HOUSTON EXPLORATION CO, 424B1, 1996-09-23

HOUSTON EXPLORATION CO
424B1, 1996-09-23
OIL & GAS FIELD EXPLORATION SERVICES

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<PAGE> 1
FILED PURSUANT TO RULE 424(b)(1)
REGISTRATION NO. 333-4437
<TABLE>
<S> <C>
[HOUSTON EXPLORATION LOGO] 6,200,000 SHARES
THE HOUSTON EXPLORATION COMPANY
COMMON STOCK
(PAR VALUE $.01 PER SHARE)
</TABLE>

---------------------
All of the shares offered hereby are being sold by the Company. Prior to
the offering, all of the outstanding shares of Common Stock of the Company have
been owned by a wholly-owned subsidiary of The Brooklyn Union Gas Company. Upon
completion of the offering, a wholly-owned subsidiary of The Brooklyn Union Gas
Company will own approximately 68% of the outstanding shares of Common Stock
(approximately 66% if the Underwriters' over-allotment option is exercised in
full). For factors considered in determining the initial public offering price,
see "Underwriting."

SEE "RISK FACTORS" BEGINNING ON PAGE 9 FOR CERTAIN CONSIDERATIONS RELEVANT
TO AN INVESTMENT IN THE COMMON STOCK.

The Common Stock has been approved for listing, subject to official notice
of issuance, on the New York Stock Exchange under the symbol "THX."

---------------------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS
THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES
COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS.
ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

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

<TABLE>
<CAPTION>
INITIAL PUBLIC UNDERWRITING PROCEEDS TO
OFFERING PRICE DISCOUNT(1) COMPANY(2)
------------------ ------------------ ------------------
<S> <C> <C> <C>
Per Share.......................... $15.50 $1.09 $14.41
Total(3)........................... $96,100,000 $6,758,000 $89,342,000
</TABLE>

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

(1) The Company has agreed to indemnify the Underwriters against certain
liabilities, including liabilities under the Securities Act of 1933. See
"Underwriting."

(2) Before deducting estimated expenses of $1,500,000 payable by the Company.

(3) The Company has granted the Underwriters an option for 30 days to purchase
up to an additional 930,000 shares of Common Stock at the initial public
offering price per share, less the underwriting discount, solely to cover
over-allotments. If such option is exercised in full, the total initial
public offering price, underwriting discount and proceeds to the Company
will be $110,515,000, $7,771,700 and $102,743,300, respectively. See
"Underwriting."

---------------------
The shares offered hereby are offered severally by the Underwriters, as
specified herein, subject to receipt and acceptance by them and subject to their
right to reject any order in whole or in part. It is expected that certificates
for the shares will be ready for delivery in New York, New York on or about
September 25, 1996 against payment therefor in immediately available funds.

GOLDMAN, SACHS & CO.
DONALDSON, LUFKIN & JENRETTE
SECURITIES CORPORATION
PAINEWEBBER INCORPORATED
---------------------
The date of this Prospectus is September 19, 1996.
<PAGE> 2

THE HOUSTON EXPLORATION COMPANY
NATURAL GAS AND OIL PROPERTIES

[MAP]

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

IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON STOCK OF
THE COMPANY AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN
MARKET. SUCH TRANSACTIONS MAY BE EFFECTED ON THE NEW YORK STOCK EXCHANGE, IN THE
OVER-THE-COUNTER MARKET OR OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE
DISCONTINUED AT ANY TIME.

2
<PAGE> 3

PROSPECTUS SUMMARY

The following summary is qualified in its entirety by the more detailed
information and financial statements, including the notes thereto, included
elsewhere in this Prospectus. Unless otherwise indicated, the information in
this Prospectus assumes that the Underwriters' over-allotment option will not be
exercised. In addition, unless otherwise specified, all numbers of shares and
per share amounts have been restated to reflect the reclassification of each
outstanding share of common stock of the Company into 2.47 shares of Common
Stock, par value $.01 per share ("Common Stock"), to be effected immediately
prior to the offering made hereby (the "Offering"). Prior to the Offering, all
of the outstanding shares of Common Stock of the Company have been owned by a
wholly-owned subsidiary of The Brooklyn Union Gas Company ("Brooklyn Union").
The Company was incorporated in December 1985, and has focused since its
inception primarily upon natural gas and oil exploration and development
offshore in the Gulf of Mexico. 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 previously held by Fuel Resources, Inc., another Brooklyn Union
subsidiary. Unless otherwise indicated, all information set forth in this
Prospectus gives effect to such reorganization. Unless otherwise indicated, the
December 31, 1995 reserve and acreage and the current production data included
in this Prospectus includes the pro forma net reserves, acreage and production
attributable to (i) properties acquired by the Company in July 1996 from
TransTexas Gas Corporation and (ii) properties that the Company will acquire
from Smith Offshore Exploration Company in an acquisition that will close
concurrently with this Offering. Investors should carefully consider the
information set forth under "Risk Factors." Oil and gas industry terms used in
this Prospectus are defined in "Glossary of Oil and Gas Terms."

THE COMPANY

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 that 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, 1995, the Company had
net proved reserves of 346 Bcfe. Approximately 98% of the Company's net proved
reserves on such date were natural gas and approximately 73% of proved reserves
were classified as proved developed. The Company operates approximately 82% 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 pro forma lease operating expenses of
$0.25 per Mcfe of production and pro forma general and administrative expenses
of $0.08 per Mcfe of production for the year ended December 31, 1995.

3
<PAGE> 4

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
potental

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 five additional exploratory wells in the Gulf of Mexico
in the remainder of 1996, 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 49 lease
blocks, representing 230,531 gross (147,180 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 16 of these lease blocks and a 50% or greater
working interest in 17 other lease blocks. During 1994 and 1995, the Company
drilled five successful exploratory wells and 11 successful development wells in
the Gulf of Mexico, resulting in added net proved reserves of approximately 61
Bcfe. During the first half of 1996, the Company drilled three successful
exploratory wells and one successful development well. The Company anticipates
that approximately $50 million of its $63 million 1996 capital expenditure
budget (excluding acquisitions) will be spent on offshore projects. In addition,
the Company intends to continue its participation in federal lease sales and to
actively pursue attractive farm-in opportunities as they become available.
During July 1996, average net production from the Company's Gulf of Mexico
properties was approximately 52,900 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 63% of its net proved reserves as of December 31, 1995. Since the
beginning of 1994, the Company has drilled or participated in the drilling of 25
successful development wells and three successful exploratory wells onshore. The
Company plans to drill 16 development wells onshore during the remainder of
1996. 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 1,060 gross (657 net) wells, and 138,385 gross
(93,419 net) acres. The Company anticipates that approximately $13 million of
its $63 million 1996 capital expenditure budget (excluding acquisitions) will be
spent on onshore projects. 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 July
1996, average net production from the Company's onshore properties was
approximately 69,300 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 1,100 square miles of 3-D seismic data,
including 3-D seismic surveys on 29 of its offshore lease blocks and on possible
lease and acquisition prospects, and

4
<PAGE> 5

60,500 linear miles of 2-D seismic data on its offshore properties. The Company
has 12 geologists/geophysicists with average industry experience of
approximately 30 years and five 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 drillbit, 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 this regard the
Company recently acquired significant onshore properties in South Texas and has
agreed to acquire additional interests in 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 82% of its Gulf of Mexico production and
approximately 92% of its onshore production. Houston Exploration operates 16
platforms and 64 wells in the Gulf of Mexico and 924 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 pro forma lease operating expense
of $0.25 per Mcfe of production and pro forma general and administrative expense
of $0.08 per Mcfe of production for the year ended December 31, 1995.

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.

RECENT 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 properties acquired in the TransTexas Acquisition represent approximately
113 Bcfe of the Company's net proved reserves of 346 Bcfe as of December 31,
1995. 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 156 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 is subject to adjustment based upon production and expenses related
to the assets between the May 1, 1996 effective date of the TransTexas
Acquisition and the July 2, 1996 closing date. The purchase price for the
TransTexas Acquisition was paid in cash, financed by borrowings under the
Company's credit facility. The properties acquired by the Company 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
against any loss arising from such judgment liens. TransTexas has appealed the
judgments to which such liens relate, and has posted bonds secured by a letter
of credit and cash in the full aggregate amount of such judgments. One of the
judgments, in the amount of $18 million, has been reversed, a decision

5
<PAGE> 6

which, if upheld, will result in the release of the related judgment lien. As a
result, the Company believes that the properties purchased in the TransTexas
Acquisition are not subject to any material risk as a result of such judgment
liens.

PENDING ACQUISITION. On July 1, 1996, the Company entered into an asset
purchase agreement with Smith Offshore Exploration Company ("Soxco"), providing
for the acquisition by the Company of substantially all of the natural gas and
oil properties and related assets of Soxco, representing approximately 32 Bcfe
of the Company's net proved reserves of 346 Bcfe as of December 31, 1995 (the
"Soxco Acquisition"). Soxco's natural gas and oil properties consist solely of
working interests in producing properties and developed and undeveloped acreage
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 will pay Soxco cash in the aggregate amount of $23.7 million (subject to
certain adjustments), and issue to Soxco 762,387 shares of Common Stock with an
aggregate value of $11.8 million. The cash portion of the purchase price will be
funded with the proceeds of this Offering. In addition to the foregoing, the
Company will pay Soxco a deferred purchase price of up to $17.6 million payable
in two installments, on January 31, 1997 and January 31, 1998. The amount of the
deferred purchase price installments will be determined by the amount of the
probable reserves of Soxco as of December 31, 1995 (approximately 17.6 Bfce)
that are produced prior to or classified as proved as of December 31, 1996 and
December 31, 1997, respectively, provided that Soxco will be entitled to receive
a minimum deferred purchase price of $8.8 million. The amounts so determined
will be paid in shares of Common Stock based upon the fair market value of such
stock at the time of issuance. The Soxco Acquisition will close concurrently
with, is conditioned upon and is a condition to the completion of this Offering.

PRINCIPAL STOCKHOLDER. The Company is currently an indirect wholly-owned
subsidiary of Brooklyn Union. Brooklyn Union distributes gas in an area of New
York City with a population of four million. Upon completion of this Offering
and giving effect to the Soxco Acquisition, a wholly-owned subsidiary of
Brooklyn Union will own approximately 68% of the outstanding shares of Common
Stock (approximately 66% if the Underwriters' over-allotment option is exercised
in full). Brooklyn Union believes that Houston Exploration will provide a
competitive vehicle with a stand-alone capital structure through which Brooklyn
Union can continue to participate in the exploration for and production of
natural gas and oil to maximize the long-term value of its substantial
investment in that business. Brooklyn Union has advised the Company that it does
not currently intend to engage in the domestic exploration for and production of
natural gas and oil except through its ownership of Common Stock of the Company.

THE OFFERING

<TABLE>
<S> <C>
Common Stock offered by the Company.................... 6,200,000 shares
Common Stock to be outstanding after this Offering..... 22,402,763 shares (1)
Proposed New York Stock Exchange symbol................ "THX"
Use of Proceeds........................................ To repay outstanding indebtedness
under the Company's Credit Facility
and to pay the cash portion of the
purchase price for the Soxco
Acquisition.
</TABLE>

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

(1) Includes 762,387 shares to be issued in connection with the Soxco
Acquisition and 145,161 shares to be issued to the Company's President and
Chief Executive Officer in connection with the Offering. Does not include
(i) 1,120,138 shares of Common Stock (1,166,638 shares if the Underwriters'
over-allotment option is exercised in full) issuable pursuant to options
that will be granted to management and other employees upon completion of
the Offering, at an exercise price per share equal to the initial public
offering price, or (ii) shares of Common Stock with a fair market value at
the time of issuance of up to $17.6 million issuable as the deferred
purchase price for the Soxco Acquisition. See "Management -- 1996 Stock
Option Plan" and "Soxco Acquisition."

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<PAGE> 7

SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA

The following table presents certain historical and pro forma financial
data of the Company as of and for each of the periods indicated. The historical
financial data for the years ended December 31, 1993, 1994 and 1995 have been
derived from the audited financial statements of the Company. The historical
financial data for the six months ended June 30, 1995 and 1996 and as of June
30, 1996 are derived from unaudited financial statements of the Company. The
results for the six months ended June 30, 1996 are not necessarily indicative of
results for the full year. The following information should be read together
with "Management's Discussion and Analysis of Financial Condition and Results of
Operations," "Pro Forma Financial Information," the Financial Statements of the
Company and Soxco and the Historical Summaries to the properties acquired from
TransTexas included elsewhere in this Prospectus.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30,
--------------------------------------- -----------------------------
PRO FORMA PRO FORMA
1993 1994 1995 1995(1) 1995 1996 1996(1)
------- ------- ------- --------- ------- ------- ---------
(IN THOUSANDS EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues:
Natural gas and oil revenues..... $37,462 $41,755 $39,431 $75,263 $20,324 $21,252 $41,055
Other............................ 799 467 1,778 1,778 825 535 535
------- ------- ------- --------- ------- ------- ---------
Total revenues............ 38,261 42,222 41,209 77,041 21,149 21,787 41,590
Expenses:
Lease operating.................. 4,477 5,344 5,468 11,580 2,875 3,634 7,036
Depreciation, depletion and
amortization................... 23,225 25,365 21,969 45,859 11,662 11,571 20,324
General and administrative,
net............................ 2,454 3,460 3,486 3,701 1,754 2,702 2,796
Nonrecurring charge(2)........... -- -- 12,000 12,000 -- -- --
------- ------- ------- --------- ------- ------- ---------
Total operating
expenses................ 30,156 34,169 42,923 73,140 16,291 17,907 30,156
------- ------- ------- --------- ------- ------- ---------
Income (loss) from operations...... 8,105 8,053 (1,714) 3,901 4,858 3,880 11,434
Interest expense, net.............. 1,764 2,102 2,398 2,183 1,319 1,118 985
------- ------- ------- --------- ------- ------- ---------
Income (loss) before income taxes.. 6,341 5,951 (4,112) 1,718 3,539 2,762 10,449
Income tax provision (benefit)..... 1,790 597 (3,809) (1,769) 514 (27) 2,663
------- ------- ------- --------- ------- ------- ---------
Net income (loss).................. $ 4,551 $ 5,354 $ (303) $ 3,487 $ 3,025 $ 2,789 $ 7,786
======= ======= ======= ======== ======= ======= ========
Net income (loss) per share........ $ 0.30 $ 0.35 $ (0.02) $ 0.16 $ 0.20 $ 0.18 $ 0.35
Weighted average shares
outstanding...................... 15,295 15,295 15,295 22,403 15,295 15,295 22,403
</TABLE>

<TABLE>
<CAPTION>
AT JUNE 30, 1996
------------------------
PRO
HISTORICAL FORMA(3)
-------- -----------
(IN THOUSANDS)
<S> <C> <C>
BALANCE SHEET DATA:
Property, plant and equipment, net........................................... $234,211 $ 339,764
Total assets................................................................. 263,842 372,639
Long-term debt............................................................... 77,853 75,916
Stockholders' equity......................................................... 116,318 218,227
</TABLE>

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(1) Gives effect to the TransTexas Acquisition, the Soxco Acquisition and the
application of the net proceeds from the Offering as if such transactions
had been consummated as of January 1, 1995.

(2) Represents an accrual for a nonrecurring charge incurred in connection with
the reorganization effective in February 1996. See Note 10 of Notes to
Combined Financial Statements.

(3) Gives effect to the TransTexas Acquisition, the Soxco Acquisition and the
application of the net proceeds from the Offering as if such transactions
had been consummated on June 30, 1996.

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<PAGE> 8

SUMMARY NATURAL GAS AND OIL RESERVE DATA

The following table summarizes the estimates of the Company's historical
and pro forma net proved natural gas and oil reserves as of the dates indicated
and the present value attributable to these reserves at such dates. The reserve
and present value data as of December 31, 1993, 1994 and 1995 have been prepared
by Ryder Scott Company, Netherland, Sewell & Associates, Inc., Huddleston & Co.,
Inc. and Miller and Lents, Ltd., independent petroleum engineering consultants.
For additional information relating to the Company's natural gas and oil
reserves, see "Business -- Natural Gas and Oil Reserves" and Note 13 of the
Notes to the Combined Financial Statements of the Company included elsewhere in
this Prospectus. Summaries of the December 31, 1995 reserve reports and the
letters of the independent petroleum engineering consultants with respect
thereto are included as Appendix A to this Prospectus.

<TABLE>
<CAPTION>
AS OF DECEMBER 31,
---------------------------------------------
PRO FORMA
1993 1994 1995 1995(1)
-------- -------- -------- ---------
($ IN THOUSANDS)
<S> <C> <C> <C> <C>
Proved Reserves:
Natural gas (Mmcf)........................... 118,118 145,945 195,946 338,529
Oil (Mbbls).................................. 536 636 889 1,234
Total (Mmcfe)................................ 121,334 149,761 201,280 345,933
Present value of future net revenues before
income taxes(2).............................. $119,326 $135,869 $206,574 $ 326,346
Standardized measure of discounted future net
cash flows(3)................................ $106,061 $118,434 $171,459 $ 282,066
</TABLE>

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(1) Gives effect to the TransTexas Acquisition and the Soxco Acquisition.

(2) The present value of future net revenues attributable to the Company's
reserves was prepared using prices in effect as of 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%.
Such amounts reflect the effects of the Company's hedging contracts.

SUMMARY OPERATING DATA

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30,
--------------------------------------- ---------------------------
PRO FORMA PRO FORMA
1993 1994 1995 1995(1) 1995 1996 1996(1)
------- ------- ------- --------- ------ ------ ---------
<S> <C> <C> <C> <C> <C> <C> <C>
Production:
Natural gas (Mmcf)......... 22,555 22,437 21,077 45,940 10,604 11,498 20,956
Oil (Mbbls)................ 101 102 100 130 68 41 51
Total (Mmcfe).............. 23,161 23,049 21,677 46,720 11,012 11,744 21,262
Average sales prices:
Natural gas (per Mcf)(2)... $ 1.58 $ 1.79 $ 1.79 $ 1.59 $ 1.81 $ 1.78 $ 1.91
Oil (per Bbl).............. 16.96 15.85 16.54 16.65 16.97 18.93 18.69
Expenses (per Mcfe):
Lease operating............ $ 0.19 $ 0.23 $ 0.25 $ 0.25 $ 0.26 $ 0.31 $ 0.32
Depreciation, depletion and
amortization............ 1.00 1.10 1.01 0.98 1.06 0.99 0.96
General and administrative,
net..................... 0.11 0.15 0.16 0.08 0.16 0.23 0.13
</TABLE>

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(1) Gives effect to the TransTexas Acquisition and the Soxco Acquisition as if
such transactions had been consummated as of January 1, 1995.

(2) Reflects the effects of hedging. See "Management's Discussion and Analysis
of Financial Condition and Results of Operations" and "Business -- Marketing
and Customers."

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<PAGE> 9

RISK FACTORS

Prospective purchasers of the Common Stock should carefully consider the
risk factors set forth below, as well as the other information contained in this
Prospectus, before purchasing the shares of Common Stock offered hereby.

VOLATILITY OF NATURAL GAS AND OIL PRICES

Revenues generated from the Company's operations are highly dependent upon
the price of, and demand for, natural gas and oil. Historically, the markets for
natural gas and oil have been volatile, and such markets are likely to continue
to be volatile in the future. Prices for natural gas and oil are subject to wide
fluctuation in response to relatively minor changes in the supply of and demand
for natural gas and oil, market uncertainty and a variety of additional factors
that are beyond the control of the Company. These factors include the level of
consumer product demand, weather conditions, domestic and foreign governmental
regulations, the price and availability of alternative fuels, political
conditions in the Middle East, the foreign supply of natural gas and oil, the
price of foreign imports and overall economic conditions. It is impossible to
predict future natural gas and oil price movements with any certainty. Declines
in natural gas and oil prices may materially adversely affect the Company's
financial condition, liquidity, ability to finance planned capital expenditures
and results of operations. Lower natural gas and oil prices also may reduce the
amount of natural gas and oil that the Company can produce economically.

In order to reduce its exposure to short-term fluctuations in the price of
natural gas, the Company enters into hedging arrangements from time to time. The
Company's hedging arrangements apply to only a portion of its production and
provide only partial price protection against declines in natural gas prices. In
addition, the Company's hedging arrangements limit the benefit to the Company of
increases in the price of natural gas. See "Management's Discussion and Analysis
of Financial Condition and Results of Operations -- General" and
"Business -- Marketing and Customers."

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 after income tax effects, 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.

UNCERTAINTY OF RESERVE INFORMATION AND FUTURE NET REVENUE ESTIMATES

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 Prospectus represents 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. Estimates of economically recoverable natural gas and oil reserves
and of future net cash flows necessarily depend upon a number of variable
factors and assumptions, such as historical production from the area compared
with production from other producing areas, the assumed effects of regulations
by governmental agencies and assumptions concerning future natural gas and oil
prices, future operating costs, severance and excise taxes, development costs
and workover and remedial costs, all of which may in fact vary considerably from
actual results. For these reasons, estimates of the economically recoverable
quantities of natural gas and oil attributable to any

9
<PAGE> 10

particular group of properties, classifications of such reserves based on risk
of recovery, and estimates of the future net cash flows expected therefrom
prepared by different engineers or by the same engineers but at different times
may vary substantially and such reserve estimates may be subject to downward or
upward adjustment based upon such factors. Actual production, revenues and
expenditures with respect to the Company's reserves will likely vary from
estimates, and such variances may be material. See "Business -- Natural Gas and
Oil Reserves."

RESERVE REPLACEMENT RISK

In general, the volume of production from natural gas and oil properties
declines as reserves are depleted. The rate of decline depends on reservoir
characteristics, and varies from the steep decline rate characteristic of Gulf
of Mexico reservoirs, where the Company has a significant portion of its
production, to the relatively slow decline rate characteristic of the
longer-lived fields in South Texas, the Arkoma Basin, East Texas and West
Virginia. Except to the extent the Company acquires properties containing proved
reserves or conducts successful exploration and development activities, or both,
the proved reserves of the Company will decline as reserves are produced. The
Company's future natural gas and oil production is, therefore, highly dependent
upon its level of success in finding or acquiring additional reserves. The
business of exploring for, developing or acquiring reserves is capital
intensive. To the extent cash flow from operations is reduced and external
sources of capital become limited or unavailable, the Company's ability to make
the necessary capital investment to maintain or expand its asset base of natural
gas and oil reserves would be impaired. In addition, there can be no assurance
that the Company's future exploration, development and acquisition activities
will result in additional proved reserves or that the Company will be able to
drill productive wells at acceptable costs.

CONTROL BY PRINCIPAL STOCKHOLDER

Prior to this offering all of the outstanding shares of Common Stock of the
Company have been owned by a wholly-owned subsidiary of Brooklyn Union. After
giving effect to this Offering and the Soxco Acquisition, a wholly-owned
subsidiary of Brooklyn Union will own approximately 68% of the outstanding
shares of Common Stock (approximately 66% if the Underwriters' over-allotment
option is exercised in full). As a result of Brooklyn Union's beneficial
holdings of Common Stock, after consummation of the Offering, Brooklyn Union
will remain in the position to control the election of the entire Board of
Directors of the Company and Brooklyn Union will be able to determine the
outcome of all matters requiring the vote of the Company's stockholders. See
"Related Party Transactions -- Transactions between the Company and Brooklyn
Union and its Affiliates."

RELATIONSHIP WITH BROOKLYN UNION AND POTENTIAL CONFLICTS OF INTEREST

There may be conflicts of interest arising in the future between the
Company and Brooklyn Union and its subsidiaries in a number of areas relating to
their past and ongoing relationships, including dividends, acquisitions of
natural gas and oil businesses or properties, transfers of assets, insurance
matters, marketing, financial commitments, registration rights and issuances and
sales of capital stock of the Company. The Company sold approximately 24% of its
gas production during July 1996, and, subject to certain conditions, has agreed
to sell substantially all of its subsequently developed or acquired production,
to an affiliate of Brooklyn Union. The Company's Chairman of the Board, Robert
B. Catell, is also the Chairman of the Board of Directors and Chief Executive
Officer of Brooklyn Union. In addition, two other directors of the Company,
Craig G. Matthews and James Q. Riordan, are the President and a director of
Brooklyn Union, respectively. See "Related Party Transactions -- Transactions
between the Company and Brooklyn Union and Affiliates" and "Management."

10
<PAGE> 11

DRILLING RISKS

Drilling involves numerous risks, including the risk that no commercially
productive natural gas or oil reservoirs will be encountered. The cost of
drilling, completing and operating wells is often uncertain, and drilling
operations may be curtailed, delayed or canceled as a result of a variety of
factors, including unexpected drilling conditions, pressure or irregularities in
formations, equipment failures or accidents, adverse weather conditions and
shortages or delays in the delivery of equipment. The Company's future drilling
activities may not be successful and, if unsuccessful, such failure will have an
adverse effect on the Company's future results of operations and financial
condition.

OPERATING RISKS OF NATURAL GAS AND OIL OPERATIONS

The natural gas and oil business involves certain operating hazards such as
well blowouts, cratering, explosions, uncontrollable flows of oil, natural gas
or well fluids, fires, formations with abnormal pressures, pollution, releases
of toxic gas and other environmental hazards and risks, any of which could
result in substantial losses to the Company. The Company's offshore operations
also are subject to the additional hazards of marine operations, such as severe
weather, capsizing and collision. The availability of a ready market for the
Company's natural gas and oil production also depends on the proximity of
reserves to, and the capacity of, natural gas and oil gathering systems,
pipelines and trucking or terminal facilities. In addition, the Company may be
liable for environmental damages caused by previous owners of property purchased
and leased by the Company. As a result, substantial liabilities to third parties
or governmental entities may be incurred, the payment of which could reduce or
eliminate the funds available for exploration, development or acquisitions or
result in the loss of the Company's properties. In accordance with customary
industry practices, the Company maintains insurance against some, but not all,
of such risks and losses. The Company does not carry business interruption
insurance. The occurrence of such an event not fully covered by insurance could
have a material adverse effect on the financial condition and results of
operations of the Company.

ACQUISITION RISKS

The acquisition of prospects that yield cost-effective and successful
exploration or development opportunities requires assessment of numerous
factors, many of which are beyond the Company's control. While the Company
believes that its technological expertise and geological database give it
advantages over some of its competitors, there can be no assurances that the
Company's acquisition of property interests will be successful and, if
unsuccessful, that such failure will not have an adverse effect on the Company's
future results of operations and financial condition.

SUBSTANTIAL CAPITAL REQUIREMENTS

The Company makes, and will continue to make, substantial capital
expenditures for the exploration, development, acquisition and production of
natural gas and oil reserves. Historically, the Company has financed these
expenditures primarily with cash generated by operations, proceeds from bank
borrowings and capital contributions by Brooklyn Union. The Company plans to
incur capital expenditures (excluding acquisitions) of approximately $63 million
in 1996. Management believes that the Company will have sufficient cash provided
by operating activities and borrowings under the Credit Facility to fund planned
capital expenditures in 1996. If revenues or the Company's borrowing base
decrease as a result of lower natural gas and oil prices, operating difficulties
or declines in reserves, the Company may have limited ability to expend the
capital necessary to undertake or complete future drilling programs or
acquisition opportunities. There can be no assurance that additional debt or
equity financing or cash generated by operations will be available to meet these
requirements. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Liquidity and Capital Resources."

11
<PAGE> 12

PENDING LEGAL PROCEEDINGS

In connection with the February 1996 reorganization, certain former
employees of Fuel Resources Inc. ("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.
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 of $35 million and punitive damages in excess of $70 million. FRI has
agreed to indemnify the Company against such suit. In addition, THEC Holdings
Corp. ("Holdings"), the subsidiary of Brooklyn Union that holds all of the
currently outstanding Common Stock of the Company, has agreed to indemnify the
Company against the suit, and has agreed to pledge all of its holdings of Common
Stock to the Company to secure such indemnification obligation. As a result of
such arrangements, the Company believes that it will not be required to pay any
damages resulting from such suit, even if a judgment adverse to the Company is
rendered in the suit. However, the Company would incur a non-cash charge in
addition to the $12 million charge previously taken by the Company in the event
such damages are determined to be in excess of such $12 million amount, which
would have the effect of reducing the Company's reported income (or resulting in
or increasing a loss) in the period in which such additional charge is
determined. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- General" and "Business -- Legal Proceedings."

DEPENDENCE ON KEY PERSONNEL

The Company depends to a large extent on the services of certain key
management personnel. The loss of the services of such management personnel
could have a material adverse effect on the Company's operations. The Company
intends to enter into employment agreements with certain of its executive
officers prior to the completion of the Offering. The Company believes that its
success is also dependent upon its ability to continue to employ and retain
skilled technical personnel. See "Management -- Employment Agreements."

GOVERNMENT REGULATION AND ENVIRONMENTAL MATTERS

The Company's business is regulated by certain local, state and federal
laws and regulations relating to the exploration for, and the development,
production, marketing, pricing, transportation and storage of, natural gas and
oil. The Company's business is also subject to extensive and changing
environmental and safety laws and regulations governing plugging and
abandonment, the discharge of materials into the environment or otherwise
relating to environmental protection. In addition, the Company is subject to
changing and extensive tax laws, and the effect of newly enacted tax laws cannot
be predicted. The implementation of new, or the modification of existing, laws
or regulations, including regulations which may be promulgated under the Oil
Pollution Act of 1990, could have a material adverse effect on the Company. See
"Business -- Abandonment Costs," "-- Regulation" and "-- Environmental Matters."

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

12
<PAGE> 13

dependent upon its ability to evaluate and select suitable properties and to
consummate transactions in this highly competitive environment.

ABSENCE OF DIVIDENDS ON COMMON STOCK

The Company currently intends to retain its cash for the operation and
expansion of its business, including exploration, development and acquisition
activities. The terms of the Credit Facility contain 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 "Dividend Policy," "Management's
Discussions and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources" and Note 2 to the Company's
Combined Financial Statements.

CERTAIN ANTI-TAKEOVER PROVISIONS

The Company's Certificate of Incorporation and Bylaws and the Delaware
General Corporation Law contain provisions that may have the effect of
discouraging unsolicited takeover proposals for the Company. These provisions,
among other things, provide for the classification of the board of directors,
restrict the ability of stockholders to take action by written consent,
authorize the Board of Directors to designate the terms of and issue new series
of preferred stock, limit the personal liability of directors, require the
Company to indemnify directors and officers to the fullest extent permitted by
applicable law and impose restrictions on business combinations with certain
interested parties. See "Description of Capital Stock -- Certain Provisions of
the Company's Charter and Bylaws and Delaware Law."

NO PRIOR PUBLIC MARKET

Prior to this Offering, there has been no public market for the shares of
the Common Stock. Although the Company has applied for the listing of its Common
Stock on the New York Stock Exchange, there can be no assurance that an active
trading market for such shares will develop or be sustained. The initial public
offering price for the Common Stock has been determined by negotiations among
the Company and the Underwriters, and may not be indicative of the market price
of the Common Stock after this Offering. See "Underwriting."

SHARES ELIGIBLE FOR FUTURE SALE

The Company, Brooklyn Union, Soxco, each holder of options to purchase
shares of Common Stock, and each director and executive officer of the Company
have agreed not to sell any shares of Common Stock for a period of 180 days from
the date of this Prospectus without the consent of the representatives of the
Underwriters. The lockup provisions in these agreements are subject to waiver by
the parties to these agreements. After expiration of the lockup period, the
15,295,215 currently outstanding shares of Common Stock, will be eligible for
resale, subject to the volume and other limitations of Rule 144 under the
Securities Act, or pursuant to the exercise of demand registration rights. In
connection with the Soxco Acquisition, the Company will issue 762,387 shares of
Common Stock with an aggregate value of $11.8 million. In addition, the Company
will be obligated to issue additional shares of Common Stock with a value at the
time of issuance of between $8.8 and $17.6 million as the deferred purchase
price for the Soxco Acquisition. Soxco will receive demand registration rights
relating to such shares. In addition, upon completion of the Offering, there
will be 1,120,138 shares of Common Stock (1,166,638 shares if the Underwriters'
over-allotment option is exercised in full) issuable pursuant to outstanding
options held by management and other employees, all of which are covered by
demand or piggyback registration rights or will be issued pursuant to a
registration statement on Form S-8 and become freely tradeable, subject to
certain requirements of Rule 144. See "Shares Eligible for Future Sale" and
"Soxco Acquisition."

13
<PAGE> 14

THE COMPANY

Houston Exploration 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. At December 31,
1995, the Company had net proved reserves of 346 Bcfe. Approximately 98% of the
Company's net proved reserves on such date were natural gas and approximately
73% of proved reserves were classified as proved developed. The Company operates
approximately 82% of its Gulf of Mexico production and approximately 92% of its
onshore production. The Company believes its primary strengths are its high
quality reserves, its substantial inventory of exploration and development
opportunities, its in-house expertise in generating new prospects, and its
geographic focus and low-cost operating structure.

The Company was incorporated in Delaware in December 1985 and commenced
operations in January 1986. The Company has focused since its inception
primarily on the exploration and development of high potential prospects
offshore in the Gulf of Mexico. In February 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. Brooklyn Union believes that Houston Exploration will
provide a competitive vehicle with a stand-alone capital structure through which
Brooklyn Union can continue to participate in the exploration for and production
of natural gas and oil and maximize the long-term value of its substantial
investment in that business. Brooklyn Union distributes natural gas in an area
of New York City with a population of four million. A marketing company
affiliated with Brooklyn Union purchases approximately 24% of the Company's
natural gas production at market prices, based upon production during July 1996.
See "Related Party Transactions."

The Company's principal executive offices are located at 1331 Lamar, Suite
1065, Houston, Texas 77010 and its telephone number is (713) 652-2847.

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 from TransTexas. The properties acquired in the TransTexas
Acquisition represent approximately 113 Bcfe of the Company's net proved
reserves of 346 Bcfe as of December 31, 1995. 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 156 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 is subject to adjustment
based on production and expenses related to the assets between the May 1, 1996
effective date of the TransTexas Acquisition and July 2, 1996. The purchase
price for the TransTexas Acquisition was paid in cash, financed by borrowings
under the Company's credit facility. If the Company notifies TransTexas of title
defects to any of the properties acquired in the TransTexas Acquisition at any
time during the 60 days following the closing of the TransTexas Acquisition,
TransTexas must cure the title defect at its expense or the Company will be
entitled to reconvey the property in question to TransTexas and receive a return
of the purchase price paid for such property. Of the purchase price, $6 million
has been placed in escrow to satisfy title defects during such 60 day period.

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 pipelines. The
Company

14
<PAGE> 15

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 July 1, 1996, the Company entered into an asset purchase agreement with
Soxco, providing for the acquisition by the Company of substantially all of the
natural gas and oil properties and related assets of Soxco, representing
approximately 32 Bcfe of the Company's net proved reserves of 346 Bcfe as of
December 31, 1995. Soxco's natural gas and oil properties consist solely of
working interests in producing properties and developed and undeveloped acreage
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 will pay Soxco cash in the aggregate amount of $23.7 million (subject to
certain adjustments), and issue to Soxco 762,387 shares of Common Stock with an
aggregate value of $11.8 million. The cash portion of the purchase price paid in
connection with the Soxco Acquisition will be funded with the proceeds of this
Offering. In addition to the foregoing, the Company will pay Soxco a deferred
purchase price of up to $17.6 million payable in two installments, on January
31, 1997 and January 31, 1998. The amount of the deferred purchase price
installments 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. The Soxco Acquisition will close concurrently with, is conditioned
upon and is a condition to the completion of this Offering.

Under the terms of the Soxco agreement, the Company has granted three
demand and certain piggyback registration rights with respect to the shares of
Common Stock to be issued in connection with the Soxco Acquisition. Such
registration rights are subject to certain conditions and are exercisable
beginning 180 days after the date of this Prospectus.

USE OF PROCEEDS

The net proceeds to the Company from this Offering will be approximately
$87.8 million, after deducting estimated underwriting discounts and offering
expenses ($101.2 million if the Underwriters' over-allotment option is exercised
in full). Of such net proceeds, (i) approximately $64.1 million will be used to
repay outstanding indebtedness under the Company's Credit Facility and (ii)
approximately $23.7 million will be used to pay the cash portion of the Soxco
Acquisition purchase price.

The Credit Facility provides for maximum borrowings of $150 million,
subject to borrowing base limitations, on a revolving basis. At August 21, 1996,
the borrowing base was $150 million, $143 million of which was borrowed and $1.6
million of which was committed under outstanding letter of credit obligations.
The Credit Facility matures on July 1, 2000. Borrowings under the Credit
Facility bear interest, at the Company's option, at (i) a fluctuating rate equal
to the higher of the Federal Funds Rate plus 0.5% or the agent bank's prime rate
or (ii) a fixed rate equal to a quoted LIBOR rate plus a margin between 0.5% and
1.125% depending upon the amount outstanding under the Credit Facility.
Borrowings under the Credit Facility are used, together with cash generated from
operations, to fund the Company's exploration and development expenditures and
property acquisitions and to meet working capital needs. The Company financed
the $62.2 million purchase price of the TransTexas Acquisition with borrowings
under the Credit Facility. For a description of certain other terms of the
Credit Facility, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources."

15
<PAGE> 16

DIVIDEND POLICY

The Company currently intends to retain its cash for the operation and
expansion of its business, including exploration, development and acquisition
activities. The Credit Facility 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 "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and Note 2 to the Company's
Combined Financial Statements.

DILUTION

As of June 30, 1996, the pro forma net tangible book value (total tangible
assets less total liabilities) of the Company giving effect to the TransTexas
Acquisition and the Soxco Acquisition as if such transactions had been completed
as of June 30, 1996 was approximately $128.1 million, or $7.98 per share of
Common Stock. After giving effect to the receipt of $87.8 million of estimated
net proceeds from this Offering (net of estimated underwriting discounts and
commissions and offering expenses), the net tangible book value of the Common
Stock outstanding at June 30, 1996 would have been $9.74 per share, representing
an immediate increase in net tangible book value of $1.76 per share to the
existing stockholder and an immediate dilution of $5.76 per share (the
difference between the assumed initial public offering price and the net
tangible book value per share after this Offering) to persons purchasing Common
Stock at the initial public offering price. The following table illustrates such
per share dilution:

<TABLE>
<S> <C> <C>
Initial public offering price per share.................................... $15.50
Pro forma net tangible book value per share before this Offering......... $ 7.98
Increase in net tangible book value per share attributable to the sale of
Common Stock in this Offering......................................... $ 1.76
Net tangible book value per share after giving effect to this Offering..... $ 9.74
Dilution in net tangible book value to the purchasers of Common Stock
offered hereby........................................................... $ 5.76
</TABLE>

The following table sets forth, as of June 30, 1996, the number of shares
of Common Stock purchased from the Company, the total consideration paid
therefor and the average price per share paid by the existing stockholder and by
new investors:

<TABLE>
<CAPTION>
SHARES PURCHASED TOTAL CONTRIBUTION AVERAGE
--------------------- ----------------------- PRICE PER
NUMBER PERCENT AMOUNT PERCENT SHARE
---------- ------- ------------ ------- ---------
<S> <C> <C> <C> <C> <C>
Existing stockholder.................. 15,295,215 68% $111,375,000 50% $ 7.28
Management............................ 145,161 1 2,250,000 1 15.50
Soxco................................. 762,387 3 11,817,000 5 15.50
New investors......................... 6,200,000 28 96,100,000 44 15.50
---------- --- ------------ --- ------
Total....................... 22,402,763 100% $221,542,000 100% $ 9.89
========== === ============ === ======
</TABLE>

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<PAGE> 17

The foregoing computations do not include (i) 1,120,138 shares of Common
Stock (1,166,638 shares if the Underwriters' over-allotment option is exercised
in full) issuable pursuant to options that will be granted to management and
other employees upon completion of the Offering, at an exercise price per share
equal to the initial public offering price, or (ii) shares of Common Stock with
a fair market value at the time of issuance of up to $17.6 million issuable as
the deferred purchase price for the Soxco Acquisition. See "Management -- 1996
Stock Option Plan" and "Soxco Acquisition." If the foregoing calculations
assumed exercise of all such employee options, the net tangible book value per
share before this Offering would be $8.47, the net tangible book value per share
after this Offering would be $10.08 and the dilution per share to new investors
would be $5.42.

17
<PAGE> 18

CAPITALIZATION

The following table sets forth the capitalization of the Company at June
30, 1996 on a historical basis and on a pro forma basis to reflect the
TransTexas Acquisition, the Soxco Acquisition, the issuance of shares of Common
Stock to an executive officer of the Company, the sale of the shares of Common
Stock in this Offering and the application of the net proceeds therefrom to
repay debt and to pay the cash portion of the purchase price for the Soxco
Acquisition. This table should be read in conjunction with "Use of Proceeds,"
"Pro Forma Financial Information," "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the Combined Financial
Statements of the Company and the related Notes thereto included elsewhere in
this Prospectus.

<TABLE>
<CAPTION>
JUNE 30, 1996
-------------------------
HISTORICAL PRO FORMA(1)
-------- ------------
(IN THOUSANDS)
<S> <C> <C>
Long-term debt (including current maturities)...................... $ 77,853 $ 75,916
Stockholders' equity:
Preferred Stock, $.01 par value, 5,000,000 shares authorized;
no shares issued and outstanding.............................. -- --
Common Stock, $.01 par value, 50,000,000 shares
authorized; 15,295,215 shares issued and outstanding(2);
22,402,763 shares issued and outstanding, as adjusted(3)...... 153 224
Additional paid in capital......................................... 111,222 213,060
Retained Earnings.................................................. 4,943 4,943
-------- --------
Total stockholders' equity............................... 116,318 218,227
-------- --------
Total capitalization................................... $194,171 $294,143
======== ========
</TABLE>

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

(1) Gives effect to the Offering, the TransTexas Acquisition, the Soxco
Acquisition and the issuance of shares of Common Stock to the Company's
President and Chief Executive Officer, including the issuance of 7,107,548
shares of Common Stock and the application of the net proceeds of this
Offering to pay the cash portion of the purchase price of the Soxco
Acquisition and to repay a portion of the Company's outstanding indebtedness
under the Credit Facility.

(2) Reflects the number of shares issued and outstanding immediately prior to
the completion of the Offering.

(3) Does not include (i) 1,120,138 shares of Common Stock (1,166,638 shares if
the Underwriters' over-allotment option is exercised in full) issuable
pursuant to options to purchase Common Stock that will be granted to
management and other employees upon completion of the Offering or (ii)
shares of Common Stock with a fair market value at the time of issuance of
up to $17.6 million issuable as the deferred purchase price for the Soxco
Acquisition. See "Management -- 1996 Stock Option Plan" and "Soxco
Acquisition."

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<PAGE> 19

SELECTED HISTORICAL FINANCIAL DATA

The following table sets forth selected combined historical financial data
for the Company as of and for each of the periods indicated. The financial data
for each of the five years ended December 31, 1995 are derived from the
financial statements for the Company audited by Arthur Andersen LLP, the
Company's independent public accountants. The financial data for the six months
ended June 30, 1995 and 1996 are derived from the Company's unaudited financial
statements, and in the opinion of management, include all adjustments (which
consist only of normal recurring adjustments) necessary for a fair presentation
of the financial position and results of operations of the Company for such
interim periods. The results for the six months ended June 30, 1996 are not
necessarily indicative of results for the full year. The following data should
be read in conjunction with "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and the Company's financial statements
included elsewhere in this Prospectus.

<TABLE>
<CAPTION>
SIX MONTHS
ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
---------------------------------------------------- -------------------
1991 1992 1993 1994 1995 1995 1996
-------- -------- -------- -------- -------- --------- --------
(IN THOUSANDS EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues:
Natural gas and oil revenues............. $ 17,566 $ 21,980 $ 37,462 $ 41,755 $ 39,431 $ 20,324 $ 21,252
Other.................................... 1,295 841 799 467 1,778 825 535
-------- -------- -------- -------- -------- -------- --------
Total revenues..................... 18,861 22,821 38,261 42,222 41,209 21,149 21,787
-------- -------- -------- -------- -------- -------- --------
Expenses:
Lease operating.......................... 3,192 3,123 4,477 5,344 5,468 2,875 3,634
Depreciation, depletion and
amortization........................... 10,252 14,440 23,225 25,365 21,969 11,662 11,571
General and administrative, net.......... 3,460 2,840 2,454 3,460 3,486 1,754 2,702
Nonrecurring charge(1)................... -- -- -- -- 12,000 -- --
Writedown in carrying value of natural
gas and oil properties................. -- 19,697 -- -- -- -- --
-------- -------- -------- -------- -------- -------- --------
Total operating expenses........... 16,904 40,100 30,156 34,169 42,923 16,291 17,907
Income (loss) from operations.............. 1,957 (17,279) 8,105 8,053 (1,714) 4,858 3,880
Interest expense, net...................... 1,700 1,469 1,764 2,102 2,398 1,319 1,118
-------- -------- -------- -------- -------- -------- --------
Income (loss) before income taxes.......... 257 (18,748) 6,341 5,951 (4,112) 3,539 2,762
Income tax provision (benefit)............. (673) (7,440) 1,790 597 (3,809) 514 (27)
-------- -------- -------- -------- -------- -------- --------
Net income (loss).......................... $ 930 $(11,308) $ 4,551 $ 5,354 $ (303) $ 3,025 $ 2,789
======== ======== ======== ======== ======== ======== ========
Net income (loss) per share................ $ 0.06 $ (0.74) $ 0.30 $ 0.35 $ (0.02) $ 0.20 $ 0.18
Weighted average shares outstanding........ 15,295 15,295 15,295 15,295 15,295 15,295 15,295
BALANCE SHEET DATA:
Property, plant and equipment, net......... $ 92,863 $ 92,698 $127,911 $169,714 $216,678 $ 195,227 $234,211
Total assets............................... 125,491 130,154 165,031 201,678 247,496 229,359 263,842
Long-term debt............................. 34,500 40,800 46,600 65,650 71,862 72,882 77,853
Stockholder's equity....................... 40,252 48,466 65,575 88,866 103,236 92,682 116,318
</TABLE>

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

(1) Represents an accrual for a nonrecurring charge incurred in connection with
the reorganization effective in February 1996. See Note 10 of Notes to
Combined Financial Statements.

19
<PAGE> 20

PRO FORMA COMBINED FINANCIAL INFORMATION

The unaudited pro forma combined statements of operations for the year
ended December 31, 1995 and the six months ended June 30, 1996 give effect to
the TransTexas Acquisition, the Soxco Acquisition and the application of the net
proceeds of the Offering as if such transactions had been consummated as of
January 1, 1995. The unaudited pro forma combined balance sheet as of June 30,
1996 gives effect to the TransTexas Acquisition, the Soxco Acquisition and the
application of the net proceeds of the Offering as if such transactions had been
consummated as of June 30, 1996. The unaudited pro forma combined statements of
operations include certain adjustments to the historical combined statement of
operations of the Company to give effect to the acquisition of the natural gas
and oil properties.

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 dates assumed, nor is the pro forma combined financial
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, included elsewhere in the Prospectus.

20
<PAGE> 21

PRO FORMA COMBINED STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1995
(UNAUDITED)

<TABLE>
<CAPTION>
HOUSTON TRANSTEXAS SOXCO OFFERING PRO FORMA
EXPLORATION ACQUISITION ACQUISITION AND OTHER COMBINED
HISTORICAL ADJUSTMENTS ADJUSTMENTS ADJUSTMENTS AS ADJUSTED
----------- ----------- ----------- ----------- -----------
(IN THOUSANDS EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C>
REVENUES:
Natural gas and oil revenues.......... $39,431 $25,460(1) $10,372(2) $75,263
Other................................. 1,778 -- -- 1,778
------- ------- ------- -------
Total revenues................... 41,209 25,460 10,372 77,041
EXPENSES:
Lease operating....................... 5,468 4,315(1) 1,797(2) 11,580
Depreciation, depletion and
amortization....................... 21,969 16,767(3) 7,123(3) 45,859
General and administrative, net....... 3,486 --(4) 215(4) 3,701
Nonrecurring charge................... 12,000 -- -- 12,000
------- ------- ------- ------- -------
Total operating expenses......... 42,923 21,082 9,135 73,140
INCOME (LOSS) FROM OPERATIONS........... (1,714) 4,378 1,237 3,901
Interest expense, net................... 2,398 1,788(5) -- (2,003)(6) 2,183
------- ------- ------- ------- -------
Income (loss) before income taxes....... (4,112) 2,590 1,237 2,003 1,718
Provision (benefit) for federal income
taxes................................. (3,809) 906(7) 433(7) 701 (8) (1,769)
------- ------- ------- ------- -------
NET INCOME (LOSS)....................... $ (303) $ 1,684 $ 804 $ 1,302 $ 3,487
======= ======= ======= ======= =======
Pro forma net income per share.......... $ 0.16
Pro forma average shares outstanding.... 22,403
</TABLE>

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

(1) Adjustment to reflect 95% of the historical revenues and lease operating
expenses of the properties acquired from TransTexas.

(2) Adjustment to add all revenues and operating expenses related to the oil and
gas properties acquired from Soxco.

(3) Adjustment to reflect additional depreciation, depletion and amortization
for a combined full cost pool.

(4) Adjustment to general and administrative expense to reflect producing
overhead charged by Houston Exploration to Soxco. Other than this
adjustment, the Company does not expect to incur any other additional
general and administrative expenses as a result of the TransTexas
Acquisition and the Soxco Acquisition. However, the Company does expect to
incur incremental general and administrative, specifically legal and outside
professional services, expenses associated with the Company becoming a
publicly traded entity. See "Management's Discussion and Analysis of
Financial Condition and Results of Operation."

(5) Adjustment to reflect additional interest expense related to the borrowed
purchase price for the TransTexas Acquisition.

(6) Adjustment to interest expense to reflect the repayment of $64.1 million of
debt under the Credit Facility with proceeds from the Offering, excluding
any interest income that would be earned from the note receivable from the
Company's President.

(7) Adjustment to income tax expense to reflect the respective TransTexas
Acquisition and the Soxco Acquisition adjustments.

(8) Adjustment to income tax expense to reflect the Offering adjustments.

21
<PAGE> 22

PRO FORMA COMBINED STATEMENTS OF OPERATIONS
FOR THE SIX MONTHS ENDED JUNE 30, 1996
(UNAUDITED)

<TABLE>
<CAPTION>
HOUSTON TRANSTEXAS SOXCO PRO FORMA
EXPLORATION ACQUISITION ACQUISITION OFFERING COMBINED
HISTORICAL ADJUSTMENTS ADJUSTMENTS ADJUSTMENTS AS ADJUSTED
----------- ------------ ----------- ----------- -----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C>
REVENUES:
Natural gas and oil revenues.......... $21,252 $ 14,568(1) $ 5,235(2) $41,055
Other................................. 535 -- -- 535
------- ------ ------ -------
Total revenues................... 21,787 14,568 5,235 41,590
EXPENSES:
Lease operating....................... 3,634 2,605(1) 797(2) 7,036
Depreciation, depletion and
amortization....................... 11,571 6,180(3) 2,573(3) 20,324
General and administrative, net....... 2,702 --(4) 94(4) 2,796
------- ------ ------ ----- -------
Total operating expenses......... 17,907 8,785 3,464 30,156
INCOME FROM OPERATIONS.................. 3,880 5,783 1,771 11,434
Interest expense, net................... 1,118 699(5) -- (832)(6) 985
------- ------ ------ ----- -------
Income before income taxes.............. 2,762 5,084 1,771 832 10,449
Provision (benefit) for federal income
taxes................................. (27) 1,779(7) 620(7) 291 (8) 2,663
------- ------ ------ ----- -------
NET INCOME.............................. $ 2,789 $ 3,305 $ 1,151 $ 541 $ 7,786
======= ====== ====== ===== =======
Pro forma net income per share.......... $ 0.35
Pro forma average shares outstanding.... 22,403
</TABLE>

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

(1) Adjustment to reflect 95% of the historical revenues and lease operating
expenses of the properties acquired from TransTexas.

(2) Adjustment to add all revenues and operating expenses related to the oil and
gas properties acquired from Soxco.

(3) Adjustment to reflect additional depreciation, depletion and amortization
for a combined full cost pool.

(5) Adjustment to reflect additional interest expense related to the borrowed
purchase price for the TransTexas Acquisition.

(6) Adjustment to interest expense to reflect the repayment of the $64.1 million
of debt under the Credit Facility with proceeds from the Offering, excluding
any interest income that would be earned from the note receivable from the
Company's President.

(7) Adjustment to income tax expense to reflect the respective TransTexas
Acquisition and the Soxco Acquisition adjustments.

(8) Adjustment to income tax expense to reflect the Offering adjustments.

22
<PAGE> 23

PRO FORMA COMBINED BALANCE SHEETS
AS OF JUNE 30, 1996
(UNAUDITED)

<TABLE>
<CAPTION>
HOUSTON TRANSTEXAS SOXCO OFFERING PRO FORMA
EXPLORATION ACQUISITION ACQUISITION PRO FORMA AND OTHER COMBINED
HISTORICAL ADJUSTMENTS ADJUSTMENTS COMBINED ADJUSTMENTS AS ADJUSTED
----------- ----------- ----------- --------- ----------- -----------
($ IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
ASSETS:
Current assets........... $ 27,679 $ -- $ 134(1) $ 27,813 -- $ 27,813
Net property, plant and
equipment............. 234,211 59,095(2) 44,208(3) 337,514 2,250 (4) 339,764
Other assets............. 1,952 3,110(5) -- 5,062 -- 5,062
-------- ------- ------- -------- -------- --------
TOTAL ASSETS........ $ 263,842 $62,205 $44,342 $370,389 $ 2,250 $ 372,639
======== ======= ======= ======== ======== ========
LIABILITIES:
Current liabilities...... 19,652 -- 23,700(6) 43,352 (23,700)(8) 19,652
Long-term debt........... 77,853 62,205(7) -- 140,058 (64,142)(8) 75,916
Deferred federal income
tax................... 49,885 -- -- 49,885 -- 49,885
Other deferred
liabilities........... 134 -- 8,825(9) 8,959 -- 8,959
-------- ------- ------- -------- -------- --------
TOTAL LIABILITIES... 147,524 62,205 32,525 242,254 (87,842) 154,412
STOCKHOLDER'S EQUITY:
Common stock............. 153(10) -- 8(11) 161 62 (12) 224
1 (4)
Additional paid-in
capital............... 111,222(10) -- 11,809(11) 123,031 87,780 (12) 213,060
2,249 (4)
Retained earnings........ 4,943 -- -- 4,943 -- 4,943
-------- ------- ------- -------- -------- --------
TOTAL STOCKHOLDER'S
EQUITY........... 116,318 -- 11,817 128,135 90,092 218,227
-------- ------- ------- -------- -------- --------
TOTAL LIABILITIES
AND STOCKHOLDER'S
EQUITY........... $ 263,842 $62,205 $44,342 $370,389 $ 2,250 $ 372,639
======== ======= ======= ======== ======== ========
</TABLE>

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

(1) Adjustment to reflect the assumption of Soxco's tubular inventory and gas
imbalance receivable.

(2) Adjustment to reflect the amount of the purchase price of $62.2 million
($59.1 million after giving effect to the exercise of the Company
President's purchase option) for the TransTexas Acquisition.

(3) Adjustment to reflect the amount of the purchase price for the Soxco
Acquisition allocated to natural gas and oil properties as follows: (i)
$31.9 million for proved reserves, (ii) $3.5 million for leasehold
interests and (iii) $8.8 million for the minimum deferred purchase price.

(4) Adjustment to reflect the issuance of 145,161 shares of Common Stock to the
Company's President in exchange for certain after program-payout working
interests based upon the initial public offering price of $15.50 per share.

(5) Adjustment to reflect a note receivable from the Company's President for
his purchase of a 5% working interest in properties acquired by the Company
in the TransTexas Acquisition.

(6) Adjustment to reflect the accrual of $23.7 million for the cash portion of
the purchase price for the Soxco Acquisition.

(7) Adjustment to reflect incremental borrowings under the Credit Facility for
the TransTexas Acquisition.

(8) Adjustment to reflect use of proceeds: (i) payment of the $23.7 million
cash portion of the purchase price for the Soxco Acquisition and (ii)
repayment of $64.1 million of debt under the Credit Facility.

(9) Adjustment to reflect the minimum deferred purchase price for the Soxco
Acquisition.

(10) Reflects the number of shares issued and outstanding immediately prior to
the completion of the Offering.

(11) Adjustment to reflect the issuance of 762,387 shares of Common Stock to
Soxco, based upon the initial public offering price of $15.50 per share.

(12) Adjustment to reflect the estimated net proceeds from the sale of 6,200,000
shares of Common Stock in this Offering.

23
<PAGE> 24

PRO FORMA PRODUCTION DATA
(MMCFE)

The following table summarizes the pro forma production for the year ended
December 31, 1995 and the six months ended June 30, 1995 and 1996, reflecting
the actual production of the Company and the pro forma production from the
properties acquired in the TransTexas Acquisition and to be acquired in the
Soxco Acquisition. This table gives effect to the TransTexas Acquisition and the
Soxco Acquisition as if such transactions had been consummated as of January 1,
1995.

<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED JUNE 30,
DECEMBER 31, -----------------
1995 1995 1996
------------ ------ ------
<S> <C> <C> <C>
Houston Exploration........................................ 21,677 11,012 11,744
TransTexas Acquisition..................................... 18,592 10,238 7,275
Soxco Acquisition.......................................... 6,451 3,577 2,243
------ ------ ------
Total (Mmcfe).................................... 46,720 24,827 21,262
====== ====== ======
</TABLE>

24
<PAGE> 25

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 the six
months ended June 30, 1995 and 1996 and each year of the three-year period ended
December 31, 1995. The Company's historical combined financial statements and
notes thereto included elsewhere in this Prospectus 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 has focused since its inception 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. At December
31, 1995, the Company had historical net proved reserves of 201 Bcfe, 97% of
which were natural gas and 83% 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.

Although the Company will incur additional general and administrative
expenses as a result of becoming a public company and will experience the
elimination of certain overhead reimbursements from Soxco, the Company believes
that cost savings resulting from the February 1996 reorganization, the increase
in its interest in certain Gulf of Mexico properties resulting from the Soxco
Acquisition and expected production increases as recently drilled wells come
on-line will result in lower general and administrative costs as compared to
recent historical levels on a per unit of production basis. Further, primarily
as a result of the small number of working interest and royalty owners, the
TransTexas assets will not require any material increase in general and
administrative costs, further reducing such expenses on a per unit of production
basis. In addition, the Company believes that the geographic focus of its
operations will allow the Company to achieve significant reserve and production
growth without materially increasing the existing level of general and
administrative expenses.

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 underdeliveries

25
<PAGE> 26

are reflected as assets. Production imbalances are valued using market value.
Management does not believe that the Company has any material overproduced gas
balances.

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 68,900 Mmbtu per day (66,300
Mcf/d) of natural gas production for September through March 1997 at a weighted
average price of $2.04 per Mmbtu, before transaction and transportation costs.
The Company has also entered into contracts covering an average of approximately
49,600 Mmbtu per day (47,700 Mcf/d) for April through October 1997 at a weighted
average price of $1.93 per Mmbtu and contracts covering an average of
approximately 22,600 Mmbtu per day (21,800 Mcf/d) for November 1997 through
March 1998 at a weighted average price of $1.91 per Mmbtu, in each case before
transaction and transportation costs. During July 1996, net production from the
Company's properties averaged approximately 122,200 Mcfe per day.

Prior to the completion of this Offering, Houston Exploration has been
included in the consolidated federal income tax return of its parent Brooklyn
Union. Under the Company's tax sharing agreement with Brooklyn Union, the
Company receives from, or pays to, Brooklyn Union an amount equal to the
reduction or increase in the currently payable federal income taxes of 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 by the Company on a separate return basis. After completion of this
Offering, the Company will no longer be included in Brooklyn Union's
consolidated federal income tax return. Thus, any reduction in currently payable
federal income taxes that cannot be utilized by the Company on a separate return
basis will now have to be deferred or, in the case of certain tax credits,
possibly forgone.

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 accrued 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. In February 1996, certain of these individuals
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 of $35 million and punitive damages
in excess of $70 million. FRI has agreed to indemnify the Company against any
damages awarded in the suit. In addition, Holdings, the subsidiary of Brooklyn
Union that holds all of the currently outstanding Common Stock of the Company,
has agreed to indemnify the Company against any such liabilities, and has agreed
to pledge all of its holdings of Common Stock to secure such indemnification
obligation. Brooklyn Union has announced its intention to establish a
publicly-traded holding company which would hold all of the stock of Brooklyn
Union. If the holding company is established, the pledge may be released at the
option of Holdings if the obligations of Holdings under such indemnification
agreement are assumed or guaranteed by the holding company. As a result of such
arrangements, the Company believes that it will not be required to pay any
damages resulting from such suit, even if a judgment adverse to the Company is
rendered in the suit. However, the Company would incur an additional

26
<PAGE> 27

non-cash charge in addition to the $12 million charge previously taken by the
Company in the event it is determined that the remuneration payable to the
former employees of FRI and any damages from the suit exceed $12 million, which
would have the effect of reducing the Company's reported income (or resulting in
or increasing a loss) in the period in which any such additional charge is
determined. See "Risk Factors -- Pending Legal Proceedings" and
"Business -- Legal Proceedings."

RESULTS OF OPERATIONS

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

<TABLE>
<CAPTION>
SIX MONTHS
ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------ ---------------
1993 1994 1995 1995 1996
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
Production:
Natural gas (Mmcf)............................... 22,555 22,437 21,077 10,604 11,498
Oil (Mbbls)...................................... 101 102 100 68 41
Total (Mmcfe).................................... 23,161 23,049 21,677 11,012 11,744
Average sales prices:
Natural gas (per Mcf)(1)......................... $ 1.58 $ 1.79 $ 1.79 $ 1.81 $ 1.78
Oil (per Bbl).................................... 16.96 15.85 16.54 16.97 18.93
Expenses (per Mcfe):
Lease operating.................................. $ 0.19 $ 0.23 $ 0.25 $ 0.26 $ 0.31
Depreciation, depletion and amortization......... 1.00 1.10 1.01 1.06 0.99
General and administrative, net.................. 0.11 0.15 0.16 0.16 0.23
</TABLE>

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

(1) Reflects the effects of hedging. Absent the effects of hedging, average
realized natural gas prices would have been $2.06, $1.83 and $1.53 per Mcf
for the years ended December 31, 1993, 1994, and 1995, respectively, and
$1.47 and $2.31 per Mcf for the six months ended June 30, 1995 and 1996,
respectively.

RECENT FINANCIAL AND OPERATING RESULTS

COMPARISON OF SIX MONTHS ENDED JUNE 30, 1995 AND 1996

General. Houston Exploration's production increased 7% from 11,012 Mmcfe
for the first six months of 1995 to 11,744 Mmcfe for the first six months of
1996. The increase in production can be attributed to shut-in production in the
first quarter of 1995 due to severely depressed natural gas prices and the
commencement of production in 1996 from additional properties.

Natural Gas and Oil Revenues. Natural gas and oil revenues increased 5%
from $20.3 million for the first six months of 1995 to $21.3 million for the
first six months of 1996 as a result of the 7% increase in production, offset in
part by a decrease in average realized natural gas prices of 2% from $1.81 per
Mcf in the first six months of 1995 to $1.78 per Mcf in the first six months of
1996.

As a result of hedging activities, the Company realized an average gas
price of $1.78 per Mcf for the first six months of 1996, compared to an average
price of $2.31 per Mcf that otherwise would have been received resulting in a
$6.0 million decrease in natural gas revenues for the six month period. For the
first six months of 1995, the average realized gas price was $1.81 per Mcf
compared to an unhedged average gas price of $1.47, resulting in an increase to
natural gas revenues of $3.5 million for the six month period.

Lease Operating Expenses. Lease operating expenses increased 24% from $2.9
million for the first six months of 1995 to $3.6 million for the first six
months of 1996. On an Mcfe basis, lease operating expenses increased 19% from
$0.26 for the first six months of 1995 to $0.31 for the first

27
<PAGE> 28

six months of 1996. The increase in costs for the first six months of 1996
reflects the higher initial operating costs associated with bringing new
facilities and wells on line.

Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense remained relatively flat for both the first six months of
1995 and the first six months of 1996. Depreciation, depletion and amortization
expense per Mcfe decreased from $1.06 for the first six months of 1995 to $0.99
for the first six months of 1996. The lower rate for the first six months of
1996 reflects added reserves.

General and Administrative Expenses. General and administrative expenses,
net of overhead reimbursements received from other working interest owners of
$0.7 million and $0.3 million for the first six months of 1995 and 1996,
respectively, increased 50% from $1.8 million for the first six months of 1995
to $2.7 million for the first six months of 1996. The Company capitalized
general and administrative expenses directly related to oil and gas exploration
and development activities of $1.8 million and $2.4 million, respectively for
the first six months of 1995 and 1996. The increase in net general and
administrative expenses for the first six months of 1996 is a result of certain
one-time expenses incurred in conjunction with the combination of offshore and
onshore operations. On an Mcfe basis, general and administrative expenses
increased from $0.16 for the first six months of 1995 to $0.23 for the first six
months of 1996.

Income Tax Provision. Income tax expense decreased from an expense of $0.5
million for the first six months of 1995 to a benefit of $0.03 million for the
first six months of 1996 due to the utilization of incremental Section 29 tax
credits associated with increased production from certain onshore properties.

Net Income. Net income decreased slightly from $3.0 million for the first
six months of 1995 to $2.8 million for the first six months of 1996. Although
production increased for the first six months of 1996 as compared to the first
six months of 1995, operating income decreased from $4.9 million for the first
six months of 1995 to $3.9 million for the first six months of 1996 as a result
of a decline in natural gas revenues of $6.0 million due to hedging activities,
higher lease operating costs associated with new properties and an increase in
general and administrative expense during the first six months of 1996 as
compared to the first six months in 1995.

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 in 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. The Company anticipates improvement in production performance as its
1994 exploratory successes, together with 1995 development wells, are brought on
line in 1996.

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.

28
<PAGE> 29

Lease Operating Expenses. Lease operating expense 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 accrued 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 10 to
Notes to 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.

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.

COMPARISON OF YEARS ENDED DECEMBER 31, 1993 AND 1994

General. The Company's production remained flat with only a slight decrease
from 23,161 Mmcfe in 1993 to 23,049 Mmcfe in 1994. Offshore production declined
by approximately 5,000 Mmcfe while onshore production increased by approximately
the same amount. Both onshore and offshore properties were voluntarily shut-in
during October and November 1994 due to severely depressed natural gas prices.
This voluntary shut-in included the Matagorda Island 600 complex, a key offshore
producing property. The net onshore production increases were attributable to
the acquisition of properties in the Arkoma Basin, West Virginia and the Willow
Springs field in East Texas in 1994, combined with a full year of production
from properties acquired in the Arkoma Basin in 1993.

Natural Gas and Oil Revenues. Natural gas and oil revenues increased 11%
from $37.5 million in 1993 to $41.8 million in 1994. Production of natural gas
decreased from 22,555 Mmcf in 1993 to 22,437 Mmcf in 1994, while the average net
realized price of natural gas increased 13% from $1.58 per Mcf in 1993 to $1.79
per Mcf for the year ended December 31, 1994. Average net realized natural gas
prices would have been $2.06 per Mcf in 1993 and $1.83 per Mcf in 1994 if hedges
had not been in place during such periods. Hedging activities reduced natural
gas revenues by $10.7 million in 1993 as compared to a reduction of $0.8 million
in 1994.

Lease Operating Expenses. Lease operating expenses increased by 19% from
$4.5 million in 1993 to $5.3 million in 1994. On an Mcfe basis, lease operating
costs increased by 21% from $0.19 in

29
<PAGE> 30

1993 to $0.23 in 1994. The cost increase and the per unit increase reflects the
increase in onshore operating costs from acquired properties.

Depreciation, Depletion and Amortization. Total depreciation, depletion and
amortization expense increased by 9% from $23.2 million in 1993 to $25.4 million
in 1994. Depreciation, depletion and amortization expense per Mcfe increased 10%
from $1.00 in 1993 to $1.10 in 1994 due to increases in finding costs during
1994.

General and Administrative Expenses. General and administrative expenses,
net of overhead reimbursements received by the Company from other working
interest owners of $1.2 million and $1.3 million in 1993 and 1994, respectively,
increased 40% from $2.5 million in 1993 to $3.5 million in 1994. The increase
was a result of a decrease, beginning in the fourth quarter of 1993, in overhead
reimbursements received from a joint interest partner. The Company capitalized
general and administrative costs directly related to gas and oil exploration and
development activities of $4.4 million and $3.9 million for years ended 1993 and
1994.

Income Tax Provision. The provision for income taxes decreased from a
provision of $1.8 million in 1993 to $0.6 million in 1994 due to a decrease in
the effective tax rate from 28% in 1993 to 10% in 1994 as a result of the
utilization of additional Section 29 tax credits and an increase in percentage
depletion.

Net Income. Operating income in 1994 remained flat at $8.1 million as
compared to 1993. The Company's income tax provision decreased from $1.8 million
in 1993 to $0.6 million in 1994 and as a result, net income increased from $4.6
million in 1993 to $5.4 million in 1994.

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
$8.0 million in working capital as of June 30, 1996.

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

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------------------
1992 1993 1994 1995
------- ------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Net cash provided by operating activities........ $ 7,396 $40,896 $26,074 $55,778
Net borrowings under Credit Facility............. 6,300 5,800 19,050 6,212
Capital contributions by Brooklyn Union.......... 21,047 12,558 18,021 6,873
</TABLE>

The Company's net cash provided by operating activities for the first six
months of 1996 was $16.8 million compared to $29.3 million for the same period
of 1995.

30
<PAGE> 31

The Company's capital expenditures for each of the past four years and the
six months ended June 30, 1996 are reflected in the following table:

<TABLE>
<CAPTION>
SIX MONTHS
YEARS ENDED DECEMBER 31, ENDED
------------------------------------------- JUNE 30,
1992 1993 1994 1995 1996
------- ------- ------- ------- ----------
(IN THOUSANDS) (UNAUDITED)
<S> <C> <C> <C> <C> <C>
OFFSHORE
Acquisitions of properties.......... $ 7,472 $ 9,796 $12,890 $18,236 $ 5,137
Development......................... 12,146 10,058 9,351 32,228 10,504
Exploration......................... 3,930 5,983 15,370 6,355 10,073
------- ------- ------- ------- -------
23,548 25,837 37,611 56,819 25,714
ONSHORE
Acquisitions of properties.......... $ 3,519 $31,446 $22,886 $ 2,803 $ 577
Development......................... 5,463 1,274 2,439 8,935 3,496
Exploration......................... -- -- 2,060 869 216
------- ------- ------- ------- -------
8,982 32,720 27,385 12,607 4,289
------- ------- ------- ------- -------
Total..................... $32,530 $58,557 $64,996 $69,426 $ 30,003
======= ======= ======= ======= =======
</TABLE>

The Company's capital expenditure budget for 1996 includes $28 million and
$35 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 1996. 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 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 August 21, 1996, the borrowing base was
$150 million, $143 million of which was borrowed and $1.6 million was committed
under outstanding letter of credit obligations. The Credit Facility matures on
July 1, 2000. The Credit Facility is secured by a pledge of all of the Company's
outstanding capital stock; however, upon the closing of the Offering the shares
will be released and the Credit Facility will be 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
$95 million plus 50% of net income (excluding net losses) and 75% of net equity
proceeds and (ii) a total debt to capitalization ratio of less than 60% prior to
the Offering and 55% thereafter. 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 in its discretion in accordance with

31
<PAGE> 32

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 "Dividend Policy."

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

32
<PAGE> 33
BUSINESS

OVERVIEW

Houston Exploration 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, 1995, the Company had net proved reserves
of 346 Bcfe. Approximately 98% of the Company's net proved reserves on such date
were natural gas and approximately 73% of proved reserves were classified as
proved developed. The Company operates approximately 82% of its Gulf of Mexico
production and approximately 92% of its onshore production.

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 five additional exploratory wells in the Gulf of Mexico
in the remainder of 1996, 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 49 lease
blocks, representing 230,531 gross (147,180 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 16 of these lease blocks and a 50% or greater
working interest in 17 other lease blocks. During 1994 and 1995, the Company
drilled

33
<PAGE> 34

five successful exploratory wells and 11 successful development wells in the
Gulf of Mexico, resulting in added net proved reserves of approximately 61 Bcfe.
During the first half of 1996, the Company drilled three successful exploratory
wells and one successful development well. The Company anticipates that
approximately $50 million of its $63 million 1996 capital expenditure budget
(excluding acquisitions) will be spent on offshore projects. 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 July
1996, net production from the Company's Gulf of Mexico properties averaged
approximately 52,900 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 63% of its net proved reserves as of December 31, 1995. Since the
beginning of 1994, the Company has drilled or participated in the drilling of 25
successful development wells and three successful exploratory wells onshore. The
Company plans to drill 16 development wells onshore during the remainder of
1996. 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 1,060 gross (657 net) wells, and 138,385 gross
(93,419 net) acres. The Company anticipates that approximately $13 million of
its $63 million 1996 capital expenditure budget (excluding acquisitions) will be
spent on onshore projects. 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 July
1996, net production from the Company's onshore properties averaged
approximately 69,300 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 1,100 square miles of 3-D seismic data,
including 3-D seismic surveys on 29 of its offshore lease blocks and on possible
lease and acquisition prospects, and 60,500 linear miles of 2-D seismic data on
its offshore properties. The Company has 12 geologists/geophysicists with
average industry experience of approximately 30 years and five 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 drillbit, 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. The Company
recently acquired significant onshore properties in South Texas and has agreed
to acquire additional interests in 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 82% of its Gulf of Mexico production and
approximately 92% of its onshore production. Houston Exploration operates 16
platforms and 64 wells in the Gulf of Mexico and 924 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 pro forma lease operating expense
of $0.25 per Mcfe of production and pro forma general and administrative expense
of $0.08 per Mcfe of production for the year ended December 31, 1995.

34
<PAGE> 35

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.

GULF OF MEXICO PROPERTIES

The Company holds interests in 49 offshore blocks, of which 28 have current
operations, and operates 22 of these blocks, accounting for approximately 82% 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, 1995, representing 97% of the
Company's Gulf of Mexico proved reserves and 90% of its offshore production:

<TABLE>
<CAPTION>
PRO FORMA PROVED RESERVES AT
DECEMBER 31, 1995(1)
AVERAGE -----------------------------
WORKING GAS OIL TOTAL
FIELD INTEREST (MMCF) (MBBLS) (MMCFE) OPERATOR
- ---------------------------------------- ------- ------- ------- ------- ------------
<S> <C> <C> <C> <C> <C>
Mustang Island Block 858................ 82.5% 21,476 523 24,614 Company
Mustang Island Block 807................ 100.0% 13,190 66 13,586 Company
Mustang Island Block 759................ 25.0% 12,997 50 13,297 Third Party
West Cameron Block 76/77/60/61 Unit..... 10.9% 11,500 48 11,788 Third Party
East Cameron Block 82/83................ 97.8% 9,616 43 9,874 Company
Mustang Island Block 785................ 71.3% 9,363 2 9,375 Company
Matagorda Island Block 650/672/671...... 45.4% 7,946 13 8,024 Company
Matagorda Island Block 651.............. 79.6% 7,491 1 7,497 Company
Vermilion Block 203..................... 50.0% 6,532 52 6,844 Company
Galveston Block 272/252................. 43.9% 5,256 10 5,316 Company
South Marsh Island Block 252/253........ 50.0% 5,129 5 5,159 Company
Eugene Island Block 48.................. 86.5% 4,315 80 4,795 Company
Mustang Island Block 738................ 49.9% 3,444 34 3,648 Company
</TABLE>

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

(1) Gives effect to the Soxco Acquisition as if such transaction had been
consummated at December 31, 1995.

During 1994 and 1995, the Company drilled five successful exploratory wells
and 11 successful development wells on its Gulf of Mexico properties. During
this same period, the Company drilled three exploratory wells and one
development well that were not successful. Capital spending associated with the
Company's Gulf of Mexico properties during 1994 and 1995 was $94.4 million,
including $21.7 million for exploratory drilling, $41.6 million for development
drilling and $31.1 million for acquisitions.

The Company has drilled three successful exploratory wells and one
successful development well on its Gulf of Mexico properties in 1996 to date.
During the same period, the Company drilled two exploratory wells that were not
successful. During the remainder of 1996, the Company intends to focus on
exploratory drilling and plans to drill at least five exploratory wells, along
with limited development drilling. The Company's exploratory projects are
located in East Cameron Block 185,

35
<PAGE> 36

West Bayou Sale, Matagorda Island Block 651, Mustang Island Block 785, Matagorda
Island Block 680 and Mustang Island Block 736. The Company's development
projects are located in Mustang Island Block 807 and Mustang Island Block 759.
Capital spending for offshore projects during 1996 is budgeted at approximately
$50 million, including $28 million for exploration and $22 million for
development and platform construction. The following is a summary description of
the Company's exploration and development activity since 1994 and significant
additional activity that is currently planned during the remainder of 1996. The
Company is the operator of each of these properties except for Mustang Island
Block 736 and Mustang Island Block 759.

Mustang Island Block 858. The Company acquired a 50% working interest in
Mustang Island Block 858 in September 1990. The Company will acquire an
additional 32.5% working interest in this block in the Soxco Acquisition. The
Company began drilling an exploratory well in Mustang Island Block 858 during
late 1993. The well was successfully completed in 1994. The Company contracted
for a proprietary 3-D seismic survey across the block to assist in planning its
development activity. The Company drilled and completed two development wells on
Mustang Island Block 858 during 1995, and installed production facilities in
1996. Initial production began the first week of July 1996. The three completed
wells are producing at a combined rate of 19,000 Mcf/d (12,400 Mcf/d net) of gas
and 450 Bbls/d (300 Bbls/d net) of condensate. The Company owns substantial
leasehold interests in adjacent blocks and is contemplating additional
exploratory and development drilling.

Mustang Island Block 807. The Company acquired a 25% working interest in
Mustang Island Block 807 in September 1993. An exploratory well was successfully
drilled in June 1994. In December 1994, the Company purchased the remaining 75%
working interest in the block. The Company intends to drill an additional
development well and begin platform construction during the fourth quarter of
1996, and to commence initial production during the first quarter of 1997.

Mustang Island Block 759. The Company acquired a 25% working interest in
Mustang Island Block 759 in September 1993. An exploratory well was successfully
drilled in December 1993, and development drilling commenced in May 1994 with
the drilling of three development wells. In December 1994, an exploratory well
was successfully drilled to test a new separate fault block not tested by the
previous wells, although the well did not reach its targeted objective because
of drilling difficulties. During the fourth quarter of 1995 an additional
exploratory well was drilled to reach the targeted objective of the December
1994 well. The Company completed the drilling of one development well on Mustang
Island Block 759 in early 1996. The "A" Platform and the "B" Platform were
constructed and installed in early 1995, and four wells on the "A" Platform were
completed and two wells on the "B" Platform were completed. Initial production
began in late July 1995. The field is currently producing 24,000 Mcf/d (4,800
Mcf/d net) of gas and 140 Bbls/d (29 Bbls/d net) of condensate. The Company
intends to participate in additional development drilling in Mustang Island
Block 759 to further develop this property.

East Cameron 82/83. The Company purchased a 100% working interest in East
Cameron Blocks 82, 83, 44 and 49 in February 1995. The property currently has
two platforms, one on Block 82 and one on Block 44. The wells on Block 82 are
currently awaiting a workover program to commence early in the fourth quarter of
1996. In connection with its purchase of the field, the Company committed to
drill two exploratory wells, a shallow well to be drilled within 90 days of the
closing of the acquisition and a deep well to be drilled after completion of the
shallow well. The Company completed the shallow well in May 1995. The well (in
which the Company has a 95% working interest) commenced production in September
1995, and is currently producing 6,750 Mcf/d (4,300 Mcf/d net) of gas and 36
Bbls/d (23 Bbls/d net) of condensate. The Company drilled the deep well during
the first quarter of 1996 and encountered no commercial amounts of hydrocarbons
in the prospective deep zone, but the well is being completed in a shallower
productive zone.

Mustang Island Block 785. The Company holds a 71.3% working interest in
Mustang Island Block 785, which currently has a platform and four producing
wells. The Company is preparing to

36
<PAGE> 37

drill a well in an untested fault block to test objectives that have been found
productive to the west of Mustang Island Block 785.

Matagorda Island Block 651. The Company holds a 79.6% working interest in
Matagorda Island Block 651, which currently has a platform and three producing
wells. The Company is preparing to drill a well in an untested fault block to
test objectives that are productive in its adjacent Matagorda Island Block 650
field. The Company plans to begin drilling this well in the third quarter of
1996.

Vermilion Block 203. The Company acquired a 50% working interest in
Vermilion Block 203 in March 1991. The Company successfully drilled an
exploratory well in February 1994. The Company contracted for a proprietary 3-D
seismic survey across the block in May 1994 to assist in planning its
exploration and development activities. The Company drilled three development
wells on Vermilion Block 203 in 1995. Initial production began in the first
quarter of 1996. The Company drilled a deep well during the first quarter of
1996 and encountered no commercial amounts of hydrocarbons. The field is
currently producing 22,000 Mcf/d (8,580 Mcf/d net) of gas and 40 Bbls/d (15
Bbls/d net) of oil. The Company has identified several untested fault blocks in
Vermilion Block 203 through its 3-D seismic survey which it intends to begin
exploring in 1996 or thereafter.

East Cameron Block 185. The Company acquired a 100% working interest in
East Cameron Block 185 in March 1996. The property has one platform currently
producing approximately 1,800 Mcf/d of gas. In connection with its purchase of
the field, the Company committed to drill two exploratory wells. The Company has
drilled one of the exploratory wells, which did not encounter commercial amounts
of hydrocarbons. The Company plans to begin drilling the second exploratory well
in the third quarter of 1996.

Matagorda Island Block 680. The Company holds a 100% working interest in
Matagorda Island Block 680. The Company is preparing to drill an exploratory
well to test objectives that have been found productive to the north and west of
the property. The Company plans to begin drilling this well in the third quarter
of 1996.

Mustang Island Block 736. The Company acquired a 50% working interest in
Mustang Island Block 736 in September 1993. The Company intends to drill a well
in Mustang Island Block 736 to test objectives that have been found productive
to the southwest of Mustang Island Block 759.

West Bayou Sale. The Company holds a 25% working interest in a West Bayou
Sale prospect located in South Louisiana that is adjacent to several productive
areas. The Company is currently participating in a deep exploratory test on this
prospect.

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 1,060 gross (657 net) wells,
92% of which the Company is the operator of record, and 138,385 gross (93,419
net) acres.

37
<PAGE> 38

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, 1995, representing 98% of the Company's
onshore reserves:

<TABLE>
<CAPTION>
PRO FORMA PROVED RESERVES AT
DECEMBER 31, 1995(1)
AVERAGE -----------------------------
WORKING GAS OIL TOTAL
FIELD INTEREST (MMCF) (MBBLS) (MMCFE)
- ---------------------------------------------------- ------- ------- ------- -------
<S> <C> <C> <C> <C>
Charco Area......................................... 95% 112,476 49 112,770
Chismville/Massard Field............................ 73% 48,776 -- 48,776
Willow Springs and Surrounding Fields............... 53% 16,575 137 17,397
Wilburton, Panola and Surrounding Fields............ 23% 13,663 -- 13,663
Appalachian Area.................................... 60% 21,068 52 21,380
</TABLE>

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

(1) Gives effect to the TransTexas Acquisition as if such transaction had been
consummated at December 31, 1995.

During 1994 and 1995, the Company participated in the drilling of 18
successful development and three successful exploratory wells on its onshore
properties. During this same period, the Company participated in the drilling of
seven development wells and one exploratory well that were not successful.
Capital spending associated with the Company's onshore drilling program during
1994 and 1995 was approximately $14.3 million, substantially all of which was
used for development drilling.

Since the beginning of 1996, the Company has drilled six successful
development wells in Arkansas and one successful development well in West
Virginia. The Company participated in two unsuccessful exploratory wells during
the same period. For the remainder of 1996 the Company has budgeted funds to
drill an additional two wells on the South Texas properties acquired in the
TransTexas Acquisition, three wells in East Texas, six wells in Arkansas, and
five wells in Oklahoma. The total 1996 capital spending for onshore projects is
budgeted at approximately $13 million with the majority being spent on
development projects. 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 156 active wells on such properties, all of which are operated by
the Company. During July 1996, the Company's Charco Area properties had average
production of 39,000 Mcfe/d net to the Company. The Company has contracted for a
3-D seismic survey covering all of its Charco Area properties. The Company
anticipates undertaking an active drilling program beginning in the fourth
quarter of 1996 to fully exploit this property.

Chismville/Massard Field. The Chismville/Massard Field is located in Logan
and Sebastian Counties, Arkansas. The Company owns working interests in
approximately 75 active wells, of which it operates 58 wells. Working interests
range from 11% to 100% and average approximately 73%. During July 1996,
production averaged 12,200 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 44 active wells, of which
it operates 17 wells. Working interests range from 3% to 100% and average
approximately 53%. During July 1996, production averaged 3,800 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 38
active wells, of which it

38
<PAGE> 39

operates 12 wells. Working interests range from 1% to 63% and average
approximately 23%. During July 1996, production averaged 4,000 Mcfe/d net to the
Company.

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, 660 of which are operated by the
Company. Working interests range from 6% to 100% and average approximately 60%.
During July 1996, production averaged 4,600 Mcfe/d net to the Company.

ADDITIONAL FUTURE PROJECTS

In addition to the properties described above, the Company has accumulated
a large inventory of offshore leases comprised of 100,024 undeveloped gross
(73,351 pro forma net) acres. These leases are under review by the Company's
geologists and geophysicists based upon 3-D seismic data acquired in 1994 and
1995. 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.

NATURAL GAS AND OIL RESERVES

The following table summarizes the estimates of the Company's historical
net proved reserves as of December 31, 1994 and 1995 and pro forma reserves as
of December 31, 1995, and the present values attributable to these reserves at
such dates. The reserve data and present values as of December 31, 1994 and 1995
were prepared by Ryder Scott Company ("Ryder Scott"), Netherland, Sewell &
Associates, Inc. ("NSA"), Huddleston & Co., Inc. ("Huddleston") and Miller and
Lents, Ltd. ("Miller and Lents"), independent petroleum engineering consultants.
The pro forma December 31, 1995 reserve data and present values are presented to
include the TransTexas Acquisition and the Soxco Acquisition. Summaries of the
December 31, 1995 reserve reports and the letters of Ryder Scott, NSA,
Huddleston and Miller and Lents with respect thereto are included as Appendix A
to this Prospectus.

<TABLE>
<CAPTION>
PRO FORMA
AS OF AS OF AS OF
DECEMBER 31, 1994 DECEMBER 31, 1995 DECEMBER 31, 1995
------------------------------- --------------------------------- ---------------------------------
OFFSHORE ONSHORE TOTAL OFFSHORE ONSHORE TOTAL OFFSHORE ONSHORE TOTAL
-------- -------- --------- --------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Net Proved
Reserves(1):
Natural gas (Mmcf).. 71,876 74,069 145,945 91,529 104,417 195,946 121,636 216,893 338,529
Oil (Mbbls)......... 326 310 636 665 224 889 961 273 1,234
Total (Mmcfe)....... 73,832 75,929 149,761 95,519 105,761 201,280 127,402 218,531 345,933
Present value of
future net revenues
before income taxes
(000s)(2)........... $69,721 $66,148 $ 135,869 $ 119,490 $ 87,084 $ 206,574 $ 162,730 $ 163,616 $ 326,346
Standardized measure
of discounted future
net cash flows
(000s)(3)........... $54,638 $63,796 $ 118,434 $ 93,637 $ 77,822 $ 171,459 $ 136,124 $ 145,942 $ 282,066
</TABLE>

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

(1) Ryder Scott, NSA and Huddleston prepared reserve data and present values
with respect to properties comprising approximately 60%, 34% and 6%,
respectively, of the present values attributable to the Company's Gulf of
Mexico pro forma proved reserves as of December 31, 1995. NSA and Miller and
Lents prepared reserve data and present values with respect to properties
comprising approximately 52% and 48%, respectively, of the present values
attributable to the Company's onshore pro forma proved reserves as of
December 31, 1995.

39
<PAGE> 40

(2) The present value of future net revenue 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.

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 Prospectus represents 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 revisions 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 net cash flows set forth in this Prospectus
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 "Related Party Transactions -- Transactions between
the Company and Management."

40
<PAGE> 41

DRILLING ACTIVITY

The following table sets forth the drilling activity of the Company on its
properties for the years ended December 31, 1993, 1994 and 1995 and the six
months ended June 30, 1996.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------- SIX MONTHS ENDED
1995 JUNE 30, 1996
1993 1994 --------------------------- ---------------------------
----------- ----------- PRO FORMA PRO FORMA
OFFSHORE DRILLING ACTIVITY: GROSS NET GROSS NET GROSS NET NET(1) GROSS NET NET(1)
- ------------------------------- ----- --- ----- --- ----- ---- ------------ ----- ---- ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Exploratory:
Productive................... 3 1.0 4 2.3 1 1.0 1.0 3 1.7 1.7
Non-productive............... 2 0.5 3 1.5 -- -- -- 2 1.5 1.5
-- --- -- --- -- ---- ---- -- ---- ----
Total.................. 5 1.5 7 3.8 1 1.0 1.0 5 3.2 3.2
Development:
Productive................... 6 1.8 4 1.3 7 2.8 3.5 1 .5 .5
Non-productive............... -- -- 1 0.3 -- -- -- -- -- --
-- --- -- --- -- ---- ---- -- ---- ----
Total.................. 6 1.8 5 1.6 7 2.8 3.5 1 .5 .5
ONSHORE DRILLING ACTIVITY:
Exploratory:
Productive................... -- -- -- -- 3 0.5 0.5 -- -- --
Non-productive............... -- -- 1 0.3 -- -- -- 1 0.3 0.3
-- --- -- --- -- ---- ---- -- ---- ----
Total.................. -- -- 1 0.3 3 0.5 0.5 1 0.3 0.3
Development:
Productive................... 3 3.0 6 3.1 12 7.4 7.4 7 4.6 4.6
Non-productive............... -- -- 2 1.7 5 2.5 2.5 -- -- --
-- --- -- --- -- ---- ---- -- ---- ----
Total.................. 3 3.0 8 4.8 17 9.9 9.9 7 4.6 4.6
</TABLE>

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

(1) Gives effect to the Soxco Acquisition as if such transaction had been
consummated at the beginning of the period presented.

PRODUCTIVE WELLS

The following table sets forth the number of productive wells in which the
Company owned an interest as of June 30, 1996.

<TABLE>
<CAPTION>
NON-OPERATED WELLS
COMPANY OPERATED WELLS TOTAL PRODUCTIVE WELLS
--------------------------------- --------------------- ---------------------------------
COMPANY PRO PRO PRO PRO PRO
OPERATED FORMA FORMA FORMA FORMA FORMA
OFFSHORE PLATFORMS GROSS NET GROSS(1) NET(1) GROSS NET NET(1) GROSS NET GROSS(1) NET(1)
- ------------------- --------- ----- ----- -------- ------ ----- ---- ------ ----- ----- -------- ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Gas................ 16 64 29.4 64 38.9 16 2.9 3.3 80 32.3 80 42.2
Oil................ -- -- -- -- -- 7 0.7 0.7 7 0.7 7 0.7
-- --- ----- --- ----- --- ---- ---- --- ----- ----- -----
Total...... 16 64 29.4 64 38.9 23 3.6 4.0 87 33.0 87 42.9
ONSHORE
- -------------------
Gas................ 765 471.1 921 618.5 119 29.7 29.7 884 500.8 1,040 648.2
Oil................ 3 2.9 3 2.9 17 6.3 6.3 20 9.2 20 9.2
--- ----- --- ----- --- ---- ---- --- ----- ----- -----
Total...... 768 474.0 924 621.4 136 36.0 36.0 904 510.0 1,060 657.4
</TABLE>

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

(1) Gives effect to the TransTexas Acquisition and the Soxco Acquisition as if
such transactions had been consummated at June 30, 1996.

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.

41
<PAGE> 42

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
June 30, 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
------------------------------------- ------------------------------------
PRO PRO PRO PRO
FORMA FORMA FORMA FORMA
GROSS NET GROSS(2) NET(2) GROSS NET GROSS(2) NET(2)
------- ------- ------- ------- ------- ------ ------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Offshore(1)............................... 130,506 57,725 130,506 73,829 100,024 58,980 100,024 73,351
Onshore................................... 97,040 59,539 128,292 84,985 3,264 1,990 10,093 8,434
------- ------- ------- ------- ------- ------ ------- ------
Total............................. 227,546 117,264 258,798 158,814 103,288 60,970 110,117 81,785
======= ======= ======= ======= ======= ====== ======= ======
</TABLE>

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

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

(2) Gives effect to the TransTexas Acquisition and the Soxco Acquisition as if
such transactions had been consummated at June 30, 1996.

MARKETING AND CUSTOMERS

Substantially all of the Company's production is sold at market prices.
During July 1996, the Company sold approximately 24% of its gas production and
has agreed, subject to certain conditions, to sell substantially all of its
subsequently developed or acquired gas production, to PennUnion Energy Services,
L.L.C. ("PennUnion"), an affiliate of Brooklyn Union. However, the gas produced
from the properties acquired in the TransTexas Acquisition is not covered by the
Agreement with PennUnion. 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 1994 and 1995, PennUnion and BRING Gas Services Corp.
("BRING"), another affiliate of Brooklyn Union, purchased approximately 63% and
46%, respectively, of the natural gas sold by the Company. The Company believes
that the 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. See Note 5 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. The Company
has entered into contracts covering an average of approximately 68,900 Mmbtu per
day (66,300 Mcf/d) of natural gas production for September through March 1997 at
a weighted average price of $2.04 per Mmbtu, before transaction and
transportation costs. The Company has also entered into contracts covering an
average of approximately 49,600 Mmbtu per day (47,700 Mcf/d) for April through
October 1997 at a weighted average price of $1.93 per Mmbtu and contracts
covering an average of approximately 22,600 Mmbtu per day (21,800 Mcf/d) for
November 1997 through March 1998 at a weighted average price of $1.91 per Mmbtu,
in each case 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 7 to the Company's Combined Financial Statements.

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."

42
<PAGE> 43

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, 1995, total pro forma undiscounted
abandonment costs estimated to be incurred through the year 2006 were
approximately $3.2 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 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

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<PAGE> 44

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.

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

44
<PAGE> 45

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 ("Decontrol Act") was enacted, which amended the NGPA to remove completely
by January 1, 1993 price and nonprice 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.

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.

45
<PAGE> 46

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 ratemaking
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.

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

46
<PAGE> 47

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 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.

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 non-jurisdictional 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

47
<PAGE> 48

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 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

48
<PAGE> 49

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 waterbodies, 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 Outer Continental
Shelf Lands Act ("OCSLA") and that would limit the definition of "offshore
facility" to include only Territorial Seas and Outer Continental Shelf
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 Oil Pollution Act 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 $75,000,000. 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.

49
<PAGE> 50

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 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 June 30, 1996, the Company had 74 full time employees, 47 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. In addition,
the Company maintains field operations offices in the areas where it operates
onshore properties.

LEGAL PROCEEDINGS

In connection with the February 1996 reorganization, 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. In February 1996,
certain such former employees filed suit against Brooklyn Union, FRI and the
Company in the 164th Judicial District Court of Harris County, Texas alleging
breach of contract, breach of fiduciary duty, fraud, negligent misrepresentation
and conspiracy, seeking actual damages in excess of $35 million and punitive
damages in excess of $70 million. FRI has agreed to indemnify the Company
against such suit. In addition, Holdings, the subsidiary of Brooklyn Union that
holds all of the currently outstanding Common Stock of the Company, has agreed
to indemnify the Company against the suit, and has agreed to pledge all of its
holdings of Common Stock to the Company to secure such indemnification
obligation. Brooklyn Union has announced its intention to establish a
publicly-traded holding company which would hold all of the stock of Brooklyn
Union. If the holding company is established, the pledge may be released at the
option of Holdings if the obligations of Holdings under such indemnification
agreement are assumed or guaranteed by the holding company. As a result of such
arrangements, the Company believes that it will not be required to pay any
damages resulting from such suit, even if a judgment adverse to the Company is
rendered in the suit. However, the Company would incur a non-cash charge in
addition to the

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<PAGE> 51

$12 million charge previously taken by the Company in the event such damages are
determined to be in excess of such $12 million amount, which would have the
effect of reducing the Company's reported income (or resulting in or increasing
a loss) in the period in which such additional charge is determined.

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.

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<PAGE> 52

MANAGEMENT
DIRECTORS AND EXECUTIVE OFFICERS

The Company's Board of Directors currently has seven members. In accordance
with the Certificate of Incorporation of the Company, the members of the Board
of Directors are divided into three classes and are elected for a term of office
expiring at the third succeeding annual shareholders' meeting following their
election to office or until a successor is duly elected and qualified. The
Certificate of Incorporation also provides that such classes shall be as nearly
equal in number as possible. The terms of office of the Class I, Class II and
Class III directors expire at the annual meeting of stockholders in 1996, 1997
and 1998, respectively. The officers of the Company are elected by, and serve
until their successors are elected by, the Board of Directors.

The following table sets forth certain information with respect to the
executive officers and directors of the Company:

<TABLE>
<CAPTION>
NAME AGE POSITION
- ---------------------------- --- --------------------------------------------------
<S> <C> <C>
James G. Floyd.............. 60 President and Chief Executive Officer and Director
(Class III)
Randall J. Fleming.......... 54 Senior Vice President -- Exploration and
Production
Thomas W. Powers............ 52 Senior Vice President -- Business Development and
Finance and Treasurer
Sammye L. Dees.............. 60 Vice President -- Land
James F. Westmoreland....... 40 Vice President, Chief Accounting Officer,
Comptroller and Secretary
Charles W. Adcock........... 43 Vice President -- Project Development
Robert B. Catell............ 59 Chairman of the Board of Directors (Class III)
Gordon F. Ahalt............. 68 Director (Class II)
Russell D. Gordy............ 45 Director (Class I)
Craig G. Matthews........... 53 Director (Class I)
James Q. Riordan............ 69 Director (Class II)
Lester H. Smith............. 54 Director (Class I)
</TABLE>

James G. Floyd has been President and Chief Executive Officer and a
Director of the Company since 1986. Mr. Floyd was President of Seagull E&P Inc.
("Seagull") and a director of Seagull Energy Corporation, Seagull's parent, from
1981 to 1986. Mr. Floyd was general manager of the offshore division of Houston
Oil and Minerals Corporation ("Houston Oil and Minerals") from 1978 to 1981. Mr.
Floyd joined Houston Oil and Minerals in 1972 after five years as an independent
geologist. Mr. Floyd began his career with Amoco Production Company in 1962. Mr.
Floyd holds a B.S. and an M.S. in geology from the University of Florida.

Randall J. Fleming has been Senior Vice President -- Exploration and
Production of the Company since October 1995 and was Vice President --
Exploration of the Company from 1986 to 1995. Mr. Fleming was Vice President --
Geology of Seagull from 1981 to 1986 and was an exploration geologist at
Houston Oil and Minerals from 1976 to 1981. Prior to such time, Mr. Fleming
was an explorationgeologist for Superior Oil Company and Sinclair Oil Company.
Mr. Fleming holds a B.A. and M.S. in geology from the University of Alabama.

Thomas W. Powers has been Senior Vice President -- Business Development and
Finance of the Company since October 1995 and Treasurer since May 1996. Mr.
Powers was General Manager for Diversification of Brooklyn Union from 1991 to
1995 and Executive Vice President of FRI, a Brooklyn Union subsidiary, from 1986
to 1991. Prior to joining Brooklyn Union, Mr. Powers was Manager of Corporate
Development of Anglo Energy. Mr. Powers holds a B.S. in Economics from Bowling
Green University and an M.B.A. from Long Island University.

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<PAGE> 53

Sammye L. Dees has been Vice President -- Land of the Company since 1986.
Ms. Dees was Vice President of Land of Seagull from 1981 to 1986, and was Land
Manager, Offshore Division, of Houston Oil and Minerals from 1974 to 1981. Prior
to joining Houston Oil and Minerals, Ms. Dees worked for Allied Chemical
Corporation. Ms. Dees is a Certified Petroleum Landman and attended Stephen F.
Austin University.

James F. Westmoreland has been Vice President, Chief Accounting Officer,
Comptroller and Secretary of the Company since October 1995 and was Vice
President and Comptroller of the Company from 1986 to 1995. Mr. Westmoreland was
supervisor of natural gas and oil accounting at Seagull from 1983 to 1986. Mr.
Westmoreland holds a B.B.A. in accounting from the University of Houston.

Charles W. Adcock has been Vice President -- Project Development of the
Company since 1996. Mr. Adcock was Vice President of Project Development of FRI,
the Brooklyn Union subsidiary that previously owned the Company's onshore
properties, from 1993 to 1996. Prior to joining FRI, Mr. Adcock worked at NERCO
Oil & Gas as Reservoir Engineering Specialist. Prior to NERCO, he held various
engineering positions with Apache, ANR Production and Aminoil U.S.A. Mr. Adcock
is a Registered Professional Engineer in the State of Texas, and received his
B.S. in Civil Engineering from Texas A&M University and an M.B.A. from the
University of St. Thomas.

Robert B. Catell has been Chairman of the Board of Directors of the Company
since 1986. Mr. Catell has been Chairman of the Board and Chief Executive
Officer of Brooklyn Union since 1991 and was President from 1991 to 1996. Mr.
Catell has been associated with Brooklyn Union since 1958 and has been an
officer of Brooklyn Union since 1974. Mr. Catell received both his Bachelor's
and Master's Degrees in Mechanical Engineering from City College of New York. He
holds a Professional Engineer's License in New York State, and attended Columbia
University's Executive Development Program and Harvard Business School's
Advanced Management Program. Mr. Catell is Trustee of Brooklyn Law School,
Independence Savings Bank and Kingsborough Community College Foundation, Inc.;
Chairman and Director of Alberta Northeast Inc. and Boundary Gas, Inc.; Chairman
of Energy Association of New York State; Director and Past Chairman, American
Gas Association; Director of The Business Council of New York State, Inc., Gas
Research Institute, New York City Partnership and New York State Energy Research
and Development Authority.

Gordon F. Ahalt has been a director of the Company since 1996. Mr. Ahalt
has been President of G.F.A. Inc., a petroleum industry financial and management
consulting firm, since 1982. Mr. Ahalt is a consultant to Brooklyn Union and
W.H. Reaves Co., Inc. Mr. Ahalt serves as a director for the Bancroft and
Ellsworth Convertible Funds, the Harbinger Group and Cal Dive International. Mr.
Ahalt received a B.S. in Petroleum Engineering in 1951 from the University of
Pittsburgh, attended New York University's Business School and is a graduate of
Harvard Business School's Advanced Management Program. He worked for Amoco from
1951 to 1955, Chase Manhattan Bank from 1955 to 1972, White Weld from 1972 to
1973, Chase Manhattan Bank from 1974 through 1976, served as President and Chief
Executive Officer of International Energy Bank London from 1977 to 1979 and as
Chief Financial Officer of Ashland Oil Inc. from 1980 to 1981.

Russell D. Gordy has been a Director of the Company since 1986. Mr. Gordy
has been Managing Partner of S.G. Interests, a private firm specializing in oil
and gas investments, since 1988. Prior to forming S.G. Interests, Mr. Gordy was
Managing Partner of Northwind Exploration, a private oil and gas firm formed in
1981 to specialize in exploration along the Texas and Louisiana Gulf Coast. From
1974 to 1981 Mr. Gordy served in various financial capacities for Houston Oil
and Minerals Corporation. Mr. Gordy holds a B.B.A. in accounting from Sam
Houston State University and is a C.P.A.

Craig G. Matthews has been a Director of the Company since 1993. Mr.
Matthews has been President and Chief Operating Officer of Brooklyn Union since
May 1996, was Executive Vice President of Brooklyn Union since 1994, and was
Executive Vice President and Chief Financial

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<PAGE> 54

Officer of Brooklyn Union from 1991 to 1994. Mr. Matthews joined Brooklyn Union
in 1965. He graduated from Rutgers University in 1965 with a Bachelor's Degree
in Civil Engineering, and acquired an M.S. Degree in Industrial Management from
Polytechnic University. Mr. Matthews is a member of the Board of Directors for
the Brooklyn Philharmonic, the Public Utilities Reports, Inc., the Brooklyn
Chamber of Commerce, Neighborhood Housing Services, Greater Jamaica Development
Corp., Regional Plan Association, Prospect Park Alliance, the National and New
York Advisory Board of the Salvation Army and Inform. Mr. Matthews is the
Treasurer of the Society of Gas Lighters.

James Q. Riordan has been a director of the Company since 1996 and a
director of Brooklyn Union since 1991. Mr. Riordan is the retired Vice Chairman
and Chief Financial Officer of Mobil Corp. He joined Mobil Corp. in 1957 as Tax
Counsel and was named Director and Chief Financial Officer in 1969. Mr. Riordan
served as Vice Chairman of Mobil Corp. from 1986 until his retirement in 1989.
He joined Bekaert Corporation in 1989 and was elected its President, and served
as President until his retirement in 1992. Mr. Riordan is a Director of Dow
Jones & Co., Inc., Tri-Continental Corporation and the Public Broadcasting
Service; Director/Trustee of the mutual funds in the Seligman Group of
investment companies; and Trustee for the Committee for Economic Development and
The Brooklyn Museum.

Lester H. Smith has been a director of the Company since 1996. Mr. Smith is
the founder, Chairman of the Board and President of Soxco. Mr. Smith is Chairman
of the Board and President of Smith Energy Company, an independent oil and gas
exploration company, and Chairman of the Board of Founders International, Ltd.,
an international downhole drilling tool company. Mr. Smith has been active in
the energy business as an independent since 1973. He attended the University of
Oklahoma where he majored in finance.

COMMITTEES

The Company's Board of Directors has established Executive, Audit and
Compensation Committees. The Audit Committee consists of Messrs. Riordan, Ahalt
and Gordy, each of whom is a non-employee director of the Company. The Audit
Committee meets separately with representatives of the Company's independent
auditors and with representatives of senior management in performing its
functions. The Audit Committee reviews the general scope of audit coverages, the
fees charged by the independent auditors, matters relating to the Company's
internal control systems, and other matters related to audit functions.

The Compensation Committee consists of Messrs. Catell, Ahalt and Riordan,
each of whom is a non-employee director of the Company. The Compensation
Committee administers the Company's 1996 Long-Term Stock Incentive Plan, and in
this capacity makes all option grants or awards to Company employees, including
executive officers, under such plans. In addition, the Compensation Committee is
responsible for making recommendations to the Board of Directors with respect to
the compensation of the Company's Chief Executive Officer and its other
executive officers, and is responsible for the establishment of policies dealing
with various compensation and employee benefit matters for the Company.

EMPLOYMENT AGREEMENTS WITH EXECUTIVE OFFICERS

Prior to completion of the Offering, Messrs. Floyd, Fleming, Powers and
Westmoreland will enter into employment agreements with the Company effective as
of the closing of this Offering pursuant to which they serve as executive
officers of the Company. Mr. Floyd's existing employment agreement with the
Company will be terminated effective as of such time.

Such employment agreements provide for Messrs. Floyd, Fleming, Powers and
Westmoreland to receive annual base salaries of $340,000, $220,000, $140,000 and
$130,000, respectively. Under such agreements, Messrs. Floyd, Fleming, Powers
and Westmoreland are entitled to annual incentive bonuses of 60%, 50%, 45% and
45%, respectively, of base salary if the Company meets

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<PAGE> 55

financial targets established by the Board of Directors. In addition, Messrs.
Floyd, Fleming, Powers and Westmoreland will be entitled to participate in such
incentive compensation and other programs as are adopted by the Company's Board
of Directors, including the Company's 1996 Stock Option Plan. The initial term
of each employment agreement extends to the third anniversary of the effective
date of such agreement; provided, however, that the term of each agreement is
automatically extended one year on each anniversary unless notice that the
agreement will not be extended is given by either party at least 90 days prior
to such anniversary.

Each of the employment agreements is subject to early termination by the
Company for cause or upon the death or disability of the employee and is subject
to early termination by the employee for any reason. If an employment agreement
is terminated without cause by the Company or with good reason (including
certain changes in control of the Company) by the employee, the Company is
obligated to pay such employee a lump-sum severance payment of 2.99 times the
employee's then current annual rate of total compensation. Based upon their
current annual rate of compensation, Messrs. Floyd, Fleming, Powers and
Westmoreland would be entitled to lump sum severance payments of $1,017,000,
$658,000, $419,000 and $389,000, respectively, if terminated without cause.

DIRECTOR COMPENSATION

Directors currently receive a fee of $1,250 per calendar quarter for
serving on the Board of Directors and $500 per board meeting attended. Upon
completion of this Offering, each director who is not also an officer or
employee of the Company will receive a fee of $4,000 per calendar quarter and
$1,000 per board meeting attended. Members of committees of Board of Directors
will receive a fee of $500 per calendar quarter.

EXECUTIVE COMPENSATION

The following table sets forth certain summary information concerning the
compensation provided by the Company in 1995 to its Chief Executive Officer and
each other person serving as an executive officer during 1995 who earned
$100,000 or more in combined salary and bonus during such year (collectively,
the "Named Executive Officers").

<TABLE>
<CAPTION>
ANNUAL COMPENSATION(1)
---------------------- ALL OTHER
NAME AND PRINCIPAL POSITION SALARY BONUS COMPENSATION(2)
------------------------------------------------- --------- -------- ---------
<S> <C> <C> <C>
James G. Floyd, President and Chief Executive
Officer........................................ $ 250,000 $ 10,000 $ 52,000
Randall J. Fleming, Senior Vice
President -- Exploration and Production........ $ 173,000 $ 7,000 $ 14,000
Sammye L. Dees, Vice President -- Land........... $ 107,000 $ 4,500 $ 9,000
James F. Westmoreland, Vice President, Chief
Accounting Officer, Comptroller and
Secretary...................................... $ 102,000 $ 4,000 $ 4,000
</TABLE>

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

(1) Amounts exclude perquisites and other personal benefits because such
compensation did not exceed the lesser of $50,000 or 10% of the total annual
salary and bonus reported for each executive officer.

(2) Consists of the value of overriding royalty interests and net profits
interests in properties of the Company conveyed during 1995. See "Related
Party Transactions -- Transactions Between the Company and Management."

1996 STOCK OPTION PLAN

Prior to completion of the Offering, it is anticipated that the Board of
Directors will adopt the Company's 1996 Stock Option Plan (the "Incentive Plan")
and that the stockholder of the Company will approve the Incentive Plan as
adopted. The purposes of the Incentive Plan are to attract, retain

55
<PAGE> 56

and motivate key employees, consultants and advisors by means of grants of stock
options, to enable such persons to participate in the long-term growth of the
Company. The aggregate amount of Common Stock with respect to which options may
be granted may not exceed 10% of the shares of the Company's Common Stock
outstanding from time to time. The aggregate amount of Common Stock with respect
to which incentive stock options may be granted under the Incentive Plan may not
exceed 1,125,000 shares of Common Stock. No individual may receive, during any
period of three consecutive years, stock options under the Incentive Plan in
respect of more than 1,125,000 shares of Common Stock.

To comply with the requirements of Section 162(m) of the Internal Revenue
Code of 1986, as amended (the "Code"), the Incentive Plan will be administered
following the Offering by the Compensation Committee of the Board of Directors
of the Company (the "Committee"), which shall be comprised solely of two or more
directors who are "outside directors" within the meaning of the Treasury
Regulations promulgated under Section 162(m) of the Code. To comply with the
requirements of Rule 16b-3 of the Securities Exchange Act of 1934, as amended,
the Incentive Plan will provide that the shares of Common Stock issuable upon
the exercise of an option may not be sold for six months from its date of grant.
The Committee will have complete authority to construe, interpret and administer
provisions of the Incentive Plan, to determine which persons are to be granted
options, the terms and conditions of options, and to make all other
determinations necessary or deemed advisable in the administration of the
Incentive Plan.

Options granted under the Incentive Plan may be either nonqualified stock
options or incentive stock options. The exercise price of any option will be as
determined by the Committee as of the date of grant, provided that the exercise
price of such options shall not be less than the fair market value of the Common
Stock as the date of grant. The exercise price must be paid in full in cash at
the time an option is exercised or, if permitted by the Board of Directors or a
committee of "non-employee directors" (as defined in Rule 16b-3), by means of a
"cashless exercise" through a broker, by tendering Common Stock already owned by
the participant, or any combination of the foregoing. The Committee will
determine the period over which individual options become exercisable.

In the event of a change in control of the Company, the Committee in its
discretion may, at the time an option is made or any time thereafter: (i)
provide for the acceleration of any time period relating to the exercise of the
option, (ii) provide for the purchase of the option upon the participant's
request for an amount of cash or other property that could have been received
upon the exercise or realization of the option had the option been currently
exercisable or payable, (iii) adjust the terms of the option in a manner
determined by the Committee to reflect the change in control, (iv) cause the
option to be assumed, or new rights substituted therefor, by another entity, or
(v) make such other provision as the Committee may consider equitable and in the
best interests of the Company.

In the event of any stock dividend, recapitalization, reorganization,
merger, consolidation or other extraordinary event, the Committee may, to the
extent deemed necessary to preserve the benefits under the Incentive Plan,
adjust the number and kind of shares which thereafter may be made the subject of
options, the number and kind of shares subject to outstanding options, and the
grant, exercise or conversion price with respect to any of the foregoing and, if
deemed appropriate, make provision for cash payments to participants. Subject to
certain limitations, the Board of Directors is authorized to amend, suspend or
terminate the Incentive Plan to meet any changes in legal requirements or for
any other purpose permitted by law.

Upon completion of the Offering, options with respect to an aggregate of
1,120,138 shares (1,166,638 shares if the Underwriters' over-allotment option is
exercised in full) of Common Stock will be granted to certain key employees of
the Company, including options for 322,600 shares to Mr. Floyd, options for
168,021 shares to Mr. Fleming, options for 100,812 shares to Mr. Powers and
options for 80,650 shares to Mr. Westmoreland. All of these options will have an
exercise price

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<PAGE> 57

equal to the initial public offering price of the Common Stock, and will vest in
one-fifth increments on each of the first five anniversaries of the grant date.

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

Effective immediately prior to the Offering, the Company will adopt 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.

401(K) 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 Code) 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 Code. 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's 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.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

Robert B. Catell, a member of the Compensation Committee, is Chairman of
the Board and Chief Executive Officer of Brooklyn Union. As a result of the
termination, upon completion of the Offering, of certain options to purchase
Common Stock held by Mr. Catell, the Company will pay $420,000 to Mr. Catell.
See "Related Party Transactions -- Transactions Between the Company and Brooklyn
Union and Affiliates."

RELATED PARTY TRANSACTIONS

TRANSACTIONS BETWEEN THE COMPANY AND BROOKLYN UNION AND AFFILIATES

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 has focused since its inception 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 not
previously owned by the Company. Brooklyn Union has advised the Company that it
does not currently intend to engage in the domestic exploration for or
production of natural gas and oil except through ownership of Common Stock of
the Company.

In 1993, 1994 and 1995 Brooklyn Union made capital contributions to the
Company of $12.6 million, $18.0 million and $6.9 million, respectively. Brooklyn
Union made capital contributions to the Company of $10.3 million during the
period from January 1, 1996 to June 30, 1996. Brooklyn Union has received shares
of Common Stock in consideration of such capital contributions.

During 1993, 1994 and 1995, the Company had natural gas sales of $32.9
million, $26.4 million and $18.9 million representing 86%, 63% and 46% of total
revenues for the years ended 1993, 1994 and 1995, respectively, to PennUnion and
BRING, both of which are affiliates of Brooklyn Union. Such natural gas sales
were made at market prices, based on an index price adjusted to reflect the

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<PAGE> 58

point of delivery of such production. The Company believes that the prices at
which it has sold natural gas to affiliates of Brooklyn Union were similar to
those it would have been able to obtain in the open market.

In July 1994, the Company granted options to purchase an aggregate of
247,000 shares of Common Stock to three officers of Brooklyn Union, including
Messrs. Catell and Matthews, with an exercise price of $11.22 per share. Upon
completion of the Offering, such options will be terminated in exchange for
payment by the Company of an aggregate of $840,000. As a result of the
termination of their options, Messrs. Catell and Matthews will receive payments
of $420,000 and $294,000, respectively. Theodore Spar, who is an officer of
Brooklyn Union but is not an officer or director of the Company, will receive a
payment of $126,000.

The Company has been and will be included in the consolidated federal
income tax returns filed by Brooklyn Union during all periods in which it has
been or will be a wholly-owned subsidiary of Brooklyn Union ("Affiliation
Years"). The Company and Brooklyn Union have entered into an agreement (the "Tax
Sharing Agreement") providing for the manner of determining payments with
respect to federal income tax liabilities and benefits arising in Affiliation
Years. Under the Tax Sharing Agreement, the Company has paid or will pay to
Brooklyn Union an amount equal to the Company's share of Brooklyn Union's
consolidated federal income tax liability, generally determined on a separate
return basis, for the years ended and the portion of 1996 preceding consummation
of the Offering, and Brooklyn Union will pay the Company for any reduction in
Brooklyn Union's consolidated federal income tax liability resulting from
utilization or deemed utilization of deductions, losses, and credits arising in
such periods which are attributable to the Company, in each case net of any
amounts theretofore paid or credited by Brooklyn Union or the Company to the
other with respect thereto. In the event that Brooklyn Union's consolidated
federal income tax liability for any Affiliation Year is adjusted upon audit or
otherwise, the Company will bear any additional liability or receive any refund
which is attributable to adjustments of items of income, deduction, gain, loss
or credit of the Company. Brooklyn Union shall permit the Company to participate
in any audits or litigation with respect to Affiliation Years, but Brooklyn
Union will otherwise have exclusive and sole responsibility and control over any
such proceedings. The Company will cease to be included in the consolidated
federal income tax returns filed by Brooklyn Union, and will file on a separate
basis, with respect to periods after consummation of the Offering.

Under a Registration Rights Agreement (the "Brooklyn Union Registration
Rights Agreement") to be entered into between the Company and Brooklyn Union,
the Company will file, upon the request of Brooklyn Union, a registration
statement under the Securities Act of 1933 for the purpose of enabling Brooklyn
Union to offer and sell any securities of the Company which Brooklyn Union may
hold. Brooklyn Union may exercise these rights at any time after the expiration
of 180 days following the completion of this Offering. The Company will bear the
costs of any registered offering, except that Brooklyn Union will pay any
underwriting commissions relating to any such offering, any transfer taxes and
any costs of complying with foreign securities laws at Brooklyn Union's request,
and each will pay for its counsel and accountants. The Company has the right to
require Brooklyn Union to delay any exercise by Brooklyn Union of its rights to
require registration and other actions for a period of up to 180 days if, in the
judgment of the Company, the Company or any offering by the Company then being
conducted or about to be conducted would be adversely affected. The Company has
also granted Brooklyn Union the right to include its securities in certain
registration statements covering offerings by the Company, and the Company will
pay all costs of such offerings other than underwriting commissions and transfer
taxes attributable to the securities sold on behalf of Brooklyn Union. The
Company has agreed to indemnify Brooklyn Union, its officers, directors, agents,
any underwriter, and each person controlling any of the foregoing, against
certain liabilities under the Securities Act or the securities laws of any state
or country in which securities of the Company are sold pursuant to the Brooklyn
Union Registration Rights Agreement.

In connection with the February 1996 reorganization, the Company and FRI,
the subsidiary of Brooklyn Union that previously owned the onshore properties,
entered into an agreement whereby

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<PAGE> 59

the Company assumed FRI's bank debt and the liabilities of FRI directly related
to the transferred properties and acreage. FRI agreed to indemnify the Company
against all of FRI's other liabilities, including any liabilities associated
with the suit filed by certain of FRI's former employees. In addition, the
Company entered into an agreement with Holdings, the subsidiary of Brooklyn
Union that holds all of the currently outstanding Common Stock of the Company,
whereby Holdings agreed to indemnify the Company against any liabilities
associated with such remuneration and suit, and agreed to pledge all of its
holdings of Common Stock to the Company to secure such indemnification
obligation.

TRANSACTIONS BETWEEN THE COMPANY AND MANAGEMENT

In July 1996, the Company entered into employment agreements with Messrs.
Floyd, Fleming, Powers and Westmoreland effective as of the completion of this
Offering. These employment agreements will replace the Company's existing
employment agreements with such officers. See "Management -- Employment
Agreements" for a description of such employment agreements.

The Company's existing employment agreement with Mr. Floyd, its President
and Chief Executive Officer, provides Mr. Floyd with the option to obtain up to
a 5% working interest in certain exploration prospects of the Company,
exercisable prior to the commencement of drilling of the initial well on any
such prospect. During 1993, 1994 and 1995, affiliates of Mr. Floyd obtained a 5%
working interest in 12 wells operated by the Company pursuant to such agreement.
In addition, during 1993, 1994 and 1995, respectively, affiliates of Mr. Floyd
paid $0.9 million, $0.7 million and $0.7 million, respectively, in expenses
attributable to working interests owned in properties operated by the Company,
and received $2.6 million, $1.6 million and $0.9 million for years ended 1993,
1994 and 1995, respectively, in distributions attributable to such working
interests. Concurrently with the closing of the TransTexas Acquisition, Mr.
Floyd exercised his right to purchase a 5% working interest in the properties
acquired by the Company in the TransTexas Acquisition on the same terms as such
properties were acquired by the Company for a purchase price of $3.1 million.
The Company's existing employment agreement with Mr. Floyd, including the option
described above, will be terminated effective upon the completion of this
Offering, provided that such termination shall not affect working interests in
properties of the Company acquired by Mr. Floyd or his affiliates prior to the
date of termination.

The Company has agreed to loan 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 owned 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 production from, such properties. The outstanding balance owed by Mr.
Floyd under the agreement will mature on July 2, 2006.

The Company's existing employment agreement with Mr. Floyd also provides
for the assignment to Mr. Floyd of a 2% net profits interest in all exploration
prospects of the Company at the time such properties are acquired by the
Company. During 1993, 1994 and 1995, the Company assigned a 2% net profits
interest to Mr. Floyd in all such properties acquired by the Company during such
periods pursuant to such agreement. In addition, during 1993, 1994 and 1995, Mr.
Floyd received $656,000, $516,000 and $307,000, respectively, in distributions
attributable to net profits interests in properties of the Company. The
Company's existing employment agreement with Mr. Floyd, including the rights
described above, will be terminated effective upon the completion of this
Offering, provided that such termination shall not affect net profits interests
in properties of the Company assigned to Mr. Floyd prior to the date of
termination.

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<PAGE> 60

The Company's existing employment agreement with Mr. Floyd also provides
for the assignment to certain key employees designated by Mr. Floyd of
overriding royalty interests in certain properties of the Company at the time
such properties are acquired by the Company. During 1993, 1994 and 1995, the
Company assigned overriding royalty interests to Mr. Fleming, Ms. Dees and Mr.
Westmoreland in all properties acquired by the Company during such periods
pursuant to such agreement. During 1993, 1994 and 1995, Mr. Fleming received
$453,000, $326,000, and $213,000, respectively, and Ms. Dees received $427,000,
$302,000 and $189,000, respectively, in distributions attributable to overriding
royalty interests in properties of the Company. The Company's existing
employment agreement with Mr. Floyd, including the provisions described above,
will be terminated effective upon the completion of this offering, provided that
such termination shall not affect overriding royalty interests in properties of
the Company assigned to key employees prior to the date of termination.

The Company's existing employment agreement with Mr. Floyd also provides
for the assignment to Mr. Floyd of a 6.75% after program-payout working interest
in the leases upon which the Company begins drilling an initial exploratory well
(whether or not successful) during a calendar year (a "program"). These working
interests entitle Mr. Floyd to receive 6.75% of the excess, if any, of the
aggregate revenues from the properties within a program over the aggregate costs
(including capital expenditures) associated with such properties. At the date of
this Offering, Mr. Floyd has not received any distributions under this
arrangement. The Company's existing employment agreement, including the rights
described above will be terminated effective upon completion of this Offering,
provided that such termination shall not affect the after program-payout working
interest in properties of the Company assigned to Mr. Floyd prior to date of
termination. Concurrently with the completion of the Offering, Mr. Floyd will
exchange certain of his after program-payout working interests for 145,161
shares of Common Stock with a value of $2.3 million.

SOXCO ACQUISITION

Under an agreement with Soxco, Lester H. Smith has received a 1.25% net
profits interest, proportionately reduced for Soxco's interest, in all
properties in which Soxco has participated. Upon the sale by Soxco of its
properties, Mr. Smith has the right to sell all such net profits interests on
the same economic terms to be received by Soxco in the transaction. Mr. Smith
has exercised such right in connection with the Soxco Acquisition, with the
result that his net profits interests will be sold to Soxco prior to the
completion of the Soxco Acquisition and included in the assets to be purchased
by the Company. Soxco estimates that, as a result of the Soxco Acquisition, Mr.
Smith will receive approximately $90,000 in cash, 13,548 initial shares of
Common Stock and additional shares of Common Stock with a value between $100,000
and $200,000 (relating to the deferred purchase price of the Soxco Acquisition).

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information as of August 15, 1996
concerning the persons known by the Company to be beneficial owners of more than
five percent of the Company's outstanding Common Stock, the members of the Board
of Directors of the Company, the Named Executive Officers listed in the Summary
Compensation Table above and all directors and executive officers of the Company
as a group.

<TABLE>
<CAPTION>
BENEFICIAL OWNERSHIP
---------------------------------------
PERCENT
-----------------------
SUBSEQUENT
PRIOR TO TO
NAME OF BENEFICIAL OWNER SHARES OFFERING OFFERING
- --------------------------------------------------------- ----------- -------- ----------
<S> <C> <C> <C>
The Brooklyn Union Gas Company........................... 15,295,215 100% 68%
James G. Floyd........................................... 145,161(1) -- *
Randall J. Fleming....................................... -- -- --
Thomas W. Powers......................................... -- -- --
Sammye L. Dees........................................... -- -- --
James F. Westmoreland.................................... -- -- --
Charles W. Adcock........................................ -- -- --
Robert B. Catell......................................... --(2) * --
Craig G. Matthews........................................ --(2) * --
Gordon F. Ahalt.......................................... -- -- --
Russell D. Gordy......................................... -- -- --
James Q. Riordan......................................... -- -- --
Lester H. Smith(3)....................................... 13,548 -- *
All directors and officers as a group
(12 persons)(1)(2)(3).................................. 158,709 * *
</TABLE>

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

* Less than 1%.

(1) Represents shares issuable upon completion of the Offering.

(2) Messrs. Catell and Matthews hold outstanding stock options exercisable for
123,500 and 86,450 shares of Common Stock, respectively, that will be
terminated upon completion of the Offering. See "Related
Transactions -- Transactions between the Company and Brooklyn Union and
Affiliates."

(3) Mr. Smith, who is Chairman of the Board and President of Soxco, may be
deemed to be the beneficial owner of the shares of Common Stock to be
issued to Soxco pursuant to the Soxco Acquisition. Mr. Smith disclaims
beneficial ownership of all such shares except for the 13,548 shares of
Common Stock to which he will be entitled as a result of the Soxco
Acquisition. See "Related Transactions -- Soxco Acquisition."

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DESCRIPTION OF CAPITAL STOCK

The Company's Restated Certificate of Incorporation (the "Certificate")
provides for authorized capital stock consisting of 50,000,000 shares of Common
Stock, par value $0.01 per share, and 5,000,000 shares of Preferred Stock, par
value $0.01 per share. The following summary, which describes the material terms
of the Company's capital stock, is qualified in its entirety by reference to the
Certificate, which is filed as an exhibit to the Registration Statement of which
this Prospectus is a part.

COMMON STOCK

Holders of Common Stock are entitled to one vote per share in the election
of directors and on all other matters submitted to a vote of common stockholders
and do not have cumulative voting rights. Holders of Common Stock are entitled
to receive ratably such dividends, if any, as may be declared by the Board of
Directors out of funds legally available therefore, subject to any preferential
dividend rights of holders of outstanding Preferred Stock. See "Dividend
Policy." Upon the liquidation, dissolution or winding up of the Company, the
holders of Common Stock are entitled to receive ratably the net assets of the
Company available after payment of all debts and other liabilities, subject to
the prior rights of any outstanding shares of Preferred Stock. Holders of Common
Stock have no preemptive, subscription, redemption or conversion rights.

PREFERRED STOCK

The Board of Directors of the Company is empowered, without approval of the
stockholders, to cause shares of Preferred Stock to be issued in one or more
series, with the numbers of shares of each series to be determined by it. The
Board of Directors is authorized to fix and determine variations in the
designations, preferences, and relative, participating, optional or other
special rights (including, without limitation, special voting rights,
preferential rights to receive dividends or to receive assets upon liquidation,
rights of conversion into Common Stock or other securities, redemption
provisions and sinking fund provisions) between series and between the Preferred
Stock or any series thereof and the Common Stock, and the qualifications,
limitations or restrictions of such rights; and the shares of Preferred Stock or
any series thereof may have full or limited voting powers, or be without voting
powers.

Although the Company has no present intention to issue shares of Preferred
Stock, the issuance of shares of Preferred Stock, or the issuance of rights to
purchase such shares, could be used to discourage an unsolicited acquisition
proposal. For instance, the issuance of a series of Preferred Stock might impede
a business combination by including class voting rights that would enable the
holders to block such a transaction; or such issuance might facilitate a
business combination by including voting rights that would provide a required
percentage vote of the stockholders. In addition, under certain circumstances,
the issuance of Preferred Stock could adversely affect the voting power of the
holders of the Common Stock. Although the Board of Directors is required to make
any determination to issue such stock based on its judgment as to the best
interests of the stockholders of the Company, the Board of Directors could act
in a manner that would discourage an acquisition attempt or other transaction in
that some or a majority of stockholders might believe to be in their best
interest or in which stockholders might receive a premium for their stock over
the then market price for such stock. The Board of Directors does not at present
intend to seek stockholder approval prior to any issuance of currently
authorized stock, unless otherwise required by law or the regulations of the
exchange on which its Common Stock is listed.

CERTAIN PROVISIONS OF THE COMPANY'S CHARTER AND BYLAWS AND DELAWARE LAW

Certain provisions of the Certificate and Bylaws are intended to enhance
the likelihood of continuity and stability in the Board of Directors of the
Company and in its policies, but might have

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<PAGE> 63

the effect of delaying or preventing a change in control of the Company and may
make more difficult the removal of incumbent management even if such
transactions could be beneficial to the interests of stockholders. Set forth
below is a summary description of such provisions:

Classification of Directors; Filling Vacancies. The Company's Bylaws
provide that the directors of the Company shall be divided into three classes as
equal in number as possible serving staggered three-year terms. The Board of
Directors of the Company, acting by a majority of the directors then in office,
may fill any vacancy or newly created directorship.

Stockholder Actions and Meetings. The Company's Certificate provides that
all actions required or permitted to be taken by the stockholders of the Company
may be taken only at a duly held annual or special meeting of the stockholders.
The Company's Bylaws establish procedures, including advance notice procedures,
with regard to the nomination, other than by or at the direction of the Board of
Directors, of candidates for election as directors and for stockholder proposals
to be submitted at meetings of the stockholders. The Company's Bylaws also
provide that special meetings of stockholders may be called only by the
President or by a majority of the directors.

Anti-takeover Provisions. Delaware law permits and the Certificate grants
the Company's Board broad discretionary authority to adopt any and all
anti-takeover measures approved by it in response to any proposal to acquire the
Company, its assets or more than 15% of its outstanding capital stock. Measures
to be adopted could include a shareholder rights plan or by-law provisions
requiring supermajority shareholder approval of acquisition proposals.

Limitation on Personal Liability of Directors. Delaware law authorizes
corporations to limit or eliminate the personal liability of directors to
corporations and their stockholders for monetary damages for breach of
director's fiduciary duty of care. The duty of care requires that, when acting
on behalf of the corporation, directors must exercise an informed business
judgment based on all material information reasonably available to them. Absent
the limitations authorized by Delaware law, directors are accountable to
corporations and their stockholders for monetary damages for conduct
constituting gross negligence in the exercise of their duty of care. Delaware
law enables corporations to limit available relief to equitable remedies such as
injunction or rescission. The Certificate of the Company limits the liability of
directors of the Company to the Company or its stockholders (in their capacity
as directors but not in their capacity as officers) to the fullest extent
permitted by Delaware law. Specifically, directors of the Company will not be
personally liable for monetary damages for breach of a director's fiduciary duty
as a director, except for liability (i) for any breach of the director's duty of
loyalty to the Company or its stockholders, (ii) for acts or omissions not in
good faith or which involve intentional misconduct or a knowing violation of
law, (iii) for unlawful payments of dividends or unlawful stock repurchases or
redemptions as provided in Section 174 of the Delaware General Corporation Law,
or (iv) for any transaction from which the director derived an improper personal
benefit.

The inclusion of this provision in the Certificate may have the effect of
reducing the likelihood of derivative litigation against directors and may
discourage or deter stockholders or management from bringing a lawsuit against
directors for breach of their duty of care, even though such an action, if
successful, might otherwise have benefited the Company and its stockholders. The
Company's Bylaws provide indemnification to the Company's officers and directors
and certain other persons with respect to certain matters.

Indemnification Arrangements. The Certificate of Incorporation and Bylaws
provide that, to the fullest extent permitted by the Delaware General
Corporation Law, the directors and officers of the Company shall be indemnified
and permit the advancement to them of expenses in connection with actual or
threatened proceedings and claims arising out of their status as such. The
Company intends to enter into indemnification agreements with each of its
directors and executive officers that provide for indemnification and expense
advancement to the fullest extent permitted under the Delaware General
Corporation Law.

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<PAGE> 64

The Company is a Delaware corporation and is subject to Section 203 of the
Delaware General Corporation Law. In general, Section 203 prevents an
"interested stockholder" (defined generally as a person owning 15% or more of a
corporation's outstanding voting stock) from engaging in a "business
combination" (as defined) with a Delaware corporation for three years following
the date such person became an interested stockholder unless (i) before such
person became an interested stockholder, the board of directors of the
corporation approved the transaction in which the interested stockholder become
an interested stockholder or approved the business combination; (ii) upon
consummation of the transaction that resulted in the interested stockholder's
becoming an interested stockholder, the interested stockholder owned at least
85% of the voting stock of the corporation outstanding at the time the
transaction commenced (excluding stock held by directors who are also officers
of the corporation and by employee stock plans that do not provide employees
with the rights to determine confidentially whether shares held subject to the
plan will be tendered in a tender or exchange offer); or (iii) following the
transaction in which such person become an interested stockholder, the business
combination was approved by the board of directors of the corporation and
authorized at a meeting of the stockholders by the affirmative vote of the
holders of two-thirds of the outstanding voting stock of the corporation not
owned by the interested stockholder. Under Section 203, the restrictions
described above also do not apply to certain business combination proposed by an
interested stockholder following the announcement or notification of one of
certain extraordinary transactions involving the corporation and a person who
had not been an interested stockholder during the previous three years or who
become an interested stockholder with the approval of a majority of the
corporation's directors, if such extraordinary transaction is approved or not
opposed by a majority of the directors who were directors prior to any person
becoming an interested stockholder during the previous three years or were
recommended for election or elected to succeed such directors by a majority of
such directors.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for the Common Stock will be The Bank of
New York.

SHARES ELIGIBLE FOR FUTURE SALE

Upon completion of this Offering, the Company will have 22,402,763 shares
of Common Stock outstanding. The shares sold in this Offering will be freely
tradeable without restriction or further registration, except for shares owned
by "affiliates" of the Company (as such term is defined under the Securities
Act) which may be sold subject to the resale limitations of Rule 144 promulgated
under the Securities Act ("Rule 144"). All of the remaining 16,202,763
outstanding shares, consisting of 15,295,215 shares of Common Stock owned by
Brooklyn Union, 762,387 shares to be issued to Soxco in the Soxco Acquisition
and 145,161 shares to be issued to certain executive officers of the Company
upon completion of the Offering, constitute "restricted securities" within the
meaning of Rule 144. Such shares may not be resold in a public distribution
except pursuant to an effective registration statement under the Securities Act
or an applicable exemption from registration, including pursuant to Rule 144. In
connection with this Offering, the Company and Brooklyn Union have entered into
the Brooklyn Union Registration Rights Agreement, pursuant to which Brooklyn
Union will have certain demand registration rights at the Company's expense and
certain piggyback registration rights. In connection with the Soxco Acquisition,
the Company will grant Soxco three demand registration rights at the Company's
expense and certain piggyback registration rights. Each of the Company, Brooklyn
Union, Soxco and the officers and directors of the Company have entered into
certain "lock up" agreements with the Underwriters pursuant to which they have
agreed not to offer or sell shares of Common Stock of the Company for a period
of 180 days after the date of this Prospectus without the written consent of the
representatives of the Underwriters. See "Underwriting."

Generally, Rule 144 provides that beginning 90 days after the date of this
Prospectus, a person (or persons whose shares are aggregate) who has
beneficially owned "restricted" securities for at

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<PAGE> 65

least two years, including a person who may be deemed an "affiliate" of the
Company, as the term "affiliate" is defined under the Securities Act, is
entitled to sell in "brokers' transactions" or in transactions directly with a
"market maker," within any three-month period, a number of shares that does not
exceed the greater of 1% of the then outstanding shares of Common Stock or the
average weekly trading volume of the Common Stock on any national securities
exchange and/or over-the-counter market during the four calendar weeks preceding
such sale. Sales under Rule 144 are also subject to certain notice requirements
and the availability of current public information about the Company. A person
(or persons whose shares are aggregated) who is not deemed an "affiliate" of the
Company would be entitled to sell such shares under Rule 144 without regard to
the volume, public information, manner of sale of notice provisions and
limitations described above, once a period of at least three years has elapsed
since the later date the shares were acquired from the Company or from an
"affiliate" of the Company.

Upon completion of the Offering, the Company will grant options to purchase
1,120,138 shares of Common Stock (1,166,638 shares if the Underwriters'
over-allotment option is exercised in full) to its employees pursuant to the
Incentive Plan. After this Offering, the Company intends to file a registration
statement on Form S-8 under the Securities Act to register the shares of Common
Stock issuable upon exercise of such options. Accordingly, such shares will be
freely tradeable by holders who are not affiliates of the Company and, subject
to the volume and manner of sale limitations of Rule 144, by holders who are
affiliates of the Company. See "Management -- 1996 Stock Option Plan."

Prior to this Offering, there has been no public market for the Common
Stock of the Company, and no prediction can be made as to the effect, if any,
that future sales of shares or the availability of shares for sale will have on
the market price for Common Stock prevailing from time to time. Sales of
substantial amounts of Common Stock in the public market, or the perception of
the availability of shares for sale, could adversely affect the prevailing
market price of the Common Stock and could impair the Company's ability to raise
capital through the sale of its equity securities.

LEGAL MATTERS

Certain legal matters in connection with the shares of Common Stock offered
hereby are being passed upon for the Company by Andrews & Kurth L.L.P., Houston,
Texas, and for the Underwriters by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

The combined audited financial statements of the Company as of December 31,
1994 and 1995, and for each of the three years in the period ended December 31,
1995, included in this Prospectus have been audited by Arthur Andersen LLP,
independent public accountants, as indicated in their report with respect
thereto, and are included herein in reliance upon the authority of said firm as
experts in giving said report.

The audited financial statements of Soxco as of December 31, 1994 and 1995,
and for each of the three years in the period ended December 31, 1995, included
in this Prospectus have been audited by Arthur Andersen LLP, independent public
accountants, as indicated in their report with respect thereto, and are included
herein in reliance upon the authority of said firm as experts in giving said
report. Reference is made to said report which includes an explanatory paragraph
with respect to the change in the method of accounting for income taxes in 1993
as discussed in Note 2 to the financial statements.

The audited Historical Summaries of the interests in the oil and gas
properties acquired from TransTexas for each of the three years in the period
ended December 31, 1995 included in this Prospectus, have been included herein
in reliance on the report of Coopers & Lybrand L.L.P., independent accountants,
given on the authority of said firm as experts in accounting and auditing.

65
<PAGE> 66

The reserve reports and estimates of the Company's net proved natural gas
and oil reserves included herein have been prepared by Ryder Scott, NSA,
Huddleston and Miller and Lents. The reserve reports and estimates of Soxco's
net proved natural gas and oil reserves included herein have been prepared by
Ryder Scott, NSA and Huddleston. Summaries of these estimates and the audit
letters of Ryder Scott, NSA, Huddleston and Miller and Lents have been included
in this Prospectus as Appendix A in reliance upon such firms as experts with
respect to such matters.

AVAILABLE INFORMATION

The Company has not previously been subject to the reporting requirements
of the Securities Exchange Act of 1934, as amended. The Company has filed with
the Commission a Registration Statement on Form S-1 (the "Registration
Statement") under the Securities Act, with respect to the offer and sale of
Common Stock pursuant to this Prospectus. This Prospectus, filed as a part of
the Registration Statement, does not contain all of the information set forth in
the Registration Statement or the exhibits and schedules thereto in accordance
with the rules and regulations of the Commission and reference is hereby made to
such omitted information. Statements made in this Prospectus concerning the
contents of any contract, agreement or other document filed as an exhibit to the
Registration Statement are summaries of the terms of such contract, agreement or
document and are not necessarily complete. Reference is made to each such
exhibit for a more complete description of the matters involved. The
Registration Statement and the exhibits and schedules thereto filed with the
Commission may be inspected, without charge, and copies may be obtained at
prescribed rates, at the public reference facility maintained by the Commission
at Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549 and at the
regional offices of the Commission at 7 World Trade Center, New York, New York
10048 and Citicorp Center, 500 West Madison Street, Chicago, Illinois 60661. The
Commission maintains a site on the World Wide Web at http://www.sec.gov that
contains reports, proxy and information statements and other information
regarding registrants that file electronically with the Commission. For further
information pertaining to the Common Stock offered by this Prospectus and the
Company, reference is made to the Registration Statement.

The Company intends to furnish holders of its Common Stock annual reports
containing audited consolidated financial statements as well as quarterly
reports containing unaudited consolidated financial statements for the first
three quarters of each fiscal year.

66
<PAGE> 67

GLOSSARY OF OIL AND GAS TERMS

The definitions set forth below shall apply to the indicated terms as used
in this Prospectus. 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.

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.

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 Bbl per day.

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 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 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.

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

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

Mmbtu. One million Btus.

67
<PAGE> 68

INDEX TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE
-----
<S> <C>
THE HOUSTON EXPLORATION COMPANY:
Report of Independent Public Accountants............................................. F-2
Combined Balance Sheets as of December 31, 1994 and 1995 and (unaudited)
June 30, 1996...................................................................... F-3
Combined Statements of Operations for the Years Ended December 31, 1993, 1994 and
1995 and (unaudited) the Six Months Ended June 30, 1995 and 1996................... F-4
Combined Statement of Stockholder's Equity for the Years Ended December 31, 1993,
1994 and 1995 and (unaudited) the Six Months Ended June 30, 1996................... F-5
Combined Statements of Cash Flows for the Years Ended December 31, 1993, 1994 and
1995 and (unaudited) the Six Months Ended June 30, 1995 and 1996................... F-6
Notes to Combined Financial Statements............................................... F-7

SMITH OFFSHORE EXPLORATION COMPANY:
Report of Independent Public Accountants............................................. F-24
Balance Sheets as of December 31, 1994 and 1995 and (unaudited) June 30, 1996........ F-25
Statements of Operations for the Years Ended December 31, 1993, 1994 and 1995 and
(unaudited) the Six Months Ended June 30, 1995 and 1996............................ F-26
Statements of Cash Flows for the Years Ended December 31, 1993, 1994 and 1995 and
(unaudited) the Six Months Ended June 30, 1995 and 1996............................ F-27
Notes to Financial Statements........................................................ F-28

TRANSTEXAS GAS CORPORATION:
Report of Independent Accountants.................................................... F-42
Historical Summaries of the Interests in the Oil and Gas Revenues and Direct
Operating Expenses of the Properties to be Acquired by the Houston Exploration
Company for the Years Ended December 31, 1993, 1994 and 1995 and (unaudited) the
Six Months Ended June 30, 1995 and 1996............................................ F-43
Notes to the Historical Summaries.................................................... F-44
</TABLE>

F-1
<PAGE> 69

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) as of December 31, 1994 and 1995,
and the related combined statements of operations, stockholder's equity and cash
flows for each of the three years in the period ended December 31, 1995. These
combined 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 combined financial statements referred to above present
fairly, in all material respects, the financial position of The Houston
Exploration Company, as of December 31, 1994 and 1995, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1995, in conformity with generally accepted accounting principles.

ARTHUR ANDERSEN LLP

Houston, Texas
September 19, 1996

F-2
<PAGE> 70

THE HOUSTON EXPLORATION COMPANY

COMBINED BALANCE SHEETS
(IN THOUSANDS, EXCEPT PER SHARE DATA)

<TABLE>
<CAPTION>
DECEMBER 31,
------------------------ JUNE 30,
1994 1995 1996
---------- ---------- ----------
<S> <C> <C> <C>
(UNAUDITED)
ASSETS:
Cash and cash equivalents................................. $ 668 $ 598 $ 4,613
Accounts receivable....................................... 17,995 18,660 16,706
Accounts receivable -- Parent............................. 8,605 6,963 4,982
Inventories............................................... 1,296 963 996
Prepayments and other..................................... 1,557 1,141 382
---------- ---------- ----------
Total current assets.............................. 30,121 28,325 27,679
Natural gas and oil properties, full cost method
Unevaluated properties................................. 25,911 42,286 47,647
Properties subject to amortization..................... 257,102 309,378 332,488
Other property and equipment.............................. 7,378 7,707 8,363
---------- ---------- ----------
290,391 359,371 388,498
Less: Accumulated depreciation, depletion and
amortization........................................... (120,677) (142,693) (154,287)
---------- ---------- ----------
169,714 216,678 234,211
Other assets.............................................. 1,843 2,493 1,952
---------- ---------- ----------
TOTAL ASSETS...................................... $ 201,678 $ 247,496 $ 263,842
========== ========== ==========
LIABILITIES:
Accounts payable and accrued expenses..................... $ 18,767 $ 28,657 $ 19,652
---------- ---------- ----------
Total current liabilities......................... 18,767 28,657 19,652
Long-term debt............................................ 65,650 71,862 77,853
Deferred federal income tax............................... 28,314 43,681 49,885
Other deferred liabilities................................ 81 60 134
---------- ---------- ----------
TOTAL LIABILITIES................................. 112,812 144,260 147,524
COMMITMENTS AND CONTINGENCIES (NOTE 9)
STOCKHOLDER'S EQUITY:
Common Stock, $.01 par value, 50,000 shares authorized and
15,295 issued and outstanding at December 31, 1994 and
1995 and June 30, 1996, respectively................... 153 153 153
Additional paid-in capital................................ 86,256 100,929 111,222
Retained earnings......................................... 2,457 2,154 4,943
---------- ---------- ----------
TOTAL STOCKHOLDER'S EQUITY........................ 88,866 103,236 116,318
---------- ---------- ----------
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY........ $ 201,678 $ 247,496 $ 263,842
========== ========== ==========
</TABLE>

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

F-3
<PAGE> 71

THE HOUSTON EXPLORATION COMPANY

COMBINED STATEMENTS OF OPERATIONS
(IN THOUSANDS EXCEPT PER SHARE DATA)

<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
----------------------------------- ----------------------
1993 1994 1995 1995 1996
--------- --------- --------- --------- ---------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
REVENUES
Natural gas and oil revenues.... $ 37,462 $ 41,755 $ 39,431 $ 20,324 $ 21,252
Other........................... 799 467 1,778 825 535
------- -------- -------- -------- --------
Total revenues.......... 38,261 42,222 41,209 21,149 21,787
OPERATING COSTS AND EXPENSES
Lease operating................. 4,477 5,344 5,468 2,875 3,634
Depreciation, depletion and
amortization................. 23,225 25,365 21,969 11,662 11,571
General and administrative,
net.......................... 2,454 3,460 3,486 1,754 2,702
Nonrecurring charge (Note 10)... -- -- 12,000 -- --
------- -------- -------- -------- --------
Total operating
expenses.............. 30,156 34,169 42,923 16,291 17,907
INCOME (LOSS) FROM OPERATIONS..... 8,105 8,053 (1,714) 4,858 3,880
Interest expense, net............. 1,764 2,102 2,398 1,319 1,118
------- -------- -------- -------- --------
Income (loss) before income
taxes........................... 6,341 5,951 (4,112) 3,539 2,762
Provision (benefit) for federal
income taxes.................... 1,790 597 (3,809) 514 (27)
------- -------- -------- -------- --------
NET INCOME (LOSS)................. $ 4,551 $ 5,354 $ (303) $ 3,025 $ 2,789
======= ======== ======== ======== ========
Net income (loss) per share....... $ 0.30 $ 0.35 $ (0.02) $ 0.20 $ 0.18
Weighted average shares
outstanding..................... 15,295 15,295 15,295 15,295 15,295
</TABLE>

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

F-4
<PAGE> 72

THE HOUSTON EXPLORATION COMPANY

COMBINED STATEMENT OF STOCKHOLDER'S EQUITY
(IN THOUSANDS)

<TABLE>
<CAPTION>
ADDITIONAL RETAINED TOTAL
COMMON PAID IN EARNINGS STOCKHOLDER'S
STOCK CAPITAL (DEFICIT) EQUITY
------ --------- -------- -------------
<S> <C> <C> <C> <C>
Balance at December 31, 1992................ $153 $ 55,677 $ (7,448) $ 48,382

Capital contributions from Parent........... -- 12,558 -- 12,558
Net income.................................. -- -- 4,551 4,551
---- -------- ------ --------
Balance at December 31, 1993................ 153 68,235 (2,897) 65,491

Capital contributions from Parent........... -- 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 Parent........... -- 14,673(1) -- 14,673
Net loss.................................... -- -- (303) (303)
---- -------- ------ --------
Balance at December 31, 1995................ 153 100,929 2,154 103,236
Capital contributions from Parent
(unaudited)............................... -- 10,293 -- 10,293
Net income (unaudited)...................... -- -- 2,789 2,789
---- -------- ------ --------
Balance at June 30, 1996 (unaudited)........ $153 $ 111,222 $ 4,943 $ 116,318
==== ======== ====== ========
</TABLE>

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

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

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

F-5
<PAGE> 73

THE HOUSTON EXPLORATION COMPANY

COMBINED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

<TABLE>
<CAPTION>
DECEMBER 31, JUNE 30,
----------------------------------- ----------------------
1993 1994 1995 1995 1996
--------- --------- --------- --------- ---------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)................................... $ 4,551 $ 5,354 $ (303) $ 3,025 $ 2,789
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Depreciation, depletion and amortization.......... 23,225 25,365 21,969 11,662 11,571
Deferred income tax expense....................... 3,028 5,847 9,632 6,885 6,206
Nonrecurring charge............................... -- -- 12,000 -- --
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable........ 672 4,551 977 (2,948) 3,935
Decrease (increase) in inventories................ 78 (229) 333 276 (33)
Decrease (increase) in prepayments and other...... (472) (450) 416 937 759
Decrease (increase) in other assets............... 722 (1,188) 864 4,487 615
Increase (decrease) in accounts payable and
accrued expenses............................... 9,092 (13,176) 9,890 4,962 (9,005)
-------- -------- -------- -------- --------
Net cash provided by operating activities........... 40,896 26,074 55,778 29,286 16,837
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment................ (58,557) (64,996) (70,249) (37,212) (30,629)
Dispositions and other.............................. (53) (63) 1,316 37 1,523
-------- -------- -------- -------- --------
Net cash used in investing activities............... (58,610) (65,059) (68,933) (37,175) (29,106)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from long-term borrowings.............. 5,800 19,050 6,212 7,232 5,991
Capital contributions from Parent................... 12,558 18,021 6,873 791 10,293
-------- -------- -------- -------- --------
Net cash provided by financing activities........... 18,358 37,071 13,085 8,023 16,284
Increase (decrease) in cash and cash equivalents.... 644 (1,914) (70) 134 4,015
Cash and cash equivalents, beginning of period...... 1,938 2,582 668 668 598
-------- -------- -------- -------- --------
Cash and cash equivalents, end of period............ $ 2,582 $ 668 $ 598 $ 802 $ 4,613
======== ======== ======== ======== ========
Cash paid for interest.............................. $ 2,259 $ 3,318 $ 4,658 $ 2,290 $ 2,253
======== ======== ======== ======== ========
Cash paid for income taxes.......................... $ 5,423 $ -- $ -- $ -- $ --
======== ======== ======== ======== ========
</TABLE>

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

F-6
<PAGE> 74

THE HOUSTON EXPLORATION COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS

NOTE 1 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization

The Houston Exploration Company ("Houston Exploration" or the "Company"),
is an indirect wholly owned subsidiary of The Brooklyn Union Gas Company
("Brooklyn Union" or the "Parent"), a New York corporation. Houston Exploration
is a Delaware corporation, 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 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
West Virginia, East Texas and the Arkoma Basin.

Effective February 29, 1996 Brooklyn Union implemented a reorganization
(the "Reorganization") of its exploration and production assets and liabilities
by transferring to Houston Exploration certain onshore producing properties and
acreage not previously owned by Houston Exploration. These combined financial
statements have been prepared giving effect to the transfer of these assets and
liabilities from the time of 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.

The financial statements reflect, retroactively, for all periods presented
(i) the increase in the authorized number of shares of common and preferred
stock to 50,000,000 and 5,000,000, respectively, and (ii) the conversion and
reclassification of each outstanding share of common stock of the Company 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
Offering. (See Note 12 -- Subsequent Events.)

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 immediately prior to the completion of the Offering after giving
effect to the split referred to above.

Interim Financial Statements

The financial statements for the six months ended June 30, 1995 and 1996
have been prepared without audit pursuant to the rules and regulations of the
Securities and Exchange Commission. Accordingly, such statements include all
adjustments, consisting only of normal recurring adjustments, which are, in the
opinion of management, necessary for a fair presentation of the Company's
financial position, results of operations and cash flows. Interim period results
are not necessarily indicative of the results to be achieved for an entire year.

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 13 -- Supplemental
Information on Natural Gas and

F-7
<PAGE> 75

THE HOUSTON EXPLORATION COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

Oil Exploration, Development and Production Activities). Because there are
numerous uncertainties inherent in the estimation process, actual results could
differ from the estimates.

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 quantities
and such differences could materially affect future amortization of natural gas
and oil properties. The Company believes that unevaluated properties at December
31, 1995 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

The Company adopted Statement of Financial Accounting Standards No. 109,
"Accounting for Income Taxes" ("SFAS 109"), effective January 1, 1993. Under
SFAS 109, 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

F-8
<PAGE> 76

THE HOUSTON EXPLORATION COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

financial reporting purposes that differ from those used for income tax
reporting purposes. The cumulative effect of adopting SFAS 109 was not
significant.

The Company is included in the consolidated federal income tax return of
Brooklyn Union. Under the Company's tax sharing agreement with Brooklyn Union,
the Company receives or pays 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.

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 $1.2 million, and $1.3 million and
$1.2 million for the years ended December 31, 1993, 1994 and 1995, 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 1993, 1994 and 1995,
aggregated $4.4 million, $3.9 million and $4.1 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, 1993, 1994 and 1995 interest
costs of $0.7 million, $1.5 million and $2.9 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 underdeliveries are
reflected as assets. Production imbalances are valued using current market
prices. Production imbalances were not material as of December 31, 1994 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

F-9
<PAGE> 77

THE HOUSTON EXPLORATION COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

as a component of natural gas revenues in accordance with a hedged transaction.
Natural gas revenues were reduced by $10.7 million and $0.8 million during 1993
and 1994 and were increased by $5.6 million in 1995, relative to these
contracts. (See Note 7 -- 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 would account for its financial instrument positions as
trading activities and mark-to-market its open positions. At December 31, 1995
the Company recognized a pretax loss of $0.7 million attributable to hedges in
place at year end that lost correlation with the cash market price.

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.

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.

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
$74 million at December 31, 1994 and $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, 1994 and 1995 $65.7 million and $71.9 million, respectively, were
outstanding under the Prior Credit Facility, and letter of credit obligations of
$1.6 million were outstanding at the end of both 1994 and 1995. 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,
1993, 1994 and 1995 was 6.3%, 7.4% and 6.9%, respectively.

F-10
<PAGE> 78

THE HOUSTON EXPLORATION COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

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 Fuel Resources Inc. ("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. At June 30, 1996 $77.9 million was outstanding under
the Interim Credit Facility and outstanding letter of credit obligations were
$1.6 million.

Interest was payable on borrowings under the Interim Credit Facility at an
alternated 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: (1) between 0.20% and
0.375% per annum on the unused portion of the Accepted Borrowing Base, (2)
0.125% per annum on the difference between the Borrowing Base and the Accepted
Borrowing Base with a 0.3125% clawback on any usage of the difference, and (3)
0.0625% per annum on the difference between the lower of the Facility Amount of
the Borrowing Base 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 is 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 ("New Credit Facility"). The
New 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 July 2, 1996. In addition, up to $5
million of the New Credit Facility will be available for the issuance of letters
of credit to support performance guarantees. The New Credit Facility matures on
July 1, 2000. The New Credit Facility is secured by a pledge of all of the
Company's outstanding capital stock; however, upon the closing of the Company's
initial public offering the pledged shares will be released and the facility
will be unsecured.

Interest is payable on borrowings under the New 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: (1)
between 0.20% and 0.375% per annum on the unused portion of the Designated
Borrowing Base, and (2) 33% of the fee in (1) above on the difference between
the lower of the Facility Amount or the Borrowing Base and the Designated
Borrowing Base.

The New Credit Facility covenants require the maintenance of a defined net
worth of $95 million plus 50% of net income and 75% of net equity proceeds,
total debt to total capitalization of no greater than 60% prior to the offering
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 July 31, 1996, the Company was in compliance
with all such covenants.

F-11
<PAGE> 79

THE HOUSTON EXPLORATION COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 3 -- STOCKHOLDER'S EQUITY

Effective July 1, 1994 the Company adopted a Long-Term Stock Incentive Plan
(the "1994 Incentive Plan") for its officers, directors and other key employees.
The 1994 Incentive Plan allows for the granting of nonqualified stock options,
which may include tandem phantom option shares while the Company remains a
privately owned entity. The number of shares of common stock subject to stock
option grants cannot exceed 10% of the Company's common shares outstanding, and
the exercise price of options granted under the 1994 Incentive Plan may not be
less than the fair market value of the common stock at the date the option is
granted. On July 1, 1994, the Company granted options to purchase an aggregate
of 247,000 shares of common stock to certain officers and directors of the
Parent, with an exercise price of $11.22 per share. As of December 31, 1995, no
options had been exercised. (See Note 12 -- Subsequent Events.)

<TABLE>
<CAPTION>
SHARES PRICE
-------- -------
<S> <C> <C>
Options outstanding at December 31, 1994.............. 247,000 $ 11.22
Options granted during 1995........................... -- --
Options outstanding at December 31, 1995.............. 247,000 $ 11.22
======= ======
Options available for grant........................... --
=======
</TABLE>

NOTE 4 -- INCOME TAXES

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

<TABLE>
<CAPTION>
1993 1994 1995
------- ------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Current................................ $(1,238) $(5,250) $(13,441)
Deferred............................... 3,028 5,847 9,632
------- ------- --------
Total.................................. $ 1,790 $ 597 $ (3,809)
======= ======= ========
</TABLE>

Amounts received from the Parent pursuant to the established tax-sharing
agreement were $2.3 million and $14.6 million in 1994 and 1995 respectively.
During 1993, the Company paid the Parent $5.4 million pursuant to the
tax-sharing agreement. State taxes are not considered material for the years
ended 1993, 1994 and 1995, respectively.

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

<TABLE>
<CAPTION>
1993 1994 1995
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Income (loss) before income taxes........... $ 6,341 $ 5,951 $(4,112)
Statutory rates............................. 35% 35% 35%
Income tax (benefit) computed at statutory
rates..................................... 2,219 2,083 (1,439)
Reconciling items:
Section 29 tax credits.................... (1,023) (1,529) (1,985)
Percentage depletion...................... (73) (27) (231)
Adjustments from change in tax rates...... 534 -- --
Other..................................... 133 70 (154)
------- ------- -------
Tax expense (benefit)....................... $ 1,790 $ 597 $(3,809)
======= ======= =======
</TABLE>

F-12
<PAGE> 80

THE HOUSTON EXPLORATION COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

Deferred Income Taxes

Deferred income tax provisions for the years ended December 31, 1993, 1994
and 1995 result from the following temporary differences:

<TABLE>
<CAPTION>
1993 1994 1995
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Temporary differences related to natural gas and oil
properties:
Intangible drilling costs......................... $ 3,460 $ 6,182 $12,067
Nonrecurring charge............................... -- -- (3,200)
Depreciation and depletion........................ (4,614) (6,049) (2,229)
Dry hole costs.................................... 835 2,871 35
Capitalized general and administrative expense.... 1,240 1,243 1,429
Impairment of properties.......................... 501 1,334 1,145
Abandonment of properties......................... 474 -- --
Lease rentals..................................... 89 104 132
Other............................................. 1,043 162 253
------- ------- -------
Total deferred tax expense................ $ 3,028 $ 5,847 $ 9,632
======= ======= =======
</TABLE>

The Company's deferred tax position reflects the net tax effects of
temporary differences between the carrying amounts of assets and liabilities for
financial reporting purposes and the amounts used for income tax reporting. At
December 31, 1993, 1994 and 1995 the Company did not have deferred tax assets
(net operating loss carryforwards or alternative minimum taxes).

NOTE 5 -- RELATED PARTY TRANSACTIONS

Transactions with the Parent are comprised of the following:

<TABLE>
<CAPTION>
1993 1994 1995
------- ------- -----
(IN THOUSANDS)
<S> <C> <C> <C>
Gas sales..................................... $ 1,067 $ 1,335 $ --
Gathering fee income.......................... 361 244 --
General and administrative costs.............. 839 776 724
</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 the Parent for certain general and administrative costs and receives
overhead allocations for other 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 October 1992, amended as of
November 1, 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"), an affiliate of Brooklyn Union. The new contract extends
until March 31, 1998, and year to year thereafter. Under the terms of the
agreement, the Company has agreed to sell and PennUnion has agreed to buy a
substantial portion of the Company's production at index-related prices. The
agreement contains 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.

F-13
<PAGE> 81

THE HOUSTON EXPLORATION COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

For the years ended December 31, 1993, 1994 and 1995, the Company had
natural gas sales of $32.9 million, $26.4 million and $18.9 million,
respectively, to PennUnion and BRING. At year end December 31, 1994 and 1995,
the Company had receivables of $1.0 million and $2.0 million, respectively,
relating to natural gas sales to PennUnion and BRING.

Employment Contracts

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 1993, 1994 and
1995, affiliates of the Company's President obtained a 5% working interest in 12
wells operated by the Company pursuant to such agreement. In addition, during
1993, 1994 and 1995, affiliates of the Company's President paid $0.9 million,
$0.7 million and $0.7 million, respectively, in expenses attributable to working
interests owned in properties operated by the Company, and received $2.6
million, $1.6 million and $0.9 million, respectively, in distributions
attributable to such working interests. (See Note 11 -- 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. (See Note 12 --
Subsequent Events.)

NOTE 6 -- EMPLOYEE BENEFIT 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's 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, 1993, 1994 and 1995, Company's contributions to the 401(k) Plan were
$115,000, $145,000 and $157,000, respectively.

F-14
<PAGE> 82

THE HOUSTON EXPLORATION COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 7 -- FINANCIAL INSTRUMENTS

<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------------------------
1994 1995
---------------------- ----------------------
CARRYING ESTIMATED CARRYING ESTIMATED
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
-------- ---------- -------- ----------
<S> <C> <C> <C> <C>
Cash and cash equivalents.......................... $ 668 $ 668 $ 598 $ 598
Long-term debt..................................... 65,650 65,650 71,862 71,862
Derivative transactions:
Interest rate swap agreements
In a receivable position...................... -- -- -- --
In a payable position......................... -- -- -- (86)
Commodity price and basis swaps:
In a receivable position...................... -- 6,069 -- --
In a payable position......................... -- -- (704) (3,982)
Commodity futures:
In a receivable position...................... -- 41 -- --
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.

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, 1995. At December 31, 1995, the Company had three interest rate
swap agreements to exchange an aggregate notional principal of $19.0 million
over various periods from January 1996 through November 1998 at rates between
5.39% and 5.66%.

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

F-15
<PAGE> 83

THE HOUSTON EXPLORATION COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

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.

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. At December 31, 1995, the
Company had fixed-price swap agreements and basis swap agreements to exchange a
total notional volume of 38,135 MMmbtu of natural gas over the period January
1996 through December 1997.

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, 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. In addition, the
Company had margin deposits relating to futures contracts held with brokers of
$0.2 million outstanding at December 31, 1995.

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
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 8 -- 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 years ended December 31, 1993, 1994 and 1995, PennUnion and BRING
were the only customers for which sales exceeded 10% of total revenues. During
1993, 1994 and 1995, sales to PennUnion and BRING comprised 86%, 63% and 46%,
respectively, of total revenues. (See Note 5 -- 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
affect on the Company's operations.

F-16
<PAGE> 84

THE HOUSTON EXPLORATION COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 9 -- 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 affect on the financial
position or results of operations of the Company. In addition, the Company has
been named in a suit involving certain former employees of Fuel Resources Inc.
("FRI"), as more fully discussed in Note 10 -- Nonrecurring Charge.

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>
MINIMUM NET MINIMUM
RENTAL SUBLEASE RENTAL
COMMITMENTS RENTALS COMMITMENTS
----------- -------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
1996....................................... $ 522 $ (238) $ 284
1997....................................... 431 (244) 187
1998....................................... 354 (246) 108
1999....................................... 361 (250) 111
2000....................................... 364 (252) 112
Thereafter................................. 171 (135) 36
------ ------- ------
$ 2,203 $(1,365) $ 838
====== ======= ======
</TABLE>

Net rental expense related to these leases for the years ended December 31,
1993, 1994 and 1995 were $0.2 million, $0.3 million and $0.3 million,
respectively.

Guarantee of PennUnion Accounts Payable

Pursuant to the PennUnion joint venture agreement between Pennzoil Gas
Marketing and BRING, the Company has guaranteed certain trade payables of
PennUnion (not including PennUnion's trade payable to the Company). The
outstanding balances under these guarantees were $2.9 million and $3.9 million
at December 31, 1994 and 1995. The Company is of the opinion that PennUnion will
be able to perform under its obligations and that no losses will be incurred
pursuant to such guarantees.

NOTE 10 -- NONRECURRING CHARGE

F-17
<PAGE> 85

THE HOUSTON EXPLORATION COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

indemnification obligations. The Company believes that it will not be required
to pay any damages resulting from such suit, even if a judgment adverse to the
Company is rendered in the suit, as a result of such arrangements. As of
December 31, 1995, the Company accrued a $12 million nonrecurring charge related
to these obligations which it believes is adequate to provide for the settlement
of these obligations and the ultimate resolution of the lawsuit. However, the
Company would incur a non-cash charge in addition to the $12 million charge
recorded by the Company in the event such damages are determined to be in excess
of $12 million, which would have the effect of reducing the Company's reported
income (or resulting in or increasing a loss) in the period in which such
additional charge is determined. Accordingly, management of the Company believes
that the ultimate resolution of these claims will not have a material adverse
impact on the Company's future financial position or results of operations.

NOTE 11 -- 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 156 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 is
subject to adjustment based upon production 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 has agreed to loan 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 New 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. The outstanding balance owed by
Mr. Floyd under the agreement will mature on July 2, 2006.

Soxco

On July 1, 1996, the Company entered into an asset purchase agreement with
Smith Offshore Exploration Company ("Soxco"), providing for the acquisition by
the Company of substantially all of the natural gas and oil properties and
related assets of Soxco (the "Soxco Acquisition"). Soxco's natural gas and oil
properties consist 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 will pay Soxco
cash in the aggregate amount of $23.7 million (subject to certain adjustments),
and issue to Soxco 762,387 shares of common stock with an aggregate value
(determined by reference to the initial public offering price) of $11.8 million.
The cash portion of the purchase price will be funded with the proceeds of the
Offering. In addition to the foregoing, the Company will pay Soxco a deferred
purchase price of up to

F-18
<PAGE> 86

THE HOUSTON EXPLORATION COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

$17.6 million payable in two installments, on January 31, 1997 and January 31,
1998. The amount of the deferred purchase price installments 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. The Soxco Acquisition will close
concurrently with, is conditioned upon and is a condition to the completion of
the Offering.

NOTE 12 -- SUBSEQUENT EVENTS (UNAUDITED)

Stock Offering

The Company intends to sell approximately 28% of its common stock in an
initial public offering ("Offering").

In connection with the Offering, the Company's board approved an increase
in the authorized capital stock of the Company, consisting of 50,000,000 shares
of common stock, par value $.01 per share, and 5,000,000 shares of preferred
stock, par value $.01 per share. Additionally, approval was obtained to increase
the number of shares of common stock issued and outstanding to 15,295,215
effective immediately prior to the completion of the Offering.

Concurrently, with the completion of the Offering, the Company's President
will exchange certain of his after program-payout working interests for shares
of common stock with a value (at the initial offering price) of $2.3 million.

1996 Stock Option Plan

Prior to completion of the Offering, it is anticipated that the Board of
Directors will adopt the Company's 1996 Stock Option Plan (the "Incentive Plan")
and that Holdings will approve the Incentive Plan as adopted.

Employment Contracts

Certain employees of the Company will enter into employment agreements with
the Company effective as of the Closing of the Offering pursuant to which they
serve as executive officers of the Company. The President's existing employment
agreement with the Company will be terminated effective as of such time. (See
Note 5 -- Related Party Transactions).

Supplemental Executive Retirement Plan

Effective immediately prior to the Offering, the Company will adopt an
unfunded, nonqualified Supplemental Executive Retirement Plan for the benefit of
the President.

1994 Incentive Plan

Upon completion of the Offering, the options under this plan will be
terminated in exchange for a cash payment by the Company in the aggregate amount
of approximately $840,000.

F-19
<PAGE> 87

THE HOUSTON EXPLORATION COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 13 -- 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, 1993, 1994 and 1995, the Company's capitalized costs of
natural gas and oil properties are as follows:

<TABLE>
<CAPTION>
1993 1994 1995
--------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Unevaluated properties, not
amortized........................... $ 11,498 $ 25,911 $ 42,286
Properties subject to amortization.... 205,868 257,102 309,378
--------- ---------- ----------
Capitalized costs..................... 217,366 283,013 351,664
Accumulated depreciation, depletion
and amortization.................... (93,333) (118,392) (137,769)
--------- ---------- ----------
Net capitalized costs................. $ 124,033 $ 164,621 $ 213,895
========= ========== ==========
</TABLE>

The following is a summary of the costs which are excluded from the
amortization calculation as of December 31, 1995, 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, 1995 will be fully evaluated within five years.

<TABLE>
<CAPTION>
(IN THOUSANDS)
<S> <C>
1995.................................................. $ 27,439
1994.................................................. 10,609
1993.................................................. 2,727
Prior................................................. 1,511
-----------
$ 42,286
===========
</TABLE>

F-20
<PAGE> 88

THE HOUSTON EXPLORATION COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

Costs incurred for natural gas and oil exploration, development and
acquisition are summarized below. Costs incurred during the years ended December
31, 1993, 1994 and 1995 include general and administrative costs related to
acquisition, exploration and development of natural gas and oil properties, of
$4.4 million, $3.9 million and $4.1 million, respectively.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------
1993 1994 1995
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Property acquisition:
Unevaluated(1)....................... $ 6,646 $ 11,148 $ 9,902
Proved............................... 34,596 24,628 11,137
Exploration costs...................... 5,983 17,430 7,224
Development costs...................... 11,332 11,790 41,163
-------- -------- --------
Total costs incurred......... $ 58,557 $ 64,996 $ 69,426
======== ======== ========
</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.

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.

F-21
<PAGE> 89

THE HOUSTON EXPLORATION COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

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.

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,
-------------------------------------
1993 1994 1995
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows............................. $ 250,745 $ 259,811 $ 418,822
Future production costs......................... (62,125) (45,428) (66,458)
Future development costs........................ (13,494) (21,973) (24,803)
Future income taxes............................. (26,592) (28,714) (74,933)
-------- -------- --------
Future net cash flows........................... 148,534 163,696 252,628
10% annual discount for estimated timing of cash
flows......................................... (42,473) (45,262) (81,169)
-------- -------- --------
Standardized measure of discounted future net
cash flows.................................... $ 106,061 $ 118,434 $ 171,459
======== ======== ========
</TABLE>

Future cash inflows include the effect of hedges in place at year end
December 31, 1993, 1994 and 1995. At December 31, 1993 and 1995, the effect of
the hedges in place is a reduction to future cash inflows of $12.3 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.

F-22
<PAGE> 90

THE HOUSTON EXPLORATION COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)

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

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-------------------------------------
1993 1994 1995
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Beginning of the year........................... $ 95,255 $ 106,061 $ 118,434
Revisions to previous estimates:
Changes in prices and costs................... (29,083) (10,077) 35,497
Changes in quantities......................... (3,914) (2,393) 11,306
Changes in future development costs........... (7,964) 511 531
Development costs incurred during the period.... 9,231 4,652 8,074
Extensions and discoveries, net of related
costs......................................... 5,515 22,723 51,061
Sales of natural gas and oil, net of production
costs......................................... (32,864) (36,156) (34,843)
Accretion of discount........................... 11,863 11,326 12,815
Net change in income taxes...................... 13,082 (272) (24,720)
Purchase of reserves in place................... 44,544 23,146 11,189
Sale of reserves in place....................... -- (1,906) (19)
Production timing and other..................... 396 819 (17,866)
-------- -------- --------
End of year..................................... $ 106,061 $ 118,434 $ 171,459
======== ======== ========
</TABLE>

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, 1993, 1994
and 1995.

<TABLE>
<CAPTION>
NATURAL GAS CRUDE OIL AND CONDENSATE
(MMCF) (MBBLS)
----------------------------------- --------------------------
1993 1994 1995 1993 1994 1995
--------- --------- --------- ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
Proved developed and undeveloped
reserves:
Beginning of year.............. 88,480 118,118 145,945 498 536 636
Revisions of previous
estimates................... (2,841) (1,912) 15,702 (98) (104) 51
Extensions and discoveries..... 4,022 25,867 45,014 3 151 254
Production..................... (22,555) (22,437) (21,077) (101) (102) (100)
Purchase of reserves in
place....................... 51,012 27,949 10,367 234 205 48
Sale of reserves in place...... -- (1,640) (5) -- (50) --
-------- -------- -------- ----- ----- -----
End of year.................... 118,118 145,945 195,946 536 636 889
======== ======== ======== ===== ===== =====
Proved developed reserves:
Beginning of year.............. 70,679 107,909 104,678 433 478 328
End of year.................... 107,909 104,678 162,784 478 328 774
</TABLE>

F-23
<PAGE> 91

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareholders and
the Board of Directors of
Smith Offshore Exploration Company:

We have audited the accompanying balance sheets of Smith Offshore
Exploration Company (a Delaware corporation) as of December 31, 1994 and 1995,
and the related statements of operations and cash flows for each of the three
years in the period ended December 31, 1995. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

As discussed in Note 1, the Company has entered into an asset purchase
agreement on July 1, 1996 for the sale of substantially all of the Company's oil
and gas assets to The Houston Exploration Company. If the sale transaction is
consummated, the purchaser's basis in the assets will differ from that reflected
in the Company's historical financial statements at December 31, 1995. The
impact of the sale, and ultimate allocation of net proceeds in connection with
the disposition of the Company's other assets and liabilities including payments
to zero coupon noteholders (see Note 4), on the Company's historical financial
statements could be significant; however, no adjustments have been made in the
accompanying financial statements to reflect these proposed transactions.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Smith Offshore Exploration
Company as of December 31, 1994 and 1995, and the results of its operations and
its cash flows for each of the three years in the period ended December 31, 1995
in conformity with generally accepted accounting principles.

As discussed in Note 2 to the financial statements, effective January 1,
1993, the Company changed its method of accounting for income taxes.

ARTHUR ANDERSEN LLP

Houston, Texas
September 19, 1996

F-24
<PAGE> 92

SMITH OFFSHORE EXPLORATION COMPANY

BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)

<TABLE>
<CAPTION>
DECEMBER 31,
---------------------- JUNE 30,
1994 1995 1996
--------- -------- -----------
(UNAUDITED)
<S> <C> <C> <C>
ASSETS:
Cash and cash equivalents................................ $ 494 $ 785 $ 1,352
Short-term investments................................... 100 100 100
Accounts receivable
Oil and gas sales..................................... 2,748 1,857 1,568
Gas sales imbalance................................... 135 44 6
Affiliates and other.................................. 12 43 0
Inventory................................................ 131 74 74
Prepaid associated costs and well costs.................. 146 -- --
Prepaid expenses and other assets........................ 84 36 8
-------- --------- ---------
Total current assets............................. 3,850 2,939 3,108
-------- --------- ---------
Oil and gas properties, full-cost method
Evaluated properties.................................. 122,610 130,963 131,874
Unevaluated properties................................ 4,766 5,335 5,624
Less: Accumulated depreciation, depletion and
amortization.......................................... (94,540) (101,418) (103,837)
-------- --------- ---------
32,836 34,880 33,661
-------- --------- ---------
Furniture, fixtures and other, net......................... 151 108 99
Other assets, net.......................................... 63 57 46
-------- --------- ---------
TOTAL ASSETS..................................... $ 36,900 $ 37,984 $ 36,914
======== ========= =========
LIABILITIES:
Current portion of long-term debt........................ $ 7,614 $ 7,956 $ 4,578
Accounts payable and accrued liabilities................. 2,558 744 711
Accrued interest payable................................. 58 175 195
-------- --------- ---------
Total current liabilities........................ 10,230 8,875 5,484
-------- --------- ---------
Long-term debt............................................. 7,718 10,569 11,800
Zero coupon notes payable.................................. 80,195 92,184 98,827
-------- --------- ---------
TOTAL LIABILITIES................................ 98,143 111,628 116,111
-------- --------- ---------
SHAREHOLDERS' EQUITY:
Preferred Stock (Class A), $0.01 par value; 3,209,375
shares authorized, issued and outstanding............. 32 32 32
Common Stock, $0.01 par value; 4,279,168 shares
authorized; 1,069,792 issued and outstanding.......... 11 11 11
Additional paid-in capital............................... 15,150 15,150 15,150
Accumulated deficit...................................... (76,436) (88,837) (94,390)
-------- --------- ---------
TOTAL SHAREHOLDERS' EQUITY....................... (61,243) (73,644) (79,197)
-------- --------- ---------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY....... $ 36,900 $ 37,984 $ 36,914
======== ========= =========
</TABLE>

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

F-25
<PAGE> 93

SMITH OFFSHORE EXPLORATION COMPANY

STATEMENTS OF OPERATIONS
(IN THOUSANDS)

<TABLE>
<CAPTION>
SIX MONTHS
YEARS ENDED DECEMBER 31, ENDED JUNE 30,
----------------------------- ------------------
1993 1994 1995 1995 1996
------- ------- ------- ------- -------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
REVENUES:
Oil and gas sales...................... $26,123 $18,536 $10,372 $ 5,587 $ 5,235
Interest income and other income....... 70 89 73 51 27
------- ------- ------- ------- -------
Total Revenues................. 26,193 18,625 10,445 5,638 5,262
------- ------- ------- ------- -------
COSTS AND EXPENSES:
General and administrative............. 569 586 837 339 346
Outside professional services.......... 313 499 501 236 157
Production............................. 2,634 2,654 2,012 1,062 891
Depreciation, depletion and
amortization........................ 20,317 15,618 6,931 4,487 2,438
Impairment of oil and gas properties... 4,000 20,000 -- -- --
Interest............................... 11,477 11,107 12,550 5,831 6,974
Other.................................. 52 46 15 10 8
------- ------- ------- ------- -------
Total costs and expenses....... 39,362 50,510 22,846 11,965 10,814
------- ------- ------- ------- -------
Loss before income taxes ($0 for all
periods) and cumulative effect of
change in accounting principle......... 13,169 31,885 12,401 6,327 5,552
Cumulative effect of change in accounting
principle (SFAS No. 109)............... 716 -- -- -- --
------- ------- ------- ------- -------
Net loss................................. $12,453 $31,885 $12,401 $ 6,327 $ 5,552
======= ======= ======= ======= =======
</TABLE>

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

F-26
<PAGE> 94

SMITH OFFSHORE EXPLORATION COMPANY

STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

<TABLE>
<CAPTION>
DECEMBER 31, JUNE 30,
----------------------------------- --------------------
1993 1994 1995 1995 1996
--------- --------- --------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss........................................ $ (12,453) $ (31,885) $ (12,401) $ (6,327) $ (5,552)
Adjustments to reconcile net loss to net cash
provided by operating activities:
Interest..................................... 10,817 10,339 11,566 5,355 6,393
Depreciation, depletion and amortization..... 20,317 15,618 6,931 4,487 2,438
Impairment of oil and gas properties......... 4,000 20,000 -- -- --
Cumulative effect of change in accounting
principle (SFAS No. 109)................... (716) -- -- -- --
Decrease (Increase) in accounts receivable... 2,413 1,179 951 571 370
Decrease (Increase) in prepaid expenses and
other assets............................... (23) (4) 10 67 28
-------- -------- -------- ------- -------
Net cash provided by operating activities....... 24,355 15,247 7,057 4,153 3,677
-------- -------- -------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES:
Changes in prepaid associated costs and well
costs........................................ 597 639 146 49 --
Additions to oil and gas properties............. (14,812) (9,888) (8,351) (5,817) (917)
Increase (Decrease) in amounts owed for oil and
gas property additions....................... 1,530 (2,324) (1,814) (305) (33)
Purchases of furniture, fixtures and other...... (46) (97) (10) (9) (10)
Transfers of inventory.......................... 92 34 95 (2) --
-------- -------- -------- ------- -------
Net cash used in investing activities........ (12,639) (11,636) (9,934) (6,084) (960)
-------- -------- -------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt........ 15,506 5,180 8,268 7,220 51
Repayment of long-term debt..................... (11,500) (10,153) (5,076) (5,076) (2,198)
Repayment of zero coupon notes.................. (16,047) -- -- -- --
Additions of other assets -- debt costs......... -- (56) (24) -- (3)
-------- -------- -------- ------- -------
Net cash (used in) provided by financing
activities................................... (12,041) (5,029) 3,168 2,144 (2,150)
-------- -------- -------- ------- -------
Net increase (decrease) in cash and cash
equivalents..................................... (325) (1,418) 291 213 567
Cash and cash equivalents, beginning of period.... 2,237 1,912 494 494 785
-------- -------- -------- ------- -------
Cash and cash equivalents, end of period.......... $ 1,912 $ 494 $ 785 707 1,352
======== ======== ======== ======= =======
</TABLE>

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

F-27
<PAGE> 95

SMITH OFFSHORE EXPLORATION COMPANY

NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 1995 AND JUNE 30, 1996

(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT AGREEMENTS

Organization

Smith Offshore Exploration Company (the "Company") was organized on January
12, 1987, under the laws of the State of Delaware. The Company is active in oil
and gas exploration and development primarily offshore in the Gulf of Mexico
area.

The Exploration Agreement

Pursuant to the terms of an Exploration Agreement, as renewed, extended and
restated (the "Agreement"), the Company agreed to participate with The Houston
Exploration Company ("HOUEX"), formerly Brooklyn Union Exploration Company,
Inc., in the exploration, development and production of oil and gas in the Gulf
of Mexico area. The Agreement provides for HOUEX to be the operator of the
properties. Under the terms of the Agreement, the Company committed to a maximum
of $60,000,000 to be expended for exploration activities over a four-year period
ended December 31, 1990, and a secondary term of two years ended December 31,
1992. The Company now continues to participate in certain exploration and
development activities with HOUEX pursuant to the terms of joint operating
agreements.

The Company pays its proportionate share of costs and expenses. Pursuant to
a letter agreement with HOUEX effective March 1, 1992, the Company and a former
affiliate, Smith Offshore Exploration Company II ("SOXCO II"), paid $375,000 of
HOUEX's general and administrative expenses during the first six months of 1995
and $750,000 during 1994 and 1993. The terms of the letter agreement terminated
on June 30, 1995. Such amounts are allocated between the Company and SOXCO II
based on relative capital and production expenditures during each month. The
Company paid or accrued approximately $219,000, $462,000 and $693,000 as
reimbursement for the Company's share of HOUEX's general and administrative
expenses during the years ended December 31, 1995, 1994 and 1993. The Company
paid or accrued $799,000, $7,779,000 and $8,746,000 for prospect acquisition,
evaluation and drilling costs billed by HOUEX during the six months ended June
30, 1996 and the years ended December 31, 1995 and 1994, respectively.

In addition, the Company paid HOUEX fees (termed "Associated Costs") of
$6,000,000 prior to 1992. Pursuant to the terms of the Agreement, no additional
Associated Costs are due HOUEX.

The lease interests included in the exploration venture are burdened by a
2% net profits interest on a prospect-by-prospect basis and an overriding
royalty of 4% of the net revenue interest pursuant to agreements between HOUEX
and several individuals. These burdens are shared by the Company in proportion
to its interest in the particular leases.

Agreement Negotiated to Sell Oil and Gas Assets to HOUEX

On April 30, 1996, the Company and HOUEX entered into a non-binding letter
of intent setting forth the general terms pursuant to which HOUEX would acquire
substantially all of the Company's oil and gas assets. The Definitive Asset
Purchase Agreement (the "Agreement") was entered into on July 1, 1996 and has
been approved by both companies' boards of directors and respective
stockholders. The purchase will take place contemporaneously with an initial
public offering of HOUEX's common stock. The effective date of the transaction
will be January 1, 1996 (the "Effective Date").

The Company will receive a purchase price ranging from a minimum of
approximately $44.3 million to a maximum of approximately $53.1 million with the
ultimate amount within that range

F-28
<PAGE> 96

SMITH OFFSHORE EXPLORATION COMPANY

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31, 1995 AND JUNE 30, 1996

depending upon the amount of probable reserves that are reclassified to proved
by December 31, 1997.

Consideration for the sale of its oil and gas assets will be paid to the
Company on the following basis:

Cash -- The Company will receive approximately $23.7 million of cash
at closing. It will use a substantial portion of such cash proceeds to
retire all outstanding debt (other than zero coupon notes "ZCN") on the
closing date of the HOUEX transaction (the "Closing").

Stock Issued at Closing -- The Company will receive shares of common
stock of HOUEX (valued at the IPO price) equal to approximately
$11,803,000.

Stock Issued on 1/31/97 and 1/31/98 -- The Company will receive shares
of common stock of HOUEX (valued at the fair market value of the stock on
those dates) equal to a minimum of approximately $8.8 million and a maximum
of approximately $17.6 million (depending upon the amount of probable
reserves transferred to proved as of December 31, 1996 and December 31,
1997) (the "Deferred Purchase Price").

HOUEX stock received by the Company will be unregistered and will
constitute "restricted stock" under the federal securities laws. The Company's
investors will have demand registration rights (once at HOUEX's expense [other
than underwriting discounts and sales commissions] and up to two additional
times at the expense of the investors making such demand), as well as unlimited
"piggyback" registration rights.

The cash portion of the consideration to be paid to the Company at closing
will be adjusted as follows:

o HOUEX will be reimbursed for revenues the Company received for production
after the Effective Date,

o the Company will be reimbursed for capital expenditures, lease operating
expenses and production taxes it incurred after the Effective Date, and

o the Company will be reimbursed by HOUEX for interest it paid or accrued
on bank debt and investor loans after the Effective Date.

Pursuant to the terms of the Agreement, the Company will retain the
following assets:

o cash and short-term investments,

o accounts receivable for oil and gas sales as of December 31, 1995,

o all other accounts receivable (except any receivable attributable to gas
imbalances),

o prepaid expenses (other than any prepayments to HOUEX), and

o furniture, fixtures and equipment.

The Company will retain all liabilities not specifically assumed by HOUEX,
including, without limitation, the following liabilities:

o accounts payable and accrued liabilities as of December 31, 1995,

o ZCN,

F-29
<PAGE> 97

SMITH OFFSHORE EXPLORATION COMPANY

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31, 1995 AND JUNE 30, 1996

o bank debt and investor loans (the Company will retire all debt except ZCN
at closing of the transaction),

o liabilities for federal or state income taxes or franchise taxes,

o liabilities to Smith Management Company or to any third parties for
services rendered,

o severance pay for employees,

o liabilities with respect to operations and events prior to the Effective
Date, and

o liabilities with respect to any breaches or failures of its
representations and warranties to HOUEX (subject to a $100,000
deductible).

The Company and HOUEX would both be bound by the terms of this Agreement
until September 30, 1996. During the term of the Agreement, neither company (nor
its stockholders) may initiate, solicit or negotiate a proposal or offer from
any third person to buy its assets. HOUEX may terminate the Agreement if it
elects not to proceed with the initial public offering because the proposed
initial offering price of its stock values HOUEX at less than $1.15 per Mcfe of
proved reserves. Either party may terminate the Agreement if the closing has not
occurred on or before September 30, 1996.

The sale of assets to HOUEX would be a taxable transaction. The Company
estimates that its tax liability related to the sale would be approximately
$560,000 to $735,000 depending upon the amount of the Deferred Purchase Price.

The president of the Company, Mr. Lester Smith, has exercised the right
(described in Footnote 6) to sell the reserves attributable to his net profits
interest ("NPI") under the same economic terms as the Company. Mr. Smith will
sell his NPI to the Company, which will then include it in the assets sold to
HOUEX. The agreement between Mr. Smith and the Company provides that the Company
will pay for the NPI by allocating a portion of the purchase price and Deferred
Purchase Price to Mr. Smith based on proved and probable reserves assigned by
independent engineering firms to Mr. Smith's NPI. The sale will be conditioned
on the closing of the HOUEX transaction.

It is currently estimated that Mr. Smith's share of the initial purchase
price is $300,000 and that his share of the Deferred Purchase Price is $100,000
to $200,000. The purchase price and Deferred Purchase Price amounts stated in
this footnote for the Company are inclusive of the estimated portion of the
purchase price and Deferred Purchase Price attributable to Mr. Smith's NPI.

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Interim Financial Statements

The financial statements as of the six months ended June 30, 1995 and 1996
have been prepared without audit pursuant to the rules and regulations of the
Securities and Exchange Commission. Accordingly, such statements include all
adjustments, consisting only of normal recurring adjustments, which are, in the
opinion of management, necessary for a fair presentation of the Company's
financial position, results of operations and cash flows. Interim period results
are not necessarily indicative of the results to be achieved for an entire year.

F-30
<PAGE> 98

SMITH OFFSHORE EXPLORATION COMPANY

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31, 1995 AND JUNE 30, 1996

Cash and Cash Equivalents

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

Short-Term Investments

Short-term investments consist of certificates of deposit and are stated at
cost, which approximates market value.

Prepaid Associated Costs and Well Costs

Associated Costs are allocated to oil and gas properties based on the ratio
of exploration and development expenditures incurred by the Company to total
exploration and development expenditures expected to be incurred. During 1994,
such costs which had not yet been allocated to oil and gas properties are
considered prepaid. During 1995, all such costs were allocated to oil and gas
properties.

Inventory

Inventory consists primarily of tubular goods used in the Company's
operations and is stated at the lower of cost or market value, with cost
determined on a weighted average basis.

Interest

Interest that relates to the costs of unevaluated oil and gas properties on
which exploration or development activities are in progress is capitalized. The
Company capitalized interest of approximately $335,000, $674,000, $226,000 and
$674,000 during the six months ended June 30, 1996 and the years ended December
31, 1995, 1994 and 1993, respectively.

HOUEX's General and Administrative Expenses

The Company capitalizes that portion of HOUEX's general and administrative
expenses which relates to exploration and development activities and expenses
the portion which relates to the operation of producing wells. During the years
ended December 31, 1995, 1994 and 1993, the Company capitalized approximately
$109,000, $231,000 and $347,000, respectively, of HOUEX's general and
administrative expenses. In addition, approximately $110,000, $231,000 and
$346,000 of such costs were charged to production expense during the years ended
December 31, 1995, 1994 and 1993, respectively. No amounts were paid to HOUEX
during 1996 as the agreement to reimburse general and administrative expenses
terminated in June 1995.

Gas Sales Imbalance

The Company records gas sales using the entitlement method. The entitlement
method requires revenue recognition of the Company's share of gas production
from properties in which gas sales are disproportionately allocated to owners
because of marketing or other contractual arrangements. The Company's net
imbalance is recorded as either a receivable or a payable in the accompanying
balance sheets.

F-31
<PAGE> 99

SMITH OFFSHORE EXPLORATION COMPANY

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31, 1995 AND JUNE 30, 1996

Oil and Gas Properties

The Company follows the full-cost method of accounting for its oil and gas
properties. This method provides for capitalizing all productive and
nonproductive costs incurred in connection with the acquisition, exploration and
development of oil and gas reserves. Such costs include lease acquisition,
geological and geophysical services, delay rentals, drilling, completing and
equipping oil and gas wells and platform fabrication and installation, as well
as interest, Associated Costs and direct general and administrative expenses.

Depreciation, depletion and amortization of oil and gas properties are
provided using the unit-of-production method whereby property costs are
amortized based on the ratio of current year production to total estimated
future production from proved oil and gas reserves. Capitalized costs associated
with the acquisition and exploration of unevaluated properties and major
properties under development are not currently amortized. Amortization of costs
associated with these properties will commence when the properties are
evaluated.

Under the full-cost method, a valuation provision is to be made if the
unamortized costs of oil and gas properties, less related deferred taxes, exceed
the limitation on capitalized costs (the "ceiling limitation"). The ceiling
limitation is the sum of: (1) the present value of future net revenues from
estimated production of proved oil and gas reserves, computed using a discount
factor of 10%; (2) the cost of unevaluated properties; less (3) any related tax
effects. During the years ended December 31, 1994 and 1993, the Company recorded
an impairment of $20,000,000 and $4,000,000, respectively, as a result of this
ceiling limitation. No such impairment was required during the six months ended
June 30, 1996 and the year ended December 31, 1995.

Future abandonment, dismantlement and site restoration costs include costs
to dismantle, relocate and dispose of the Company's offshore production
platforms, gathering systems, wells and related structures. The Company relies
on HOUEX to provide estimates of its future abandonment, dismantlement and site
restoration costs for each of its properties. While such estimates have been
considered in the standardized measure of future cash flows and in the
determination of depreciation, depletion and amortization of oil and gas
properties, the amount has never been significant and, accordingly, has been
recorded in the accompanying financial statements through additional
depreciation, depletion and amortization.

Furniture, Fixtures and Other

Provisions for depreciation of furniture, fixtures and other property are
computed on a straight-line basis over their estimated useful lives of five
years.

Income Taxes

Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes", which
supersedes SFAS No. 96, and changes the criteria for recognition and measurement
of deferred tax assets and various other requirements of the previous standard.
As a result of such adoption, the Company recognized a cumulative benefit of
$716,000 during 1993. Under the provisions of SFAS No. 109, the Company had a
deferred tax asset of $12,993,000 attributable to regular net operating loss
("NOL") carryforwards as of December 31, 1995. Since it is unlikely that any of
the deferred tax asset will be realized, a valuation allowance of the entire
amount has been recorded.

At December 31, 1995, the Company had NOL carryforwards of approximately
$107,244,000 and alternative minimum net operating loss carryforwards of
approximately $72,429,000, all of

F-32
<PAGE> 100

SMITH OFFSHORE EXPLORATION COMPANY

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31, 1995 AND JUNE 30, 1996

which are available to reduce future federal income tax liabilities. Such
carryforwards expire during the years 2002 through 2010. The difference between
tax NOL carryforwards and the accumulated deficit at December 31, 1995 is due
primarily to the previous deduction for tax purposes of certain oil and gas
exploration and development costs which were capitalized for financial reporting
purposes.

Impact of Recently Issued Accounting Standards

In March 1995, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards ("SFAS") No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." SFAS No. 121
is effective for financial statements for fiscal years beginning after December
15, 1995. SFAS No. 121 will not have an impact on the financial position or
results of operations of the Company.

Use of Estimates

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

Fair Value of Financial Instruments

The Company's financial instruments consist of cash and cash equivalents,
accounts receivable, accounts payable, and long-term debt. The carrying amounts
of cash and cash equivalents, accounts receivable, and accounts payable
approximate fair value due to the highly liquid nature of these short-term
instruments. The fair value of long-term debt was determined based upon interest
rates currently available to the Company for borrowings with similar terms. The
fair value of long-term debt approximates the carrying amount as of December 31,
1995.

The fair value of ZCN cannot be determined at this time pending the outcome
of the proposed sale of oil and gas assets to HOUEX as discussed in Note 1. As
further discussed in Note 4, the board of directors (which includes majority
representation of zero coupon noteholders) has agreed to work with the officers
of the Company to develop a plan of liquidation (including ZCN) if the proposed
transaction is consummated. In the event the proposed sale is not consummated,
the board of directors and officers have agreed to renegotiate and extend the
terms of payment to the zero coupon noteholders. In either event, the fair value
of the ZCN is substantially less than the carrying amount as of June 30, 1996.
Reference is made to Note 4 regarding the terms, carrying amount, effective
interest rates and maturities of the ZCN.

(3) PREFERRED STOCK

The preferred shareholders have preference in liquidation over the holders
of common stock to the extent of $7.50 per share. Each preferred shareholder has
the option to convert each preferred share into one share of common stock on or
after January 15, 1992. Preferred shareholders are not entitled to vote.
Preferred shareholders are entitled to dividends as if they had converted their
shares to common stock when, if ever, common stock dividends are declared;
however, no dividends are expected to be paid on either the preferred stock or
common stock until substantially all of the preferred stock is converted. Under
the renegotiated subscription agreements, preferred shareholders are entitled to
receive a dollar for dollar dividend for each dollar of exploration money spent
over the original $48,140,625 exploration budget. The dividends will be paid
after all debt and zero coupon notes are retired but before any dividends are
paid to common shareholders.

F-33
<PAGE> 101

SMITH OFFSHORE EXPLORATION COMPANY

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31, 1995 AND JUNE 30, 1996

In addition to providing funding for exploration activities, subscribers
agreed to guarantee bank borrowings of or loan to the Company a maximum of
$96,000,000 as additional funds are required for development activities.
Pursuant to the terms of the renegotiated subscription agreements, this
commitment has now been reduced from $96,000,000 to $60,000,000.

(4) ZERO COUPON NOTES PAYABLE

In order to fund a portion of its exploration commitment under the
Agreement, the Company issued ZCN and $.01 par value preferred stock to
investors for an aggregate consideration of $48,140,625. The ZCN and preferred
stock were issued in four stages during the period March 1987 through September
1990 pursuant to the terms of Subscription Agreements between the Company and
investors. ZCN are subordinate to the Company's bank debt and were to mature six
years from the date of their issuance (on varying maturity dates from March 1993
through September 1996) at a combined maturity amount of $96,281,250.

By virtue of the intended repayment of ZCN at a maturity value equal to two
times the investors' original cash outlay (i.e., two times the cash outlay of
$48,140,625, or $96,281,250), investors were to receive a 12.25% preferred
return on their investment. For accounting and tax purposes, 68% of the proceeds
received from investors was allocated to ZCN and 32% was allocated to preferred
stock. This allocation resulted in an effective annual rate of interest on the
ZCN of 18% per annum. Thus, interest was accrued at 18% per annum on the portion
of the proceeds recorded as ZCN and such interest was added to the face amount
of the notes.

In March 1993, the Company renegotiated the terms of its ZCN. This
renegotiation was necessary because the Company made the decision to not produce
its oil and gas properties at full capacity when gas prices were below $1.75 per
MCF, in order to preserve the Company's gas reserves for production in periods
of higher gas prices. Under the terms of the renegotiated ZCN, 50% of the first
ZCN due in March 1993 was paid upon receipt of executed amendments from
investors. The maturity date of the remaining portion of the first ZCN was
extended three years and the maturity dates of the other ZCN were extended 1 1/2
to 3 years. Interest will accrue on the original maturity value of the ZCN at an
effective rate of 12.25% per annum from the date of original maturity until the
notes are paid off. However, the Company may prepay the ZCN at any time without
penalty.

The revised maturity dates and amounts of ZCN are as follows:

<TABLE>
<CAPTION>
MATURITY DATE OF ZCN MATURITY AMOUNT AMOUNT ACCRUED AT
----------------------------------------- ----------------------------------- -----------------------------------
ORIGINAL REVISED ORIGINAL REVISED 6/30/96 12/31/95
---------------------- ----------------- ---------------- ---------------- ---------------- ----------------
<S> <C> <C> <C> <C> <C>
March 16, 1993
(50% Paid).......... -- $16,046,875 $16,046,875 $ -- $ --
March 16, 1993
(50%)............... March 16, 1996 16,046,875 23,130,480 23,964,161 22,558,615
January 15, 1994...... January 15, 1997 32,093,750 46,260,949 43,287,510 40,748,677
July 1, 1996.......... March 15, 1998 16,046,875 19,753,553 16,030,699 14,660,751
September 4, 1996..... March 15, 1998 16,046,875 19,336,948 15,544,542 14,216,140
----------- ------------ ----------- -----------
$96,281,250 $124,528,805 $98,826,912 $92,184,183
=========== ============ =========== ===========
</TABLE>

ZCN due on March 16, 1996 have not been paid because any payment on ZCN
prior to retirement of all bank debt would cause the Company to be in default of
the Development and Exploration Credit Agreements. Interest, however, is being
accreted on these ZCN at a rate of 12.25%. By the terms of the ZCN, the Company
cannot make payments on ZCN if such payment

F-34
<PAGE> 102

SMITH OFFSHORE EXPLORATION COMPANY

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31, 1995 AND JUNE 30, 1996

would cause the Company to be in default of senior indebtedness. The Company is
currently dedicating all free cash flow to reduction of debt and projects that
it will have retired all debt (except ZCN) by early 1998.

On May 21, 1996, the board of directors of the Company (which includes
majority representation of zero coupon noteholders) agreed to develop with the
officers of the Company a Plan of Liquidation of SOXCO that will be acceptable
to the zero coupon noteholders if the proposed Sale of Assets to HOUEX is
consummated (see Note 1). In the event that the transaction with HOUEX is not
consummated, the board of directors has agreed to work with the officers of the
Company to renegotiate and extend the terms of payment to the zero coupon
noteholders after repayment of all bank debt and investor loans. Accordingly,
all ZCN are reflected as long-term at June 30, 1996 at the accrued amounts
summarized above. However, considering present circumstances, including the
proposed sale of assets, the ultimate payment to zero coupon noteholders will be
substantially less than the amount reflected in the accompanying financial
statements.

During the six months ended June 30, 1996 and the years ended December 31,
1995, 1994, and 1993 interest of approximately $6,643,000, $11,989,000,
$10,461,000 and $11,322,000, respectively, was accreted on the ZCN.

(5) LONG-TERM DEBT

Long-term debt consisted of the following:

<TABLE>
<CAPTION>
DECEMBER 31,
JUNE 30, ------------------------------
1996 1995 1994
------------ ------------ ------------
<S> <C> <C> <C>
Development Credit Agreement.......... $ 2,820,000 $ 3,760,000 $ 7,520,000
Preferred Shareholders Development
Loans............................... 658,000 1,317,000 2,632,000
Exploration Credit Agreement.......... 11,800,000 12,400,000 5,180,000
Preferred Shareholders Loans.......... 1,100,000 1,048,000 --
------------ ----------- -----------
16,378,000 18,525,000 15,332,000
Less: Current Portion of Long-term
Debt................................ (4,578,000) (7,956,000) (7,614,000)
------------ ----------- -----------
Long-term Debt........................ $ 11,800,000 $ 10,569,000 $ 7,718,000
============ =========== ===========
</TABLE>

The current portion of long-term debt at December 31, 1995 and June 30,
1996 includes a portion from each of the above mentioned loans.

Maturities of long-term debt by calendar year are as follows at December
31, 1995:

Development Credit Agreement

As of June 30, 1996, $2,820,000 was outstanding under a $30,068,836 line of
credit agreement, which was used to fund development expenditures (the
"Development Credit Agreement"). As of December 31, 1995 and 1994, the Company
had $3,760,000 and $7,520,000, respectively, outstanding under the Development
Credit Agreement. The Development Credit Agreement, amended in

F-35
<PAGE> 103

SMITH OFFSHORE EXPLORATION COMPANY

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31, 1995 AND JUNE 30, 1996

August 1992 and amended a second time in October 1995, is guaranteed by certain
preferred shareholders. The debt converted to a term loan on January 1, 1994.
Under the original loan terms, principal was due in eight equal quarterly
payments which began April 1, 1994. Six of eight payments were made prior to
October 1995. Under the second amendment, the debt will be paid in four
quarterly installments which will begin April 1, 1996.

Interest rates on borrowings are based on whichever of the following
methods, as defined in the Development Credit Agreement, the Company elects at
the time of borrowing: 3/4% above the Eurodollar rate, 7/8% above the
certificate of deposit rate, or the alternate base rate. Upon conversion to a
term loan on January 1, 1994, interest rates increased by 1/8%. Interest rates
are adjusted every 30 to 180 days, and interest is payable every 30 to 90 days,
depending upon certain factors. During the six months ended June 30, 1996 and
the years ended December 31, 1995, 1994 and 1993, the weighted average interest
rate was 6.92% and 5.94%, 4.17% and 3.61%, respectively. Also during the six
months ended June 30, 1996 and the years ended December 31, 1995, 1994 and 1993,
the Company accrued interest of approximately $105,000, $308,000, $522,000 and
$535,000, respectively, on the borrowings under the Development Credit
Agreement, with approximately $133,000, $307,000, $493,000 and $572,000,
respectively, paid.

Commitment fees under the Development Credit Agreement were 3/8% per annum
on the average unutilized commitment until the debt converted to a term loan.
Commitment fees incurred during the year ended December 31, 1993, were
approximately $59,000. None were incurred during the year ended December 31,
1994 as the debt converted to a term loan on January 1, 1994.

The Development Credit Agreement includes covenants which, among other
things, restrict payment of cash dividends on common stock and require the
Company to maintain stated net worth amounts in addition to a specific liquidity
ratio. As of June 30, 1996 and December 31, 1995, the Company was in compliance
with all covenants.

Preferred Shareholders Development Loans

As of June 30, 1996, the Company had $658,000 outstanding under loan
agreements with certain preferred shareholders not electing to guarantee the
Development Credit Agreement. As of December 31, 1995 and 1994, the Company had
$1,317,000 and $2,632,000, respectively, outstanding under the agreements. The
loan agreements were amended in October 1995. The total amount available under
these loan agreements as of December 31, 1995 was $1,317,000. The loans bear
interest at 3/4% above a certain bank's six-month Eurodollar rate, as
determined each August 1 and February 1. Upon conversion of the Development
Credit Agreement to a term loan on January 1, 1994, interest rates increased by
1/8%. Interest is paid in quarterly installments. Under the original loan
terms, principal was due in eight equal quarterly payments which began April 1,
1994. Six of eight payments were made prior to October 1995. Under the amended
terms, principal will be paid in four quarterly installments which will begin
April 1, 1996. The quarterly payment due April 1, 1996 of $330,000 was paid on
June 30, 1996. The weighted average interest rate for the six months ended June
30, 1996 and the years ending December 31, 1995, 1994 and 1993, was 6.21%,
6.86%, 5.10% and 4.20%, respectively. The Company accrued interest on these
loans of approximately $36,000, $125,000, $215,000 and $221,000 and paid
interest of approximately $61,000, $120,000, $205,000 and $213,000 during the
six months ended June 30, 1996 and the years ended December 31, 1995, 1994 and
1993, respectively.

F-36
<PAGE> 104

SMITH OFFSHORE EXPLORATION COMPANY

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31, 1995 AND JUNE 30, 1996

Exploration Credit Agreement

On April 29, 1994 the Company entered into a $25,000,000 collateral based
line of credit agreement with a current borrowing base of $11,800,000 (beginning
February 1996) which will be used to fund the remaining exploration activity
under the Agreement and other general corporate activities (the "Exploration
Credit Agreement"). The borrowing base was reduced in February 1996 from the
base of $12,400,000 at December 31, 1995. A repayment of principal in the amount
of $600,000 was made at that time. The Exploration Credit Agreement has been
written to allow the Company to increase its borrowing base up to $25,000,000 as
additional reserves are added as collateral. As of June 30, 1996, $11,800,000
was outstanding under this agreement. As of December 31, 1995 and 1994,
$12,400,000 and $5,180,000 were outstanding. Under the existing loan terms, the
debt will convert to a term loan on May 29, 1997 to be paid in eight equal
quarterly installments beginning August 1, 1997. Effective August 31, 1996, the
borrowing base of the Exploration Credit Agreement will be reduced to $9,200,000
until redetermination by the bank is made.

Prior to May 29, 1996, interest rates on borrowings were based on whichever
of the following methods, as defined in the Exploration Credit Agreement, the
Company elected at the time of borrowing: 1 1/2% above the Eurodollar rate,
1 5/8% above the certificate of deposit rate, or prime rate. After May 29, 1996,
interest is as follows: 3% above the Eurodollar rate, 3 1/8% above the
certificate of deposit rate, or 1/2% above the prime rate. After the debt
converts to a term loan on May 29, 1997, interest rates are increased by 1/8%.
Interest rates are adjusted every 30 to 180 days, and interest is payable every
month during the revolving period and every quarter during the term period.
During the six months ended June 30, 1996 and the years ended December 31, 1995
and 1994, the weighted average interest rates were 7.49%, 7.43% and 5.48%. Also
during the six months ended June 30, 1996 and the years ended December 31, 1995
and 1994, the Company accrued interest of approximately $437,000, $719,000 and
$73,000 on the borrowings under the Exploration Credit Agreement with payments
of approximately $443,000, $643,000 and $71,000.

Commitment fees under the Exploration Credit Agreement are 1/2% per annum
on the average daily unused portion of the Borrowing Base until the debt
converts to a term loan. Commitment fees incurred during the years ended
December 31, 1995 and 1994 were approximately $18,000 and $36,000. None were
incurred during the six months ended June 30, 1996 as the Exploration Credit
Agreement was drawn down to the maximum.

The Exploration Credit Agreement includes covenants which, among other
things, restrict payments of cash dividends on common stock and require the
Company to maintain stated net worth amounts in addition to a specific liquidity
ratio. As of June 30, 1996 and December 31, 1995, the Company was in compliance
with all covenants.

Preferred Shareholder Loans

In September 1995, the Company entered into loan agreements with all
preferred shareholders totalling $2,500,000. As of June 30, 1996 and December
31, 1995, the Company had $1,100,000 and $1,048,000, respectively, outstanding
under the loan agreements. The loans bear interest at 12.25%. Principal and
interest will be paid in full on September 14, 1996. The Company accrued
interest on these loans of approximately $66,000, and $33,000, respectively, and
paid no interest during the six months ended June 30, 1996 and the year ended
December 31, 1995.

F-37
<PAGE> 105

SMITH OFFSHORE EXPLORATION COMPANY

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31, 1995 AND JUNE 30, 1996

(6) RELATED-PARTY TRANSACTIONS

The Company has entered into a management agreement with an affiliated
company. The management agreement provides that the Company will reimburse the
affiliate for general and administrative expenses incurred by the affiliate on
the Company's behalf. During the six months ended June 30, 1996 and the years
ended December 31, 1995, 1994 and 1993, pursuant to the management agreement,
the Company paid or accrued approximately $346,000, $837,000, $586,000 and
$569,000, respectively, for general and administrative expenses incurred by the
affiliate on the Company's behalf. In addition, the Company paid the affiliate
$63,000, $154,000, $171,000 and $134,000 for exploration and development
services which have been capitalized as part of the full-cost pool during the
six months ended June 30, 1996 and the years ended December 31, 1995, 1994 and
1993, respectively.

As part of the Company's employment agreement with its president, each
prospect acquired by the Company or in which the Company participates is
burdened by a 1.25% net profits interest on a prospect-by-prospect basis,
proportionately reduced to the interest of the Company.

The president has exercised his right to sell the reserves attributable to
the net profits interest under the same economic terms as the Company would be
selling its reserves to HOUEX. See further discussion in Note 1.

During the six months ended June 30, 1996 and the years ended December 31,
1995, 1994 and 1993, the Company paid or accrued approximately $20,000, $81,000,
$80,000 and $65,000, respectively, related to outside professional services
provided pursuant to consulting agreements with an individual who serves as a
director of the Company and as a director of affiliated companies. An additional
$15,000, $23,000 and $15,000 have been capitalized as part of the full-cost pool
during the years ended December 31, 1995, 1994 and 1993, respectively. No costs
were capitalized for the six months ended June 30, 1996.

(7) MAJOR CUSTOMERS

The Company markets its oil and gas production to numerous purchasers under
short-term contracts. During 1995, H&N Gas Limited, Enron Gas Marketing, Inc.
and Dow Hydrocarbons & Resources, Inc. accounted for 42%, 12% and 11%,
respectively, of oil and gas revenues of the Company. During 1994, H&N Gas
Limited, Transco Energy Marketing Company, Enron Gas Marketing, Inc. and Dow
Hydrocarbons & Resources, Inc., accounted for 19%, 13%, 12%, and 10%,
respectively, of oil and gas revenues. During 1993, Transco Energy Marketing
Company, American Central Marketing and Enron Gas Marketing, Inc. accounted for
19%, 12% and 11%, respectively, of oil and gas revenues. The Company believes
that the loss of any single customer would not have a material adverse effect on
the results of operations of the Company.

(8) SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCING ACTIVITIES
(UNAUDITED)

Oil and Gas Reserves and Related Financial Data

Information with respect to the Company's oil and gas producing activities
is presented in the following tables. Reserve quantities as well as certain
information regarding future production and discounted cash flows were
determined by independent petroleum consultants; Ryder Scott Company, Huddleston
& Co., Inc. and Netherland, Sewell & Associates, Inc.

The Company cautions that there are many uncertainties inherent in
estimating proved reserve quantities, and in projecting future production rates
and the timing of future development expendi-

F-38
<PAGE> 106

SMITH OFFSHORE EXPLORATION COMPANY

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31, 1995 AND JUNE 30, 1996

tures. In addition, reserve estimates of new discoveries are more imprecise than
those of properties with a production history. Accordingly, these estimates are
subject to change as additional information becomes available.

Proved oil and gas reserves are the estimated quantities of crude oil,
condensate, natural gas and natural gas liquids that geological and engineering
data demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions. Proved
developed oil and gas reserves are those reserves expected to be recovered
through existing wells and existing equipment and operating methods.

Capitalized Costs Related to Oil and Gas Producing Activities

The following table sets forth information concerning capitalized costs at
December 31, 1995, 1994 and 1993 related to the Company's oil and gas operations
(in thousands of dollars):

<TABLE>
<CAPTION>
1995 1994
---------- ---------
<S> <C> <C>
Capitalized costs:
Evaluated properties..................................... $ 130,963 $ 122,610
Unevaluated properties................................... 5,335 4,766
--------- --------
136,298 127,376
Less -- Accumulated depreciation, depletion and
amortization............................................. (101,418) (94,540)
--------- --------
Net capitalized costs...................................... $ 34,880 $ 32,836
========= ========
</TABLE>

Costs Incurred on Oil and Gas Producing Activities

The following table includes all costs incurred in the years ended December
31, 1995, 1994 and 1993 (in thousands of dollars):

<TABLE>
<CAPTION>
1995 1994 1993
------- -------- --------
<S> <C> <C> <C>
Acquisition -- Unproved properties................. $ -- $ 1,017 $ --
Exploration costs.................................. 872 6,168 6,043
Development costs.................................. 8,050 2,893 9,244
------ ------- -------
Total costs incurred............................... $ 8,922 $ 10,078 $ 15,287
====== ======= =======
</TABLE>

F-39
<PAGE> 107

SMITH OFFSHORE EXPLORATION COMPANY

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31, 1995 AND JUNE 30, 1996

Estimated Quantities of Proved Oil and Gas Reserves

Estimates prepared by the Company's independent engineers of proved
reserves and proved developed reserves owned at year end and changes in proved
reserves since December 31, 1992 are shown in the following tables:

<TABLE>
<CAPTION>
OIL NATURAL
NATURAL AND GAS
GAS CONDENSATE LIQUIDS
(MMCF) (MBBLS) (MBBLS)
-------- ---- -----
<S> <C> <C> <C>
Proved reserves:
December 31, 1992....................................... 49,991 214 117
Revisions of previous estimates...................... (2,611) (70) (117)
Extensions and discoveries........................... 5,533 56 --
Production........................................... (12,476) (38) --
------- --- ----
December 31, 1993....................................... 40,437 162 --
Revisions of previous estimates...................... (363) 1 --
Extensions and discoveries........................... 1,790 2 --
Production........................................... (9,554) (31) --
------- --- ----
December 31, 1994....................................... 32,310 134 --
Revisions of previous estimates...................... 1,652 115 --
Extensions and discoveries........................... 2,440 73 --
Production........................................... (6,295) (26) --
------- --- ----
December 31, 1995....................................... 30,107 296 --
======= === ====
Proved developed reserves:
December 31, 1992....................................... 44,630 184 85
------- --- ----
December 31, 1993....................................... 34,651 75 --
------- --- ----
December 31, 1994....................................... 28,752 81 --
------- --- ----
December 31, 1995....................................... 28,690 291 --
------- --- ----
</TABLE>

Results of Operations from Producing Activities

The following table sets forth the Company's results of operations from oil
and gas producing activities for the years ended December 31, 1995, 1994 and
1993 (in thousands of dollars):

<TABLE>
<CAPTION>
1995 1994 1993
-------- --------- --------
<S> <C> <C> <C>
Revenues from oil and gas producing activities... $ 10,373 $ 18,536 $ 26,123
Production costs................................. 2,012 2,654 2,634
Depreciation, depletion and amortization......... 6,877 35,550 24,196
------- -------- -------
Total expenses......................... 8,889 38,204 26,830
------- -------- -------
Income tax....................................... -- -- --
Results of operations from producing
activities..................................... $ 1,484 $ (19,668) $ (707)
======= ======== =======
</TABLE>

Standardized Measure

The following disclosure concerning standardized measure of future net cash
flows from proved oil and gas reserves is presented in accordance with Statement
of Financial Accounting

F-40
<PAGE> 108

SMITH OFFSHORE EXPLORATION COMPANY

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31, 1995 AND JUNE 30, 1996

Standards (SFAS) No. 69, "Disclosures about Oil and Gas Producing Activities".
As prescribed by this statement, the amounts shown are based on prices and costs
at the end of each period discounted at 10% and are not adjusted in anticipation
of increases due to inflation or other factors. At December 31, 1995, the
standardized measure reflects an average oil price of $17.99 per barrel and an
average gas price of $2.20 per MCF. Future income tax estimates are calculated
by applying the appropriate statutory income tax rate to the estimated future
undiscounted pretax net cash flows from proved oil and gas properties and
considering estimates of permanent differences, net operating loss carryforwards
and tax credits.

The above assumptions used to compute the standardized measure are those
specifically required by SFAS No. 69 and, as such, do not reflect the Company's
expectations of actual revenues to be derived from those reserves, and are not
necessarily indicative of the fair value of the Company's oil and gas reserves.

The following table reflects the standardized measure of discounted future
net cash flows relating to the Company's interest in proved oil and gas reserves
as of December 31, 1995, 1994 and 1993 (in thousands of dollars):

<TABLE>
<CAPTION>
1995 1994 1993
--------- --------- ---------
<S> <C> <C> <C>
Future cash inflows........................... $ 71,693 $ 54,217 $ 90,266
Future costs:
Production.................................. (9,036) (10,027) (11,730)
Development and abandonment costs........... (4,680) (6,493) (6,004)
-------- -------- --------
Future net inflows before income tax.......... 57,977 37,697 72,532
Future income taxes........................... (968) (504) (2,377)
-------- -------- --------
Future net cash flows......................... 57,009 37,193 70,155
10% annual discount factor.................... (14,522) (9,228) (15,334)
-------- -------- --------
Standardized Measure at end of year........... $ 42,487 $ 27,965 $ 54,821
======== ======== ========
</TABLE>

The change in the standardized measure of discounted future net cash flows
related to the proved oil and gas reserves for the years ended December 31,
1995, 1994, and 1993 is as follows (in thousands of dollars):

<TABLE>
<CAPTION>
1995 1994 1993
-------- --------- ---------
<S> <C> <C> <C>
Standardized Measure at beginning of year....... $ 27,965 $ 54,821 $ 71,345
Oil and gas sales, net of production costs...... (8,361) (15,882) (23,489)
Net change in oil and gas sales prices, net of
production costs.............................. 12,085 (15,920) (4,802)
Extensions and discoveries, net of future
production and development costs.............. 5,253 2,310 7,667
Changes in estimated future development costs... 771 (1,586) (1,296)
Previously estimated development and abandonment
costs incurred................................ 906 1,647 4,956
Revisions of quantity estimates................. 3,411 (367) (5,713)
Accretion of discount........................... 2,838 5,643 7,777
Net change in income taxes...................... (338) 1,197 4,816
Changes in production rates (timing) and
other......................................... (2,043) (3,898) (6,440)
------- -------- --------
Standardized Measure at end of year............. $ 42,487 $ 27,965 $ 54,821
======= ======== ========
</TABLE>

F-41
<PAGE> 109

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Stockholder of
The Houston Exploration Company

We have audited the accompanying Historical Summaries of the interests in
the oil and gas revenues and direct operating expenses of the properties to be
acquired by The Houston Exploration Company (an indirect wholly-owned subsidiary
of The Brooklyn Union Gas Company) from TransTexas Gas Corporation for each of
the three years in the period ended December 31, 1995 ("Historical Summaries").
These Historical Summaries are the responsibility of TransTexas Gas
Corporation's management. Our responsibility is to express an opinion on the
Historical Summaries 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 Historical Summaries are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the Historical Summaries. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the Historical
Summaries. We believe that our audits provide a reasonable basis for our
opinion.

The accompanying Historical Summaries were prepared for the purpose of
complying with the rules and regulations of the Securities and Exchange
Commission (for inclusion in the registration statement on Form S-1 of The
Houston Exploration Company) and are not intended to be a complete financial
presentation of TransTexas Gas Corporation's interests in the properties
described above.

In our opinion, the Historical Summaries referred to above present fairly,
in all material respects, the interests in the oil and gas revenues and direct
operating expenses of the properties to be acquired by The Houston Exploration
Company from TransTexas Gas Corporation for each of the three years in the
period ended December 31, 1995, in conformity with generally accepted accounting
principles.

COOPERS & LYBRAND L.L.P.

Houston, Texas
July 2, 1996

F-42
<PAGE> 110

HISTORICAL SUMMARIES OF THE INTERESTS IN THE
OIL AND GAS REVENUES AND DIRECT OPERATING EXPENSES
OF THE PROPERTIES TO BE ACQUIRED BY THE HOUSTON EXPLORATION COMPANY
FROM TRANSTEXAS GAS CORPORATION

(IN THOUSANDS)

<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
----------------------------- -------------------
1993 1994 1995 1996 1995
------- ------- ------- ------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Oil and gas revenues..................... $27,728 $34,119 $26,800 $15,335 $14,105
Direct operating expenses................ 3,562 4,258 4,542 2,743 2,547
------- ------- ------- ------
Revenues in excess of direct operating
expenses............................... $24,166 $29,861 $22,258 $12,592 $11,558
======= ======= ======= ======
</TABLE>

The accompanying notes are an integral part of this statement.

F-43
<PAGE> 111

NOTES TO THE HISTORICAL SUMMARIES OF THE INTERESTS IN THE OIL AND GAS REVENUES
AND DIRECT OPERATING EXPENSES OF THE PROPERTIES TO BE ACQUIRED BY THE HOUSTON
EXPLORATION COMPANY FROM TRANSTEXAS GAS CORPORATION

1. OPERATIONS, ORGANIZATION AND BASIS OF PRESENTATION

The accompanying Historical Summaries represent the interests in the
natural gas and oil revenues and direct operating expenses of the natural gas
and oil producing properties to be acquired by The Houston Exploration Company
("Houston Exploration"), an indirect wholly-owned subsidiary of The Brooklyn
Union Gas Company ("Brooklyn Union"), from TransTexas Gas Corporation
("TransTexas") effective May 1, 1996. The oil and gas producing properties to be
acquired are located primarily in South Texas. These properties are referred to
herein as the "properties." The Historical Summaries may not be representative
of future operations.

The accompanying Historical Summaries were prepared from the historical
accounting records of TransTexas (accrual basis, full cost method of accounting
for oil and gas activities, in accordance with generally accepted accounting
principles).

The agreement for Purchase and Sale of Oil and Gas Properties by and
between The Houston Exploration Company, TransTexas Gas Corporation and
TransTexas Transmission Corporation (the "Agreement") for $62,205,000 is dated
June 21, 1996. The scheduled closing date set forth in the Agreement is July 2,
1996.

Historical financial statements reflecting financial position, results of
operations and cash flows required by generally accepted accounting principles
are not presented as such information is neither readily available on an
individual property basis nor meaningful for the properties. Historically no
allocation of general and administrative, litigation, interest or federal income
tax expense was made to the properties, and depreciation, depletion and
amortization was computed based on TransTexas' basis in the properties.
Accordingly, the Historical Summaries are presented in lieu of the financial
statements required under Rule 3-05 of Securities and Exchange Commission
Regulation S-X.

The Historical Summaries as of the six months ended June 30, 1995 and 1996
have been prepared without audit pursuant to the rules and regulations of the
Securities and Exchange Commission. Accordingly, such Historical Summaries
include all adjustments, consisting only of normal recurring adjustments, which
are, in the opinion of management, necessary for a fair presentation of the
Company's revenues and expenses of the properties to be acquired by Houston
Exploration. Interim period results are not necessarily indicative of the
results to be achieved for an entire year.

2. COMMITMENT AND CONTINGENCIES

The properties listed in the Agreement 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 Houston Exploration against
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 collateralized by an irrevocable letter of
credit, and the other bond is collateralized by cash. One of the judgments in
the amount of $18 million has been reversed, a decision which, if upheld, will
result in the release of the related judgment lien. As a result of such
arrangements, TransTexas believes that such judgments are adequately
collateralized.

F-44
<PAGE> 112

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

ESTIMATED NET QUANTITIES OF PROVED AND PROVED DEVELOPED OIL AND GAS RESERVES

Proved reserves are estimated quantities of crude oil and natural gas 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 developed reserves are proved reserves that can be
expected to be recovered through existing wells with existing equipment and
operating methods.

The following tables present the estimated net proved and proved developed
oil and gas reserves, estimated by Netherland, Sewell & Associates, Inc.,
independent reserve engineers, attributable to the properties at December 31,
1993, 1994 and 1995, along with a summary of changes in the quantities of net
proved reserves during 1993, 1994 and 1995.

<TABLE>
<CAPTION>
GAS (MILLIONS OF CUBIC FEET)
-------------------------------
DECEMBER 31,
-------------------------------
1993 1994 1995
------- ------- -------
<S> <C> <C> <C>
Proved Reserves:
Beginning of period....................................... 108,253 106,800 111,630
Revisions of previous estimates........................... (2,299) 3,099 21,560
Extensions and discoveries................................ 15,477 23,357 4,751
Production................................................ (14,631) (21,626) (19,545)
------- ------- -------
End of period............................................. 106,800 111,630 118,396
======== ======== ========
Proved Developed Reserves:
End of period............................................. 54,182 73,596 56,329
======== ======== ========
</TABLE>

<TABLE>
<CAPTION>
OIL (THOUSANDS OF BARRELS)
------------------------------
DECEMBER 31,
------------------------------
1993 1994 1995
------ ----- -----
<S> <C> <C> <C>
Proved Reserves:
Beginning of period........................................ 44.4 47.5 34.1
Revisions of previous estimates............................ 7.6 (12.6) 21.4
Extensions and discoveries................................. .8 4.4 0
Production................................................. (5.3) (5.2) (4.4)
------ ----- -----
End of period.............................................. 47.5 34.1 51.1
====== ===== =====
Proved Developed Reserves:
End of period.............................................. 28.8 32.3 33.2
====== ===== =====
</TABLE>

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED
RESERVES

The following tables set forth the computation of the standardized measure
of discounted future net cash flows (before income taxes) relating to proved
reserves, estimated by TransTexas for 1993, 1994 and 1995. Future cash inflows
represent expected revenues from production of year-end quantities of proved
reserves based on December 31, 1993, 1994, and 1995 prices and any fixed and
determinable future escalation provided by contractual arrangements in existence
at year-end. Escalation based on inflation and supply and demand are not
considered. Estimated future production and development costs related to future
production of year-end reserves are based on year-end costs. A discount rate of
10% is applied to the annual future net cash flows.

The methodology and assumptions used in calculating the standardized
measure are those required by Statement of Financial Accounting Standards No.
69. This data is not intended to be representative of the fair market value of
the properties' proved reserves. The valuation of revenues

F-45
<PAGE> 113

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) -- (CONTINUED)

and costs do not necessarily reflect the amounts to be received or expended. In
addition to the valuations used, numerous other factors are considered in
evaluating known and prospective oil and gas reserves.

<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS)
--------------------------------
DECEMBER 31,
--------------------------------
1993 1994 1995
-------- -------- --------
<S> <C> <C> <C>
Future cash inflows....................................... $199,966 $156,926 $210,844
Future production and development costs................... (72,960) (63,744) (90,997)
-------- -------- --------
Future net cash flows..................................... 127,006 93,182 119,847
10% annual discount to reflect timing of net cash flows... (32,884) (23,728) (39,287)
-------- -------- --------
Standardized measure (before income taxes) of discounted
future net cash flows relating to proved reserves....... $ 94,122 $ 69,454 $ 80,560
========= ========= =========
</TABLE>

SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED
FUTURE NET CASH FLOWS RELATING TO PROVED RESERVES

The primary elements of changes in the standardized measure (before income
taxes) of discounted future net cash flows relating to proved reserves for the
years 1993, 1994 and 1995 (in thousands):

<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------------
1993 1994 1995
-------- -------- --------
<S> <C> <C> <C>
Standardized measure (before income taxes),
beginning of period..................................... $ 95,358 $ 94,122 $ 69,454
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas produced, net of
production costs................................... (24,166) (29,861) (22,258)
Revisions to estimates of proved reserves:
Prices, including production costs................. 4,049 (36,143) 20,185
Production and development costs................... (17,795) (7,451) (17,406)
Quantities......................................... (2,568) 2,643 17,548
Extensions, discoveries and improved recovery less
related costs...................................... 14,543 15,315 3,778
Development costs incurred during the period......... 15,165 21,417 2,314
Accretion of discount................................ 9,536 9,412 6,945
-------- -------- --------
Standardized measure (before income taxes), end of
period.................................................. $ 94,122 $ 69,454 $ 80,560
========= ========= =========
</TABLE>

F-46
<PAGE> 114

UNDERWRITING

Subject to the terms and conditions of the Underwriting Agreement the
Company has agreed to sell to each of the Underwriters named below, and each of
the Underwriters, for whom Goldman, Sachs & Co., Donaldson, Lufkin & Jenrette
Securities Corporation and PaineWebber Incorporated are acting as
representatives, has severally agreed to purchase from the Company, the
respective number of shares of Common Stock set forth opposite its name below:

<TABLE>
<CAPTION>
NUMBER OF
SHARES OF
UNDERWRITER COMMON STOCK
---------------------------------------------------------------------- ------------
<S> <C>
Goldman, Sachs & Co................................................... 1,445,000
Donaldson, Lufkin & Jenrette Securities Corporation................... 1,445,000
PaineWebber Incorporated.............................................. 1,445,000
A.G. Edwards & Sons, Inc.............................................. 200,000
Lehman Brothers Inc................................................... 200,000
Merrill Lynch, Pierce, Fenner & Smith Incorporated.................... 200,000
Rauscher Pierce Refsnes, Inc.......................................... 200,000
Salomon Brothers Inc.................................................. 200,000
Wasserstein Perella Securities, Inc................................... 200,000
Edward D. Jones & Co.................................................. 95,000
McDonald & Company Securities, Inc.................................... 95,000
Petrie Parkman & Co., Inc............................................. 95,000
Principal Financial Securities, Inc................................... 95,000
Scott & Stringfellow, Inc............................................. 95,000
Southcoast Capital Corporation........................................ 95,000
Stifel, Nicolaus & Company, Incorporated.............................. 95,000
---------
Total....................................................... 6,200,000
=========
</TABLE>

Under the terms and conditions of the Underwriting Agreement, the
Underwriters are committed to take and pay for all of the shares offered hereby,
if any are taken.

The Underwriters propose to offer the shares of Common Stock in part
directly to the public at the initial public offering price set forth on the
cover page of this Prospectus, and in part to certain securities dealers at such
price less a concession of $0.65 per share. The Underwriters may allow, and such
dealers may reallow, a concession not in excess of $0.10 per share to certain
brokers and dealers. After the shares of Common Stock are released for sale to
the public, the offering price and other selling terms may from time to time be
varied by the representatives.

The Company has granted the Underwriters an option exercisable for 30 days
after the date of this Prospectus to purchase up to an aggregate of 930,000
additional shares of Common Stock solely to cover over-allotments, if any. If
the Underwriters exercise their over-allotment option, the Underwriters have
severally agreed, subject to certain conditions, to purchase approximately the
same percentage thereof that the number of shares to be purchased by each of
them, as shown in the foregoing table, bears to the 6,200,000 shares of Common
Stock offered.

The Company, the Company's executive officers and directors, Brooklyn Union
and Soxco have agreed, during the period beginning from the date of this
Prospectus and continuing to and including the date 180 days after the date of
this Prospectus, not to offer, sell, contract to sell or otherwise dispose of
any securities of the Company (other than pursuant to employee stock option
plans existing on, or on the conversion or exchange of convertible or
exchangeable securities outstanding on the date of this Prospectus) which are
substantially similar to the shares of Common Stock or which are convertible or
exchangeable into securities which are substantially similar to the shares of
Common Stock, without the prior written consent of the representatives of the
Underwriters. See "Shares Eligible for Future Sale."

U-1
<PAGE> 115

The representatives of the Underwriters have informed the Company that they
do not expect sales to accounts over which the Underwriters exercise
discretionary authority to exceed five percent of the total number of shares of
Common Stock offered by them.

Prior to this Offering, there has been no public market for the Common
Stock. The initial public offering price of the Common Stock will be negotiated
between the Company and the representatives of the Underwriters. Among the
factors to be considered in determining the initial public offering price of the
Common Stock, in addition to prevailing market conditions, will be current and
historical natural gas and oil prices, current and prospective conditions in the
supply and demand for natural gas and oil, reserve and production quantities for
the Company's natural gas and oil properties, the history of, and prospects for,
the industry in which the Company operates, the price earnings multiples of
publicly traded common stocks of comparable companies, the cash flow and
earnings of the Company and comparable companies in recent periods and the
Company's business potential and cash flow and earnings prospects.

The Company has agreed to indemnify the several Underwriters against
certain liabilities, including liabilities under the Securities Act of 1993.

U-2
<PAGE> 116

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

NO PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY
REPRESENTATIONS OTHER THAN THOSE CONTAINED IN THIS PROSPECTUS, AND, IF GIVEN OR
MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN
AUTHORIZED. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR THE
SOLICITATION OF AN OFFER TO BUY ANY SECURITIES OTHER THAN THE SECURITIES TO
WHICH IT RELATES OR AN OFFER TO SELL OR THE SOLICITATION OF AN OFFER TO BUY SUCH
SECURITIES IN ANY CIRCUMSTANCES IN WHICH SUCH OFFER OR SOLICITATION IS UNLAWFUL.
NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER
ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THERE HAS BEEN NO CHANGE IN THE
AFFAIRS OF THE COMPANY SINCE THE DATE HEREOF OR THAT THE INFORMATION CONTAINED
HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO ITS DATE.
------------------------

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Prospectus Summary...................... 3
Risk Factors............................ 9
The Company............................. 14
TransTexas Acquisition.................. 14
Soxco Acquisition....................... 15
Use of Proceeds......................... 15
Dividend Policy......................... 16
Dilution................................ 16
Capitalization.......................... 18
Selected Historical Financial Data...... 19
Pro Forma Combined Financial
Information........................... 20
Management's Discussion and Analysis of
Financial Condition and Results of
Operations............................ 25
Business................................ 33
Management.............................. 52
Related Party Transactions.............. 57
Security Ownership of Certain Beneficial
Owners and Management................. 61
Description of Capital Stock............ 62
Shares Eligible for Future Sale......... 64
Legal Matters........................... 65
Experts................................. 65
Available Information................... 66
Glossary of Oil and Gas Terms........... 67
Index to Financial Statements........... F-1
Underwriting............................ U-1
Reports of Independent Petroleum
Engineers............................. A-1
</TABLE>

THROUGH AND INCLUDING OCTOBER 14, 1996 (THE 25TH DAY AFTER THE DATE OF THIS
PROSPECTUS), ALL DEALERS EFFECTING TRANSACTIONS IN THE COMMON STOCK, WHETHER OR
NOT PARTICIPATING IN THIS DISTRIBUTION, MAY BE REQUIRED TO DELIVER A PROSPECTUS.
THIS IS IN ADDITION TO THE OBLIGATION OF DEALERS TO DELIVER A PROSPECTUS WHEN
ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR UNSOLD ALLOTMENTS OR
SUBSCRIPTIONS.

- ---------------------------------------------------------
- ---------------------------------------------------------
- ---------------------------------------------------------
- ---------------------------------------------------------
6,200,000 SHARES

THE HOUSTON
EXPLORATION COMPANY
COMMON STOCK
(PAR VALUE $.01 PER SHARE)
------------------------

[HOUSTON EXPLORATION LOGO]

------------------------
GOLDMAN, SACHS & CO.

DONALDSON, LUFKIN & JENRETTE
SECURITIES CORPORATION

PAINEWEBBER INCORPORATED
REPRESENTATIVES OF THE UNDERWRITERS
- ---------------------------------------------------------
- ---------------------------------------------------------