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, 1995
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-722
THE BROOKLYN UNION GAS COMPANY
(Exact name of Registrant as specified in its charter)
New York 11-0584613
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
ONE METROTECH CENTER, BROOKLYN, NEW YORK 11201-3850
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code 718-403-2000
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange on
Title of Each Class Which Registered
Common Capital 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 13, 1995 was $1,385,422,629.
On December 13, 1995 the Company had 49,041,509 shares of
Common Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Part of
Documents Form 10-K
Definitive Proxy Statement dated December 28, 1995 Part III
PART I
Item 1. Business
The Company 2
Subsidiaries 3
Gas Supply 5
Regulation and Rate Matters 6
Competition 7
Research and Development 8
Employees 8
Environmental Matters 9
Item 2. Properties 9
Item 3. Legal Proceedings 10
Item 4. Submission of Matters to a Vote of Security
Holders 10
PART II
Item 5. Market for the Registrant's Common Stock and
Related Security Holder Matters 10
Item 6. Selected Financial Data 13
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 14
Item 8. Financial Statements and Supplementary Data 23
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 47
PART III
Item 10. Directors and Executive Officers of the
Registrant 47
Item 11. Executive Compensation 47 & 49
Item 12. Security Ownership of Certain Beneficial Owners
and Management 47
Item 13. Certain Relationships and Related Transactions 47
Part IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 48
Signatures 56
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, 1995, the Company had
approximately 1,125,000 active meters, of which approximately
1,086,000 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. Financial and other information is also
available through the World Wide Web at http://www.bug.com.
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 Rate Matters"). Also, results of
operations are affected by the timing and amounts of approved rate
changes.
The heating capacity of gas is measured in therms. One therm
equals 100,000 BTUs, the heat content of approximately 100 cubic
feet of natural gas. The heat content of approximately 1,000,000
cubic feet of gas represents 10,000 therms or 1 MDTH. Accordingly,
one billion cubic feet (BCF) of gas equals approximately 1,000
MDTH.
For the fiscal year ended September 30, 1995, utility firm gas
sales were 123,356 MDTH, of which 75% were residential, 12%
commercial, 8% governmental and 5% industrial. Other utility gas
sales and transportation deliveries to off-system and interruptible
customers amounted to 49,910 MDTH. In addition, utility capacity
release transactions amounted to approximately 32,170 MDTH.
Subsidiaries
The PSC has authorized the Company to invest up to 20% of its
consolidated capitalization in non-utility energy-related
businesses through fiscal 1996. This authorization is based upon
the Company's cash investments less dividends received. At
September 30, 1995, the total investment in non-utility
subsidiaries computed on this basis was approximately 14% of
capitalization. In August 1995, the Company filed a petition with
the PSC to organize its utility operations and those of its
subsidiaries within a holding company. (See Part II, Item 7.,
"Management's Discussion and Analysis of Financial Condition and
Results of Operations - 'Rate and Regulatory Matters - Holding
Company Petition and Price Cap Proposal'.") If the holding company
petition is approved, the Company will no longer require this
investment authorization.
The Company's principal wholly-owned subsidiaries participate
and own investments in gas exploration, production, marketing, and
cogeneration. Subsidiaries also have minority interests in pipeline
and storage projects. In fiscal 1995, earnings from subsidiaries
were $12.8 million, or 27 cents per share, representing 14% 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."
Gas Exploration, Production and Marketing
Fuel Resources Inc. (FRI) operates in the Arkoma Basin, and
its subsidiaries operate in West Virginia, East Texas and Canada.
The Houston Exploration Company (THEC) operates in the Gulf of
Mexico. In 1995, total gas production was approximately 23 BCF and
proved net gas reserves at year-end were 202 BCF. Such reserves
are divided equally between FRI and THEC. (For additional
information, see Part II, Item 8., "Financial Statements and
Supplementary Data," Note 8., "Supplemental Gas and Oil
Disclosures.")
BRING Gas Services Corp. (BRING), FRI's marketing subsidiary,
combined its operations with those of Pennzoil Gas Marketing, Inc.,
a wholly-owned subsidiary of Pennzoil Corporation, effective as of
April 1, 1995. BRING owns a 50% equity interest in the new entity,
PennUnion Energy Services, L.L.C.
Solex Energy Company, Inc., FRI's Canadian affiliate, acquired
an operating gas processing plant located in British Columbia,
Canada in 1995.
Investments 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 a 100-
megawatt facility at John F. Kennedy International Airport (JFK) in
Queens, New York. This facility commenced operations in 1995. In
October 1993, GEI purchased an 11.3% interest in a previously
completed 174-megawatt gas cogeneration plant located in Lockport,
New York. GECI is a 50% partner in a 40-megawatt facility that
serves the State University of New York at Stony Brook, Long
Island. This facility also commenced operations in 1995.
Additionally, GECI is a 45% partner in a 50-megawatt gas
cogeneration plant that has been producing heat and power at a
Northrop Grumman facility located in Bethpage, Long Island, New
York.
The scope of cogeneration activities also includes providing
fuel-management services. GEI subsidiaries provide such services
to the JFK, Stony Brook and Northrop Grumman facilities and to
another 50-megawatt facility which provides heating and cooling to
Nassau Veterans Memorial Coliseum and Nassau Community College. In
1995, these subsidiaries, as fuel managers, provided 12,700 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 that currently transports more than 800 MDTH of
Canadian gas supply daily to markets in the northeastern United
States. The Company currently receives up to 70 MDTH of gas per
day through Iroquois. For information regarding governmental
investigations of alleged violations involving the Iroquois
project, see Part II, Item 8., "Financial Statements and
Supplementary Data," Note 6., "Investment in Iroquois Pipeline."
Through its affiliates, Brooklyn Union has equity investments
in two gas storage facilities located in New York State.
Gas Supply
General
Changes in regulatory policies and market forces have shifted
the industry from traditional cost-based regulation involving gas
sales, transportation, storage and other related services on a
bundled basis by the interstate pipelines toward market-based sales
on an unbundled basis. These policy changes have made the market
more competitive with respect to gas supply and related services.
Accordingly, the PSC has initiated a proceeding to establish policy
and implement utility tariff revisions in line with market
objectives of providing utility customers with wider choices in gas
supply and related services at the local level. (See Part II, Item
7., "Management's Discussion and Analysis of Financial Condition
and Results of Operations - 'Rate and Regulatory Matters -
Restructuring Proceeding'.") This proceeding could affect utility
gas merchant activities and the Company is managing its gas
procurement practices accordingly.
In 1995, 66% of gas supply was purchased from domestic sources
under long-term contracts, 23% from Canadian sources under long-
term contracts and 11% from spot market sources.
The Company opened the first New York-based market hub for
buyers and sellers of natural gas in the Northeast in fiscal 1994.
With interconnections and access to several major pipelines, the
New York Market Hub offers transportation, balancing and exchange
services to a wide variety of customers, including utilities,
municipalities, marketers and large-volume customers. In 1995, the
Company delivered 39,200 MDTH of gas and related services to
customers in 16 states as well as Washington, D.C. and Ontario,
Canada. In addition, capacity release transactions amounted to
approximately 32,170 MDTH.
Long-Term Supply
Under long-term contracts and regulatory certificates
applicable to gas supply and pipeline transportation and storage
services, the Company's suppliers will provide maximum firm daily
total deliveries of 966 MDTH of gas for the 1995-96 winter,
consisting of 376 MDTH per day of firm domestic gas supply, 100
MDTH per day of firm Canadian gas supply and 490 MDTH per day of
domestic storage and winter services.
The Company's major providers of domestic interstate pipeline
capacity and related services are: Transcontinental Gas PipeLine
Corporation, Texas Eastern Transmission Corporation, Tennessee Gas
Pipeline Company (Tennessee), CNG Transmission Corporation and
Texas Gas Transmission Company, 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
U.S. supplies are 866 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.
Spot Market Supply
The Company continues to purchase gas on the spot market when
contractually and economically feasible. In fiscal 1995, spot
purchases totaled 17,756 MDTH of gas.
Peak-day Supply
The Company plans for peak-day demand on the basis of an
average temperature of 0oF. Gas demand on such a design peak-day
is estimated at 1,128 MDTH during the 1995-96 winter. The highest
24-hour firm sendout experienced by the Company was 1,022 MDTH on
January 19, 1994, when the average temperature was 4oF.
For the 1995-96 winter, the Company has the capability to
provide a maximum peak-day supply of approximately 1,257 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 $3.12
per DTH in fiscal 1995, $3.55 per DTH in 1994 and $3.49 per DTH in
1993. Gas prices have been competitive with costs of most other
energy sources, including alternate grades of fuel oil, although
gas continues to be priced at some premium to No. 2 grade fuel oil.
Gas costs reflect the results of the Company's hedging program.
Regulation and Rate Matters
Utility retail sales, which include sales of gas,
transportation and balancing services by the Company, are made
primarily under rate schedules and tariffs filed with and subject
to the jurisdiction of the PSC. 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, subject to
sharing provisions.
Service is provided to certain large-volume customers,
principally in the multi-family and commercial markets, under a
temperature controlled (TC) rate that is competitive with the price
of 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.
Further, the PSC has authorized more pricing flexibility to
the Company in the TC market. The Company offers negotiated
"customized" rates to large-volume customers both within and
outside its service territory. In some instances, the Company uses
financial instruments to protect margins on these sales. ( See
Part II, Item 8., "Financial Statements and Supplementary Data,"
Note 5B., "Derivative 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. Effective October 1,
1994, the adjustment was modified to exclude weather variations
(positive or negative) of less than 2.2% from normal during each
billing cycle.
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'." 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 - Regulatory Assets'."
Competition
As discussed above, changes in Federal and more recently State
regulatory policies have resulted in increased competition in
interstate and local gas markets. The Company has responded to
these changes by increasing sales to off-system customers,
primarily through its New York Market Hub, while maintaining its
position in local markets for which new tariffs have been filed
with the PSC in accordance with its restructuring proceeding. (See
Part II, Item 7., "Management's Discussion and Analysis of
Financial Condition and Results of Operations - 'Rate and
Regulatory Matters - Restructuring Proceeding'.")
In local markets, gas also competes with fuel oil. The
Company has expanded existing markets and is developing new ones to
increase gas sales. In the residential heating market, gas is sold
in competition with No. 2 grade fuel oil. During the year, gas at
the burner tip was generally competitive with alternate grades of
fuel oil, although it was priced at some premium to No. 2 grade
fuel oil. Conversions from oil to gas heat continued during fiscal
1995. Approximately 77% 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.
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 Company continues to be committed to obtaining greater
operational efficiencies, through workforce reductions achieved
through early retirement programs and normal attrition, as well as
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 gas facilities is tax-exempt.
Research and Development
In fiscal 1995, the Company spent $11.9 million on research
and development (R&D) programs. Of this amount, $2.1 million went
to support programs of the Gas Research Institute. The Company also
provided $2.7 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 $7.1 million was devoted primarily to the
Company's internal R&D programs relating to efficient gas
utilization and operations technologies. These programs include
development and demonstration of gas heat pumps, fuel cells, new
technologies to reduce meter reading costs and vehicles powered by
compressed natural gas, as well as refueling stations. In
addition, the Company made significant efforts to develop
innovative operation systems which reduce utility costs. These new
systems deploy state-of-the-art hardware such as pen-based hand-
held computers and object-oriented software for precise risk
analysis and modeling.
Employees
The Company and its subsidiaries employed 3,378 people at
September 30, 1995, compared to 3,506 at September 30, 1994. The
decrease reflects normal workforce reductions and the effect of
early retirement programs.
In November 1995, a new labor agreement was ratified by the
membership of Local 101 of the Transport Workers Union, which
represents approximately 1,900 employees. The agreement provides
for total wage increases of approximately 9.3% over its three-year
term. The agreement also provides certain productivity savings and
a gainsharing incentive tied to attainment of certain corporate
goals. A similar agreement applicable to 200 employees represented
by Local 3 of the International Brotherhood of Electrical Workers
was ratified in August 1995.
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."
Item 2. Properties
In fiscal 1995, consolidated capital expenditures were $214.0
million, of which $108.7 million was primarily for utility property
additions and $105.3 million was for subsidiaries. Consolidated
capital expenditures are estimated to be approximately $195 million
for each of fiscal years 1996 and 1997.
The Company holds franchises to lay gas mains in the streets,
highways and public places in the Boroughs of Brooklyn and Staten
Island, and the former Second and Fourth Wards of the Borough of
Queens. The Company has consents and permits which, with
immaterial exceptions, give it the right to carry on its utility
operations, substantially as now carried on, in the territory
served. The Company's franchises are unlimited in duration, except
that a franchise to transmit and distribute gas in the former Fifth
Ward of the Borough of Staten Island expires in 2006. Gas sales
revenues in the former Fifth Ward are approximately 2.4% of the
total gas sales revenues of the Company.
As of September 30, 1995, the Company's distribution pipeline
system consisted of approximately 2,005 miles of cast iron main,
1,680 miles of steel main and 255 miles of mains with plastic
inserts, with requisite accessory compressor and regulating
stations, and one gas storage holder having a capacity of 15 MDTH.
The distribution system for the most part is located under public
streets.
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 16 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
$14.3 million per year.
Principal consolidated properties of subsidiaries and their
affiliates include gas and oil leasehold interests, producing wells
and related equipment and structures.
For information 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 Statements
and Supplementary Data," Note 8., "Supplemental Gas and Oil
Disclosures."
Item 3. Legal Proceedings
For information regarding governmental investigations of
alleged violations involving the Iroquois project, see Part II,
Item 8., "Financial Statements and Supplementary Data," Note 6.,
"Investment in Iroquois Pipeline." For information regarding
environmental matters affecting the Company, see Part II, Item 7.,
"Management's Discussion and Analysis of Financial Condition and
Results of Operations - Environmental Matters," and Part II, Item
8., "Financial Statements and Supplementary Data," Note 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 BrklyUG 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 1,
1996.
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
SUPPLEMENTARY INFORMATION (UNAUDITED)
QUARTERLY INFORMATION
SUMMARY OF QUARTERLY INFORMATION
The following is a table of financial data for each quarter of fiscal 1995 and 1994. 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.
First Second Third Fourth
Quarter Quarter Quarter Quarter
(Thousands of Dollars Except Per Share Data)
1995
Operating revenues 358,348 481,615 217,696 158,625
Operating income(loss) 55,153 85,902 6,326 (8,871)
Income (loss) applicable
to common stock 42,753 73,555 (6,188) (18,622)
Per common share:
Earnings (loss) (a) 0.90 1.53 (0.13) (0.38)
Dividends declared 0.3475 0.3475 0.3475 0.3475
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
(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.
SUMMARY OF QUARTERLY STOCK INFORMATION
First Second Third Fourth
Quarter Quarter Quarter Quarter
1995
High 25 3/8 24 3/4 26 3/8 26 3/8
Low 21 1/2 22 23 3/4 23 1/4
Close 22 1/4 24 1/8 26 1/4 24 5/8
Shares Traded (000) 2,695 3,977 2,543 3,219
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
Item 6. Selected Financial Data
For the Year Ended September 30, 1995 1994 1993 1992 1991
(Thousands of Dollars Except Per Share Data)
Income Summary
Operating revenues
Utility sales $1,152,331 $1,279,638 $1,145,315 $1,038,061 $951,711
Gas production and other 63,953 58,992 60,189 36,799 25,550
Total operating revenues 1,216,284 1,338,630 1,205,504 1,074,860 977,261
Operating expenses
Cost of gas 446,559 560,657 466,573 402,137 373,048
Operation and maintenance 381,194 381,696 363,792 333,984 302,171
Depreciation and depletion 72,020 69,611 64,779 73,930 42,644
General taxes 134,718 150,743 144,827 135,549 136,245
Federal income tax 43,283 41,619 42,433 30,812 27,017
Operating income 138,510 134,304 123,100 98,448 96,136
Income (loss) from energy services
investments 9,458 5,689 1,150 (1,041) 136
Gain on sale of investment in
Canadian gas company - - 20,462 - -
Write-off of investment in propane
company - - (17,617) - -
Other, net (4,309) (2,338) (3,379) 2,935 2,949
Federal income tax benefit 1,243 921 950 1,593 3,050
Interest charges 53,067 51,192 48,103 42,062 40,462
Net income 91,835 87,384 76,563 59,873 61,809
Dividends on preferred stock 337 351 364 2,078 3,847
Income available for common stock $91,498 $87,033 $76,199 $57,795 $57,962
Financial Summary
Common stock information
Per share
Earnings ($) 1.90 1.85 1.73 1.35 1.45
Cash dividends declared ($) 1.39 1.35 1.32 1.29 1.27
Book value, year-end ($) 16.94 16.27 15.55 14.56 14.37
Market value, year-end ($) 24 5/8 24 7/8 25 3/4 22 3/8 20 5/8
Average shares outstanding (000) 48,211 46,980 44,042 42,882 39,894
Shareholders 33,669 35,233 30,925 31,367 30,749
Daily average shares traded 49,100 42,100 33,100 26,900 30,500
Capital expenditures ($) 214,006 199,572 204,514 173,467 147,745
Total assets ($) 2,116,922 2,029,074 1,897,847 1,748,027 1,717,493
Common equity ($) 826,290 774,236 721,076 632,254 607,573
Preferred stock, redeemable ($) 6,900 7,200 7,500 7,800 44,467
Long-term debt ($) 720,569 701,377 689,300 682,031 685,413
Total capitalization ($) 1,553,759 1,482,813 1,417,876 1,322,085 1,337,453
Earnings to fixed charges (times) 3.17 3.21 3.19 2.86 2.95
Utility Operating Statistics
Gas data (MDTH)
Firm sales 123,356 133,513 128,972 122,476 108,694
Other gas and transportation 49,910 42,392 25,032 23,706 15,963
Maximum daily capacity, year-end 1,256 1,256 1,258 1,199 1,179
Maximum daily sendout 963 1,022 915 904 837
Total active meters (000) 1,125 1,122 1,119 1,117 1,111
Heating customers (000) 454 446 441 436 428
Degree days 4,240 4,974 4,802 4,659 3,971
Colder (Warmer) than normal (%) (11.2) 3.1 - (4.0) (19.0)
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations
Earnings and Dividends
In fiscal 1995, consolidated income available for common stock
was $91.5 million, or $1.90 per share, compared to $87.0 million,
or $1.85 per share, in 1994, and $76.2 million, or $1.73 per share,
in 1993. This was the third consecutive year of record earnings.
Consolidated earnings, including income from equity
investments, for the last three fiscal years are summarized below:
__________________________________________________________________________
1995 1994 1993
__________________________________________________________________________
(Thousands of Dollars)
Income Available for Common Stock
Utility $78,677 $76,665 $69,083
_________________________________________________________________________
Gas exploration and production
Operations
United States 7,849 5,707 2,707
Canadian (includes gas processing) 227 - 2,739
Gain on sale of Canadian investment - - 12,500
__________________________________________________________________________
8,076 5,707 17,946
_________________________________________________________________________
Energy services
Pipeline and other 2,075 3,358 2,792
Cogeneration 2,670 1,303 907
Propane
Operations - - ( 3,078)
Write-off - - (11,451)
__________________________________________________________________________
4,745 4,661 (10,830)
__________________________________________________________________________
Consolidated $91,498 $87,033 $76,199
__________________________________________________________________________
In 1995, utility operations provided an equity return of
12.3%. The return, which included incentives authorized by the New
York State Public Service Commission (PSC), was higher than the
allowed rate of 11.0%. The Company has earned at or above its
allowed return on utility common equity in 16 of the last 17 years.
In the last three years, income available for common stock
from utility operations has benefited from additions of new firm
gas heating customers, principally as a result of customer
conversions from oil to gas for space heating in homes and
buildings, rate relief and earnings incentives provided under rate
stipulations (see "Rate and Regulatory Matters"). In 1995, such
incentive-based earnings were related largely to higher margins on
sales to large-volume customers and attaining a 95% customer
satisfaction rating in benchmarks used by the PSC. The effect on
utility revenues of variations in weather largely was offset by the
weather normalization adjustment included in the Company's tariff.
However, effective October 1, 1994, the adjustment was modified to
exclude weather variations (positive or negative) of less than 2.2%
from normal. This modification adversely affected utility net
revenues by approximately $4.9 million in 1995. Sales growth
normalized for weather slackened from levels attained in recent
years. Utility operating margins have improved due to cost
reduction efforts.
In 1995, earnings from gas exploration and production
increased despite lower market prices. In 1994 and 1993, earnings
from gas exploration and production operations increased primarily
due to higher U.S. production. In 1993, earnings also 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.
Canadian gas processing operations began anew in 1995.
Earnings from investments in energy services are attributable
to a number of factors. Earnings from pipeline and other in all
periods reflect higher throughput on the Iroquois Gas Transmission
System, L.P., in which a Company subsidiary holds an 11.4%
interest. In 1995, earnings were reduced by a provision for the
subsidiary's proportionate share of estimated costs of legal
matters involving the Iroquois project. Higher earnings from
cogeneration investments reflect equity income from gas-fired
plants at John F. Kennedy International Airport and the campus of
the State University of New York at Stony Brook, both of which were
completed in 1995, and the acquisition in 1994 of an interest in a
previously completed cogeneration plant located in Lockport, New
York.
The consolidated rate of return on average common equity was
10.9% in 1995, compared to 11.0% in 1994 and 10.9% in 1993.
In December 1994, the Board of Directors authorized an
increase in the annual dividend on common stock to $1.39 per share
from $1.35 per share. This increase became effective on February
1, 1995, when the quarterly dividend was raised to 34 3/4 cents per
share from 33 3/4 cents per share. Common dividends have been
increased in 19 consecutive years and paid continuously for 47
years.
Sales, Gas Costs and Net Revenues
Firm utility gas sales volume in fiscal 1995 was 123,356 MDTH
compared to 133,513 MDTH in 1994 and 128,972 MDTH in 1993.
Measured by annual degree days, weather was 11.2% warmer than
normal in 1995, 3.1% colder than normal in 1994 and normal in 1993.
Sales growth in all markets resulted primarily from conversions to
natural gas from oil for space heating, especially by large
apartment buildings. In 1995, the growth in firm sales normalized
for weather fell short of the rate experienced in recent years,
reflecting reduced consumption per customer related to the
extremely warm weather.
_________________________________________________________________
1995 1994 1993
_________________________________________________________________
(Thousands of Dollars)
Utility sales $ 1,152,331 $ 1,279,638 $ 1,145,315
Cost of gas (446,559) (560,657) (466,573)
_________________________________________________________________
Net revenues $ 705,772 $ 718,981 $ 678,742
_________________________________________________________________
Gas production
and other $ 63,953 $ 58,992 $ 60,189
_________________________________________________________________
In 1995, lower utility sales primarily reflect lower billings
for gas costs due to warm weather. Further, utility sales (and net
revenues) reflect reductions of approximately $13.2 million related
to sharing of margins on sales to certain large-volume customers.
As previously mentioned, modification of the weather normalization
adjustment caused a reduction in utility net revenues of $4.9
million in 1995. For additional information regarding utility
sales and net revenues in the last three years, see "Rate and
Regulatory Matters."
During the year, gas at the burner tip was competitive with
alternative grades of fuel oil, although it continued to be 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 75% of
firm sales volume in 1995. Demand in these markets is less
sensitive to periodic differences between gas and oil prices. In
large-volume heating markets, gas service is provided under rates
that are set to compete with prices of alternative fuel, including
No. 6 grade heating oil. There is substantial sales potential in
these markets, which include large apartment houses, government
buildings and schools.
Moreover, a significant market for off-system sales has
developed as a result of Federal Energy Regulatory Commission
(FERC) initiatives. In 1995, other gas and transportation sales to
off-system and interruptible customers amounted to 49,910 MDTH. In
addition, capacity release transactions amounted to approximately
32,170 MDTH. These revenue producing transactions reflect optimal
use of available pipeline capacity and the Company's New York-based
market hub.
The cost of gas, $446.6 million in 1995, was $114.1 million or
20.4% lower than in 1994. The lower cost reflects lower heating
sales due to warmer weather and lower average gas prices. The cost
of gas for firm customers was $3.12 per DTH (one DTH equals 10
therms) in 1995, compared to $3.55 per DTH in 1994 and $3.49 per
DTH in 1993.
The Company and its gas exploration and production subsidiary
employ derivative financial instruments, natural gas futures and
swaps, for the purpose of managing commodity price risk. In
connection with utility operations, the Company primarily uses
derivative financial instruments to fix margins on sales to large-
volume customers to which gas is sold at a price indexed to the
prevailing price of oil, their alternate fuel. Derivative
financial instruments are used by the Company's gas exploration and
production subsidiary to manage the risk associated with
fluctuations in the price received for natural gas production.
Hedging strategies are managed independently. (See Part II, Item
8., "Financial Statements and Supplementary Data," Note 5B.,
"Derivative Financial Instruments," for additional information.)
The increase in revenues from gas production and other in 1995
is due to the acquisition of a gas processing plant located in
British Columbia, Canada by the Company's Canadian affiliate.
Revenues from U.S. operations were down as a result of lower
production and pricing due to reduced demand related to weather.
In 1995, gas production was approximately 22.7 billion cubic feet
(BCF), or 0.7 BCF below last year's production. Wellhead prices
prevailing in 1995 were lower than in 1994. However, hedging
helped reduce the adverse effects of lower wellhead prices. In
1995, wellhead prices averaged approximately $1.47 per MCF compared
to $1.97 per MCF last year. The effective price (average wellhead
price received for production including realized hedging gains and
losses) was $1.77 per MCF in 1995 compared to $1.84 per MCF in
1994. The decrease in revenues from gas production and other in
1994 is due to the sale of Canadian gas exploration and production
operations at the end of 1993 to realize the profit and value
embodied in the investment. (See Part II, Item 8., "Financial
Statements and Supplementary Data," Note 8., "Supplemental Gas and
Oil Disclosures," for additional information.)
Expenses, Other Income and Preferred Dividends
The decrease in operation expense in 1995 reflects the effects
of warm weather compared to last year and various cost reduction
efforts. In 1994, severe winter weather caused higher utility gas
distribution operation expense. The benefit of ongoing cost
reduction programs substantially outweighed the adverse effects of
generally higher labor and material costs. Moreover, consolidated
operation expense in 1995 included approximately $9.0 million of
costs related to Canadian gas processing operations, which
commenced anew in the second half of the year. Maintenance expense
includes costs related to city and state construction projects.
The increase in depreciation and depletion expense in 1995
reflects higher depreciation charges related to utility property
additions. The effect of higher utility depreciation expense more
than offset lower depletion expense due to reduced gas production
of subsidiaries. The increase in consolidated expense in 1994
reflects higher utility depreciation expense as well as higher
depletion charges related to increased gas production in that year.
General taxes principally include state and city taxes on
utility revenues and property. The applicable property base
generally has increased, although the Company has been able to
realize significant savings by the aggressive pursuit of reductions
in property value assessments. Taxes based on revenues reflect the
variations in utility revenues each year.
Federal income tax expense reflects changes in pre-tax income.
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 in each of the last three
fiscal years generally reflect higher average subsidiary
borrowings. Other interest expense primarily reflects accruals of
carrying charges related to regulatory settlement items.
The increase in other income in 1995 primarily reflects the
increase in earnings from energy services investments as discussed
above.
Dividends on preferred stock reflect reductions in the level
of preferred stock outstanding due to sinking fund redemptions.
Capital Expenditures
Consolidated capital expenditures were $214.0 million in
fiscal 1995, $199.6 million in fiscal 1994 and $204.5 million in
1993.
Capital expenditures related to utility operations were $108.7
million in 1995, $103.8 million in 1994 and $110.8 million in 1993.
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 $28.0 million in 1995,
$28.8 million in 1994 and $24.9 million in 1993.
Capital expenditures related to gas exploration, production
and processing activities were $83.0 million in 1995, $71.3 million
in 1994 and $66.3 million in 1993. The 1995 amount reflects
increased off-shore development activities and the purchase of a
Canadian gas processing plant. Net proved gas reserves at
September 30, 1995 were approximately 202 BCF. 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 investments
were $22.3 million in 1995, $24.5 million in 1994 and $27.4 million
in 1993. Expenditures in all years were primarily related to the
construction of the John F. Kennedy International Airport
cogeneration project and, in 1995, include $5.6 million related to
the Stony Brook cogeneration plant. In 1994, capital expenditures
also include $10.9 million related to the acquisition of an
interest in a previously completed cogeneration plant located in
Lockport, New York.
Consolidated capital expenditures for fiscal years 1996 and
1997 are estimated to be approximately $195 million in each year,
including $85 million per year related to non-utility activities.
The level of such expenditures is reviewed periodically and can be
affected by timing, scope and changes in 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, 1995, the
total investment in non-utility subsidiaries computed on this basis
was approximately 14% of capitalization.
Financing
Cash provided by operating activities continues to be strong
and is the principal source for financing capital expenditures. In
1995, operating cash flow was enhanced substantially by the timing
of weather normalization and gas cost recoveries, and reflects
higher margins received from sales to large-volume customers and
market hub activities.
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 $28.0
million in 1995, $29.8 million in 1994 and $27 million in 1993.
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 5.64%. In addition, $75
million of 9 1/8% Gas Facilities Revenue Bonds was refunded in
1993. The interest rate on the refunding bonds, which mature in
2020, is 6.37%. Increased subsidiary borrowings included in long-
term debt provided an additional $19.2 million to finance
consolidated capital expenditures.
At September 30, 1995, the consolidated annualized cost of
long-term debt was 7.1%. The Company's 9% and 8.75% Gas Facilities
Revenue Bonds became callable on May 15, 1995 and July 1, 1995,
respectively, at optional redemption prices of $102. The Company
is evaluating the possibility of refunding these bond issues.
Financial Flexibility and Liquidity
At September 30, 1995, the Company had cash and temporary cash
investments of $40.5 million and available bank lines of credit of
$75 million, which lines are available to secure the issuance of
commercial paper. The lines of credit can be increased to $150
million by December 1995. Related borrowings primarily are used to
finance seasonal working capital requirements, which in recent
years have not been significant. At September 30, 1995, there were
no borrowings outstanding. In addition, subsidiaries have lines of
credit totaling $84 million, which for the most part support
borrowings under revolving loan agreements.
At September 30, 1995, the common equity component of the
Company's capitalization was 53.2%.
Fixed charge coverage ratios were 3.17 times in fiscal 1995,
3.21 times in 1994 and 3.19 times in 1993.
Rate and Regulatory Matters
Rate Settlement Plan
In October 1994, the PSC approved a new three-year rate
settlement agreement which provided for no base rate increase in
fiscal 1995; however, the Company was permitted to amortize to
income approximately $1.3 million of deferred credits. Previously,
the PSC had approved $31.3 million of additional revenues for
fiscal 1994, including $3.0 million of deferred credits, and $31.5
million of additional revenues for fiscal 1993, including $10.9
million of deferred credits.
In addition to earnings sharing provisions, the plan provides
new incentives, more flexible pricing in large-volume competitive
markets, and rate design modifications to improve the Company's
competitive position. The Company is permitted to retain 100% of
any earnings from discrete incentives (up to 100 basis points on
utility equity.) With respect to earnings sharing provisions, the
Company will retain 75% of the first 100 basis points of earnings
in excess of the allowed return on utility equity unrelated to
discrete incentives, and 50% of any additional earnings above that
level. In addition, the Company will retain a portion of margins
above a specified level of sales to certain large-volume customers.
In September 1995, the PSC approved the Company's second stage
rate filing covering fiscal 1996. The approval provides for no
base rate increase; however, it permits the amortization of $7.5
million in deferred credits. The rate of return on utility common
equity will be 10.65% for fiscal 1996, reflecting generally lower
prevailing capital costs, and the incentive provisions currently in
place would continue and remain available to permit earned rates of
return to rise above the allowed level. These revisions became
effective on October 1, 1995.
Additionally, base rate increases, if any, in the third year
of the agreement would continue to be limited to inflation and
partially would be offset by the use of additional available
credits.
Restructuring Proceeding
In December 1994, the PSC issued its order in the gas industry
restructuring case. The proceeding was instituted by the PSC in
response to the restructuring of interstate pipeline services by
FERC Order 636, which took effect in November 1993.
The PSC order addresses incentives and margin-sharing issues
in a manner that is generally consistent with the Company's current
rate settlement plan and provides utilities broad discretion to
employ market-based pricing (subject to caps) for services offered
to large-volume, or non-core, customers with dual-fuel capability.
The order allows the Company to continue to offer customers a
complete array of bundled sales services as well as gas-supply
pricing flexibility generally comparable to that offered by
unregulated competitors to large-volume customers. Further, the
Company will offer core customers, reliant solely on gas as a
heating or cooling fuel, unbundled sales and transportation,
including access to available pipeline transportation and storage
capacity. The order reduces the minimum transportation service
volume requirement for customers, while encouraging the ultimate
elimination of such a requirement. Lastly, the order initiated a
new proceeding currently underway to evaluate gas purchasing
practices and revised gas cost recovery mechanisms and invited
proposals for providing service to small-volume customers
aggregated into gas purchasing groups. The PSC also has now lifted
its orders prohibiting any Company gas marketing subsidiary from
operating within the Company's territory.
The Company is fully prepared to meet the requirements of the
PSC order. It has filed tariffs applicable to both core and non-
core markets in compliance with the PSC order, and has proposed a
pilot incentive gas cost recovery mechanism, which was approved by
the PSC in September 1995. The mechanism became effective as of
September 1, 1995, and provides for the Company to share the
benefits of, or absorb a portion of the costs related to,
variations in its weighted average cost of gas as compared with a
market-based index. Under the terms of the incentive mechanism,
the maximum award or penalty that could be realized is $2.0 million
in gas cost recoveries.
Holding Company Petition and Price Cap Proposal
The Company filed a petition with the PSC to organize its
utility operations and those of its subsidiaries within a holding
company. This form of corporate organization would provide the
Company with the flexibility to take advantage of timely investment
and market-entry opportunities and allow the Company to compete
more effectively against other energy providers. The Company plans
to expand gas marketing and energy management services to large-
volume customers, potentially through new subsidiaries to be
incorporated separately and owned by the holding company. In
conjunction with the formation of the holding company, the Company
has proposed to institute a price cap plan for gas services
provided to firm tariff customers and to modify the ratemaking
applicable to margins for large-volume, non-core transactions.
Essentially, any rate increase applicable to core customers would
be limited to general price inflation. Further, a specified level
of margins on services to non-core customers would be imputed and
reflected in overall revenue requirements at the outset of the
price cap period. Thus, the Company would realize any benefit or
loss associated with changes in such sales margins from the level
initially fixed.
Environmental Matters
The Company is subject to various Federal, state and local
laws and regulatory programs related to the environment. These
environmental laws govern both the normal, ongoing operations of
the Company as well as the cleanup of historically contaminated
properties. Ongoing environmental compliance activities, which
historically have not been material, are integrated with the
Company's regular operations and maintenance activities. As of
September 30, 1995, the Company had an accrued liability of $29.3
million and a related unamortized regulatory asset of $33.2 million
representing costs associated with investigation and remediation at
former manufactured gas plant sites. (See Part II, Item 8 .,
"Financial Statements and Supplementary Data," Note 7.,
"Environmental Matters.")
Inflation
In recent years, the impact of inflation has diminished.
Purchased gas costs are passed on to customers through the Gas
Adjustment Clause in the Company's tariff. Gas generally 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.
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.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To The Brooklyn Union Gas Company:
We have audited the accompanying Consolidated Balance Sheet and
Consolidated Statement of Capitalization of The Brooklyn Union Gas
Company (a New York corporation) and subsidiaries as of September
30, 1995 and 1994, and the related Consolidated Statements of
Income, Retained Earnings and Cash Flows for each of the three
years in the period ended September 30, 1995. 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, 1995 and 1994, and the results of their
operations and their cash flows for each of the three years in the
period ended September 30, 1995, 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
schedule listed in Item 14 is the responsibility of the Company's
management and is presented for the purpose of complying with the
Securities and Exchange Commission's rules and is not part of the
basic consolidated financial statements. This schedule has been
subjected to the auditing procedures applied in the audits of the
basic consolidated financial statements and, in our opinion, fairly
states in all material respects the financial data required to be
set forth therein in relation to the basic consolidated financial
statements taken as a whole.
ARTHUR ANDERSEN LLP
October 23, 1995
New York, New York
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. All other adjustments are of a
normal, recurring nature.
Utility Gas Property -
Depreciation and Maintenance
Utility gas property is stated at original cost of construction,
which includes allocations of overheads and taxes and an allowance
for funds used during construction.
Depreciation is provided on a straight-line basis in amounts
equivalent to composite rates on average depreciable property of
3.4% in 1995, 3.3% in 1994 and 3.2% in 1993.
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 units-of-production method and, when necessary, include
provisions related to the asset ceiling test limitations required
by the regulations of the Securities and Exchange Commission.
Costs of unevaluated gas and oil 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 assets 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.
Revenues include unbilled amounts related to the estimated gas
usage that occurred from the last meter reading to the end of each
month.
Revenue requirements to establish utility rates are based on
sales to 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 and capacity
release credits are refunded to firm customers subject to sharing
provisions in the Company's tariff. The GAC provision requires an
annual reconciliation of recoverable gas costs with GAC revenues.
Any difference is deferred pending recovery from or refund to firm
customers during a subsequent twelve-month period. Revenues also
reflect provisions for refund to firm customers of margins in
excess of tariff levels.
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. Effective
October 1, 1994, the adjustment was modified to exclude weather
variations (positive or negative) of less than 2.2% from normal
during each billing cycle.
As of April 1,1995, the Company's gas marketing activities are
being accounted for under the equity method pursuant to a
combination with Pennzoil Gas Marketing, Inc., a wholly-owned
subsidiary of Pennzoil Corporation, through a limited liability
corporation. Prior to that combination, gas sales by the Company's
marketing subsidiary were classified in gas production and other
revenue net of their related gas purchase and transportation costs.
Hedge Accounting
The Company and its gas exploration and production subsidiaries
employ derivative financial instruments, natural gas futures and
swaps, for the purpose of managing commodity price risk. Hedging
strategies are managed on an individual company basis and meet the
criteria for hedge accounting treatment under Statement of
Financial Accounting Standards (SFAS) No. 80, "Accounting for
Futures Contracts." 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 as margin positions are established and maintained.
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 regularly assesses the relationship between
natural gas commodity prices in "cash" and futures markets. The
correlation between prices in these markets has been well within a
range generally deemed to be acceptable. If correlation fell out
of an acceptable range, the Company would account for its financial
instrument positions as trading activities.
Federal Income Tax
The Company adopted 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.
Regulatory Assets
Regulatory assets arise from the allocation of costs and revenues
to accounting periods for utility ratemaking purposes differently
from bases generally applied by nonregulated companies. Regulatory
assets are recognized in accordance with SFAS-71, "Accounting for
Certain Types of Regulation."
The Company had net regulatory assets as of September 30, 1995 and
1994 of $109,636,000 and $105,155,000, respectively. These amounts
are included in Deferred Charges and Deferred Credits-Other in the
Consolidated Balance Sheet at September 30, 1995 and 1994. In the
event that it were no longer subject to the provisions of SFAS-71,
the Company estimates that the write-off of these net regulatory
assets could result in a charge to net income of approximately
$69,000,000 which would be classified as an extraordinary item.
SFAS-121, issued in March 1995 and effective for 1996, establishes
accounting standards for the impairment of long-lived assets. This
statement is not expected to have a material impact on the
Company's financial condition or results of operations upon
adoption.
CONSOLIDATED STATEMENT OF INCOME
For the Year Ended September 30, 1995 1994 1993
(Thousands of Dollars)
Operating Revenues
Utility sales $ 1,152,331 $1,279,638 $1,145,315
Gas production and other 63,953 58,992 60,189
1,216,284 1,338,630 1,205,504
Operating Expenses
Cost of gas 446,559 560,657 466,573
Operation 326,381 327,356 309,070
Maintenance 54,813 54,340 54,722
Depreciation and depletion 72,020 69,611 64,779
General taxes 134,718 150,743 144,827
Federal income tax (See Note 1) 43,283 41,619 42,433
Operating Income 138,510 134,304 123,100
Other Income
Income from energy services investments 9,458 5,689 1,150
Gain on sale of investment in Canadian gas company - - 20,462
Write-off of investment in propane company - - (17,617)
Other, net (4,309) (2,338) (3,379)
Federal income tax benefit (See Note 1) 1,243 921 950
Income Before Interest Charges 144,902 138,576 124,666
Interest Charges
Long-term debt 47,939 46,900 45,344
Other 5,128 4,292 2,759
Net Income 91,835 87,384 76,563
Dividends on Preferred Stock 337 351 364
Income Available for Common Stock $ 91,498 $ 87,033 $ 76,199
Earnings Per Share of Common Stock
(Average shares outstanding of 48,211,220,
46,979,597 and 44,042,365, respectively) $ 1.90 $ 1.85 $ 1.73
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
For the Year Ended September 30, 1995 1994 1993
(Thousands of Dollars)
Balance at Beginning of Year $ 279,466 $ 255,979 $ 238,867
Income Available for Common Stock 91,498 87,033 76,199
370,964 343,012 315,066
Less:
Cash dividends declared ($1.39, $1.35 and $1.32
per common share, respectively) 67,229 63,652 58,914
Other adjustments 26 (106) 173
Balance at End of Year $ 303,709 $ 279,466 $ 255,979
The accompanying summary of significant accounting policies and notes are integral parts of these
statements.
CONSOLIDATED BALANCE SHEET
September 30, 1995 1994
(Thousands of Dollars)
Assets
Property
Utility, at cost $ 1,690,193 $ 1,599,452
Accumulated depreciation (393,263) (354,925)
Gas exploration and production, at cost 353,847 276,659
Accumulated depletion (138,136) (115,890)
1,512,641 1,405,296
Investments in Energy Services (See Note 6) 121,023 91,283
Current Assets
Cash 15,992 11,610
Temporary cash investments 24,550 41,881
Accounts receivable 146,018 193,130
Allowance for uncollectible accounts (13,730) (14,963)
Gas in storage, at average cost 88,810 96,076
Materials and supplies, at average cost 13,203 11,356
Prepaid gas costs 15,725 14,667
Other 19,856 31,441
310,424 385,198
Deferred Charges 172,834 147,297
$ 2,116,922 $ 2,029,074
Capitalization and Liabilities
Capitalization (See accompanying statement and Note 4)
Common equity $ 826,290 $ 774,236
Preferred stock, redeemable 6,900 7,200
Long-term debt 720,569 701,377
1,553,759 1,482,813
Current Liabilities
Accounts payable 103,705 132,491
Dividends payable 17,536 16,609
Taxes accrued 3,635 15,213
Customer deposits 22,252 22,445
Customer budget plan credits 24,790 18,358
Interest accrued and other 39,438 45,807
211,356 250,923
Deferred Credits and Other Liabilities
Federal income tax 247,882 230,316
Unamortized investment tax credits 20,948 22,000
Other 82,977 43,022
351,807 295,338
$ 2,116,922 $ 2,029,074
The accompanying summary of significant accounting policies and notes are integral parts of these
statements.
CONSOLIDATED STATEMENT OF CAPITALIZATION
September 30, 1995 1994
(Thousands of Dollars)
Common Equity
Common stock, $.33 1/3 par value, authorized 70,000,000 shares;
outstanding 48,788,320 and 47,590,015 shares,
respectively, stated at $ 522,581 $ 494,770
Retained earnings (See accompanying statement) 303,709 279,466
826,290 774,236
Preferred Stock, Redeemable
$100 par value, cumulative, authorized 900,000 shares
4.60% Series B, 72,000 and 75,000 shares outstanding, respectively 7,200 7,500
Less: Current sinking fund requirements 300 300
6,900 7,200
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
648,500 648,500
Subsidiary borrowings 72,069 52,877
720,569 701,377
$ 1,553,759 $ 1,482,813
The accompanying summary of significant accounting policies and notes are integral parts of these statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
For the Year Ended September 30, 1995 1994 1993
(Thousands of Dollars)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 91,835 $ 87,384 $ 76,563
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation and depletion 77,696 75,386 71,376
Deferred Federal income tax 11,037 10,897 7,599
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 (1,052) (1,074) (1,074)
Income from energy services investments (9,458) (5,689) (1,150)
Dividends received from energy services investments 3,595 4,392 7,421
Allowance for equity funds used during construction (1,274) (2,076) (1,671)
Change in accounts receivable, net 44,712 31,906 (61,097)
Change in accounts payable (29,283) (34,121) 41,094
Gas inventory and prepayments 6,208 5,498 (31,063)
Other 16,799 21,518 7,883
Cash provided by operating activities 210,815 194,021 113,036
CASH FLOWS FROM FINANCING ACTIVITIES
Sale of common stock 27,974 29,828 71,866
Common stock proceeds receivable - 44,910 (44,910)
Issuance of long-term debt 19,192 12,077 186,900
47,166 86,815 213,856
Repayments
Preferred stock (300) (300) (300)
Long-term debt - - (180,000)
46,866 86,515 33,556
Dividends paid (67,566) (64,003) (59,278)
Other (34) 106 2,156
Cash (used in) provided by financing activities (20,734) 22,618 (23,566)
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (excluding allowance
for equity funds used during construction) (212,732) (197,496) (202,843)
Trust funds, utility construction - - 54,610
Proceeds from sale of investment in Canadian gas company - 11,691 30,027
Other 9,702 1,398 7,400
Cash used in investing activities (203,030) (184,407) (110,806)
Change in Cash and Temporary Cash Investments (12,949) 32,232 (21,336)
Cash and Temporary Cash Investments at Beginning of Year 53,491 21,259 42,595
Cash and Temporary Cash Investments at End of Year $ 40,542 $ 53,491 $ 21,259
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 $ 36,000 $ 36,900 $ 32,100
Interest $ 53,047 $ 50,872 $ 51,804
The accompanying summary of significant accounting policies and notes are integral parts of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. FEDERAL INCOME TAX
Income tax expense (benefit) is reflected as follows in the
Consolidated Statement of Income:
Year Ended September 30, 1995 1994 1993
(Thousands of Dollars)
Operating Expenses
Current $ 32,970 $ 39,466 $ 29,172
Deferred 10,313 2,153 13,261
43,283 41,619 42,433
Other Income
Current (915) (8,591) 5,786
Deferred 724 8,744 (5,662)
Amortization of investment
tax credits (1,052) (1,074) (1,074)
(1,243) (921) (950)
Total Federal income tax $ 42,040 $ 40,698 $ 41,483
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 for the increase in accumulated deferred Federal income taxes
not previously provided pursuant to regulatory orders.
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:
September 30, 1995 1994
(Thousands of Dollars)
Deferred Credits and Other
Liabilities - Federal
income tax
Property-related
Utility $ 180,708 $ 176,486
Net tax regulatory asset 28,214 29,087
Gas production and other 49,402 30,841
Regulatory settlement items (9,261) (9,879)
Gas cost and other (1,181) 3,781
Net deferred income tax liability $ 247,882 $ 230,316
As required by standards in effect prior to the adoption of SFAS-
109, the components of deferred tax expense related to the
following items in 1993 are: property related - $9,782,000; rate
settlement items - $(245,000); write-off of propane investment -
$(7,720,000); gas costs and other - $5,781,000.
The following is a reconciliation between reported income tax and
tax computed at the statutory rate of 35% for 1995 and 1994 and
34.75% for 1993:
Year Ended September 30, 1995 1994 1993
(Thousands of Dollars)
Computed at statutory rate $ 46,856 $ 44,828 $ 41,021
Adjustments related to:
Utility property - - 1,179
Gas production and other (2,730) (1,303) 858
Nontaxable interest income (870) (556) (396)
Amortization of investment
tax credits (1,052) (1,074) (1,074)
Other, net (164) (1,197) (105)
Total Federal income tax $ 42,040 $ 40,698 $ 41,483
Effective income tax rate 31% 32% 35%
2. POSTRETIREMENT BENEFITS
A. Pension: The Company has a noncontributory defined benefit
pension plan covering substantially all employees. Benefits are
based on years of service and compensation. The Company records
expense in accordance with treatment established by the New York
State Public Service Commission (PSC) applicable to its 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.
In December 1994, the Company completed a voluntary early
retirement program for bargaining employees. In September 1994,
the Company completed a similar voluntary early retirement program
for management employees. As a result, the Company recorded
special retirement charges in fiscal 1995 and 1994 of $5,416,000
and $8,465,000, respectively.
The Company's funding policy for pensions is in accordance with
requirements of Federal law and regulations. There were no pension
contributions in 1995, 1994 and 1993.
The calculation of net periodic pension cost follows:
Year Ended September 30, 1995 1994 1993
(Thousands of Dollars)
Service cost, benefits earned
during the year $ 11,533 $ 15,100 $ 14,244
Special retirement charge 5,416 8,465 -
$ 16,949 $ 23,565 $ 14,244
Interest cost on projected
benefit obligation 35,128 29,511 24,617
Return on plan assets (82,626) (12,430) (76,671)
Net amortization and deferral 34,786 (32,798) 44,976
Total pension cost $ 4,237 $ 7,848 $ 7,166
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.
September 30, 1995 1994
(Thousands of Dollars)
Actuarial present value of
benefit obligations:
Vested $(401,159) $(333,890)
Accumulated $(423,434) $(353,172)
Projected $(545,825) $(446,676)
Plan assets at fair value $ 555,906 $ 497,280
Plan assets in excess of
projected benefit obligation $ 10,081 $ 50,604
Unrecognized net loss (gain)
from experience and changes in
assumptions 10,880 (21,007)
Unrecognized transition asset (32,566) (37,218)
Accrued pension cost $ (11,605) $ (7,621)
Assumptions:
Obligation discount 7.00% 8.00%
Asset return 7.50% 8.00%
Average annual increase
in compensation 5.50% 5.50%
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 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.
Net periodic postretirement benefit cost included the following
components:
Year Ended September 30, 1995 1994
(Thousands of Dollars)
Service cost, benefits earned
during the year $ 2,590 $ 2,826
Interest cost on accumulated
postretirement benefit obligation 9,958 7,916
Return on plan assets (6,746) (340)
Net amortization and deferral 6,752 141
Postretirement benefit cost $12,554 $10,543
The following table sets forth the plans' funded status, reconciled
with amounts recognized in the Company's Consolidated Balance
Sheet.
September 30, 1995 1994
(Thousands of Dollars)
Actuarial present value of accumulated
postretirement benefit obligation
Retirees $ (87,022) $ (53,218)
Fully eligible active plan
participants (10,980) (17,106)
Other active plan participants (56,157) (32,890)
$(154,159) $(103,214)
Plan assets at fair value, primarily
stocks and bonds $ 72,638 $ 56,163
Accumulated postretirement benefit
obligation in excess of plan assets $ (81,521) $ (47,051)
Unrecognized net loss (gain) from past
experience different from that assumed
and from changes in assumptions 25,345 (16,875)
Unrecognized transition obligation 67,781 71,547
Prepaid postretirement benefit cost $ 11,605 $ 7,621
Assumptions:
Obligation discount 7.00% 8.00%
Asset return 7.50% 8.00%
The measurement also assumes a health care cost trend rate of 9.0%
in 1995, decreasing to 5.0% by the year 2007 and remaining at that
level thereafter. A 1.0% increase in the health care cost trend
rate would have the effect of increasing the accumulated
postretirement benefit obligation as of September 30, 1995 and the
net periodic SFAS-106 expense by approximately $15,830,000 and
$1,752,000, respectively. The measurement for the year ended
September 30, 1994 assumed a health care cost trend rate of 9.5% in
1994 decreasing to 5.0% by 2007.
3. FIXED OBLIGATIONS
A. Leases: Lease costs included in operation expense were
$14,706,000 in 1995, $15,547,000 in 1994 and $14,247,000 in 1993.
The future minimum lease payments under the Company's various
leases, all of which are operating leases, are approximately
$14,300,000 per year over the next five years and $163,100,000 in
the aggregate for years thereafter.
The Company has a lease agreement with a remaining term of 16 years
for its corporate headquarters.
B. Fixed Charges Under Firm Contracts: The Company has entered
into various contracts for gas delivery and supply services. The
contracts have varying terms that extend from one to twenty years.
Certain of these contracts require payment of monthly charges in
the aggregate amount of approximately $4.2 million per month in all
events and regardless of the level of service available. Such
charges are recovered as gas costs.
4. CAPITALIZATION
A. Common and Preferred Stock: In 1995 and 1994, the Company
issued 1,198,305 and 1,209,734 shares of common stock for
$27,974,000 and $29,828,000, 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, 1995, 1,200,070 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. Other changes to common stock reflect the
amortization of premiums paid on preferred stock redeemed in prior
years which were deferred in order to reflect the ratemaking
treatment. Annual amortization was approximately $155,000 in each
of the past two years.
The 4.60% Series B preferred stock is subject to an annual sinking
fund requirement of 3,000 shares at par value.
B. Gas Facilities Revenue Bonds and Other: The Company can issue
tax-exempt bonds through the New York State Energy Research and
Development Authority. Whenever bonds are issued for new gas
facilities projects, proceeds are deposited in trust and
subsequently withdrawn by the Company to finance qualified
expenditures.
There are no sinking fund requirements for any Gas Facilities
Revenue Bonds. The Company's 9.0% and 8.75% Gas Facilities Revenue
Bonds became callable on May 15, 1995 and July 1, 1995,
respectively, each issue at the optional redemption price of 102%
of par value plus accrued interest. The Company is evaluating the
possibility of refunding these bond issues.
Other long-term debt consists primarily of debt of a subsidiary
under a revolving loan agreement with no payments currently due.
The annual average interest rate on this debt was 6.8% in fiscal
1995.
5. FINANCIAL INSTRUMENTS
A. Fair Value of Financial Instruments: The Company's long-term
debt consists primarily of publicly traded Gas Facilities Revenue
Bonds, the fair value of which is estimated based on quoted market
prices for the same or similar issues. The fair value of these
bonds at September 30, 1995 and 1994 was $673,408,300 and
$651,255,200, 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, 1995 and 1994, the fair value of this stock was
$5,228,800 and $4,796,640, respectively, and the carrying value was
$6,900,000 and $7,200,000, 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 gas
exploration and production subsidiaries employ derivative financial
instruments, natural gas futures and swaps, for the purpose of
managing commodity price risk.
The utility tariff applicable to certain large-volume customers
permits gas to be sold at prices established monthly within a
specified range expressed as a percentage of prevailing alternate
fuel prices (oil). Commencing in fiscal 1995, the Company
initiated a hedging strategy designed to fix margins on specified
portions of the sales to this market. Implementation of the
strategy involves establishment of long positions in gas futures
with offsetting short positions in oil futures of equivalent energy
value over the same time period. The long gas futures position
replicates the cost of gas to serve this market while the short oil
futures position correspondingly fixes the selling price of gas to
the target customers at the desired relationship to the price of
the alternative fuel. A similar strategy involving swaps contracts
is utilized for customers whose alternate fuel is No. 6 oil. These
contracts cover 463,000 barrels of oil and extend through September
1996.
The Company also entered into a series of swaps transactions to
minimize its exposure to differences in the market prices of gas at
certain receipt points in producing areas. These basis swaps
contracts cover 14.5 billion cubic feet of gas through October
1996.
With respect to natural gas production operations, the Company
generally uses swaps (for production beyond 18 months), and
standard New York Mercantile Exchange futures contracts (for
production within 18 months) to hedge the price risk related to
known production plans and capabilities. These contracts include
a fixed price/volume and are structured as both straight and
participating swaps. In either case, the Company pays the other
parties the amount by which the floating variable price (settlement
price) exceeds the fixed price and receives the amount by which the
settlement price is below the fixed price. The settlement volume
of participating swaps is reduced by 50% if the settlement price
exceeds a defined limit.
The following table summarizes the notional amounts and related
fair values of the Company's derivative financial instrument
positions outstanding at September 30, 1995 and 1994. In 1994,
these amounts included marketing activities which were combined
with those of Pennzoil Gas Marketing, Inc., through a limited
liability company in 1995. Fair values are based on dealer quotes
for the same or similar instruments. Differences between the
notional contract amounts and fair values represent implicit gains
or losses if the instruments were settled at market.
September 30, 1995 1994
(Thousands of Dollars)
Notional Fair Notional Fair
Amount Value Amount Value
Futures contracts $89,640 $86,394 $ 43,047 $ 39,911
Swaps contracts $80,073 $82,705 $123,291 $116,161
Futures contracts expire and are renewed monthly. As of September
30, 1995, no such contract extended beyond September 1996.
Further, swaps contracts are settled monthly and extend through
March 1998. Margin deposits with brokers at September 30, 1995
amounted to $1,662,400. Deferred losses on closed positions were
$748,000 and $1,225,000 at September 30, 1995 and 1994,
respectively.
The Company and its subsidiaries are exposed to credit risk in the
event of nonperformance by counterparties to futures and swaps
contracts, as well as nonperformance by the counterparties of the
transactions against which they are hedged. The Company believes
that the credit risk related to the futures and swaps 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. INVESTMENT IN 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
$23.4 million at September 30, 1995.
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. Further, agency investigations of matters related to
the construction of the Iroquois pipeline have been commenced by
COE and the Federal Energy Regulatory Commission. Iroquois also
has received inquiries from the Federal Department of
Transportation and the PSC concerning certain construction
activities. Civil penalties could be imposed if violations of
Iroquois' governmental authorizations are shown to have occurred.
No proceedings in connection with these investigations and
inquiries 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.
The Company has been informed that Iroquois and its counsel have
met and expect to continue to meet with those responsible for the
civil and criminal investigations, from time to time, both to gain
an informed understanding of the focus and direction of the
investigations in order to defend itself and to explore possible
resolutions that may be acceptable to all parties. A comprehensive
resolution of these matters could have a material adverse effect on
Iroquois' financial condition. Although no agreements have been
reached regarding the disposition of these matters, based on
discussions with Iroquois' management, in 1995 the Company recorded
a provision which it believes to be adequate to cover its
proportionate share of estimated costs of legal proceedings
involving Iroquois. The provision and ultimate resolution of these
matters has not and is not expected to materially affect the
Company's results of operations and financial position.
7. ENVIRONMENTAL MATTERS
Historically, the Company, or predecessor entities to the Company,
owned or operated several former manufactured gas plant (MGP)
sites. These sites have been identified for the New York State
Department of Environmental Conservation (DEC) for inclusion on
appropriate waste site inventories. In certain circumstances,
former MGP sites can give rise to environmental cleanup
responsibilities for the Company.
Two MGP sites are under active consideration by the Company. One
site, which is located on property still owned by the Company, is
the former Coney Island MGP facility located in Brooklyn, New York.
This site is the subject of continuing interim remedial action
under the direction of the U.S. Coast Guard. Moreover, the Company
recently has executed a consent order with the DEC with respect to
addressing the overall remediation of the Coney Island site in
accordance with state law. A schedule of investigative and cleanup
activities is being developed, leading to a cleanup over the next
several years. The other site currently is owned by the City of
New York. The Company and the City are in the process of
discussing a mutual approach to sharing potential environmental
responsibility for this site. The Company believes it is likely
that, at a minimum, investigative costs will be incurred by the
Company with respect to that site.
The DEC is maintaining open files and requiring the Company to
continue monitoring or related investigatory efforts at two other
Company-owned properties.
Except as described above, no administrative or judicial
proceedings or claims involving other former MGP sites have been
initiated. Although the potential cost of cleanup with respect to
these other sites may be material if the Company ever is compelled
to address these sites, the Company cannot at this time determine
the cost or extent of any cleanup efforts if cleanup ultimately
should be required.
Based upon the terms of the consent order for the Coney Island site
and costs of investigation for the other MGP site under active
consideration, the Company believes that the minimum cost of MGP-
related environmental cleanup will be approximately $34 million,
which, based upon current information, will be primarily for the
Coney Island site. This amount includes approximately $4.9 million
of costs expended as of September 30, 1995. The Company's actual
MGP-related costs may be substantially higher, depending upon
remediation experience, eventual end use of the sites, and
environmental conditions not addressed in the consent order or
current investigative plans. Such potential additional costs are
not subject to estimation at this time.
As of September 30, 1995, the Company had an accrued liability of
$29.3 million and a related unamortized regulatory asset of $33.2
million. By order issued February 16, 1995, the PSC approved the
Company's July 1993 petition to defer the costs associated with
environmental site investigation and remediation incurred in 1993
and thereafter. Accordingly, recovery of these costs began in
fiscal 1995. The recovery of these costs in rates is conditioned
upon the absence of a PSC determination that such costs have not
been reasonably or prudently incurred. In addition, the Company
must demonstrate that it has taken all reasonable steps to obtain
cost recovery from all available funding sources, including other
potentially responsible parties. The PSC has initiated a generic
proceeding to assess the extent of the potential liability for
cleanup of MGP sites by the State's gas utilities and has indicated
that it may consider in that proceeding generic policies regarding
the recovery of such costs through gas utility rates. Any such
policies may affect the Company's ability to reflect such costs in
rates following the last year of the current rate agreement. At
this time, the Company is unable to predict the outcome of that
proceeding.
NOTE 8. SUPPLEMENTAL GAS AND OIL DISCLOSURES
CAPITALIZED COSTS RELATING TO GAS AND OIL PRODUCING ACTIVITIES
September 30, 1995 1994
(Thousands of Dollars)
Unproved properties not being amortized $35,082 $25,335
Properties being amortized-productive and nonproductive 299,398 240,572
Total capitalized costs 334,480 265,907
Accumulated depletion (132,809) (109,885)
Net capitalized costs $201,671 $156,022
At September 30, 1995, the Company had an immaterial deficiency in its asset
ceiling test; however, such deficiency was eliminated by subsequent price
changes.
The following is a summary of the costs (in thousands of dollars) which are
excluded from the amortization calculation as of September 30, 1995, by
year of acquisition: 1995-$23,114; 1994-$9,889; and prior years-$2,077.
The Company cannot accurately predict when these costs will be included in
the amortization base, but it is expected these costs will be evaluated
within the next five years.
COSTS INCURRED IN PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT
ACTIVITIES
United
Total States Canada
1995* 1994* 1993 1993 1993
(Thousands of Dollars)
Acquisition of properties-
Unproved properties $10,996 $11,022 $5,289 $4,937 $352
Proved properties 14,983 28,370 40,091 30,541 9,550
Exploration 5,907 18,961 2,831 2,831 -
Development 37,953 9,781 16,588 11,238 5,350
Total costs incurred $69,839 $68,134 $64,799 $49,547 $15,252
RESULTS OF OPERATIONS FROM GAS AND OIL PRODUCING ACTIVITIES
Total United Canada
States
1995* 1994* 1993 1993 1993
(Thousands of Dollars)
Revenues from gas and oil
producing activities-
Sales to unaffiliated parties $40,810 $41,185 $43,076 $31,745 $11,331
Sales to affiliates - 2,023 1,482 1,482 -
Revenues 40,810 43,208 44,558 33,227 11,331
Production and lifting costs 5,762 5,360 8,608 4,232 4,376
Depletion 22,906 24,978 22,525 20,990 1,535
Total expenses 28,668 30,338 31,133 25,222 5,911
Income before taxes 12,142 12,870 13,425 8,005 5,420
Income taxes 1,957 3,306 4,129 1,691 2,438
Results of gas and oil producing
activities (excluding corporate
overhead and interest costs) $10,185 $9,564 $9,296 $6,314 $2,982
* Gas and oil operations were conducted predominantly in the United States
in 1995 and 1994.
8. 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 quantities 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)
United
Total States Canada
1995* 1994* 1993 1993 1993
Proved Reserves-
Beginning of Year 142,858 108,847 111,664 84,171 27,493
Revisions of previous estimates 13,539 (2,297) 9,036 1,438 7,598
Extensions and discoveries 38,985 25,890 4,696 3,915 781
Production (21,822) (22,814) (26,596) (21,007) (5,589)
Purchases of reserves in place 21,495 34,931 91,016 40,330 50,686
Sales of reserves in place - (1,699) (80,969) - (80,969)
Proved Reserves-
End of Year 195,055 142,858 108,847 108,847 -
Proved Developed Reserves-
Beginning of Year 110,225 100,454 93,417 65,924 27,493
End of Year 151,594 110,225 100,454 100,454 -
*Gas and oil reserves were located predominantly in the United States in 1995 and 1994.
8. SUPPLEMENTAL GAS AND OIL DISCLOSURES (CONTINUED)
CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS (MBBLS)
United
Total States Canada
1995* 1994* 1993 1993 1993
Proved Reserves-
Beginning of Year 807 443 2,304 520 1,784
Revisions of previous estimates 245 (140) 184 (91) 275
Extensions and discoveries 155 155 3 3 -
Production (148) (96) (320) (109) (211)
Purchases of reserves in place 103 495 121 120 1
Sales of reserves in place - (50) (1,849) - (1,849)
Proved Reserves-
End of Year 1,162 807 443 443 -
Proved Developed Reserves-
Beginning of Year 543 407 2,239 455 1,784
End of Year 974 543 407 407 -
* Gas and oil reserves were located predominantly in the United States in 1995 and 1994.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED GAS AND OIL RESERVES
Total*
1995 1994
(Thousands of dollars)
Future cash flow $314,627 $249,437
Future costs-
Production (57,941) (47,149)
Development (29,948) (22,241)
Future net inflows
before income tax 226,738 180,047
Future income taxes (43,705) (26,930)
Future net cash flows 183,033 153,117
10% discount factor (49,512) (44,983)
Standardized measure of
discounted future net
cash flows $133,521 $108,134
* Gas and oil reserves were located predominantly in the United States in 1995 and 1994.
8. SUPPLEMENTAL GAS AND OIL DISCLOSURES (CONTINUED)
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
FROM PROVED RESERVE QUANTITIES
1995 1994 1993
United
Total* Total* Total States Canada
(Thousands of dollars)
Standardized measure-
beginning of year $108,134 $110,406 $90,665 $76,695 $13,970
Sales and transfers, net of
production costs (35,048) (37,848) (35,950) (28,995) (6,955)
Net change in sales and
transfer prices, net of
production costs (2,786) (25,005) 4,001 7,011 (3,010)
Extensions and discoveries and
improved recovery, net of
future production 28,868 15,536 6,554 5,994 560
Changes in estimated future
development costs (2,351) (1,016) (8,281) (8,281) -
Development costs incurred
during the period that reduced
future development costs 10,360 6,381 12,354 12,354 -
Revisions of quantity estimates 13,858 (2,917) 6,195 1,926 4,269
Accretion of discount 11,763 12,397 11,033 8,921 2,112
Net change in income taxes (7,856) 4,001 (3,079) (1,045) (2,034)
Purchases of reserves in place 15,176 27,561 61,410 40,548 20,862
Sales of reserves in place - (2,110) (27,539) - (27,539)
Changes in production rates
(timing) and other (6,597) 748 (6,956) (4,721) (2,235)
Standardized measure-end
of year $133,521 $108,134 $110,406 $110,406 $ -
* Gas and oil reserves were located predominantly in the United States in 1995 and 1994.
8. SUPPLEMENTAL GAS AND OIL DISCLOSURES (CONTINUED)
Average Sales Prices and Production Costs - Per Unit
For the year ended September 30,
1995 1994 1993
Average Sales Price*
Natural Gas ($/MCF)
United States 1.47 1.97 2.12
Canada - - 1.39
Total 1.47 1.97 1.97
Oil, Condensate and Natural
Gas Liquid ($/Bbl)
United States 16.92 15.63 17.70
Canada - - 16.90
Total 16.92 15.63 17.17
*Represents the cash price received which excludes the effect of
any hedging transactions.
Production Cost Per
Equivalent MCF ($)
United States .25 .23 .18
Canada - - .64
Total .25 .23 .29
Acreage**
As of September 30, 1995
Gross Net
Producing 251,894 116,417
Undeveloped 118,935 56,133
Number of Producing Wells**
As of September 30, 1995
Gross Net
Gas wells 1000 533
Oil wells 18 6
**Located predominantly in the United States.
Drilling Activity (Net)
For the years ended September 30,
1995 1994 1993
Pro- Dry Total Pro- Dry Total Pro- Dry Total
ducing ducing ducing
Net developmental
wells
United States 10.0 3.4 13.4 6.6 - 6.6 5.4 - 5.4
Canada - - - - - - 5.0 - 5.0
Total 10.0 3.4 13.4 6.6 - 6.6 10.4 - 10.4
Net exploratory
wells (U.S.) 1.4 0.4 1.8 2.5 1.2 3.7 - 0.5 0.5
At September 30, 1995 the Company, through a subsidiary, was involved in the
drilling of one developmental well of which it was the sole owner.
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 7 of the Company's
definitive Proxy Statement, dated December 28, 1995, for its Annual
Meeting of Shareholders to be held on February 1, 1996.
Information regarding the Company's executive officers, who
are elected annually by the directors, is found on page 49 hereof.
Item 11. Executive Compensation
Information regarding compensation of the Company's executive
officers is incorporated herein by reference to pages 7 through 11
of the Company's definitive Proxy Statement, dated December 28,
1995, for its Annual Meeting of Shareholders to be held on February
1, 1996.
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 7, dated December 28, 1995, for its Annual
Meeting of Shareholders to be held on February 1, 1996.
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.
Part IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K
(a) 1. All Financial Statements
Page in
Form 10-K
Report of Independent Public Accountants 24
Summary of Significant Accounting Policies 25
Consolidated Statement of Income for the Years
Ended September 30, 1995, 1994 and 1993 28
Consolidated Statement of Retained Earnings for
the Years Ended September 30, 1995, 1994
and 1993 28
Consolidated Balance Sheet at September 30, 1995
and 1994 29
Consolidated Statement of Capitalization at
September 30, 1995 and 1994 30
Consolidated Statement of Cash Flows for the
Years Ended September 30, 1995, 1994 and 1993 31
Notes to Consolidated Financial Statements 32
(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, 1995, 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, 1995, 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, 1995.
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.
Executive Officers of the Registrant
- ------------------------------------
All Executive Officers serve one-year terms.
Age as of
Sept. 30, Period Served
Name and Position 1995 In Such Capacity Business Experience in Past 5 Years
Robert B. Catell, President 58 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 52 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 63 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 54 1992 to Present Senior Vice President
Senior Vice President 1989 to 1992 Vice President
Vincent D. Enright, Senior Vice 51 1994 to Present Senior Vice President and Chief
President and Chief Financial Financial Officer
Officer 1992 to 1994 Senior Vice President
1984 to 1992 Vice President
William K. Feraudo 45 1994 to Present Senior Vice President
Senior Vice President 1989 to 1994 Vice President
Wallace P. Parker, Jr. 46 1994 to Present Senior Vice President
Senior Vice President 1990 to 1994 Vice President
1987 to 1990 Assistant Vice President
Lenore F. Puleo 42 1994 to Present Senior Vice President
Senior Vice President 1990 to 1994 Vice President
Maurice K. Shaw, Senior Vice 56 1993 to Present Senior Vice President
President and Corporate Affairs Officer 1987 to 1993 Senior Vice President and Chief
Marketing Officer
Edward J. Sondey 57 1992 to Present Senior Vice President
Senior Vice President 1981 to 1992 Vice President
Tina G. Barber, Vice President 46 1994 to Present Vice President and Chief
and Chief Information Officer Information Officer
1992 to 1994 Vice President
Richard M. Desmond, Vice 61 1992 to Present Vice President, Comptroller and
President, Comptroller and Chief Accounting Officer
Chief Accounting Officer 1984 to 1992 Vice President and Comptroller
Robert H. Preusser, Vice President 58 1992 to Present Vice President and Chief Engineer
and Chief Engineer 1987 to 1992 Vice President
Roger J. Walz, Vice President 50 1990 to Present Vice President and General Auditor
and General Auditor 1988 to 1990 General Auditor
Robert R. Wieczorek, Vice President 53 1994 to Present Vice President, Secretary
Secretary and Treasurer and Treasurer
1989 to 1994 Vice President, Treasurer, and
Assistant Secretary
SCHEDULE II
THE BROOKLYN UNION GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED SCHEDULE OF VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED SEPTEMBER 30, 1995, 1994 AND 1993
____________________________________________________________________
(Thousands of Dollars)
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
______________________________ ____________ ______________ ______________ ______________
Year Ended September 30, 1995
Allowance for uncollectible accounts $14,963 $17,494 $18,727 (a) $13,730
____________ ______________ ______________ ______________
Reserve for injuries and damages
Public Liability $5,350 $4,368 $3,818 (b) $5,900
Workers' Compensation $1,425 $500 $335 (b) $1,590
____________ ______________ ______________ ______________
$6,775 $4,868 $4,153 $7,490
____________ ______________ ______________ ______________
Year Ended September 30, 1994
Allowance for uncollectible accounts $14,212 $18,737 $17,986 (a) $14,963
____________ ______________ ______________ ______________
Reserve for injuries and damages $6,816 $3,447 $3,488 (b) $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
____________ ______________ ______________ ______________
(a) Write-off of bad debts, net recoveries.
(b) Cost of injury and damage claims.
(a) 3. Exhibits
(3) Articles of incorporation and by-laws
By-laws of the Company, dated June 28, 1995, incorporated by
reference from Form 8-K dated September 5, 1995.
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
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,
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.
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
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, 1995, 1994 and 1993," for information
required by this item.
(12) Statement re: Computation of consolidated ratio of earnings to
fixed charges
(21) Subsidiaries of the registrant
(23) Consents of experts
(27) Financial data schedule
(b) Reports on Form 8-K:
There was a Form 8-K report filed on September 5, 1995, noting
that the Company amended its by-laws on June 28, 1995. No
financial statements were included in that report.
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 13, 1995.
THE BROOKLYN UNION GAS COMPANY
Signature Title
s/Robert B. Catell President and Chief Executive
(Robert B. Catell) Officer
s/Craig G. Matthews Executive Vice President
(Craig G. Matthews)
s/Vincent D. Enright Senior Vice President and
(Vincent D. Enright) Chief Financial Officer
s/Richard M. Desmond Vice President, Comptroller
(Richard M. Desmond) and Chief Accounting
Officer
s/Kenneth I. Chenault Director
(Kenneth I. Chenault)
s/Andrea S. Christensen Director
(Andrea S. Christensen)
s/Donald H. Elliott Director
(Donald H. Elliott)
s/Alan H. Fishman Director
(Alan H. Fishman)
s/James L. Larocca Director
(James L. Larocca)
s/Edward D. Miller Director
(Edward D. Miller)
s/Richardson Pratt, Jr. Director
(Richardson Pratt, Jr.)
s/James Q. Riordan Director
(James Q. Riordan)