<PAGE>   1
================================================================================

                                UNITED STATES
                      SECURITIES AND EXCHANGE COMMISSION
                            Washington, D.C. 20549

                        ------------------------------

                                  FORM 10-K
            [X]  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
                     THE SECURITIES EXCHANGE ACT OF 1934
                 FOR THE FISCAL YEAR ENDED DECEMBER 31, 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 NO. 001-11899

                        ------------------------------

                       THE HOUSTON EXPLORATION COMPANY
            (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

<TABLE>
           <S>                                                      <C>
                      DELAWARE                                            22-2674487
          (STATE OR OTHER JURISDICTION OF                               (IRS EMPLOYER
           INCORPORATION OR ORGANIZATION)                            IDENTIFICATION NO.)


               1331 LAMAR, SUITE 1065
                  HOUSTON, TEXAS
          (ADDRESS OF PRINCIPAL EXECUTIVE                                    77010
                      OFFICES)                                            (ZIP CODE)
</TABLE>
                                 (713) 652-2847
              (REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)

                        ------------------------------

          SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

<TABLE>
          <S>                                                   <C>
                                                                        NAME OF EACH
                 TITLE OF EACH CLASS                            EXCHANGE ON WHICH REGISTERED
                 -------------------                            ----------------------------
          Common Stock, $.01 par value                             New York Stock Exchange
</TABLE>

       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 Regulations 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 ]
                               ---
    The aggregate market value of the voting stock held by non-affiliates of
the registrant was approximately $110,009,676 as of February 28, 1997, based on
the closing sales price of the registrant's common stock on the New York Stock
Exchange on such date of $14.00 per share.  For purposes of the preceding
sentence only, all directors, executive officers and beneficial owners of ten
percent or more of the common stock are assumed to be affiliates.  As of March
10, 1997, 23,332,763 shares of common stock were outstanding.

    Certain sections of the registrant's definitive proxy statement relating to
the registrant's 1997 annual meeting of stockholders, which proxy statement
will be filed under the Securities Exchange Act of 1934 within 120 days of the
end of the registrant's fiscal year ended December 31, 1996, are incorporated
by reference into Part III of this Form 10-K.

================================================================================



<PAGE>   2
         This Annual Report on Form 10-K contains certain "forward-looking
statements" within the meaning of Section 27A of the Securities Act of 1993, as
amended, and Section 21E of the Securities Exchange Act of 1934, as amended.
The words "anticipate," "believe," "expect," "estimate," "project" and similar
expressions are intended to identify forward-looking statements.  Without
limiting the foregoing, all statements under the caption "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations"
relating to the Company's anticipated capital expenditures, future cash flows
and borrowings, pursuit of potential future acquisition opportunities and
sources of funding for exploration and development are forward-looking
statements.  Such statements are subject to certain risks and uncertainties,
such as the volatility of natural gas and oil prices, uncertainty of reserve
information and future net revenue estimates, reserve replacement risks,
drilling risks, operating risks of natural gas and oil operations, acquisition
risks, substantial capital requirements, government regulation, environmental
matters and competition.  Should one or more of these risks or uncertainties
materialize, or should underlying assumptions prove incorrect, actual results
may vary materially from those anticipated, believed, expected, estimated or
projected.  For additional discussion of such risks, uncertainties and
assumptions, see "Items 1 and 2.  Business and Properties" and "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" contained in this Annual Report on Form 10-K.  Certain terms used
herein relating to the oil and gas industry are defined in "Glossary of Oil and
Gas Terms" included on pages G-1 through G-3 of this Annual Report on Form
10-K.

PART I.

ITEMS 1 AND 2.  BUSINESS AND PROPERTIES

OVERVIEW

         The Houston Exploration Company ("Houston Exploration" or the
"Company") is an independent natural gas and oil company engaged in the
exploration, development and acquisition of domestic natural gas and oil
properties.  The Company's offshore properties are located in the shallow
waters (up to 600 feet) of the Gulf of Mexico, and its onshore properties are
located in South Texas, the Arkoma Basin, East Texas and West Virginia.  The
Company has grown its Gulf of Mexico reserves and production through
exploratory drilling and subsequent development of prospects originally
generated utilizing in-house geological and geophysical expertise.  The Company
has grown its onshore reserves and production through successful acquisitions
and subsequent exploitation and development of low risk, long-lived reserves.
The Company believes that these lower risk projects and the stable production
from its longer-lived onshore properties complement its high potential
exploratory prospects in the Gulf of Mexico by balancing risk and reducing
volatility.

         The Company believes its primary strengths are its high quality
reserves, its substantial inventory of exploration and development
opportunities, its expertise in generating new prospects and its geographic
focus and low-cost operating structure.  At December 31, 1996, the Company had
net proved reserves of 327 Bcfe.  Approximately 98% of the Company's net proved
reserves on such date were natural gas and approximately 74% of proved reserves
were classified as proved developed.  The Company operates approximately 88% of
its Gulf of Mexico production and approximately 92% of its onshore production.

         The geographic focus of the Company's operations in the Gulf of Mexico
and core onshore areas of operation enable it to manage a large asset base with
a relatively small number of employees and to add production at relatively low
incremental cost.  The Company achieved lease operating expenses of $0.38 per
Mcfe of production and general and administrative expenses of $0.20 per Mcfe of
production for the year ended December 31, 1996.

         The Company was incorporated in Delaware in December 1985 and began
operations in January 1986.  Prior to its initial public offering in September
1996, the Company was an indirect wholly-owned subsidiary of The Brooklyn Union
Gas Company ("Brooklyn Union").  The Company's executive offices are located at
1331 Lamar, Suite 1065, Houston, Texas 77010, and its telephone number is (713)
652-2847.





                                      -2-
<PAGE>   3
STRATEGY

         The Company's strategy is to expand its reserves and increase its cash
flow through the exploration of Gulf of Mexico prospects which are internally
generated by the Company, the continued development of its existing offshore
and onshore properties and the selective acquisition of additional properties
both offshore and onshore.  The Company implements its strategy by focusing on
the following key strengths:

         o       High potential exploratory drilling in the Gulf of Mexico

         o       Low risk exploitation and development drilling in core onshore
                 areas of operation

         o       Use of advanced technology for in-house prospect generation

         o       Opportunistic acquisitions with additional exploratory and/or
                 development potential

         o       High percentage of operated properties to control operations
                 and costs

         o       Geographically focused operations

         High Potential Exploratory Drilling in the Gulf of Mexico.  The
Company plans to drill at least 12 exploratory wells in the Gulf of Mexico in
1997, the successful completion of any one of which could substantially
increase the Company's reserves.  The Company believes it has assembled a three
year inventory of exploration and development drilling opportunities in the
Gulf of Mexico.  The Company holds interests in 62 lease blocks, representing
297,935 gross (210,652 net) acres, in federal and state waters in the Gulf of
Mexico, of which 28 have current operations.  The Company has a 100% working
interest in 26 of these lease blocks and a 50% or greater working interest in
19 other lease blocks.  During 1996, the Company drilled six successful
exploratory wells and one successful development well in the Gulf of Mexico,
resulting in added net proved reserves of approximately 15.4 Bcfe.  Currently
the Company is drilling two exploratory wells and completing one exploratory
well and one development well. The Company plans to continue an active
exploration program on its offshore properties in 1997. In addition, the
Company intends to continue its participation in federal lease sales and to
actively pursue attractive farm-in opportunities as they arise.  During January
1997, net production from the Company's Gulf of Mexico properties averaged
approximately 55,000 Mcfe per day.

         Low Risk Exploitation and Development Drilling Onshore.  The Company
owns significant onshore natural gas and oil properties in South Texas, the
Arkoma Basin of Oklahoma and Arkansas, East Texas and West Virginia, accounting
for approximately 62% of its net proved reserves as of December 31, 1996.
During 1996, the Company drilled or participated in the drilling of nine
successful development wells and one successful exploratory well onshore.  The
Company plans to drill approximately 20 development wells and several
exploratory wells onshore during 1997.  Since the beginning of 1997, the
Company has drilled four successful development wells and is currently drilling
two exploratory wells and six development wells.  The Company believes that
these lower risk projects and the stable production from its longer-lived
onshore properties complement its higher potential Gulf of Mexico operations
and reserve base.  The Company's onshore properties represent interests in
1,034 gross (637 net) wells, and 139,299 gross (98,495 net) acres.  The Company
intends to continue an active drilling program on its onshore properties in
1997.  In addition the Company anticipates that it will continue to acquire
onshore properties with exploitation and development potential in its core
areas of operation as opportunities arise.  During January 1997, net production
from the Company's onshore properties averaged approximately 63,000 Mcfe per
day.

         Use of Advanced Technology for In-House Prospect Generation.  The
Company generates virtually all of its Gulf of Mexico exploration prospects
utilizing in-house geological and geophysical expertise.  The Company uses
advanced technology, including 3-D seismic and in-house computer-aided
exploration technology, to reduce risks, lower costs and prioritize drilling
prospects.  The Company has acquired approximately 1,400 square miles of 3-D
seismic data, including 3-D seismic surveys on 125 square miles in South Texas
and 42 of its offshore lease blocks and on possible lease and acquisition
prospects, and 62,000 linear miles of 2-D seismic data on its offshore
properties.  The Company has 18 geologists/geophysicists with average industry
experience of approximately 30 years and eight





                                      -3-
<PAGE>   4
geophysical workstations for use in interpreting 3-D seismic data.  The
availability of 3-D seismic data for Gulf of Mexico properties at reasonable
costs has enabled the Company to identify multiple exploration and development
prospects in the Company's existing inventory of properties and to define
possible lease and acquisition prospects.

         Opportunistic Acquisitions.  Although the Company's primary strategy
is to grow its reserves through the drill bit, the Company anticipates making
opportunistic acquisitions in the Gulf of Mexico with exploratory potential and
in core areas of operation onshore with exploitation and development potential.
The Company has a successful track record of building its reserves through
opportunistic acquisitions in the Gulf of Mexico and onshore.  In 1996, the
Company acquired significant onshore properties in South Texas and offshore
properties in the Gulf of Mexico.

         High Percentage of Operated Properties.  The Company prefers to
operate its properties in order to manage production performance while
controlling operating expenses and the timing and amount of capital
expenditures.  Properties operated by the Company account for 88% of its Gulf
of Mexico production and approximately 92% of its onshore production.  The
Company operates 16 platforms and 61 wells in the Gulf of Mexico and 908 wells
onshore.  The Company also pursues cost savings through the use of outside
contractors for much of its offshore field operations activities and
administrative work.  As a result of these and other factors, the Company
achieved lease operating expense of $0.38 per Mcfe of production and general
and administrative expense of $0.20 per Mcfe of production for the year ended
December 31, 1996.

         Geographically Focused Operations.  Focusing drilling activities on
properties in a relatively concentrated area in the Gulf of Mexico permits the
Company to utilize its base of geological, engineering, exploration and
production experience in the region.  The geographic focus of the Company's
operations allows it to manage a large asset base with a relatively small
number of employees and enables the Company to add production at relatively low
incremental costs.  Management believes that the Gulf of Mexico area remains
attractive for future exploration and development activities due to the
availability of geologic data, remaining reserve potential and the
infrastructure of gathering systems, pipelines, platforms and providers of
drilling services and equipment.  The Company's onshore strategy is to make
opportunistic acquisitions of low risk, long-lived natural gas reserves of
sufficient size to provide a core area of operation and to use that base to
develop additional acquisition opportunities and exploitation drilling at
little or no incremental overhead cost.

REORGANIZATION AND ACQUISITIONS

         Reorganization.  In February 1996, Brooklyn Union implemented a
reorganization of its exploration and production assets by transferring to the
Company certain onshore producing properties and developed and undeveloped
acreage formerly owned by Fuel Resources Inc. ("FRI"), another subsidiary of
Brooklyn Union.  The properties that were transferred to the Company in the
reorganization are located in the Arkoma Basin, East Texas and West Virginia.

         TransTexas Acquisition. On July 2, 1996, the Company acquired certain
natural gas and oil properties and associated gathering pipelines and equipment
located in Zapata County, Texas (the "TransTexas Acquisition") from TransTexas
Gas Corporation and TransTexas Transmission Corporation (together,
"TransTexas").  The Company acquired a 100% working interest (95% after the
exercise by James G. Floyd, the Company's President and Chief Executive
Officer, of his right to purchase a 5% working interest) in the approximately
142 wells on such properties.  The purchase price of $62.2 million ($59.1
million after giving effect to the exercise of Mr. Floyd's purchase option) for
the TransTexas Acquisition was reduced by $3.1 million for production revenues
and expenses related to the assets between the May 1, 1996 effective date of
the TransTexas Acquisition and July 2, 1996.  The purchase price of the
TransTexas Acquisition was paid in cash, financed with borrowings under the
Company's Credit Facility (as defined in "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources").

         In connection with the TransTexas Acquisition, the Company and
TransTexas entered into a Gas Exchange Agreement whereby the Company has
agreed, subject to certain conditions, to deliver, for the term of the acquired
leases, all of the gas produced from such leases to TransTexas' pipeline in
exchange for an equivalent amount of gas (measured in Btus) at a designated
delivery point where the TransTexas pipeline connects with several major
interstate





                                      -4-
<PAGE>   5
pipelines.  The Company  has agreed to pay TransTexas a fee on a per Mmbtu
basis for exchanging the gas production at the collection point with the gas at
the designated delivery point.

         Soxco Acquisition.  On September 25, 1996, the Company acquired
substantially all of the natural gas and oil properties and related assets (the
"Soxco Acquisition") of Smith Offshore Exploration Company ("Soxco").  The
natural gas and oil properties acquired in the Soxco Acquisition consisted
solely of working interests in properties located in the Gulf of Mexico that
were already operated by the Company or in which the Company also had a working
interest.  Pursuant to the Soxco Acquisition, the Company paid Soxco cash in
the aggregate amount of $20.3 million (net of $3.4 million for certain purchase
price adjustments), and issued to Soxco 762,387 shares of Common Stock.  In
addition, the Company agreed to pay Soxco a deferred purchase price of up to
$17.6 million payable on January 31, 1998.  The amount of the deferred purchase
price is determined by the probable reserves of Soxco as of December 31, 1995
(approximately 17.6 Bcfe) that are produced prior to or classified as proved as
of December 31, 1997, provided that Soxco is entitled to receive a minimum
deferred purchase price of approximately $8.8 million.  The amount so
determined will be paid in shares of Common Stock based on the fair market
value of such stock at the time of issuance.

GULF OF MEXICO PROPERTIES

         The Company holds interests in 62 offshore blocks, of which 28 have
current operations, and operates 22 of these blocks, accounting for
approximately 88% of the Company's offshore production.  The following table
lists the Company's average working interest, net proved reserves and the
operator for the Company's largest offshore properties as of December 31, 1996,
representing 96% of the Company's Gulf of Mexico proved reserves and 93% of its
offshore production:
<TABLE>
<CAPTION>
                                                                       Proved Reserves at
                                                                       December 31, 1996          
                                                              ------------------------------------
                                                   Average        Gas         Oil         Total
                                                   Working        ---         ---         -----
                      Field                        Interest      (Mmcf)     (Mbbls)      (Mmcfe)     Operator  
                      -----                      ------------ -----------  ---------- ------------ ------------
 <S>                                               <C>          <C>          <C>         <C>       <C>
 Mustang Island Block 858  . . . . . . . . . .      82.5%       19,869       440         22,509    Company
 Mustang Island Block 807  . . . . . . . . . .     100.0%       13,190        66         13,586    Company
 West Cameron Block 76/77/60/61 Unit . . . . .      10.9%       11,743        78         12,211    Third Party
 Matagorda Island Block 651  . . . . . . . . .      79.6%       12,122         7         12,164    Company
 East Cameron Block 82/83  . . . . . . . . . .      97.8%       10,936       180         12,016    Company
 Mustang Island Block 759  . . . . . . . . . .      25.0%       10,902        29         11,076    Third Party
 Mustang Island Block 785  . . . . . . . . . .      71.3%        8,595         2          8,607    Company
 Matagorda Island Block 650/672/671  . . . . .      45.4%        7,179         8          7,227    Company
 Vermilion Block 203 . . . . . . . . . . . . .      50.0%        5,741         6          5,777    Company
 Galveston Island Block 272/252  . . . . . . .      43.9%        4,279        21          4,405    Company
 South Marsh Island Block 252/253  . . . . . .      50.0%        3,594         4          3,618    Company
 Eugene Island Block 48  . . . . . . . . . . .      86.5%        3,278        15          3,368    Company
 Mustang Island Block 738  . . . . . . . . . .      49.9%        2,861        17          2,963    Company
</TABLE>

         During 1996, the Company drilled six successful exploratory wells and
one successful development well on its Gulf of Mexico properties.  During this
same period, the Company drilled four exploratory wells that were not
successful.  Capital spending associated with the Company's Gulf of Mexico
properties during 1996 was $111.4 million, including $27.4 million for
exploratory drilling, $25.4 million for development drilling and $58.6 million
for acquisitions.

         During 1997, the Company intends to focus on exploratory drilling and
plans to drill at least 12 exploratory wells, along with limited development
drilling.  The Company's exploratory projects are located in Mustang Island
858,





                                      -5-
<PAGE>   6
Galveston Island 272, High Island Block 138, Galveston Island Block 297, East
Cameron Block 185, East Cameron Block 82/83 and Mustang Island Block 736.  The
Company's development projects are located in Mustang Island Block 807 and
Mustang Island Block 858.  The following is a summary description of the
Company's exploration and development activity during 1996 and significant
additional activity that is currently planned during 1997.  The Company is the
operator of each of these properties except for Mustang Island Block 736.

         Mustang Island Block 858.  The Company holds an 82.5% working interest
in Mustang Island Block 858.  The block has three wells.  Initial production
began the first week of July 1996; however, one well is currently shut-in and a
workover is planned for the second quarter of 1997.  During January 1997, the
remaining two wells produced at an average combined rate of 7,800 Mcfe/d, net
to the Company.  The Company owns substantial leasehold interests in adjacent
blocks and is planning additional exploratory and development drilling during
1997.

         Mustang Island Block 807.  The Company holds a 100% working interest
in Mustang Island Block 807.  The block has one well which the Company is
currently completing.  Platform construction began in the fourth quarter of
1996, and initial production is scheduled for the beginning of the second
quarter of 1997.

         Matagorda Island Block 651.  The Company holds a 79.6% working
interest in Matagorda Island Block 651, which has a platform and four producing
wells. The Company drilled a successful exploratory well during the fourth
quarter of 1996.  During January 1997, the block's average production was 8,700
mcfe/d, net to the Company.

         East Cameron Block 82/83.  The Company holds an average working
interest of 97.8% in East Cameron Blocks 82, 83, 44 and 49.  The property
currently has two platforms, one on Block 82 and one on Block 44 and two
satellite platforms.  The Company drilled a deep well during the first quarter
of 1996 and encountered no commercial amounts of hydrocarbons in the
prospective deep zone.  The well was completed in a shallower productive zone.
The Company is currently drilling an exploratory well on Block 83.  During
January 1997, the combined blocks produced an average of 5,700 Mcfe/d, net to
the Company.

         Mustang Island Block 785.  The Company holds a 71.3% working interest
in Mustang Island Block 785, which currently has a platform and five producing
wells. The Company drilled a deep exploratory well during the third quarter of
1996 to test objectives to the west of Mustang Island Block 785.  The deep
objective was unsuccessful and the well was completed in a shallower productive
zone.  An extensive workover program was conducted during the third and fourth
quarters of 1996.  During January 1997, the production from Mustang Island
Block 785 averaged 7,600 Mcfe/d, net to the Company.

         Vermilion Block 203.  The Company holds a 50% working interest in
Vermilion Block 203.  The block has four wells.  Initial production began in
the first quarter of 1996.  The Company drilled an additional deep well during
the first quarter of 1996 and encountered no commercial amounts of
hydrocarbons.  During January 1997, the field produced an average 4,900 Mcfe/d,
net to the Company.

         Galveston Island Block 252/272.  The Company holds an average working
interest of 43.9% in Galveston Island Block 252/272.  The property has two
platforms and one satellite platform at Galveston Island Block 272.  The five
wells are currently producing at a combined rate of 2,300 Mcfe/d, net to the
Company.  The Company is currently drilling an exploratory well to test an
untested fault block to the south of the satellite platform.

         East Cameron Block 185.  The Company acquired a 100% working interest
in East Cameron Block 185 in March 1996.  In January 1997, the property's one
platform produced an average of 2,200 Mcfe/d, net to the Company.  In
connection with its purchase of the field, the Company committed to drill two
exploratory wells.  The Company drilled one of the exploratory wells in the
second quarter of 1996 and did not encounter commercial amounts of
hydrocarbons. The Company plans to begin drilling the second exploratory well
in the second half of 1997.

         Matagorda Island Block 680.  The Company holds a 100% working interest
in Matagorda Island Block 680.  The Company began drilling an exploratory well
to test objectives that have been found productive to the north and west





                                      -6-
<PAGE>   7
of the property in early December 1996.  The well reached targeted depth in
early February 1997, and no commercially productive sands were found.

         Mustang Island Block 736.  The Company holds a 50% working interest in
Mustang Island Block 736.  The Company intends to drill a well in Mustang
Island Block 736 during the second half of 1997 to test objectives that have
been found productive to the southwest of Mustang Island Block 759.

ONSHORE PROPERTIES

         The Company also owns significant onshore natural gas and oil
properties in South Texas, the Arkoma Basin of Oklahoma and Arkansas, East
Texas and West Virginia.  These properties represent interests in 1,034 gross
(637 net) wells, 92% of which the Company is the operator of record, and
139,299 gross (98,495 net) acres.

         The following table lists the Company's average working interest and
net proved reserves for the Company's three largest onshore fields and the
Charco and Appalachian Areas as of December 31, 1996, representing 99% of the
Company's onshore reserves:

<TABLE>
<CAPTION>
                                                                               Proved Reserves at
                                                                                December 31, 1996           
                                                      Average       ----------------------------------------
                                                      Working           Gas            Oil          Total
                     Field                            Interest         (Mmcf)        (Mbbls)       (Mmcfe)  
                     -----                        ----------------  -----------   ------------   -----------
<S>                                                       <C>           <C>           <C>         <C>
Charco Area . . . . . . . . . . . . . . . . . .            95%          105,843        43         106,101
Chismville/Massard Field  . . . . . . . . . . .            73%           45,912        --          45,912
Willow Springs and Surrounding Fields . . . . .            53%           13,881       105          14,511
Wilburton, Panola and Surrounding Fields  . . .            23%            9,892        --           9,892
Appalachian Area  . . . . . . . . . . . . . . .            60%           25,961        57          26,303
</TABLE>

         During 1996, the Company participated in the drilling of nine
successful development wells and one successful exploratory well on its onshore
properties.  During this same period, the Company participated in the drilling
of one development well and three exploratory wells that were not successful.
Capital spending associated with the Company's onshore drilling program during
1996 was approximately $65.4 million, of which $59.5 million was used for
acquisitions.

         For 1997 the Company has budgeted funds to drill approximately 20
wells in the Charco Area of South Texas, three wells in East Texas, four wells
in Arkansas, and one well in Oklahoma.  The Company has identified enough
additional development and exploratory projects on its existing acreage to
maintain an active drilling program for the next four to six years.

         The following is a description of several of the Company's most
significant onshore properties:

         Charco Area.  The Charco Area is located in Zapata County, Texas.  The
Company acquired its properties in the Charco Area in July 1996 in the
TransTexas Acquisition.  The Company owns a 95% working interest in the
approximately 142 active wells on such properties, all of which are operated by
the Company.  During January 1997, the Company's Charco Area properties had
average production of 33,300 Mcfe/d, net to the Company.  The Company has
contracted for a 3-D seismic survey covering 125 square miles of its Charco
Area properties.  The Company commenced an active drilling program beginning in
the fourth quarter of 1996 to fully exploit this property and currently has two
drilling rigs under contract for the remainder of 1997.  Since the beginning of
1997, the Company has successfully drilled and completed three development
wells, drilled one unsuccessful development well and is currently drilling
three additional development wells in the Charco Area.

         Chismville/Massard Field.  The Chismville/Massard Field is located in
Logan and Sebastian Counties, Arkansas.  The Company owns working interests in
approximately 123 active wells, of which it operates 59 wells.





                                      -7-
<PAGE>   8
Working interests range from 11% to 100% and average approximately 73%.  The
Company is currently drilling two development wells in this area.  During
January 1997, production averaged 13,300 Mcfe/d, net to the Company.

         Willow Springs and Surrounding Fields.  The Willow Springs Field is
located in Gregg County, with surrounding fields located in Panola and Harrison
Counties, Texas.  The Company owns working interests in 45 active wells, of
which it operates 17 wells.  Working interests range from 3% to 100% and
average approximately 53%.  The Company is currently participating in the
drilling of one development well in this area.  During January 1997, production
averaged 4,100 Mcfe/d, net to the Company.

         Wilburton, Panola and Surrounding Fields.  The Wilburton and Panola
Fields are located in Latimer County, Oklahoma.  The Company owns working
interest in 41 active wells, of which it operates 12 wells.  Working interests
range from 1% to 63% and average approximately 23%.  During January 1997,
production averaged 7,800 Mcfe/d, net to the Company.  The Company is currently
participating in two exploratory wells that were being drilled at the end of
1996.

         Appalachian Area.  The Belington, Clarksburg and Seneca Upshur Fields
are located in Barbour, Randolph, Upshur and Mingo Counties, West Virginia.
The Company owns working interests in 675 wells, all of which are operated by
the Company.  Working interests range from 6% to 100% and average approximately
60%.  During January 1997, production averaged 4,300 Mcfe/d, net to the
Company.  In January 1997, the Company drilled and successfully completed one
development well in this area.

ADDITIONAL FUTURE PROJECTS

         In addition to the properties described above, the Company has
accumulated a large inventory of offshore leases comprised of 165,349
undeveloped gross (136,309 net) acres.  These leases are under review by the
Company's geologists and geophysicists based upon 3-D seismic data acquired in
recent years.  The Company has assembled a team of geologists and geophysicists
to evaluate unleased acreage offshore which will be available at upcoming lease
sales.  The Company is also actively pursuing farm-ins from other companies,
interests in other companies' joint ventures and potential acquisitions.
Finally, the Company is also evaluating its producing properties for workovers
and recompletions which it will undertake in the next several years.





                                      -8-
<PAGE>   9
NATURAL GAS AND OIL RESERVES

         The following table summarizes the estimates of the Company's
historical net proved reserves as of December 31, 1996, 1995 and 1994, and the
present values attributable to these reserves at such dates.  The reserve data
and present values as of December 31, 1996, 1995 and 1994 were prepared by
Netherland, Sewell & Associates, Inc. ("NSA"), Ryder Scott Company ("Ryder
Scott"), and Miller and Lents, Ltd. ("Miller and Lents"), independent petroleum
engineering consultants.

<TABLE>
<CAPTION>
                                                                 As of December 31,
                                                      1996              1995              1994      
                                               ---------------   ----------------  -----------------
                                                                   (in thousands)
<S>                                            <C>               <C>               <C>
Net Proved Reserves (1):
Natural gas (Mmcf)  . . . . . . . . . . . . .        320,474           195,946           145,945
Oil (Mbbls) . . . . . . . . . . . . . . . . .          1,131               889               636
Total (Mmcfe) . . . . . . . . . . . . . . . .        327,260           201,280           149,761
Present value of future net revenues
   before income taxes(2)   . . . . . . . . .  $     577,000     $     206,574     $     135,869
Standardized measure of discounted
   future net cash flows(3)   . . . . . . . .  $     452,582     $     171,459     $     118,434
</TABLE>

--------------------------

(1) NSA, Ryder Scott, and Miller and Lents prepared reserve data and present
    values with respect to properties comprising approximately 46%, 29% and
    25%, respectively, of the present values attributable to the Company's
    proved reserves as of December 31, 1996.
(2) The present value of future net revenues attributable to the Company's
    reserves was prepared using prices in effect at the end of the respective
    periods presented, discounted at 10% per annum on a pre-tax basis.  Such
    amounts reflect the effects of the Company's hedging contracts and do not
    reflect the effects of Section 29 tax credits.
(3) The standardized measure of discounted future net cash flows represents the
    present value of future net revenues after income tax discounted at 10% per
    annum.  Such amounts reflect the effects of the Company's hedging
    contracts.

         In accordance with applicable requirements of the Securities and
Exchange Commission, estimates of the Company's proved reserves and future net
revenues are made using sales prices estimated to be in effect as of the date
of such reserve estimates and are held constant throughout the life of the
properties (except to the extent a contract specifically provides for
escalation).  Estimated quantities of proved reserves and future net revenues
therefrom are affected by gas prices, which have fluctuated widely in recent
years.  There are numerous uncertainties inherent in estimating natural gas and
oil reserves and their estimated values, including many factors beyond the
control of the producer.  The reserve data set forth in this report represent
only estimates.  Reservoir engineering is a subjective process of estimating
underground accumulations of natural gas and oil that cannot be measured in an
exact manner.  The accuracy of any reserve estimate is a function of the
quality of available data and of engineering and geological interpretation and
judgment.  As a result, estimates of different engineers, including those used
by the Company, may vary.  In addition, estimates of reserves are subject to
revision based upon actual production, results of future development and
exploration activities, prevailing natural gas and oil prices, operating costs
and other factors, which revision may be material.  Accordingly, reserve
estimates are often different from the quantities of natural gas and oil that
are ultimately recovered and are highly dependent upon the accuracy of the
assumptions upon which they are based.  The Company's estimated proved reserves
have not been filed with or included in reports to any federal agency.

         The present value of future net revenues before income taxes and the
standardized measure of discounted future net cash flows set forth in this
Annual Report on Form 10-K do not reflect any adjustment for after
program-payout working interests held by the Company's President and Chief
Executive Officer in certain properties of the Company.  The amounts expected
to be payable in respect of such after program-payout working interests would
not have a material effect on the information presented.  See "Item 13. Certain
Relationships and Related Transactions."





                                      -9-
<PAGE>   10
DRILLING ACTIVITY

         The following table sets forth the drilling activity of the Company on
its properties for the years ended December 31, 1996, 1995 and 1994.

<TABLE>
<CAPTION>
                                                                         Year Ended December 31,                        
                                                 -----------------------------------------------------------------------
                                                           1996                    1995                    1994         
                                                 ----------------------- ----------------------- -----------------------
 Offshore Drilling Activity:                        Gross        Net        Gross        Net        Gross        Net    
 --------------------------                      ----------- ----------- -----------  ---------- -----------  ----------
 <S>                                                 <C>          <C>         <C>         <C>         <C>         <C>
 Exploratory:
    Productive   . . . . . . . . . . . . . . .        6            4.2         1           1.0         4           2.3
    Non-Productive   . . . . . . . . . . . . .        4            2.2        --          --           3           1.5
                                                 ------      ---------   -------      --------   -------      --------
           Total . . . . . . . . . . . . . . .       10            6.4         1           1.0         7           3.8
 Development:
    Productive   . . . . . . . . . . . . . . .        1            0.5         7           2.8         4           1.3
    Non-Productive   . . . . . . . . . . . . .       --           --          --          --           1           0.3
                                                 ------      ---------   -------      --------   -------      --------
           Total . . . . . . . . . . . . . . .        1            0.5         7           2.8         5           1.6

 ONSHORE DRILLING ACTIVITY:
 ------------------------- 
 Exploratory:
    Productive   . . . . . . . . . . . . . . .        1            0.1         3           0.5        --          --
    Non-Productive   . . . . . . . . . . . . .        3            2.2        --          --           1           0.3
                                                 ------      ---------   -------      --------   -------      --------
           Total . . . . . . . . . . . . . . .        4            2.3         3           0.5         1           0.3
 Development:
    Productive   . . . . . . . . . . . . . . .        9            6.5        12           7.4         6           3.1
    Non-Productive   . . . . . . . . . . . . .        1            1.0         5           2.5         2           1.7
                                                 ------      ---------   -------      --------   -------      --------
           Total . . . . . . . . . . . . . . .       10            7.5        17           9.9         8           4.8
</TABLE>

PRODUCTIVE WELLS

         The following table sets forth the number of productive wells in which
the Company owned an interest as of December 31, 1996.

<TABLE>
<CAPTION>
                               Company              Company
                               Operated             Operated                                        Total Productive
                              Platforms              Wells               Non-Operated Wells              Wells          
                            --------------  ------------------------  ---------------------     ------------------------
 Offshore                                      Gross         Net         Gross         Net         Gross         Net    
 --------                                   -----------  -----------  -----------  -----------  -----------  -----------
 <S>                                <C>          <C>        <C>           <C>          <C>        <C>            <C>
 Gas . . . . . . . . . .            16            61         37.9          12           2.7          73           40.6
 Oil . . . . . . . . . .            --            --         --             7           0.8           7            0.8
                            ----------      --------     --------     -------      --------     -------      ---------
     Total . . . . . . .            16            61         37.9          19           3.5          80           41.4
                            ==========      ========     ========     =======      ========     =======      =========

 ONSHORE
 -------
 Gas . . . . . . . . . .                         906        605.1         124          29.8       1,030          634.9
 Oil . . . . . . . . . .                           2          1.9           2           0.5           4            2.4
                                            --------     --------     -------      --------     -------      ---------
     Total . . . . . . .                         908        607.0         126          30.3       1,034          637.3
                                            ========     ========     =======      ========     =======      =========
</TABLE>

         Productive wells consist of producing wells capable of production,
including gas wells awaiting connections.  Wells that are completed in more
than one producing horizon are counted as one well.





                                      -10-
<PAGE>   11
ACREAGE DATA

         The following table sets forth the approximate developed and
undeveloped acreage in which the Company held a leasehold mineral or other
interest as of December 31, 1996.  Undeveloped acreage includes leased acres on
which wells have not been drilled or completed to a point that would permit the
production of commercial quantities of natural gas and oil, regardless of
whether or not such acreage contains proved reserves:

<TABLE>
<CAPTION>
                                                Developed Acres                            Undeveloped Acres            
                                   -----------------------------------------   -----------------------------------------
                                          Gross                  Net                  Gross                  Net        
                                   -------------------   -------------------   -------------------   -------------------
 <S>                                     <C>                   <C>                   <C>                   <C>
 Offshore (1)  . . . . . . . .           132,586                74,343               165,349               136,309
 Onshore . . . . . . . . . . .           136,035                96,505                 3,264                 1,990
                                   -------------         -------------         -------------         -------------
      Total  . . . . . . . . .           268,621               170,848               168,613               138,299
                                   =============         =============         =============         =============
</TABLE>


(1) Offshore includes acreage in federal and state waters.

MARKETING AND CUSTOMERS

         Substantially all of the Company's production is sold at market
prices.  Prior to October 1996, the Company agreed, subject to certain
conditions, to sell substantially all of its subsequently developed or acquired
gas production, to an affiliate of Brooklyn Union, PennUnion Energy Services,
L.L.C. ("PennUnion").  The gas sales agreement with PennUnion was terminated in
September 1996 when Brooklyn Union sold its interest in PennUnion; however,
PennUnion still remains a major purchaser of the Company's natural gas
production. The gas production sold to PennUnion is sold at market prices,
based upon an index price adjusted to reflect the point of delivery of such
production.  During 1996, 1995 and 1994, sales to PennUnion and BRING Gas
Services Corp. ("BRING"), predecessor to PennUnion and an affiliate of Brooklyn
Union, accounted for 40%, 46% and 63% of total revenues, respectively.  The
Company believes that the prices at which it sold gas to PennUnion and BRING
are similar to those it would be able to obtain in the open market, and that
the loss of PennUnion and BRING as purchasers would not have a material adverse
effect on the Company.  See Note 9 to the Company's Combined Financial
Statements.

         The Company enters into commodity swaps with unaffiliated third
parties for portions of its natural gas production to achieve more predictable
cash flows and to reduce its exposure to short-term fluctuations in gas prices.
See "Item 7.   Management's Discussion and Analysis of Financial Condition and
Results of Operations -- General."

         Most of the Company's natural gas is transported through gas gathering
systems and gas pipelines which are not owned by the Company.  Transportation
space on such gathering systems and pipelines is occasionally limited and at
times unavailable due to repairs or improvements being made to such facilities
or due to such space being utilized by other gas shippers with priority
transportation agreements.  While the Company has not experienced any inability
to market its natural gas, if transportation space is restricted or is
unavailable, the Company's cash flow from the affected properties could be
adversely affected.  See "-- Regulation."

ABANDONMENT COSTS

         The Company is responsible for the payment of abandonment costs on the
natural gas and oil properties pro rata to its working interest.  The Company
provides for its expected future abandonment liabilities by accruing for such
costs as a component of depletion, depreciation and amortization as the
properties are produced.  As of December 31, 1996, total undiscounted
abandonment costs estimated to be incurred through the year 2007 were
approximately $5.2 million for properties in the federal and state waters and
are not considered significant for onshore properties.  Estimates of
abandonment costs and their timing may change due to many factors including
actual drilling and production results, inflation rates, and changes in
environmental laws and regulations.

         The Minerals Management Service ("MMS") requires lessees of Outer
Continental Shelf ("OCS") properties to post bonds in connection with the
plugging and abandonment of wells located offshore and the removal of all
production facilities.  Operators in the OCS waters of the Gulf of Mexico are
currently required to post an area wide





                                      -11-
<PAGE>   12
bond of $3 million or $500,000 per producing lease.  The Company is presently
exempt from any requirement by MMS to provide supplemental bonding on its
offshore leases, although no assurance can be made that it will continue to
satisfy the requirements for such exemption in the future.  Whether or not the
Company qualifies for such exemption, the Company does not believe that the
cost of any such bonding requirements will materially affect the Company's
financial condition or results of operations.  Under certain circumstances, the
MMS has the authority to suspend or terminate operations on federal leases for
failure to comply with applicable bonding requirements or other regulations
applicable to plugging and abandonment.  Any such suspensions or terminations
of the Company's operations could have a material adverse effect on the
Company's financial condition and results of operations.

TITLE TO PROPERTIES

         As is customary in the oil and gas industry, the Company makes only a
cursory review of title to farmout acreage and to undeveloped natural gas and
oil leases upon execution of the contracts.  Prior to the commencement of
drilling operations, a thorough title examination is conducted and curative
work is performed with respect to significant defects.  To the extent title
opinions or other investigations reflect title defects, the Company, rather
than the seller of the undeveloped property, is typically responsible for
curing any such title defects at its expense.  If the Company were unable to
remedy or cure any title defect of a nature such that it would not be prudent
to commence drilling operations on the property, the Company could suffer a
loss of its entire investment in the property.  The Company has obtained title
opinions on substantially all of its producing properties and believes that it
has satisfactory title to such properties in accordance with standards
generally accepted in the oil and gas industry.  Prior to completing an
acquisition of producing natural gas and oil leases, the Company obtains title
opinions on the most significant leases.  The Company's natural gas and oil
properties are subject to customary royalty interests, liens for current taxes
and other burdens which the Company believes do not materially interfere with
the use of or affect the value of such properties.

COMPETITION

         The Company encounters competition from other oil and gas companies in
all areas of its operations, including the acquisition of producing properties.
The Company's competitors include major integrated oil and gas companies and
numerous independent oil and gas companies, individuals and drilling and income
programs.  Many of its competitors are large, well-established companies with
substantially larger operating staffs and greater capital resources than the
Company's and which, in many instances, have been engaged in the oil and gas
business for a much longer time than the Company.  Such companies may be able
to pay more for productive natural gas and oil properties and exploratory
prospects and to define, evaluate, bid for and purchase a greater number of
properties and prospects than the Company's financial or human resources
permit.  The Company's ability to acquire additional properties and to discover
reserves in the future will be dependent upon its ability to evaluate and
select suitable properties and to consummate transactions in this highly
competitive environment.

OPERATING HAZARDS AND UNINSURED RISKS

         The Company's operations are subject to hazards and risks inherent in
drilling for and production and transportation of natural gas and oil, such as
fires, natural disasters, explosions, encountering formations with abnormal
pressures, blowouts, cratering, pipeline ruptures, and spills, any of which can
result in loss of hydrocarbons, environmental pollution, personal injury
claims, and other damage to properties of the Company and others.
Additionally, certain of the Company's natural gas and oil operations are
located in an area that is subject to tropical weather disturbances, some of
which can be severe enough to cause substantial damage to facilities and
possibly interrupt production.  As protection against operating hazards, the
Company maintains insurance coverage against some, but not all, potential
losses.  The Company's coverages include, but are not limited to, operator's
extra expense, to include loss of well, blowouts and certain costs of pollution
control, physical damage on certain assets, employer's liability, comprehensive
general liability, automobile and worker's compensation.  The Company believes
that its insurance is adequate and customary for companies of a similar size
engaged in operations similar to those of the Company, but losses could occur
for uninsurable or uninsured risks or in amounts in excess of existing
insurance coverage.  The occurrence of an event that is not fully covered by
insurance could have an adverse impact on the Company's financial condition and
results of operations.





                                      -12-
<PAGE>   13
REGULATION

         The availability of a ready market for natural gas and oil production
depends upon numerous factors beyond the Company's control.  These factors
include regulation of natural gas and oil production, federal and state
regulations governing environmental quality and pollution control, state limits
on allowable rates of production by a well or proration unit, the supply of
natural gas and oil available for sale, the availability of adequate pipeline
and other transportation and processing facilities and the marketing of
competitive fuels.  For example, a productive natural gas well may be "shut-in"
because of an oversupply of natural gas or the lack of an available natural gas
pipeline in the areas in which the Company may conduct operations.  State and
federal regulations generally are intended to prevent waste of natural gas and
oil, protect rights to produce natural gas and oil between owners in a common
reservoir, control the amount of natural gas and oil produced by assigning
allowable rate of production and control contamination of the environment.

         Regulation of Oil and Gas Exploration and Production.  Exploration and
production operations of the Company are subject to various types of regulation
at the federal, state and local levels.  Such regulation includes requiring
permits for the drilling of wells, maintaining bonding requirements in order to
drill or operate wells, and regulating the location of wells, the method of
drilling and casing wells, the surface use and restoration of properties upon
which wells are drilling and the plugging and abandonment of wells.  The
Company's operations are also subject to various conservation laws and
regulations.  These include the regulation of the size of drilling and spacing
units or proration units and the density of wells which may be drilled and
unitization or pooling of oil and gas properties.  In this regard, some states
allow the forced pooling or integration of tracts to facilitate exploration
while other states rely on voluntary pooling of lands and leases.  In addition,
state conservation laws establish maximum rates of production from natural gas
and oil wells, generally prohibit the venting or flaring of natural gas and
impose certain requirements regarding the ratability of production.  The effect
of these regulations is to limit the amounts of natural gas and oil the
Company's operator or the Company can produce from its wells, and to limit the
number of wells or the locations of which the Company can drill.  Legislation
affecting the oil and gas industry also is under constant review for amendment
or expansion.  Generally, state-established allowables have been influenced by
overall natural gas market supply and demand in the United States, as well as
the specific "nominations" for natural gas from the parties who produce or
purchase gas from the field and other factors deemed relevant by the agency.
The Company cannot predict whether further changes will be made in how these
states set allowables or what impact, if any, such further changes might have.
In addition, numerous departments and agencies, both federal and state, are
authorized by statute to issue rules and regulations binding on the oil and gas
industry and its individual members, some of which carry substantial penalties
for failure to comply.  The regulatory burden on the oil and gas industry
increases the Company's cost of doing business and, consequently, affects its
profitability.  Inasmuch as such laws and regulations are frequently expanded,
amended or reinterpreted, the Company is unable to predict the future cost or
impact of complying with such regulations.

         Natural Gas Marketing and Transportation.  Federal legislation and
regulatory controls in the United States have historically affected the price
of the natural gas produced by the Company and the manner in which such
production is marketed.  The transportation and sale for resale of natural gas
in interstate commerce are regulated pursuant to the Natural Gas Act of 1938
(the "NGA"), the Natural Gas Policy Act of 1978 (the "NGPA") and the Federal
Energy Regulatory Commission (the "FERC").  Although maximum selling prices of
natural gas were formerly regulated, on July 26, 1989, the Natural Gas Wellhead
Decontrol Act of 1989 (the "Decontrol Act") was enacted, which amended the NGPA
to remove completely by January 1, 1993 price and non-price controls for all
"first sales" of domestic natural gas, which include all sales by the Company
of its own production; consequently, sales of the Company's natural gas
production currently may be made at market prices, subject to applicable
contract provisions.  The FERC's jurisdiction over natural gas transportation
was unaffected by the Decontrol Act.

         In July 1994, the FERC eliminated a regulation that had rendered
virtually all sales of natural gas by pipeline and distribution company
affiliates, such as the Company, to be deregulated first sales.  As a result,
all sales by the Company of gas for resale in interstate commerce, other than
sales by the Company of its own production, are now jurisdictional sales
subject to an NGA certificate.  This includes, for example, sales for resale of
gas purchased from third parties.  The Company does not anticipate this change
will have any significant current adverse effects in light of the flexible
terms and conditions of the existing blanket certificate.  Such sales are
subject to the future possibility of greater federal oversight, however,
including the possibility the FERC might prospectively impose more restrictive
conditions on such sales.





                                      -13-
<PAGE>   14
         The FERC also regulates interstate natural gas transportation rates
and service conditions, which affect the marketing of natural gas produced by
the Company, as well as the revenues received by the Company for sales of such
natural gas.  Since the latter part of 1985, the FERC has endeavored to make
interstate natural gas transportation more accessible to natural gas buyers and
sellers on an open and nondiscriminatory basis.  The FERC's efforts have
significantly altered the marketing and pricing of natural gas.  Commencing in
April 1992, the FERC issued Order Nos. 636, 636-A and 636-B (collectively,
"Order No. 636"), which, among other things, require interstate pipelines to
"restructure" to provide transportation separate or "unbundled" from the
pipelines' sales of natural gas.  Also, Order No. 636 requires pipelines to
provide open-access transportation on a basis that is equal for all natural gas
supplies.  Order No. 636 has been implemented through negotiated settlements in
individual pipeline service restructuring proceedings.  In many instances, the
result of the Order No. 636 and related initiatives have been to substantially
reduce or bring to an end the interstate pipelines' traditional role as
wholesalers of natural gas in favor of providing only storage and
transportation services.  The FERC has issued final orders in virtually all
pipeline restructuring proceedings, and has now commenced a series of one year
reviews to determine whether refinements are required regarding individual
pipeline implementations of Order No. 636.

         Although Order No. 636 does not regulate natural gas producers such as
the Company, the FERC has stated that Order No. 636 is intended to foster
increased competition within all phases of the natural gas industry.  It is
unclear what impact, if any, increased competition within the natural gas
industry under Order No. 636 will have on the Company and its natural gas
marketing efforts.  The United States Court of Appeals for the District of
Columbia Circuit (the "Court") recently issued its decision in the appeals of
Order No. 636.  The Court largely upheld the basic tenets of Order No. 636,
including the requirements that interstate pipelines "unbundle" their sales of
gas from transportation and that pipelines provide open-access transportation
on a basis that is equal for all gas suppliers.  The Court remanded five
relatively narrow issues for further explanation by the FERC.  In doing so, the
Court made it clear that the FERC's existing rules on the remanded issues would
remain in effect pending further consideration.  The Court's decision is still
subject to rehearing and parties could potentially petition for writ of
certiorari to the United States Supreme Court.  It is not possible to predict
what effect, if any, the ultimate outcome of this judicial review process will
have on the Company.  Although Order No. 636, assuming it is upheld in its
entirety in its current form, could provide the Company with additional market
access and more fairly applied transportation service rates, terms and
conditions, it could also subject the Company to more restrictive pipeline
imbalance tolerances and greater penalties for violation of those tolerances.
The Company does not believe, however, that it will be affected by any action
taken with respect to Order No. 636 materially differently than other natural
gas producers and marketers with which it competes.

         The FERC recently issued a statement of policy and a request for
comments concerning alternatives to its traditional cost-of-service rate making
methodology.  This policy statement articulates the criteria that the FERC will
use to evaluate proposals to charge market-based rates for the transportation
of natural gas.  The policy statement also provides that the FERC will consider
proposals for negotiated rates for individual shippers of natural gas, so long
as a cost-of-service-based rate is available.  The FERC requested comments on
whether it should allow gas pipelines the flexibility to negotiate the terms
and conditions of transportation service with prospective shippers.  The
Company cannot predict what further action the FERC will take on these matters;
however, the Company does not believe that it will be affected by any action
taken materially differently than other natural gas producers and marketers
with which it competes.

         The FERC has announced its intention to reexamine certain of its
transportation-related policies, including the manner in which interstate
pipeline shippers may release interstate pipeline capacity under Order No. 636
for resale in the secondary markets.  While any resulting FERC action would
affect the Company only indirectly, the FERC's current rules and policy
statements may have the effect of enhancing competition in natural gas markets
by, among other things, encouraging non-producer natural gas marketers to
engage in certain purchase and sale transactions.  The Company cannot predict
what action the FERC will take on these matters, nor can it accurately predict
whether the FERC's actions will achieve the goal of increasing competition in
markets in which the Company's natural gas is sold.  However, the Company does
not believe that it will be affected by any action taken materially differently
than other natural gas producers and marketers with which it competes.





                                      -14-
<PAGE>   15
         Recently, the FERC issued policy statements on how interstate natural
gas pipelines can recover the costs of new pipeline facilities and on how the
FERC intends to regulate natural gas gathering facilities owned (or previously
owned but either "spun down" to an affiliate or "spun off" to a non-affiliate)
by interstate pipeline companies after Order No. 636.  While the FERC's policy
statement on new construction cost recovery affects the Company only
indirectly, in its present form, the new policy should enhance competition in
natural gas markets and facilitate construction of gas supply laterals.
However, requests for rehearing of this policy statement are currently pending.
In respect of interstate pipeline-owned gathering, the FERC has approved the
spin down or spin off by several interstate pipelines of their gathering
facilities.  These approvals were given despite the strong protests of a number
of producers concerned that any diminution in FERC's oversight of interstate
pipeline-related gathering services might result in a denial of open access or
otherwise enhance the pipeline's monopoly power.  While the FERC has stated
that it will retain limited jurisdiction over such gathering facilities and
will hear complaints concerning any denial of access, it is unclear what effect
the FERC's new gathering policy will have on producers such as the Company and
the Company cannot predict what further action the FERC will take on these
matters.

         Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts.  The Company cannot predict when or if any
such proposals might become effective, or their effect, if any, on the
Company's operations.  The natural gas industry historically has been very
heavily regulated; therefore, there is no assurance that the less stringent
regulatory approach recently pursued by the FERC and Congress will continue
indefinitely into the future.

         Offshore Leasing.  Certain operations the Company conducts are on
federal oil and gas leases, which the MMS administers.  The MMS issues such
leases through competitive bidding.  These leases contain relatively
standardized terms and require compliance with detailed MMS regulations and
orders pursuant to the Outer Continental Shelf Lands Act ("OCSLA") (which are
subject to change by the MMS).  For offshore operations, lessees must obtain
MMS approval for exploration plans and development and production plans prior
to the commencement of such operations.  In addition to permits required from
other agencies (such as the Coast Guard, the Army Corps of Engineers and the
Environmental Protection Agency), lessees must obtain a permit from the MMS
prior to the commencement of drilling.  The MMS has promulgated regulations
requiring offshore production facilities located on the Outer Continental Shelf
(the "OCS") to meet stringent engineering and construction specifications, and
has recently proposed additional safety-related regulations concerning the
design and operating procedures for OCS production platforms and pipelines.
The MMS also has issued regulations restricting the flaring or venting of
natural gas, and has recently proposed to amend such regulations to prohibit
the flaring of liquid hydrocarbons and oil without prior authorization.
Similarly, the MMS has promulgated other regulations governing the plugging and
abandonment of wells located offshore and the removal of all production
facilities.  To cover the various obligations of lessees on the OCS, the MMS
generally requires that lessees post substantial bonds or other acceptable
assurances that such obligations will be met.  The cost of such bonds or other
surety can be substantial and there is no assurance that the Company can obtain
bonds or other surety in all cases.  See "-- Environmental Matters."

         In addition, the MMS is conducting an inquiry into certain contract
settlement agreements from which producers on MMS leases have received
settlement proceeds that are royalty bearing and the extent to which producers
have paid the appropriate royalties on those proceeds.

         The MMS has recently issued a notice of proposed rulemaking in which
it proposes to amend its regulations governing the calculation of royalties and
the valuation of natural gas produced from federal leases.  The principal
feature in the amendments, as proposed, would establish an alternative
market-index based method to calculate royalties on certain natural gas
production sold to affiliates or pursuant to non-arm's-length contracts.  The
MMS has proposed this rulemaking to facilitate royalty valuation in light of
changes in the natural gas marketing environment.  The Company cannot predict
what action the MMS will take on these matters, nor can it predict at this
state of the rulemaking proceeding how the Company might be affected by
amendments to the regulations.





                                      -15-
<PAGE>   16
         The OCSLA requires that all pipelines operating on or across the OCS
provide open-access, non-discriminatory service.  Although the FERC has opted
not to impose the regulations of Order No. 509, which implements these
requirements of the OCSLA, on gatherers and other nonjurisdictional entities,
the FERC has retained the authority to exercise jurisdiction over those
entities if necessary to permit non-discriminatory access to services on the
OCS.  If the FERC were to apply Order No. 509 to gatherers in the OCS,
eliminate the exemption of gathering lines, and redefine its jurisdiction over
gathering lines, then these acts could result in a reduction in available
pipeline space for existing shippers in the Gulf of Mexico and elsewhere.

         Oil Sales and Transportation Rates.  Sales of crude oil, condensate
and gas liquids by the Company are not regulated and are made at market prices.
The price the Company receives from the sale of these products is affected by
the cost of transporting the products to market.  Effective as of January 1,
1995, the FERC implemented regulations establishing an indexing system for
transportation rates for oil pipelines, which would generally index such rates
to inflation, subject to certain conditions and limitations.  These regulations
are subject to pending petitions for judicial review.  The Company is not able
to predict with certainty what effect, if any, these regulations will have on
it, but other factors being equal, under certain conditions the regulations may
tend to increase transportation costs or reduce wellhead prices for such
commodities.

         Safety Regulation.  The Company's gathering operations are subject to
safety and operational regulations relating to the design, installation,
testing, construction, operation, replacement, and management of facilities.
Pipeline safety issues have recently been the subject of increasing focus in
various political and administrative arenas at both the state and federal
levels.  In addition, the major federal pipeline safety law is subject to
change this year as it is considered for reauthorization by Congress.  For
example, federal legislation addressing pipeline safety issues has been
introduced, which, if enacted, would establish a federal "one call"
notification system.  Additional pending legislation would, among other things,
increase the frequency with which certain pipelines must be inspected, as well
as increase potential civil and criminal penalties for violations of pipeline
safety requirements.  The Company believes its operations, to the extent they
may be subject to current natural gas pipeline safety requirements, comply in
all material respects with such requirements.  The Company cannot predict what
effect, if any, the adoption of this or other additional pipeline safety
legislation might have on its operations, but the industry could be required to
incur additional capital expenditures and increased costs depending upon future
legislative and regulatory changes.

ENVIRONMENTAL MATTERS

         The Company's operations are subject to federal, state and local laws
and regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection.  These laws and regulations may
require the acquisition of a permit before drilling commences, restrict the
types, quantities and concentration of various substances that can be released
into the environment in connection with drilling and production activities,
limit or prohibit drilling activities on certain lands lying within wilderness,
wetlands and other protected areas, require remedial measures to prevent
pollution from former operations, such as pit closure and plugging abandoned
wells, and impose substantial liabilities for pollution resulting from the
Company's operations.  In addition, these laws, rules and regulations may
restrict the rate of oil and natural gas production below the rate that would
otherwise exist.  The regulatory burden on the oil and gas industry increases
the cost of doing business and consequently affects its profitability.  Changes
in environmental laws and regulations occur frequently, and any changes that
result in more stringent and costly waste handling, disposal and clean-up
requirements could have a significant impact on the operating costs of the
Company, as well as the oil and gas industry in general.  Management believes
that the Company is in substantial compliance with current applicable
environmental laws and regulations and that continued compliance with existing
requirements will not have a material adverse impact on the Company.

         The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the original conduct, on certain classes of persons who are
considered to be responsible for the release of a "hazardous substance" into
the environment.  These persons include the owner or operator of the disposal
site or sites where the release occurred and companies that disposed or
arranged for the disposal of the hazardous substances.  Under CERCLA, such
persons may be subject to joint and several liability for the costs of cleaning
up the hazardous substances that have been released into the environment, for
damages to





                                      -16-
<PAGE>   17
natural resources and for the costs of certain health studies, and it is not
uncommon for neighboring landowners and other third parties to file claims for
personal injury and property damage allegedly caused by the release of
hazardous substances.

         The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder
impose a variety of requirements on "responsible parties" related to the
prevention of oil spills and liability for damages resulting from such spills
in "waters of the United States." A "responsible party" includes the owner or
operator of a facility or vessel, or the lessee or permittee of the area in
which an offshore facility is located.  The term "waters of the United States"
has been broadly defined to include not only the waters of the Gulf of Mexico
but also inland water bodies, including wetlands, playa lakes and intermittent
streams.  The OPA also requires owners and operators of "offshore facilities"
to establish $150 million in financial responsibility to cover environmental
cleanup and restoration costs likely to be incurred in connection with an oil
spill.  In August, 1993, the MMS published an advance notice of its intention
to adopt a rule under the OPA that would define "offshore facilities" to
include all oil and gas facilities that have the potential to affect "waters of
the United States." Since the Company has many oil and gas facilities that
could affect "waters of the United States," the Company could become subject to
the financial responsibility rule if it is adopted as proposed.  However, in
May of 1995, the U.S. House of Representatives passed a bill that would reduce
the level of financial responsibility required under OPA to $35 million (the
current requirement under the OCSLA) and that would limit the definition of
"offshore facility" to include only Territorial Seas and OCS production,
transportation, and storage facilities.  In November of 1995, the U.S. Senate
adopted similar but slightly different legislation that must be reconciled with
the House of Representatives bill before either bill can be submitted to
President Clinton for approval.  The Senate bill would limit the definition of
"offshore facility" to not only Territorial Sea and Outer Continental Shelf
production, transportation and storage facilities but also inland waters, such
as coastal bays, estuaries or perhaps even rivers.  Both bills allow the
financial responsibility limit to be increased to $150 million if a formal risk
assessment indicates the increase is warranted.  The Company cannot predict the
final form of any financial responsibility rule that may be imposed under the
OPA, but any rule that requires the Company to establish $150 million in
financial responsibility for oil spills has the potential to result in
increased annual operating costs.  The Clinton Administration has indicated
tentative support for changes to the OPA financial responsibility requirements.
Whether these legislative efforts will reduce the OPA financial responsibility
requirements applicable to the Company cannot be determined at this time.  In
any event, the impact of any rule is not expected to be any more burdensome to
the Company than it will be to other similarly situated companies involved in
oil and gas exploration and production.

         OPA imposes a variety of additional requirements on responsible
parties for vessels or oil and gas facilities related to the prevention of oil
spills and liability for damages resulting from such spills in waters of the
United States.  OPA assigns liability to each responsible party for oil spill
removal costs and a variety of public and private damages from oil spills.
While liability limits apply in some circumstances, a party cannot take
advantage of liability limits if the spill is caused by gross negligence or
willful misconduct or resulted from violation of a federal safety, construction
or operating regulation.  If a party fails to report a spill or to cooperate
fully in the cleanup, liability limits likewise do not apply.  OPA establishes
a liability limit for offshore facilities of all removal costs plus $75
million.  Few defenses exist to the liability for oil spills imposed by OPA.
OPA also imposes other requirements on facility operators, such as the
preparation of an oil spill contingency plan.  Failure to comply with ongoing
requirements or inadequate cooperation in a spill event may subject a
responsible party to civil or criminal enforcement actions.  As of this date,
the Company is not the subject of any civil or criminal enforcement actions
under the OPA.

         In addition, the OCSLA authorizes regulations relating to safety and
environmental protection applicable to lessees and permittees operating in the
OCS.  Specific design and operational standards may apply to OCS vessels, rigs,
platforms, vehicles and structures.  Violations of lease conditions or
regulations issued pursuant to OCSLA can result in substantial civil and
criminal penalties, as well as potential court injunctions curtailing
operations and the cancellation of leases.  Such enforcement liabilities can
result from either governmental or private prosecution.  As of this date, the
Company is not the subject of any civil or criminal enforcement actions under
OCSLA.

         The Federal Water Pollution Control Act ("FWPCA") imposes restrictions
and strict controls regarding the discharge of produced waters and other oil
and gas wastes into navigable waters.  Permits must be obtained to discharge
pollutants to state and federal waters.  The FWPCA provides for civil, criminal
and administrative penalties for any





                                      -17-
<PAGE>   18
unauthorized discharges of oil and other hazardous substances in reportable
quantities and, along with the OPA, imposes substantial potential liability for
the costs of removal, remediation and damages.  State laws for the control of
water pollution also provide varying civil, criminal and administrative
penalties and liabilities in the case of a discharge of petroleum or its
derivatives into state waters.  In January 1995, the U.S. Environmental
Protection Agency ("EPA") issued general permits prohibiting the discharge of
produced water and produced sand derived from oil and gas point source
facilities to coastal waters in Louisiana and Texas, effective February 8,
1995.  However, concurrent with this action, EPA Region VI issued an
administrative order effectively delaying the prohibition on discharges of
produced water and produced sands to January 1, 1997, unless an earlier
compliance date is required by the State.  Although the costs to comply with
zero discharge mandates under federal or state law may be significant, the
entire industry will experience similar costs and the Company believes that
these costs will not have a material adverse impact on the Company's financial
conditions and operations.  Some oil and gas exploration and production
facilities are required to obtain permits for their storm water discharges.
Costs may be associated with treatment of wastewater or developing storm water
pollution prevention plans.  Further, the Coastal Zone Management Act
authorizes state implementation and development of programs of management
measures for nonpoint source pollution to restore and protect coastal waters.

EMPLOYEES

         As of March 10, 1997, the Company had 97 full time employees, 55 of
whom are located at the Company's headquarters in Houston, Texas and the
remainder of whom are located at field offices.  None of the Company's
employees are represented by a labor union.  The Company contracts with third
parties to conduct its offshore field operations.

OFFICES

         The Company currently leases approximately 54,000 square feet of
office space in Houston, Texas, where its principal offices are located, of
which 25,000 square feet have been subleased to a third party.  In addition,
the Company maintains field operations offices in the areas where it operates
onshore properties.

ITEM 3. LEGAL PROCEEDINGS

         The properties purchased in the TransTexas Acquisition are subject to
two judgment liens imposed on substantially all of TransTexas' properties in
the aggregate amount of $20 million.  TransTexas has agreed to indemnify the
Company with respect to any loss arising from such judgment liens.  TransTexas
has appealed the judgments to which such liens relate, and has posted bonds to
ensure payment of such judgments pending the completion of such appeals.  One
such bond, in the approximate amount of $18 million, is secured by an
irrevocable letter of credit, and the other bond is secured by cash.  The $18
million judgment against TransTexas has been reversed, a decision which, if
upheld, will result in the release of the related judgment lien.  As a result
of such arrangements, the Company believes that the properties purchased in the
TransTexas Acquisition are not subject to any material risk that any such
judgment against TransTexas will not be paid.

         The Company is not a party to any other pending legal proceedings,
other than ordinary routine litigation incidental to its business that
management believes will not have a material adverse effect on its financial
condition or results of operations.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

         No matters were submitted to a vote of the Company's security holders
during the last quarter of the fiscal year ended December 31, 1996.





                                      -18-
<PAGE>   19
PART II.

ITEM 5.  MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
         MATTERS

         The Company's common stock (symbol: THX) is traded on the New York
Stock Exchange.  The following table sets forth the range of high and low sales
prices for each calendar quarterly period from September 20, 1996 through
December 31, 1996 as reported on the New York Stock Exchange:

<TABLE>
<CAPTION>
           YEAR ENDED DECEMBER 31, 1996                                         High          Low    
           ----------------------------                                      ----------   -----------
           <S>                                                               <C>          <C>
           Third Quarter (commencing September 20, 1996) . . . . . . . . .   $  17.00     $   16.50
           Fourth Quarter  . . . . . . . . . . . . . . . . . . . . . . . .      18.25         15.875
</TABLE>

         As of March 10, 1997, 23,332,763 shares of Common Stock were
outstanding and the Company had approximately 58 shareholders of record and
approximately 2,800 beneficial owners.

DIVIDENDS

         The Company currently intends to retain its cash for the operation and
expansion of its business, including exploration, development and acquisition
activities.  The Company's Credit Facility (as defined in "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Liquidity and Capital Resources") contains restrictions on the payment of
dividends to holders of Common Stock.  Accordingly, the Company's ability to
pay dividends will depend upon such restrictions and the Company's results of
operations, financial condition, capital requirements and other factors deemed
relevant by the Board of Directors.  See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations."





                                      -19-
<PAGE>   20
ITEM 6.  SELECTED FINANCIAL DATA

         The selected financial data set forth below with respect to the
Company's combined statements of operations for each of the five years in the
period ended December 31, 1996 and with respect to the Company's combined
balance sheets as of December 31, 1996, 1995, 1994, 1993 and 1992 are derived
from the financial statements of the Company that have been audited by Arthur
Andersen LLP, independent public accountants.  The financial data should be
read in conjunction with the "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and the Company's Financial Statements and
Notes thereto included elsewhere in this report.

<TABLE>
<CAPTION>
                                                                    Year Ended December 31,                           
                                         ----------------------------------------------------------------------
                                             1996           1995           1994          1993           1992       
                                         -----------   ------------    ----------   -------------   -----------        
 Combined Statement of                                       (in thousands, except per share data)
 <S>                                     <C>            <C>              <C>         <C>            <C>
    Operations Data:
 Revenues:
    Natural gas and oil revenues   . . . $  64,864      $  39,431        $41,755     $   37,462     $   21,980
    Other  . . . . . . . . . . . . . . .     1,040          1,778            467            799            841
                                         ---------      ---------        -------     ----------     ----------
         Total revenues  . . . . . . . .    65,904         41,209         42,222         38,261         22,821
 Expenses:
    Lease operating  . . . . . . . . . .    12,201          5,468          5,344          4,477          3,123
    Depreciation, depletion and
    amortization   . . . . . . . . . . .    33,732         21,969         25,365         23,225         14,440
    General and administrative, net  . .     6,249          3,486          3,460          2,454          2,840
    Nonrecurring charge(1)   . . . . . .        --         12,000             --             --             --
    Writedown in carrying value of
         natural gas and oil properties         --             --             --             --         19,697
                                         ---------      ---------        -------     ----------     ----------
         Total operating expenses  . . .    52,182         42,923         34,169         30,156         40,100
 Income (loss) from operations . . . . .    13,722         (1,714)         8,053          8,105        (17,279)
 Interest expense, net . . . . . . . . .     2,875          2,398          2,102          1,764          1,469
                                         ---------      ---------        -------     ----------     ----------
 Income (loss) before income taxes . . .    10,847         (4,112)         5,951          6,341        (18,748)
 Income tax provision (benefit)  . . . .     2,205         (3,809)           597          1,790         (7,440)
                                         ---------      ---------        -------     ----------     ---------- 
 Net income (loss) . . . . . . . . . . . $   8,642      $    (303)       $ 5,354     $    4,551     $  (11,308)
                                         =========      =========        =======     ==========     ========== 
 Net income (loss) per share . . . . . .     $0.49      $   (0.02)       $  0.35     $    (0.30)    $    (0.74)
                                         =========      =========        =======     ==========     ==========
 Weighted average shares outstanding . .    17,532         15,295         15,295         15,295         15,295
</TABLE>

------------------------

(1) Represents a nonrecurring charge incurred in connection with the
    reorganization effective in February 1996.  See Note 11 to the Company's
    Combined Financial Statements.

<TABLE>
<CAPTION>
                                                                     DECEMBER 31,                            
                                          -------------------------------------------------------------------
                                             1996          1995          1994          1993          1992    
                                          -----------   -----------  -----------   -----------   ------------
 <S>                                      <C>           <C>          <C>           <C>           <C>
 COMBINED BALANCE SHEET DATA:
 Property, plant and equipment, net  .    $  359,124    $  216,678   $   169,714   $   127,911   $   92,698
 Total assets  . . . . . . . . . . . .       401,285       247,496       201,678       165,031      130,154
 Long-term debt  . . . . . . . . . . .        65,000        71,862        65,650        46,600       40,800
 Stockholder's equity  . . . . . . . .       233,300       103,236        88,866        65,575       48,466
</TABLE>





                                      -20-
<PAGE>   21
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
         RESULTS OF OPERATIONS

         The following discussion is intended to assist in an understanding of
the Company's historical financial position and results of operations for each
year of the three-year period ended December 31, 1996.  The Company's
historical combined financial statements and notes thereto included elsewhere
in this Annual Report on Form 10-K contain detailed information that should be
referred to in conjunction with the following discussion.

GENERAL

         Houston Exploration was incorporated in December 1985 to conduct
certain of the natural gas and oil exploration and development activities of
Brooklyn Union.  The Company initially focused primarily on the exploration and
development of high potential prospects in the Gulf of Mexico.  Effective
February 29, 1996, Brooklyn Union implemented a reorganization of its
exploration and production assets by transferring to Houston Exploration
certain onshore producing properties and developed and undeveloped acreage.
Subsequent to the reorganization the Company has expanded its focus to include
low risk exploitation and development drilling on the onshore properties
transferred, in addition to seeking opportunistic acquisitions both onshore and
offshore.  On July 2, 1996, the Company acquired certain natural gas and oil
properties and associated pipelines located in Zapata County, Texas from
TransTexas. In September 1996, the Company completed an initial public offering
(the "IPO") of 7,130,000 shares of its Common Stock at $15.50 per share,
resulting in net cash proceeds of approximately $101.0 million.  Concurrently
with the completion of the IPO, the Company completed the acquisition of the
natural gas and oil properties and related assets of Soxco.  As of December 31,
1996, THEC Holdings Corp., a wholly-owned subsidiary of Brooklyn Union, owned
approximately 66% of the outstanding shares of Common Stock.  At December 31,
1996, the Company had historical net proved reserves of 327 Bcfe, 98% of which
were natural gas and 74% of which were classified as proved developed.

         The Company's revenue, profitability and future rate of growth are
substantially dependent upon prevailing prices for natural gas, oil and
condensate, which are dependent upon numerous factors beyond the Company's
control, such as economic, political and regulatory developments and
competition from other sources of energy.  The energy markets have historically
been highly volatile, and future decreases in natural gas and oil prices could
have a material adverse effect on the Company's financial position, results of
operations, quantities of natural gas and oil reserves that may be economically
produced, and access to capital.

         The Company uses the full cost method of accounting for its investment
in natural gas and oil properties.  Under the full cost method of accounting,
all costs of acquisition, exploration and development of natural gas and oil
reserves are capitalized into a "full cost pool" as incurred, and properties in
the pool are depleted and charged to operations using the unit-of-production
method based on the ratio of current production to total proved natural gas and
oil reserves.  To the extent that such capitalized costs (net of accumulated
depreciation, depletion and amortization) less deferred taxes exceed the
present value (using a 10% discount rate) of estimated future net cash flows
from proved natural gas and oil reserves and the lower of cost or fair value of
unproved properties, such excess costs are charged to operations.  If a
writedown is required, it would result in a charge to earnings but would not
have an impact on cash flows from operating activities.

         As of December 31, 1996, the Company estimates, using prices in effect
as of such date, that the ceiling limitation imposed under full cost accounting
rules on total capitalized natural gas and oil property costs exceeded actual
capitalized costs by approximately $182.0 million (net of taxes).  Natural gas
prices declined substantially during the first quarter of 1997 from prices in
effect on December 31, 1996.  As a result, the Company may be required to write
down the carrying value of its natural gas and oil properties at the end of the
first quarter of 1997, depending upon natural gas prices and the results of the
Company's drilling programs during the first quarter 1997.

         The Company incurs certain production gas volume imbalances in the
ordinary course of business and utilizes the entitlements method to account for
its gas imbalances.  Under this method, income is recorded based on the
Company's net revenue interest in production or nominated deliveries.
Deliveries in excess of these amounts are recorded as liabilities, while under
deliveries are reflected as assets.  Production imbalances are valued using
market value.  Management does not believe that the Company has any material
overproduced gas balances.





                                      -21-
<PAGE>   22
         The Company receives reimbursement for administrative and overhead
expenses incurred on the behalf of other working interest owners of properties
operated by the Company.  In addition, the Company capitalizes general and
administrative costs and interest expense directly related to its acquisition,
exploration and development activities.

         The Company utilizes natural gas forward contracts or fixed-floating
price swaps for a portion of its natural gas production to achieve a more
predictable cash flow, as well as to reduce its exposure to adverse price
fluctuations of natural gas.  The swap agreements call for the Company to
receive or make payment based upon the differential between a fixed and a
variable commodity price specified in the contracts.  The Company accounts for
these transactions as hedging activities and, accordingly, gains or losses are
included in natural gas and oil revenues in the period of the hedged
production.  The Company has entered into contracts covering an average of
approximately 53,000 Mmbtu per day (51,000 Mcf/d) of natural gas production for
April through October 1997 at a weighted average price of $1.98 per Mmbtu,
before transaction and transportation costs.  The Company has also entered into
contracts covering an average of approximately 19,000 Mmbtu per day (18,000 Mcf
/d) for November 1997 through March 1998 at a weighted average price of $2.02
per Mmbtu before transaction and transportation costs.  The Company accounts
for its commodity swaps and futures as hedging activities and, accordingly,
gains or losses are included in natural gas and oil revenues in the period the
production occurs.  See Note 8 to the Company's Combined Financial Statements.

         The Company's combined historical financial statements include the
historical results of operations associated with the onshore producing
properties and developed and undeveloped acreage transferred to the Company by
FRI, a subsidiary of Brooklyn Union, in the February 1996 reorganization
implemented by Brooklyn Union.  Accordingly, the Company's historical results
of operations reflect a nonrecurring charge of $12 million incurred in the year
ended December 31, 1995 with respect to remuneration to which certain employees
of FRI were entitled for the increase in the value of the transferred
properties prior to the reorganization. See Notes 1 and 11 to the Company's
Combined Financial Statements.

RESULTS OF OPERATIONS

         The following table sets forth the Company's historical natural gas
and oil production data during the periods indicated:

<TABLE>
<CAPTION>
                                                                    Year Ended December 31,                  
                                                  -----------------------------------------------------------
                                                         1996                1995                 1994       
                                                  ------------------  ------------------   ------------------
 <S>                                              <C>                 <C>                  <C>
 Production:
 Natural gas (Mmcf)  . . . . . . . . . . . . .           31,215             21,077               22,437
 Oil (Mbbls) . . . . . . . . . . . . . . . . .              118                100                  102
 Total (Mmcfe) . . . . . . . . . . . . . . . .           31,923             21,677               23,049

 Average sales prices:
    Natural Gas (per Mcf)(1) . . . . . . . . .    $        2.00       $       1.79         $       1.79
    Oil (per Bbl)  . . . . . . . . . . . . . .            21.53              16.54                15.85

 Expenses (per Mcfe):
    Lease operating  . . . . . . . . . . . . .    $        0.38       $       0.25         $       0.23
    Depreciation, depletion and amortization .             1.06               1.01                 1.10
    General and administrative, net  . . . . .             0.20               0.16                 0.15
</TABLE>


(1)      Reflects the effects of hedging.  Absent the effects of hedging,
         average realized natural gas prices would have been $2.35, $1.53 and
         $1.83 per Mcf for the years ended December 31, 1996, 1995, and 1994,
         respectively.





                                      -22-
<PAGE>   23
RECENT FINANCIAL AND OPERATING RESULTS

         COMPARISON OF YEARS ENDED DECEMBER 31, 1995 AND 1996

         General.  Houston Exploration's production increased 47% from 21,677
Mmcfe in 1995 to 31,923 Mmcfe in 1996.  The 1996 production increase is
attributed to commencement of production from newly developed offshore
properties during the first half of the year and the Company's two significant
acquisitions during the second half of the year: (i) the TransTexas
Acquisition, which was completed on July 2, 1996,  and (ii) the Soxco
Acquisition, which was completed on September 25, 1996 concurrently with the
closing of the IPO.

         Natural Gas and Oil Revenues.  Natural gas and oil revenues increased
65% from $39.4 million in 1995 to $64.9 million in 1996 as a result of the 47%
increase in production and an increase in average realized natural gas prices
of 12% from $1.79 per Mcf in 1995 to $2.00 Mcf in 1996.

         As a result of hedging activities, the Company realized an average gas
price of $2.00 per Mcf for 1996, compared to an average price of $2.35 per Mcf
that otherwise would have been received, resulting in a $11.1 million decrease
in natural gas revenues for the year ended December 31, 1996.  During 1995, the
average realized gas price was $1.79 per Mcf  compared to an unhedged average
gas price of $1.53, resulting in an increase to natural gas revenues of $5.6
million for the year ended December 31, 1995.

         Lease Operating Expenses.  Lease operating expenses increased 122%
from $5.5 million in 1995 to $12.2 million in 1996.  On an Mcfe basis, lease
operating expenses increased from $0.25 in 1995 to $0.38 in 1996.  Of the $6.7
million increase in lease operating costs during 1996, $3.2 million relates
directly to properties acquired in the TransTexas Acquisition at the beginning
of the third quarter and includes certain one-time expenses incurred in taking
over operations of these properties, and the remaining $3.5 million reflects
higher initial operating costs associated with bringing new facilities and
wells on line.

         Depreciation, Depletion and Amortization.  Depreciation, depletion and
amortization expense increased 53% from $22.0 million in 1995 to $33.7 million
in 1996. The increase was attributable to the increase in production during
1996.  Depreciation, depletion and amortization expense per Mcfe increased from
$1.01 in 1995 to $1.06 in 1996, primarily as a result of exploratory drilling
which did not add significant new reserves during the period.

         General and Administrative Expenses.  General and administrative
expenses, net of overhead reimbursements received from other working interest
owners of $1.2 million and $1.0 million for 1995 and 1996, respectively,
increased 77% from $3.5 million in 1995 to $6.2 million in 1996.  The Company
capitalized general and administrative expenses directly related to oil and gas
exploration and development activities of $4.1 million and $5.3 million,
respectively, in 1995 and 1996.  The increase in net general and administrative
expenses during 1996 is a result of certain one-time expenses incurred in
conjunction with the combination of offshore and onshore operations and an $0.8
million charge taken in conjunction with the IPO for the buyout and termination
of options to purchase Common Stock granted to certain officers and directors
of Brooklyn Union under the Company's 1994 Incentive Plan.  On an Mcfe basis,
general and administrative expenses increased from $0.16 in 1995 to $0.20 in
1996, or $0.17 per Mcfe excluding the $0.8 million buyout of the options issued
under the 1994 Incentive Plan.

         Nonrecurring Charge. During 1995, the Company incurred a $12.0 million
nonrecurring charge to reflect the amount of remuneration paid to former
employees of FRI.  During 1996 the Company did not incur additional charges
related to the remuneration paid to former FRI employees.  See "--General" and
Note 11 to the Company's  Combined Financial Statements.

         Income Tax Provision.  Income tax expense increased from a benefit of
$3.8 million in 1995 to an expense of $2.2 million in 1996.  Included in the
provision for 1995 was a credit of $4.2 million related to the $12.0 million
nonrecurring charge.  For 1996, the primary difference between the Company's
statutory tax rate of 35% and its effective rate of 20% was due to the
utilization of Section 29 credits received for specific onshore properties.





                                      -23-
<PAGE>   24
         Net Income.  The Company's net income increased from a loss of $0.3
million in 1995 to net income of $8.6 million in 1996.  Excluding the effects
of the $12.0 million charge ($7.8 million net of tax), the Company's net income
increased 15% from $7.5 million in 1995 to $8.6 million in 1996.  The increase
in net income resulted from increased production from newly developed
properties and production from properties acquired in the TransTexas and Soxco
Acquisitions, combined with an increase in realized natural gas prices.  Both
lease operating and general and administrative expenses increased from the
prior year due to certain one-time charges and interest expense reflects third
quarter borrowings, which were repaid with proceeds from the IPO.

         COMPARISON OF YEARS ENDED DECEMBER 31, 1994 AND 1995

         General.  Houston Exploration's production decreased 6% from 23,049
Mmcfe in 1994 to 21,677 Mmcfe in 1995.  Lower production rates from year
earlier levels resulted from voluntary shut-ins the first quarter of 1995 due
to severely depressed natural gas prices, combined with natural production
declines.  In addition, capital spending constraints for offshore exploration
in 1992 and 1993 contributed to the 1995 production shortfall.  Production
declines were offset somewhat by new production at Mustang Island 759 and East
Cameron 82.  Despite the successful drilling of eight offshore wells, only one
of these new wells, East Cameron 82, was producing by year end 1995.  In 1994,
capital expenditures for offshore exploration increased to $15.4 million,
compared with capital expenditures for offshore exploration of $6.0 million in
1993 and $3.9 million in 1992.

         Natural Gas and Oil Revenues.  Natural gas and oil revenues decreased
6% from $41.7 million in 1994 to $39.4 million in 1995 as a result of the 6%
decrease in production.  Average realized natural gas prices remained flat at
$1.79 per Mcf in both 1994 and 1995.

         As a result of hedging activities, the Company realized an average gas
price of $1.79 per Mcf compared to an average price of $1.53 per Mcf that
otherwise would have been received, resulting in a $5.6 million increase in
natural gas and oil revenues for 1995.  For 1994, the average realized gas
price was $1.79 per Mcf compared to an unhedged average gas price of $1.83,
resulting in a $0.8 million decrease in natural gas and oil revenues for the
year.

         Lease Operating Expenses.  Lease operating expenses for the year ended
1995 increased 4% from $5.3 million in 1994 to $5.5 million in 1995.  On an
Mcfe basis, lease operating costs increased 9% from $0.23 in 1994 to $0.25 in
1995, corresponding to the decrease in 1995 production.

         Depreciation, Depletion and Amortization.  Depreciation, depletion and
amortization expense decreased 13% from $25.4 million in 1994 to $22.0 million
in 1995.  The decrease was attributable to a lower depletion rate per Mcfe
combined with decreased production.  Depreciation, depletion and amortization
expense per Mcfe decreased from $1.10 in 1994 to $1.01 in 1995, due to a higher
successful drilling rate in 1995 as compared to 1994.

         General and Administrative Expenses.  General and administrative
expenses, net of overhead reimbursements received from other working interest
owners of $1.3 million and $1.2 million in 1994 and 1995, respectively,
remained flat at $3.5 million for both 1994 and 1995.  The Company capitalized
general and administrative expenses directly related to oil and gas exploration
and development activities of $3.9 million and $4.1 million, respectively, for
1994 and 1995.  On an Mcfe basis, general and administrative expenses increased
from $0.15 in 1994 to $0.16 in 1995, reflecting flat costs and lower
production.

         Nonrecurring Charge.  The Company incurred a $12 million nonrecurring
charge in the year ended December 31, 1995 to reflect the estimated amount of
remuneration payable to former employees of FRI.  See "--General" and Note 11
to the Company's Combined Financial Statements.

         Income Tax Provision.  Income tax expense decreased from an expense of
$0.6 million in 1994 to a benefit of $3.8 million in 1995.  The benefit in 1995
reflects the tax effect of the $12.0 million nonrecurring charge as well as the
utilization of Section 29 tax credits received for specific onshore properties.





                                      -24-
<PAGE>   25
         Net Income (Loss).  Net income decreased $5.7 million from $5.4
million in 1994 to a loss of $0.3 million in 1995, primarily as a result of the
$12.0 million nonrecurring charge.  Operating income before the $12.0 million
nonrecurring charge increased $2.2 million from $8.1 million in 1994 to $10.3
million in 1995 as a result of additional revenues recognized from hedging
activities and lower depreciation, depletion and amortization expense resulting
from lower production volumes and lower depletion rates.

LIQUIDITY AND CAPITAL RESOURCES

         The Company has historically funded its operations, acquisitions,
capital expenditures and working capital requirements from cash flows from
operations, bank borrowings and capital contributions from Brooklyn Union.

         The Company had $2.9 million in working capital and an $85.0 million
available borrowing base under its Credit Facility as of December 31, 1996. Net
cash provided by operating activities during 1996 aggregated $54.1 million.
The Company's cash position was increased during the period by proceeds of
$101.0 million from the issuance of 7,130,000 shares of Common Stock in the
IPO, borrowing of $76.8 million under the Company's Credit Facility and $6.3
million in capital contributions from Brooklyn Union.  Funds used in investing
and financing activities consisted of $154.1 million for investments in
property and equipment and principal payments of $83.7 million on long-term
borrowings under the Credit Facility.  As a result of these activities, cash
and cash equivalents increased $2.2 million from $0.6 million at December 31,
1995 to $2.8 million at December 31, 1996.

         The Company's primary sources of funds for each of the past three
years are reflected in the following table:

<TABLE>
<CAPTION>
                                                                YEARS ENDED DECEMBER 31,
                                                         ------------------------------------------
                                                              1996          1995          1994     
                                                         ------------------------------------------
<S>                                                      <C>           <C>           <C>
Net cash provided by operating activities . . . . . . .  $   54,065    $    55,778   $   26,074
Net borrowings (repayments) under Credit Facility . . .      (6,862)         6,212       19,050
Proceeds from sale of common stock  . . . . . . . . . .     101,014            ---           --
Capital contributions by Brooklyn Union . . . . . . . .       6,342          6,873       18,021
</TABLE>


         The Company's capital expenditures for each of the past five years are
reflected in the following table:

<TABLE>
<CAPTION>
                                                                 Years Ended December 31,                     
                                           -------------------------------------------------------------------
                                               1996          1995          1994         1993          1992    
                                           ------------- ------------ ------------- ------------ -------------
 <S>                                       <C>           <C>          <C>           <C>          <C>
 OFFSHORE:
 Acquisitions of properties  . . . . . . . $   58,578    $  18,236    $    12,890   $   9,796    $    7,472
 Development . . . . . . . . . . . . . . .     25,399       32,228          9,351      10,058        12,146
 Exploration . . . . . . . . . . . . . . .     27,398        6,355         15,370       5,983         3,930
                                           ----------    ---------    -----------   ---------    ----------
                                              111,375       56,819         37,611      25,837        23,548

 ONSHORE:
 Acquisitions of properties  . . . . . . . $   59,513    $   2,803    $    22,886   $  31,446    $    3,519
 Development . . . . . . . . . . . . . . .      5,844        8,935          2,439       1,274         5,463
 Exploration . . . . . . . . . . . . . . .         --          869          2,060          --            --
                                           ----------    ---------    -----------   ---------    ----------
                                               65,357       12,607         27,385      32,720         8,982
                                           ----------    ---------    -----------   ---------    ----------
    Total  . . . . . . . . . . . . . . . . $  176,732    $  69,426    $    64,996   $  58,557    $   32,530
                                           ==========    =========    ===========   =========    ==========
</TABLE>

         The Company's capital expenditure budget for 1997 of $75 million
includes $39 million and $36 million, respectively, for exploration and
development.  These amounts include development costs associated with recently
acquired properties and amounts that are contingent upon drilling success.  The
Company will continue to evaluate its capital spending plans through the year.
No significant abandonment or dismantlement costs are anticipated through 1997.
Actual levels of capital expenditures may vary significantly due to a variety
of factors, including drilling results, natural gas and oil prices, industry
conditions and outlook and future acquisitions of properties.  The Company
believes cash flows from operations and borrowings under its credit facility
will be sufficient to fund these expenditures.  The





                                      -25-
<PAGE>   26
Company will continue to selectively seek acquisition opportunities for proved
reserves with substantial exploration and development potential both offshore
and onshore.  The size and timing of capital requirements for acquisitions is
inherently unpredictable.  The Company expects to fund exploration and
development through a combination of cash flow from operations, borrowings
under its Credit Facility, additional borrowing facilities or the issuance of
equity or debt securities.

         The Company has entered into a credit facility (the "Credit Facility")
with a syndicate of lenders led by Texas Commerce Bank National Association
("TCB") which provides a maximum loan amount of $150 million, subject to
borrowing base limitations, on a revolving basis.  On March 10, the borrowing
base was $150 million, $82.5 million of which was borrowed.  The Credit
Facility matures on July 1, 2000 and is currently unsecured.  Advances under
the Credit Facility bear interest, at the Company's election at (i) a
fluctuating rate ("Base Rate") equal to the higher of the Federal Funds Rate
plus 0.5% or TCB's prime rate or (ii) a fixed rate ("Fixed Rate") equal to a
quoted LIBOR rate plus a margin between 0.5% and 1.125% depending on the amount
outstanding under the Credit Facility.  Interest is due at calendar quarters
for Base Rate loans and at the earlier of maturity or three months from the
date of the loan for Fixed Rate loans.  The Credit Facility contains covenants
of the Company, including certain restrictions on liens and financial covenants
which require the Company to, among other things, maintain (i) a minimum
tangible net worth of $181 million and (ii) a total debt to capitalization
ratio of less than 55%.  The Credit Facility also restricts the Company's
ability to purchase or redeem its capital stock or to pledge its oil and gas
properties or other assets.  The borrowing base under the Credit Facility is
determined by TCB at its discretion in accordance with TCB's then current
standards and practices for similar oil and gas loans taking into account such
factors as TCB deems appropriate.

         Pursuant to the Credit Facility, the Company may declare and pay cash
dividends to its stockholders provided that (i) no defaults exist and the
Company will not be in default with respect to any financial covenants as a
result of such dividend payment and (ii) the Company continues to have a ratio
of consolidated total debt to consolidated total capitalization of less than
55%.  Accordingly, the Company's ability to pay dividends will depend upon such
restrictions and the Company's results of operations, financial condition,
capital requirements and other factors deemed relevant by the Board of
Directors.  See "Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters -- Dividends."

         For a description of certain bonding requirements related to offshore
production proposed by the Minerals Management Service, see "Items 1 and 2.
Business and Properties -- Environmental Matters."

ITEM 8.  FINANCIAL STATEMENTS

         The financial statements required by this Item are incorporated under
Item 14 in Part IV of this report.

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
         FINANCIAL DISCLOSURE

         None.





                                      -26-
<PAGE>   27
                                   PART III.

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

         The information required by this Item as to the directors and
executive officers of the Company is hereby incorporated by reference from the
information appearing under the captions "Election of Directors" and "Executive
Officers" in the Company's definitive proxy statement which involves the
election of directors and is to be filed with the Securities and Exchange
Commission ("Commission") pursuant to the Securities Exchange Act of 1934
within 120 days of the end of the Company's fiscal year on December 31, 1996.

ITEM 11.  EXECUTIVE COMPENSATION

         The information required by this Item as to the management of the
Company is hereby incorporated by reference from the information appearing
under the captions "Executive Compensation" and "Election of Directors -
Director's Meetings and Compensation" in the Company's definitive proxy
statement which involves the election of directors and is to be filed with the
Commission pursuant to the Securities Exchange Act of 1934 within 120 days of
the end of the Company's fiscal year on December 31, 1996.  Notwithstanding the
foregoing, in accordance with the instructions to Item 402 of Regulation S-K,
the information contained in the Company's proxy statement under the
sub-heading "Report of the Compensation Committee of the Board of Directors"
and "Performance Graph" shall not be deemed to be filed as part of or
incorporated by reference into this Form 10-K.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

         The information required by this Item as to the ownership by
management and others of securities of the Company is hereby incorporated by
reference from the information appearing under the caption "Security Ownership
of Certain Beneficial Owners and Management" to the Company's definitive proxy
statement which involves the election of directors and is to be filed with the
Commission pursuant to the Securities Exchange Act of 1934 within 120 days of
the end of the Company's fiscal year on December 31, 1996.

ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

         The information required by this Item as to certain business
relationships and transactions with management and other related parties of the
Company is hereby incorporated by reference to such information appearing under
the captions "Certain Transactions" and "Executive Compensation--Compensation
Committee Interlocks and Insider Participation" in the Company's definitive
proxy statement which involves the election of directors and is to be filed
with the Commission pursuant to the Securities Exchange Act of 1934 within 120
days of the end of the Company's fiscal year on December 31, 1996.





                                      -27-
<PAGE>   28
                                    PART IV.

ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

         (a)     Documents Filed as a Part of this Report

1.   FINANCIAL STATEMENTS:
<TABLE>
<CAPTION>
                                                                                                    PAGE     
                                                                                               --------------
 <S>                                                                                             <C>
 Report of Independent Public Accountants  . . . . . . . . . . . . . . . . . . . . . . . .          F-1
 Combined Balance Sheets as of December 31, 1996 and 1995  . . . . . . . . . . . . . . . .          F-2
 Combined Statements of Operations for the Years Ended December 31, 1996, 1995 and 1994  .          F-3
 Combined Statement of Stockholders' Equity for the Period from December 31, 1993
    to December 31, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          F-4
 Combined Statements of Cash Flows for the Years Ended December 31, 1996, 1995 and 1994  .          F-5
 Notes to Combined Financial Statements  . . . . . . . . . . . . . . . . . . . . . . . . .       F-6 - F-18
 Supplemental Oil and Gas Reserve Information  . . . . . . . . . . . . . . . . . . . . . .          F-19
 Quarterly Financial Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          F-22
</TABLE>

         All other schedules are omitted because they are not applicable, not
required, or because the required information is included in the financial
statements or notes thereto.

2.   EXHIBITS:

         Exhibits to the Form 10-K have been included only with the copies of
the Form 10-K filed with the Commission and the New York Stock Exchange.  Upon
request to the Company and payment of a reasonable fee, copies of the
individual exhibits will be furnished.

<TABLE>                                   
<CAPTION>                                 
 EXHIBITS         DESCRIPTION             
 --------         -----------             
 <S>            <C>                       
 3.1    --      Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Company's Registration                       
                Statement on Form S-1 (Registration No. 333-4437) and incorporated by reference herein).                        
 3.2    --      Restated Bylaws (filed as Exhibit 3.2 to the Company's Registration Statement on Form S-1                       
                (Registration No. 333-4437) and incorporated by reference herein).                                              
 4.1    --      Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company's Registration                           
                Statement on Form S-1 (Registration No. 333-4437) and incorporated by reference herein).                        
 10.1+  --      Gas Sales Agreement dated as of April 1, 1995 between The Houston Exploration Company and                       
                PennUnion Energy Services, L.L.C. (filed as Exhibit 10.1 to the Company's Registration                          
                Statement on Form S-1 (Registration No. 333-4437) and incorporated by reference herein).                        
 10.2+  --      Gas Sales Agreement dated as of April 1, 1995 between Fuel Resources Inc. and PennUnion                         
                Energy Services L.L.C. (filed as Exhibit 10.2 to the Company's Registration Statement on                        
                Form S-1 (Registration No. 333-4437) and incorporated by reference herein).                                     
 10.3   --      Confidentiality and Non-Competition Agreement dated as of March 21, 1995 among PennUnion                        
                Energy Services, L.L.C., BRING Gas Services Corp., The Brooklyn Union Gas Company, Fuel                         
                Resources Inc., Fuel Resources Production and Development, Inc., The Houston Exploration                        
                Company, Gas Energy, Inc., Pennzoil Gas Marketing Company, Pennzoil Exploration and                             
                Development Company, and Pennzoil Company (filed as Exhibit 10.3 to the Company's                               
                Registration Statement on Form S-1 (Registration No. 333-4437) and incorporated by                              
                reference herein).                                                                                              
 10.4   --      Swap Agreement dated September 22, 1994 between Enron Risk Management Services Corp. and                        
                The Houston Exploration Company (filed as Exhibit 10.4 to the Company's Registration                            
                Statement on Form S-1 (Registration No. 333-4437) and incorporated by reference herein).                        
</TABLE>                                  
                                          
                                          
                                          
                                          
                                          
                                     -28- 
<PAGE>   29
<TABLE>                                                                 
<CAPTION>                                                               
 EXHIBITS         DESCRIPTION                                           
 --------         -----------                                                                                                   
 <S>            <C>                                                                                                             
 10.5    --     Swap Agreement dated February 21, 1995 between Chemical Bank and The Houston Exploration                        
                Company (filed as Exhibit 10.5 to the Company's Registration Statement on Form S-1                              
                (Registration No. 333-4437) and incorporated by reference herein).                                              
 10.6    --     Swap Agreement dated March 2, 1995 between Chemical Bank and The Houston Exploration                            
                Company (filed as Exhibit 10.6 to the Company's Registration Statement on Form S-1                              
                (Registration No. 333-4437) and incorporated by reference herein).                                              
 10.7    --     Swap Agreement dated February 5, 1992 between Chemical Bank and Fuel Resources Inc. (filed                      
                as Exhibit 10.7 to the Company's Registration Statement on Form S-1 (Registration                               
                No. 333-4437) and incorporated by reference herein).                                                            
 10.8    --     Agreement for Filing Consolidated Federal Income Tax Returns and for Allocation of                              
                Consolidated Federal Income Tax Liabilities and Benefits dated September 1, 1994 between                        
                The Brooklyn Union Gas Company and its subsidiaries (filed as Exhibit 10.19 to the                              
                Company's Registration Statement on Form S-1 (Registration No. 333-4437) and incorporated                       
                by reference herein).                                                                                           
 10.9**  --     Employment Agreement dated July 2, 1996 between The Houston Exploration Company and James                       
                G. Floyd (filed as Exhibit 10.8 to the Company's Registration Statement on Form S-1                             
                (Registration No. 333-4437) and incorporated by reference herein).                                              
 10.10** --     Employment Agreement dated July 2, 1996 between The Houston Exploration Company and Randall                     
                J. Fleming (filed as Exhibit 10.9 to the Company's Registration Statement on Form S-1                           
                (Registration No. 333-4437) and incorporated by reference herein).                                              
 10.11** --     Employment Agreement dated July 2, 1996 between The Houston Exploration Company and Thomas                      
                W. Powers (filed as Exhibit 10.10 to the Company's Registration Statement on Form S-1                           
                (Registration No. 333-4437) and incorporated by reference herein).                                              
 10.12** --     Employment Agreement dated July 2, 1996 between The Houston Exploration Company and James                       
                F. Westmoreland (filed as Exhibit 10.11 to the Company's Registration Statement on Form S-1                     
                (Registration No. 333-4437) and incorporated by reference herein).                                               
 10.13** --     1996 Stock Option Plan (filed as Exhibit 10.12 to the Company's Registration Statement on                       
                Form S-1 (Registration No. 333-4437) and incorporated by reference herein).                                     
 10.14   --     Registration Rights Agreement dated as of July 2, 1996 between The Houston Exploration                          
                Company and THEC Holdings Corp. (filed as Exhibit 10.13 to the Company's Registration                           
                Statement on Form S-1 (Registration No. 333-4437) and incorporated by reference herein).                        
 10.15   --     Asset Purchase Agreement dated as of July 1, 1996 between The Houston Exploration Company                       
                and Smith Offshore Exploration Company (filed as Exhibit 10.14 to the Company's                                 
                Registration Statement on Form S-1 (Registration No. 333-4437) and incorporated by                              
                reference herein).                                                                                              
 10.16   --     Registration Rights Agreement between The Houston Exploration Company and Smith Offshore                        
                Exploration Company (filed as Exhibit 10.15 to the Company's Registration Statement on Form                     
                S-1 (Registration No. 333-4437) and incorporated by reference herein).                                          
 10.17   --     Credit Agreement dated as of July 2, 1996 among The Houston Exploration Company and Texas                       
                Commerce Bank National Association, as Administrative Agent, and the other Banks signatory                      
                thereto (filed as Exhibit 10.16 to the Company's Registration Statement on Form S-1                             
                (Registration No. 333-4437) and incorporated by reference herein).                                              
 10.18   --     Purchase and Sale Agreement dated as of June 21, 1996, among The Houston Exploration                            
                Company, TransTexas Gas Corporation and TransTexas Transmission Corporation (filed as                           
                Exhibit 10.17 to the Company's Registration Statement on Form S-1 (Registration No. 333-                        
                4437) and incorporated by reference herein).                                                                    
 10.19   --     Gas Exchange Agreement dated as of July 2, 1996 between The Houston Exploration Company and                     
                TransTexas Gas Corporation (filed as Exhibit 10.18 to the Company's Registration Statement                      
                on Form S-1 (Registration No. 333-4437) and incorporated by reference herein).                                  
 10.20   --     Indemnification Agreement dated as of September 25, 1996 between The Houston Exploration                        
                Company and THEC Holdings Corp. (filed as Exhibit 10.20 to the Company's Registration                           
                Statement on Form S-1 (Registration No. 333-4437) and incorporated by reference herein).                        
</TABLE>     
             
             
             
             
             
                                     -29-                               
<PAGE>   30
<TABLE>                                                                    
<CAPTION>                                                                  
 EXHIBITS         DESCRIPTION                                              
 --------         -----------                                              
<S>             <C>                                                        
 10.21    --    Contribution Agreement dated as of February 26, 1996 between The Houston Exploration                            
                Company and Fuel Resources Inc. (filed as Exhibit 10.21 to the Company's Registration                           
                Statement on Form S-1 (Registration No. 333-4437) and incorporated by reference herein).                        
 10.22**  --    Registration Rights Agreement dated as of September 25, 1996 between The Houston                                
                Exploration Company and James G. Floyd (filed as Exhibit 10.22 to the Company's                                 
                Registration Statement on Form S-1 (Registration No. 333-4437) and incorporated by                              
                reference herein).                                                                                              
 10.23**  --    Supplemental Executive Pension Plan (filed as Exhibit 10.23 to the Company's Registration                       
                Statement on Form S-1 (Registration No. 333-4437) and incorporated by reference herein).                        
 10.24    --    Deed of Trust, Assignment of Production, Security Agreement and Financing Statement between                     
                The Houston Exploration Company and James G. Floyd (filed as Exhibit 10.24 to the Company's                     
                Registration Statement on Form S-1 (Registration No. 333-4437) and incorporated by                              
                reference herein).                                                                                              
 10.25    --    Contribution Agreement between James G. Floyd and The Houston Exploration Company (filed as                     
                Exhibit 10.25 to the Company's Registration Statement on Form S-1 (Registration No. 333-                        
                4437) and incorporated by reference herein).                                                                    
 *10.26** --    Employment Agreement, dated September 19, 1996, between The Houston Exploration Company and                     
                Charles W. Adcock.                                                                                              
 *10.27** --    Form of Letter Agreement from The Houston Exploration Company to each of James G. Floyd,                        
                Randall J. Fleming, Thomas W. Powers, Charles W. Adcock, James F. Westmoreland and                              
                Sammye L. Dees evidencing grants of Phantom Stock Rights effective as of December 16, 1996.                     
 * 21.1   --    Subsidiaries of the Company.                                                                                    
 * 27.1   --    Financial Data Schedule.                                                                                        
</TABLE>


-----------------------
*        Filed herewith.
**       Management contract or compensation plan.
+        Confidential treatment has been requested.  The copy filed as an
         exhibit omits the information subject to the confidentiality request.

         (b)     Reports on Form 8-K:

                 None





                                     -30-
<PAGE>   31
                                   SIGNATURES

         Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.

                                        THE HOUSTON EXPLORATION COMPANY

                                        By:       /s/ James G. Floyd
                                           ------------------------------------
                                                      James G. Floyd
Date: March 20, 1997                       President and Chief Executive Officer

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

<TABLE>
<CAPTION>
         Signature                                          Title                                     Date
         ---------                                          -----                                     ----
<S>                                        <C>                                                <C>
/s/ JAMES G. FLOYD                         President, Chief Executive Officer                 March 20, 1997
----------------------------------         and Director (Principal Executive                                        
         James G. Floyd                    Officer)                          
                                                                             

/s/ JAMES F. WESTMORELAND                  Vice President, Chief Accounting                   March 20, 1997
----------------------------------         Officer, Comptroller and Secretary                               
         James F. Westmoreland             (Principal Financial Officer and  
                                           Principal Accounting Officer)     
                                                                             

/s/ ROBERT B. CATELL                       Chairman of the Board of Directors                 March 20,1997
----------------------------------                                                                         
         Robert B. Catell

/s/ GORDON F. AHALT                        Director                                           March 20, 1997
----------------------------------                                                                                  
         Gordon F. Ahalt

/s/ RUSSELL D. GORDY                       Director                                           March 20, 1997
----------------------------------                                                                                  
         Russell D. Gordy

/s/ CRAIG G. MATTHEWS                      Director                                           March 20, 1997
----------------------------------                                                                                  
         Craig G. Matthews

/s/ JAMES Q. RIORDAN                       Director                                           March 20, 1997
----------------------------------                                                                                  
         James Q. Riordan

/s/ LESTER H. SMITH                        Director                                           March 20, 1997
----------------------------------                                                                                  
         Lester H. Smith
</TABLE>





                                      -31-
<PAGE>   32
                         GLOSSARY OF OIL AND GAS TERMS

         The definitions set forth below shall apply to the indicated terms as
used in this Annual Report on Form 10-K.  All volumes of natural gas referred
to herein are stated at the legal pressure base of the state or area where the
reserves exist and at 60 degrees Fahrenheit and in most instances are rounded
to the nearest major multiple.

         Bbl.  One stock tank barrel, or 42 U.S. gallons liquid volume, used
herein in reference to crude oil or other liquid hydrocarbons.

         Bbl/d.  One barrel per day.

         Bcf.  Billion cubic feet.

         Bcfe.  Billion cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.

         Btu.   British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

         Completion.   The installation of permanent equipment for the
production of oil or gas, or in the case of a dry hole, the reporting of
abandonment to the appropriate agency.

         Developed acreage.  The number of acres which are allocated or
assignable to producing wells or wells capable of production.

         Developed well.  A well drilled within the proved area of an oil or
gas reservoir to the depth of a stratigraphic horizon known to be productive.

         Dry hole or well.  A well found to be incapable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.

         Exploratory well.  A well drilled to find and produce oil or gas
reserves not classified as proved, to find a new reservoir in a field
previously found to be productive of oil or gas in another reservoir or to
extend a known reservoir.

         Farm-in or farm-out.  An agreement whereunder the owner of a working
interest in an natural gas and oil lease assigns the working interest or a
portion thereof to another party who desires to drill on the leased acreage.
Generally, the assignee is required to drill one or more wells in order to earn
its interest in the acreage.  The assignor usually retains a royalty or
reversionary interest in the lease.  The interest received by an assignee is a
"farm-in" while the interest transferred by the assignor is a "farm-out."

         Field.  An area consisting of a single reservoir or multiple
reservoirs all grouped on or related to the same individual geological
structural feature and/or stratigraphic condition.

         Gross acres or gross wells.  The total acres or wells, as the case may
be, in which a working interest is owned.

         Mbbls.   One thousand barrels of crude oil or other liquid
hydrocarbons.

         Mbbls/d.  One thousand barrels of crude oil or other liquid
hydrocarbons per day.

         Mcf.  One thousand cubic feet.

         Mcf/d.  One thousand cubic feet per day.





                                      G-1

<PAGE>   33
         Mcfe.  One thousand barrels of oil equivalent, determined using the
ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural
gas liquids.

         Mcfe/d.  One thousand barrels of oil equivalent, determined using the
ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural
gas liquids per day.

         Mmbbls.  One million barrels of crude oil or other liquid
hydrocarbons.

         Mmbtu.  One million Btus.

         Mmcf.  One million cubic feet.

         Mmcf/d.  One million cubic feet per day.

         Mmcf/e.  One million barrels of oil equivalent, determined using the
ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural
gas liquids.

         Net acres or net wells.  The sum of the fractional working interests
owned in gross acres or gross wells.

         Oil.  Crude oil and condensate.

         Present value.  When used with respect to natural gas and oil
reserves, the estimated future gross revenue to be generated from the
production of proved reserves, net of estimated production and future
development costs, using prices and costs in effect as of the date indicated,
without giving effect to non-property related expenses such as general and
administrative expenses, debt service and future income tax expenses or to
depreciation, depletion and amortization, discounted using an annual discount
rate of 10%.

         Productive well.  A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.

         Proved developed producing reserves.  Proved developed reserves that
are expected to be recovered from completion intervals currently open in
existing wells and able to produce to market.

         Proved developed nonproducing reserves.  Proved developed reserves
expected to be recovered from zones behind casing in existing wells.

         Proved reserves.  The estimated quantities of crude oil, natural gas
and natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.

         Proved undeveloped location.  A site on which a development well can
be drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.

         Proved undeveloped reserves.  Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required from recompletion.

         Recompletion.   The completion for production of an existing well bore
in another formation from that in which the well has been previously completed.

         Reservoir.  A porous and permeable underground formation containing a
natural accumulation of producible oil and/or gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.





                                      G-2

<PAGE>   34
         Royalty interest.  An interest in a natural gas and oil property
entitling the owner to a share of oil or gas production free of costs of
production.

         Undeveloped acreage.  Lease acreage on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of natural gas and oil regardless of whether such acreage contains
proved reserves.

         Working interest.  The operating interest which gives the owner the
right to drill, produce and conduct operating activities on the property and a
share of production.

         Workover.  Operations on a producing well to restore or increase
production.





                                      G-3

<PAGE>   35
                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

         We have audited the accompanying combined balance sheets of The
Houston Exploration Company (a Delaware corporation and an indirect
wholly-owned subsidiary of The Brooklyn Union Gas Company prior to September
20, 1996) as of December 31, 1996 and 1995, and the related combined statements
of operations, stockholders' equity and cash flows for each of the three years
in the period ended December 31, 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 of The Houston
Exploration Company, as of December 31, 1996 and 1995, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1996, in conformity with generally accepted accounting principles.


                                              ARTHUR ANDERSEN LLP
                




New York, New York
January 30, 1997





                                      F-1
<PAGE>   36
                        THE HOUSTON EXPLORATION COMPANY
                            COMBINED BALANCE SHEETS
                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                                     DECEMBER 31,
                                                                                1996              1995      
                                                                           ---------------   ---------------
<S>                                                                        <C>               <C>
ASSETS:
   Cash and cash equivalents  . . . . . . . . . . . . . . . . . . . . .    $     2,851       $       598
   Accounts receivable  . . . . . . . . . . . . . . . . . . . . . . . .         35,845            18,660
   Accounts receivable -- Parent  . . . . . . . . . . . . . . . . . . .             --             6,963
   Inventories  . . . . . . . . . . . . . . . . . . . . . . . . . . . .            992               963
   Prepayments and other  . . . . . . . . . . . . . . . . . . . . . . .            924             1,141
                                                                           -----------       -----------
        Total current assets  . . . . . . . . . . . . . . . . . . . . .         40,612            28,325

   Natural gas and oil properties, full cost method
        Unevaluated properties  . . . . . . . . . . . . . . . . . . . .         60,258            42,286
        Properties subject to amortization  . . . . . . . . . . . . . .        468,062           309,378
   Other property and equipment . . . . . . . . . . . . . . . . . . . .          7,308             7,707
                                                                           -----------       -----------
                                                                               535,628           359,371
   Less:  Accumulated depreciation, depletion and amortization  . . . .       (176,504)         (142,693)
                                                                           -----------       ----------- 
                                                                               359,124           216,678
   Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . .          1,549             2,493
                                                                           -----------       -----------
        TOTAL ASSETS  . . . . . . . . . . . . . . . . . . . . . . . . .    $   401,285       $   247,496
                                                                           ===========       ===========

LIABILITIES:
   Accounts payable and accrued expenses  . . . . . . . . . . . . . . .    $    36,650       $    28,657
   Accounts payable -- Parent . . . . . . . . . . . . . . . . . . . . .          1,010                --
                                                                           -----------       -----------
        Total current liabilities . . . . . . . . . . . . . . . . . . .         37,660            28,657
   Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . .         65,000            71,862
   Deferred federal income taxes  . . . . . . . . . . . . . . . . . . .         56,475            43,681
   Other deferred liabilities . . . . . . . . . . . . . . . . . . . . .          8,850                60
                                                                           -----------       -----------
        TOTAL LIABILITIES . . . . . . . . . . . . . . . . . . . . . . .        167,985           144,260

COMMITMENTS AND CONTINGENCIES (SEE NOTE 10)
STOCKHOLDERS' EQUITY:
   Common Stock, $.01 par value, 50,000 shares authorized and 23,333
shares issued and outstanding at December 31, 1996 and 15,295
         shares issued and outstanding at December 31, 1995 . . . . . .            233               153
   Additional paid-in capital . . . . . . . . . . . . . . . . . . . . .        222,271           100,929
   Retained earnings  . . . . . . . . . . . . . . . . . . . . . . . . .         10,796             2,154
                                                                           -----------       -----------
        TOTAL STOCKHOLDERS' EQUITY  . . . . . . . . . . . . . . . . . .        233,300           103,236
                                                                           -----------       -----------

        TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY  . . . . . . . . . .    $   401,285       $   247,496
                                                                           ===========       ===========
</TABLE>





    The accompanying notes are an integral part of these combined financial
                                  statements.





                                      F-2
<PAGE>   37
                        THE HOUSTON EXPLORATION COMPANY
                       COMBINED STATEMENTS OF OPERATIONS
                     (IN THOUSANDS, EXCEPT PER SHARE DATA)


<TABLE>
<CAPTION>
                                                                              Year Ended December 31,            
                                                                        1996            1995           1994      
                                                                   -------------- --------------- -------------- 
 <S>                                                               <C>            <C>             <C>            
 REVENUES                                                                                                        
     Natural gas and oil revenues  . . . . . . . . . . . . . . .   $   64,864     $   39,431      $   41,755     
     Other   . . . . . . . . . . . . . . . . . . . . . . . . . .        1,040          1,778             467     
                                                                   ----------     ----------      ----------     
         Total revenues  . . . . . . . . . . . . . . . . . . . .       65,904         41,209          42,222     
 OPERATING COSTS AND EXPENSES                                                                                    
     Lease operating   . . . . . . . . . . . . . . . . . . . . .       12,201          5,468           5,344     
     Depreciation, depletion and amortization  . . . . . . . . .       33,732         21,969          25,365     
     General and administrative, net   . . . . . . . . . . . . .        6,249          3,486           3,460     
     Nonrecurring charge   . . . . . . . . . . . . . . . . . . .           --         12,000              --     
                                                                   ----------     ----------      ----------     
         Total operating expenses  . . . . . . . . . . . . . . .       52,182         42,923          34,169     
 INCOME (LOSS) FROM OPERATIONS . . . . . . . . . . . . . . . . .       13,722         (1,714)          8,053     
                                                                                                                 
 Interest expense, net . . . . . . . . . . . . . . . . . . . . .        2,875          2,398           2,102     
                                                                   ----------     ----------      ----------     
 Net income (loss) before income taxes . . . . . . . . . . . . .       10,847         (4,112)          5,951     
                                                                                                                 
 Provision (benefit) for federal income taxes  . . . . . . . . .        2,205         (3,809)            597     
                                                                   ----------     ----------      ----------     
 NET INCOME (LOSS) . . . . . . . . . . . . . . . . . . . . . . .   $    8,642     $     (303)     $    5,354     
                                                                   ==========     ==========      ==========     
 Net income (loss) per share . . . . . . . . . . . . . . . . . .   $     0.49     $    (0.02)     $     0.35 
                                                                   ==========     ==========      ==========     
 Weighted average shares outstanding . . . . . . . . . . . . . .       17,532         15,295          15,295     
</TABLE>





    The accompanying notes are an integral part of these combined financial
                                  statements.





                                      F-3
<PAGE>   38
                        THE HOUSTON EXPLORATION COMPANY
                   COMBINED STATEMENT OF STOCKHOLDERS' EQUITY
                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                       Additional         Retained           Total
                                                          Common         Paid in          Earnings        Stockholders'
                                                          Stock          Capital         (Deficit)           Equity      
                                                      -------------- ---------------  ---------------  ------------------
 <S>                                                    <C>            <C>               <C>               <C>         
 Balance at December 31, 1993  . . . . . . . . . . .    $   153        $   68,235        $  (2,897)        $  65,491   
 Capital contributions from Brooklyn Union . . . . .         --            18,021               --            18,021   
 Net income    . . . . . . . . . . . . . . . . . . .         --                --            5,354             5,354   
                                                        -------        ----------        ---------         ---------   
 Balance at December 31, 1994  . . . . . . . . . . .    $   153        $   86,256        $   2,457         $  88,866   
 Capital contributions from Brooklyn Union . . . . .         --            14,673(1)            --            14,673   
                                                                                                                       
 Net loss  . . . . . . . . . . . . . . . . . . . . .         --                --             (303)             (303)  
                                                        -------        ----------        ---------         ---------   
 Balance at December 31, 1995  . . . . . . . . . . .    $   153        $  100,929        $   2,154         $ 103,236   
 Capital contributions from Brooklyn Union . . . . .         --             6,342               --             6,342   
 8,037 shares of common stock at $15.50 (2)  . . . .         80           115,000               --           115,080   
 Net income  . . . . . . . . . . . . . . . . . . . .         --                --            8,642             8,642   
                                                        -------        ----------        ---------         ---------   
                                                                                                                       
 Balance at December 31, 1996  . . . . . . . . . . .    $   233        $  222,271        $  10,796         $ 233,300   
                                                        =======        ==========        =========         =========   
</TABLE>                                                                     

------------------

(1)  Includes $7.8 million related to the $12.0 million nonrecurring charge,
     net of the tax benefit of $4.2 million.

(2)  See Note 3--Stockholders' Equity





    The accompanying notes are an integral part of these combined financial
                                  statements.





                                      F-4
<PAGE>   39
                        THE HOUSTON EXPLORATION COMPANY
                       COMBINED STATEMENTS OF CASH FLOWS
                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                              YEAR ENDED DECEMBER 31,
                                                                        1996           1995            1994      
                                                                   ------------   -------------   ---------------
<S>                                                                <C>            <C>            <C>
OPERATING ACTIVITIES:
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . .  $     8,642    $      (303)   $     5,354
Adjustments to reconcile net income (loss) to net
    cash provided by operating activities:
    Depreciation, depletion and amortization  . . . . . . . . . .       33,732         21,969         25,365
    Deferred income tax expense   . . . . . . . . . . . . . . . .       11,939          9,632          5,847
    Nonrecurring charge   . . . . . . . . . . . . . . . . . . . .           --         12,000             --

    Changes in operating assets and liabilities:
    Decrease (increase) in accounts receivable  . . . . . . . . .      (10,348)           977          4,551
    Decrease (increase) in inventories  . . . . . . . . . . . . .          217            333           (229)
    Decrease (increase) in prepayments and other  . . . . . . . .          (29)           416           (450)
    Decrease (increase) in other assets and liabilities   . . . .          909            864         (1,188)
    Increase (decrease) in accounts payable
         and accrued expenses . . . . . . . . . . . . . . . . . .        9,003          9,890        (13,176)
                                                                   -----------    -----------    ----------- 

Net cash provided by operating activities . . . . . . . . . . . .       54,065         55,778         26,074
INVESTING ACTIVITIES:

Investment in property and equipment  . . . . . . . . . . . . . .     (154,125)       (70,249)       (64,996)
Dispositions and other  . . . . . . . . . . . . . . . . . . . . .        1,819          1,316            (63)
                                                                   -----------    -----------    ----------- 
Net cash used in investing activities . . . . . . . . . . . . . .     (152,306)       (68,933)       (65,059)

FINANCING ACTIVITIES:
Net proceeds (repayments) from long term borrowings . . . . . . .       (6,862)         6,212         19,050
Proceeds from issuance of common stock  . . . . . . . . . . . . .      101,014             --             --
Capital contributions from Brooklyn Union . . . . . . . . . . . .        6,342          6,873         18,021
                                                                   -----------    -----------    -----------

Net cash provided by financing activities . . . . . . . . . . . .      100,494         13,085         37,071

Increase (decrease) in cash and cash equivalents  . . . . . . . .        2,253            (70)        (1,914)
Cash and cash equivalents, beginning of period  . . . . . . . . .          598            668          2,582
                                                                   -----------    -----------    -----------

Cash and cash equivalents, end of period  . . . . . . . . . . . .  $     2,851    $       598    $       668
                                                                   ===========    ===========    ===========

Cash paid for interest  . . . . . . . . . . . . . . . . . . . . .  $     5,708    $     4,658    $     3,318
                                                                   ===========    ===========    ===========
Cash paid for taxes . . . . . . . . . . . . . . . . . . . . . . .  $        --    $        --    $        --
                                                                   ===========    ===========    ===========
</TABLE>





    The accompanying notes are an integral part of these combined financial
                                  statements.





                                      F-5
<PAGE>   40
                        THE HOUSTON EXPLORATION COMPANY
                     NOTES TO COMBINED FINANCIAL STATEMENTS



NOTE 1 ---SUMMARY OF ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES

         Organization

         The Houston Exploration Company ("Houston Exploration" or the
"Company"), a Delaware corporation, was incorporated in December 1985 and began
operations in January 1986 for the purpose of conducting certain natural gas
and oil exploration and development activities for The Brooklyn Union Gas
Company ("Brooklyn Union").  Prior to the Company's initial public offering in
September 1996 (the "IPO"), the Company was an indirect wholly-owned subsidiary
of Brooklyn Union.  The Company's operations focus on the exploration,
development and acquisition of domestic natural gas and oil properties offshore
in the Gulf of Mexico and onshore in South Texas, the Arkoma Basin, East Texas
and West Virginia.

         Effective February 29, 1996 Brooklyn Union implemented a
reorganization of its exploration and production assets and liabilities by
transferring to Houston Exploration certain onshore producing properties and
acreage formerly owned by Fuel Resources Inc. ("FRI"), another subsidiary of
Brooklyn Union.  These combined financial statements have been prepared giving
effect to the transfer of these assets and liabilities from the time of the
acquisition of such assets and liabilities by Brooklyn Union.  The transfer of
assets and liabilities has been accounted for at historical cost as a
reorganization of companies under common control in a manner similar to a
pooling-of-interests and the financial statements reflect the combined
historical results of Houston Exploration and the assets and liabilities
transferred by Brooklyn Union for all of the periods presented.

         Common Stock Conversion and Split

         The combined financial statements reflect, retroactively for all
periods presented (i) the increase in the authorized number of shares of common
and preferred stock of the Company to 50 million and five million,
respectively, and (ii) conversion and reclassification of each outstanding
share of common stock into 2.47 shares of common stock, resulting in 15,295,215
shares of common stock issued and outstanding effective immediately prior to
the completion of the IPO.  See Note 3--Stockholders' Equity.

         Net Income (Loss) Per Share

         Net income (loss) per share for each period presented was determined
by dividing net income (loss) by the weighted average number of common shares
outstanding after giving effect to the split referred to above.  As of December
31, 1996, the Company had 2,333,276 options authorized, of which 1,238,638 were
granted.  The options were not reflected as common stock equivalents as they
were antidilutive as of December 31, 1996.

         Reclassifications and Use of Estimates

         The preparation of the combined 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 dates of
the financial statements and the reported amounts of revenues and expenses
during the reporting periods. The Company's most significant financial
estimates are based on remaining proved natural gas and oil reserves.  See Note
14 -- Supplemental Information on Natural Gas and Oil Exploration, Development
and Production Activities.  Because there are numerous uncertainties inherent
in the estimation process, actual results could differ from the estimates.
Certain reclassifications for prior years have been made to conform with
current year presentation.





                                      F-6
<PAGE>   41
         Natural Gas and Oil Properties

         Natural gas and oil properties are accounted for using the full cost
method of accounting.  Under this method of accounting, all costs identified
with acquisition, exploration and development of natural gas and oil
properties, including leasehold acquisition costs, geological and geophysical
costs, dry hole costs, tangible and intangible drilling costs, interest and the
general and administrative overhead directly associated with these activities
are capitalized as incurred.  The Company computes the provision for
depreciation, depletion and amortization of natural gas and oil properties on a
quarterly basis using the unit-of-production method.  The quarterly provision
is calculated by multiplying the natural gas and oil production each quarter by
a depletion rate determined by dividing the total unamortized cost of natural
gas and oil properties (including estimates of the costs of future development
and property abandonment and excluding the cost of significant investments in
unproved and unevaluated properties) by net equivalent proved reserves at the
beginning of the quarter.  Natural gas and oil reserve quantities represent
estimates only.  Actual future production may be materially different from
estimated reserve quantities and such differences could materially affect
future amortization of natural gas and oil properties.  The Company believes
that unevaluated properties at December 31, 1996 will be fully evaluated within
five years.

         Proceeds from the dispositions of natural gas and oil properties are
recorded as reductions of capitalized costs, with no gain or loss recognized,
unless such adjustments significantly alter the relationship of unamortized
capitalized costs and total proved reserves.

         The Company limits the capitalized costs of natural gas and oil
properties, net of accumulated depreciation, depletion and amortization and
related deferred taxes to the estimated future net cash flows from proved
natural gas and oil reserves discounted at ten percent, plus the lower of cost
or fair value of unproved properties, as adjusted for related income tax
effects (the "full cost ceiling").  A current period charge to operating income
is required to the extent that capitalized costs plus certain estimated costs
for future property development, plugging, abandonment and site restorations,
net of related accumulated depreciation, depletion and amortization and related
deferred income taxes, exceed the full cost ceiling.

         Other Property and Equipment

         Other property and equipment include the costs of West Virginia
gathering facilities which are depreciated using the unit-of-production basis
utilizing estimated proved reserves accessible to the facilities.  Also
included in other property and equipment are costs of office furniture,
fixtures and equipment which are recorded at cost and depreciated using the
straight-line method over estimated useful lives ranging between two to five
years.

         Income Taxes

         Deferred taxes are determined based on the estimated future tax effect
of differences between the financial statement and tax basis of assets and
liabilities given the provisions of enacted tax laws.  These differences relate
primarily to (i) intangible drilling and development costs associated with
natural gas and oil properties, which are capitalized and amortized for
financial reporting purposes and expensed as incurred for tax reporting
purposes and (ii) provisions for depreciation and amortization for financial
reporting purposes that differ from those used for income tax reporting
purposes.

         Prior to September 30, 1996, the Company was included in the
consolidated federal income tax return of Brooklyn Union.  Under the Company's
tax sharing agreement with Brooklyn Union, the Company received or paid to
Brooklyn Union an amount equal to the reduction or increase in the currently
payable federal income taxes for Brooklyn Union resulting from the inclusion of
the Company's taxable income or loss in the consolidated Brooklyn Union return,
whether or not such amounts could be utilized on a separate return basis.  For
periods subsequent to September 1996, the Company calculates and pays taxes on
a separate return basis.





                                      F-7
<PAGE>   42
         Cash and Cash Equivalents

          The Company considers all highly liquid investments with an original
maturity of three months or less to be cash equivalents.

         Inventories

         Inventories consist primarily of tubular goods used in the Company's
operations and are stated at the lower of cost or market value.

         General and Administrative Costs and Expenses

         The Company receives reimbursement for administrative and overhead
expenses incurred on behalf of other working interest owners of properties
operated by the Company.  These reimbursements totaling $1.0 million, $1.2
million and $1.3 million for the years ended December 31, 1996, 1995 and 1994,
respectively, were allocated as reductions to general and administrative
expenses.  The capitalized general and administrative costs directly related to
the Company's acquisition, exploration and development activities, during 1996,
1995 and 1994, aggregated $5.3 million, $4.1 million and $3.9 million,
respectively.

         Capitalization of Interest

         The Company capitalizes interest related to its unevaluated natural
gas and oil properties and certain properties under development which are not
currently being amortized.  For the years ended December 31, 1996, 1995 and
1994 interest costs of $3.5 million, $2.9 million and $1.5 million,
respectively, were capitalized.

         Gas Imbalances

         The Company utilizes the entitlements method to account for its gas
imbalances.  Under this method, income is recorded based on the Company's net
revenue interest in production or nominated deliveries.  Net deliveries in
excess of these amounts are recorded as liabilities, while net under deliveries
are reflected as assets.  Production imbalances are valued using current market
prices.  Production imbalances were not material as of December 31, 1996 and
1995.

         Hedging

         The Company enters into natural gas futures and forward contracts in
the normal course of business.  Principally, these contracts are used to hedge
against the risk of adverse impacts of market price fluctuations of natural
gas.  The Company's hedging strategies meet the criteria for hedge accounting
treatment under Statement of Financial Accounting Standards No.  80,
"Accounting for Futures Contracts" ("SFAS 80").  Accordingly, gains and losses
are recognized when the underlying transaction is completed, at which time
these gains and losses are included in earnings as a component of natural gas
revenues in accordance with a hedged transaction.  Natural gas revenues were
reduced by $11.1 million and $0.8 million during 1996 and 1994 and were
increased by $5.6 million in 1995, relative to these contracts.  See Note
8--Financial Instruments.

         The Company regularly assesses the relationship between natural gas
commodity prices in the "cash" and futures markets.  The correlation between
prices in these markets has been well within a range generally deemed to be
acceptable.  If correlation ceases to exist for more than a temporary period of
time, the Company accounts for its financial instrument positions as trading
activities and marks-to-market its open positions.

         The Company also uses interest rate swaps to manage the interest rate
exposure arising from certain borrowings.  Swaps used to hedge debt are
designated as hedges and are matched to the debt as to notional amount and
maturity.  The periodic receipts or payments from each swap are recognized
ratably over the term of the swap as an adjustment to interest expense.  Gains
and losses resulting from the termination of hedge contracts prior to their
stated maturity are recognized ratably over the remaining life of the
instrument being hedged.





                                      F-8
<PAGE>   43
         Concentration of Credit Risk

         Substantially all of the Company's accounts receivable result from
natural gas and oil sales or joint interest billings to third parties in the
oil and gas industry.  This concentration of customers and joint interest
owners may impact the Company's overall credit risk in that these entities may
be similarly affected by changes in economic and other conditions.
Historically the Company has not experienced credit losses on such receivables.

         New Accounting Pronouncements

         In October 1995, the Financial Accounting Standards Board issued
("SFAS") No. 123, "Accounting for Stock-Based Compensation," which is effective
for years beginning after December 15, 1995.  This statement encourages, but
does not require companies to record compensation expense for stock-based
compensation at fair value.  The Company has chosen to continue to account for
stock-based compensation using the intrinsic value method prescribed in
Accounting Principles Board Opinion ("APB") No. 25, "Accounting for Stock
Issued to Employees," and related Interpretations.  Under APB No.  25,
compensation expense is measured as the excess, if any, of the fair market
value of the Company's stock at the date of grant over the price at which the
option was granted.  Compensation expense for phantom stock rights is recorded
annually based on the quoted market price of the Company's stock at the end of
the period.  See Note 4--Incentive Stock Option Plans.

NOTE 2--LONG-TERM DEBT

         Prior Credit Facility. The Company maintained a revolving credit
facility ("Prior Credit Facility") with a syndicate of lenders which provided
for an aggregate commitment of $100 million, subject to borrowing base
limitations of $76 million as of December 31, 1995.  The Prior Credit Facility
limited advances to a borrowing base established by a specified formula and was
redetermined by the bank at least semi-annually.  At December 31, 1995, $71.9
million was outstanding under the Prior Credit Facility, and letter of credit
obligations of $1.6 million were outstanding.  Borrowings under the Prior
Credit Facility were secured by the stock of the Company.

         The Prior Credit Facility provided for payments of interest only until
the scheduled maturity on October 1, 1998.  The Company elected to borrow funds
at either (i) a fluctuating base rate ("Base Rate" loan) equal to the higher of
the Federal Funds rate plus  1/2% or the agent bank's prime rate, or (ii) a
fixed rate ("Fixed Rate" loan) at either (at the Company's option) a market
Eurodollar rate or an average market Certificate of Deposit ("CD") rate.
Interest was payable at calendar quarter end on Base Rate loans and at maturity
of the financial instrument (approximately every 90 days) for Fixed Rate loans.
In addition, the Prior Credit Facility required quarterly payments of a
commitment fee of (i) three-eighths of one percent per annum of the daily
average unused portion of the borrowing base and (ii) one-sixteenth of one
percent per annum of the daily average difference between the commitment and
the borrowing base and (iii) one-eighth of one percent per annum of the daily
average difference between the borrowing base and the "Accepted Borrowing Base"
as defined in the Agreement.  The weighted average interest rate for the
periods ended December 31, 1995 and 1994 was 6.9% and 7.4%, respectively.

         Interim Credit Facility.  On April 23, 1996, the Company revised the
terms and conditions of the existing Credit Facility ("Interim Credit
Facility").  The Interim Credit Facility was provided by a syndicate of lenders
led by the Company's prior agent, Texas Commerce Bank National Association,
again as agent, and provided an aggregate commitment of $150 million, subject
to borrowing base limitations of $80 million as of April 23, 1996.  In
addition, up to $5 million of the Interim Credit Facility was available for the
issuance of letters of credit to support performance guarantees.  The Interim
Credit Facility was guaranteed by FRI and by THEC Holdings Corp., each of which
is a wholly-owned subsidiary of Brooklyn Union.  Borrowings were secured by the
stock of the Company and the stock of FRI together with a negative pledge on
all the Company's assets.

         Interest was payable on borrowings under the Interim Credit Facility
at an alternate base rate of the greater of the Federal Funds rate plus 0.5% or
the agent bank's prime rate or, at the Company's election, 0.8125% above a
quoted LIBOR rate.  Interest was payable at calendar quarters on base rate
loans and at maturity on LIBOR loans.  In addition a commitment fee of: (i)
between 0.20% and 0.375% per annum on the unused portion of the Accepted
Borrowing Base,





                                      F-9
<PAGE>   44
(ii) 0.125% per annum on the difference between the Borrowing Base and the
Accepted Borrowing Base with a 0.3125% charge on any usage of the difference,
and (iii) 0.0625% per annum on the difference between the lower of the Facility
Amount and the Borrowing Base.

         The Interim Credit Facility required the maintenance of a defined net
worth, total debt to total capitalization of no greater than 50% and a defined
fixed charge coverage ratio of 2.0 to 1.  In addition to maintenance of certain
financial ratios, cash dividends and/or purchase or redemption of the Company's
stock was restricted as well as the encumbering of the Company's gas and oil
assets or pledging of the assets as collateral.

         New Credit Facility.  On July 2, 1996, the Company revised the terms
and conditions of the existing Interim Credit Facility ("Credit Facility").
The Credit Facility is provided by the Company's prior agent, Texas Commerce
Bank, National Association and provides an aggregate commitment of $150
million, the full amount of which was available as of December 31, 1996.  In
addition, up to $5 million of the Credit Facility is available for the issuance
of letters of credit to support performance guarantees.  The Credit Facility
matures on July 1, 2000.  The Credit Facility is unsecured.  At December 31,
1996 $65.0 million was outstanding under the Credit Facility and there were no
outstanding letter of credit obligations.

         Interest is payable on borrowings under the Credit Facility, at the
Company's option, at an alternate base rate of the greater of the Federal Funds
rate plus 0.5% or the agent bank's prime rate or at a margin of 0.50% to 1.125%
above a quoted LIBOR rate.  Interest is payable at calendar quarters on base
rate loans and at maturity on LIBOR loans.  In addition, a commitment fee of:
(i) between 0.20% and 0.375% per annum on the unused portion of the Designated
Borrowing Base, and (ii) 33% of the fee in (i) above on the difference between
the lower of the Facility Amount or the Borrowing Base and the Designated
Borrowing Base.  The weighted average interest rate was 6.25% for 1996.

         The Credit Facility covenants require the maintenance of a defined net
worth of $181 million and total capitalization of no greater than 60% prior to
the IPO and 55% thereafter.  In addition to maintenance of certain financial
ratios, cash dividends and/or purchase or redemption of the Company's stock is
restricted as well as the encumbering of the Company's gas and oil assets or
the pledging of the assets as collateral.  As of December 31, 1996, the Company
was in compliance with all such covenants.

NOTE 3--STOCKHOLDERS' EQUITY

         On September 19, 1996, the Company entered into an underwriting
agreement with respect to the Company's IPO of its common stock at a price of
$15.50 per share.  The initial closing of the IPO, in which the Company issued
6,200,000 shares of common stock, was completed on September 25, 1996.  The
underwriters delivered notice of the exercise of their over-allotment option on
September 30, 1996.  The closing of the over-allotment, in which the Company
issued an additional 930,000 shares of common stock, was completed on October
3, 1996.  The Company received net proceeds of approximately $101.0 million
from the total of 7,130,000 shares sold in the IPO.

         Concurrently with the completion of the IPO, the Company's President
exchanged certain of his after program- payout working interests valued at $2.3
million for 145,161 shares of common stock.  In addition, concurrently with the
completion of the IPO, the Company issued 762,387 shares of common stock valued
at $11.8 million to Soxco in connection with the Soxco Acquisition.  See Note
12--Acquisitions.

         In connection with the IPO, the Company's certificate of incorporation
was amended to effect an increase in the authorized capital stock of the
Company to 50 million shares of common stock, par value $.01 per share, and
five million shares of preferred stock, par value $.01 per share.
Additionally, the Company effected a forward stock split, effective prior to
the completion of the IPO, increasing the number of shares of common stock
issued and outstanding to 15,295,215.  The financial statements reflect,
retroactively for all periods presented, the conversion and reclassification of
the Company's common stock pursuant to the split.





                                      F-10
<PAGE>   45
NOTE 4--INCENTIVE STOCK OPTION PLANS

         1994 Incentive Plan

         On July 1, 1994, the Company adopted the Long-Term Stock Incentive
Plan (the "1994 Incentive Plan"), and granted options to purchase 247,000
shares of common stock at $11.22 per share to certain officers and directors of
Brooklyn Union. Options under the 1994 Incentive Plan were nonqualified and had
tandem phantom option shares that gave the option holder the right to receive a
cash payment five years from the grant date provided the Company was a
privately held entity.  At completion of the Company's IPO on September 20,
1996, all options under the 1994 Incentive Plan were canceled in exchange for a
cash payment by the Company of  $840,000.  The Company recorded the $840,000
charge as compensation expense.

         1996 Incentive Plan

         At the completion of the IPO, the Company adopted the 1996 Stock
Option Plan (the "1996 Incentive Plan"), which allows the Company to grant
options not to exceed 10% of the shares of the Company's common stock
outstanding from time to time.  On September 20, 1996, the Company authorized
2,333,276 options and subsequently granted 1,238,638 options at a weighted
average exercise price of $15.53 per share.  The options granted under the 1996
Incentive Plan expire 10 years from the grant date and vest in one-fifth
increments on each of the first five anniversaries of the grant date.  As of
December 31, 1996, no options were exercisable.

         Under the 1996 Incentive Plan, 281,303 of the options granted are
incentive stock options ("ISOs") and the balance, 957,335 are nonqualified
stock options ("NQSOs").  Common stock issued through the exercise of
nonqualified options will result in a tax deduction for the Company equivalent
to the taxable gain recognized by the optionee.  Generally, the Company will
not receive an income tax deduction for ISOs.

         The following is a summary of option activity during the years ended
December 31, 1996, 1995 and 1994:

<TABLE>
<CAPTION>
                                                               Year Ended December 31,                           
                                    -----------------------------------------------------------------------------
                                               1996                       1995                     1994          
                                    --------------------------- ------------------------- -----------------------
                                        Shares        Price*       Shares       Price*      Shares      Price*   
                                    -------------- ------------ ------------ ------------ ---------- ------------
<S>                                 <C>            <C>             <C>       <C>            <C>      <C>
Options at beginning of year  .         247,000    $    11.22      247,000   $     11.22         --
    Granted . . . . . . . . . . .     1,238,638         15.53           --                  247,000  $    11.22
    Canceled  . . . . . . . . . .      (247,000)        11.22           --                       --
                                    -----------                 ----------                ---------
Outstanding at end of year  . . .     1,238,638    $    15.53      247,000   $     11.22    247,000  $    11.22
                                    ===========                 ==========                  =======            

Exercisable at end of year  . . .            --                    247,000   $     11.22    247,000  $    11.22

Options available for grant . . .     1,094,638                         --                       --

Weighted average fair value of
    options granted . . . . . . .   $      7.17
</TABLE>

--------------

*  Weighted average exercise price for the year.

         Phantom Stock Rights

         On December 16, 1996, the Company granted key employees of Houston
Exploration 176,470 phantom stock rights ("PSRs") that give the holder the
right to receive a cash payment determined by reference to the fair market
value of one share of the Company's common stock.  Twenty percent (20%) of the
PSRs are payable on December 16th of each of the years 1997 through 2001.   On
each date on which a PSR is payable, the holder will receive a cash payment





                                     F-11
<PAGE>   46
equal to (i) the average of the closing prices per share of the Company's
common stock for the five trading days immediately preceding such payment date
multiplied by (ii) the number of PSRs payable on such date.

         Fair Value of Employee Stock-Based Compensation

         The Company accounts for the Incentive Stock Plans using the intrinsic
value method prescribed under APB No. 25 and accordingly no compensation
expense has been recognized for stock options granted.  Had stock options been
accounted for using the fair value method as recommended in SFAS No. 123,
compensation expense would have had the following pro forma effect on the
Company's net income and earnings per share for the years ended December 31,
1996 and 1995:

<TABLE>
<CAPTION>
                                                               1996                 1995         
                                                        ------------------- ---------------------
                                                          (in thousands, except per share data)
              <S>                                       <C>                 <C>
              Net income (loss) - as reported . . . .   $     8,642         $       (303)
              Net income (loss) - pro forma . . . . .         8,268                 (303)
              Net income (loss) per share - as          $      0.49         $      (0.02)
              reported  . . . . . . . . . . . . . . .
              Net income (loss) per share - pro forma          0.47                (0.02)
</TABLE>

         The effects of applying SFAS No. 123 in this pro forma disclosure are
not indicative of future amounts.  SFAS No. 123 does not apply to awards prior
to 1995.  The fair value of each option grant is estimated on the date of grant
using the Black-Scholes option pricing model with the following assumptions
used for grants in 1996: (i) risk-free interest rate of 6.66%; (ii) expected
lives of 5 years; (iii) expected dividends of zero; and (iv) expected
volatility of 41%.

NOTE 5--INCOME TAXES

         The components of the federal income tax provision (benefit) are:

<TABLE>
<CAPTION>
                                                           1996             1995            1994    
                                                      ---------------  -------------   -------------
                                                                      (in thousands)
              <S>                                     <C>              <C>             <C>
              Current . . . . . . . . . . . . . . .   $    (9,734)     $    (13,441)   $     (5,250)
              Deferred  . . . . . . . . . . . . . .        11,939             9,632           5,847
                                                      -----------      ------------    ------------
              Total . . . . . . . . . . . . . . . .   $     2,205      $     (3,809)   $        597
                                                      ===========      ============    ============
</TABLE>

         Amounts received from Brooklyn Union pursuant to the previous
tax-sharing agreement were $13.7 million, $14.6 million and $2.3 million in
1996, 1995 and 1994, respectively.

         The following is a reconciliation of statutory federal income tax
expense (benefit) to the Company's income tax provision:

<TABLE>
<CAPTION>
                                                             1996            1995            1994    
                                                        --------------  -------------   -------------
                                                                        (in thousands)
              <S>                                       <C>             <C>             <C>
              Income (loss) before income taxes . . .       10,847      $    (4,112)    $     5,951
              Statutory rate  . . . . . . . . . . . .          35%              35%             35%
              Income tax expense (benefit) computed          3,796           (1,439)          2,083
              at statutory rate . . . . . . . . . . .
              Reconciling items:
                 Section 29 tax credits . . . . . . .       (1,401)          (1,985)         (1,529)
                 Percentage depletion . . . . . . . .          (33)            (231)            (27)
                 Other  . . . . . . . . . . . . . . .         (157)            (154)             70
                                                        ----------      -----------     -----------
              Tax expense (benefit) . . . . . . . . .   $    2,205      $    (3,809)    $       597
                                                        ==========      ===========     ===========
</TABLE>





                                      F-12
<PAGE>   47
Deferred Income Taxes

         The components of deferred tax assets and liabilities pursuant to SFAS
No. 109 for the years ended December 31, 1996 and 1995 primarily represent
temporary differences related to natural gas and oil properties.

NOTE 6--RELATED PARTY TRANSACTIONS

         Transactions with Brooklyn Union are comprised of the following:

<TABLE>
<CAPTION>
                                                             1996            1995            1994    
                                                        --------------  -------------   -------------
                                                                        (in thousands)
              <S>                                          <C>          <C>             <C>
              Gas sales . . . . . . . . . . . . . . .      $     --     $        --     $     1,335
              Gathering fee income  . . . . . . . . .            --              --             244
              General and administrative costs  . . .           644             724             776
</TABLE>

         Gas sales with Brooklyn Union were at market prices, based upon an
index price adjusted to reflect the point of delivery of such production.  The
Company believes that the prices at which it sold gas to Brooklyn Union were
similar to those it would have been able to obtain in the open market.  The
Company reimburses Brooklyn Union for certain general and administrative costs.

         Gas Sales

         The Company entered into a term supply agreement with BRING Gas
Services Corp. ("BRING"), an affiliate of Brooklyn Union, in 1992.  As of April
1, 1995, this contract was superseded when the Company entered into a term
supply agreement with PennUnion Energy Services, L.L.C.  ("PennUnion"),
successor to BRING and an affiliate of Brooklyn Union.  This contract was
terminated in October 1996 with Brooklyn Union's sale of its interest in
PennUnion.  Under the terms of the agreement, the Company agreed to sell and
PennUnion agreed to buy a substantial portion of the Company's production at
index-related prices.  The agreement contained provisions for both the
commitment of gas reserves subsequently developed or acquired by the Company
and the release of gas reserves sold, traded or exchanged to third parties.

         For the years ended December 31, 1996, 1995 and 1994, the Company had
natural gas sales of $26.7 million, $18.9 million and $26.4 million,
respectively, to PennUnion and BRING.

         Employment Contracts

         Prior to the IPO the Company maintained an employment agreement with
its President and Chief Executive Officer which provided him with the option to
participate in up to a 5% working interest in certain prospects of the Company.
During 1996, 1995 and 1994, affiliates of the Company's President obtained a 5%
working interest in 154 wells (which includes 142 Charco wells) operated by the
Company pursuant to such agreement.  In addition, during 1996, 1995 and 1994,
affiliates of the Company's President paid $1.4 million, $0.7 million and $0.7
million, respectively, in expenses attributable to working interests owned in
properties operated by the Company, and received $1.6 million, $0.9 million and
$1.6 million, respectively, in distributions attributable to such working
interests.  See Note 12--Acquisitions.

         The employment agreement also provided for the assignment to the
President of a 2% net profits interest in all prospects of the Company and a
6.75% after program-payout working interest.  In addition, the employment
agreement provided for the assignment to certain key employees designated by
the President of an overriding royalty interest equivalent in the aggregate to
a four percent net revenue interest in certain properties acquired by the
Company.  Assignments were made in twelve wells during 1995 and 1994; no
assignments were made in 1996.  Upon completion of the IPO, the President's
employment agreement was terminated and replaced with a new employment
agreement, which does not provide the President with the option to participate
in prospects of the Company or to receive or grant





                                      F-13
<PAGE>   48
assignments or after program-payout working interests.  In addition to the
Company's President, certain other key employees of the Company entered into
employment agreements upon completion of the IPO.

NOTE 7--EMPLOYEE BENEFIT PLANS

         401(k) Profit Sharing Plan

         The Company maintains a 401(k) Profit Sharing Plan (the "401(k) Plan")
for its employees.  Under the 401(k) Plan, eligible employees may elect to have
the Company contribute on their behalf up to 10% of their base compensation
(subject to certain limitations imposed under the Internal Revenue Code of
1986, as amended) on a before tax basis.  The Company makes a matching
contribution of $0.50 for each $1.00 of employee deferral, not to exceed 5% of
an employee's base compensation, subject to limitations imposed by the Internal
Revenue Service.  The amounts contributed under the 401(k) Plan are held in a
trust and invested among various investment funds in accordance with the
directions of each participant.  An employee's salary deferral contributions
under the 401(k) Plan are 100% vested.  The Company' matching contributions
vest at the rate of 20% per year of service.  Participants are entitled to
payment of their vested account balances upon termination of employment.  For
the years ended December 31, 1996, 1995 and 1994, Company contributions to the
401(k) Plan were $158,000, $157,000 and $145,000, respectively.

         Supplemental Executive Plan

         Effective immediately prior to the IPO, the Company adopted an
unfunded, nonqualified Supplemental Executive Retirement Plan (the "SERP") for
the benefit of Mr. Floyd.  The SERP will provide that, if the executive remains
with the Company until age 65, upon his retirement on or after age 65, the
executive will be paid $100,000 per year for life.  If, after retirement, the
executive predeceases his spouse, 50% of the executive's SERP benefit will
continue to be paid to the executive's surviving spouse for her life.  There
were no accruals made in 1996 related to the SERP as amounts were considered de
minimus.

NOTE 8--FINANCIAL INSTRUMENTS

<TABLE>
<CAPTION>
                                                                          December 31,                       
                                                  -----------------------------------------------------------
                                                             1996                           1995             
                                                  --------------------------   ------------------------------
                                                    Carrying      Estimated       Carrying        Estimated
                                                     Amount      Fair Value        Amount         Fair Value 
                                                  -----------   ------------   --------------   -------------
                                                                         (in thousands)
 <S>                                              <C>           <C>            <C>              <C>
 Cash and cash equivalents . . . . . . . . . .    $  2,851      $   2,851      $      598       $      598
 Long-term debt  . . . . . . . . . . . . . . .      65,000         65,000          71,862           71,862
 Derivative transactions:
    Interest rate swap agreements:
         In a payable position . . . . . . . .          --           (171)             --              (86)
 Commodity price and basis swaps:
    In a payable position  . . . . . . . . . .          --        (30,286)           (704)          (3,982)
 Commodity futures:
    In a payable position  . . . . . . . . . .          --             --              --             (240)
</TABLE>

         Cash and Cash Equivalents

         The carrying amount approximates fair value due to the short maturity
of these instruments.

         Long-Term Debt

         The carrying amount of borrowings outstanding under the Credit
Facility approximates fair value as the interest rate is tied to current market
rates.





                                      F-14
<PAGE>   49
DERIVATIVE TRANSACTIONS

         Interest Rate Swap Agreements

         The fair values are obtained from the financial institutions that are
counterparties to the transactions.  These values represent the estimated
amount the Company would pay or receive to terminate the agreements, taking
into consideration current interest rates and the current creditworthiness of
the counterparties.  The Company's interest rate swap agreements are off
balance sheet transactions and, accordingly, no respective carrying amounts for
these transactions are included in the accompanying combined balance sheets at
December 31, 1996.  At December 31, 1996, the Company had two interest rate
swap agreements to exchange an aggregate notional principal of $39.0 million
over various periods from November 1996 through November 1999 at rates between
5.66% and 6.025%.

         Commodity Related Transactions

         The Company uses derivative financial instruments for non-trading
purposes as a hedging strategy to reduce the impact of market volatility and to
ensure cash flows.  Gains and losses on these hedging transactions are recorded
when the related natural gas production has been produced or delivered.  While
derivative financial instruments are intended to reduce the Company's exposure
to declines in the market price of natural gas, the derivative financial
instruments may limit the Company's gain from increases in the market price.

         The derivative instruments used to hedge commodity transactions have
historically had high correlation with commodity prices and are expected to
continue to do so.  The correlation of indices and prices is regularly
evaluated to ensure that the instruments continue to be effective hedges.  In
the event that correlation falls below allowable levels, the gains or losses
associated with the hedging instruments are immediately recognized to the
extent that correlation was lost.  In December of 1995, the Company recognized
a pretax loss of $0.7 million due to the loss of correlation of the New York
Mercantile Exchange ("NYMEX") futures market for natural gas with the market
price for natural gas in certain parts of the country.  The Company's hedges in
place at December 31, 1996 did not experience loss of market correlation.

         Commodity Price Swaps

         Price swap agreements call for one party to make monthly payments to
(or receive from) another party based upon the differential between a fixed and
a variable price (fixed-price swap) or two variable prices (basis swap) for a
notional volume specified by the contract.  The fair value is the estimated
amount the Company would receive or pay to terminate swap agreements at
year-end, taking into account the difference between NYMEX natural gas prices
or index prices at year-end and fixed swap prices.  NYMEX natural gas price
closed at $3.61 per Mmbtu and $2.14 per Mmbtu at December 31, 1996 and 1995,
respectively.  At December 31, 1996 and 1995, the Company had fixed-price swap
agreements and basis swap agreements to exchange a total notional volume of
23,278 MMmbtu and 38,135 MMmbtu, respectively, of natural gas over the period
January 1996 through March 1998.

         Commodity Futures

         Natural gas futures contracts and options on natural gas futures
contracts are traded on the NYMEX.  Contracts are for fixed units of 10,000
MMBtu.  The Company uses futures contracts to lock in the price for a portion
of its expected future natural gas production when it believes that prices are
at acceptable levels.  At December 31, 1996, the Company had no futures
contracts.  At December 31, 1995, the Company had a total of 420 net contracts
open (1,650 long and 2,070 short futures contracts).  The fair value is the
estimated amount the Company would receive or pay to close the futures
contracts at year-end, taking into account the difference between the NYMEX
natural gas prices at year-end and the fixed futures price.

         The Company is exposed to credit risk in the event of nonperformance
by counterparties to futures and swaps contracts.  The Company believes that
the credit risk related to the futures and swap contracts is no greater than
that





                                      F-15
<PAGE>   50
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.

NOTE 9--SALES TO MAJOR CUSTOMERS

         As is the nature of the exploration, development and production
business, production is normally sold to relatively few customers.  However,
alternate buyers are available to replace the loss of any of the Company's
major customers.  For the year ended December 31, 1996, the Company sold
natural gas production representing more than 10% of its total revenues to
PennUnion (40%) and H&N Gas Ltd. (27%).  For years ended December 31, 1995 and
1994, PennUnion and BRING were the only customers for which natural gas sales
exceeded 10% of total revenues.  During 1995 and 1994, sales to PennUnion and
BRING comprised 46% and 63%, respectively, of total revenues.  See Note
6--Related Party Transactions.  The Company believes that prices at which it
sells and has sold gas to PennUnion and BRING are similar to those it would be
able to obtain in the open market, and that the loss of PennUnion as a
purchaser would not have a material adverse effect on the Company's operations.

NOTE 10--COMMITMENTS AND CONTINGENCIES

         Litigation

         The Company is involved from time to time in various claims and
lawsuits incidental to its business.  In the opinion of management, the
ultimate liability thereunder, if any, will not have a material adverse effect
on the financial position or results of operations of the Company.

         Leases

         The Company has entered into certain noncancelable operating lease
agreements relative to office space and equipment with various expiration dates
through 2001.  Minimum rental commitments under the terms of the leases are as
follows:
<TABLE>
<CAPTION>
                                                                                                 Net
                                                    Minimum                                    Minimum
                                                     Rental               Sublease              Rental
                                                  Commitments             Rentals            Commitments    
                                              ---------------       -------------------      ---------------
                                                                      (in thousands)
         <S>                                  <C>                   <C>                   <C>
         1997  . . . . . . . . . . . . . .            427                   (244)                 183
         1998  . . . . . . . . . . . . . .            351                   (246)                 105
         1999  . . . . . . . . . . . . . .            357                   (250)                 107
         2000  . . . . . . . . . . . . . .            360                   (252)                 108
         2001  . . . . . . . . . . . . . .            171                   (135)                  36
                                              -----------           ------------          -----------
         Thereafter  . . . . . . . . . . .    $     1,666           $     (1,127)         $       539
                                              ===========           ============          -----------
</TABLE>


         Net rental expense related to these leases was $0.3 million for each
of the years ended December 31, 1996, 1995 and 1994.

NOTE 11--NONRECURRING CHARGE

         In connection with the February 1996 reorganization in which Brooklyn
Union transferred certain onshore producing properties and acreage to the
Company, certain former employees of FRI, the subsidiary of Brooklyn Union that
previously owned the onshore properties, were entitled to remuneration for the
increase in the value of the transferred properties prior to the
reorganization.  The Company incurred a $12 million non-cash charge in the
quarter ended December 31, 1995 with respect to the remuneration to which such
employees of FRI were entitled.  In February 1996, certain such former
employees filed suit against Brooklyn Union, FRI and the Company alleging
breach of contract, breach of fiduciary duty, fraud, negligent
misrepresentation and conspiracy, seeking actual damages in excess





                                     F-16
<PAGE>   51
of $35 million and punitive damages in excess of $70 million.  The suit was
settled in October 1996 without liability to the Company.

NOTE 12--ACQUISITIONS

         TransTexas

         On July 2, 1996, the Company acquired certain natural gas and oil
properties and associated gathering pipelines and equipment located in Zapata
County, Texas (the "TransTexas Acquisition") from TransTexas Gas Corporation
and TransTexas Transmission Corporation (together, "TransTexas").  The Company
acquired a 100% working interest (95% after the exercise by James G. Floyd, the
Company's President and Chief Executive Officer, of his right to purchase a 5%
working interest) in the approximately 142 wells on such properties.  The
purchase price of $62.2 million ($59.1 million after giving effect to the
exercise of Mr. Floyd's purchase option) for the TransTexas Acquisition was
reduced by $3.1 million for production revenue and expenses related to the
assets between the May 1, 1996 effective date of the TransTexas Acquisition and
July 2, 1996.  The purchase price of the TransTexas Acquisition was paid in
cash, financed with borrowings under the Company's Credit Facility.

         The Company loaned Mr. Floyd the $3.1 million purchase price for his
purchase of a 5% working interest in the properties purchased by the Company in
the TransTexas Acquisition.  In addition, the Company has agreed to loan Mr.
Floyd, on a revolving basis, the amounts required to fund the expenses
attributable to Mr. Floyd's working interest.  Mr. Floyd is required to repay
amounts owed under the loan in the amount of 65% of all distributions received
by Mr. Floyd in respect of such working interest, as distributions are
received.  Amounts outstanding under such loan bear interest at an interest
rate equal to the Company's cost of borrowing under the Credit Facility.  Mr.
Floyd's obligations under the agreement are secured by a pledge of his working
interest in, and the production from, such properties.  As of December 31,
1996, the outstanding balance owed by Mr. Floyd under the agreement was $2.9
million and the loan will mature on July 2, 2006.

         Soxco

         On September 25, 1996, the Company acquired  substantially all of the
natural gas and oil properties and related assets (the "Soxco Acquisition") of
Smith Offshore Exploration Company ("Soxco").  The natural gas and oil
properties acquired in the Soxco Acquisition consisted solely of working
interests in properties located in the Gulf of Mexico that are operated by the
Company or in which the Company also has a working interest.  Pursuant to the
Soxco Acquisition, the Company paid Soxco cash in the aggregate amount of $20.3
million (net of $3.4 million for certain purchase price adjustments), and
issued to Soxco 762,387 shares of common stock with an aggregate value
(determined by reference to the IPO price) of  $11.8 million.  The cash portion
of the purchase price was funded with the proceeds of the IPO.  In addition to
the foregoing, the Company will pay Soxco a deferred purchase price of up to
$17.6 million payable January 31, 1998.  The amount of the deferred purchase
price will be determined by the probable reserves of Soxco as of December 31,
1995 (approximately 17.6 Bcfe) that are produced prior to or classified as
proved as of December 31, 1996 and December 31, 1997, respectively, provided
that Soxco is entitled to receive a minimum deferred purchase price of
approximately $8.8 million.  The amounts so determined will be paid in shares
of common stock based on the fair market value of such stock at the time of
issuance.





                                     F-17
<PAGE>   52
NOTE 13--PRO FORMA COMBINED FINANCIAL INFORMATION (UNAUDITED)

         The unaudited pro forma information for the years ended December 31,
1996 and 1995 gives effect to the TransTexas Acquisition, the Soxco Acquisition
and the application of the net proceeds from the IPO as if such transactions
had been completed as of January 1, 1995.  See Note 3--Stockholders' Equity and
Note 12--Acquisitions.

         The historical results of operations have been adjusted to reflect (i)
an increase in natural gas and oil revenues, lease operating expense and
depreciation, depletion and amortization attributed to the acquired properties,
(ii) a reduction in interest expense giving effect to the use of proceeds from
the IPO to pay down long-term debt, and (iii) an increase in income taxes as a
result of the above.

         The pro forma combined financial information does not purport to be
indicative of the results of operations of the Company had such transactions
occurred on the date assumed, nor is the pro forma combined information
necessarily indicative of the future results of operations of the Company.  The
pro forma combined financial information should be read together with the
Combined Financial Statements of the Company, including the Notes thereto.


<TABLE>
<CAPTION>
                                                                                            Year Ended December 31,
                                                                                       ---------------------------
                                                                                          1996              1995
                                                                                       -----------       ---------
                                                                                                (in thousands)
 <S>                                                                                   <C>               <C>
 REVENUES
    Natural gas and oil revenues . . . . . . . . . . . . . . . . . . . . . . . . .     $    87,605       $   75,263
    Other  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .           1,040            1,778
                                                                                       -----------       ----------
       Total revenues  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          88,645           77,041
 OPERATING COSTS AND EXPENSES
    Lease operating expense  . . . . . . . . . . . . . . . . . . . . . . . . . . .          16,053           11,580
    Depreciation, depletion and amortization . . . . . . . . . . . . . . . . . . .          43,903           45,859
    General and administrative, net  . . . . . . . . . . . . . . . . . . . . . . .           6,390            3,701
    Nonrecurring reorganization charge . . . . . . . . . . . . . . . . . . . . . .              --           12,000
                                                                                       -----------       ----------

       Total operating expenses  . . . . . . . . . . . . . . . . . . . . . . . . .          66,346           73,140
 INCOME FROM OPERATIONS  . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          22,299            3,901
 Interest expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .           1,563            1,751
                                                                                       -----------       ----------
 Net income before income taxes  . . . . . . . . . . . . . . . . . . . . . . . . .          20,736            2,150
 Provision (benefit) for federal income taxes  . . . . . . . . . . . . . . . . . .           5,666           (1,618)
                                                                                       -----------       -----------
 NET INCOME  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     $    15,070       $    3,768
                                                                                       ===========       ==========
 Income per share  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     $      0.65       $     0.16
                                                                                       ===========       ==========
 Weighted average shares outstanding . . . . . . . . . . . . . . . . . . . . . . .          23,333           23,333
</TABLE>

<TABLE>
<CAPTION>
 PRO FORMA OPERATING DATA (UNAUDITED)                                                      YEAR ENDED DECEMBER 31,     
                                                                                            1996             1995      
                                                                                       --------------   -------------- 
 <S>                                                                                   <C>              <C>            
 PRODUCTION:                                                                                                           
    Natural gas (Mmcf) . . . . . . . . . . . . . . . . . . . . . . . . . .                41,812            45,940     
    Oil (Mbbls)  . . . . . . . . . . . . . . . . . . . . . . . . . . . . .                   140               130     
    Total (Mmcfe)  . . . . . . . . . . . . . . . . . . . . . . . . . . . .                42,652            46,720     
 AVERAGE SALES PRICES:                                                                                                 
    Natural Gas realized (per Mcf) . . . . . . . . . . . . . . . . . . . .             $    2.02        $     1.59     
    Natural Gas unhedged (per Mcf) . . . . . . . . . . . . . . . . . . . .                  2.29              1.47     
    Oil (per Bbl)  . . . . . . . . . . . . . . . . . . . . . . . . . . . .                 21.24             16.65     
</TABLE>





                                      F-18
<PAGE>   53
NOTE 14--SUPPLEMENTAL INFORMATION ON NATURAL GAS AND OIL EXPLORATION,
         DEVELOPMENT AND PRODUCTION ACTIVITIES

         The following information concerning the Company's natural gas and oil
operations has been provided pursuant to Statement of Financial Accounting
Standards No.  69, "Disclosures about Oil and Gas Producing Activities." The
Company's natural gas and oil producing activities are conducted onshore within
the continental United States and offshore in federal and state waters of the
Gulf of Mexico.  The Company's natural gas and oil reserves were estimated by
independent reserve engineers.

Capitalized Costs of Natural Gas and Oil Properties

         As of December 31, 1996, 1995 and 1994, the Company's capitalized
costs of natural gas and oil properties are as follows:

<TABLE>
<CAPTION>
                                                              1996               1995              1994      
                                                         ---------------   ----------------   ---------------
                                                                            (in thousands)
 <S>                                                     <C>               <C>                <C>
 Unevaluated properties, not amortized . . . . . . .     $     60,258      $      42,286      $     25,911
 Properties subject to amortization  . . . . . . . .          468,062            309,378           257,102
                                                         ------------      -------------      ------------
 Capitalized costs . . . . . . . . . . . . . . . . .          528,320            351,664           283,013
 Accumulated depreciation, depletion and
     amortization  . . . . . . . . . . . . . . . . .         (171,258)          (137,769)         (118,392)
                                                         ------------      -------------      ------------ 
 Net capitalized costs . . . . . . . . . . . . . . .     $    357,062      $     213,895      $    164,621
                                                         ============      =============      ============
</TABLE>

         The following is a summary of the costs (in thousands) which are
excluded from the amortization calculation as of December 31, 1996, by year of
acquisition.  The Company is not able to accurately predict when these costs
will be included in the amortization base; however, the Company believes that
unevaluated properties at December 31, 1996 will be fully evaluated within five
years.

<TABLE>
                          <S>                                   <C>
                          1996  . . . . . . . . . . . . . .     $       35,428
                          1995  . . . . . . . . . . . . . .             13,120
                          1994  . . . . . . . . . . . . . .              8,398
                          Prior . . . . . . . . . . . . . .              3,312
                                                                --------------
                                                                $       60,258
                                                                ==============
</TABLE>

         Costs incurred for natural gas and oil exploration, development and
acquisition are summarized below.  Costs incurred during the years ended
December 31, 1996, 1995 and 1994 include interest expense, general and
administrative costs related to acquisition, exploration and development of
natural gas and oil properties, of $8.8 million, $7.0 million and $5.4 million,
respectively.

<TABLE>
<CAPTION>
                                                                       Year Ended December 31,               
                                                         ----------------------------------------------------
                                                              1996              1995               1994      
                                                         ---------------   ---------------   ----------------
                                                                            (in thousands)
 <S>                                                     <C>               <C>               <C>
 Property acquisition:
    Unevaluated(1) . . . . . . . . . . . . . . . . .     $    23,317       $      9,902      $      11,148
    Proved . . . . . . . . . . . . . . . . . . . . .          94,774             11,137             24,628
 Exploration costs . . . . . . . . . . . . . . . . .          27,398              7,224             17,430
 Development costs . . . . . . . . . . . . . . . . .          31,243             41,163             11,790
                                                         -----------       ------------      -------------
 Total costs incurred  . . . . . . . . . . . . . . .     $   176,732       $     69,426      $      64,996
                                                         ===========       ============      =============
</TABLE>
-------------------------

(1) These amounts represent costs incurred by the Company and excluded from the
    amortization base until proved reserves are established or impairment is
    determined.





                                      F-19
<PAGE>   54
         Standardized Measure of Discounted Future Net Cash Flows Relating to
         Proved Natural Gas and Oil Reserves (unaudited)

         The following summarizes the policies used by the Company in the
preparation of the accompanying natural gas and oil reserve disclosures,
standardized measures of discounted future net cash flows from proved natural
gas and oil reserves and the reconciliations of such standardized measures from
year to year.  The information disclosed, as prescribed by the Statement of
Financial Accounting Standards No.  69 is an attempt to present such
information in a manner comparable with industry peers.

         The information is based on estimates of proved reserves attributable
to the Company's interest in natural gas and oil properties as of December 31
of the years presented.  These estimates were principally prepared by
independent petroleum consultants.  Proved reserves are estimated quantities of
natural gas and crude oil which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions.

         The standardized measure of discounted future net cash flows from
production of proved reserves was developed as follows:

                 1.       Estimates are made of quantities of proved reserves
         and future periods during which they are expected to be produced based
         on year-end economic conditions.

                 2.       The estimated future cash flows are compiled by
         applying year-end prices of natural gas and oil relating to the
         Company's proved reserves to the year-end quantities of those reserves
         except for those reserves devoted to future production that is hedged.
         The estimated future cash flows associated with such reserves are
         compiled by applying the reference prices of such hedges to the future
         production that is hedged.  Future price changes are considered only
         to the extent provided by contractual arrangements in existence at
         year-end.

                 3.       The future cash flows are reduced by estimated
         production costs, costs to develop and produce the proved reserves and
         certain abandonment costs, all based on year-end economic conditions.

                 4.       Future income tax expenses are based on year-end
         statutory tax rates giving effect to the remaining tax basis in the
         natural gas and oil properties, other deductions, credits and
         allowances relating to the Company's proved natural gas and oil
         reserves.

                 5.       Future net cash flows are discounted to present value
         by applying a discount rate of 10 percent.

         The standardized measure of discounted future net cash flows does not
purport, nor should it be interpreted, to present the fair value of the
Company's natural 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.





                                      F-20
<PAGE>   55
         The standardized measure of discounted future net cash flows relating
to proved natural gas and oil reserves is as follows:

<TABLE>
<CAPTION>
                                                                         As of December 31,                  
                                                        -----------------------------------------------------
                                                              1996               1995              1994      
                                                        ----------------   ----------------   ---------------
                                                                           (in thousands)
<S>                                                     <C>                <C>                <C>
 Future cash inflows . . . . . . . . . . . . . . . .    $   1,117,058      $   418,822        $   259,811
 Future production costs . . . . . . . . . . . . . .         (153,452)         (66,458)           (45,428)
 Future development costs  . . . . . . . . . . . . .          (67,966)         (24,803)           (21,973)
 Future income taxes . . . . . . . . . . . . . . . .         (230,316)         (74,933)           (28,714)
                                                        -------------      -----------        ----------- 
 Future net cash flows . . . . . . . . . . . . . . .          665,324          252,628            163,696
 10% annual discount for estimated timing of
    cash flows . . . . . . . . . . . . . . . . . . .         (212,742)         (81,169)           (45,262)
                                                        -------------      -----------        ----------- 
 Standardized measure of discounted future
    net cash flows . . . . . . . . . . . . . . . . .    $     452,582      $   171,459        $   118,434
                                                        =============      ===========        ===========
</TABLE>

         Future cash inflows include the effect of hedges in place at year end
December 31, 1996, 1995 and 1994.  At December 31, 1996 and 1995, the effect of
the hedges in place is a reduction to future cash inflows of $28.7 million and
$4.4 million, respectively.  At December 31, 1994, future cash inflows were
increased by $17.2 million for hedges in effect at year end.

         The following table summarizes changes in the standardized measure of
discounted future net cash flows:

<TABLE>
<CAPTION>
                                                                         As of December 31,                  
                                                        -----------------------------------------------------
                                                              1996               1995              1994      
                                                        ----------------   ----------------   ---------------
                                                                           (in thousands)
 <S>                                                    <C>                <C>                <C>
 Beginning of the year . . . . . . . . . . . . . . .    $   171,459        $   118,434        $    106,061
 Revisions to previous estimates:
    Changes in prices and costs  . . . . . . . . . .        145,385             35,497             (10,077)
    Changes in quantities  . . . . . . . . . . . . .        (19,132)            11,306              (2,393)
    Changes in future development costs  . . . . . .        (14,068)               531                 511
 Development costs incurred during the period  . . .         19,594              8,074               4,652
 Extensions and discoveries, net of related costs  .         46,616             51,061              22,723
 Sales of natural gas and oil, net of
    production costs . . . . . . . . . . . . . . . .        (52,663)           (34,843)            (36,156)
 Accretion of discount . . . . . . . . . . . . . .           20,652             12,815              11,326
 Net change in income taxes  . . . . . . . . . . . .        (89,353)           (24,720)               (272)
 Purchase of reserves in place . . . . . . . . . . .        251,713             11,189              23,146
 Sale of reserves in place . . . . . . . . . . . . .           (723)               (19)             (1,906)
 Production timing and other . . . . . . . . . . . .        (26,898)           (17,866)                819
                                                        -----------        -----------        ------------
 End of year . . . . . . . . . . . . . . . . . . . .    $   452,582        $   171,459        $    118,434
                                                        ===========        ===========        ============
</TABLE>





                                     F-21
<PAGE>   56
ESTIMATED NET QUANTITIES OF NATURAL GAS AND OIL RESERVES (UNAUDITED)

         The following table sets forth the Company's net proved reserves,
including changes therein, and proved developed reserves (all within the United
States) at the end of each of the three years in the period ended December 31,
1996, 1995 and 1994.

<TABLE>
<CAPTION>
                                               Natural Gas                     Crude Oil and Condensate
                                                 (Mmcf)                                 (Mbbls)               
                                ---------------------------------------- -------------------------------------
                                     1996          1995         1994         1996        1995         1994    
                                ------------- ------------- ------------ -----------  ----------- ------------
 <S>                               <C>          <C>           <C>           <C>           <C>         <C>
 Proved developed and
 undeveloped reserves: . . . .     195,946      145,945       118,118         889          636         536
 Revisions of previous                                                                                     
 estimates . . . . . . . . . .      (8,665)      15,702        (1,912)       (157)          51        (104)
 Extensions and discoveries         21,445       45,014        25,867         198          254         151
 Production  . . . . . . . . .     (31,215)     (21,077)      (22,437)       (118)        (100)       (102)
 Purchase of reserves in place     143,688       10,367        27,949         361           48         205
 Sales of reserves in place  .        (725)          (5)       (1,640)        (42)          --         (50)
                                ----------    ---------     ---------    --------     --------    -------- 
 End of year . . . . . . . . .     320,474      195,946       145,945       1,131          889         636
                                ==========    =========     =========    ========     ========    ========

 Proved developed reserves:
 Beginning of year . . . . . .     162,784      104,678       107,909         774          328         478
 End of year . . . . . . . . .     236,544      162,784       104,678       1,013          774         328
</TABLE>


NOTE 15 -- QUARTERLY RESULTS (UNAUDITED)

Selected unaudited quarterly data is shown below:

<TABLE>
<CAPTION>
                                      1ST                2ND                3RD               4TH
                                    QUARTER            QUARTER            QUARTER           QUARTER   
                                 -------------      -------------      ------------      -------------
                                                 (in thousands, except per share data)
 <S>                           <C>               <C>                <C>                <C>
 1996
 Total revenues                $    10,213       $      11,574      $      19,171      $    24,946
 Income from operations              1,219               2,661              2,740            7,102
 Net income                            976               1,813              1,267            4,586

 Earnings per share(1)         $      0.06       $        0.12      $        0.08      $      0.20

 1995
 Total revenues                $     9,751       $      11,398      $      10,162      $     9,898
 Income (loss) from                  1,838               3,020              3,346           (9,918)(2)
 operations
 Net income (loss)                   1,156               1,869              2,983           (6,311)

 Earnings (loss) per share     $      0.07       $        0.12      $        0.20      $     (0.41)
</TABLE>



(1) Quarterly earnings per share are based on the weighted average number of
    shares outstanding during the quarter.  Because of the increase in the
    number of shares outstanding during the third quarter, the sum of quarterly
    earnings per share do not equal earnings per share for the year.
(2) Includes a nonrecurring charge of $12.0 million ($7.8 million net of taxes)
    incurred pursuant to the February 1996 reorganization.  (See Note 11 --
    Nonrecurring Charge)





                                      F-22
<PAGE>   57
                                 EXHIBIT INDEX
<TABLE>                                                                    
<CAPTION>                                                                  
 EXHIBITS         DESCRIPTION                                              
 --------         -----------                                              
<S>             <C>                                                        
 *10.26** --    Employment Agreement, dated September 19, 1996, between The Houston Exploration Company and                     
                Charles W. Adcock.                                                                                              
 *10.27** --    Form of Letter Agreement from The Houston Exploration Company to each of James G. Floyd,                        
                Randall J. Fleming, Thomas W. Powers, Charles W. Adcock, James F. Westmoreland and                              
                Sammye L. Dees evidencing grants of Phantom Stock Rights effective as of December 16, 1996.                     
 * 21.1   --    Subsidiaries of the Company.                                                                                    
 * 27.1   --    Financial Data Schedule.                                                                                        
</TABLE>