<PAGE>
         UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                     WASHINGTON, D. C. 20549
                            FORM 10-K
(Mark One)
 X  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES 
    EXCHANGE ACT OF 1934
For the fiscal year ended           September 30, 1996           
                                                     OR
    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE      
    SECURITIES EXCHANGE ACT OF 1934
For the transition period from                 to                

Commission file number                   1-722                   

                 THE BROOKLYN UNION GAS COMPANY                  
     (Exact name of Registrant as specified in its charter) 

           New York                               11-0584613     
(State or other jurisdiction of              (I.R.S. Employer
 incorporation or organization)               Identification No.)

ONE METROTECH CENTER, BROOKLYN, NEW YORK          11201-3850     
(Address of principal executive offices)          (Zip Code)

Registrant's telephone number, including area code  718-403-2000 

Securities registered pursuant to Section 12(b) of the Act:
                                           Name of Each Exchange on
     Title of Each Class                       Which Registered   
Common Stock-$.33 1/3 par value             New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:  None

         Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements
for the past 90 days.  Yes  X   No    
         Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein, and
will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K.  (X)
         Aggregate market value of registrant's voting Common Stock
held by non-affiliates as of December 16, 1996 was approximately
$1.5 billion.
         On December 18, 1996 the Company had 49,993,378 shares of
Common Stock outstanding.
               DOCUMENTS INCORPORATED BY REFERENCE 
                                                        Part of
Documents                                               Form 10-K
Prospectus/Proxy Statement dated December 20, 1996       Part III

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PART   I
                                   
Item   1.  Business                 
                  The Company                                 2
                  Gas Supply                                  4
                  Regulation and Rate Matters                 5
                  Competition                                 6
                  Environmental Matters                       8   
                  Research and Development                    8 
                  Subsidiaries                                8
                  Employees                                   11  
                                                                  
Item   2.  Properties                                         11  
                                                                  
Item   3.  Legal Proceedings                                  12  
  
Item   4.  Submission of Matters to a Vote of Security 
           Holders                                            12
PART   II
Item   5.  Market for the Registrant's Common Stock and 
           Related Security Holder Matters                    12

Item   6.  Selected Financial Data                            14

Item   7.  Management's Discussion and Analysis of 
           Financial Condition and Results of Operations      15

Item   8.  Financial Statements and Supplementary Data        25

Item   9.  Changes in and Disagreements with Accountants          
           on Accounting and Financial Disclosure             50  

PART   III

Item  10.  Directors and Executive Officers of the 
           Registrant                                         50

Item  11.  Executive Compensation                             50
                                                                  
Item  12.  Security Ownership of Certain Beneficial Owners
           and Management                                     50

Item 13.   Certain Relationships and Related Transactions     50

Part IV

Item 14.   Exhibits, Financial Statement Schedules, and
           Reports on Form 8-K                                51

Signatures                                                    58 
<PAGE>
                                                   Part I

Item 1.   Business

                              The Company

         The Brooklyn Union Gas Company (Company) was incorporated in
the State of New York in 1895 as a combination of existing
companies, the first of which was granted a franchise in 1849.  The
Company distributes natural gas at retail, primarily in a territory
of approximately 187 square miles, which includes the Boroughs of
Brooklyn and Staten Island and two-thirds of the Borough of Queens,
all in New York City.  The population of the territory served is
approximately 4,000,000.  As of September 30, 1996, the Company had
approximately 1,126,000 active meters, of which approximately
1,089,000 were residential.  The Company is subject to the
regulatory jurisdiction of the New York State Public Service
Commission (PSC).  Its subsidiaries participate and own investments
in gas and oil exploration, production and processing, gas pipeline
transportation and storage, cogeneration, marketing and other
energy-related services.  Gas exploration and production
investments are fully consolidated.  Other investments are
accounted for on the equity method.  The Company's executive
offices are located at One MetroTech Center, Brooklyn, New York
11201-3850.  Its telephone number is (718)403-2000.  Financial and
other information is also available through the World Wide Web at
http://www.bug.com. 

         The Company's gas distribution business is influenced by
seasonal weather conditions.  Annual revenues are substantially
realized during the heating season (November 1 to April 30) as a
result of the large proportion of heating sales, primarily
residential, compared to total sales.  Accordingly, results of
operations historically are most favorable in the second quarter
(the three months ended March 31) of the Company's fiscal year,
with results of operations being next most favorable in the first
quarter.  Results for the third quarter are marginally
unprofitable, and losses are usually incurred in the fourth
quarter.  The Company's tariff contains a weather normalization
adjustment that provides for recovery from or refund to firm
customers of material shortfalls or excesses of firm net revenues
during a heating season due to variations from normal weather. (See
Item 1., "Business - Regulation and Rate Matters" and Part II, Item
7., "Management's Discussion and Analysis of Financial Condition
and Results of Operations - 'Rate and Regulatory 
Matters' ").  
         
         The heating capacity of gas is measured in therms.  One therm
equals 100,000 BTUs, the heat content of approximately 100 cubic
feet of natural gas.  The heat content of approximately 1,000,000 

cubic feet of gas represents 10,000 therms or 1 MDTH.  Accordingly,

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one billion cubic feet (BCF) of gas equals approximately 1,000
MDTH.

         For the fiscal year ended September 30, 1996, utility firm gas
sales were 141,948 MDTH, of which 75% were residential, 13%
commercial, 8% governmental and 4% industrial.  Other utility gas
sales and transportation deliveries to off-system and interruptible
on-system customers amounted to 42,950 MDTH.  

         In September 1996, the New York State Public Service
Commission (PSC) granted the Company's petition to restructure into
a holding company, to be named KeySpan Energy Corporation
(KeySpan).  If the Company's common shareholders approve the
restructuring at its Annual Meeting in February 1997, KeySpan would
become the parent holding company of Brooklyn Union and its
subsidiaries (which would become subsidiaries of KeySpan).  This
would be completed through a share exchange whereby the Company's
common shareholders would receive KeySpan common stock on a share
for share basis, thus becoming the owners of KeySpan.  The PSC by
order also approved a settlement agreement that contains
restrictions and limitations on certain investments by KeySpan,
limitations on the level of dividend payments from Brooklyn Union
to KeySpan under certain circumstances, prohibitions on certain
intercompany loans, guarantees and pledges, and restrictions on
transactions among the affiliated holding company group.  For
further information, see Part II, Item 7., "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and
Item 1., "Business - Competition".
                                  
<PAGE>
                               Gas Supply
General

         Changes in regulatory policies and market forces have shifted
the industry from traditional cost-based regulation involving gas
sales, transportation, storage and other related services on a
bundled basis by the interstate pipelines toward market-based sales
on an unbundled basis.  These policy changes have made the market
more competitive with respect to gas supply and related services. 
Accordingly, the PSC has set forth a policy framework and has
issued an order on May 1, 1996 regarding utility compliance tariff
filings, including the Company's, in line with market objectives of
providing utility customers with wider choices in gas supply and
related services at the local level.  As a result of the order, all
customers who choose to do so can arrange to purchase their gas
directly from qualified marketers.  The Company continues to serve
as the transporter of gas within its local distribution network,
and the related rates provide full margin recovery of all costs of
service.  (See Part II, Item 7., "Management's Discussion and
Analysis of Financial Condition and Results of Operations - 'Rate
and Regulatory Matters'.")   

         In 1996, 66% of gas supply was purchased from domestic sources
under long-term contracts, 21% from Canadian sources under long-
term contracts and 13% from spot market sources.

         The Company opened the first New York-based market hub for
buyers and sellers of natural gas in the Northeast in fiscal 1994. 
With interconnections and access to several major pipelines, the
New York Market Hub offers transportation, balancing and exchange
services to utilities, municipalities, marketers and large-volume
customers.  In 1996, the Hub placed 29,638 MDTH of gas for delivery
to customers in 14 states and one Canadian province.    

Long-Term Sources of Supply 

         Under long-term contracts and regulatory certificates
applicable to gas supply and pipeline transportation and storage
services, the Company's suppliers are authorized and obligated to
provide maximum firm daily total deliveries of 992 MDTH of gas for
the 1996-97 winter.  This supply consists of 375 MDTH per day of
firm gas supply from U.S. sources, 100 MDTH per day of firm
Canadian gas supply, 492 MDTH per day of storage and winter
services related to U.S. sources, and 25 MDTH of on-system peaking
supply.  

         The Company's major providers of interstate pipeline capacity
and related services are:  Transcontinental Gas PipeLine
Corporation, Texas Eastern Transmission Corporation, Iroquois Gas 

Transmission System, Tennessee Gas Pipeline Company, CNG 

<PAGE>
Transmission Corporation and Texas Gas Transmission Company, which
provide unbundled firm transportation and storage services.  These
pipelines are the conduit for the delivery of U.S. and Canadian
supplies purchased from natural gas sellers to the Company's
market.

Peak-day Supply

         The Company plans for peak-day demand on the basis of an
average temperature of 0oF.  Gas demand on such a design peak-day
is estimated at 1,122 MDTH during the 1996-97 winter.  The highest
24-hour firm sendout experienced by the Company was 1,022 MDTH on
January 19, 1994, when the average temperature was 4oF.

         For the 1996-97 winter, the Company has the capability to
provide a maximum peak-day supply of 1,284 MDTH, consisting of firm
flowing supply, pipeline storage supply, seasonal winter supply,
and vaporized liquefied natural gas (LNG).  The Company's LNG plant
has a storage capacity of 1,660 MDTH and peak-day sendout capacity
of 291 MDTH, or 23% of peak-day supply.  Effective November 1,
1996, a new winter peaking service, the Brooklyn Navy Yard Peaking
Supply, was added to the Company's gas supply portfolio.  It can
provide a maximum daily quantity of 25 MDTH and a total available
seasonal quantity of 480 MDTH.

Gas Costs

         The average cost of gas purchased for firm customers was $3.49
per DTH in 1996, $3.12 per DTH in 1995 and $3.55 per DTH in 1994. 
                                                      
                      Regulation and Rate Matters

         The agreement reached in the holding company filing included
a new multi-year rate plan that became effective on October 1,
1996. After an initial rate reduction of approximately $3.0 million
in fiscal 1997, the non-gas component in customer bills will be
under specific price caps.  Hence, the total amount for this
component in rates that the Company can charge customers, in the
aggregate, will remain constant for the subsequent five years,
although rates in certain customer classes may be increased in
order to reflect cost responsibility more appropriately.  The
Company also will be permitted to charge for various ancillary
services.  

         Utility retail sales, which include sales of gas,
transportation and balancing services by the Company, are made
primarily under rate schedules and tariffs filed with and subject
to the jurisdiction of the PSC.  Amendments have been made to rate
schedules and tariffs to reflect the conditions and rates under
which delivery and other services are provided to  customers who
opt to have their gas supplied by third parties.  Rate schedules
also have been established governing the provision of certain 

<PAGE>
services to such marketers.  In general, the schedules provide for
block rates that result in reductions in the unit price as use
increases. They contain gas cost adjustment provisions that permit
the Company to pass on to firm customers increases and decreases in
the cost of gas currently in billings to firm customers through the
operation of a tariff provision, the Gas Adjustment Clause (GAC). 
Revenue requirements to establish utility rates are based on tariff
sales to customers.  Net revenues from off-system gas sales and
tariff gas balancing services and capacity release credits are
refunded to firm customers subject to sharing provisions in the
Company's tariff.  Prior to October 1, 1996, net revenues from
tariff sales for gas and transportation services to on-system
customers made on an interruptible basis were refunded to firm
customers subject to sharing provisions.  The GAC provision
requires an annual reconciliation of recoverable gas costs with GAC
revenues.  Any difference is deferred pending recovery from or
refund to firm customers during a subsequent twelve-month period.
                                                      
         For information regarding the status of rate settlements and
other regulatory proceedings, including the Company's rate order
that became effective in October 1996, see Part II, Item 7.,
"Management's Discussion and Analysis of Financial Condition and
Results of Operations - 'Sales, Gas Costs and Net Revenues' and
'Rate and Regulatory Matters'."  Also, for additional information
on the effects of rate regulation, see Part II, Item 8., "Financial
Statements and Supplementary Data, 'Summary of Significant
Accounting Policies and Basis for Financial Statement Presentation-
Regulatory Assets'."
  
                           Competition

         Within its utility service territory, the Company  competes
with suppliers of oil, electricity and other fuels for cooking,
heating, air conditioning and other purposes.   Regulatory changes
have resulted in the unbundling of services in the natural gas
industry.  Beginning on May 1, 1996, customers in the Company's
small-volume market have the option to purchase their gas supplies
from sources other than the Company.  Large volume customers have
had this option for a number of years.  Regardless of whether the
Company's customers purchase gas from the Company or other
suppliers, the customers pay the Company for transporting the gas. 
(See Part II, Item 7., "Management's Discussion and Analysis of
Financial Condition and Results of Operations - 'Sales, Gas Costs
and Net Revenues' and 'Rate and Regulatory Matters'.")  

           The Company has expanded existing markets and is developing
new ones to increase gas sales.  In the residential heating market,
gas is sold in competition with No. 2 grade fuel oil.  During the
year, gas at the burner tip was generally competitive with
alternate grades of fuel oil.  Conversions from oil to gas heat
continued during fiscal 1996.  Approximately 78% of one- and 
two-family homes in the Company's service area now use gas for 

<PAGE>
space heating.

         The Company's share of the multi-family market is
approximately 46%.  In this market, gas service under large-volume
rates is competitively priced with alternate grades of fuel oil. 
In the commercial and industrial markets, the Company offers
special area development and business incentive gas rates to
businesses that move to or expand operations in designated areas in
the Company's territory.

         The Company continues to be committed to obtaining greater
operational efficiencies through aggressive cost-containment
programs, continuous reviews of business processes and the use of
advanced technologies.  

         Further, as a result of deregulation, a significant market for
off-system gas sales, transportation and other services has
developed.  Competition is expected to intensify in this market as
deregulation is more widely implemented in the Northeast.

         Moreover, many in the energy industry, including the Company,
believe that the increasingly deregulated and more competitive
environment may lead to industry consolidation, vertical
integration and other strategic alliances as energy companies seek
to offer a broader range of energy services to compete more
effectively in attracting and retaining customers.  For example,
affiliations with other operating utilities could potentially
result in economies and synergies, and vertical integration could
provide a means to offer customers a more complete range of energy
services.  The Company believes that its proposed holding company
structure, if approved by shareholders, would further expansion and
diversification in energy-related businesses through investments,
acquisitions and strategic alliances.  The Company has been
studying, and in some cases has held discussions regarding, utility
and energy-related investments and transactions.  The Company is
unable to predict whether its activities will lead to investments
and transactions that will result in enhanced competitive
capabilities in the changing industry environment.

         In early December 1995, New York's Governor George Pataki
endorsed a proposal to dismantle the Long Island Lighting Company
(LILCO).  Among other things, the proposal contemplates that the
Long Island Power Authority (LIPA) would issue and sell tax-exempt
bonds to purchase LILCO's electric transmission and distribution
system and regulatory assets, and would assume a portion of LILCO's
debt; LILCO's electric generating facilities and its gas business
would be sold to other companies; and an energy company would
contract with LIPA to manage the transmission and distribution of
electricity to LILCO's customers.  The Company has been following
developments, and has had discussions and explored alternatives 
regarding the possibility of the Company participating in a
combination or other transaction involving LILCO's gas and electric

<PAGE>
businesses and assets.  The Company is unable to predict the course
of developments or whether or how the Company might be involved
should there be a transaction.

                     Environmental Matters

         For information regarding environmental matters affecting the
Company, see Part II, Item 7., "Management's Discussion and
Analysis of Financial Condition and Results of Operations -
'Environmental Matters'," and Part II, Item 8., "Financial
Statements and Supplementary Data," Note 9., "Environmental
Matters." 
                     Research and Development

         In fiscal 1996, the Company spent $12.8 million on research
and development (R&D) programs.  Of this amount, $2.4 million was
spent to support programs of the Gas Research Institute. The
Company also provided $2.1 million to other research associations,
including the New York State Energy Research and Development
Authority (NYSERDA) and the New York Gas Group.  The balance of
$8.3 million was devoted primarily to the Company's internal R&D
programs relating to efficient gas utilization and operations
technologies.  These programs covered cogeneration, power stations,
refrigeration, fuel cells, as well as natural gas refueling
stations.  In addition, the Company continues to make significant
efforts to develop innovative operation systems which reduce
utility costs.  

                            Subsidiaries

         The Company's principal non-utility subsidiaries participate
and own investments in gas exploration, production and processing;
gas pipeline transportation and storage; cogeneration; marketing
and other energy-related services.  In fiscal 1996, earnings from
subsidiaries were $40.5 million, or 82 cents per share, which
included non-recurring gains from initial public offerings of $33.5
million and a reorganization  charge of $7.8 million.  Earnings
excluding these non-recurring items were $14.8 million, or 30 cents
per share.  The Company's total investment in these businesses,
computed in accordance with PSC specifications as a percentage of
consolidated capitalization, was 13.4%, 14.2% and 12.8% as of
September 30, 1996, 1995 and 1994, respectively.  For further
information regarding the subsidiaries, see Part II, Item 7.,
"Management's Discussion and Analysis of Financial Condition and
Results of Operations", Part II, Item 8., "Financial Statements and
Supplementary Data", Note 3., " The Houston Exploration Company",
Note 8., "Investment in Iroquois Pipeline" and Note 10.,
"Supplemental Gas and Oil Disclosures".  

         If the Company's common shareholders approve the holding
company restructuring at the Company's Annual Meeting in February
1997, these non-utility subsidiaries will become subsidiaries of
the 
<PAGE>
holding company, KeySpan, and will no longer be subsidiaries of the
Company. 

Gas Exploration, Production and Processing

         The Houston Exploration Company ("THEC") is an independent
natural gas and oil company engaged in the exploration, development
and acquisition of domestic natural gas and oil properties. THEC's
offshore properties are located in the Gulf of Mexico, and its
onshore properties are located in Texas, the Arkoma Basin and West
Virginia. In contemplation of the initial public offering  (IPO) 
of THEC's common stock, the Company implemented a reorganization of
its exploration and production subsidiaries' assets and liabilities
by transferring to THEC certain onshore producing properties and
acreage not previously owned by THEC. As a result , all U. S. oil
and gas properties of Fuel Resources Inc. ( FRI), a wholly owned
subsidiary of the Company,  were  transferred to THEC. In September
1996, THEC completed the initial public offering of 7,130,000
shares of its common stock at an offering price of $15.50 per share
and two smaller stock issuances, which reduced the Company's
ownership from 100% to approximately 66%. The Company recorded a
$35.4 million gain ($23.0 million after tax) as a result of these
stock issuances and the related net increase in book value of the
Company's investment in THEC.  The proceeds to THEC from the IPO,
after deductions for commissions and offering expenses, were
approximately $101 million and were used to repay a portion of
THEC's short-term borrowings incurred as a result of two major
acquisitions in 1996 of properties and proved gas reserves in South
Texas and the Gulf of Mexico for $84.7 million. In connection with
the reorganization of the exploration and production properties, a
reorganization charge of $7.8 million, net of federal income taxes,
was  recorded by THEC in fiscal 1996. (See Part II, Item 8.,
"Financial Statements and Supplementary Data," Note 3., "The
Houston Exploration Company.")  Total gas production was
approximately 27.3 BCFe (one billion cubic feet of gas including
oil equivalent volumes) during fiscal 1996  and net proved gas
reserves at September 30, 1996 were approximately 322 BCFe.  For
information concerning the gas and oil exploration, development and
producing activities of the Company's subsidiaries, see Part II,
Item 8., "Financial Statements and Supplementary Data," Note 10.,
"Supplemental Gas and Oil Disclosures".

         Solex Development Energy Company, a subsidiary of FRI, 
completed a public offering of trust units in the Taylor gas-
processing plant in British Columbia, Canada, and realized a gain
of $10.5 million, after taxes. This plant had been purchased in
April 1995 and was sold to realize its value. The Company's
subsidiary, KeySpan Energy Canada, Ltd., has an option to
participate in the planned expansion of the plant. 
         
<PAGE>

Investments in Energy Services

Pipeline and Storage 

         North East Transmission Co., Inc. (NETCO) increased its
ownership interest by 8.0% in fiscal 1996 and as a result owns a
19.4% interest in the Iroquois Gas Transmission System L.P.
(Iroquois), a 375-mile pipeline that currently transports
approximately 860 MDTH of Canadian gas supply daily to markets in
the northeastern United States.  The Company currently receives up
to 70 MDTH of gas per day through Iroquois.  For information
regarding the resolution of governmental investigations involving
the Iroquois project, see Part II, Item 8., "Financial Statements
and Supplementary Data," Note 8., "Investment in Iroquois
Pipeline."

         Through a subsidiary, the Company has equity investments in
two gas storage facilities located in New York State.  

Cogeneration

         Gas Energy Inc. (GEI) participates in the development,
operation and ownership of cogeneration projects.  A GEI subsidiary
is a 50% partner in a 100-megawatt facility at John F. Kennedy
International Airport (JFK) in Queens, New York. This facility
commenced operations in 1995.  GEI owns an 11.3% interest in a 
174-megawatt gas cogeneration plant located in Lockport, New York. 
An affiliate is a 50% partner in a 40-megawatt facility that serves
the State University of New York at Stony Brook, Long Island, which
commenced operations in 1995, and is a 45% partner in a 50-megawatt
gas cogeneration plant that has been producing heat and power at a
Northrop Grumman facility located in Bethpage, Long Island, New
York.  

         The scope of cogeneration activities also includes providing
fuel-management services.  GEI subsidiaries provide such services
to the JFK, Stony Brook and Northrop Grumman facilities and to
another 50-megawatt facility.  In 1996, these subsidiaries, as fuel
managers, provided 15,000 MDTH of gas to these cogeneration
projects.

Marketing

         BRING Gas Services Corp., FRI's marketing subsidiary, in
September 1996, sold its 50% interest in PennUnion Energy Services,
L.L.C. to its partner, Pennzoil Gas Marketing Company, an affiliate
of Pennzoil Company.  
         
         KeySpan Energy Services Inc. (KES), formed in April 1996,
sells natural gas both inside and outside the Company's utility
service territory to large commercial and industrial customers, as
well as groups of residential and small commercial customers. It 
<PAGE>
has been authorized by the Federal Energy Regulatory Commission to
market electricity interstate.

         KeySpan Energy Management Inc.(KEM), formed in October 1996,
develops energy-related projects and provides a variety of 
technical and maintenance services for commercial and industrial
customers. KEM has formed a strategic alliance with South Jersey
Industries to develop energy projects in the mid-Atlantic region.

                               Employees

         The Company and its subsidiaries employed 3,336 people at
September 30, 1996, compared to 3,378 at September 30, 1995.  

         In November 1995, a new labor agreement was ratified by the
membership of Local 101 of the Transport Workers Union, which
represents approximately 1,900 utility employees.  The agreement
provides for total wage increases of approximately 9.3% over its
three-year term.  The agreement also provides certain productivity
savings and a gainsharing incentive tied to attainment of certain
corporate goals.  A similar agreement applicable to 200 utility
employees represented by Local 3 of the International Brotherhood
of Electrical Workers was ratified in August 1995.

Item 2. Properties

         In fiscal 1996, consolidated capital expenditures were $ 302.3
million, of which $110.8 million was primarily for utility property
additions and $191.5 million was for subsidiaries.  Consolidated
capital expenditures are estimated to be approximately $195 million
for each of fiscal years 1997 and 1998. 

         The Company holds franchises to lay gas mains in the streets,
highways and public places in the Boroughs of Brooklyn and Staten
Island, and the former Second and Fourth Wards of the Borough of
Queens.  The Company has consents and permits which, with
immaterial exceptions, give it the right to carry on its utility
operations, substantially as now carried on, in the territory
served. The Company's franchises are unlimited in duration, except
that a franchise to transmit and distribute gas in the former Fifth
Ward of the Borough of Staten Island expires in 2006.  Gas sales
revenues in the former Fifth Ward are approximately 2.4% of the
total gas sales revenues of the Company.

         As of September 30, 1996, the Company's distribution pipeline
system consisted of approximately 1,987 miles of cast iron main,
1,677 miles of steel main and 288 miles of mains with plastic
inserts, with requisite accessory compressor and regulating
stations, and one gas storage holder having a capacity of 15 MDTH. 
The distribution system for the most part is located under public
streets. 
<PAGE>
         The Company owns and operates a liquefied natural gas (LNG)
plant, located at its Greenpoint Energy Center in Brooklyn, to
liquefy and store gas during the summer months for vaporization and
use during the winter months.  This plant has a storage capacity of
1,660 MDTH of natural gas in liquid form and a vaporization 
capacity of 291 MDTH per day.

         The Company leases its corporate headquarters at One MetroTech
Center in downtown Brooklyn. The lease agreement has a remaining
term of 15 years and renewal options.  The Company and its
subsidiaries own or lease certain other buildings and facilities
for use in the conduct of their business.  The Company's gross
lease payments are approximately $14.1 million per year.

         Principal consolidated properties of subsidiaries and their
affiliates include gas and oil leasehold interests, producing wells
and related equipment and structures.  For information concerning
the gas exploration, production and processing activities of the
Company's subsidiaries, see Part II, Item 8., "Financial Statements
and Supplementary Data," Note 10., "Supplemental Gas and Oil
Disclosures."
               
Item 3.   Legal Proceedings

         For information regarding the resolution of governmental
investigations involving the  Iroquois project, see Part II, Item
8., "Financial Statements and Supplementary Data," Note 8.,
"Investment in Iroquois Pipeline."  For information regarding
environmental matters affecting the Company, see Part II, Item 7.,
"Management's Discussion and Analysis of Financial Condition and
Results of Operations - Environmental Matters," and Part II, Item
8., "Financial Statements and Supplementary Data," Note 9.,
"Environmental Matters."   

Item 4.   Submission of Matters to a Vote of Security Holders

         There was no matter submitted to a vote of security holders
during the fourth quarter of the fiscal year covered by this report
through solicitation of proxies or otherwise.

                             Part II

Item 5.   Market for the Registrant's Common Stock and Related
          Security Holder Matters

         The following is information regarding the Company's common
stock.  For additional information required by this item, see Part
II, Item 6., "Selected Financial Data" and Part II, Item 8.,
"Financial Statements and Supplementary Data," Note 5.,
"Capitalization."
<PAGE>
Stock Listings
         The Company's common stock is traded on the New York Stock
Exchange (NYSE) under the trading symbol BU.  The Houston
Exploration Company (THEC) common stock is traded on the NYSE under
the trading symbol THX.  Daily stock reports are carried by most
major newspapers under the heading BklyUG and HoustEX,
respectively.

Dividends
         Quarterly dividends on the Company's common stock have been 
payable on the first of February, May, August and November;
preferred dividends are payable on the first of March, June,
September and December.  All dividends paid by the Company are
taxable as ordinary income.  The PSC's holding company order
contains limitations on the level of dividend payments from
Brooklyn Union to KeySpan under certain circumstances, should the
holding company restructuring be approved by shareholders.
         
Annual Meeting
         The next annual meeting of shareholders will be held at the
Company's General Office at 10:00 a.m. on Thursday, February 6,
1997.

Transfer Agent and Registrar of Stock
First Chicago Trust Company of New York
P.O. Box 2500
Jersey City, N.J.  07303-2500
(800)328-5090

Independent Public Accountants
Arthur Andersen LLP
1345 Avenue of the Americas
New York, NY  10105
(212)708-4000 

<PAGE>
Item 6. Selected Financial Data
<TABLE>
<CAPTION>
For the Year Ended September 30,       1996         1995         1994         1993         1992
                                              (Thousands of Dollars Except Per Share Data)

<S>                               <C>          <C>          <C>          <C>          <C> 
Income Summary
Operating revenues                       
   Utility sales                  $1,351,821   $1,152,331   $1,279,638   $1,145,315   $1,038,061     
   Gas production and other           80,181       63,953       58,992       60,189       36,799       
------------------------------------------------------------------------------------------------
Total operating revenues           1,432,002    1,216,284    1,338,630    1,205,504    1,074,860      
Operating expenses
   Cost of gas                       610,053      446,559      560,657      466,573      402,137      
   Operation and maintenance         428,977      385,654      384,734      366,706      336,156      
   Depreciation and depletion         79,610       72,020       69,611       64,779       73,930      
   General taxes                     143,296      134,718      150,743      144,827      135,549      
   Federal income tax                 39,508       41,989       40,556       41,413       30,052      
-------------------------------------------------------------------------------------------------
Operating income                     130,558      135,344      132,329      121,206       97,036      
Income (loss) from energy services 
     investments                      13,523        9,458        5,689        1,150       (1,041)         
Gain on sale of investment in  
   Canadian properties                16,160          -            -         20,462          -            
Gain on sale of subsidiary stock      35,437          -            -            -            -  
Write-off of investment in propane 
     company                             -            -            -        (17,617)         -            
Other, net                            (1,188)         151          700         (465)       5,107        
Federal income tax (expense) benefit (19,861)         (51)        (142)         (70)         833        
Interest charges                      51,721       53,067       51,192       48,103       42,062       
-------------------------------------------------------------------------------------------------
Net income                           122,908       91,835       87,384       76,563       59,873        
Dividends on preferred stock             323          337          351          364        2,078        
-------------------------------------------------------------------------------------------------
Income available for common stock   $122,585      $91,498      $87,033      $76,199      $57,795      
=================================================================================================
Financial Summary
Common stock information
     Per share
         Earnings ($)                   2.48         1.90         1.85         1.73         1.35         
         Cash dividends declared ($)    1.42         1.39         1.35         1.32         1.29         
         Book value, year-end ($)      18.17        16.94        16.27        15.55        14.56        
         Market value, year-end ($)   27 7/8       24 5/8       24 7/8       25 3/4       22 3/8       
     Average shares outstanding (000) 49,365       48,211       46,980       44,042       42,882       
     Shareholders                     33,320       33,669       35,233       30,925       31,367       
     Daily average shares traded      64,500       49,100       42,100       33,100       26,900       
Capital expenditures ($)             302,280      214,006      199,572      204,514      173,467      
Total assets ($)                   2,289,603    2,116,922    2,029,074    1,897,847    1,748,027    
Common equity ($)                    905,808      826,290      774,236      721,076      632,254      
Preferred stock, redeemable ($)        6,600        6,900        7,200        7,500        7,800       
Long-term debt ($)                   712,013      720,569      701,377      689,300      682,031      
Total capitalization ($)           1,624,421    1,553,759    1,482,813    1,417,876    1,322,085    
Earnings to fixed charges (times)       3.99         3.17         3.21         3.19         2.86         
Utility Operating Statistics
Gas data (MDTH)
  Firm sales                        141,948      123,356      133,513      128,972      122,476      
  Other gas and transportation sales 42,950       49,910       42,392       25,032       23,706       
  Maximum daily capacity, year-end    1,284        1,256        1,256        1,258        1,199        
  Maximum daily sendout                 994          963        1,022          915          904          
Total active meters (000)              1,126        1,125        1,122        1,119        1,117        
Heating customers (000)                  461          454          446          441          436          
Degree days                            5,170        4,240        4,974        4,802        4,659        
     Colder (Warmer) than normal (%)     7.7        (11.2)         3.1          -           (4.0)       
</TABLE>    

<PAGE>
Item 7.  Management's Discussion and Analysis of Financial        
         Condition and Results of Operations

Earnings and Dividends

         In fiscal 1996, consolidated income available for common stock
was $122.6 million, or $2.48 per share, compared to $91.5 million,
or $1.90 per share, in 1995, and $87.0 million, or $1.85 per share,
in 1994.  This was the fourth consecutive year of record earnings.

         Consolidated earnings for the last three fiscal years are 
summarized below: 
    <TABLE>
    <CAPTION>  
    __________________________________________________________________________
                                         1996            1995          1994  
   __________________________________________________________________________
                                                 (Thousands of Dollars)
   <S>                                  <C>             <C>          <C>
   Income Available for Common Stock

    Utility                             $ 82,090         $78,677      $76,665
    _________________________________________________________________________
    Gas exploration and production                                       
     Operations (before reorganization
       charge)                             7,627           7,843        5,707
     Reorganization charge                (7,800)             -            -
     Gain on sale of subsidiary stock     23,034              -            -
     Gain on sale of Canadian plant       10,505              -            -
    _________________________________________________________________________
                                          33,366           7,843        5,707
    _________________________________________________________________________
  
    Energy services
     Pipeline and storage                  5,319             979        3,358
     Cogeneration                            414           2,670        1,303
     Marketing                             1,396           1,329            -  
    _________________________________________________________________________
                                           7,129           4,978        4,661 
    _________________________________________________________________________
             Consolidated               $122,585         $91,498      $87,033 

    _________________________________________________________________________

   </TABLE>
         In 1996, regulated utility operations provided an equity
return of 12.80%.  The return, which included incentives authorized
by the New York State Public Service Commission (PSC), was higher
than the allowed rate of 10.65%.  The Company has earned at or
above its allowed return on utility common equity in 17 of the last
18 years.

         In the last three years, income available for common stock
from utility operations has benefited from additions of new firm
gas heating customers, principally as a result of customer 

<PAGE>
conversions from oil to gas for space heating in homes and
buildings, as well as earnings incentives provided under rate
stipulations (see "Rate and Regulatory Matters").  In 1996, such
incentive-based earnings were related largely to higher margins on
sales to large-volume and off-system customers and attaining a 93%
customer satisfaction rating in benchmarks used by the PSC.  The
effect on utility revenues of variations in weather largely was
offset by the weather normalization adjustment included in the
Company's tariff.  Utility operating margins have improved due to
ongoing cost reduction efforts.
 
         In 1996, earnings from gas exploration, production and
processing operations decreased, primarily due to a reorganization
charge of $7.8 million, net of federal income taxes, recorded by
the U.S. exploration and production subsidiary, The Houston
Exploration Company (THEC).  Excluding this charge, operating
results were comparable in 1996 and 1995.  However, earnings in
1996 also included an after-tax gain of $23.0 million on the
issuance by THEC of 34% of its common stock in September 1996 (see
Note 3 to the Consolidated Financial Statements, "The Houston
Exploration Company" for additional information).  Neither the
Company, nor THEC, has plans for any further issuances of THEC
stock, nor the stock of any of the Company's other subsidiaries -
except for issuances under ongoing stock plans .  Further, earnings
included a gain of $10.5 million on the sale in July 1996 of an
investment in a Canadian gas processing plant, which was sold to
realize the substantial value embodied in the investment at the
time.  In 1995, earnings from gas exploration, production and
processing operations increased, primarily due to higher U.S.
natural gas production. 
 
         Earnings from investments in energy services are attributable
to various operations.  In April 1996, a Company subsidiary
increased its equity interest in the Iroquois Gas Transmission
System, L.P. (Iroquois) by 8.0% to 19.4%, resulting in higher 
earnings during the year from Iroquois.  In addition, earnings from
pipeline and storage operations in all periods reflect higher
throughput on Iroquois.  In 1995, earnings were reduced by a
provision for the Company's proportionate share of estimated costs
of legal matters involving Iroquois.  With respect to cogeneration
investments, higher fuel prices caused earnings from these
investments to decrease in 1996.  In 1995, the increase in earnings
reflected equity income from the start of operations at John F.
Kennedy International Airport (JFK) and the campus of the State
University of New York at Stony Brook. 
 
         Earnings from gas marketing in 1996 were $1.4 million, similar
to last year.  Looking toward the future, the Company expects
revenue growth as a result of the rationalization and refocusing of
these operations.  New wholly-owned subsidiaries have been formed
to operate effectively as part of the Company's holding company
strategy.  One of these business units sells gas and expects to
sell electricity inside and outside the traditional utility 
<PAGE>
territory.  The other will provide a variety of technical and 
maintenance management services for commercial and industrial
customers.  The initial focus will be conducted both independently
and through strategic alliances.  As an integral part of this
marketing realignment, a Company subsidiary sold its 50% interest
in the gas-marketing venture, PennUnion Energy Services, L.L.C., to
the other partner.
  
         The consolidated rate of return on average common equity was
13.6% in 1996, 10.9% in 1995, and 11.0% in 1994.

         In December 1995, the Board of Directors authorized an
increase in the annual dividend on common stock to $1.42 per share
from $1.39 per share.  This increase became effective on February
1, 1996, when the quarterly dividend was raised to 35 1/2 cents per
share from 34 3/4 cents per share.  Common dividends have been
increased in 20 consecutive years and paid continuously for 48
years.

Sales, Gas Costs and Net Revenues

         Firm utility gas sales volumes in fiscal 1996 were 141,948
MDTH compared to 123,356 MDTH in 1995 and 133,513 MDTH in 1994. 
Measured by annual degree days, weather was 7.7% colder than normal
in 1996, 11.2% warmer than normal in 1995 and 3.1% colder than
normal in 1994.  Sales growth in all markets resulted primarily
from conversions to natural gas from oil for space heating,
especially by large apartment buildings.  In 1996, the growth in
firm sales normalized for weather was 2.4%, similar to that 
experienced in recent years.
<TABLE>
<CAPTION> 
_________________________________________________________________
                         1996             1995            1994
_________________________________________________________________
                                   (Thousands of Dollars)
<S>               <C>              <C>             <C> 
Utility sales     $ 1,351,821      $ 1,152,331     $ 1,279,638
Cost of gas          (610,053)        (446,559)       (560,657)
_________________________________________________________________
Net revenues      $   741,768      $   705,772     $   718,981
_________________________________________________________________
Gas production 
   and other      $    80,181      $    63,953     $    58,992
_________________________________________________________________
</TABLE>
         In 1996, higher utility sales primarily reflected higher
billings due to colder weather.  In 1995, the opposite occurred as
lower utility sales primarily reflected lower billings for gas
costs due to warm weather.  For additional information regarding
utility sales and net revenues in the last three years, see "Rate
and Regulatory Matters."

         During the year, gas at the burner tip was competitive with
alternative grades of fuel oil.  Residential heating sales in 
<PAGE>
markets where the competing fuel is No. 2 grade fuel oil and sales 
to other small-volume customers were approximately 75% of firm
sales volume in 1996.  Demand in these markets is less sensitive to
periodic differences between gas and oil prices.  In large-volume
heating markets, gas service is provided under rates that are set
to compete with prices of alternative fuel, including No. 6 grade
heating oil.  There is substantial sales potential in these
markets, which include large apartment houses, government buildings
and schools.  Competition with other gas suppliers is expected to
continue to increase as a result of deregulation.

         Moreover, a significant market for off-system gas sales,
transportation and other services has developed as a result of
deregulation.  These sales or services reflect optimal use of
available pipeline capacity as affected by weather and the
Company's New York Market Hub in balancing on-system requirements
to core customers with off-system services to increase total
margins.  In colder-than-normal winters, such as 1996, sales to on-
system customers are higher whereas off-system services are
comparatively lower.  As a result, in 1996 gas and transportation
sales and services to off-system and interruptible customers
amounted  to 42,950 MDTH compared with 49,910 MDTH in 1995.  

         The Company and its gas exploration and production subsidiary
employ derivative financial instruments, such as natural gas and
oil futures, options and swaps, for the purpose of managing
exposures to commodity price risk.  In connection with utility
operations, the Company primarily uses derivative financial
instruments to fix margins on sales to large-volume customers to
which gas is sold at a price indexed to the prevailing price of
oil, their alternate fuel.  Derivative financial instruments are
used by the Company's gas exploration and production subsidiary to
manage the risk associated with fluctuations in the price received
for natural gas production in order to achieve a more predictable
cash flow.  Hedging strategies have been managed independently. 
(See Note 7B to the Consolidated Financial Statements, "Derivative
Financial Instruments," for additional information.)

         The cost of gas, $610.1 million in 1996, was $163.5 million or
36.6% higher than in 1995.  The higher cost reflects higher heating
sales due to colder weather and higher average gas costs.  The cost
of gas in 1994 was $560.7 million reflecting higher volumes sold
and higher average prices, both of which were primarily the result
of cold weather in that year as compared to volumes and prices in
1995.  The cost of gas for firm customers was $3.49 per DTH (one
DTH equals 10 therms) in 1996, compared to $3.12 per DTH in 1995
and $3.55 per DTH in 1994.  For the year ended September 30, 1996,
the utility's cost of gas included hedging losses of $1.7 million
related to its margin fixing strategy.  

         The increase in revenues from gas production and other in 1996
is due primarily to the acquisition of additional natural gas
properties (see Note 3 to the Consolidated Financial Statements, 
<PAGE>
"The Houston Exploration Company", for additional information) and 
increased production from the gas processing plant located in
British Columbia, Canada, which was purchased in April 1995 and was
sold in July 1996.  In 1996, gas production, including oil
equivalents,  was approximately 27.3 billion cubic feet (BCFe), or
4.6 BCFe above the level of production last year.  In 1996,
wellhead prices averaged approximately $2.11 per MCF compared with
$1.47 per MCF last year.  The realized price (average wellhead
price received for production including recognized hedging gains
and losses) was $1.82 per MCF in 1996 compared with $1.77 per MCF
in 1995.  Hence, the Company's hedging strategy stabilized the
weather-related volatility inherent in the wellhead price which
showed an increase on average of 64 cents per MCF in 1996 compared
to 1995.  The effective price increased 5 cents in 1996 compared to
1995.  The effective price in 1996 included a hedging loss of $7.7
million while the effective price in 1995 included a hedging gain
of $6.6 million.  (See Note 10 to the Consolidated Financial
Statements, "Supplemental Gas and Oil Disclosures", for additional
information.)

Expenses, Other Income and Preferred Dividends

         The increase in operation and maintenance expense in 1996
reflects the effects of colder weather compared to last year and
the reorganization charge incurred by the U.S. exploration and
production subsidiaries.  The reorganization charge of $12.0
million reflects remuneration that certain former employees of the
Company's other exploration and production subsidiary were paid as
the result of the increase in the value of the gas and oil
properties transferred to THEC.  The decrease in 1995 reflected
warmer weather and various cost reduction efforts.  In 1994, severe
winter weather caused higher utility gas distribution operation
expense.  The benefit of ongoing cost reduction programs
substantially outweighed the adverse effects of generally higher
labor and material costs.  Moreover, consolidated operation expense
in 1996 and 1995 included costs related to Canadian gas processing
operations, which ceased in July 1996 when the plant was sold.  

         The increase in depreciation and depletion expense in 1996
reflects higher depletion charges of subsidiaries due to increased
gas production and higher utility depreciation expense due to
property additions. 

         General taxes principally include state and city taxes on
utility revenues and property.  The applicable property base
generally has increased, although the Company has been able to
realize significant savings by the aggressive pursuit of reductions
in property value assessments.  Taxes based on revenues reflect the
variations in utility revenues each year.

         Federal income tax expense reflects changes in pre-tax income. 
         
         The increase in earnings from energy services investments in 
<PAGE>
1996 is primarily due to the increase in earnings from Iroquois 
offset by lower cogeneration earnings, as previously discussed. 
Other income also includes pre-tax gains on the sale of the
Canadian plant and on the issuance of 34% of THEC's common stock.

         Interest charges on long-term debt in each of the last three
fiscal years generally reflect higher average subsidiary
borrowings.  In fiscal 1996, interest charges reflected lower
utility interest costs due to debt refunding.  Other interest
expense primarily reflects accruals of carrying charges related to
regulatory settlement items.   

         Dividends on preferred stock reflect reductions in the level
of preferred stock outstanding due to sinking fund redemptions. 

Capital Expenditures

         Consolidated capital expenditures were $302.3 million in 1996,
$214.0 million in 1995 and $199.6 million in 1994.

         Capital expenditures related to utility operations were $110.8
million in 1996, $108.7 million in 1995 and $103.8 million in 1994. 
Utility expenditures in all years principally were for the renewal
and replacement of mains and services.  
         
     Capital expenditures related to gas exploration, production
and processing activities were $169.0 million in 1996, $83.0
million in 1995 and $71.3 million in 1994.  Expenditures in 1996
reflect two major acquisitions totaling $84.7 million for gas and
oil reserves in South Texas and the Gulf of Mexico, as well as on-
going exploration and development activities.  Expenditures in 1996
primarily reflect increased off-shore development activities.  Net
proved gas reserves at September 30, 1996 were approximately 322
BCFe.  These reserves are located off-shore in the Gulf of Mexico
and on-shore in Texas, the Arkoma Basin and West Virginia. 

         Capital expenditures related to energy services investments
were $22.5 million in 1996, $22.3 million in 1995 and $24.5 million
in 1994.  Expenditures in 1996 primarily were for the acquisition
of the additional interest in Iroquois.  Also, in 1996 the
cogeneration plant at JFK was refinanced and cash flows from
investing activities include a return of capital from the proceeds. 
In 1995 and 1994, expenditures were primarily related to the
construction of the JFK cogeneration project and, in 1995, also
included $5.6 million related to the Stony Brook cogeneration
plant.  In 1994, capital expenditures also included the acquisition
of an interest in a cogeneration plant located in Lockport, New
York.

         Consolidated capital expenditures for fiscal years 1997 and
1998 are estimated to be approximately $195 million in each year,
including $85 million per year related to non-utility activities.
The level of such expenditures is reviewed on an ongoing basis and 
<PAGE>
can be affected by timing, scope and changes in investment 
opportunities.

Financing 

         Cash provided by operating activities continues to be strong
and is a substantial source for financing ongoing capital
expenditures.  In 1996, cash flow from utility operations was
reduced by the timing of budget plan billing settlements related to
cold weather. 


         In September 1996, THEC issued 7,130,000 shares of its common
stock in an initial public offering, providing net proceeds of
$101.0 million, which were used to pay down debt and to complete
the financing of gas reserve acquisitions and property additions
discussed previously.

         In addition, proceeds from common stock issued through the
Company's employee and shareholder stock purchase plans have
provided the Company approximately $27.4 million in 1996, $28.0
million in 1995 and $29.8 million in 1994.  The Company issued
1,800,000 new shares of common stock on October 6, 1993, providing
net proceeds of $44.9 million.  

         In March 1996, the Company refunded $153.5 million of Gas
Facilities Revenue Bonds, including a $98.5 million series of 9%
bonds and a $55 million series of 8.75% bonds.  Both series were
called for redemption at optional redemption prices equal to 102%
of the face amount per bond plus accrued interest.  The $153.5
million refunding series, which matures in 2021, was issued on
January 29, 1996, with a coupon rate of 5.5% at a price of 99% of
the principal amount of the bonds.  The Company expects to initiate
a call of its Gas Facilities Revenue Bonds, 7 1/8% Series 1985 I
and 7% Series 1985 II, which are callable on December 1, 1996 at
102% of face amount per bond plus accrued interest to the call
date.  If authorization is received from government agencies, the
bonds would be called early in calendar year 1997.

         At September 30, 1996, the consolidated annualized cost of
long-term debt was 6.3%, compared to 7.1% in 1995 and 6.9% in 1994. 

Financial Flexibility and Liquidity

         At September 30, 1996, the Company had cash and temporary cash
investments of $41.9 million and available bank lines of credit of
$75 million, which lines are available to secure the issuance of
commercial paper.  The lines of credit can be increased to $150
million by December 1996.  Related borrowings primarily are used to
finance seasonal working capital requirements, which in recent
years have not been significant.  At September 30, 1996, there were
no borrowings outstanding.  In addition, subsidiaries have lines of
credit totaling $150 million, which for the most part support 
<PAGE>
borrowings under revolving loan agreements.  (See Note 5C to the 
Consolidated Financial Statements, "Other Long-Term Debt", for
additional information.) 

         At September 30, 1996, the common equity component of the
Company's capitalization was 55.8%.

         Fixed charge coverage ratios were 3.99 times in 1996, 3.17
times in 1995 and 3.21 times in 1994. 

Rate and Regulatory Matters

      Rate Settlement Matters and Holding Company Agreement

In September 1996, the New York State Public Service Commission
(PSC) granted the Company's petition to restructure into a holding
company, to be named KeySpan Energy Corporation.  If the Company's
shareholders approve the restructuring at its Annual Meeting in
February 1997, KeySpan would become the parent holding company of
Brooklyn Union and its subsidiaries (which would become
subsidiaries of KeySpan) through a share exchange whereby the
Company's common shareholders would receive KeySpan common stock,
thus becoming the owners of KeySpan.  The PSC's holding company
order approved a settlement agreement among Brooklyn Union, the
Staff of the Department of Public Service and several intervenor
parties.  This agreement contains restrictions and limitations on
certain investments by KeySpan, limitations on the level of
dividend payments from Brooklyn Union to KeySpan under certain
circumstances, prohibitions on certain intercompany loans,
guarantees and pledges, and restrictions on transactions among the
affiliated holding company group.
 
The agreement reached in the holding company filing included a new
multi-year rate plan that became effective on October 1, 1996.
After an initial rate reduction of approximately $3.0 million in
fiscal 1997, the non-gas component in customer bills will be under
specific price caps.  Hence, the total amount for this component in
rates that the Company can charge customers, in the aggregate, will
remain constant for the subsequent five years, although rates in
certain customer classes may be increased in order to reflect cost
responsibility more appropriately.  The Company also will be
permitted to charge for various ancillary services.  

During the six-year term of the rate plan, the costs of gas
purchased by the Company for its customers will be recovered
currently in billed firm revenues through the operation of a tariff
provision, the Gas Adjustment Clause (GAC).  Further, in addition
to recovering its specific gas costs in applicable rates, the
Company's rates for transporting gas within its local distribution
system provide for full margin recovery of its cost of service. 
(See Notes to Consolidated Financial Statements, "Summary of
Significant Accounting Policies and Basis for Financial Statement
Presentation -- Regulatory Assets".)
<PAGE>
Although there is no specific authorized rate of return on common
equity, the rate plan includes provisions for rate changes if
certain conditions applicable to inflation, exogenous costs or
changes in financial condition occur.   Under the agreement the
Company generally is not subject to any earnings cap or provisions
to share with customers any level of earnings from utility
operations.  However, incentive provisions remain for retention of
20% of margins on sales to off-system customers and capacity
release credits, and expenditures related to remediation of the
sites of former gas manufacturing plants are subject to a provision
enabling the Company to retain any savings, while requiring it to
absorb any costs, to the extent that expenditures vary by 10%
compared with estimates.  The agreement includes a customer service
quality performance plan with a maximum forty basis-point pre-tax
return penalty if service quality diminishes in certain categories
over the term of the agreement.  Also, the weather normalization
adjustment was modified to provide that the Company may recover or
be required to refund 87.5% of all margin shortfalls or surpluses
resulting from weather that is warmer or colder-than-normal. 

In September 1995, the PSC approved the Company's second stage rate
filing covering fiscal 1996.  The approval provided for no base
rate increase; however, $7.5 million in deferred credits were
amortized to income in 1996.  The authorized rate of return on
utility common equity was set at 10.65% for fiscal 1996.

In October 1994, the PSC approved a three-year rate settlement
agreement which provided for no base rate increase in fiscal 1995;
however, the Company amortized to income, as permitted, 
approximately $1.3 million of deferred credits in that year.  The
third year of this agreement was superseded by the PSC order in the
holding company proceeding of September 1996 mentioned above. 

                     Restructuring Proceeding 

The PSC has set forth a policy framework to guide the transition of
New York State's gas distribution industry in the deregulated gas
industry environment.  In March 1996, the PSC issued an order on
utility compliance tariff filings, including the Company's, related
to this framework.  

Pursuant to this order, beginning on May 1, 1996, customers in the
Company's small-volume market have the option to purchase their gas
supplies from sources other than the Company, which would serve as
gas transporter.  Large-volume customers have had this option for
a number of years.  Small-volume  customers can be grouped together
by marketers if their combined minimum threshold usage reaches
50,000 therms of gas per year, which approximates the usage of 35
homes.  The PSC approved the Company's methodology of recovering
the cost of pipeline capacity and storage service provided to
marketing firms and transportation customers.  In addition to
transporting gas that customers purchase from marketers, utilities
such as the Company will provide billing, meter reading and other 
<PAGE>
services for aggregate rates that closely approximate the
distribution charge reflected in otherwise applicable sales rates
to supply these customers.  The PSC order placed a limit on the
amount of gas the Company would be obligated to transport in its
core market under aggregation programs to 5% of total core sales in
each of the next three years, with no more than 25% of any one
service class permitted to convert to transportation service.  

Environmental Matters

         The Company is subject to various Federal, state and local
laws and regulatory programs related to the environment.  These
environmental laws govern both the normal, ongoing operations of
the Company as well as the cleanup of historically contaminated
properties.  Ongoing environmental compliance activities, which
historically have not been material, are integrated with the
Company's operations and maintenance activities.  As of September
30, 1996, the Company had an accrued liability of $28.8 million
representing costs associated with investigation and remediation at
former manufactured gas plant sites.  (See Note 9 to the
Consolidated Financial Statements, "Environmental Matters," for
additional information.)
<PAGE>
Item 8.   Financial Statements and Supplementary Data

Financial Statement
Responsibility


The Consolidated Financial Statements of the Company and its
subsidiaries were prepared by management in conformity with
generally accepted accounting principles.

         The Company's system of internal controls is designed to
provide reasonable assurance that assets are safeguarded and that
transactions are executed in accordance with management's
authorizations and recorded to permit preparation of financial
statements that present fairly the financial position and operating
results of the Company.  The Company's internal auditors evaluate
and test the system of internal controls.  The Company's Vice
President and General Auditor reports directly to the Audit
Committee of the Board of Directors, which is composed solely of
outside directors.  The Audit Committee meets periodically with
management, the Vice President and General Auditor and Arthur
Andersen LLP to review and discuss internal accounting controls,
audit results, accounting principles and practices and financial 
reporting matters.

<PAGE>
            REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To The Brooklyn Union Gas Company:

We have audited the accompanying Consolidated Balance Sheet and
Consolidated Statement of Capitalization of The Brooklyn Union Gas
Company (a New York corporation) and subsidiaries as of September
30, 1996 and 1995, and the related Consolidated Statements of
Income, Retained Earnings and Cash Flows for each of the three
years in the period ended September 30, 1996.  These financial
statements are the responsibility of the Company's management.  Our
responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits in accordance with generally accepted
auditing standards.  Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement.  An audit
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements.  An audit also
includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall
financial statement presentation.  We believe that our audits
provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position and
capitalization of The Brooklyn Union Gas Company and subsidiaries
as of September 30, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the
period ended September 30, 1996, in conformity with generally
accepted accounting principles.

Our audits were made for the purpose of forming an opinion on the
basic consolidated financial statements taken as a whole.  The
schedule listed in Item 14 is the responsibility of the Company's
management and is presented for the purpose of complying with the
Securities and Exchange Commission's rules and is not part of the
basic consolidated financial statements. This schedule has been
subjected to the auditing procedures applied in the audits of the
basic consolidated financial statements and, in our opinion, fairly
states in all material respects the financial data required to be
set forth therein in relation to the basic consolidated financial 
statements taken as a whole.

ARTHUR ANDERSEN LLP


October 23, 1996
New York, New York

<PAGE>
Summary of Significant Accounting Policies and Basis for Financial
Statement Presentation

Principles of Consolidation

The Consolidated Financial Statements reflect the accounts of the
Company and its subsidiaries.  All significant intercompany
transactions are eliminated.  All other adjustments are of a
normal, recurring nature and certain reclassifications have been
made to amounts in prior periods to conform them with the current
period presentation. 

         Further, the preparation of financial statements in conformity
with generally accepted accounting principles requires management
to make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting
period.  Actual results could differ from those estimates.

Utility Gas Property -
Depreciation and Maintenance

Utility gas property is stated at original cost of construction,
which includes allocations of overheads and taxes and an allowance
for funds used during construction.

         Depreciation is provided on a straight-line basis in amounts
equivalent to composite rates on average depreciable property of
3.4% in 1996 and 1995, and 3.3% in 1994.

         The cost of property retired, plus the cost of removal less
salvage, is charged to accumulated depreciation.  The cost of
repair and minor replacement and renewal of property is charged to
maintenance expense.

Gas Exploration and Production Property - Depletion
and Depreciation

The Company's gas exploration and production subsidiary follows the
full cost method of accounting.  All productive and nonproductive
costs identified with acquisition, exploration and development are
capitalized.  Provisions for depletion are based on the units-of-
production method and, when necessary, include provisions related
to the asset ceiling test limitations required by the regulations
of the Securities and Exchange Commission.  Costs of unevaluated
gas and oil properties are excluded from the amortization base
until proved reserves are established or an impairment is
determined.

         Provisions for depreciation of all other non-utility property 
are computed on a straight-line basis over useful lives of three to
<PAGE>
fifteen years.

Investments in Energy Services

Certain subsidiaries own as their principal assets investments
representing ownership interests of 50% or less in energy-related
businesses that are accounted for under the equity method.

Revenues

Utility customers generally are billed bi-monthly on a cycle basis. 
Revenues include unbilled amounts related to the estimated gas
usage that occurred from the last meter reading to the end of each
month.

         Revenue requirements to establish utility rates are based on
sales to customers.  Gas costs are recovered currently in billed
firm revenues through the operation of a tariff provision, the Gas
Adjustment Clause (GAC).  Net revenues from off-system gas sales
and tariff gas balancing services and capacity release credits are
refunded to firm customers subject to certain limited sharing
provisions in the Company's tariff.  Prior to October 1, 1996, net
revenues from tariff sales for gas and transportation services to
on-system customers made on an interruptible basis were refunded to
firm customers subject to sharing provisions.  The GAC provision
requires an annual reconciliation of recoverable gas costs and GAC
revenues.  Any difference is deferred pending recovery from or
refund to firm customers during a subsequent twelve-month period. 

         
Derivative Financial Instruments

The Company and THEC use derivative financial instruments primarily
to hedge exposures in cash flows due to fluctuations in the price
of natural gas and fuel oil, which in certain markets may strongly
influence the Company's selling price for natural gas.  Gains and
losses on these instruments are recognized concurrently with the
recognition of the related physical transactions.

The Company regularly assesses the relationship between natural gas
commodity prices in "cash" and futures markets.  The correlation
between prices in these markets has been well within a range
generally deemed to be acceptable.  If correlation were not to
remain in an acceptable range, the Company would account for its
financial instrument positions as trading activities.

Federal Income Tax

Prior to the adoption in 1994 of SFAS-109, "Accounting for Income
Taxes", pursuant to PSC policy, deferred taxes were not provided
for certain construction costs incurred before fiscal 1988 and for
bases differences related to differences between tax and book 
<PAGE>
depreciation methods.  In accordance with SFAS-109, the Company
recorded a regulatory asset for the net cumulative effect of having
to provide deferred Federal income tax expense on all differences
between the tax and book bases of assets and liabilities at the
current tax rate.  

         Investment tax credits, which were available prior to the Tax
Reform Act of 1986,  were deferred in operating expense and are
amortized as a reduction of Federal income tax in other income over
the estimated life of the related property.

Regulatory Assets

The Company is subject to the provisions of Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation".  Regulatory assets arise from the
allocation of costs and revenues to accounting periods for utility
ratemaking purposes differently from bases generally applied by
nonregulated companies.  Regulatory assets are recognized in
accordance with SFAS-71.  With the exception of net tax regulatory
assets all other significant assets and liabilities created by the
ratemaking process, including the $33.2 million recorded for
environmental remediation costs as of September 30, 1995, have been
reflected in utility rates pursuant to the agreement approved by
the PSC in its September 25, 1996 holding company order. 
Accordingly, at September 30, 1996 the Company had only a net tax
regulatory asset of $74,885,000 compared to a regulatory asset of
$109,636,000 related to taxes and environmental costs at September
30, 1995.

         In the event that it were no longer subject to the provisions
of SFAS-71, the Company estimates that the write-off of this net
regulatory tax asset could result in a charge to net income of
approximately $48,675,000 which would be classified as an
extraordinary item.

Subsidiary Common Stock Issuances to Third Parties

         The Company follows an accounting policy of income statement
recognition for parent company gains or losses from issuances of
stock by subsidiaries.

Research and Development Costs

         All research and development costs are expensed as incurred. 
For the years ended September 30, 1996, 1995 and 1994, these costs 
were $12.8 million, $11.9 million and $11.9 million, respectively.
   
  

    <PAGE>
    CONSOLIDATED STATEMENT OF INCOME
    <TABLE>
    <CAPTION>
    =====================================================================================
    For the Year Ended September 30,                      1996          1995         1994
    =====================================================================================
                                                               (Thousands of Dollars)
    <S>                                                <C>           <C>          <C> 
    Operating Revenues
       Utility sales                                   $ 1,351,821   $1,152,331   $1,279,638
    Gas production and other                                80,181       63,953       58,992       
    ----------------------------------------------------------------------------------------
                                                         1,432,002    1,216,284    1,338,630    
    ----------------------------------------------------------------------------------------
    Operating Expenses
       Cost of gas                                         610,053      446,559      560,657      
       Operation and maintenance                           428,977      385,654      384,734      
       Depreciation and depletion                           79,610       72,020       69,611      
       General taxes                                       143,296      134,718      150,743      
       Federal income tax (See Note 1)                      39,508       41,989       40,556      
    ----------------------------------------------------------------------------------------
    Operating Income                                       130,558      135,344      132,329      
    Other Income
        Income from energy services investments             13,523        9,458        5,689      
        Gain on sale of investment in Canadian plant        16,160          -            -       
        Gain on sale of subsidiary stock (See Note 3)       35,437          -            -       
        Other, net                                          (1,188)         151          700     
        Federal income tax (See Note 1)                    (19,861)         (51)        (142)       
    -----------------------------------------------------------------------------------------
    Income Before Interest Charges                         174,629      144,902      138,576      
    Interest Charges
       Long-term debt                                       46,803       47,939       46,900      
       Other                                                 4,918        5,128        4,292      
    ----------------------------------------------------------------------------------------
    Net Income                                             122,908       91,835       87,384      
    Dividends on Preferred Stock                               323          337          351      
    ----------------------------------------------------------------------------------------
    Income Available for Common Stock                  $   122,585   $   91,498   $   87,033     
    ========================================================================================
    Earnings Per Share of Common Stock
       (Average shares outstanding of 49,365,435,
        48,211,220 and 46,979,597, respectively)       $      2.48   $     1.90   $     1.85        
    ========================================================================================
    </TABLE>
    CONSOLIDATED STATEMENT OF RETAINED EARNINGS
    <TABLE>
    <CAPTION>
    =======================================================================================
    For the Year Ended September 30,                         1996         1995         1994
    ---------------------------------------------------------------------------------------
                                                               (Thousands of Dollars)
    <S>                                                <C>           <C>          <C>
    Balance at Beginning of Year                       $   303,709   $  279,466   $  255,979
    Income Available for Common Stock                      122,585       91,498       87,033      
    ----------------------------------------------------------------------------------------
                                                           426,294      370,964      343,012      
    Less:
          Cash dividends declared ($1.42, $1.39 and $1.35
              per common share, respectively)               70,291       67,229       63,652      
        Other adjustments                                       30           26         (106)     
   -----------------------------------------------------------------------------------------
       Balance at End of Year                          $   355,973   $  303,709   $  279,466     
   =========================================================================================
    The accompanying Summary of Significant Accounting Policies and Basis for Financial Statement
    Presentation and Notes to Consolidated Financial Statements are integral parts of these statements.
    </TABLE>
    
    <PAGE>
    <TABLE>
    <CAPTION>
    ===============================================================================================
    CONSOLIDATED BALANCE SHEET
    September 30,                                                      1996                  1995
                                                                          (Thousands of Dollars)
    <S>                                                        <C>                 <C>              
    Assets   
    Property
       Utility, at cost                                         $    1,782,440      $     1,690,193
       Accumulated depreciation                                       (429,476)            (393,263)
       Gas exploration and production, at cost (See Note 3)            510,568              353,847 
       Accumulated depletion                                          (165,414)            (138,136)
    ------------------------------------------------------------------------------------------------
                                                                     1,698,118            1,512,641 
    ------------------------------------------------------------------------------------------------
    Investments in Energy Services (See Note 8)                        115,529              121,023 
    ------------------------------------------------------------------------------------------------
    Current Assets
       Cash                                                             18,524               15,992 
       Temporary cash investments                                       23,397               24,550 
       Accounts receivable                                             172,843              146,018 
       Allowance for uncollectible accounts                            (15,616)             (13,730)
       Gas in storage, at average cost                                  91,813               88,810 
       Materials and supplies, at average cost                          12,089               13,203 
       Prepaid gas costs                                                11,945               15,725 
       Other                                                            38,888               19,856 
    ------------------------------------------------------------------------------------------------  
                                                                       353,883              310,424 
    ------------------------------------------------------------------------------------------------
    Deferred Charges                                                   122,073              172,834 
    ------------------------------------------------------------------------------------------------
                                                                $    2,289,603      $     2,116,922 
    ================================================================================================
    Capitalization and Liabilities    
    Capitalization (See accompanying statement and Note 5)
       Common equity                                            $      905,808      $       826,290
       Preferred stock, redeemable                                       6,600                6,900  
       Long-term debt                                                  712,013              720,569  
    ------------------------------------------------------------------------------------------------  
                                                                     1,624,421            1,553,759  
    ------------------------------------------------------------------------------------------------ 
    Current Liabilities                                            
       Accounts payable                                                143,561              103,705     
       Dividends payable                                                18,229               17,536     
       Taxes accrued                                                    10,905                3,635     
       Customer deposits                                                21,881               22,252     
       Customer budget plan credits                                      8,892               24,790     
       Interest accrued and other                                       37,244               39,438     
    ------------------------------------------------------------------------------------------------
                                                                       240,712              211,356     
    ------------------------------------------------------------------------------------------------
    Deferred Credits and Other Liabilities
       Federal income tax                                              282,041              247,882     
       Unamortized investment tax credits                               20,007               20,948     
       Other                                                            43,573               82,977     
    ------------------------------------------------------------------------------------------------             
                                                                       345,621              351,807     
    ------------------------------------------------------------------------------------------------
    Minority Interest in Subsidiary Company (See Note 3)                78,849                  -
    ------------------------------------------------------------------------------------------------
                                                                $    2,289,603      $     2,116,922
    ================================================================================================
    The accompanying Summary of Significant Accounting Policies and Basis for Financial Statement
    Presentation and Notes to Consolidated Financial Statements are integral parts of these statements. 
    </TABLE>
    
    <PAGE>
    CONSOLIDATED STATEMENT OF CAPITALIZATION
    <TABLE>
    <CAPTION>  
    =========================================================================================
    September 30,                                                        1996          1995
    -----------------------------------------------------------------------------------------
    <S>                                                             <C>           <C> 
                                                                       (Thousands of Dollars)
   
    Common Equity
    Common stock, $.33 1/3 par value, authorized 70,000,000 shares;
        outstanding 49,857,448 and 48,788,320 shares,                                
        respectively                                                $    549,835  $    522,581
    Retained earnings (See accompanying statement)                       355,973       303,709
    ------------------------------------------------------------------------------------------     
                                                                         905,808       826,290
    ------------------------------------------------------------------------------------------
    Preferred Stock, Redeemable 
      $100 par value, cumulative, authorized 900,000 shares
        4.60% Series B, 69,000 and 72,000 shares outstanding, respectively 6,900         7,200
         Less: Current sinking fund requirements                             300           300
    ------------------------------------------------------------------------------------------     
                                                                           6,600         6,900
    ------------------------------------------------------------------------------------------
     Long-term Debt 
      Gas facilities revenue bonds (issued through New York
        State Energy Research and Development Authority)
        9% Series 1985A due May 2015                                         -          98,500
        8 3/4% Series 1985 due July 2015                                     -          55,000
        6.368% Series 1993A and Series 1993B due April 2020               75,000        75,000
        7 1/8% Series 1985 I due December 2020                            62,500        62,500
        7% Series 1985 II due December 2020                               62,500        62,500
        5.5% Series 1996 due January 2021                                153,500           -
        6.75% Series 1989A due February 2024                              45,000        45,000
        6.75% Series 1989B due February 2024                              45,000        45,000
        5.6% Series 1993C due June 2025                                   55,000        55,000
        6.95% Series 1991A and Series 1991B due July 2026                100,000       100,000
        5.635% Series 1993D-1 and Series 1993D-2 due July 2026            50,000        50,000
     -----------------------------------------------------------------------------------------   
                                                                         648,500       648,500
      Unamortized premium - Long-term debt                                (1,489)          -
      Subsidiary borrowings                                               65,002        72,069
     ----------------------------------------------------------------------------------------- 
                                                                         712,013       720,569 
     -----------------------------------------------------------------------------------------
                                                                    $  1,624,421  $  1,553,759
     =========================================================================================
    
       The accompanying Summary of Significant Accounting Policies and Basis for Financial Statement
    Presentation and Notes to Consolidated Financial Statements are integral parts of these statements. 
   </TABLE>  
  
  <PAGE>
  CONSOLIDATED STATEMENT OF CASH FLOWS  
  <TABLE>
  <CAPTION>
 ============================================================================================================== 
 For the Year Ended September 30,                                          1996           1995             1994
 -------------------------------------------------------------------------------------------------------------- 
                                                                             (Thousands of Dollars)
 <S>                                                                 <C>             <C>             <C>
 CASH FLOWS FROM OPERATING ACTIVITIES
    Net income                                                       $   122,908     $    91,835     $    87,384
    Adjustments to reconcile net income                                                                      
         to net cash provided by operating activities:
      Depreciation and depletion                                          83,006          77,696          75,386 
      Deferred Federal income tax                                         25,985          11,037          10,897 
      Gain on sale of investment in Canadian operations                  (16,160)            -               -    
      Gain on sale of subsidiary stock                                   (35,437)            -               -
      Income from energy services investments                            (13,523)         (9,458)         (5,689)    
      Dividends received from energy services investments                 11,031           3,595           4,392 
      Change in accounts receivable, net                                 (24,939)         44,712          31,906 
      Change in accounts payable                                          39,856         (29,283)        (34,121)
      Gas inventory and prepayments                                          777           6,208           5,498 
     Other                                                                 8,863          14,439          18,474 
 --------------------------------------------------------------------------------------------------------------- 
   Cash provided by operating activities                                 202,367         210,781         194,127 
 ---------------------------------------------------------------------------------------------------------------  
 CASH FLOWS FROM FINANCING ACTIVITIES
      Sale of common stock                                                27,407          27,974          29,828 
      Proceeds from sale of subsidiary stock                             101,041             -               - 
      Common stock proceeds receivable                                       -               -            44,910 
      Issuance of long-term debt                                         153,500          19,192          12,077 
      Repayments of long-term debt and preferred stock                  (160,867)           (300)           (300)     
      Dividends paid                                                     (70,614)        (67,566)        (64,003)  
 ---------------------------------------------------------------------------------------------------------------- 
   Cash provided by (used for)financing activities                        50,467         (20,700)         22,512   
 ----------------------------------------------------------------------------------------------------------------  
   CASH FLOWS FROM INVESTING ACTIVITIES
       Capital expenditures (excluding allowance                                                             
        for equity funds used during construction)                      (301,307)       (212,732)       (197,496)  
       Proceeds from sale of investment in Canadian plant                 26,938             -            11,691   
       Partnership distribution 1996 and other                            22,914           9,702           1,398   
 ----------------------------------------------------------------------------------------------------------------  
   Cash used in investing activities                                    (251,455)       (203,030)       (184,407)  
 ----------------------------------------------------------------------------------------------------------------  
   Change in Cash and Temporary Cash Investments                           1,379         (12,949)         32,232   
   Cash and Temporary Cash Investments at Beginning of Year               40,542          53,491          21,259   
 ----------------------------------------------------------------------------------------------------------------  
   Cash and Temporary Cash Investments at End of Year                $    41,921     $    40,542     $    53,491
 ================================================================================================================     
Temporary cash investments are short-term marketable securities purchased with maturities of three months or
 less that are carried at cost which approximates their fair value.
      Supplemental disclosures of cash flows 
      Income taxes                                                   $    37,053     $    36,000     $    36,900
      Interest                                                       $    53,210     $    53,047     $    50,872
 ================================================================================================================
   The accompanying Summary of Significant Accounting Policies and Basis for Financial Statement
    Presentation and Notes to Consolidated Financial Statements are integral parts of these statements. 
</TABLE>

<PAGE>
                                 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>

1.  FEDERAL INCOME TAX
Income tax expense (benefit) is reflected as follows in the
Consolidated Statement of Income:

                                                           
Year Ended September 30,         1996      1995      1994         
                                  (Thousands of Dollars)
<S>                            <C>      <C>        <C>
Operating Expenses                                                
   Current                     $ 27,766 $ 31,676   $ 38,403
   Deferred                      11,742   10,313      2,153
                                 39,508   41,989     40,556
Other Income
   Current                        6,559      379     (7,528) 
   Deferred                      14,243      724      8,744
   Amortization of investment
     tax credits                   (941)  (1,052)    (1,074)
                                 19,861       51        142 
                                                    
Total Federal income tax       $ 59,369 $ 42,040   $ 40,698 
</TABLE>

The components of the Company's net deferred income tax liability
reflected as Deferred Credits and Other Liabilities - Federal
income tax in the Consolidated Balance Sheet are as follows:
<TABLE>
<CAPTION>

September 30,                          1996          1995   
                                     (Thousands of Dollars)
<S>                                <C>           <C>          
Utility property                   $ 176,565     $ 180,708        
Gas production and other property     69,488        49,402                     
Net tax regulatory asset              26,210        28,214     
Other                                  9,778       (10,442)  
Net deferred income tax liability  $ 282,041     $ 247,882   
</TABLE>

<PAGE>
The following is a reconciliation between reported income tax and
tax computed at the statutory rate of 35%:
<TABLE>
<CAPTION>

Year Ended September 30,          1996      1995      1994        
                                   (Thousands of Dollars)
<S>                            <C>       <C>       <C>
Computed at statutory rate     $ 63,797  $ 46,856  $ 44,828
Adjustments related to:
  Gas production tax credits     (1,962)   (2,730)   (1,303) 
  Nontaxable interest income       (678)     (870)     (556)
  Amortization of investment
   tax credits                     (941)   (1,052)   (1,074)
  Other, net                       (847)     (164)   (1,197)  
Total Federal income tax       $ 59,369  $ 42,040  $ 40,698   
Effective income tax rate           33%       31%       32%    
</TABLE>

2.  POSTRETIREMENT BENEFITS
A.  Pension:  The Company has a noncontributory defined benefit
pension plan covering substantially all employees.  Benefits are
based on years of service and compensation. The Company's funding
policy for pensions is in accordance with requirements of Federal
law and regulations.  There were no pension contributions in 1996,
1995 and 1994.  Special retirement programs were initiated in 1995
and 1994.

The calculation of net periodic pension cost follows:
<TABLE>
<CAPTION>

                                                             
Year Ended September 30,       1996       1995       1994         
                                 (Thousands of Dollars)
<S>                           <C>        <C>       <C>
Service cost, benefits earned
  during the year             $ 15,160   $ 11,533  $ 15,100 
Special retirement charge         -         5,416     8,465  
                                15,160     16,949    23,565       
   
Interest cost on projected
  benefit obligation            37,128     35,128    29,511   
Return on plan assets          (78,930)   (82,626)  (12,430) 
Net amortization and deferral   31,745     34,786   (32,798) 
Total pension cost            $  5,103   $  4,237  $  7,848  
 
</TABLE>

<PAGE>
The following table sets forth the plan's funded status and
amounts recognized in the Company's Consolidated Balance Sheet. 
Plan assets principally are investment grade common stock and 
fixed income securities:
<TABLE>
<CAPTION>

September 30,                     1996             1995           
                                  (Thousands of Dollars)
<S>                               <C>            <C>
Actuarial present value of
  benefit obligations:  
 Vested                           $(414,988)     $(401,159)
 Accumulated                      $(439,278)     $(423,434)

 Projected                        $(563,852)     $(545,825)
 
Plan assets at fair value         $ 608,080      $ 555,906    

Plan assets in excess of
  projected benefit obligation    $  44,228      $  10,081

Unrecognized net loss (gain)
  from past experience different
  from that assumed and from 
  changes in assumptions            (32,755)        10,880

Unrecognized transition asset       (27,914)       (32,566)
                                                              
Accrued pension liability         $ (16,441)     $ (11,605)   
Assumptions:
 Obligation discount                   7.25%          7.00%
 Asset return                          7.75%          7.50%
 Average annual increase
  in compensation                      5.50%          5.50%       
          
</TABLE>
B.  Other - Retiree Health Care and Life Insurance:  The Company
sponsors noncontributory defined benefit plans under which it
provides certain health care and life insurance benefits for
retired employees.  The Company has been funding a portion of
future benefits over employees' active service lives through a
Voluntary Employee Beneficiary Association (VEBA) trust. 
Contributions to VEBA trusts are tax deductible, subject to
limitations contained in the Internal Revenue Code.  The Company's
policy is to fund the cost of postretirement benefits in a tax
effective manner as part of its overall strategy to manage the
costs of its benefit programs for employees. 

<PAGE>
Net periodic other postretirement benefit cost included the
following components:
<TABLE>
<CAPTION>

Year Ended September 30,               1996          1995         
                                     (Thousands of Dollars)
<S>                                  <C>          <C>
Service cost, benefits earned 
 during the year                     $ 3,178      $ 2,590
Interest cost on accumulated 
 postretirement benefit obligation    10,673        9,958
Return on plan assets                 (9,382)      (6,746)
Net amortization and deferral         10,961        6,752
                                                              
Other postretirement benefit cost    $15,430      $12,554     
</TABLE>
The following table sets forth the plans' funded status, reconciled
with amounts recognized in the Company's Consolidated Balance
Sheet:
<TABLE>
<CAPTION>

                                                              
September 30,                           1996         1995         
                                     (Thousands of Dollars)
<S>                                   <C>         <C>
Actuarial present value of accumulated
 postretirement benefit obligation 
    Retirees                           $ (88,278)  $ (87,022)
    Fully eligible active plan                                                 
    participants                         (18,271)    (10,980)
  Other active plan participants         (63,762)    (56,157)     
                                       $(170,311)  $(154,159)    
Plan assets at fair value, primarily 
 stocks and bonds                      $  93,452   $  72,638   
Accumulated postretirement benefit 
 obligation in excess of plan assets   $ (76,859)  $ (81,521)
Unrecognized net loss from past 
 experience different from that assumed
 and from changes in assumptions          29,285      25,345
Unrecognized transition obligation        64,015      67,781      
 
Prepaid other postretirement benefit   $  16,441   $  11,605    
Assumptions:
 Obligation discount                       7.25%       7.00%                   
 Asset return                              7.75%       7.50%      
</TABLE>   
The measurement also assumes a health care cost trend rate of 8.5%
annually  decreasing to 5.0% by the year 2007 and remaining at that
level thereafter.  A 1.0% increase in the health care cost trend
rate would have the effect of increasing the accumulated
postretirement benefit obligation as of September 30, 1996 and the
net periodic SFAS-106 expense by approximately $23,825,000 and
$1,935,000, respectively.
<PAGE>
3.  THE HOUSTON EXPLORATION COMPANY (THEC)
Certain former employees of Fuel Resources Inc., the subsidiary of
the Company that previously owned certain onshore natural gas and
oil producing properties and acreage, were entitled to receive
remuneration for the increase in the value of these properties
should these properties be sold or transferred.  These former
employees were paid, and a reorganization charge of $12.0 million
was recorded in operation and maintenance expense in the
accompanying Consolidated Statement of Income as a result of the
transfer of these properties to THEC in 1996.

In September, 1996, THEC completed an initial public offering (the
IPO) of 7,130,000 shares of its common stock at an offering price
of $15.50 per share.  The cash proceeds to THEC from the IPO, after
deductions for commissions and offering expenses, were $101.0
million and were used to repay a portion of THEC's short-term
borrowings incurred as a result of two major acquisitions in 1996
of properties and proved gas reserves for $84.7 million.  One of
these acquisitions also required THEC to issue, in conjunction with
the IPO, 762,387 shares (the number of shares being determined by
the IPO price) of its common stock as consideration for the $11.8
million portion of the acquisition's purchase price that was to be
funded with THEC's stock.

Further, in September 1996, THEC issued, also in conjunction with
the IPO, 145,161 shares of its common stock to its President for
certain of his working interests, valued at $2.3 million, in
properties owned by THEC.  As a result of these three stock
issuances, the Company's ownership in THEC was reduced from 100% to
approximately 66% and the Company recorded a $35.4 million gain
($23.0 million after tax) in recognition of the net increase in the
book value of the Company's investment in THEC.

4.  FIXED OBLIGATIONS
A.  Leases:  Lease costs included in operation expense were
$13,894,000 in 1996, $14,706,000 in 1995 and $15,547,000 in 1994. 
The future minimum lease payments under the Company's various
leases, all of which are operating leases, are approximately
$14,143,000 per year over the next five years and $149,547,000 in
the aggregate for years thereafter.
  
The Company has a lease agreement with a remaining term of 15 years
for its corporate headquarters. 

B.  Fixed Charges Under Firm Contracts:  The Company has entered
into various contracts for gas delivery and supply services.  The
contracts have remaining terms that cover from one to seventeen   
years.  Certain of these contracts require payment of monthly
charges in the aggregate amount of approximately $4.3 million per
month in all events and regardless of the level of service
available.  Such charges are recovered as gas costs.

<PAGE>
5.  CAPITALIZATION
A.  Common and Preferred Stock:   In 1996 and 1995, the Company
issued 1,069,128 and 1,198,305 shares of common stock for
$27,407,000 and $27,974,000, respectively, under the Dividend
Reinvestment and Stock Purchase Plan, the Discount Stock Purchase
Plan for Employees, and the Employee Savings Plan. At September 30,
1996, 2,355,942 unissued shares of common stock were reserved for
issuance under these plans.  Other changes to common stock reflect
the amortization of premiums paid on preferred stock redeemed in
prior years which were deferred in order to reflect the ratemaking
treatment.  Annual amortization was approximately $155,000 in each
of the past two years.

The 4.60% Series B preferred stock is subject to an annual sinking
fund requirement of 3,000 shares at par value.  

B.  Gas Facilities Revenue Bonds and Other:  The Company can issue
tax-exempt bonds through the New York State Energy Research and
Development Authority.  Whenever bonds are issued for new gas
facilities projects, proceeds are deposited in trust and
subsequently withdrawn by the Company to finance qualified
expenditures.

There are no sinking fund requirements for any Gas Facilities
Revenue Bonds.  The Company's 7 1/8% Series 1985 I  and 7% Series
1985 II Gas Facilities Revenue Bonds became callable on December 1,
1996, at the optional redemption price of 102% of par value plus
accrued interest.  The Company is seeking authorization of
government agencies for the call and refunding of these bond
issues.

C.  Other Long-Term Debt:  THEC has a $150 million unsecured line
of credit which for the most part supports borrowings under a
revolving loan agreement.  Up to $5 million of this line is
available for the issuance of letters of credit to support
performance guarantees.  This credit facility matures on July 1,
2000.  At September 30, 1996, borrowings of $65 million were
outstanding under this line of credit and $1.6 million was
committed under outstanding letter of credit obligations. 
Borrowings under this facility bear interest, at THEC's option, at
rates indexed at a premium to the Federal Funds rate or LIBOR, or
based on the prime rate.  The interest rate on this debt was 6.5%
per annum at fiscal year-end.  Covenants related to this line of
credit require the maintenance of certain financial ratios and
involve other restrictions regarding cash dividends, the purchase
or redemption of stock and the pledging of assets.    

6. STOCK OPTIONS AND AWARDS
On November 15, 1995, the Company implemented the Long-Term
Performance Incentive Compensation Plan and granted 202,800
nonqualified stock options and 13,000 performance shares to
officers. The number of shares of Common Stock reserved for 

<PAGE>
issuance under this Plan is 1,500,000 in the aggregate; however, no
more than 750,000 shares will be available for issuance pursuant to
the exercise of the stock options. 

The stock options were awarded at an exercise price of $27.00 (the
fair market value on the grant date).  They vest ratably over a
three-year period from the grant date with a ten-year exercise
period. The stock options were not exercisable as of September 30,
1996. The performance shares granted represent the target number of
shares, as defined under the Plan, that will vest at the end of a
three-year performance period ending on September 30, 1998. The
actual number of performance shares to be earned is contingent upon
achieving target levels of total shareholder return in relation to
the Standard & Poor's Utilities Index. The actual awards will range
from 0 to 200% of the target number of shares.
 
In October 1995, the FASB issued Statement No. 123, "Accounting for
Stock-Based Compensation".  This statement requires companies to
either recognize compensation costs attributable to employee stock
options (or similar equity instruments) in net income or, in the
alternative, provide pro forma footnote disclosure on net income
and earnings per share.  Implementation of this statement is
required in the Company's 1997 fiscal year.  The Company does not
anticipate that the provisions of this statement will have a
material effect on the Company's net income.   

7.  FINANCIAL INSTRUMENTS
A.  Fair Value of Financial Instruments:  The Company's long-term
debt consists primarily of publicly traded Gas Facilities Revenue
Bonds,  the fair value of which is estimated based on quoted market
prices for the same or similar issues.  The fair value of these
bonds at September 30, 1996 and 1995 was $660,499,600 and
$673,408,300, respectively, and the carrying value was $648,500,000
in both years.  Subsidiary debt is carried at an amount
approximating fair value because its interest rate is based on
current market rates.

The fair value of the Company's redeemable preferred stock is
estimated based on quoted market prices for similar issues.  At
September 30, 1996 and 1995, the fair value of this stock was 
$4,958,300 and $5,228,800, respectively, and the carrying value was
$6,600,000 and $6,900,000, respectively.

All other financial instruments included in the Consolidated
Balance Sheet are stated at amounts that approximate fair values.

B.  Derivative Financial Instruments:  The Company and THEC employ
derivative financial instruments - natural gas futures, options and
swaps - for the purpose of managing commodity price risk.  

The utility tariff applicable to certain large-volume customers
permits gas to be sold at prices established monthly within a 
<PAGE>
specified range expressed as a percentage of prevailing alternate
fuel oil prices.  The Company uses derivatives, primarily futures,
to fix profit margins on specified portions of the sales to this
market in line with pricing objectives.  Implementation of the
strategy involves establishment of long (buy) positions in gas
futures contracts with offsetting short (sell) positions in oil
futures contracts of equivalent energy value that are capped by
options over the same time period.   The long gas futures position
follows, generally within a range of 80% to 120%, the cost of gas
to serve this market while the short oil futures position
correspondingly replicates, within the same range, the selling
price of gas.  The Company has developed a strong sense of the
relationship between gas and oil prices in the target markets, and
the implementation of its strategy has satisfactorily hedged its
exposure to the loss of profit margins on the desired portion of
anticipated sales.

With respect to natural gas production operations, THEC generally
uses swaps and standard New York Mercantile Exchange futures
contracts or options to hedge the price risk related to known
production plans and capabilities.  These instruments include a
fixed price/volume and the swaps are structured as both straight
and participating swaps.  In all cases, THEC pays the other parties
the amount by which the floating variable price (settlement price)
exceeds the fixed price and receives the amount by which the
settlement price is below the fixed price.    

Two participating swap contracts covering 1,860,000 and 930,000 Mcf
in 1997 and 1998, respectively, are priced at $1.98 and $2.05.  The
volumes under these two swaps are reduced by 50% in each month
where the NYMEX prices for that month exceed the fixed price under
the swap contract.

<PAGE>
The following table summarizes the notional amounts and related
fair values of the Company's derivative financial instrument
positions outstanding at September 30, 1996.  Fair values are based
on quotes for the same or similar instruments.  Differences between
the notional contract amounts and fair values represent implicit
gains on gas contracts representing long positions or losses on oil
contracts representing short positions if the instruments were
settled at market.
__________________________________________________________________
<TABLE>
<CAPTION> 
 Gas
Type of      Fiscal Year  Fixed Price  Volume   Notional    Fair
Instrument   of Maturity   per Mcf      (Mcf)     Amount    Value
                                                   (in thousands)
<S>                      <C>          <C>         <C>      <C>
Futures contracts 1997   $1.97-$2.39  13,630,000  $30,447  $30,613
Options           1997   $2.30-$3.00   3,020,000  $   -    $   964
Swap contracts    1997   $1.53-$2.09  16,858,000  $32,219  $32,165
                  1998   $1.53-$2.09   4,280,000  $ 8,054  $ 8,166
</TABLE>
<TABLE>
<CAPTION>  
 Oil
Type of      Fiscal Year  Fixed Price  Volume   Notional    Fair
Instrument   of Maturity  per Gallon  (Gallons)  Amount    Value
                                                   (in thousands)
<S>                      <C>         <C>          <C>      <C>    
Futures contracts 1997   $0.49-$0.58 122,556,000  $66,297  $81,530
                  1998      $0.52      6,342,000  $ 3,315  $ 3,592
Options           1997   $0.13-$0.22  63,672,000  $   211  $ 1,018
__________________________________________________________________
</TABLE>
Futures contracts expire and are renewed monthly.  As of September
30, 1996, no such contract extended beyond January 1998.  Further,
swaps contracts are settled monthly and extend through March 1998. 
Margin deposits with brokers at September 30, 1996 and 1995
amounted to $23,619,000 and $1,662,400, respectively, and are
recorded in Other in the current assets section of the balance
sheet.  Deferred gains (losses) on closed positions were $1,330,000
and ($748,000) at September 30, 1996 and 1995, respectively.

The Company and THEC are exposed to credit risk in the event of
nonperformance by counterparties to derivative contracts, as well
as nonperformance by the counterparties of the transactions against
which they are hedged.  The Company believes that the credit risk
related to the futures, options and swap contracts is no greater
than that associated with the primary contracts which they hedge,
as these contracts are with major investment grade financial
institutions, and that elimination of the price risk lowers the
Company's overall business risk.  

8.  INVESTMENT IN IROQUOIS PIPELINE
A Company subsidiary, North East Transmission Co., Inc. (NETCO),
owns a 19.4% partnership interest in Iroquois Gas Transmission
System, L.P. (Iroquois).  Iroquois owns a 375-mile pipeline
extending from Canada to the Northeast United States.   NETCO's 

<PAGE>
investment in Iroquois was $35.4 million at September 30, 1996.

In 1992 Iroquois was informed that Federal criminal and civil
investigations of the construction of certain of its pipeline
facilities had been commenced.  The investigations were to
determine whether Iroquois violated various environmental and other
laws in the construction of such facilities.  In addition,
beginning in late 1993, Iroquois was informed by the Federal Energy
Regulatory Commission (FERC), the Army Corps of Engineers, the U.S.
Department of Transportation (DOT) and the New York State Public
Service Commission that each of these agencies had also commenced
investigations regarding the construction of pipeline facilities.

On May 23, 1996, as part of a comprehensive resolution of these
investigations, Iroquois Pipeline Operating Company (IPOC), the
operator of the pipeline, pleaded guilty to four felony violations
of the Clean Water Act and entered into consent decrees under the
Clean Water Act in four federal judicial districts.  Although not
a named defendant, Iroquois signed the plea agreement and consent
decrees and is bound by their terms.  Iroquois also entered into a
related settlement with the State of New York.  Under these various
agreements, Iroquois and IPOC agreed to pay $22 million in fines
and penalties, agreed to remediate 27 wetlands along the length of
the pipeline, and agreed to implement under FERC and DOT orders two
ten-year plans to address certain ground stability and pipeline
safety concerns.  Iroquois also entered into a separate settlement
with the FERC.  In September 1995, a provision was made in the
Company's Consolidated Statement of Income for NETCO's share of the
estimated settlement costs.  This provision was adequate to account
for NETCO's share of the above costs.                             
                            
9.  ENVIRONMENTAL MATTERS
Historically, the Company, or predecessor entities to the Company,
owned or operated several former manufactured gas plant (MGP)
sites.  These sites have been identified for the New York State
Department of Environmental Conservation (DEC) for inclusion on
appropriate waste site inventories.  In certain circumstances,
former MGP sites can give rise to environmental cleanup
responsibilities for the Company.

Two MGP sites are under active consideration by the Company.  One
site, which is located on property still owned by the Company, is
the former Coney Island MGP facility located in Brooklyn, New York. 
This site is the subject of continuing interim remedial action
under the direction of the U.S. Coast Guard.  The Company executed
a consent order with the DEC addressing the overall remediation of
the Coney Island site in accordance with state law.  A schedule of
investigative and cleanup activities is being developed, leading to
a cleanup over the next several years.  The other site currently is
owned by the City of New York (City).  The Company and the City are
discussing a mutual approach to sharing potential environmental
responsibility for this site.  The Company believes it is likely 
that, at a minimum, investigative costs will be incurred by the 

<PAGE>
Company with respect to that site.

Based upon the Coney Island site consent order and the estimated
costs of investigation of the City site, the Company believes that
the minimum cost of MGP-related environmental cleanup will be
approximately $34 million, based upon current information,
primarily for the Coney Island site.  The Company's actual MGP-
related costs may be substantially higher, depending upon
remediation experience, eventual end use of the sites, and
environmental conditions not addressed in the consent order or
current investigative plans.  Such potential additional costs are
not subject to estimation at this time.

As of September 30, 1996, the Company had an unpaid liability of
$28.4 million.  By order issued February 16, 1995, the PSC approved
the Company's July 1993 petition to defer the costs associated with
environmental site investigation and remediation incurred in 1993
and thereafter.  Recovery of these costs began in fiscal year 1995,
and is conditioned upon absence of a PSC determination that such
costs have not been reasonably or prudently incurred.  In addition,
the Company must demonstrate that it has taken all reasonable steps
to obtain cost recovery from all available funding sources,
including other responsible parties and insurance sources.

Moreover, the rate agreement that became effective on October 1,
1996, described in "Rate and Regulatory Matters" of Management's
Discussion and Analysis of Results of Operations and Financial
Condition, provides, among other things, that if the total cost of
investigating and remediating the Coney Island site plus the cost
of investigating the City site varies from the amount originally
accrued for these activities, the Company will retain or absorb 10%
of the variation.  Under the rate agreement, similar ratemaking
treatment will be available for any additional accrued liabilities
for other MGP sites, should such accrual be required. 

<PAGE>
NOTE 10.  SUPPLEMENTAL GAS AND OIL DISCLOSURES (Unaudited)

This information includes amounts attributable to a 34% minority
interest in THEC at September30, 1996.  In addition, gas and oil
operations, and reserves, were predominantly located in the United
States in all years.

<TABLE>
<CAPTION>
CAPITALIZED COSTS RELATING TO GAS AND OIL PRODUCING ACTIVITIES
---------------------------------------------------------------------------
September 30,                                               1996      1995
----------------------------------------------------------------------------
                                                      (Thousands of Dollars)
<S>                                                     <C>       <C>  
Unproved properties not being amortized                  $60,137   $35,082
Properties being amortized-productive and nonproductive  441,024   299,398
---------------------------------------------------------------------------
Total capitalized costs                                  501,161   334,480
Accumulated depletion                                   (160,128) (132,809)
---------------------------------------------------------------------------  
  Net capitalized costs                                 $341,033  $201,671
---------------------------------------------------------------------------
At September 30, 1996 and 1995, the Company had an immaterial deficiency
in its asset ceiling test; however, such deficiency was eliminated by
subsequent increases in the price of natural gas.
</TABLE>

<TABLE>
<CAPTION>
The following is a break-out of the costs (in thousands of dollars) which
are excluded from the amortization calculation as of September 30, 1996,
by year of acquisition:  1996-$36,557; 1995-$13,312; and prior years-$10,268. 
The Company cannot accurately predict when these costs will be included in
the amortization base, but it is expected these costs will be evaluated
within the next five years.

COSTS INCURRED IN PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT
 ACTIVITIES                                                
-------------------------------------------------------------------            
                              1996      1995      1994    
-------------------------------------------------------------------
                               (Thousands of Dollars)                           
<S>                       <C>       <C>       <C> 
Acquisition of properties-
  Unproved properties      $24,577   $10,996   $11,022  
  Proved properties         89,828    14,983    28,370  
Exploration                 20,828     5,907    18,961    
Development                 31,005    37,953     9,781  
------------------------------------------------------------------
Total costs incurred      $166,238   $69,839   $68,134  
------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>

RESULTS OF OPERATIONS FROM GAS AND OIL PRODUCING ACTIVITIES
------------------------------------------------------------------             
                                1996      1995       1994   
------------------------------------------------------------------             
                                 (Thousands of Dollars)   
<S>                           <C>       <C>       <C>
Revenues from gas and oil
  producing activities-
Sales to unaffiliated parties  $50,431   $40,810   $41,185    
Sales to affiliates                 -         -      2,023  
------------------------------------------------------------------  
Revenues                        50,431    40,810    43,208  
------------------------------------------------------------------
Production and lifting costs     8,860     5,762     5,360  
Depletion                       27,368    22,906    24,978  
------------------------------------------------------------------  
  Total expenses                36,228    28,668    30,338  
------------------------------------------------------------------
Income before taxes             14,203    12,142    12,870  
Income taxes                     3,037     1,957     3,306  
------------------------------------------------------------------
Results of gas and oil producing 
  activities (excluding corporate
  overhead and interest costs) $11,166   $10,185    $9,564    
==================================================================
</TABLE>

<PAGE>
10. SUPPLEMENTAL GAS AND OIL DISCLOSURES (CONTINUED)

The gas and oil reserves information is based on estimates of
proved reserves attributable to the Company's interest as of
September 30 for each of the years presented.  These estimates
principally were prepared by independent petroleum consultants. 
Proved reserves are estimated quantities of natural gas and crude
oil which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions.
   
The standardized measure of discounted future net cash flows was
prepared by applying year-end prices of gas and oil to the
Company's proved reserves, except for those reserves devoted to
future production that is hedged.  These reserves are priced at
their respective hedged amount.  The standardized measure does not
purport, nor should it be interpreted, to present the fair value of
the Company's gas and oil reserves.  An estimate of fair value
would also take into account, among other things, the recovery of
reserves not presently classified as proved, anticipated future
changes in prices and costs, and a discount factor more
representative of the time value of money and the risks inherent in
reserve estimates.
<TABLE>
<CAPTION>

RESERVE QUANTITY INFORMATION
Natural Gas (MMcf)
---------------------------------------------------------------
                                    1996       1995     1994 
---------------------------------------------------------------
<S>                                <C>       <C>       <C>
Proved Reserves-
  Beginning of Year                195,055   142,858   108,847  
  Revisions of previous estimates     (354)   13,539    (2,297)  
  Extensions and discoveries        13,139    38,985    25,890   
  Production                       (26,435)  (21,822)  (22,814) 
  Purchases of reserves in place   134,325    21,495    34,931   
  Sales of reserves in place        (1,189)     -       (1,699) 
---------------------------------------------------------------
Proved Reserves-
  End of Year                      314,541   195,055   142,858   
---------------------------------------------------------------
Proved Developed Reserves-
  Beginning of Year                151,594   110,225   100,454   
--------------------------------------------------------------- 
  End of Year                      222,522   151,594   110,225   
===============================================================
</TABLE>

<TABLE>
<CAPTION>
Crude Oil, Condensate and Natural Gas Liquids (MBbls)
---------------------------------------------------------------
                                      1996      1995      1994 
---------------------------------------------------------------
<S>                                  <C>       <C>       <C>  
Proved Reserves-
  Beginning of Year                  1,162       807       443 
  Revisions of previous estimates     (148)      245      (140)      
  Extensions and discoveries           182       155       155        
  Production                          (136)     (148)      (96)    
  Purchases of reserves in place       294      103       495     
  Sales of reserves in place          (106)       -        (50)  
---------------------------------------------------------------
Proved Reserves-
  End of Year                        1,248     1,162       807   
---------------------------------------------------------------
Proved Developed Reserves-
  Beginning of Year                    974       543       407   
---------------------------------------------------------------  
  End of Year                        1,040       974       543   
---------------------------------------------------------------
</TABLE>
<PAGE>
10.  SUPPLEMENTAL GAS AND OIL DISCLOSURES (CONTINUED)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED GAS AND OIL RESERVES
<TABLE>
<CAPTION>
---------------------------------------------------------------
                                1996      1995
---------------------------------------------------------------                
                           
                           (Thousands of Dollars)
<S>                        <C>        <C> 
Future cash flows           $554,798  $314,627
Future costs-
  Production                 (89,303)  (57,941) 
  Development                (60,926)  (29,948)
---------------------------------------------------------------
Future net inflows
  before income tax          404,569   226,738
Future income taxes          (59,623)  (43,705)
---------------------------------------------------------------
Future net cash flows        344,946   183,033 
10% discount factor          (85,688)  (49,512)
---------------------------------------------------------------
Standardized measure of
  discounted future net
  cash flows                $259,258  $133,521 
---------------------------------------------------------------
</TABLE>
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
FROM PROVED RESERVE QUANTITIES
<TABLE>
<CAPTION>
----------------------------------------------------------------
                                    1996      1995      1994  
----------------------------------------------------------------
                                      (Thousands of Dollars)
<S>                              <C>        <C>      <C> 
Standardized measure-
  beginning of year               $133,521  $108,134  $110,406 
Sales and transfers, net of 
  production costs                 (41,571)  (35,048)  (37,848)
Net change in sales and
  transfer prices, net of 
  production costs                  44,719    (2,786)  (25,005)   
Extensions and discoveries and
  improved recovery, net of
  related costs                     18,894    28,868    15,536    
Changes in estimated future
  development costs                 (4,798)   (2,351)   (1,016)     
Development costs incurred
  during the period that reduced
  future development costs          15,056    10,360     6,381       
Revisions of quantity estimates     (2,338)   13,858    (2,917)   
Accretion of discount               16,880    11,763    12,397    
Net change in income taxes          21,026    (7,856)    4,001    
Purchases of reserves in place      94,945    15,176    27,561    
Sales of reserves in place             -         -      (2,110)
Changes in production rates

  (timing) and other               (37,076)   (6,597)      748 
------------------------------------------------------------------
Standardized measure-end
  of year                         $259,258  $133,521  $108,134   
------------------------------------------------------------------
</TABLE>

<PAGE>
10.  SUPPLEMENTAL GAS AND OIL DISCLOSURES (CONTINUED)
<TABLE>
<CAPTION>
Average Sales Prices and Production Costs - Per Unit
------------------------------------------------------------------
For the year ended September 30,      1996      1995     1994
------------------------------------------------------------------
<S>                                 <C>        <C>      <C> 
Average Sales Price*
     Natural Gas ($/MCF)              2.11      1.47      1.97 

     Oil, Condensate and Natural
      Gas Liquid ($/Bbl)             19.21     16.92     15.63

Production Cost Per
 Equivalent MCF ($)                    .32       .25       .23
------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Acreage
------------------------------------------------------------------
As of September 30, 1996              Gross               Net
------------------------------------------------------------------
<S>                                 <C>               <C>         
Producing                           258,798           160,154
Undeveloped                         111,087            88,554
------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Number of Producing Wells
------------------------------------------------------------------
As of September 30, 1996              Gross             Net
------------------------------------------------------------------
<S>                                   <C>              <C>
Gas Wells                             1,114             678
Oil Wells                                11               3
------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Drilling Activity (Net)
------------------------------------------------------------------
                          For the year ended September 30, 
                      1996             1995               1994
           Pro-                  Pro-              Pro-
           ducing   Dry  Total   ducing Dry Total  ducing Dry Total
<S>           <C>   <C>    <C>    <C>   <C>  <C>    <C>   <C>  <C> 
   
Net Develop-       
mental Wells  10.1   0.8   10.9   10.0  3.4  13.4   6.6    -   6.6
Net Explora-     
tory Wells     2.1   3.4    5.5    1.4  0.4   1.8   2.5   1.2  3.7
-------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Wells in Process
As of September 30, 1996              Gross             Net
<S>                                     <C>             <C>
Exploratory                             4.0             1.1
Developmental                           2.0             1.1
-------------------------------------------------------------------
</TABLE>
* Represents the cash price received which excludes the effect of
any hedging transactions.

<PAGE>
SUPPLEMENTARY INFORMATION (UNAUDITED)

QUARTERLY INFORMATION

                  SUMMARY OF QUARTERLY INFORMATION

The following is a table of financial data for each quarter of fiscal
1996 and 1995.  The Company's business is influenced by seasonal weather
conditions and the timing of approved base utility tariff rate changes.
The effect on utility earnings of variations in revenues caused by
abnormal weather is largely mitigated by operation of a weather
normalization adjustment contained in the Company's tariff.
<TABLE>
<CAPTION>
=========================================================================
                           First       Second      Third       Fourth
                           Quarter     Quarter     Quarter     Quarter
=========================================================================       
                    (Thousands of Dollars Except Per Share Data)
<S>                        <C>          <C>         <C>         <C>    
1996
  Operating revenues        398,083     595,438     254,311     184,170
  Operating income(loss)     57,400      88,505       5,495     (20,842)(a)
  Gains on sale of subsidiary
    stock and Canadian plant
    (after taxes)               -           -           -        33,539
  Income (loss) applicable
    to common stock          44,624      74,413      (4,561)      8,109
  Per common share:
    Earnings (loss) (b)        0.91        1.51       (0.09)       0.16
    Dividends declared       0.3550      0.3550      0.3550      0.3550
--------------------------------------------------------------------------
1995
  Operating revenues        358,348     481,615     217,696     158,625
  Operating income(loss)     54,580      85,364       5,650     (10,250)
  Income (loss) applicable
    to common stock          42,753      73,555      (6,188)    (18,622)
  Per common share:
    Earnings (loss) (b)        0.90        1.53       (0.13)      (0.38)
    Dividends declared       0.3475      0.3475      0.3475      0.3475
=========================================================================
</TABLE>
(a)  Includes a subsidiary reorganization charge of $7.8 million after 
     taxes.
(b)  Quarterly earnings per share are based on the average number of 
     shares outstanding during the quarter.  Because of the increasing 
     number of common shares outstanding in each quarter, the sum of   
     quarterly earnings per share does not equal earnings per share 
     for the year.                   

<TABLE>
<CAPTION>

                  SUMMARY OF QUARTERLY STOCK INFORMATION

============================================================================
                                    First       Second     Third     Fourth
                                    Quarter     Quarter    Quarter   Quarter
============================================================================
<S>                                <C>         <C>        <C>       <C> 
1996
  High                              29 5/8      29 7/8     27 1/2    28 1/8
  Low                               24 5/8      25 3/4     24 7/8    24 7/8
  Close                             29 1/4      26 3/4     27 1/4    27 7/8
  Shares Traded (000)               3,710       3,884      5,121     3,592
---------------------------------------------------------------------------- 
1995
  High                              25 3/8      24 3/4     26 3/8    26 3/8
  Low                               21 1/2      22         23 3/4    23 1/4
  Close                             22 1/4      24 1/8     26 1/4    24 5/8
  Shares Traded (000)               2,695       3,977      2,543     3,219
============================================================================
</TABLE> 
<PAGE>
Item 9. Changes in and Disagreements with Accountants on 
        Accounting and Financial Disclosure

      There have been no changes in accountants. In addition, there
have been no disagreements between the Company and its independent
public accountants concerning any matter of accounting principles
or practices or financial disclosure required to be disclosed by
this item.

                           Part   III

Item 10.  Directors and Executive Officers of the Registrant

         Information regarding the Company's directors is incorporated
herein by reference to pages 33 through 39 of the Company's
Prospectus/Proxy Statement, dated December 20, 1996, for its Annual
Meeting of Shareholders to be held on February 6, 1997.

         Information regarding the Company's executive officers, who
are elected annually by the directors, is found on page 52 hereof.

Item 11.  Executive Compensation

         Information regarding compensation of the Company's executive
officers is incorporated herein by reference to pages 39 through 47
of the Company's Prospectus/Proxy Statement, dated December 20,
1996, for its Annual Meeting of Shareholders to be held on February
6, 1997.

Item 12.  Security Ownership of Certain Beneficial Owners and 
          Management

         Information regarding beneficial ownership and management
ownership is incorporated herein by reference to "Proposal (2) -
Election of Directors of Brooklyn Union" in the Company's
Prospectus/Proxy Statement, on pages 37 and 38, dated December 20,
1996, for its Annual Meeting of Shareholders to be held on February
6, 1997. 

Item 13.  Certain Relationships and Related Transactions

         There are no transactions, or series of similar transactions,
or contemplated transactions which have occurred since the
beginning of the last fiscal year of the Company which exceed
$60,000 and involve any director or executive officer of the
Company.

         No executive officer or director of the Company was indebted
to the Company or its subsidiaries at any time since the beginning
of the last fiscal year of the Company in an amount in excess of
$60,000.


<PAGE>      
                          Part   IV

Item 14.  Exhibits, Financial Statement Schedules, and Reports on
          Form 8-K

(a)   1.  All Financial Statements
                                                       Page in    
                                                      Form 10-K

Report of Independent Public Accountants                   26     
                         
Summary of Significant Accounting Policies and
  Basis of Financial Statement Presentation                27     
  
Consolidated Statement of Income for the Years
  Ended September 30, 1996, 1995 and 1994                  30     
     
Consolidated Statement of Retained Earnings for
  the Years Ended September 30, 1996, 1995
   and 1994                                                30
               
Consolidated Balance Sheet at September 30, 1996
  and 1995                                                 31

Consolidated Statement of Capitalization at
  September 30, 1996 and 1995                              32     
                  
Consolidated Statement of Cash Flows for the
  Years Ended September 30, 1996, 1995 and 1994            33     
    

Notes to Consolidated Financial Statements                 34  

(a)   2.  Financial Statement Schedules

The following additional data should be read in conjunction with
the financial statements included in Part II, Item 8.  Schedules
not included herein have been omitted because they are not
applicable or the required information is shown in such financial
statements or notes thereto.

<PAGE>
Executive Officers of the Registrant
------------------------------------
All Executive Officers serve one-year terms.
<TABLE>
<CAPTION>
                                 Age as of
                                 Sept. 30,  Period Served
<S>                                <C>      <C>             <C>
Name and Position                  1996     In Such Capacity Business Experience in Past 5 Years

Robert B. Catell, Chairman           59     1996 to Present  Chairman and Chief Executive Officer
and Chief Executive Officer                 1991 to 1996     President and Chief Executive Officer 
                                            1990 to 1991     President and Chief Operating Officer 
    
Craig G. Matthews, President         53     1996 to Present  President and Chief Operating Officer
and Chief Operating Officer                 1994 to 1996     Executive Vice President 
                                            1991 to 1994     Executive Vice President and Chief
                                                             Financial Officer                  
                                             1988 to 1991    Group Senior Vice President and Chief
                                                             Financial Officer
 
   
Helmut W. Peter                      64     1996 to Present  Vice Chairman                          
Vice Chairman                               1992 to 1996     Executive Vice President 
                                            1991 to 1992     Executive Vice President and Chief 
                                                             Engineer
                                            1988 to 1991     Group Senior Vice President and
                                                             Chief Engineer
    
Anthony J. DiBrita                   55     1992 to Present  Senior Vice President
Senior Vice President                       1989 to 1992     Vice President
    
Vincent D. Enright, Senior Vice      52     1994 to Present  Senior Vice President and Chief 
President and Chief Financial                                Financial Officer
Officer                                     1992 to 1994     Senior Vice President
                                            1984 to 1992     Vice President
    
William K. Feraudo                   46     1994 to Present  Senior Vice President
Senior Vice President                       1989 to 1994     Vice President
    
Wallace P. Parker, Jr.               47     1994 to Present  Senior Vice President
Senior Vice President                       1990 to 1994     Vice President
                                                
Lenore F. Puleo                      43     1994 to Present  Senior Vice President
Senior Vice President                       1990 to 1994     Vice President
    
Maurice K. Shaw, Senior Vice         57     1993 to Present  Senior Vice President and Corporate
President and Corporate Affairs Officer                      Affairs Officer
                                            1987 to 1993     Senior Vice President and Chief 
                                                             Marketing Officer
    
Edward J. Sondey                     58     1992 to Present  Senior Vice President
Senior Vice President                       1981 to 1992     Vice President

   
Tina G. Barber, Vice President       47     1994 to Present  Vice President and Chief 
and Chief Information Officer                                Information Officer
                                            1992 to 1994     Vice President
    
Richard M. Desmond, Vice             62     1992 to Present  Vice President, Comptroller and 
President, Comptroller and                                   Chief Accounting Officer
Chief Accounting Officer                    1984 to 1992     Vice President and Comptroller
      
Robert H. Preusser, Vice President   59     1992 to Present  Vice President and Chief Engineer
and Chief Engineer                          1987 to 1992     Vice President
    
Roger J. Walz, Vice President        51     1990 to Present  Vice President and General Auditor
and General Auditor                                                         
    
Robert R. Wieczorek, Vice President, 54     1994 to Present  Vice President, Secretary  
Secretary and Treasurer                                      and Treasurer

                                            1989 to 1994     Vice President, Treasurer, and 
                                                             Assistant Secretary
</TABLE>

<PAGE>
(a)  3.   Exhibits
(3)  Articles of incorporation and by-laws

By-laws of the Company, dated February 1, 1996, duly filed in     
    December 1996 as Exhibit 3(b) on KeySpan Energy Corporation's 
    Form S-4.

Restated Certificate of Incorporation of the Company filed                     
    August 1, 1989, and Certificate of Amendment filed 
    July 2, 1993; incorporated by reference from Exhibit 4(b) to  
    Form S-3 Registration Statement No. 33-50249.

(4)  Instruments defining the rights of security holders, including 
    indentures:
     
Official Statement, dated December 4, 1985, respective of
    $125,000,000 of New York State Energy Research and Development 
    Authority Variable Rate Gas Facilities Revenue Bonds Series   
    1985 I and 1985 II, incorporated by reference from Form 10-K  
    for the year ended September 30, 1985.

Participation Agreement, dated as of December 1, 1985, between the 
    New York State Energy Research and Development Authority and  
    The Brooklyn Union Gas Company relating to the Variable Rate  
    Gas Facilities Revenue Bonds Series 1985 I and 1985 II,       
    incorporated by reference from Form 10-K for the year ended   
    September 30, 1985.

Indenture of Trust, dated December 1, 1985, between New York 
    State Energy Research and Development Authority and Chemical  
    Bank, as Trustee, relating to the Variable Rate Gas Facilities 
    Revenue Bonds Series 1985 I and 1985 II, incorporated by      
    reference from Form 10-K for the year ended September 30, 1985.

Official Statement, dated February 23, 1989, respective of                   
    $90,000,000 of the New York State Research and Development    
    Authority Adjustable Rate Gas Facilities Revenue Bonds Series 
    1989A and Series 1989B, incorporated by reference from Form S-8 
   Registration Statement No. 33-29898.

Participation Agreement, dated as of February 1, 1989, between the 
    New York State Energy Research and Development Authority and  
    The Brooklyn Union Gas Company relating to the Adjustable Rate 
    Gas Facilities Revenue Bonds Series 1989A, incorporated by    
    reference from Form 10-K for the year ended September 30, 1989.

Participation Agreement, dated as of February 1, 1989, between the 
    New York State Energy Research and Development Authority and  
    The Brooklyn Union Gas Company relating to the Adjustable Rate 
    Gas Facilities Revenue Bonds Series 1989B, incorporated  by   
    reference from Form 10-K for the year ended September 30, 1989.
<PAGE>
Indenture of Trust, dated February 1, 1989, between the                         
    New York State Energy Research and Development Authority and  
    Manufacturers Hanover Trust Company, as Trustee, relating to  
    the Adjustable Rate Gas Facilities Revenue Bonds Series 1989A, 
    incorporated by reference from Form 10-K for the year ended   
    September 30, 1989.

Indenture of Trust, dated February 1, 1989, between the                         
    New York State Energy Research and Development Authority and  
    Manufacturers Hanover Trust Company, as Trustee, relating to  
    the Adjustable Rate Gas Facilities Revenue Bonds Series 1989B, 
    incorporated by reference from Form 10-K for the year ended   
    September 30, 1989.

Official Statement, dated July 24, 1991, respective of                          
    $50,000,000 of the New York State Research and Development    
    Authority Gas Facilities Revenue Bonds Series 1991A and       
    $50,000,000 of the New York State Research and Development    
    Authority  Gas Facilities Revenue Bonds Series 1991B,         
    incorporated by reference from Form 10-K for the year ended   
    September 30, 1991. 

Participation Agreement, dated as of July 1, 1991,between the New 
   York State Energy Research and Development Authority and The   
   Brooklyn Union Gas Company relating to the Gas Facilities      
   Revenue Bonds Series 1991A and 1991B, incorporated by reference 
   from Form 10-K for the year ended September 30, 1991. 

Indenture of Trust, dated as of July 1, 1991, between the                      
    New York State Energy Research and Development Authority and  
    Manufacturers Hanover Trust Company, as Trustee, relating to  
    the Gas Facilities Revenue Bonds Series 1991A and 1991B,      
    incorporated by reference from Form 10-K for the year ended   
    September 30, 1991. 

Official Statement, dated July 23, 1992, respective of                         
   $37,500,000 of the New York State Energy Research and          
   Development Authority Gas Facilities Revenue Bonds Series 1993A 
   and $37,500,000 of the New York State Energy Research and      
   Development Authority Gas Facilities Revenue Bonds Series 1993B, 
  incorporated by reference from Form 10-K for the year ended     
  September 30, 1992.

Participation Agreement, dated as of July 1, 1992, between the New 
   York State Energy Research and Development Authority and The   
   Brooklyn Union Gas Company relating to the Gas Facilities      
   Revenue Bonds Series 1993A and 1993B, incorporated by reference 
   from Form 10-K for the year ended September 30, 1992.


<PAGE>
Indenture of Trust, dated as of July 1, 1992, between the New York 
   State Energy Research and Development Authority and Chemical   
   Bank, as Trustee, relating to the Gas Facilities Revenue Bonds 
   Form Series 1993A and 1993B, incorporated by reference from Form 
  10-K for the year ended September 30, 1992. 
                           
Official Statement, dated April 29, 1992, respective of 
   $90,000,000 of the New York State Energy Research and          
   Development Authority, 6.75% Gas Facilities Revenue Bonds,     
   replacing $45,000,000 Series 1989A and $45,000,000 Series 1989B, 
   incorporated by reference from Form 10-K for the year ended    
   September 30, 1992.
    
First Supplemental Participation Agreement dated as of May 1, 1992 
   to Participation Agreement dated February 1, 1989 between the  
   New York State Energy Research and Development Authority and The 
  Brooklyn Union Gas Company relating to Adjustable Rate Gas      
  Facilities Revenue Bonds, Series 1989A & B, incorporated by     
  reference from Form 10-K for the year ended September 30, 1992.

First Supplemental Trust Indenture dated as of May 1, 1992 to Trust 
   Indenture dated February 1, 1989 between the New York State    
   Energy Research and  Development Authority and Manufacturers   
   Hanover Trust Company, as Trustee, relating to Adjustable Rate 
   Gas Facilities Revenue Bonds, Series 1989A & B, incorporated by 
   reference from Form 10-K for the year ended September 30, 1992.

Official Statement, dated July 15, 1993, respective of 
   $25,000,000 of the New York State Energy Research and          
   Development Authority Gas Facilities Revenue Bonds Series D-1  
   and $25,000,000 of the New York State Energy Research and      
   Development Authority Gas Facilities Revenue Bonds Series D-2, 
   incorporated by reference from Form S-8 Registration Statement 
   No. 33-66182.

Participation Agreement, dated July 15, 1993, between the New York 
   State Energy Research and Development Authority and The Brooklyn 
   Union Gas Company relating to the Gas Facilities Revenue Bonds 
   Series D-1 1993 and Series D-2 1993, incorporated by reference 
   from Form S-8 Registration Statement No. 33-66182.

Indenture of Trust, dated July 15, 1993, between The New York State 
   Energy Research and Development Authority and Chemical Bank as 
   Trustee, relating to the Gas Facilities Revenue Bonds Series D-1 
   1993 and Series D-2 1993, incorporated by reference from Form
   S-8 Registration Statement No. 33-60182.

<PAGE>           
Official Statement, dated July 8, 1993, respective of $55,000,000 
   of the New York State Energy Research and Development Authority 
   Gas Facilities Revenue Bonds Series C, incorporated by reference 
  from Form 10-K for the year ended September 30, 1993.

First Supplemental Participation Agreement dated as of July 1, 1993 
   to Participation Agreement dated as of June 1, 1990, between the 
   New York State Energy Research and Development Authority and The 
   Brooklyn Union Gas Company relating to Gas Facilities Revenue  
   Bonds Series C, incorporated by reference from Form 10-K for the 
   year ended September 30, 1993.

First Supplemental Trust Indenture dated as of July 1, 1993 to    
   Trust Indenture dated as of June 1, 1990 between the New
   York State Energy Research and Development Authority and       
   Chemical Bank, as Trustee, relating to Gas Facilities Revenue  
   Bonds Series C, incorporated by reference from Form 10-K for the 
   year ended September 30, 1993.

Official Statement, dated January 15, 1996, respective of         
   $153,500,000 of the New York State Energy Research and         
   Development Authority, 5 1/2% Gas Facilities Revenue Bonds     
   Series 1996, replacing $98,500,000 Series 1985A and $55,000,000 
   Series 1985.
         
Participation Agreement, dated January 1, 1996, between the New   
   York Energy Research and Development Authority and The Brooklyn 
   Union Gas Company relating to the Gas Facilities Revenue Bonds 
   Series 1996.

Indenture of Trust, dated January 1, 1996, between The New York   
   State Energy Research and Development Authority and Chemical   
   Bank, as Trustee, relating to the Gas Facilities Revenue       
   Bonds Series 1996.

(10)     Material contracts

Deferred Compensation Plan Preamble, dated, December 17, 1986,    
   incorporated by reference from Form 10-K for the year ended    
   September 30, 1987.

Corporate Incentive Compensation Plan Description, 
   incorporated by reference from Form 10-K for the year ended    
   September 30, 1989.  

Marketing Incentive Compensation Plan Description, 
   incorporated by reference from Form 10-K for the year ended    
   September 30, 1989.  

<PAGE>
Deferral Plan for Incentive Awards Description, incorporated
   by reference from Form 10-K for the year ended September 30,   
   1989.  
  
Agreement of Lease between Forest City Jay Street Associates and  
   The Brooklyn Union Gas Company dated September 15, 1988,       
   incorporated by reference from Form 10-K for the year ended    
   September 30, 1990. 

Long-Term Performance Incentive Compensation Plan, dated November 
   15, 1995.

(11) Statement re:  Computation of per share earnings.  See Part 
      II, Item 8., "Financial Statements and Supplementary Data-  
      Consolidated Statement of Income for the Years Ended        
      September 30, 1995, 1994 and 1993," for information required 
      by this item.

(12) Statement re: Computation of consolidated ratio of earnings to 
     fixed charges 

(21) Subsidiaries of the registrant

(23) Consents of experts

(27) Financial data schedule

(b)   Reports on Form 8-K:

There were no reports filed on Form 8-K during the quarter ended
September 30, 1996.               

<PAGE>
                                              SIGNATURES

         Pursuant to the requirements of the Securities Exchange
Act of 1934, this report has been signed by the following persons
on behalf of the registrant, and in the capacities indicated on
December 11, 1996.

                                       THE BROOKLYN UNION GAS COMPANY


           Signature                           Title

    s/Robert B. Catell               Chairman and Chief Executive 
    (Robert B. Catell)                  Officer

    s/Craig G. Matthews              President and Chief Operating 
    (Craig G. Matthews)                 Officer

    s/Vincent D. Enright             Senior Vice President and    
    (Vincent D. Enright)                Chief Financial Officer   

    s/Richard M. Desmond             Vice President, Comptroller  
    (Richard M. Desmond)                and Chief Accounting      
                                        Officer

    s/Kenneth I. Chenault            Director
    (Kenneth I. Chenault)

    s/Andrea S. Christensen          Director
    (Andrea S. Christensen) 

    s/Donald H. Elliott              Director
    (Donald H. Elliott)

    s/Alan H. Fishman                Director
    (Alan H. Fishman)

    s/James L. Larocca               Director
    (James L. Larocca)

    s/Edward D. Miller               Director
    (Edward D. Miller)

    s/James Q. Riordan               Director
    (James Q. Riordan)

    s/Charles Uribe                  Director
    (Charles Uribe)