,897,847 1,748,027 1,717,493 1,460,728
Common equity ($) 774,236 721,076 632,254 607,573 510,489
Preferred stock, redeemable ($) 7,200 7,500 7,800 44,467 45,389
Long-term debt ($) 701,377 689,300 682,031 685,413 534,093
Total capitalization ($) 1,482,813 1,417,876 1,322,085 1,337,453 1,089,971
Earnings to fixed charges (times) 3.21 3.19 2.86 2.95 2.47
==================================================================================================================================
UTILITY OPERATING STATISTICS
Gas data (MDTH)
Firm sales 133,513 128,972 122,476 108,694 114,300
Other gas sales and transportation 42,392 25,032 23,706 15,963 11,726
Maximum daily capacity, year-end 1,256 1,258 1,199 1,179 1,129
Maximum daily send out 1,022 915 904 837 855
Total active meters (000) 1,122 1,119 1,117 1,111 1,106
Heating customers (000) 446 441 436 428 419
Degree days (normal 4,824;leap year 4,851) 4,974 4,802 4,659 3,971 4,614
Colder (Warmer) than normal (%) 3.1 - (4.0) (19.0) (5.8)
==================================================================================================================================
</TABLE>
14
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
-----------------------------------------------------------
CONDITION AND RESULTS OF OPERATIONS
-----------------------------------
EARNINGS AND DIVIDENDS
In fiscal 1994, consolidated income available for common stock was
$87.0 million, or $1.85 per share, a record, compared to $76.2 million, or
$1.73 per share, in 1993, and $57.8 million, or $1.35 per share, in 1992.
Consolidated earnings, including income from equity investments, for
the last three fiscal years are summarized below:
<TABLE>
<CAPTION>
- - --------------------------------------------------------------------------------
1994 1993 1992
- - --------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
INCOME AVAILABLE FOR COMMON STOCK
UTILITY $76,665 $ 69,083 $ 68,365
- - --------------------------------------------------------------------------------
GAS EXPLORATION AND PRODUCTION
OPERATIONS
DOMESTIC 5,707 2,707 2,485
CANADIAN - 2,739 840
GAIN (IMPAIRMENT) - 12,500 (13,000)
- - --------------------------------------------------------------------------------
5,707 17,946 (9,675)
- - --------------------------------------------------------------------------------
ENERGY SERVICES
PIPELINE AND OTHER 3,358 2,792 2,127
COGENERATION 1,303 907 644
PROPANE
OPERATIONS - ( 3,078) (3,666)
WRITE-OFF - (11,451) -
- - --------------------------------------------------------------------------------
4,661 (10,830) ( 895)
- - --------------------------------------------------------------------------------
CONSOLIDATED $87,033 $ 76,199 $ 57,795
- - --------------------------------------------------------------------------------
</TABLE>
In 1994, utility operations provided an equity return of 12.2%. The
return, which included incentives authorized by the State of New York Public
Service Commission (PSC), was slightly higher than the allowed rate of
12.1%. The Company has earned or exceeded its allowed return on utility
common equity in 15 of the last 16 years.
In the last three years, income available for common stock from utility
operations has benefited from rate increases (see "Rate and Regulatory
Matters"), additions of new firm gas heating
15
<PAGE>
customers, primarily as a result of converting homes and buildings from oil to
gas for space heating, and the benefit of certain ratemaking incentives. The
effect on utility revenues of variations due to colder- or warmer-than-normal
weather during the heating season is largely offset by the weather normalization
adjustment included in the Company's tariff. In 1994, utility earnings reflected
higher operation expense due to the extremely cold weather last winter. However,
cost management strategies employed throughout the year were able to offset
substantially the adverse effects of the cold weather.
In 1994, earnings from gas exploration and production operations increased
primarily due to higher U.S. production and higher average prices. Earnings from
gas exploration and production in 1993 included an after tax gain of $12.5
million on the sale of a subsidiary's investment in a Canadian gas exploration
and production company. This sale is the reason no earnings resulted from
Canadian operations in 1994; however, the Company intends to again conduct
Canadian operations in fiscal 1995. Earnings in 1992 included a non-cash ceiling
test impairment charge of $13.0 million after Federal income taxes recorded to
reflect the effect of low natural gas prices in March 1992 on a subsidiary's
valuation of proved gas reserves.
Earnings from investments in energy services are attributable to a number
of factors. The increase in earnings from pipeline and other reflects in part
higher throughput by the Iroquois Gas Transmission System during its second full
year of operation. The increase in cogeneration earnings reflects equity income
arising from the acquisition of an interest in an operating cogeneration plant,
located in Lockport, N.Y., as well as higher income from the investment in a
similar plant serving a Northrop Grumman facility, and continued profitable
operations from the Company's fuel management subsidiaries. Further, earnings
from investments in energy services increased as the Company did not incur any
losses in 1994 related to its former investment in a propane company as it had
in 1993 and 1992.
The consolidated rate of return on average common equity was 11.04% in
1994, compared to 10.85% in 1993 and 8.74% in 1992.
In December 1993, the Board of Directors authorized an increase in the
annual dividend on common stock to $1.35 per share from $1.32 per share,
reflecting the three-for-two stock split approved in June 1993. This increase
became effective on February 1, 1994, when the quarterly dividend was raised to
33 3/4 cents per share from 33 cents per share. Common dividends have been
increased for 18 consecutive years and paid continuously for 46 years.
16
<PAGE>
<TABLE>
<CAPTION>
SALES, GAS COSTS AND NET REVENUES
- - --------------------------------------------------------------------------------
1994 1993 1992
- - --------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Utility sales $1,279,638 $1,145,315 $1,038,061
Cost of gas (560,657) (466,573) (402,137)
- - --------------------------------------------------------------------------------
Net revenues $ 718,981 $ 678,742 $ 635,924
- - --------------------------------------------------------------------------------
Gas production
and other $ 58,992 $ 60,189 $ 36,799
- - --------------------------------------------------------------------------------
</TABLE>
Firm utility gas sales in fiscal 1994 were 133,513 MDTH compared to 128,972
MDTH in 1993 and 122,476 MDTH in 1992. Measured by annual degree days, weather
was 3.1% colder than normal in 1994, and in 1993 and 1992, it was normal and
4.0% warmer than normal, respectively. In 1994, firm sales normalized for
weather increased at a rate slightly below the increases in the prior two fiscal
years. Sales growth in all markets resulted primarily from conversions to
natural gas from oil for space heating, especially by large apartment buildings.
During the year, gas at the burner tip was competitive with alternative grades
of fuel oil, although it was priced at some premium to No. 2 grade fuel oil.
Residential heating sales in markets where the competing fuel is No. 2
grade fuel oil and sales to other small volume customers were approximately 80%
of firm sales in fiscal 1994. Demand in these markets is less sensitive to
periodic differences between gas and oil prices.
In large volume heating markets, where the competing fuel is No. 6 grade
fuel oil, gas service is provided under rates that competitively track the price
of that fuel. There is substantial sales potential in these markets, which
include large apartment houses, government buildings and schools.
Moreover, a significant market for off-system sales has developed as a
result of Federal Energy Regulatory Commission initiatives. In 1994, the Company
delivered 42.4 BCF of gas to off-system and interruptible customers by making
optimal use of interstate pipeline capacity and its New York-based market hub.
The benefit of these transactions is passed on to firm customers pursuant to the
Company's tariff.
The cost of gas, $560.7 million in 1994, was $94.1 million or 20.2% higher
than in 1993. This is the result of higher heating sales as weather was colder
than normal during the 1994 heating season, and higher off-system sales. The
cost of gas for firm customers was $3.55 per DTH (one DTH equals 10 therms) in
1994, compared to $3.49 per DTH in 1993 and $3.29 per DTH in 1992.
17
<PAGE>
Net revenues (utility operating revenues less cost of gas) of $719.0
million in 1994 and $678.7 million in 1993 reflect increased tariff revenues and
weather normalized firm sales growth in each year.
The decrease in revenues from gas production and other in 1994 is due to
the sale of the Canadian gas exploration and production operations at the end of
1993. Revenues from U.S. production were up significantly, reflecting higher
production and average prices. (See Part II, Item 8., "Financial Statements and
Supplementary Data - Supplemental Gas and Oil Disclosures.") The increase in
prior years' revenues was the result of higher production volumes.
EXPENSES AND PREFERRED DIVIDENDS
Increases in operation expense in 1994 reflect the effects of severe winter
conditions. Maintenance expense includes costs related to city and state
construction projects. Such costs are partially reimbursed by New York City.
Expenses in all years reflect generally higher labor and material costs, which
were offset in part by ongoing productivity savings.
The increase in depreciation and depletion expense in 1994 primarily
reflects charges related to utility property additions and increased U.S. gas
production from the Company's exploration and production operations. In 1992,
depreciation and depletion expense included a pre-tax impairment charge of $19.7
million recorded by the Company's gas exploration and production subsidiary to
reduce the value of its proved gas reserves in accordance with the Securities
and Exchange Commission's asset ceiling test limitations applicable to gas
exploration and production operations accounted for under the full cost method.
General taxes principally include state and city taxes on utility revenues
and property. The applicable tax rates and the property base generally have
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 increase in utility revenues each year.
Federal income tax expense reflects changes in pre-tax income and the
increase in the corporate tax rate that occurred in 1993. Also, the Company
adopted Statement of Financial Accounting Standards No. 109, "Accounting for
Income Taxes" (SFAS-109) in 1994. Adoption of SFAS-109 had no effect on net
income. (See Part II, Item 8., "Financial Statements and Supplementary Data,"
Note 1. "Federal Income Tax.")
Interest charges on long-term debt generally reflect higher average levels
of debt and the conversion of variable rate bonds to fixed interest rates. Other
interest charges include interest on deferred regulatory items.
Dividends on preferred stock reflect the Company's redemption
18
<PAGE>
of three series of preferred stock on April 1, 1992 at optional redemption
prices. Call premiums are being amortized pursuant to PSC authorization. (See
Part II, Item 8., "Financial Statements and Supplementary Data," Note 4A.,
"Capitalization -Common and Preferred Stock.")
CAPITAL EXPENDITURES
Consolidated capital expenditures were $199.6 million in fiscal 1994,
$204.5 million in fiscal 1993 and $173.5 million in 1992.
Capital expenditures related to utility operations were $103.8 million in
1994, $110.8 million in 1993 and $113.8 million in 1992. Utility expenditures in
all years principally were for the renewal and replacement of mains and
services. Plant additions to serve new customers and develop new markets were
$28.8 million in 1994, compared to $24.9 million in 1993 and $31.7 million in
1992.
Capital expenditures related to gas exploration and production activities
were $71.3 million in 1994, compared to $66.3 million in 1993 and $41.9 million
in 1992. The 1994 amount reflects several on-shore acquisitions and increased
off-shore exploration activities. Net proved gas reserves at September 30, 1994
were 148 billion cubic feet. These reserves are located off-shore in the Gulf of
Mexico and on-shore in the Arkoma Basin, East Texas and West Virginia.
Capital expenditures related to energy services were $24.5 million in 1994,
$27.4 million in 1993 and $17.7 million in 1992. Expenditures in all years were
primarily related to the development of the John F. Kennedy International
Airport cogeneration project and in 1994 include $10.9 million related to the
acquisition of an interest in an operating cogeneration plant located in
Lockport, N.Y.
Consolidated capital expenditures for fiscal years 1995 and 1996 are
estimated to be approximately $185 million in each year, including $75 million
per year related to non-utility activities. The level of such expenditures is
reviewed periodically and can be affected by the timing and scope of investment
opportunities. The PSC has authorized the Company to invest up to 20% of its
consolidated capitalization in non-utility energy-related businesses. This
authorization is based on the Company's cash investments less dividends
received. At September 30, 1994, the total investment in non-utility
subsidiaries computed on this basis was approximately 13% of capitalization.
FINANCING
Cash provided by operating activities continues to be strong and is the
principal source for financing capital expenditures.
19
<PAGE>
The Company issued 1,800,000 new shares of common stock on October 6, 1993,
providing net proceeds of $44.9 million. Proceeds from common stock issued
through employee and shareholder stock purchase plans have provided the Company
approximately $29.8 million in 1994, $27 million in 1993 and $23 million in
1992.
In 1993, the Company converted $55 million of Series C Variable Rate Gas
Facilities Revenue Bonds to a fixed rate of 5.60% and $50 million of Series D
Variable Rate Gas Facilities Revenue Bonds to a fixed rate equivalent of 5.635%.
In addition, $75 million of 9 1/8% Gas Facilities Revenue Bonds were refunded in
1993. The interest rate on the refunding bonds, which mature in 2020, is 6.368%.
Increased borrowings by a subsidiary, included in long-term debt, provided an
additional $12.1 million to finance capital expenditures.
As a result of bond refinancings and redemptions of preferred stock, the
Company's composite cost of capital is the lowest in decades. At September 30,
1994, the consolidated annualized cost of long-term debt was 6.9%. Depending on
market conditions, the Company expects to be able to issue additional tax-exempt
debt in 1995 in either fixed or variable rate form in conjunction with the
possible refunding of the Company's 9% and 8.75% Gas Facilities Revenue Bonds
which are callable in May 1995 and July 1995, respectively, at optional
redemption prices of $102.
FINANCIAL FLEXIBILITY AND LIQUIDITY
At September 30, 1994, the Company had cash and temporary cash investments
of $53.5 million and available bank lines of credit of $100 million, which lines
are available to secure the issuance of commercial paper. Related borrowings
primarily are used to finance seasonal working capital requirements, which in
recent years have not been significant. At September 30, 1994, there were no
borrowings outstanding. In addition, subsidiaries have lines of credit of $71
million, which for the most part support borrowings under revolving loan
agreements.
At September 30, 1994, the common equity component of the Company's
capitalization was 52.2%.
Fixed charge coverage ratios were 3.21 times in fiscal 1994, 3.19 in 1993
and 2.86 in 1992 (3.27 excluding the ceiling test impairment charge in March
1992 due to low wellhead gas prices).
The Company's Gas Facilities Revenue Bonds continue to be rated A-1 by
Moody's and A by Standard & Poor's, and the series of preferred stock still
outstanding is rated A-2 by Moody's and A by Standard & Poor's. The Company's
commercial paper is rated Prime-1 by Moody's and A-1 by Standard & Poor's.
20
<PAGE>
RATE AND REGULATORY MATTERS
In September 1993, the PSC approved a revenue increase of $31.3 million,
including $3.0 million of deferred credits, which became effective in fiscal
1994, the final year of a three-year rate settlement. Previously, the PSC had
approved $31.5 million of additional revenues for fiscal 1993 and $31.3 million
for fiscal 1992.
In October 1994, the PSC approved a new three-year rate settlement. The
agreement allows an 11.0% return on common equity devoted to utility operations
in fiscal 1995, the first year of the new three-year rate plan. The allowed
return will be adjusted in each of the last two years of the plan to reflect
changes in capital costs. The settlement agreement provides for several discrete
incentives in customer service and sales, and affords the Company substantial
additional pricing flexibility in price elastic markets. Under the agreement,
the Company will be permitted to retain 100% of any earnings from incentives (up
to 100 basis points on utility equity) and further will be permitted to retain
75% of the first 100 basis points of earnings unrelated to discrete incentives
in excess of its allowed return, and 50% of any additional earnings above that
level.
The agreement provides for no rate increase in fiscal 1995; however, the
Company is permitted to amortize to income approximately $1.3 million of
previously deferred credits. Estimated rate increases of $17 million in each of
fiscal years 1996 and 1997 may be partially offset through the use of additional
available deferred credits.
Moreover, the settlement includes a revenue reduction for a "royalty" based
on the Company's level of investment in unregulated activities. In fiscal 1995,
the royalty is .75% of the capitalization of the Company's unregulated
subsidiaries, and will decline to .30% in fiscal 1997, the last year of the
agreement. The "royalty" will not have a material impact on earnings.
Additionally, as part of the settlement, the Company agreed to a plan to
separate utility and subsidiary operations further, and to change the names of
two of its subsidiaries.
RESTRUCTURING PROCEEDING
The PSC has instituted a generic proceeding to determine whether and how to
adjust services provided by gas utilities in the State of New York so that a
wider range of consumers have access to "unbundled" services envisioned by
Federal Energy Regulatory Commission Order 636. Order 636 requires interstate
pipelines to "unbundle" or separate their sales service from their
transportation and storage services. As a result, the responsibility for
procuring gas supplies and managing their deliveries to the "city gate" was
shifted to local distribution companies such as the Company. Order 636 also
allows producers and
21
<PAGE>
gas marketers to negotiate directly for sales to customers currently supplied by
local utilities, and allows these customers to arrange transportation for their
gas supplies, thereby broadening opportunities for gas users to purchase gas
from multiple sources.
The issues for utilities in the PSC proceeding are far-reaching, including
greater flexibility in pricing, competition with brokers/marketers in a
utility's service area, cost of service allocations, and obligations to provide
service to core (small volume) and non-core (interruptible and large volume)
markets.
The Company believes it is prepared to meet the challenges of additional
competition in its traditional service territory and to take advantage of new
opportunities for off-system sales growth. As early as 1984, the Company began
restructuring its gas purchase contracts with pipelines to transportation-only
contracts, and securing additional competitively priced long-term domestic gas
supplies from major non-pipeline suppliers, and further diversifying its supply
portfolio by importing gas from Canada. The Company is unable to determine at
this time how regulatory changes resulting from the PSC proceeding will impact
future operations.
ENVIRONMENTAL MATTERS
The Company is subject to Federal, state, and local laws and regulatory
programs relating 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 are integrated with the
Company's regular operations and maintenance activities. Based upon current
information and regulatory status, no material increases or changes are
anticipated for the Company's ongoing environmental compliance efforts.
The Company may be deemed to be liable for environmental cleanup expenses
with respect to properties or facilities that have sustained historical
contamination, in particular those properties or facilities that supported
manufactured gas plant (MGP) operations or otherwise utilized underground
storage tanks.
The Company has reviewed its current and historical properties and
identified fourteen MGP sites and certain other industrial properties which may
have sustained historical contamination. Of these properties, four MGP sites are
undergoing various stages of preliminary investigations and/or discussions with
regulatory agencies or third parties. Of the four properties being addressed,
based upon current information and regulatory status, three of the properties
are not expected to present material liabilities. The fourth property, the Coney
Island site, may result in material cleanup liabilities in the future. As at
September 30, 1994, the
22
<PAGE>
Company accrued $8.0 million for potential cleanup costs at this site and
recorded a corresponding regulatory asset. Previously, the Company had accrued
$4.1 million for interim response costs which were fully paid by September 30,
1994. (See Part II, Item 8., "Financial Statements and Supplementary Data," Note
7., "Environmental Matters.")
In October 1994, 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, including the $4.1 million in interim response
costs accrued in 1993 and the $8.0 million liability accrued as at September 30,
1994. In addition, as part of its October 1994 order approving the Company's
three year rate settlement, the PSC approved the deferral of environmental site
investigation and remediation costs incurred after September 30, 1994. Pursuant
to that order, rates commencing in October 1994 reflect the recovery of the $4.1
million deferred interim response costs over a five year period, and the Company
may reflect in rates commencing October 1995 and October 1996, the deferred
balance of environmental site investigation and remediation costs accrued as at
September 30, 1994 and September 30, 1995, respectively, each over a five year
period. The recovery of these costs in rates is conditioned upon the absence of
a PSC determination that such costs have been unreasonable or imprudently
incurred. In general, the Company believes that, based on applicable law and
prior PSC precedents with respect to similar expenditures incurred by other
utilities in New York State, the Company will be permitted to recover its
prudently incurred environmental site investigation and remediation costs in
rates.
INFLATION
In recent years, the impact of inflation has diminished. Purchased gas
costs, which have been relatively stable, are passed on to customers through the
Gas Adjustment Clause in the Company's tariff. Gas remains competitively priced
with alternative fuels. Recovery of the cost of utility property is based on
historical cost depreciation charges that are included in utility rates. Such
charges are less than current costs or inflation-adjusted costs. However, the
Company believes its utility rates generally provide an opportunity to earn a
fair return on shareholder investment reflective of its cost of capital and,
therefore, maintain access to capital markets in order to finance property
additions and replacements.
23
<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.
24
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of
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, 1994 and 1993, and
the related Consolidated Statements of Income, Retained Earnings and Cash Flows
for each of the three years in the period ended September 30, 1994. 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, 1994 and 1993,
and the results of their operations and their cash flows for each of the three
years in the period ended September 30, 1994 in conformity with generally
accepted accounting principles.
As discussed in Notes 1 and 2 to the Consolidated Financial Statements the
Company changed its method of accounting for income taxes and postretirement
benefits effective as of October 1, 1993.
Our audits were made for the purpose of forming an opinion on the basic
consolidated financial statements taken as a whole. The schedules listed in Item
14 are the responsibility of the Company's management and are presented for
purposes of complying with the Securities and Exchange Commission's rules and
are not part of the basic consolidated financial statements. These schedules
have been subjected to the auditing procedures applied in the audits of the
basic consolidated financial statements and, in our opinion, fairly state 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 26, 1994
New York, New York
25
<PAGE>
SUMMARY OF SIGNIFICANT
ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The Consolidated Financial Statements reflect the accounts of the Company and
its subsidiaries. All significant intercompany transactions are eliminated.
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 3.3% in 1994, and 3.2% in
1993 and 1992.
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 subsidiaries follow 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 unit-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 property 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 fifteen years.
INVESTMENTS IN ENERGY SERVICES
Certain subsidiaries own as their principal asset investments in energy-related
businesses that are accounted for under the equity method.
REVENUES
Utility customers generally are billed bi-monthly on a cycle basis. Unbilled
revenue reflects the estimated gas usage that occurred from the last meter
reading to the end of each month.
26
<PAGE>
Revenue requirements to establish utility rates are based on sales to firm
customers. Changes in gas costs from amounts recovered in base tariff rates are
included in billed firm revenues through the operation of a tariff provision,
the Gas Adjustment Clause (GAC). Net revenues from tariff sales for gas and
transportation service on an interruptible basis as well as from off-system gas
sales and tariff gas balancing services are refunded to firm customers through
the GAC. This 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.
The Company's tariff contains a weather normalization adjustment that
provides for recovery from or refund to firm customers of shortfalls or excesses
of firm net revenues during a heating season due to variations from normal
weather, which is the basis for projecting base tariff revenue requirements.
Gas sales by the Company's marketing subsidiary are classified in gas
production and other revenue net of their related gas purchase and
transportation costs.
FEDERAL INCOME TAX
The Company adopted Statement of Financial Accounting Standards No. 109 (SFAS-
109) "Accounting for Income Taxes" at the beginning of fiscal 1994. 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. Prior to adoption of
SFAS-109, 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 depreciation methods. An amortization of
the regulatory asset is included in operation expense commencing in 1994 while
amounts comparable to this amortization previously were included as part of
Federal income tax expense.
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.
EFFECTS OF RATE REGULATION
Allocation of costs and revenues to accounting periods for ratemaking and
regulatory purposes may differ from bases generally applied by nonregulated
companies. Such allocations to meet regulatory accounting requirements are
considered to be generally accepted accounting principles for regulated
utilities provided that there is a demonstrable ability to recover any deferred
costs in future rates. Otherwise, such
27
<PAGE>
deferred costs, or regulatory assets, would have to be expensed. The Company has
recorded a net regulatory asset of $95.2 million as of September 30, 1994. This
asset is largely related to differences in allocating Federal income tax
expense.
28
<PAGE>
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
========================================================================================================
For the Years Ended September 30, 1994 1993 1992
========================================================================================================
(Thousands of Dollars)
<S> <C> <C> <C>
OPERATING REVENUES
Utility sales $ 1,279,638 $ 1,145,315 $ 1,038,061
Gas production and other 58,992 60,189 36,799
- - --------------------------------------------------------------------------------------------------------
1,338,630 1,205,504 1,074,860
- - --------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas 560,657 466,573 402,137
Operation 327,356 309,070 281,031
Maintenance 54,340 54,722 52,953
Depreciation and depletion 69,611 64,779 73,930
General taxes 150,743 144,827 135,549
Federal income tax (See Note 1) 41,619 42,433 30,812
- - --------------------------------------------------------------------------------------------------------
OPERATING INCOME 134,304 123,100 98,448
OTHER INCOME
Equity income (loss) from energy services investments 5,689 1,150 (1,041)
Other income (loss), net (2,338) (3,379) 2,935
Gain on sale of investment in Canadian gas company - 20,462 -
Write-off of investment in propane company - (17,617) -
Federal income tax benefit (See Note 1) 921 950 1,593
- - --------------------------------------------------------------------------------------------------------
INCOME BEFORE INTEREST CHARGES 138,576 124,666 101,935
INTEREST CHARGES
Long-term debt 46,900 45,344 40,016
Other 4,292 2,759 2,046
- - --------------------------------------------------------------------------------------------------------
NET INCOME 87,384 76,563 59,873
DIVIDENDS ON PREFERRED STOCK 351 364 2,078
- - --------------------------------------------------------------------------------------------------------
INCOME AVAILABLE FOR COMMON STOCK $ 87,033 $ 76,199 $ 57,795
========================================================================================================
EARNINGS PER SHARE OF COMMON STOCK
(Average shares outstanding of 46,979,597,
44,042,365 and 42,882,627, respectively) $ 1.85 $ 1.73 $ 1.35
========================================================================================================
</TABLE>
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
<TABLE>
<CAPTION>
========================================================================================================
For the Years Ended September 30, 1994 1993 1992
- - --------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
BALANCE AT BEGINNING OF YEAR $ 255,979 $ 238,867 $ 237,156
INCOME AVAILABLE FOR COMMON STOCK 87,033 76,199 57,795
- - --------------------------------------------------------------------------------------------------------
343,012 315,066 294,951
Less:
Cash dividends declared ($1.35, $1.32 and $1.29
per common share, respectively) 63,652 58,914 55,667
Other adjustments (106) 173 417
- - --------------------------------------------------------------------------------------------------------
BALANCE AT END OF YEAR $ 279,466 $ 255,979 $ 238,867
========================================================================================================
</TABLE>
The accompanying summary of significant accounting policies and notes are
integral parts of these statements.
29
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEET
===================================================================================================
September 30, 1994 1993
- - ---------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Assets
Property
Utility, at cost $ 1,599,452 $ 1,523,894
Accumulated depreciation (354,925) (333,468)
Gas exploration and production, at cost 276,659 205,328
Accumulated depletion (115,890) (90,237)
- - ----------------------------------------------------------------------------------------------------
1,405,296 1,305,517
- - ----------------------------------------------------------------------------------------------------
Investments in Energy Services (See Note 6) 91,283 66,682
- - ----------------------------------------------------------------------------------------------------
Current Assets
Cash 11,610 10,834
Temporary cash investments 41,881 10,425
Common stock proceeds receivable - 44,910
Accounts receivable 193,130 230,688
Allowance for uncollectible accounts (14,963) (14,212)
Gas in storage, at average cost 96,076 102,516
Materials and supplies, at average cost 11,356 11,084
Prepaid gas costs 14,667 13,725
Other 31,441 37,304
- - ----------------------------------------------------------------------------------------------------
385,198 447,274
- - ----------------------------------------------------------------------------------------------------
Deferred Charges 147,297 78,374
- - ----------------------------------------------------------------------------------------------------
$ 2,029,074 $ 1,897,847
====================================================================================================
Capitalization and Liabilities
Capitalization (See accompanying statement and Note 4)
Common equity $ 774,236 $ 721,076
Preferred stock, redeemable 7,200 7,500
Long-term debt 701,377 689,300
- - ----------------------------------------------------------------------------------------------------
1,482,813 1,417,876
- - ----------------------------------------------------------------------------------------------------
Current Liabilities
Accounts payable 132,491 163,876
Dividends payable 16,609 15,868
Taxes accrued 15,213 15,345
Customer deposits 22,445 21,584
Customer budget plan credits 18,358 17,296
Interest accrued and other 45,807 53,491
- - ----------------------------------------------------------------------------------------------------
250,923 287,460
- - ----------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Federal income tax 230,316 139,289
Unamortized investment tax credits 22,000 23,074
Other 43,022 30,148
- - ----------------------------------------------------------------------------------------------------
295,338 192,511
- - ----------------------------------------------------------------------------------------------------
$ 2,029,074 $ 1,897,847
====================================================================================================
</TABLE>
The accompanying summary of significant accounting policies and notes are
integral parts of these statements.
30
<PAGE>
CONSOLIDATED STATEMENT OF CAPITALIZATION
<TABLE>
<CAPTION>
=========================================================================================================================
September 30, 1994 1993
- - -------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Common Equity
Common stock, $.33 1/3 par value, authorized 70,000,000 shares;
outstanding 47,590,015 and 46,380,282 shares,
respectively, stated at $ 494,770 $ 465,097
Retained earnings (See accompanying statement) 279,466 255,979
- - -------------------------------------------------------------------------------------------------------------------------
774,236 721,076
- - -------------------------------------------------------------------------------------------------------------------------
Preferred Stock, Redeemable
$100 par value, cumulative, authorized 900,000 shares
4.60% Series B, 75,000 and 78,000 shares outstanding, respectively 7,500 7,800
Less: Current sinking fund requirements 300 300
- - -------------------------------------------------------------------------------------------------------------------------
7,200 7,500
- - -------------------------------------------------------------------------------------------------------------------------
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 98,500
8 3/4% Series 1985 due July 2015 55,000 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
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
- - -------------------------------------------------------------------------------------------------------------------------
648,500 648,5OO
Borrowings by subsidiary 52,877 40,800
- - -------------------------------------------------------------------------------------------------------------------------
701,377 689,300
- - -------------------------------------------------------------------------------------------------------------------------
$ 1,482,813 $ 1,417,876
=========================================================================================================================
</TABLE>
The accompanying summary of significant accounting policies and notes are
integral parts of these statements.
31
<PAGE>
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
============================================================================================================
For the Years Ended September 30, 1994 1993 1992
- - ------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net income $ 87,384 $ 76,563 $ 59,873
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation and depletion 75,386 71,376 76,959
Deferred Federal income tax 10,897 7,599 7,980
Gain on sale of investment in Canadian gas company - (20,462) -
Write-off of investment in propane company - 17,617 -
Amortization of investment tax credit (1,074) (1,074) (1,074)
(Income) loss from energy services investments (5,689) (1,150) 1,041
Dividends received from energy services investments 4,392 7,421 1,884
Allowance for equity funds used during construction (2,076) (1,671) (1,876)
- - ------------------------------------------------------------------------------------------------------------
169,220 156,219 144,787
- - ------------------------------------------------------------------------------------------------------------
Effect of changes in working capital and other
Accounts receivable, net 31,906 (61,097) (11,559)
Accounts payable (34,121) 41,094 27,808
Gas inventory and prepayments 5,498 (31,063) (4,842)
Other 21,518 7,883 (21,433)
- - ------------------------------------------------------------------------------------------------------------
24,801 (43,183) (10,026)
- - ------------------------------------------------------------------------------------------------------------
Cash provided by operating activities 194,021 113,036 134,761
- - ------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Sale of common stock 29,828 71,866 23,037
Common stock proceeds receivable 44,910 (44,910) -
Issuance of long-term debt 12,077 186,900 93,400
- - ------------------------------------------------------------------------------------------------------------
86,815 213,856 116,437
Repayments
Preferred stock (300) (300) (37,273)
Long-term debt - (180,000) (90,400)
- - ------------------------------------------------------------------------------------------------------------
86,515 33,556 (11,236)
Dividends paid (64,003) (59,278) (57,745)
Trust funds, utility construction - 54,610 72,664
Other 106 2,156 (1,106)
- - ------------------------------------------------------------------------------------------------------------
Cash provided by financing activities 22,618 31,044 2,577
- - ------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Capital expenditures (excluding allowance
for equity funds used during construction) (197,496) (202,843) (171,591)
Proceeds from sale of investment in Canadian gas company 11,691 30,027 -
Other 1,398 7,400 (9,045)
- - ------------------------------------------------------------------------------------------------------------
Cash used in investing activities (184,407) (165,416) (180,636)
- - ------------------------------------------------------------------------------------------------------------
Change in Cash and Temporary Cash Investments $ 32,232 $ (21,336) $ (43,298)
============================================================================================================
Cash and Temporary Cash Investments at End of Year $ 53,491 $ 21,259 $ 42,595
============================================================================================================
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 $ 36,900 $ 32,100 $ 19,800
Interest $ 50,872 $ 51,804 $ 41,290
============================================================================================================
</TABLE>
The accompanying summary of significant accounting policies and notes are
integral parts of these statements.
32
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATMENTS
1.FEDERAL INCOME TAX
Income tax expense (benefit) is reflected as follows in the Consolidated
Statement of Income:
<TABLE>
<CAPTION>
- - --------------------------------------------------------------------------------
1994 1993 1992
- - --------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
OPERATING EXPENSES
Current $ 39,466 $29,172 $ 26,118
Deferred 2,153 13,261 4,694
- - --------------------------------------------------------------------------------
41,619 42,433 30,812
- - --------------------------------------------------------------------------------
OTHER INCOME
Current (8,591) 5,786 (3,805)
Deferred 8,744 (5,662) 3,286
Amortization of investment
tax credits (1,074) (1,074) (1,074)
- - --------------------------------------------------------------------------------
(921) (950) (1,593)
- - --------------------------------------------------------------------------------
Total Federal income tax $ 40,698 $41,483 $ 29,219
- - --------------------------------------------------------------------------------
</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, 1994(A)
- - --------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C>
DEFERRED CREDITS AND OTHER
LIABILITIES - FEDERAL
INCOME TAX
Property related
Utility $176,486
Net tax regulatory asset 29,087
Gas production and other 30,841
- - --------------------------------------------------------------------------------
$236,414
- - --------------------------------------------------------------------------------
Regulatory settlement items (9,879)
Gas cost and other 3,781
- - --------------------------------------------------------------------------------
Net deferred income tax liability $230,316
- - --------------------------------------------------------------------------------
</TABLE>
(A) As required by standards in effect prior to the adoption of SFAS-109, the
components of deferred tax expense (benefit) related to the following items in
1993 and 1992 are, respectively: property related - $9,782,000 and $6,684,000;
rate settlement items - $(245,000) and $(311,000); write-off of propane
investment $(7,720,000) and $0; gas costs and other - $5,781,000 and $1,607,000.
33
<PAGE>
The following is a reconciliation between reported income tax and tax computed
at the statutory rate of 35% for 1994, 34.75% for 1993 and 34% for 1992:
<TABLE>
<CAPTION>
- - --------------------------------------------------------------------------------
1994 1993 1992
- - --------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Computed at statutory rate $ 44,828 $41,021 $30,291
Book-tax differences:
Property related
Utility - 1,179 718
Gas production and other (1,303) 858 (1,497)
- - --------------------------------------------------------------------------------
(1,303) 2,037 (779)
- - --------------------------------------------------------------------------------
Nontaxable interest income (556) (396) (864)
Amortization of investment
tax credits (1,074) (1,074) (1,074)
Flow-through items - 536 1,598
Other (1,197) (641) 47
- - --------------------------------------------------------------------------------
Total Federal income tax $40,698 $41,483 $29,219
- - --------------------------------------------------------------------------------
Effective income tax rate 32% 35% 33%
- - --------------------------------------------------------------------------------
</TABLE>
The Company adopted Statement of Financial Accounting Standards (SFAS) No. 109,
"Accounting for Income Taxes" as of October 1, 1993. The adoption of SFAS-109
did not have a material effect on consolidated net income because the Company
recorded a regulatory asset to cover the increase in accumulated deferred
Federal income taxes not previously provided pursuant to regulatory orders.
2. POSTRETIREMENT AND POSTEMPLOYMENT 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. Commencing in fiscal 1994, the Company began recording
expense in accordance with treatment established by the PSC for ratemaking and
accounting purposes in a generic policy statement issued in September 1993
applicable to the adoption of SFAS-87, "Employers' Accounting for Pensions,"
SFAS-88, "Employers' Accounting for Settlements and Curtailments of Defined
Benefit Pension Plans and for Termination Benefits" and SFAS-106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions." Accordingly, the
Company's revenue requirement reflects the aggregate expenses related to
pensions and other postretirement benefit obligations as determined under the
applicable accounting standards.
On September 1, 1994, the Company completed a voluntary early retirement program
for management employees who were age 55 or older with at least 15 years of
service. As a result, the
34
<PAGE>
Company recorded a special retirement charge of $8,465,000. The effect of this
program was offset by reductions in other elements of total expense for
postretirement benefits, which in the aggregate remained within the revenue
allowance reflected in the Company's rates. Therefore, the program had no
material effect on consolidated net income. A similar program for bargaining
unit employees is expected to be completed in the first quarter of fiscal 1995.
Likewise, this program is not expected to have a material effect on consolidated
net income.
The Company's funding policy for pensions is in accordance with requirements of
Federal law and regulations. There were no pension contributions in 1994, 1993
and 1992.
The calculation of net periodic pension cost follows:
<TABLE>
<CAPTION>
- - --------------------------------------------------------------------------------
Year Ending September 30, 1994 1993 1992
- - --------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Service cost, benefits earned
during the year $ 15,100 $14,244 $ 11,406
Special retirement charge 8,465 - -
- - --------------------------------------------------------------------------------
$ 23,565 $14,244 $ 11,406
- - --------------------------------------------------------------------------------
Interest cost on projected
benefit obligation 29,511 24,617 21,966
Gain on assets (12,430) (76,671) (40,345)
Net amortization and deferral (32,798) 44,976 8,934
- - --------------------------------------------------------------------------------
Total pension cost $ 7,848 $ 7,166 $ 1,961
- - --------------------------------------------------------------------------------
</TABLE>
35
<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, 1994 1993
- - --------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Actuarial present value of
benefit obligations:
Vested $(333,890) $(274,118)
Accumulated $(353,172) $(296,375)
Projected $(446,676) $(398,300)
Plan assets at fair value $ 497,280 $ 503,838
- - --------------------------------------------------------------------------------
Plan assets in excess of
projected benefit obligation $ 50,604 $ 105,538
Unrecognized net gain from experience
and change in assumptions (21,007) (65,339)
Unrecognized transition asset (37,218) (41,870)
Expensing of pension cost to reflect
amount included in rates - 1,671
- - --------------------------------------------------------------------------------
Accrued pension cost $ (7,621) $ -
- - --------------------------------------------------------------------------------
Assumptions:
Obligation discount 8.00% 6.50%
Asset return 8.00% 7.50%
Average annual increase
in compensation 5.50% 5.50%
- - --------------------------------------------------------------------------------
</TABLE>
36
<PAGE>
B. 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 to the extent rate recoveries are allowed for pension and
postretirement benefit costs.
The Company adopted SFAS-106 as of October 1, 1993. SFAS-106 requires that the
costs of postretirement benefits other than pensions be accrued over employee
service lives by the time of retirement eligibility. Its adoption did not have
a material effect on consolidated net income because utility rates in fiscal
1994 reflected full recovery of annual SFAS-106 costs. The transition
obligation upon adoption totaled $77.1 million, which is being amortized and
recovered in rates over twenty years. Prior to the adoption of SFAS-106, such
costs, including payments to retirees and trust fund contributions, amounted to
$17,078,000 in 1993 and $13,437,000 in 1992.
The following table sets forth the plans' funded status, reconciled with amounts
recognized in the Company's Consolidated Balance Sheet.
<TABLE>
<CAPTION>
- - --------------------------------------------------------------------------------
September 30, 1994
- - --------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C>
Actuarial present value of accumulated
postretirement benefit obligation
Retirees $ (53,218)
Fully eligible active plan
participants (17,106)
Other active plan participants (32,890)
- - --------------------------------------------------------------------------------
(103,214)
- - --------------------------------------------------------------------------------
Plan assets at fair value, primarily
stocks and bonds $ 56,163
- - --------------------------------------------------------------------------------
Accumulated postretirement benefit
obligation in excess of plan assets $ (47,051)
Unrecognized net gain from past experience
different from that assumed and from
changes in assumptions (16,875)
Unrecognized transition obligation 71,547
- - --------------------------------------------------------------------------------
Prepaid postretirement benefit cost 7,621
- - --------------------------------------------------------------------------------
</TABLE>
37
<PAGE>
Net periodic postretirement benefit cost included the following components:
<TABLE>
<CAPTION>
- - --------------------------------------------------------------------------------
Year Ended September 30, 1994
- - --------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C>
Service cost, benefits earned during the year $2,826
Interest cost on accumulated postretirement
benefit obligation 7,916
Actual return on plan assets (340)
Net amortization and deferral 141
- - --------------------------------------------------------------------------------
Postretirement benefit cost $10,543
- - --------------------------------------------------------------------------------
</TABLE>
The measurement assumes an 8% discount rate and a health care cost trend rate of
9.5% in 1994, decreasing to 5% by the year 2007 and remaining at that level
thereafter. A 1% increase in the health care cost trend rate would have the
effect of increasing the accumulated postretirement benefit obligation as of
September 30, 1994 and the net periodic SFAS-106 expense by approximately
$13,348,000 and $1,706,000, respectively. The expected long-term rate of return
on plan assets was 8.0%.
C. OTHER: In November 1992, the Financial Accounting Standards Board (FASB)
issued SFAS-112, "Employers' Accounting for Postemployment Benefits." This
Statement requires accounting recognition on an accrual basis of any obligation
which exists to provide benefits to former or inactive employees after
employment, but before retirement. The Company adopted SFAS-112 on October 1,
1993. Its adoption had no material effect on the Company's Consolidated
Financial Statements.
3. FIXED OBLIGATIONS
A. LEASES
Lease costs included in operation expense were $15,547,000 in 1994, $14,247,000
in 1993 and $14,103,000 in 1992. The future minimum lease payments under the
Company's various leases, all of which are operating leases, are approximately
$14,200,000 per year over the next five years and $176,900,000 in the aggregate
for years thereafter.
For its corporate headquarters, the Company has a lease agreement with a
remaining term of 17 years.
B. FIXED CHARGES UNDER FIRM CONTRACTS: The Company has entered into various
contracts for gas delivery and supply services. The contracts have varying
terms that extend from one to twenty 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.
38
<PAGE>
4. CAPITALIZATION
A. COMMON AND PREFERRED STOCK: In 1994, 1993 and 1992, the Company issued
1,209,734, 1,128,662 and 1,172,040 shares of common stock for $29,828,000,
$26,956,000 and $23,037,000, respectively, under the Automatic Dividend
Reinvestment and Stock Purchase Plan, the Discount Stock Purchase Plan for
Employees, and the Employee Savings Plan. At September 30, 1994, 2,398,375
unissued shares of common stock were reserved for issuance under these plans.
On October 6, 1993, the Company issued 1,800,000 shares of common stock
providing net proceeds of $44,910,000.
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 issues tax-exempt bonds
through the New York State Energy Research and Development Authority
(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.
The Company converted $55 million of Series C Variable Rate Gas Facilities
Revenue Bonds to a fixed rate of 5.60% in July 1993 and $50 million of Series D
Variable Rate Gas Facilities Revenue Bonds to a fixed rate equivalent of 5.635%
in June 1993. In April 1993, the Company issued through the Authority $37.5
million of Gas Facilities Revenue Bonds 1993 Series A, in the form of Select
Auction Variable Rate Securities (SAVRS) and $37.5 million Gas Facilities
Revenue Bonds 1993 Series B, in the form of Residual Interest Bonds (RIBS). The
interest rate applicable to the 1993 Series A and B linked RIBS/SAVRS bonds,
which mature in 2020, is 6.368% per annum. The proceeds were received on April
29, 1993 and then applied to the redemption of $75 million of 9 1/8% Gas
Facilities Revenue Bonds due May 2013, called on May 1, 1993 at 103% of par
value plus accrued interest.
There are no sinking fund requirements for any Gas Facilities Revenue Bonds.
The Company's 9.0% and 8.75% Gas Facilities Revenue Bonds are callable in May
1995 and July 1995, respectively, at an optional redemption price of 102% of par
value plus accrued interest.
Other long-term debt consists of debt of a subsidiary amounting to $52,877,000
under a revolving loan agreement with no payments currently due. Interest on
this debt is at a composite rate which is less than the prime rate.
5. FINANCIAL INSTRUMENTS
In October 1994, the FASB issued SFAS-119, "Disclosure About Derivative
Financial Instruments and Fair Value of Financial Instruments," which required
various disclosures about financial instruments and related transactions.
39
<PAGE>
A. FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company's long-term debt consists primarily of publicly traded Gas
Facilities Revenue Bonds (see Note 4.B.), 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, 1994 and 1993 was $651,255,200 and $704,642,400,
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 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, 1994 and 1993, the
fair value of this stock was $4,796,640 and $4,893,750, respectively, and the
carrying value was $7,200,000 and $7,500,000, respectively.
All other financial instruments included in the Consolidated Balance Sheet are
stated in amounts that approximate fair values.
B. DERIVATIVE FINANCIAL INSTRUMENTS
The Company and its subsidiaries employ derivative financial instruments,
principally natural gas futures and swaps, for the purpose of risk management,
although employment of such instruments with respect to utility operations has
been minimal in 1994.
Natural gas futures are utilized to fix margins on purchases and sales of gas
entered into in the ordinary course of business. The Company and its
subsidiaries, principally its marketing subsidiary, had 2,768 futures contracts
outstanding at September 30, 1994, requiring margin deposits with brokers in the
amount of $2,251,600. The underlying transactions are of varying durations,
none of which extend beyond March 1996. The Company would be required to pay
approximately $3,136,600 to settle these contracts at September 30, 1994.
Deferred losses amounted to $1,240,600 at September 30, 1994.
The Company entered into a series of swap transactions intended to minimize the
Company's exposure to differences in the market prices of gas at certain receipt
points in producing areas. The swap contracts cover 14.5 BCF of gas per year
through October 1996.
The Company's gas exploration and production subsidiary also manages the risk
associated with fluctuations in the price of natural gas through commodity swap
contracts with financial institutions. The subsidiary has several contracts in
effect, at various prices, which cover a significant amount of its estimated
production for the next three years. The Company would be required to pay
approximately $7,130,000 to settle these contracts at September 30, 1994.
All of the foregoing transactions meet the criteria for hedge
40
<PAGE>
accounting treatment. Accordingly, gains and losses are recognized when the
underlying transaction is completed, at which time these gains and losses are
included in earnings as an offset to revenues or costs recognized when the gas
is sold, purchased or transported in accordance with a hedged transaction, and
are reflected as cash flows from operations in the accompanying Consolidated
Statement of Cash Flows at that time. Further, in cases where the transaction
results in the acquisition of an asset, deferred gains and losses are included
as part of the carrying amount of the asset acquired.
The Company and its subsidiaries are exposed to credit risk in the event of
nonperformance by counterparties to futures and swap contracts, as well as
nonperformance by the counterparties of the transactions which they are hedged
against. The Company believes that the credit risk related to the futures 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.
6. INVESTMENTS IN ENERGY SERVICES
A. IROQUOIS PIPELINE: A Company subsidiary, North East Transmission Co., Inc.
(NETCO), owns an 11.4% interest in Iroquois Gas Transmission System, L.P.
(Iroquois), which partnership owns and operates a 375-mile pipeline from Canada
to the Northeast. NETCO's investment in Iroquois was $20.1 million at September
30, 1994.
In 1992, Iroquois was informed by the U.S. Attorneys' Offices of various
districts of New York of a civil investigation of alleged violations of the U.S.
Army Corps of Engineers (COE) permit, a related State Water Quality
Certification and/or the Federal Clean Water Act. Related agency investigations
of matters related to the construction of the Iroquois Pipeline have been
commenced by COE and the Federal Energy Regulatory Commission (FERC). Civil
penalties could be imposed if violations of Iroquois' COE and FERC
authorizations are shown to have occurred. No proceedings in connection with
these investigations have been commenced.
Also in 1992, a criminal investigation of Iroquois was initiated and is being
conducted by Federal authorities pertaining to various matters related to the
construction of the pipeline. To date, no criminal charges have been filed.
Iroquois' management believes the pipeline construction and right-of-way
activities were conducted in a responsible manner. However, Iroquois deems it
probable that indictments will be sought in connection with this investigation
and in them substantial fines and other sanctions.
Iroquois' management has been informed that meetings are expected with those
responsible for the civil and criminal
41
<PAGE>
investigations, from time to time, both to gain an informed understanding of the
focus and direction of the investigation in order to defend itself and, if and
when appropriate, to explore possible resolutions that may be acceptable to all
parties. Although the ultimate outcome of these matters cannot be predicted at
this time, based on information currently available, the Company does not
believe that the resolution of these matters will have a material adverse effect
on its consolidated financial results.
B. COGENERATION PROJECTS: A Company subsidiary, Gas Energy Inc. (GEI), through
affiliates, owns a 50% partnership interest, and has invested approximately
$47.5 million as of September 30, 1994, in a project to construct, own and
operate a 100-megawatt cogeneration plant at John F. Kennedy International
Airport in Queens, New York. The estimated cost of the project is approximately
$292 million, of which $175 million is being financed by proceeds from bonds
issued by the Port Authority of New York and New Jersey and guaranteed by an
international banking group. The partners are committed to make equal
contributions for project costs above $175 million. Construction of the project
is scheduled for completion in 1995.
In addition, a project to construct, own and operate a 40-megawatt cogeneration
plant at the State University of New York at Stony Brook is under construction.
The debt financing is being provided through $79 million of tax-exempt Suffolk
County Industrial Development Revenue Bonds and is guaranteed by a letter of
credit issued by Toronto-Dominion Bank. Commercial operation is scheduled for
the first quarter of 1995. Another Company subsidiary, Gas Energy Cogeneration,
Inc., through affiliates, owns a 50% partnership interest in the project,
estimated to cost $92.6 million. As of September 30, 1994, the subsidiary had
funded $3.6 million of an expected total of $6.8 million as its share of the
project.
7. ENVIRONMENTAL MATTERS
The Company is involved in environmental site investigation, implementation of
interim remedial measures, and consideration of long-term remedial solutions at
the former manufactured gas plant (MGP) site in Coney Island that was owned and
operated by a predecessor company. This property was the subject of a notice by
the City of New York in January 1993 alleging that the site presented an
imminent and substantial endangerment to health and the environment and stating
that the City intended to bring a citizens' suit under the Federal Resource
Conservation and Recovery Act and related statutes to compel cleanup and recover
its own response costs. The Company has denied the City's allegations, but has
met informally with City officials, apprised them of the Company's own ongoing
environmental investigation, and committed itself to keeping the City informed
of developments. The City has not filed suit as of this date.
42
<PAGE>
In addition, the Company in cooperation with the U.S. Coast Guard has been
responding to pollution incidents, occurring and reported to governmental
authorities during the summer of 1993, involving the apparent seep of oil into
Coney Island Creek from the Coney Island site. This response has included the
construction of an interim response measure (IRM) to contain and recover any
such oil seep. While expenses to date have not been material with respect to
the pollution incident, the Coast Guard has not issued its final approval of
this response measure and the Company cannot predict how long the IRM will
operate or whether additional containment or response measures will be required
or what such measures would cost.
In October 1994, the Company had an initial meeting with the New York State
Department of Environmental Conservation (DEC) for the purpose of reaching a
consensual agreement under state environmental laws for a long-term site
management plan for the Coney Island site. The discussions with the DEC to date
have been preliminary and the Company is unable to predict which, if any, of the
options discussed with the DEC might be mutually acceptable. Based on these
preliminary discussions, the Company believes that long-term site management
costs will be at least $8,000,000 and may be several times that amount,
depending upon the site management option finally negotiated with the DEC. A
consensual agreement is not likely to be reached before the end of 1995.
Accordingly, as at September 30, 1994, the Company accrued a liability of
$8,000,000 as the minimum estimate of costs most likely to be incurred and a
corresponding regulatory asset, in addition to $4,100,000 of interim response
costs previously recorded. Expenditures related to any negotiated site
management plan will be over a number of years.
The Company has been approached by the City of New York with respect to another
former MGP property regarding potential cost sharing of environmental cleanup
costs. This property is currently owned by the City. The Company and the City
have had several meetings but discussions are preliminary. Until it becomes
clear that the property will in fact be developed by the City or a third party,
or it is demonstrated that the property presents a significant environmental
risk, the Company cannot determine its potential legal liabilities and/or
financial exposure, if any, associated with this property.
The Company has notified several of its insurance carriers of potential claims
regarding environmental cleanup liabilities. The Company's consideration of its
potential insurance claims is continuing.
With the exception of the matters referenced above, no significant
administrative or judicial proceedings involving the Company have been initiated
with respect to any other MGP property. Although the potential cost of cleanup
at these sites may be material if the Company is ever compelled to
43
<PAGE>
address these sites, the Company cannot at this time determine the cost or
extent of any cleanup efforts if cleanup ultimately should be required.
In October 1994, 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, including the $4.1 million in interim response
costs accrued in 1993 and the $8.0 million liability accrued as at September 30,
1994. In addition, as part of its October 1994 order approving the Company's
three-year rate settlement, the PSC approved the deferral of environmental site
investigation and remediation costs incurred after September 30, 1994. Pursuant
to that order, rates commencing in October 1994 reflect the recovery of the $4.1
million deferred interim response costs over a five year period, and the Company
may reflect in rates commencing October 1995 and October 1996, the deferred
balance of environmental site investigation and remediation costs accrued as at
September 30, 1994 and September 30, 1995, respectively, each over a five year
period. The recovery of these costs in rates is conditioned upon the absence of
a PSC determination that such costs have been unreasonable or imprudently
incurred. In general, the Company believes that, based on applicable law and
prior PSC precedents with respect to similar expenditures incurred by other
utilities in New York State, the Company will be permitted to recover its
prudently incurred environmental site investigation and remediation costs in
rates.
44
<PAGE>
SUPPLEMENTAL GAS AND OIL DISCLOSURES
CAPITALIZED COSTS RELATING TO GAS AND OIL PRODUCING ACTIVITIES
<TABLE>
<CAPTION>
==============================================================================================================
September 30, 1994 1993
==============================================================================================================
<S> <C> <C>
(Thousands of dollars)
Unproved properties not being amortized $25,335 $9,875
Properties being amortized-productive and nonproductive 240,572 187,856
==============================================================================================================
Total capitalized costs 265,907 197,731
Accumulated depletion (109,885) (84,907)
- - --------------------------------------------------------------------------------------------------------------
Net capitalized costs $156,022 $112,824
==============================================================================================================
</TABLE>
The following is a summary of the costs (in thousands of dollars) which are
excluded from the amortization calculation as of September 30, 1994, by year of
acquisition: 1994-$18,703; 1993-$0; 1992-$3,573 and prior years-$3,059. The
Company cannot accurately predict when these costs will be included in the
amortization base, but it is expected that these costs will be evaluated within
the next five years.
COSTS INCURRED IN PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES
<TABLE>
<CAPTION>
====================================================================================================================================
Total United States Canada
-------------------------------------- --------------------------- ------------------------------
1994* 1993 1992 1993 1992 1993 1992
- - ------------------------------------------------------------------------------------------------------------------------------------
(Thousands of dollars)
<S> <C> <C> <C> <C> <C> <C> <C>
Aquisition of properties-
Unproved properties $11,022 $5,289 $6,159 $4,937 $6,159 $352 $ -
Proved properties 28,370 40,091 13,624 30,541 8,206 9,550 5,418
Exploration 18,961 2,831 7,615 2,831 7,615 - -
Development 9,781 16,588 13,436 11,238 12,681 5,350 755
- - ------------------------------------------------------------------------------------------------------------------------------------
Total costs incurred $68,134 $64,799 $40,834 $49,547 $34,661 $15,252 $6,173
====================================================================================================================================
</TABLE>
RESULTS OF OPERATIONS FROM GAS AND OIL PRODUCING ACTIVITIES
<TABLE>
<CAPTION>
====================================================================================================================================
Total United States Canada
-------------------------------------------------------------------------------------------------
1994* 1993 1992 1993 1992 1993 1992
- - ------------------------------------------------------------------------------------------------------------------------------------
(Thousands of dollars)
<S> <C> <C> <C> <C> <C> <C> <C>
Revenues from gas and oil
producing activities-
Sales to unaffiliated parties $41,185 $43,076 $24,122 $31,745 $20,379 $11,331 $3,743
Sales to affiliates 2,023 1,482 1,802 1,482 1,802 - -
- - ------------------------------------------------------------------------------------------------------------------------------------
Revenues 43,208 44,558 25,924 33,227 22,181 11,331 3,743
- - ------------------------------------------------------------------------------------------------------------------------------------
Production and lifting costs 5,360 8,608 5,065 4,232 3,363 4,376 1,702
Depletion 24,978 22,525 14,242 20,990 13,749 1,535 493
Impairment - - 19,697 - 19,697 - -
- - ------------------------------------------------------------------------------------------------------------------------------------
Total expenses 30,338 31,133 39,004 25,222 36,809 5,911 2,195
- - ------------------------------------------------------------------------------------------------------------------------------------
Income(loss) before taxes 12,870 13,425 (13,080) 8,005 (14,628) 5,420 1,548
Income taxes(benefit) 3,306 4,129 (5,556) 1,691 (6,253) 2,438 697
- - ------------------------------------------------------------------------------------------------------------------------------------
Results of gas and oil producing
activities (excluding corporate
overhead and interest costs) $9,564 $9,296 ($7,524) $6,314 ($8,375) $2,982 $851
====================================================================================================================================
</TABLE>
* Gas and oil operations were conducted predominantly in the United States in
1994.
45
<PAGE>
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 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 from production
of proved reserves was developed as follows:
1) Estimates are made of quantities of proved reserves and future periods
during which they are expected to be produced based on year-end economic
conditions.
2) The estimated future cash flows are compiled by applying year-end prices of
gas and oil relating to the Company's proved reserves to the year-end
quantites of those reserves except for the reserves devoted to future
production that is hedged. These reserves are priced at their respective
hedge amount. Future price changes are considered only to the extent
provided by contractual arrangements in existence at year-end.
3) The future cash flows are reduced by estimated production costs, costs to
develop the proved reserves and certain abandonment costs, all based on
year-end economic conditions.
4) Future income tax expenses are based on year-end statutory tax rates giving
effect to the remaining tax basis in the gas and oil properties and other
deductions, credits and allowances relating to the Company's proved gas and
oil reserves.
5) Future net cash flows are discounted to present value by applying a discount
rate of 10%.
The standardized measure of discounted future net cash flows 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.
RESERVE QUANTITY INFORMATION
Natural Gas (MMcf)
<TABLE>
<CAPTION>
====================================================================================================================================
Total United States Canada
---------------------------------------------------------------------------------------------------
1994* 1993 1992 1993 1992 1993 1992
- - ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Proved Reserves-
Beginning of Year 108,847 111,664 69,042 84,171 69,042 27,493 -
Revisions of previous estimates (2,297) 9,036 5,094 1,438 5,094 7,598 -
Extensions and discoveries 25,890 4,696 12,765 3,915 12,765 781 -
Production (22,814) (26,596) (14,302) (21,007) (12,252) (5,589) (2,050)
Purchases of reserves in place 34,931 91,016 39,065 40,330 9,522 50,686 29,543
Sales of reserves in place (1,699) (80,969) - - - (80,969) -
- - ------------------------------------------------------------------------------------------------------------------------------------
Proved Reserves-
End of Year 142,858 108,847 111,664 108,847 84,171 - 27,493
- - ------------------------------------------------------------------------------------------------------------------------------------
Proved Developed Reserves-
Beginning of Year 100,454 93,417 60,826 65,924 60,826 27,493 -
- - ------------------------------------------------------------------------------------------------------------------------------------
End of Year 110,225 100,454 93,417 100,454 65,924 - 27,493
- - ------------------------------------------------------------------------------------------------------------------------------------
Crude Oil, Condensate and Natural Gas Liquids (MBbls)
Total United States Canada
------------------------------------------------- ------------------------------------------------
1994* 1993 1992 1993 1992 1993 1992
- - ------------------------------------------------------------------------------------------------------------------------------------
Proved Reserves-
Beginning of Year 443 2,304 488 520 488 1,784 -
Revisions of previous estimates (140) 184 29 (91) 29 275 -
Extensions and discoveries 155 3 90 3 90 - -
Production (96) (320) (220) (109) (106) (211) (114)
Purchases of reserves in place 495 121 1,917 120 19 1 1,898
Sales of reserves in place (50) (1,849) - - - (1,849) -
- - ------------------------------------------------------------------------------------------------------------------------------------
Proved Reserves-
End of Year 807 443 2,304 443 520 0 1,784
- - ------------------------------------------------------------------------------------------------------------------------------------
Proved Developed Reserves-
Beginning of Year 407 2,239 424 455 424 1,784 -
- - ------------------------------------------------------------------------------------------------------------------------------------
End of Year 543 407 2,239 407 455 - 1,784
- - ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
* Gas and oil reserves were located predominantly in the United States in 1994.
46
<PAGE>
SUPPLEMENTAL GAS AND OIL DISCLOSURES (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED GAS AND OIL RESERVES
<TABLE>
<CAPTION>
=================================================================
Total
-----------------------------
1994 1993
- - -----------------------------------------------------------------
(Thousands of dollars)
<S> <C> <C>
Future cash flow $249,437 $247,117
Future costs-
Production (47,149) (51,199)
Development (22,241) (12,552)
- - -----------------------------------------------------------------
Future net inflows
before income tax 180,047 183,366
Future income taxes (26,930) (32,804)
- - -----------------------------------------------------------------
Future net cash flows 153,117 150,562
10% discount factor (44,983) (40,155)
- - -----------------------------------------------------------------
Standardized measure of
discounted future net
cash flows $108,134 $110,406
=================================================================
</TABLE>
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
FROM PROVED RESERVE QUANTITIES
<TABLE>
<CAPTION>
====================================================================================================================================
1994 1993 1992
- - ------------------------------------------------------------------------------------------------------------------------------------
United United
Total Total States Canada Total States Canada
- - ------------------------------------------------------------------------------------------------------------------------------------
(Thousands of dollars)
<S> <C> <C> <C> <C> <C> <C> <C>
Standardized measure-
beginning of year $110,406 $90,665 $76,695 $13,970 50,359 $50,359 $ -
Sales and transfers, net of
production costs (37,848) (35,950) (28,995) (6,955) (20,859) (18,818) (2,041)
Net change in sales and
transfer prices, net of
production costs (25,005) 4,001 7,011 (3,010) 9,939 9,939 -
Extensions and discoveries and
improved recovery, net of
future production 15,536 6,554 5,994 560 14,592 14,592 -
Changes in estimated future
development costs (1,016) (8,281) (8,281) - (1,261) (1,261) -
Development costs incurred
during the period that reduced
future development costs 6,381 12,354 12,354 - 5,317 5,317 -
Revisions of quantity estimates (2,917) 6,195 1,926 4,269 5,709 5,709 -
Accretion of discount 12,397 11,033 8,921 2,112 6,030 6,030 -
Net change in income taxes 4,001 (3,079) (1,045) (2,034) (10,133) (2,579) (7,554)
Purchases of reserves in place 27,561 61,410 40,548 20,862 33,638 10,073 23,565
Sales of reserves in place (2,110) (27,539) - (27,539) - - -
Changes in production rates
(timing) and other 748 (6,956) (4,721) (2,235) (2,666) (2,666) -
- - ------------------------------------------------------------------------------------------------------------------------------------
Standardized measure-end
of year $108,134 $110,406 $110,406 $ - $90,665 $76,695 $13,970
====================================================================================================================================
</TABLE>
47
<PAGE>
SUPPLEMENTAL GAS AND OIL DISCLOSURES (CONTINUED)
AVERAGE SALES PRICES AND PRODUCTION COSTS - PER UNIT
<TABLE>
<CAPTION>
For the years ended September 30,
1994 1993 1992
<S> <C> <C> <C>
Average Sales Price*
Natural Gas ($/MCF)
United States 1.97 2.12 1.72
Canada - 1.39 1.01
Total 1.97 1.97 1.62
Oil, Condensate and Natural
Gas Liquid ($/Bbl)
United States 15.63 17.70 24.33
Canada - 16.90 15.06
Total 15.63 17.17 19.60
</TABLE>
*Represents the cash price received which excludes the effect of any hedging
transactions.
<TABLE>
<S> <C> <C> <C>
Production Cost Per
Equivalent MCF ($)
United States .23 .18 .22
Canada - .64 .63
Total .23 .29 .29
<CAPTION>
ACREAGE
As of September 30, 1994
Gross Net
<S> <C> <C>
Producing** 236,242 112,347
Undeveloped 209,534 80,258
<CAPTION>
NUMBER OF PRODUCING WELLS
As of September 30, 1994
Gross Net
<S> <C> <C>
Gas wells** 928 488
Oil wells 19 8
</TABLE>
**Located predominantly in the United States.
48
<PAGE>
DRILLING ACTIVITY (NET)
<TABLE>
<CAPTION>
For the years ended September 30,
1994 1993 1992
Prod Dry Total Prod Dry Total Prod Dry Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Net developmental
wells
United States 6.6 - 6.6 5.4 - 5.4 14.3 - 14.3
Canada - - - 5.0 - 5.0 - - -
Total 6.6 - 6.6 10.4 - 10.4 14.3 - 14.3
Net exploratory
wells (U.S.) 2.5 1.2 3.7 - 0.5 0.5 0.2 5.0 5.2
</TABLE>
At September 30, 1994 the Company, through its subsidiaries, was participating
in the drilling of 2 developmental wells and 1 exploratory well with the
Company's net interest being 1.0 and .9 wells, respectively.
49
<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 1 through 6 of the Company's definitive Proxy Statement,
dated December 29, 1994, for its Annual Meeting of Shareholders to be held on
February 2, 1995.
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 6 through 10 of the Company's
definitive Proxy Statement, dated December 29, 1994, for its Annual Meeting of
Shareholders to be held on February 2, 1995.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
- - -------------------------------------------------------------
MANAGEMENT
----------
Information regarding beneficial ownership and management ownership is
incorporated herein by reference to "Proposal (1) - Election of Directors" in
the Company's definitive Proxy Statement, on pages 1 through 6, dated December
29, 1994, for its Annual Meeting of Shareholders to be held on February 2, 1995.
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.
50
<PAGE>
PART IV
---------
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
- - -----------------------------------------------------------------
FORM 8-K
--------
(a) 1. All Financial Statements
- - ----------------------------------
<TABLE>
<CAPTION>
Page in
Form 10-K
---------
<S> <C>
Report of Independent Public Accountants 25
Summary of Significant Accounting Policies 26
Consolidated Statement of Income for the Years
Ended September 30, 1994, 1993 and 1992 29
Consolidated Statement of Retained Earnings for
the Years Ended September 30, 1994, 1993
and 1992 29
Consolidated Balance Sheet at September 30, 1994
and 1993 30
Consolidated Statement of Capitalization at
September 30, 1994 and 1993 31
Consolidated Statement of Cash Flows for the
Years Ended September 30, 1994, 1993 and 1992 32
Notes to Consolidated Financial Statements 33
</TABLE>
(a) 2. Financial Statement Schedules
- - ---------------------------------------
Separate financial statements for The Brooklyn Union Gas Company are omitted for
the reason that the Company's total assets for the fiscal year ended September
30, 1994, exclusive of investments in and advances to its consolidated
subsidiaries, constitute more than 75% of the total assets shown by the
Consolidated Balance Sheet as of September 30, 1994, and the Company's total
gross revenues, exclusive of interest and dividends received or equity in income
from the consolidated subsidiaries, constitute more than 75% of the total gross
revenues shown by the Consolidated Statement of Income for the year ended
September 30, 1994.
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.
51
<PAGE>
Executice Officers of the Registrant
- - -------------------------------------------
All Executive Officers serve one-year terms.
<TABLE>
<CAPTION>
AGE AS OF
SEPT. 30, PERIOD SERVED
NAME AND POSITION 1994 IN SUCH CAPACITY BUSINESS EXPERIENCE IN PAST 5 YEARS
<S> <C> <C> <C>
Robert B. Catell, President 57 1991 to Present President and Chief Executive Officer
and Chief Executive Officer 1990 to 1991 President and Chief Operating Officer
1986 to 1990 Executive Vice President and Chief Operating Officer
Craig G. Matthews 51 1994 to Present Executive Vice President
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 62 1992 to Present Executive Vice President
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 53 1992 to Present Senior Vice President
Senior Vice President 1989 to 1992 Vice President
Vincent D. Enright, Senior Vice 50 1994 to Present Senior Vice President and Chief Financial Officer
President and Chief Financial Officer 1992 to 1994 Senior Vice President
1984 to 1992 Vice President
William K. Feraudo 44 1994 to Present Senior Vice President
Senior Vice President 1989 to 1994 Vice President
Wallace P. Parker, Jr. 45 1994 to Present Senior Vice President
Senior Vice President 1990 to 1994 Vice President
1987 to 1990 Assistant Vice President
Lenore F. Puleo 41 1994 to Present Senior Vice President
Senior Vice President 1990 to 1994 Vice President
Maurice K. Shaw, Senior Vice 55 1993 to Present Senior Vice President and Corporate Affairs Officer
President and Corporate Affairs Officer 1987 to 1993 Senior Vice President and Chief Marketing Officer
Edward J. Sondey 56 1992 to Present Senior Vice President
Senior Vice President 1981 to 1992 Vice President
Tina G. Barber, Vice President 45 1994 to Present Vice President and Chief Information Officer
and Chief Information Officer 1992 to 1994 Vice President
Richard M. Desmond, Vice President, 60 1992 to Present Vice President, Comptroller and Chief
Comptroller and Accounting Officer
Chief Accounting Officer 1984 to 1992 Vice President and Comptroller
Robert H. Preusser, Vice President 57 1992 to Present Vice President and Chief Engineer
and Chief Engineer 1987 to 1992 Vice President
Roger J. Walz, Vice President 49 1990 to Present Vice President and General Auditor
and General Auditor 1988 to 1990 General Auditor
Robert R. Wieczorek, Vice President, 52 1994 to Present Vice President, Secretary and Treasurer
Secretary and Treasurer 1989 to 1994 Vice President, Treasurer, and Assistant Secretary
</TABLE>
52
<PAGE>
Index
<TABLE>
<CAPTION>
Page in
Form 10-K
----------
<S> <C>
V Consolidated Schedule of Property, Plant and
Equipment for the Years Ended September
30, 1994, 1993 and 1992 54
VI Consolidated Schedule of Accumulated
Depreciation, Depletion and Amortization
of Property, Plant and Equipment for the
Years Ended September 30, 1994, 1993 and
1992 56
VIII Consolidated Schedule of Valuation and
Qualifying Accounts for the Years
Ended September 30, 1994, 1993 and
1992 58
X Consolidated Supplementary Income
Statement Information for the
Years Ended September 30, 1994,
1993 and 1992 59
</TABLE>
53
<PAGE>
Schedule V
THE BROOKLYN UNION GAS COMPANY AND SUBSIDIARIES Page 1 of 2
CONSOLIDATED SCHEDULE OF PROPERTY, PLANT AND EQUIPMENT
FOR THE YEARS ENDED SEPTEMBER 30,1994,1993 AND 1992
--------------------------------------------------
(Thousands of Dollars)
<TABLE>
<CAPTION>
Column A Column B Column C Column D Column E Column F
- - ------------------------------------------ ------------- ----------- ----------- --------- --------------
Balance at Balance
Beginning Additions at End
Description of Period at Cost Retirements Other of Period
- - ------------------------------------------ ------------- ------------ ---------- --------- ---------------
Year Ended September 30,1994
- - ------------------------------------------
<S> <C> <C> <C> <C> <C>
Utility Gas Property
Gas Property in Service
Intangible plant $ 47,960 $ - $ - $ - $ 47,960
Production - - - - -
Storage 69,659 3,038 223 (75) 72,399
Distribution 1,216,025 100,500 20,855 (2,516) 1,293,154
General 155,116 16,568 7,160 262 164,786
------------- ------------ ---------- ----------- ---------------
Total Gas Property in Service 1,488,760 120,106 28,238 (2,329) 1,578,299
Construction work in progress 33,911 (16,312) - (1) 17,598
Held for future use 365 - - 2,332 2,697
Gas stored underground 858 - - - 858
------------- ------------ ---------- ----------- ---------------
Total Utility Gas Property 1,523,894 103,794 28,238 2 1,599,452
------------- ------------ ---------- ----------- ---------------
Gas Exploration and Production Property 205,328 71,331 - - 276,659
------------- ------------ ---------- ----------- ---------------
Total Property $ 1,729,222 $ 175,125 $ 28,238 $ 2 $ 1,876,111
------------- ------------ ---------- ----------- ---------------
Year Ended September 30,1993
- - -----------------------------------------
Utility Gas Property
Gas Property in Service
Intangible plant $ 46,412 $ 1,548 $ - $ - $ 47,960
Production - - - - -
Storage 70,368 2,365 3,074 - 69,659
Distribution 1,147,664 80,151 11,797 7 1,216,025
General 147,717 11,235 3,829 (7) 155,116
------------- ------------ ---------- ----------- -------------
Total Gas Property in Service 1,412,161 95,299 18,700 0 1,488,760
Construction work in progress 18,279 15,366 - 266 33,911
Held for future use 17,817 - 17,686 234 365
Gas stored underground 858 - - - 858
------------- ------------ ---------- ----------- -------------
Total Utility Gas Property 1,449,115 110,665 36,386 500 1,523,894
------------- ------------ ---------- ----------- -------------
Gas Exploration and Production Property 165,799 66,324 26,795 - 205,328
------------- ------------ ---------- ----------- -------------
Total Property $ 1,614,914 $ 176,989 $ 63,181 $ 500 $ 1,729,222
------------- ------------ ---------- ----------- -------------
</TABLE>
54
<PAGE>
Schedule V
THE BROOKLYN UNION GAS COMPANY AND SUBSIDIARIES Page 2 of 2
CONSOLIDATED SCHEDULE OF PROPERTY, PLANT AND EQUIPMENT
FOR THE YEARS ENDED SEPTEMBER 30,1994,1993 AND 1992
-------------------------------------------------
(Thousands of Dollars)
<TABLE>
<CAPTION>
Column A Column B Column C Column D Column E Column F
- - ------------------------------------------ ------------- ------------ ----------- ----------- -------------
Balance at Balance
Beginning Additions at End
Description of Period at Cost Retirements Other of Period
- - ------------------------------------------ ------------- ------------ ---------- ----------- -------------
Year Ended September 30,1992
- - ------------------------------------------
<S> <C> <C> <C> <C> <C>
Utility Gas Property
Gas Property in Service
Intangible plant $ 46,412 $ - $ - $ - $ 46,412
Production 491 5 496 - 0
Storage 68,924 1,743 299 - 70,368
Distribution 1,075,033 84,048 11,417 - 1,147,664
General 120,924 56,961 16,628 (13,540) 147,717
-------------- ------------ ----------- ----------- -------------
Total Gas Property in Service 1,311,784 142,757 28,840 (13,540) 1,412,161
Construction work in progress 48,658 (30,379) - - 18,279
Held for future use 292 - - 17,525 17,817
Gas stored underground 858 - - - 858
-------------- ------------ ----------- ----------- -------------
Total Utility Gas Property 1,361,592 112,378 28,840 3,985 1,449,115
-------------- ------------ ----------- ----------- -------------
Gas Exploration and Production Property 142,521 41,792 19,127 613 165,799
-------------- ------------ ----------- ----------- -------------
Total Property $ 1,504,113 $ 154,170 $ 47,967 $ 4,598 $ 1,614,914
-------------- ------------ ----------- ----------- -------------
</TABLE>
55
<PAGE>
Schedule VI
THE BROOKLYN UNION GAS COMPANY AND SUBSIDIARIES Page 1 of 2
CONSOLIDATED SCHEDULE OF ACCUMULATED DEPRECIATION, DEPLETION AND
AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
FOR THE YEARS ENDED SEPTEMBER 30, 1994, 1993 AND 1992
-------------------------------------------------------
(Thousands of Dollars)
<TABLE>
<CAPTION>
Column A Column B Column C Column D Column E
- - ------------------------------- -------- --------- ---------- -------- ------- --------- ----------
Additions Charged to Retirements
Balance at -------------------- -------- ------- --------- Balance
Description Beginning Other Original Removal Salvage at End
of Period Expense Accounts Cost & Other (Credit) of Period
- - ------------------------------- --------- ---------- -------- ------- ------- -------- ----------
Year Ended September 30,1994
- - -------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Utility Gas Property
Accumulated depreciation $ 334,196 $ 43,512 $ 6,126 $ 25,700 $ 2,545 $ (227) $ 355,816
Retirement work in progress (728) - 19 - 182 (891)
-------- ---------- ------- ------ ------ ------- ---------
333,468 43,512 6,145 25,700 2,727 (227) 354,925
-------- ---------- ------- ------ ------ ------- ---------
Other,Principally Gas Exploration
and Production
Accumulated depletion and
depreciation 90,237 25,596 - 16 (73) 115,890
-------- ---------- ------- ------ ------ ------- ---------
$ 423,705 $ 69,108 $ 6,145 $ 25,716 $ 2,654 $ (227) $ 470,815
-------- ------- ------ ------ ------- ---------
Miscellaneous Amortization 503
----------
Total Depreciation, Depletion
and Amortization Expense $ 69,611
----------
Year Ended September 30,1993
- - -------------------------------
Utility Gas Property
Accumulated depreciation $ 316,400 $ 40,476 $ 6,597 $ 32,900 $ 3,113 $ (6,736) $ 334,196
Retirement work in progress (691) - - - 125 (88) (728)
--------- ---------- ------- ------ ------ ------- ---------
315,709 40,476 6,597 32,900 3,238 (6,824) 333,468
--------- ---------- ------- ------ ------ ------- ---------
Other,Principally Gas Exploration
and Production
Accumulated depletion and
depreciation 69,112 23,526 - 2,675 0 (274) 90,237
--------- ---------- ------- ------ ------ ------- ---------
$ 384,821 $ 64,002 $ 6,597 $ 35,575 $ 3,238 $ (7,098) $ 423,705
--------- ------- ------ ------ ------- ---------
Miscellaneous Amortization 777
----------
Total Depreciation, Depletion
and Amortization Expense $ 64,779
----------
</TABLE>
56
<PAGE>
Schedule VI
THE BROOKLYN UNION GAS COMPANY AND SUBSIDIARIES Page 2 of 2
CONSOLIDATED SCHEDULE OF ACCUMULATED DEPRECIATION, DEPLETION AND
AMORTIZATION OF PROPERTY,PLANT AND EQUIPMENT
FOR THE YEARS ENDED SEPTEMBER 30, 1994, 1993 AND 1992
----------------------------------------------
(Thousands of Dollars)
<TABLE>
<CAPTION>
Column A Column B Column C Column D Column E
- - ------------------------------- --------- -------------------- -------------------------- ----------
Additions Charged to Retirements
Balance at -------------------- -------------------------- Balance
Description Beginning Other Original Removal Salvage at End
of Period Expense Accounts Cost & Other (Credit) of Period
- - ------------------------------- --------- ---------- -------- ------- ------- -------- ----------
<S> <C> <C> <C> <C> <C>
Year Ended September 30,1992
- - -------------------------------
Utility Gas Property
Accumulated depreciation $ 299,199 $ 37,252 $ 3,029 $ 28,790 $ 951 $ (6,661) $ 316,400
Retirement work in progress (525) - - - 114 52 (691)
--------- ---------- -------- ------- ------- -------- ---------
298,674 37,252 3,029 28,790 1,065 (6,609) 315,709
--------- ---------- -------- ------- ------- -------- ---------
Other,Principally Gas Exploration
and Production Accumulated
depletion and depreciation 54,106 35,095 - 19,068 1,682 (661) 69,112
--------- ---------- -------- ------- ------- -------- ---------
$ 352,780 $ 72,347 $ 3,029 $ 47,858 $ 2,747 $ (7,270) $ 384,821
--------- -------- ------- ------- -------- ---------
Miscellaneous Amortization 1,583
----------
Total Depreciation, Depletion
and Amortization Expense $ 73,930
----------
</TABLE>
57
<PAGE>
SCHEDULE VIII
THE BROOKLYN UNION GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED SCHEDULE OF VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED SEPTEMBER 30, 1994, 1993 AND 1992
---------------------------------------------------------------
(Thousands of Dollars)
<TABLE>
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
Balance at Additions Balance at
Beginning Charged to End of
Description of Period Expense Deductions Period
- - --------------------------------------- ------------- -------------- -------------- --------------
<S> <C> <C> <C> <C>
Year Ended September 30, 1994
Allowance for uncollectible accounts $14,212 $18,737 $17,986 (a) $14,963
------------- -------------- -------------- --------------
Reserve for injuries and damages
Public liability $5,000 $3,447 $3,097 (b) $5,350
Workers' compensation $1,816 $0 $391 (b) $1,425
------------- -------------- -------------- --------------
$6,816 $3,447 $3,488 $6,775
============= ============== ============== ==============
Year Ended September 30, 1993
Allowance for uncollectible accounts $11,609 $19,113 $16,510 (a) $14,212
------------- -------------- -------------- --------------
Reserve for injuries and damages $6,900 $3,241 $3,325 (b) $6,816
------------- -------------- -------------- --------------
Year Ended September 30, 1992
Allowance for uncollectible accounts $10,336 $15,950 $14,677 (a) $11,609
------------- -------------- -------------- --------------
Reserve for injuries and damages $4,204 $6,961 $4,265 (b) $6,900
COLUMN A ------------- -------------- -------------- --------------
</TABLE>
(a) Write-off of bad debts, net of recoveries.
(b) Settlements of injury and damage claims.
58
<PAGE>
SCHEDULE X
THE BROOKLYN UNION GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED SUPPLEMENTARY INCOME STATEMENT INFORMATION
FOR THE YEARS ENDED SEPTEMBER 30, 1994, 1993 AND 1992
-----------------------------------------------------------------------------
(Thousands of Dollars)
<TABLE>
<CAPTION>
GENERAL TAXES
---------------------------------------------------
1994 1993 1992
------------ ---------------- ---------------
<S> <C> <C> <C>
Real estate $ 8,622 $ 11,730 $ 11,000
Special franchise 30,190 25,759 25,400
State excise 52,740 52,257 49,019
City excise 28,037 25,752 23,714
Gross earnings and dividends 14,083 13,756 12,198
Payroll 15,292 14,458 12,710
Other 7,549 7,264 8,261
------------ ---------------- ---------------
$ 156,513 $ 150,976 $ 142,302
Less-Amount charged to
other accounts $ 5,770 $ 6,149 $ 6,753
------------ ---------------- ---------------
Total general taxes $ 150,743 $ 144,827 $ 135,549
============ ================ ===============
</TABLE>
The above General Taxes together with the other amounts reported as maintenance,
depreciation and depletion shown in the Consolidated Statement of Income
represent all significant supplementary income statement information.
59
<PAGE>
(a) 3. Exhibits
- - ------------------
(3) Articles of incorporation and by-laws
By-laws of the Company, dated April 26, 1989, incorporated by reference
from Form S-8 Registration Statement No. 33-29898 amendment dated July 27,
1994 incorporated by reference from Exhibit 4(a) to Post-Effective
Amendment No. 1 to For S-8 Registration Statement No. 33-51561.
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 May 15, 1985, respective of $98,500,000 New York
State Energy Research and Development Authority, 9% Gas Facilities
Refunding Revenue Bonds Series 1985A, incorporated by reference from
Form 10-K for the year ended September 30, 1985.
Participation Agreement, dated as of May 15, 1985, between the New York
State Energy Research and Development Authority and The Brooklyn Union
Gas Company relating to the 9% Gas Facilities Refunding Revenue Bonds
Series 1985A, incorporated by reference from Form 10-K for the year
ended September 30, 1985.
Indenture of Trust, dated as of May 15, 1985, between the New York State
Energy Research and Development Authority and Chemical Bank, as
Trustee, relating to 9% Gas Facilities Refunding Revenue Bonds Series
1985A, incorporated by reference from Form 10-K for the year ended
September 30, 1985.
Official Statement, dated July 17, 1985, respective of $55,000,000 of New
York State Energy Research and Development Authority, 8-3/4% Gas
Facilities Revenue Bonds Series 1985, incorporated by reference from
Form 10-K for the year ended September 30, 1985.
Participation Agreement, dated as of July 1, 1985, between the New York
State Energy Research and Development Authority and The Brooklyn Union
Gas Company relating to the 8-3/4% Gas Facilities Revenue Bonds Series
1985, incorporated by reference from Form 10-K for the year ended
September 30, 1985.
Indenture of Trust, dated as of July 1, 1985, between the New York State
Energy Research and Development Authority and Chemical Bank, as
Trustee, relating to 8-3/4% Gas Facilities Revenue Bonds Series 1985,
incorporated by
60
<PAGE>
reference from Form 10-K for the year ended September 30, 1985.
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.
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,
61
<PAGE>
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.
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.
62
<PAGE>
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.
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
63
<PAGE>
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.
(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.
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.
(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, 1994, 1993 and 1992," 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 for the quarter ended September 30,
1994.
64
<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 21, 1994.
THE BROOKLYN UNION GAS COMPANY
SIGNATURE TITLE
--------- -----
[S] [C]
/s/Robert B. Catell President and Chief Executive
- - ----------------------------- Officer
(Robert B. Catell)
/s/Craig G. Matthews Executive Vice President
- - -----------------------------
(Craig G. Matthews)
/s/Vincent D. Enright Senior Vice President and
- - ----------------------------- Chief Financial Officer
(Vincent D. Enright)
/s/Richard M. Desmond Vice President, Comptroller
- - ----------------------------- and Chief Accounting
(Richard M. Desmond) 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/Edward D. Miller Director
- - -----------------------------
(Edward D. Miller)
/s/Richardson Pratt, Jr. Director
- - -----------------------------
(Richardson Pratt, Jr.)
/s/James Q. Riordan Director
- - -----------------------------
(James Q. Riordan)
65
<PAGE>
Exhibit 12
THE BROOKLYN UNION GAS COMPANY AND SUBSIDIARIES
Computation of Consolidated Ratio of Earnings to Fixed Charges
--------------------------------------------------------------
<TABLE>
<CAPTION>
Fiscal Year Ended September 30,
--------------------------------------------------------------------------
1994 1993 1992 1991 1990
---------- ---------- ----------- ----------- ----------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Earnings
Net Income $ 87,384 $ 76,563 $ 59,873 $ 61,809 $ 56,436
Federal Income Tax 40,698 41,483 29,219 23,640 16,882
Interest on Long-Term Debt 48,084 46,353 40,990 38,162 40,859
Other Interest Charges 2,044 2,059 1,589 2,734 4,752
Amortization of Debt Premium
and Expenses, Net 743 558 457 1,013 1,026
Portion of Rentals Representing
Interest 5,196 4,256 5,310 1,401 1,345
Adjustments Related to Equity
Investments (601) 729 3,239 1,524 (213)
Earnings Available to Cover ---------- ---------- ----------- ---------- ----------
Fixed Charges $ 183,548 $ 172,001 $ 140,677 $ 130,283 $ 121,087
========== ========== =========== ========== ==========
Fixed Charges *
Interest on Long-Term Debt $ 49,280 $ 47,017 $ 41,766 $ 39,063 $ 41,937
Other Interest Charges 2,044 2,059 1,589 2,734 4,752
Amortization of Debt Premium
and Expenses, Net 743 558 457 1,013 1,026
Portion of Rentals Representing
Interest 5,196 4,256 5,310 1,401 1,345
---------- ---------- ----------- ----------- ----------
Total Fixed Charges $ 57,263 $ 53,890 $ 49,122 $ 44,211 $ 49,060
========== ========== =========== =========== ==========
Ratio of Earnings to Fixed
Charges 3.21 3.19 2.86 2.95 2.47
========== ========== =========== =========== ==========
</TABLE>
* Includes capitalized interest of $1,196,225 in 1994, $663,836 in 1993,
$775,726 in 1992, $901,137 in 1991 and $1,078,000 in 1990.
<PAGE>
Exhibit 21
PRINCIPAL OPERATING SUBSIDIARIES
--------------------------------
FUEL RESOURCES INC.
1330 Post Oak Boulevard
Houston, Texas 77056
R. Gerald Bennett
President and Chief Executive Officer
THE HOUSTON EXPLORATION COMPANY
1331 Lamar
Houston, Texas 77010
James G. Floyd
President and Chief Executive Officer
BRING GAS SERVICES CORP.
1330 Post Oak Boulevard
Houston, Texas 77056
Lyndell E. Maddox
President and Chief Operating Officer
SOLEX ENERGY COMPANY, INC.
421 7th Avenue S.W.
Suite 1920
Calgary, Alberta, Canada T2P 4K8
Kevin Jabusch, President
GAS ENERGY INC.
GAS ENERGY COGENERATION INC.
111 Livingston Street
Brooklyn, New York 11201
David S. Milne, Jr.
President and Chief Executive Officer
<PAGE>
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 File Nos. 33-66182, 33-61283 and 33-51561.
ARTHUR ANDERSEN LLP
December 21, 1994
New York, New York
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<MULTIPLIER> 1
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> SEP-30-1994
<PERIOD-START> OCT-01-1993
<PERIOD-END> SEP-30-1994
<EXCHANGE-RATE> 1
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,244,527,000
<OTHER-PROPERTY-AND-INVEST> 252,052,000
<TOTAL-CURRENT-ASSETS> 385,198,000
<TOTAL-DEFERRED-CHARGES> 147,297,000
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,029,074,000
<COMMON> 15,862,000
<CAPITAL-SURPLUS-PAID-IN> 478,908,000
<RETAINED-EARNINGS> 279,466,000
<TOTAL-COMMON-STOCKHOLDERS-EQ> 774,236,000
0
7,200,000
<LONG-TERM-DEBT-NET> 701,377,000
<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> 545,961,000
<TOT-CAPITALIZATION-AND-LIAB> 2,029,074,000
<GROSS-OPERATING-REVENUE> 1,338,630,000
<INCOME-TAX-EXPENSE> 41,619,000
<OTHER-OPERATING-EXPENSES> 1,162,707,000
<TOTAL-OPERATING-EXPENSES> 1,204,326,000
<OPERATING-INCOME-LOSS> 134,304,000
<OTHER-INCOME-NET> 4,272,000
<INCOME-BEFORE-INTEREST-EXPEN> 138,576,000
<TOTAL-INTEREST-EXPENSE> 51,192,000
<NET-INCOME> 87,384,000
351,000
<EARNINGS-AVAILABLE-FOR-COMM> 87,033,000
<COMMON-STOCK-DIVIDENDS> 63,652,000
<TOTAL-INTEREST-ON-BONDS> 46,200,000
<CASH-FLOW-OPERATIONS> 194,021,000
<EPS-PRIMARY> 1.85
<EPS-DILUTED> 1.85
</TABLE>
