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

                                   FORM 10-K/A
                                 AMENDMENT NO. 1
              [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                       THE SECURITIES EXCHANGE ACT OF 1934
                   FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002
                                       OR
            [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                       THE SECURITIES EXCHANGE ACT OF 1934
            FOR THE TRANSITION PERIOD FROM __________ TO __________

                          COMMISSION FILE NO. 001-11899

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

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

                DELAWARE                                         22-2674487
    (STATE OR OTHER JURISDICTION OF                             (IRS EMPLOYER
     INCORPORATION OR ORGANIZATION)                          IDENTIFICATION NO.)

       1100 LOUISIANA, SUITE 2000
             HOUSTON, TEXAS                                      77002-5215
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)                         (ZIP CODE)

                                 (713) 830-6800
              (REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)

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

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

                                                             NAME OF EACH
           TITLE OF EACH CLASS                      EXCHANGE ON WHICH REGISTERED
           -------------------                      ----------------------------
       Common Stock, $.01 par value                    New York Stock Exchange
8 3/8%  Senior Subordinated Notes due 2008

        SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE

         Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X]  No [ ]

         Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulations S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K/A or any
amendment to this Form 10-K. [X]

         Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Act). Yes [X] No [ ]

         The aggregate market value of the voting stock held by non-affiliates
of the registrant was approximately $294,266,721 as of June 28, 2002, based on
the closing sales price of the registrant's common stock on the New York Stock
Exchange on such date of $29.00 per share. For purposes of the preceding
sentence only, all directors, executive officers and beneficial owners of ten
percent or more of the common stock are assumed to be affiliates. As of February
20, 2003, 30,961,418 shares of common stock were outstanding.


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

<PAGE>



                                TABLE OF CONTENTS



<Table>
<Caption>
                                                                                                           PAGE
                                                                                                           ----

<S>                                                                                                        <C>
                                                      PART I.

Items 1. and 2.   Business and Properties....................................................................1
Item 3.           Legal Proceedings..........................................................................17
Item 4.           Submission of Matters to a Vote of Security Holders........................................17

                                                     PART II.

Item 5.           Market for the Registrant's Common Equity and Related Stockholder Matters..................18
Item 6.           Selected Financial Data....................................................................19
Item 7.           Management's Discussion and Analysis of Financial Condition and Results of Operations......21
Item 7A.          Quantitative and Qualitative Disclosures About Market Risk.................................33
Item 8.           Financial Statements.......................................................................36
Item 9.           Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.......36

                                                     PART III.

Item 10.          Directors and Executive Officers of the Registration.......................................37
Item 11.          Executive Compensation.....................................................................41
Item 12.          Security Ownership of Beneficial Owners and Management.....................................44
Item 13.          Certain Relationships and Related Transactions.............................................46
Item 14.          Controls and Procedures....................................................................51

                                                     PART IV.

Item 15.          Exhibits, Financial Statements Schedules and Reports on Form 8-K...........................52

SIGNATURES...................................................................................................53
CERTIFICATIONS...............................................................................................54
GLOSSARY OF OIL AND GAS TERMS................................................................................G-1
INDEX TO FINANCIAL STATEMENTS................................................................................F-1
</Table>



                                        i

<PAGE>




     All of the estimates and assumptions contained in this Annual Report and in
the documents we have incorporated by reference into this Annual Report
constitute forward looking statements as that term is defined in Section 27A of
the Securities Act of 1993 and Section 21E of the Securities Exchange Act of
1934. These forward-looking statements generally are accompanied by words such
as "anticipate," "believe," "expect," "estimate," "project" or similar
expressions. All statements under the caption "Item 7." Management's Discussion
and Analysis of Financial Condition and Results of Operations" relating to our
anticipated capital expenditures, future cash flows and borrowings, pursuit of
potential future acquisition opportunities and sources of funding for
exploration and development are forward looking statements. Although we believe
that these forward-looking statements are based on reasonable assumptions, our
expectations may not occur and we cannot guarantee that the anticipated future
results will be achieved. A number of factors could cause our actual future
results to differ materially from the anticipated future results expressed in
this Annual Report. These factors include, among other things, the volatility of
natural gas and oil prices, the requirement to take write downs if natural gas
and oil prices decline, our ability to meet our substantial capital
requirements, our substantial outstanding indebtedness, the uncertainty of
estimates of natural gas and oil reserves and production rates, our ability to
replace reserves, and our hedging activities. For additional discussion of these
risks, uncertainties and assumptions, see "Items 1 and 2." Business and
Properties" and "Item 7". Management's Discussion and Analysis of Financial
Condition and Results of Operations" contained in this Annual Report.

     In this Annual Report, unless the context requires otherwise, when we refer
to "we", "us" or "our", we are describing The Houston Exploration Company and
its subsidiaries on a consolidated basis. Further, if you are not familiar with
the oil and gas terms used in this report please refer to the explanations of
the terms under the caption "Glossary of Oil and Gas Terms" included on pages
G-1 through G-3. When we refer to "equivalents," we are doing so to compare
quantities of oil with quantities of natural gas or to express these different
commodities in a common unit. In calculating equivalents, we use a generally
recognized standard in which one barrel of oil is equal to six thousand cubic
feet of natural gas.

PART I.

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

OVERVIEW AND ORGANIZATION

     We are an independent natural gas and oil company engaged in the
exploration, development, exploitation and acquisition of domestic natural gas
and oil properties. Our operations are primarily focused in South Texas,
offshore in the Gulf of Mexico and in the Arkoma Basin of Oklahoma and Arkansas.

     At December 31, 2002, our net proved reserves were 650 billion cubic feet
equivalent or Bcfe, with a present value, discounted at 10% per annum, of cash
flows before income taxes of $1.3 billion. Our reserves are fully engineered on
an annual basis by independent petroleum engineers. Our focus is natural gas.
Approximately 94% of our net proved reserves at December 31, 2002 were natural
gas, approximately 69% of which were classified as proved developed. We operate
approximately 85% of our properties.

     We began exploring for natural gas and oil in December 1985 on behalf of
The Brooklyn Union Gas Company. Brooklyn Union is an indirect wholly owned
subsidiary of KeySpan Corporation. KeySpan, a member of the Standard & Poor's
500 Index, is a diversified energy provider whose principal natural gas
distribution and electric generation operations are located in the Northeastern
United States. In September 1996 we completed our initial public offering and
sold approximately 31% of our shares to the public. As of December 31, 2002,
THEC Holdings Corp., an indirect wholly owned subsidiary of KeySpan, owned
approximately 66% of the outstanding shares of our common stock.

     Our principal executive offices are located at 1100 Louisiana, Suite 2000,
Houston, Texas 77002. Our telephone number is (713) 830-6800

2002 OPERATING HIGHLIGHTS

     During the year ended December 31, 2002 we drilled a total of 97 wells of
which 84 were successful reflecting a success rate of 86%. We produced a total
of 103 billion cubic feet equivalent, or Bcfe, and increased our average daily
production by 14% to 281 million cubic feet equivalent, or MMcfe, per day. We
replaced 141% of our production by adding 145 Bcfe in net proved reserves. We
generated $282 million in cash flows from operations before adjustments for
changes in current assets and liabilities and invested a net $253 million in
natural gas and oil properties, including $65 million for producing properties
acquired in South Texas and the Gulf of Mexico.




                                      -1-
<PAGE>


INVESTMENT STRATEGY

     We strive to maximize shareholder value while maintaining our financial
flexibility by pursuing a dynamic investment strategy involving elements of each
of the following activities:

     o    Exploitation. Exploitation, both onshore and offshore, is one of our
          core competencies and the cornerstone of our investment strategy. We
          invest in exploitation and development activities intended to generate
          stable and growing cash flows from which we can fund future expansion.

     o    Exploration. Founded as an exploration company, we continue to invest
          in exploratory prospects to supplement the reserves added through our
          exploitation activities. We generate the majority of our exploration
          prospects through our in-house geo-science personnel and currently
          have assembled a three-year inventory of offshore drilling prospects.

     o    Acquisitions. We augment our exploration and exploitation activities
          with disciplined investments in acquisitions of new properties that
          conform to our operating philosophy, , and offer unexploited reserve
          potential.

     We typically fund exploitation and exploration activities out of cash flows
from operations. We typically fund acquisitions through our revolving bank
credit facility. When we incur debt in connection with an acquisition, we focus
on prompt repayment in order to minimize our debt service obligations. Our
current debt levels provide flexibility to continually review and adjust our
capital budgets during the year based on operational developments, commodity
prices, service costs, acquisition opportunities and numerous other factors.

OPERATING PHILOSOPHY

     o    Natural Gas Emphasis. Our production and reserve base is heavily
          weighted toward natural gas. Since natural gas can only be transported
          from overseas in liquefied form and is thus more difficult to import
          than crude oil, we believe natural gas is better insulated from the
          price volatility associated with global geopolitical instability. The
          lease operating expense associated with natural gas properties is also
          typically less than oil properties, which allows us to maintain our
          low per-unit cost structure.

     o    Operating Control. We prefer to operate our properties rather than
          owning non-operating interests. Operating our properties allows us
          more control over the nature and timing of capital expenditures and
          overall operating expenses. As operator, we supervise production,
          maintain production records, employ or contract for field personnel,
          distribute revenues and perform other functions. As operator, we
          receive reimbursement for direct expenses incurred in the performance
          of duties, as well as monthly per-well producing and drilling overhead
          reimbursements at rates customarily charged in the area by
          unaffiliated third parties. We currently operate approximately 85% of
          our properties, which has contributed to our historically low
          operating costs.

     o    Geographic Focus. By concentrating our operations within
          geographically focused areas, we can manage a large asset base with a
          relatively small number of employees and can integrate additional
          properties at relatively low incremental costs. Our strategy of
          focusing drilling activities on properties in relatively concentrated
          offshore and onshore areas permits us to more efficiently utilize our
          base of geological, engineering, exploration and production experience
          in these regions. At December 31, 2002, 91% of our reserves were
          located in our three core areas: South Texas, the Gulf of Mexico and
          the Arkoma Basin of Oklahoma and Arkansas.

     o    Operating Environment. We focus our operations in areas that are
          conducive to low cost operations, avoiding areas where fractionalized
          ownership issues, local regulation or lack of a qualified workforce
          would drive up operational, legal and other costs.

     o    Cash Flow Hedging. We maintain an active hedging program designed to
          reduce the impact of commodity price fluctuations and provide more
          predictable cash flows that allow us to better plan our capital
          expenditures. Our hedges typically take the form of fixed price swaps
          and no-cost collars under which we are assured a minimum floor price
          for our production and enjoy the benefit of price increases up to a
          predetermined ceiling price. Depending on the outlook for future
          prices and the state of the options markets, we may hedge up to 70% of
          our production for up to two years or more.



                                      -2-
<PAGE>


2002 OPERATIONS REVIEW

     The table below summarizes certain data for our core operating areas for
the year ended December 31, 2002. More detailed information regarding natural
gas and oil production and average prices received in 2002, 2001 and 2000 is
available in Item 7. "Management's Discussion and Analysis of Financial
Condition and Results of Operations." See Item 7A. "Quantitative and Qualitative
Disclosures About Market Risk" for more information regarding our hedging
practices. In addition, for more information regarding reserve quantities,
capitalized costs and estimated future revenues and expenses relating to our
natural gas and oil properties, see "Notes to Consolidated Financial Statements
- Note 12 - Supplemental Information On Natural Gas and Oil Exploration,
Development and Production Activities (Unaudited)."

<Table>
<Caption>
                                     ACTIVITY AND BALANCES AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2002
-----------------------------------------------------------------------------------------------------------------------------
                                                       NATURAL
                         AVERAGE                       GAS AND          TOTAL       PERCENTAGE           WELLS DRILLED
                          DAILY          TOTAL           OIL           PROVED      TOTAL PROVED   ---------------------------
        AREA            PRODUCTION    PRODUCTION       REVENUES       RESERVES       RESERVES        TOTAL        SUCCESSFUL
--------------------   ------------   ------------   ------------   ------------   ------------   ------------   ------------
                        (MMcfe/d)       (MMcfe)      ($ Thousands)    (MMcfe)                        (Gross)        (Gross)

<S>                    <C>            <C>            <C>            <C>            <C>            <C>            <C>
South Texas ........            123         44,720   $    141,220        298,926            46%             63             54
Gulf of Mexico .....            126         46,226        149,810        197,856            31%             10              9
Arkoma Basin .......             20          7,432         21,750         93,081            14%             24             21
Other Onshore ......             12          4,144         15,157         59,744             9%             --             --
                       ------------   ------------   ------------   ------------   -----------    ------------   ------------

Total ..............            281        102,522   $    327,937        649,607           100%             97             84
                       ============   ============   ============   ============   ===========    ============   ============
</Table>


     South Texas. Our South Texas properties are concentrated in the Charco,
Haynes and South Trevino Fields of Zapata County; the Alexander, Hubbard and
South Laredo Fields of Webb County; and the North East Thompsonville Field in
Jim Hogg County. We own interests in 562 producing wells, 450 of which we
operate.

     Gulf of Mexico. Our offshore properties are located in the shallow waters
of the Outer Continental Shelf. Our key producing properties are located in the
western and central Gulf of Mexico and include the Mustang Island, High Island,
East Cameron, Vermilion and South Timbalier areas. We hold interests 86 blocks
in federal and state waters, of which 42 are developed. We operate 29 of our
developed blocks, which accounted for approximately 75% of our offshore
production during 2002. We have a total of 37 platforms and production cassions
of which we operate 27.

     Arkoma Basin. Our Arkoma Basin properties are located in two primary areas:
the Chismville/Massard Field located in Logan and Sebastian Counties of Arkansas
and the Wilburton and Panola Fields located in Latimer County, Oklahoma. We own
working interests in 252 producing natural gas wells, 131of which we operate.

     Other Onshore. Other Onshore properties are concentrated in three areas:
South Louisiana; West Virginia; and East Texas. On a combined basis, we own
working interests in 708 producing wells, 653 of which we operate.



                                      -3-
<PAGE>


ACQUISITIONS

     KeySpan Joint Venture Assets. On October 11, 2002, we purchased from
KeySpan a portion of the assets developed under the joint exploration agreement
with KeySpan Exploration & Production, LLC, a subsidiary of KeySpan. The
acquisition consisted of interests averaging between 11.25% and 45% in 17 wells
covering eight of the twelve blocks that were developed under the joint
exploration agreement from 1999 through 2002. The interests purchased were in
the following blocks: Vermilion 408, East Cameron 81 and 84, High Island 115,
Galveston Island 190 and 389, Matagorda Island 704 and North Padre Island 883.
KeySpan has retained its 45% interest in four blocks: South Timbalier 314 and
317 and Mustang Island 725 and 726, as these blocks are in various stages of
development. KeySpan has committed to continued participation in the ongoing
development of these blocks including the completion of the platform and
production facilities at South Timbalier 314/317 together with possible further
developmental drilling at both South Timbalier 314/317 and Mustang Island
725/726. As of September 1, 2002, the effective date of the purchase, the
estimated proved reserves associated with the interests acquired were 13.5 Bcfe.
The $26.5 million purchase price was paid in cash and financed with borrowings
under our revolving bank credit facility. Subsequent purchase price adjustments
reduced our acquisition price by $1.2 million. The purchase price was adjusted
for various customary closing items, including revenues received by and
expenditures made by the seller related to the properties acquired for the
period between the effective date of the transaction (September 1, 2002) and the
closing date (October 11, 2002). Our acquisition of the properties was accounted
for as a transaction between entities under common control. As a result, the
excess fair value of the properties acquired of $3.1 million ($2.0 million net
of tax) was treated as a capital contribution from KeySpan and recorded as an
increase to additional paid-in capital during the fourth quarter of 2002.

     Burlington Acquisition. On May 30, 2002, we completed the purchase of
natural gas and oil producing properties, together with undeveloped acreage,
from Burlington Resources Inc. located in the Webb and Jim Hogg Counties of
South Texas. The properties purchased cover approximately 24,800 gross (10,800
net) acres located in the North East Thompsonville and South Laredo Fields. The
properties purchased represent interests in approximately 123 producing wells
and total proved reserves of 37 Bcfe as of January 1, 2002, the effective date
of the transaction. The North East Thompsonville Field has 10 wells producing
from the Wilcox formation, all of which we operate. This field represents
approximately 70% of the proved reserves and 75% of the current production
associated with the acquisition. The South Laredo Field, located in Webb County
and in the Lobo Trend, contains 113 wells, all operated by a third party. The
$39.5 million purchase price, which was reduced by a purchase price adjustment
of $3.9 million and proceeds of $5.0 million received from the subsequent sale
of a portion of the assets acquired, was financed by borrowings under our
revolving bank credit facility. The purchase price was adjusted for various
customary closing items, including revenues received by and expenditures made by
the seller related to the properties acquired for the period between the
effective date of the transaction (January 1, 2002) and the closing date (May
30, 2002).

     Conoco Acquisition. On December 31, 2001, we completed the purchase from
Conoco Inc. of natural gas and oil properties and associated gathering pipelines
and equipment, together with developed and undeveloped acreage, located in the
Webb and Zapata Counties of South Texas. The $69 million cash purchase price was
financed by borrowings under our revolving bank credit facility. The properties
purchased cover approximately 25,274 gross (16,885 net) acres located in the
Alexander, Haynes, Hubbard and South Trevino Fields, which are in close
proximity to our existing operations in the Charco Field, and represent
interests in approximately 159 producing wells. We operate approximately 95% of
the producing wells we acquired. Our average working interest is 87%. Total
proved reserves associated with the interests acquired were 85 Bcfe, as of
October 1, 2001, the effective date of the transaction.

OTHER RECENT DEVELOPMENTS

     Joint Offshore Exploration Program. Effective September 1, 2002, we entered
into a joint offshore exploration agreement with El Paso Production Oil & Gas
USA, L.P., a subsidiary of El Paso Corporation. Under the terms of the
agreement, El Paso contributed approximately $50 million for land, seismic and
drilling costs in exchange for 50% of our working interest in six specified
prospects that we developed. El Paso pays 100% of the drilling costs to casing
point or 100% of the "dry hole costs", except for the High Island 115 prospect
for which we have an obligation of $5 million for dry hole costs. El Paso is the
operator of four of the wells and we are operator of the remaining two. Under
the terms of the agreement, El Paso has the option to extend the exploration
agreement beyond the initial six well program. The option expires in August
2003. As of the date of this report, four wells in the program have been
drilled. Two resulted in discoveries and have been successfully completed and
placed on-line. One well has been completed and is currently testing and the
fourth well has been temporarily abandoned and is being evaluated for further
completion. The fifth well in the program, High Island 115, is operated by El
Paso and currently drilling to a target depth of 21,000 feet. The sixth well in
the program is currently planned for the second quarter of 2003. El Paso will
operate this well and if they elect not to drill the final well, all interests
in the prospect will revert back to us.





                                      -4-
<PAGE>

     Severance Tax Refund. During July 2002, we applied for and received from
the Railroad Commission of Texas a "high-cost/tight-gas formation" designation
for a portion of our South Texas production. The "high-cost/tight-gas formation"
designation will allow us to receive an abatement of severance taxes for
qualifying wells in various fields. For qualifying wells, production will be
either exempt from tax or taxed at a reduced rate until certain capital costs
are recovered. For qualifying wells, we will also be entitled to a refund of
severance taxes paid during a designated prior 48-month period. Applications for
refund are submitted on a well-by-well basis to the State Comptroller's Office
and due to timing of the acceptance of applications, we are unable to project
the 48-month look-back period for qualifying refunds. We currently estimate that
the total refund, for 2002 and prior periods, will be between $18 million to $23
million ($12 million to $15 million, net of tax), although we can provide no
assurances that the actual total refund amount will fall within our current
estimate. During the fourth quarter of 2002, we recorded refunds totaling $10.4
million ($6.8 million net of tax) of which $1.3 million related to refund of
2002 severance tax expense and $9.1 related to refunds of prior period expense.

2003 CAPITAL EXPENDITURE PLANS

     For 2003, we have budgeted $286 million for capital investments in natural
gas and oil properties. The table below summarizes by area where we plan to
spend our exploration and development dollars together with an estimate of wells
planned for each area. The amount and allocation of our capital investment
program is subject to change based on operational developments, commodity
prices, service costs, acquisitions and numerous other factors. Of the $286
million budgeted for 2003, approximately $21 million of the budget includes
capitalized interest and general and administrative expenses. Generally we do
not budget for acquisitions. The table below reflects our 2003 capital spending
plans as of the date of this report; however, there can be no assurances that
actual amounts spent and wells drilled will equal amounts budgeted.

<Table>
<Caption>
                                  ESTIMATES FOR THE YEAR ENDED DECEMBER 31, 2003
-------------------------------------------------------------------------------------------------------------------
                                           (IN THOUSANDS, EXCEPT WELLS)
                                                WELLS                                          TOTAL CAPITAL
                                               PLANNED    $ EXPLORATION       $ DEVELOPMENT     EXPENDITURES
                                          ----------------   ----------------   ----------------   ----------------
<S>                                       <C>                <C>                <C>                <C>
Onshore ...............................                103   $         10,700   $        139,300   $        150,000
Offshore ..............................                 16             61,000             54,000            115,000
                                          ----------------   ----------------   ----------------   ----------------
                                                       119   $         71,700   $        193,300            265,000
Capitalized expenses ..................                                                                      21,000
                                                                                                   ----------------
Total capital expenditures ............                                                            $        286,000
                                                                                                   ================
</Table>






                                      -5-
<PAGE>



NATURAL GAS AND OIL RESERVES

     The following table summarizes the estimates of our historical net proved
reserves as of December 31, 2002, 2001 and 2000, and the present values
attributable to these reserves at these dates. The reserve data and present
values were fully engineered by Netherland, Sewell & Associates, Inc. and Miller
and Lents, Ltd., independent petroleum engineering consultants.

<Table>
<Caption>
                                                                               AS OF DECEMBER 31,
                                                                   -------------------------------------------
NET PROVED RESERVES:(1)                                                2002           2001           2000
------------------------------------------------------------------ -------------  -------------  -------------
                                                                                 (IN THOUSANDS)

<S>                                                                <C>            <C>            <C>
Natural gas (MMcf)...............................................        610,409        568,208        529,518
Oil (MBbls)......................................................          6,533          6,605          5,352
Total (MMcfe)....................................................        649,607        607,838        561,630
Present value of future net revenues before income taxes(2)......  $   1,326,314  $     714,416  $   2,725,913
Standardized measure of discounted future net cash flows(3)......  $   1,058,064  $     551,525  $   2,064,027
</Table>


----------

     (1)  Netherland, Sewell & Associates engineered reserve data for our Gulf
          of Mexico properties and our South Texas properties which represent
          present values of approximately 83%, 79% and 78%, respectively, of our
          reserves at December 31, 2002, 2001 and 2000. Miller and Lents
          engineered reserve data for the remainder of our onshore properties
          which represent approximately 17%, 21% and 22%, respectively, of the
          present values attributable to our proved reserves at December 31,
          2002, 2001 and 2000.

     (2)  The present value of future net revenues attributable to our reserves
          was prepared using prices in effect at the end of the respective
          periods presented, discounted at 10% per annum ("PV10") on a pre-tax
          basis. In accordance with current SEC guidelines, the PV10 includes
          the fair value of our natural gas and oil hedges in place at December
          31, 2002, 2001 and 2000 of a negative $38.6 million, a positive $65.8
          million and a negative $70.6 million, respectively. Year-end prices
          per Mcf of natural gas used in making the present value determinations
          as of December 31, 2002, 2001 and 2000 were $4.35, $2.38 and $9.55,
          respectively. Year-end prices per Bbl of oil used in making the
          present value determinations as of December 31, 2002, 2001 and 2000
          were $28.74, $17.78 and $24.69, respectively.

     (3)  The standardized measure of discounted future net cash flows
          represents the present value of future net revenues after income tax
          discounted at 10% per annum and has been calculated in accordance with
          SFAS No. 69, "Disclosures About Oil and Gas Producing Activities" (see
          Note 12 -- Supplemental Information on Natural Gas and Oil
          Exploration, Development and Production Activities (Unaudited)) and,
          in accordance with current SEC guidelines, does not include estimated
          future cash inflows from our hedging program.

     In accordance with applicable requirements of the Securities and Exchange
Commission, we estimate our proved reserves and future net revenues using sales
prices estimated to be in effect as of the date we make the reserve estimates.
We hold the estimates constant throughout the life of the properties, except to
the extent a contract specifically provides for escalation. Gas prices, which
have fluctuated widely in recent years, affect estimated quantities of proved
reserves and future net revenues. Any estimates of natural gas and oil reserves
and their values are inherently uncertain, including many factors beyond our
control. The reserve data contained in this Annual Report on Form 10-K represent
only estimates. Reservoir engineering is a subjective process of estimating
underground accumulations of natural gas and oil that cannot be measured in an
exact manner. The accuracy of any reserve estimate is a function of the quality
of available data and of engineering and geological interpretation and judgment.
As a result, estimates of different engineers, including those we use, may vary.
In addition, estimates of reserves may be revised based upon actual production,
results of future development and exploration activities, prevailing natural gas
and oil prices, operating costs and other factors, which revision may be
material. Accordingly, reserve estimates may be different from the quantities of
natural gas and oil that we are ultimately able to recover and are highly
dependent upon the accuracy of the underlying assumptions. Our estimated proved
reserves have not been filed with or included in reports to any federal agency.




                                      -6-
<PAGE>


DRILLING ACTIVITY

The following table sets forth our drilling activity on our properties for the
years ended December 31, 2002, 2001 and 2000.

<Table>
<Caption>
                                                                           YEAR ENDED DECEMBER 31,
                                           ---------------------------------------------------------------------------------------
                                                       2002                          2001                          2000
                                           ---------------------------   ---------------------------   ---------------------------
                                              GROSS            NET          GROSS            NET          GROSS           NET
                                           ------------   ------------   ------------   ------------   ------------   ------------

<S>                                        <C>            <C>            <C>            <C>            <C>            <C>
ONSHORE DRILLING ACTIVITY
EXPLORATORY
   Productive ..........................              2            2.0              1            0.3              1            0.1
   Non-Productive ......................              2            1.8              3            1.0             --             --
                                           ------------   ------------   ------------   ------------   ------------   ------------
     Total onshore exploratory .........              4            3.8              4            1.3              1            0.1
DEVELOPMENT
   Productive ..........................             73           64.0             60           46.9             44           36.5
   Non-Productive ......................             10            9.4             12            9.2              4            3.5
                                           ------------   ------------   ------------   ------------   ------------   ------------
     Total onshore development .........             83           73.4             72           56.1             48           40.0
                                           ------------   ------------   ------------   ------------   ------------   ------------

TOTAL ONSHORE WELLS DRILLED ............             87           77.2             76           57.4             49           40.1

OFFSHORE DRILLING ACTIVITY
EXPLORATORY
   Productive ..........................              6            2.0              7            4.4              8            3.0
   Non-Productive ......................              1            0.4              5            3.9              2            0.9
                                           ------------   ------------   ------------   ------------   ------------   ------------
        Total offshore exploratory .....              7            2.4             12            8.3             10            3.9
DEVELOPMENT
   Productive ..........................              3            1.1              7            4.9              6            3.3
   Non-Productive ......................             --             --              1            1.0              2            0.8
                                           ------------   ------------   ------------   ------------   ------------   ------------
        Total offshore development .....              3            1.1              8            5.9              8            4.1
                                           ------------   ------------   ------------   ------------   ------------   ------------

TOTAL OFFSHORE WELLS DRILLED ...........             10            3.5             20           14.2             18            8.0

TOTAL WELLS DRILLED ....................             97           80.7             96           71.6             67           48.1
                                           ============   ============   ============   ============   ============   ============
</Table>

PRODUCTIVE WELLS

The following table sets forth the number of productive wells in which we owned
an interest as of December 31, 2002.

<Table>
<Caption>
                             OIL WELLS                           NATURAL GAS WELLS
                       -----------------------   -------------------------------------------------
                              OPERATED                  OPERATED                 NON-OPERATED            TOTAL PRODUCTIVE
                       -----------------------   -----------------------   -----------------------   -----------------------
                         GROSS         NET         GROSS         NET         GROSS         NET         GROSS         NET
                       ----------   ----------   ----------   ----------   ----------   ----------   ----------   ----------
<S>                    <C>          <C>          <C>          <C>          <C>          <C>          <C>          <C>
South Texas ........           --           --          450        313.6          112         12.2          562        325.8
Gulf of Mexico .....            6          3.8           48         31.1           25          5.6           79         40.5
Arkoma .............           --           --          131         72.7          121         18.4          252         91.1
Other onshore ......            2          1.4          651        395.9           55         11.8          708        409.1
                       ----------   ----------   ----------   ----------   ----------   ----------   ----------   ----------

Total ..............            8          5.2        1,280        813.3          313         48.0        1,601        866.5
                       ==========   ==========   ==========   ==========   ==========   ==========   ==========   ==========
</Table>

     Productive wells consist of producing wells capable of production,
including wells awaiting connections. Wells that are completed in more than one
producing horizon are counted as one well. The day-to-day operations of natural
gas properties are the responsibility of an operator designated under an
operating agreement. All of our wells classified as "oil" producers are operated
by us.



                                      -7-
<PAGE>


ACREAGE DATA

     The following table sets forth the approximate developed and undeveloped
acreage in which we held a leasehold mineral or other interest as of December
31, 2002. 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 or oil, regardless of whether or not the acreage
contains proved reserves.

<Table>
<Caption>
                                                            AT DECEMBER 31, 2002
                          ---------------------------------------------------------------------------------------
                                  TOTAL ACRES                 DEVELOPED ACRES             UNDEVELOPED ACRES
                          ---------------------------   ---------------------------   ---------------------------
                              GROSS          NET           GROSS           NET           GROSS           NET
                          ------------   ------------   ------------   ------------   ------------   ------------
<S>                       <C>            <C>            <C>            <C>            <C>            <C>
South Texas ...........         92,165         71,014         66,458         49,898         25,707         21,116
Gulf of Mexico(1) .....        423,212        328,361        207,599        131,856        215,613        196,505
Arkoma Basin ..........         75,071         34,111         52,032         26,278         23,039          7,833
Other onshore .........         74,206         50,589         70,899         47,615          3,307          2,974
                          ------------   ------------   ------------   ------------   ------------   ------------

Total .................        664,654        484,075        396,988        255,647        267,666        228,428
                          ============   ============   ============   ============   ============   ============
</Table>


----------
     (1)  Gulf of Mexico includes acreage in federal and state waters.

MARKETING AND CUSTOMERS

     We market the majority of all the natural gas and oil production from
properties we operate for both our account and the account of the other working
interest owners in these properties. We sell substantially all of our production
to a variety of purchasers under short-term (less than 12 months) contracts or
spot gas purchase contracts ranging anywhere from one to 30 days, all at market
prices. We normally sell production to a relatively small number of customers,
as is customary in the exploration, development and production business.
However, based on the current demand for natural gas and oil, we believe that
the loss of any of our major purchasers would not have a material adverse effect
on our financial condition and results of operations. For a list of our
purchasers that accounted for 10% or more of our natural gas and oil revenues
during the preceding last three calendar years, please see "Notes to
Consolidated Financial Statements - Note 8 - Sales to Major Customers."

     We enter into commodity swaps with unaffiliated third parties for portions
of our natural gas production to achieve more predictable cash flows and to
reduce our exposure to short-term fluctuations in gas prices. For more detailed
discussion, please read Item 7. "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- General" and Item 7A.
"Quantitative and Qualitative Disclosures About Market Risk."

     We incur gathering and transportation expenses to move our gas from the
wellhead to a purchaser-specified delivery point. These expenses vary based on
the volume and distance shipped, and the fee charged by the third party
transporter. We do not have any material transportation agreements and we have
not contracted for firm capacity for which we would pay monthly demand charges.
Our oil and natural gas are transported through third party gathering systems
and pipelines. Transportation space on these gathering systems and pipelines is
occasionally limited and at times unavailable because of repairs or
improvements, or as a result of priority transportation agreements with other
gas shippers. While our ability to market our natural gas has only been
infrequently limited or delayed, if transportation space is restricted or is
unavailable, our cash flow from the affected properties could be adversely
affected. Please read the section entitled "Risk Factors -- Operating Hazards
and Uninsured Risks."

ABANDONMENT COSTS

     We are responsible for our working interest share of costs to abandon
natural gas and oil properties and facilities once they are depleted. We have
historically provided for our expected future abandonment liabilities as a
component of our future development costs which have been included in our
calculation of depreciation, depletion and amortization as the properties are
produced. Our estimates of abandonment costs and their timing may change as a
result of many factors including actual drilling and production results,
inflation rates, and changes in environmental laws and regulations. Pursuant to
our adoption of Statement of Financial Accounting Standards No. 143, "Accounting
for Asset Retirement Obligations" on January 1, 2003, we estimate our discounted
future net asset retirement obligation for all of our natural gas and oil
properties and equipment to be approximately $57 million. SFAS No. 143 requires
that the fair value of a liability for an asset's retirement obligation be
recorded in the period in which it is incurred and the corresponding cost
capitalized by increasing the carrying amount of the related long-lived asset.
The liability is accreted to its then present value each period, and the
capitalized cost is depreciated over the useful life of the related asset. If
the liability is settled for an amount other than the recorded amount, a gain or
loss is recognized.




                                      -8-
<PAGE>

         The Minerals Management Service requires lessees of Outer Continental
Shelf 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 Outer Continental Shelf waters of the Gulf of Mexico are
currently required to post an area-wide bond of $3 million or $500,000 per
producing lease. We are presently exempt from any requirement by the Minerals
Management Service to provide supplemental bonding on our offshore leases,
although we may not be able to continue to satisfy the requirements for this
exemption in the future. We believe that even if we did not qualify for this
exemption, the cost of any bonding requirements would not materially affect our
financial condition or results of operations. The Minerals Management Service
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 suspensions or terminations of our
operations could have a material adverse effect on our financial condition and
results of operations.

TITLE TO PROPERTIES

    As is customary in the oil and gas industry, we initially conduct only a
cursory review of the title to undeveloped acreage in farm-out agreements and
natural gas and oil leases. Prior to the commencement of drilling operations, we
conduct a thorough title examination and perform curative work with respect to
significant defects. To the extent title opinions or other investigations
reflect title defects, we, rather than the seller of the undeveloped property,
are typically responsible for curing any title defects at our expense. If we
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, we could suffer
a loss of our entire investment in the property. We have obtained title opinions
on substantially all of our producing properties and believe that we have
satisfactory title to these 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, we obtain title opinions on the most
significant leases. Our natural gas and oil properties are subject to customary
royalty interests, liens for current taxes and other burdens which we believe do
not materially interfere with the use of or affect our carrying value of the
properties.

COMPETITION

     We encounter intense competition from other oil and gas companies in all
areas of our operations, including the acquisition of producing properties and
proved undeveloped acreage. Our competitors include major integrated oil and gas
companies and numerous independent oil and gas companies, individuals and
drilling and income programs. Many of our competitors are large,
well-established companies with substantially larger operating staffs and
greater capital resources than our own and which, in many instances, have been
engaged in the oil and gas business for a much longer time than we have. These
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 our financial or human resources
permit. Our ability to acquire additional properties and to discover reserves in
the future will be dependent upon our ability to evaluate and select suitable
properties and to consummate transactions in this highly competitive
environment.

REGULATION

     The oil and gas industry is extensively regulated by numerous federal,
state and local authorities. Legislation affecting the oil and gas industry is
under constant review for amendment or expansion, frequently increasing the
regulatory burden. Also, 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. Although the regulatory burden on the oil and
gas industry increases our cost of doing business and, consequently, affects our
profitability, generally, these burdens do not appear to affect us any
differently or to any greater or lesser extent than they affect other companies
in the industry with similar types, quantities and locations of production.

     Drilling and Production. Our operations are subject to various types of
regulation at federal, state and local levels. These types of regulation include
requiring permits for the drilling of wells, drilling bonds and reports
concerning operations. Most states in which we operate also regulate:

     o    the location of wells;

     o    the method of drilling and casing wells;

     o    the surface use and restoration of properties upon which wells are
          drilled; and

     o    the plugging and abandoning of wells.




                                      -9-
<PAGE>

     State laws regulate the size and shape of drilling and spacing units or
proration pooling of oil and gas properties. Some states allow 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 oil and gas wells, generally prohibit
the venting or flaring of natural gas and impose requirements regarding the
ratability of production. These regulations may limit the amount of oil and gas
we can produce from our wells or limit the number of wells or the locations at
which we can drill. Generally, our properties located in federal waters are
regulated by the Minerals Management Service and are not subject to regulation
by state agencies.

     We conduct our operations in the Gulf of Mexico on oil and natural gas
leases which are granted by the U.S. federal government and are administered by
the Minerals Management Service. The Minerals Management Service issues leases
through competitive bidding. The lease contracts contain relatively standardized
terms and require compliance with detailed regulations of the Minerals
Management Service. For offshore operations, lessees must obtain Minerals
Management Service approval for exploration plans and development and production
plans prior to the commencement of the 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 Minerals Management Service prior to the commencement of drilling.

     The Minerals Management Service promulgates and enforces regulations that
require offshore production facilities located on the outer continental shelf to
meet stringent engineering, construction, and safety specifications, that impose
strong restrictions on the flaring or venting of natural gas, that prohibit the
burning of liquid hydrocarbons and oil without prior authorization, and that
govern the plugging and abandonment of offshore wells and removal of offshore
production facilities. To cover the various obligations of lessees on the outer
continental shelf, the Minerals Management Service generally requires that
lessees post substantial bonds or other acceptable assurances that these
obligations will be met. The Outer Continental Shelf Lands Act may generally
impose liabilities on us for our offshore operations conducted on federal leases
for clean-up costs and damages caused by pollution resulting from our
operations. Under circumstances such as conditions deemed to be a threat or harm
to the environment, the Minerals Management Service may suspend or terminate any
of our operations in the affected area.

ENVIRONMENTAL MATTERS AND REGULATION

    General. Our operations must comply with 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:

     o    require the acquisition of a permit before drilling commences;

     o    restrict the types, quantities and concentration of various substances
          that can be released into the environment in connection with drilling
          and production activities;

     o    limit or prohibit drilling activities on lands lying within
          wilderness, wetlands and other protected areas;

     o    require remedial measures to prevent pollution from former operations,
          such as pit closure and plugging of abandoned wells; and

     o    impose substantial liabilities for pollution resulting from our
          operations.

     These laws, rules and regulations may also restrict the rate of oil and
natural gas production below the rate that would otherwise be possible. The
regulatory burden on the oil and gas industry increases the cost of doing
business in the industry and consequently affects profitability. Additionally,
Congress and the federal and state agencies frequently revise the environmental
laws and regulations. Any changes that result in more stringent and costly waste
handling, disposal and clean-up requirements could have a significant impact on
the oil and gas industry's operating costs, including ours. We believe that we
substantially comply with all current applicable environmental laws and
regulations and that our continued compliance with existing requirements will
not have a material adverse impact on our financial condition and results of
operations. However, we cannot predict the passage of or quantify the potential
impact of more stringent future laws and regulations at this time. For the year
ended December 31, 2002, we did not incur any material capital expenditures for
environmental control facilities. As of the date of our report, we are not aware
of any environmental issues or claims that will require material capital
expenditures during 2003 or that will have a material impact on our financial
position or results of operations.




                                      -10-
<PAGE>

     Resource Conservation and Recovery Act. The Resource Conservation and
Recovery Act affects oil and gas production activities by imposing regulations
on the generation, transportation, treatment, storage, disposal and cleanup of
"hazardous wastes" and on the disposal of non-hazardous wastes. Under the
auspices of the Environmental Protection Agency, or the EPA, the individual
states administer some or all of the provisions of the Resource Conservation and
Recovery Act, sometimes in conjunction with their own, more stringent
requirements. Drilling fluids, produced waters, and most of the other wastes
associated with the exploration, development, and production of crude oil,
natural gas, or geothermal energy constitute "solid wastes," which are regulated
under the less stringent non-hazardous waste provisions, but there is no
guarantee that the EPA or the individual states will not adopt more stringent
requirements for the handling of non-hazardous wastes or categorize some
non-hazardous wastes as hazardous for future regulation.

     We believe that we are currently in substantial compliance with the
requirements of the Resource Conservation and Recovery Act and related state and
local laws and regulations and that we hold all necessary and up-to-date permits
to the extent that our operations require them under the Resource Conservation
and Recovery Act.

     Comprehensive Environmental Response, Compensation and Liability Act. The
Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA,
also known as the "superfund" law, imposes joint and several liability, without
regard to fault or legality of conduct, on 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
site where the release occurred and companies that disposed or arranged for the
disposal of the hazardous substance. CERCLA also authorizes the EPA and affected
parties to respond to threats to the public health or the environment and to
seek recovery from responsible classes of persons for the costs of the response
actions.

     In the course of our operations, we generate wastes that may fall within
CERCLA's definition of "hazardous substances." Therefore, we may be responsible
under CERCLA for all or part of the costs to clean up sites at which such
"hazardous substances" have been deposited. At this time, however, we have not
been named by the EPA or alleged by any third party as being responsible for
costs and liability associated with alleged releases of any "hazardous
substance" at any "superfund" site.

     Oil Pollution Act. The Oil Pollution Act imposes on responsible parties
strict, joint and several, and potentially unlimited liability for removal costs
and other damages caused by an oil spill covered by the Oil Pollution Act. The
Oil Pollution Act also requires the lessee of an offshore area or a permittee
whose operations take place within a covered offshore facility to establish and
maintain financial responsibility of at least $35 million, which may be
increased to $150 million for facilities with large worst-case spill potentials
and under other circumstances, to cover liabilities related to an oil spill for
which the lessee or permittee of the offshore area is statutorily responsible.
Owners of multiple facilities are required to maintain financial responsibility
for only the facility with the largest potential worst-case spill. We have
received certification from the MMS that due to our financial status, we are
able to cover a minimum of $35 million per occurrence and because we do not have
major oil producing facilities, the maximum certification of $150 million in
coverage is not currently required. As such, we believe we are in compliance
with the financial responsibility provisions of the Oil Pollution Act.

     Federal Water Pollution Control Act. The Federal Water Pollution Control
Act and related state laws provide varying civil and criminal penalties and
liabilities for the unauthorized discharge of petroleum products and other
pollutants to surface waters. The federal discharge permitting program also
prohibits the discharge of produced water, sand and other substances related to
the oil and gas industry to coastal waters. We believe that we are in
substantial compliance with all pollutant, wastewater, and stormwater discharge
regulations and that we hold all necessary and valid permits for the discharge
of such materials from our operations.

     Federal Clean Air Act. The Federal Clean Air Act restricts the emission of
air pollutants and affects both onshore and offshore oil and gas operations. New
facilities may be required to obtain permits before work can begin, and existing
facilities may be required to incur capital costs in order to remain in
compliance. In addition, more stringent regulations governing emissions of toxic
air pollutants are being developed by the EPA, and may increase the costs of
compliance for some facilities. We believe that we are in substantial compliance
with all air emissions regulations and that we hold all necessary and valid
construction and operating permits for our operations.

     Natural Gas Sales Transportation. Historically, federal legislation and
regulatory controls affect the price of the natural gas we produce and the
manner in which we market our production. The Federal Energy Regulatory
Commission, or FERC, has jurisdiction over the transportation and sale for
resale of natural gas in interstate commerce by natural gas companies under the
Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978,
various federal laws have been enacted which have resulted in the complete
removal on January 1, 1993 of all price and non-price controls for sales of
domestic natural gas sold in "first sales," which include all of our sales of
our own production.




                                      -11-
<PAGE>

     FERC also regulates interstate natural gas transportation rates and service
conditions, which affect the marketing of natural gas that we produce, as well
as the revenues we receive for sales of our natural gas. Commencing in 1985,
FERC promulgated a series of orders and regulations that significantly fostered
competition in the business of transporting and marketing gas. These orders and
regulations induced, and ultimately required, interstate pipeline companies to
provide nondiscriminatory transportation services to producers, marketers and
other shippers, regardless of whether shippers were affiliated with an
interstate pipeline company. FERC's initiatives have led to the development of a
competitive, unregulated, open access market for gas purchases and sales that
permits all purchasers of gas to buy gas directly from third-party sellers other
than pipelines. However, the natural gas industry historically has been very
heavily regulated; therefore, we cannot guarantee that the less stringent
regulatory approach recently pursued by FERC and Congress will continue
indefinitely into the future.

     Under FERC's current regulatory regime, transmission services must be
provided on an open-access, non- discriminatory basis at cost-based rates.
Gathering service, which occurs upstream of jurisdictional transmission
services, is regulated by the states onshore and in state waters. In offshore
Federal waters, gathering is regulated by FERC under the Outer Continental Shelf
Lands Act. The Outer Continental Shelf Lands Act requires open access and
non-discriminatory rates, but does not provide for cost-based rates. Although
its policy is still in flux, FERC has recently reclassified jurisdictional
transmission facilities as non-jurisdictional gathering facilities, which has
the tendency to increase our costs of getting gas to point-of-sale locations.



                                      -12-
<PAGE>


RISK FACTORS AFFECTING OUR BUSINESS

OUR BUSINESS AND OPERATIONS COULD BE ADVERSELY AFFECTED BY RECENT TERRORIST.

     On September 11, 2001, the United States was the target of terrorist
attacks of unprecedented scope, and the United States and others instituted
military action in response. Since the September 11th attacks, the U.S.
government has issued public warnings that indicate that energy assets might be
specific targets of terrorist organizations. The continued threat of terrorism
and the impact of military and other actions will likely lead to increased
volatility in prices for natural gas and oil and could affect the markets for
our operations. In addition, future acts of terrorism could be directed against
companies operating in the United States, particularly those engaged in sectors
essential to our economic prosperity, such as natural resources. These
developments have subjected our operations to increased risk and, depending on
their ultimate magnitude, could have a material adverse affect on our business.


     A DECLINE IN NATURAL GAS AND OIL PRICES MAY ADVERSELY AFFECT OUR FINANCIAL
RESULTS.

     As an independent natural gas and oil producer, the revenues we generate
from our operations are highly dependent on the price of, and demand for,
natural gas and oil. Even relatively modest changes in oil and natural gas
prices may significantly change our revenues, results of operations, cash flows
and proved reserves. Historically, the markets for natural gas and oil have been
volatile and are likely to continue to be volatile in the future. Prices for
natural gas and oil may fluctuate widely 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 our control, such as:

     o    the domestic and foreign supply of natural gas and oil;

     o    the price of foreign imports;

     o    overall domestic and global economic conditions;

     o    political and economic conditions in oil producing countries,
          including the Middle East and South America;

     o    the ability of members of the Organization of Petroleum Exporting
          Countries to agree to and maintain oil price and production controls;

     o    the level of consumer product demand;

     o    weather conditions;

     o    domestic and foreign governmental regulations; and

     o    the price and availability of alternative fuels.

     If natural gas and oil prices decline, the amount of natural gas and oil we
can economically produce may be reduced, which may result in a material decline
in our revenues.

     WE MAY BE REQUIRED TO TAKE ADDITIONAL WRITEDOWNS IF NATURAL GAS AND OIL
PRICES DECLINE.

     We may be required under full cost accounting rules to write down the
carrying value of our natural gas and oil properties when natural gas and oil
prices are low or if we have substantial downward adjustments to our estimated
proved reserves, increases in our estimates of development costs or
deterioration in our exploration results.

     For the quarter ended December 31, 2001, we were required under SEC
accounting rules to take a non-cash charge to impair or reduce the carrying
value of our oil and gas properties by $6.2 million ($4.0 million net of tax).
The charge was primarily a result of low natural gas prices. We may be required
to take additional write downs in future periods should prices decline to
unfavorable levels or if we have unsuccessful drilling results.

     WE MAY NOT BE ABLE TO MEET OUR SUBSTANTIAL CAPITAL REQUIREMENTS.

     Our business is capital intensive. To maintain or increase our base of
proved oil and gas reserves, we must invest a significant amount of cash flow
from operations in property acquisitions, development and exploration
activities. We are currently making and will continue to make substantial
capital expenditures to find, develop, acquire and produce natural gas and oil
reserves. If our revenues or borrowing base under our revolving credit facility
decrease as a result of lower natural gas and oil prices, operating difficulties
or declines in reserves, we may not be able to expend the capital necessary to
undertake or complete future drilling programs or acquisition opportunities
unless we raise additional funds through debt or equity financings. Without
continued employment of capital, our oil and gas reserves will decline. We may
not be able to obtain debt or equity financing, and cash generated by operations
or available under our revolving credit facility may not be sufficient to meet
our capital requirements.





                                      -13-
<PAGE>

     THE AMOUNT OF OUR OUTSTANDING INDEBTEDNESS MAY RESTRICT OUR FINANCIAL
FLEXIBILITY.

     Our outstanding indebtedness at December 31, 2002 was $252 million, and as
of February 20, 2003 was $247 million. Further, as of February 20, 2003, we have
remaining borrowing capacity under our credit facility of $152.6 million, which
we may use for future acquisitions. Our level of indebtedness affects our
operations in a number of ways. Our revolving credit facility and the indenture
governing our senior subordinated notes contain covenants that require a
substantial portion of our cash flow from operations to be dedicated to the
payment of interest on our indebtedness. During 2002 and 2001, we made aggregate
cash interest payments of $14.9 million and $14.8 million, respectively. Funds
dedicated to debt service payment will not be available for other purposes.
Further, other covenants in these agreements require us to meet the financial
tests specified in these agreements and establish other restrictions that limit
our ability to borrow additional funds or dispose of assets. They may also
affect our flexibility in planning for, and reacting to, changes in business
conditions. Moreover, future acquisition and development activities may require
us to significantly alter our capitalization structure, which may alter our
indebtedness. Our ability to meet our debt service obligations and reduce our
total indebtedness will depend upon our future performance.

     ESTIMATES OF PROVED RESERVES AND FUTURE NET REVENUE MAY CHANGE.

     The estimates of proved reserves of natural gas and oil included in this
document are based on various assumptions. The accuracy of any reserve estimate
is a function of the quality of available data, engineering, geological
interpretation and judgment and the assumptions used regarding quantities of
recoverable natural gas and oil reserves and prices for crude oil and natural
gas. Actual prices, production, development expenditures, operating expenses and
quantities of recoverable oil and natural gas reserves will vary from those
assumed in our estimates, and these variances may be significant. Any
significant variance from the assumptions used could result in the actual
quantity of our reserves and future net cash flow being materially different
from the estimates in our reserve reports. In addition, results of drilling,
testing and production and changes in crude oil and natural gas prices after the
date of the estimate may result in downward revisions.

     THE SUCCESS OF OUR BUSINESS DEPENDS UPON OUR ABILITY TO FIND, DEVELOP AND
ACQUIRE OIL AND GAS RESERVES.

     Without successful exploration, development or acquisition activities, our
oil and gas reserves and our revenues will decline over time. The continuing
development of reserves and acquisition activities require significant
expenditures. Our cash flow from operations may not be sufficient for this
purpose, and we may not be able to obtain the necessary funds from other
sources. If we are not able to replace reserves at sufficient levels, the amount
of credit available to us may decrease since the maximum amount of borrowing
capacity available under our revolving credit facility is based, at least in
part, on the estimated quantities of our proved reserves.


     THE OIL AND GAS BUSINESS INVOLVES MANY OPERATING RISKS THAT CAN CAUSE
SUBSTANTIAL LOSSES; INSURANCE MAY NOT PROTECT US AGAINST ALL THESE RISKS.

     In our operations we may experience hazards and risks inherent in drilling
for, producing and transporting of natural gas and oil. These hazards and risks
may result in loss of hydrocarbons, environmental pollution, personal injury
claims, and other damage to our properties and third parties and include:

     o    fires;

     o    natural disasters;

     o    explosions;

     o    encountering formations with abnormal pressures;

     o    blowouts;

     o    cratering;

     o    pipeline ruptures; and

     o    spills.

     We are insured against some, but not all, of the hazards associated with
our business. As a result, we may be liable or sustain losses that could be
substantial due to events that are not insured.

     Additionally, our natural gas and oil operations located in the Gulf of
Mexico may experience tropical weather disturbances, some of which can be severe
enough to cause substantial damage to facilities and possibly interrupt
production. We are not insured against all potential losses. 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 a material adverse impact on our financial condition and results of
operations.



                                      -14-
<PAGE>

     OUR ACQUISITION AND INVESTMENT ACTIVITIES MAY NOT BE SUCCESSFUL.

     The successful acquisition of producing properties requires assessment of
reserves, future commodity prices, operating costs, potential environmental and
other liabilities. These assessments may not be accurate. Our review of the
properties we intend to acquire may not reveal all existing or potential
problems nor allow us to become sufficiently familiar with the properties to
fully assess their deficiencies and capabilities. We may not always perform
inspections on every property or well, and structural or environmental problems
may not be observable even when an inspection is undertaken. Accordingly, we may
suffer the loss of one or more acquired properties due to title deficiencies or
may be required to make significant expenditures to cure environmental
contamination with respect to acquired properties. Even when problems are
identified, the seller may be unwilling or unable to provide effective
contractual protection against all or part of the problems. We are generally not
entitled to contractual indemnification for environmental liabilities and we
typically acquire structures on a property on an "as is" basis.

     DRILLING OIL AND NATURAL GAS WELLS IS A HIGH-RISK ACTIVITY AND SUBJECTS US
TO A VARIETY OF FACTORS THAT WE CANNOT CONTROL.

     Our drilling activities subject us to many risks, including the risk that
we will not find commercially productive reservoirs. Drilling for oil and
natural gas can be unprofitable, not only from dry wells, but from productive
wells that do not produce sufficient revenues to return a profit. Also, title
problems, weather conditions, governmental requirements and shortages or delays
in the delivery of equipment and services can delay our drilling operations or
result in their cancellation. The cost of drilling, completing and operating
wells is often uncertain, and new wells may not be productive. As a result, we
may not recover all or any portion of our investment.

     OUR HEDGING ACTIVITIES COULD RESULT IN FINANCIAL LOSSES OR COULD REDUCE OUR
INCOME.

     To achieve a more predictable cash flow and to reduce our exposure to
adverse fluctuations in the prices of oil and natural gas, we currently and may
in the future enter into hedging arrangements for a portion of our natural gas
and oil production. The hedging instruments we generally use, such as fixed
price swaps, collars and options, expose us to a number of risks, including
instances where our hedging contracts will not permit us to realize the full
benefit of higher natural gas prices. In addition, there is the risk that our
actual production is less than expected and that the counterparty to the hedging
contract defaults on its contractual obligations.

     WE MAY INCUR SUBSTANTIAL COSTS TO COMPLY WITH ENVIRONMENTAL AND OTHER
GOVERNMENTAL REGULATIONS.

     Our exploration and production operations are regulated extensively at the
federal and state levels. Environmental and other governmental regulations have
increased the costs to plan, design, drill, install, operate and abandon oil and
natural gas wells. We have made and will continue to make all necessary
expenditures, both financial and managerial, in our efforts to comply with the
requirements of environmental and governmental regulations. Increasingly strict
environmental laws, regulations and enforcement policies and claims for damages
to property, employees, other persons and the environment resulting from our
operations, could result in substantial costs and liabilities in the future.

     COMPETITIVE INDUSTRY CONDITIONS MAY ADVERSELY AFFECT OUR RESULTS OF
OPERATIONS.

     As an independent natural gas and oil producer, we face strong competition
in all aspects of our business. Many of our competitors are large,
well-established companies that have substantially larger operating staffs and
greater capital resources than we do. These 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 our financial and human resources permit.

     THE INABILITY OF ONE OR MORE OF OUR CUSTOMERS TO MEET THEIR OBLIGATIONS MAY
ADVERSELY AFFECT OUR FINANCIAL RESULTS.

     Substantially all of our accounts receivable result from natural gas and
oil sales or joint interest billings to third parties in the energy industry.
This concentration of customers and joint interest owners may impact our overall
credit risk in that these entities may be similarly affected by changes in
economic and other conditions. Recent market conditions resulting in downgrades
to credit ratings of energy merchants have affected the liquidity of several of
our purchasers. During the third quarter of 2002, we discontinued selling our
natural gas and oil to several energy merchants that received downgrades to
their credit ratings.




                                      -15-
<PAGE>

     Further, our natural gas futures and swap contracts also expose us to
credit risk in the event of nonperformance by counterparties.

     POTENTIAL CONFLICTS OF INTEREST WITH OUR MAJORITY STOCKHOLDER.

     A variety of conflicts of interest between KeySpan and our public
stockholders may arise as a result of KeySpan's controlling interest in our
company. As of the date of this report, KeySpan owns approximately 66% of our
common stock. KeySpan is in a position to control:

     o    the election of the entire Board of Directors;

     o    the outcome of the vote on all matters requiring the vote of our
          stockholders;

     o    all matters relating to our management;

     o    the acquisition or disposition of our assets, including the sale of
          our business as a whole;

     o    payment of dividends on our common stock;

     o    the future issuance of our common stock or other securities; and

     o    hedging, drilling, operating and acquisition expenditure plans.

     The Chairman of our Board of Directors, Robert B. Catell, is also the
Chairman of the Board of Directors and Chief Executive Officer of KeySpan. In
addition to Mr. Catell, four of our nine other directors are currently or were
previously affiliated with KeySpan: Gerald Luterman is Executive Vice President
and Chief Financial Officer of KeySpan; H. Neil Nichols is Senior Vice President
of Corporate Development and Asset Management of KeySpan; Robert J. Fani is
President of KeySpan Energy Services and Supply; and James Q. Riordan, Chairman
of our Audit Committee, retired from KeySpan's Board in May 2002.

     INVESTORS WILL HAVE VERY LIMITED ABILITY TO RECOVER AGAINST OUR FORMER
AUDITORS WITH RESPECT TO OUR FINANCIAL STATEMENTS.

     On March 29, 2002, we dismissed Arthur Andersen LLP and engaged Deloitte &
Touche LLP as our independent public accountants. Our consolidated financial
statements as of and for the years ended December 31, 2000, 1999 and 1998 were
audited by Arthur Andersen, as indicated in their report with respect thereto.
The firm Arthur Andersen was convicted of obstruction of justice relating to a
federal investigation of Enron Corp., has ceased operations and has lost the
services of the material personnel responsible for our audit. As a result, it is
not possible to obtain Arthur Andersen's consent to the incorporation by
reference of their report in future filings with the SEC under the Securities
Act of 1933. Because Arthur Andersen will not be deemed to have consented to the
incorporation by reference of their report in such filings, investors will not
be able to recover against Arthur Andersen under Section 11 of the Securities
Act for any untrue statements of a material fact contained in the financial
statements audited by Arthur Andersen or any omissions to state a material fact
required to be stated therein.




                                      -16-
<PAGE>


EMPLOYEES

     As of December 31, 2002, we had 145 full time employees, 101 of whom are
located at our headquarters in Houston, Texas and the remainder of whom are
located in our South Texas, Arkansas, West Virginia and East Texas field
offices. None of our employees are represented by a labor union. We employ the
services of independent consultants and contractors to perform various
professional services, particularly in the areas of construction, design and
well-site surveillance, permitting and environmental assessment. At our
direction, independent contractors usually perform field and on-site production
operation services, including pumping, maintenance, dispatching, inspection and
testing.

OFFICES

     We currently lease approximately 69,000 square feet of office space in
Houston, Texas at 1100 Louisiana Street, where our principal offices are
located. In addition, we maintain field operations offices in South Texas,
Arkansas, West Virginia and East Texas.

AVAILABLE INFORMATION

     Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K and other filings pursuant to Section 13 (a) or 15 (d) of
the Exchange Act are available free of charge on our internet website at
http://www.houstonexploration.com as soon as reasonably practicable after we
electronically file such material with, or furnish it to, the Securities and
Exchange Commission.

ITEM 3. LEGAL PROCEEDINGS

On August 18, 2002, a complaint styled Victor Ramirez, Santiago Ramirez, Jr.,
Oswaldo H. Ramirez and Javier Ramirez as Co-Trustees of the Ramirez Mineral
Trust v. The Houston Exploration Company, cause number 5,207, was filed in the
district court of the 49th Judicial District in Zapata County, Texas. The
complaint alleges that we trespassed by drilling the No. 7 RMT well to a depth
in excess of our lease rights and commingled production by producing from the
excess depth. The plaintiffs claim damages for trespass and conversion in excess
of $6 million and further seek to recover exemplary damages in excess of $18
million. At February 20, 2003, the issuance date of our original report, we were
in the discovery stage of the litigation process for this claim. We believe that
the claim will not have a material adverse effect on our financial condition or
results of operations.

     With the exception of the matter described above, we are not a party to any
material pending legal proceedings, other than ordinary routine litigation
incidental to our business that management believes will not have a material
adverse effect on our financial condition or results of operations.

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

     No matters were submitted to a vote of our security holders during the last
quarter of the fiscal year ended December 31, 2002.



                                      -17-
<PAGE>


PART II.

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

     Our common stock is traded on the New York Stock Exchange under the symbol
"THX." The following table sets forth the range of high and low sales prices for
each calendar quarterly period from January 1, 2000 through December 31, 2002 as
reported on the New York Stock Exchange:

<Table>
<Caption>
YEAR ENDED DECEMBER 31, 2002          HIGH        LOW
---------------------------------   --------   --------
<S>                                 <C>        <C>
First Quarter ...................   $  33.65   $  27.32
Second Quarter ..................   $  31.85   $  28.40
Third Quarter ...................   $  31.45   $  23.80
Fourth Quarter ..................   $  34.00   $  28.21
</Table>

<Table>
<Caption>
YEAR ENDED DECEMBER 31, 2001          HIGH       LOW
---------------------------------   --------   --------
<S>                                 <C>        <C>
First Quarter ...................   $  39.21   $  27.45
Second Quarter ..................   $  38.00   $  24.90
Third Quarter ...................   $  34.26   $  22.20
Fourth Quarter ..................   $  35.00   $  23.10
</Table>

     As of February 20, 2003, 30,961,418 shares of common stock were outstanding
and we had approximately 40 stockholders of record and approximately 3,500
beneficial owners.

DIVIDENDS

     We have never paid any cash dividends and do not anticipate declaring any
dividends in the foreseeable future. We plan to retain our cash for the
operation and expansion of our business, including exploration, development and
acquisition activities. Moreover, our bank credit facility and the indenture
governing our 8?% Senior Subordinated Notes due 2008 contain restrictions on the
payment of dividends to holders of common stock. Accordingly, were our dividend
policy to change in the future, our ability to pay dividends would be subject to
these restrictions and our results of operations, financial condition, capital
requirements and other factors deemed relevant by the Board of Directors. Please
read Item 7. "Management's Discussion and Analysis of Financial Condition and
Results of Operations."

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

     The table below lists the number of stock options and restricted stock that
would be issued upon exercise of grants made under equity compensation plans
that have been approved by our stockholders (the 1996 Stock Option Plan and the
2002 Long-Term Incentive Plan) and under equity compensation plans or other
grants that have not been approved by our stockholders (primarily option grants
under our 1999 Non-Qualified Stock Option Plan). We have not issued any warrants
or rights.

<Table>
<Caption>
                              EQUITY COMPENSATION PLAN TABLE PURSUANT TO RULE 102(b)
--------------------------------------------------------------------------------------------------------------
                                       NUMBER OF SECURITIES
                                       TO BE ISSUED UPON         WEIGHTED AVERAGED
                                       EXERCISE OF                EXERCISE PRICE OF       NUMBER OF SECURITIES
                                       OUTSTANDING OPTIONS,      OUTSTANDING OPTIONS,     REMAINING AVAILABLE
PLAN CATEGORY                          WARRANTS AND RIGHTS       WARRANTS AND RIGHTS      FOR FUTURE ISSUANCE
----------------------------------     --------------------      --------------------     --------------------

<S>                                    <C>                       <C>                      <C>
Equity compensation plans
   approved by shareholders                       1,708,142      $              27.63                  906,379
Equity compensation plans not
   approved by shareholders(1)                      720,191                     27.19                      566
                                       --------------------      --------------------     --------------------

Total                                             2,428,333      $              27.50                  906,945
                                       ====================      ====================     ====================
</Table>


----------
(1) Includes shares issued under our 1999 Non-Qualified Stock Option Plan and
    6,667 shares of restricted stock that remain outstanding and that were
    issued to our Chief Executive Officer in April 2001 pursuant to the terms of
    his employment contract.





                                      -18-
<PAGE>


ITEM 6. SELECTED FINANCIAL DATA


     The following table shows selected financial data derived from our
consolidated financial statements for each of the five years in the period ended
December 31, 2002. You should read these financial data in conjunction with Item
7. "Management's Discussion and Analysis of Financial Condition and Results of
Operations" and our Consolidated Financial Statements and the related Notes.

<Table>
<Caption>
                                                                             YEARS ENDED DECEMBER 31,
                                                        ----------------------------------------------------------------
                                                           2002          2001         2000          1999         1998
                                                        ----------    ----------   ----------    ----------   ----------
                                                                     (IN THOUSANDS, EXCEPT PER SHARE DATA)
<S>                                                     <C>           <C>          <C>           <C>          <C>
INCOME STATEMENT DATA:
REVENUES:
  Natural gas and oil revenues(1) ...................   $  344,295    $  387,156   $  277,487    $  157,137   $  134,003
  Other .............................................        1,086         1,353        1,738         1,147        1,123
                                                        ----------    ----------   ----------    ----------   ----------
        Total revenues(1) ...........................      345,381       388,509      279,225       158,284      135,126
EXPENSES:
  Lease operating expense ...........................       33,976        25,291       23,553        18,406       16,199
  Severance tax (2) .................................        9,487        11,035        9,757         5,444        4,967
  Transportation expense (1) ........................        9,317         7,652        6,892         6,557        6,879
  Depreciation, depletion and amortization ..........      171,610       128,736       89,239        74,051       79,838
  Writedown in carrying value .......................           --         6,170           --            --      130,000
  General and administrative, net ...................       13,077        17,110        8,928         4,150        6,086
                                                        ----------    ----------   ----------    ----------   ----------
        Total operating expenses ....................      237,467       195,994      138,369       108,608      243,969
Income (loss) from operations .......................      107,914       192,515      140,856        49,676     (108,843)
Other (income) expense (3) ..........................       (9,070)          119        1,752            --           --
Interest expense, net ...............................        7,398         2,992       11,361        13,307        4,597
                                                        ----------    ----------   ----------    ----------   ----------
Income (loss) before income taxes ...................      109,586       189,404      127,743        36,369     (113,440)
Income tax provision (benefit) ......................       39,092        66,803       42,485        11,748      (40,754)
                                                        ----------    ----------   ----------    ----------   ----------
NET INCOME (LOSS) ...................................   $   70,494    $  122,601   $   85,258    $   24,621   $  (72,686)
                                                        ==========    ==========   ==========    ==========   ==========

Net income (loss) per share .........................   $     2.31    $     4.06   $     3.06    $     1.03   $    (3.05)
                                                        ==========    ==========   ==========    ==========   ==========
Net income (loss) per share--diluted ................   $     2.28    $     4.00   $     3.02    $     0.95   $    (3.05)
                                                        ==========    ==========   ==========    ==========   ==========

Weighted average shares .............................       30,569        30,228       27,860        23,906       23,768
Weighted average shares--diluted ....................       30,878        30,645       28,213        28,310       23,768

Ratio of earnings to fixed charges (4) ..............         7.6x         12.8x         5.5x          2.0x          N/M

CASH FLOW DATA:
Net cash flows from operating activities
    before adjustments for working capital ..........   $  282,049    $  325,214   $  217,800    $  111,381   $   97,438
Net cash provided by operating activities ...........      243,869       358,032      200,791       110,072      102,378
Net cash used in investing activities ...............      252,125       368,277      184,512       147,654      302,685
Net cash provided (used) in financing activities ....       17,668         9,189      (22,106)       48,439      200,207
</Table>

<Table>
<Caption>
                                                                         AT DECEMBER 31,
                                           --------------------------------------------------------------------------
                                               2002            2001           2000           1999            1998
                                           ------------    ------------   ------------   ------------    ------------
<S>                                        <C>             <C>            <C>            <C>             <C>
BALANCE SHEET DATA:
Working capital (deficit) ..............   $     (1,702)   $     34,314   $     19,746   $    (71,219)   $     (3,242)
Property, plant and equipment, net .....      1,022,414         938,761        705,390        610,116         536,582
Total assets ...........................      1,138,816       1,059,092        837,384        678,483         569,452
Long-term debt and notes ...............        252,000         244,000        245,000        281,000         313,000
Stockholders' equity ...................        592,789         565,881        396,742        217,590         192,530
</Table>



                                      -19-
<PAGE>




----------
(1)  For all periods presented, we applied Emerging Issues Task Force ("EITF")
     No. 00-10 "Accounting for Shipping and Handling Fees and Costs." Pursuant
     to our application of EITF No. 00-10, transportation expenses previously
     reflected as a reduction to natural gas and oil revenues were added back to
     revenues and reflected as a separate component of operating expense. The
     application of EITF No. 00-10 has no effect on income from operations or
     net income. See Note 11 - Restatement and Reclassification - Application of
     EITF No. 00-10 - Transportation Expense.

(2)  Severance tax expense for 2002 is reported net of a reduction of $1.3
     million for expense incurred and recorded in 2002 pursuant to the receipt
     of a "high-cost/tight sand" designation for a portion of our South Texas
     production. See Note 9 - Commitments and Contingencies - Severance Tax
     Refund.

(3)  For 2002, other income of $9.1 million represents a refund of prior period
     severance tax expense recorded pursuant to the receipt of a "high
     cost/tight sand" designation for a portion of our South Texas production.
     For 2001 and 2000, other expense of $0.2 million and $1.8 million,
     respectively, represents nonrecurring expenses incurred in connection with
     a strategic review of alternatives for Houston Exploration and KeySpan's
     investment in our company, including the possible sale of all or a portion
     of Houston Exploration. Please see Note 6 - Related Party Transactions.

(4)  For purposes of determining the ratio of earnings to fixed charges,
     earnings are defined as income (loss) before tax plus fixed charges,
     adjusted to exclude capitalized interest. Fixed charges consist of interest
     expense, whether expensed or capitalized, and an imputed or estimated
     interest component of rent expense (See Exhibit 12.1 for calculation). For
     the year ended December 31, 1998, ratio of earnings to fixed charges was
     less than one-to-one coverage due to a deficiency of $123.2 million caused
     by a writedown of the carrying value of our natural gas and oil properties
     of $130 million ($84.5 million after taxes).




                                      -20-
<PAGE>


ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

     As discussed in Notes to the Consolidated Financial Statements - Note 11 -
Restatement and Reclassifications, the accompanying 2001 consolidated financial
statements have been restated. The restatements have no effect on income from
operations or net income. The following Management's Discussion and Analysis of
Financial Condition and Results of Operations reflects this restatement.

GENERAL

     We are an independent natural gas and oil company engaged in the
exploration, development, exploitation and acquisition of domestic natural gas
and oil properties. Our operations are primarily focused in South Texas,
offshore in the Gulf of Mexico and in the Arkoma Basin of Oklahoma and Arkansas.

     At December 31, 2002, our net proved reserves were 650 billion cubic feet
equivalent or Bcfe, with a present value, discounted at 10% per annum, of cash
flows before income taxes of $1.3 billion. Our reserves are fully engineered on
an annual basis by independent petroleum engineers. Our focus is natural gas.
Approximately 94% of our net proved reserves at December 31, 2002 were natural
gas, approximately 69% of which were classified as proved developed. We operate
approximately 85% of our properties.

     During the year ended December 31, 2002 we drilled a total of 97 wells of
which 84 were successful reflecting a success rate of 86%. We produced a total
of 103 billion cubic feet equivalent, or Bcfe, and increased our average daily
production during the year by 14% to 281 million cubic feet equivalent, or
MMcfe, per day. We replaced 141% of our production by adding 145 Bcfe in net
proved reserves. We generated $282 million in cash flows from operations before
adjustments for changes in current assets and liabilities and invested a net
$253 million in natural gas and oil properties, including $65 million for
producing properties acquired in South Texas and the Gulf of Mexico.

     We began exploring for natural gas and oil in December 1985 on behalf of
The Brooklyn Union Gas Company. Brooklyn Union is an indirect wholly owned
subsidiary of KeySpan Corporation. KeySpan, a member of the Standard & Poor's
500 Index, is a diversified energy provider whose principal natural gas
distribution and electric generation operations are located in the Northeastern
United States. In September 1996 we completed our initial public offering and
sold approximately 31% of our shares to the public. As of December 31, 2002,
THEC Holdings Corp., an indirect wholly owned subsidiary of KeySpan, owned
approximately 66% of the outstanding shares of our common stock.

     As an independent oil and gas producer, our revenue, profitability and
future rate of growth are substantially dependent upon prevailing prices for
natural gas and oil, our ability to find and produce natural gas and oil and our
ability to control and reduce costs, all of which are dependent upon numerous
factors beyond our control, such as economic, political and regulatory
developments and competition from other sources of energy. The energy markets
have historically been very volatile and commodity prices may fluctuate widely
in the future. A substantial or extended decline in natural gas and oil prices
or poor drilling results could have a material adverse effect on our financial
position, results of operations, cash flows, quantities of natural gas and oil
reserves that may be economically produced and access to capital.

CRITICAL ACCOUNTING POLICIES AND USE OF ESTIMATES

     Revenue Recognition and Gas Imbalances. We use the entitlements method of
accounting for the recognition of natural gas and oil revenues. Under this
method of accounting, income is recorded based on our net revenue interest in
production or nominated deliveries. We incur production gas volume imbalances in
the ordinary course of business. Net deliveries in excess of entitled amounts
are recorded as liabilities, while net under deliveries are reflected as assets.
Imbalances are reduced either by subsequent recoupment of over-and under
deliveries or by cash settlement, as required by applicable contracts.

     Hedging Activities. On January 1, 2001, we adopted Statements of Financial
Accounting Standards No. 133, as amended, "Accounting for Derivative Instruments
and Hedging Activities." Our hedges are cash flow hedges and qualify for hedge
accounting under SFAS No. 133 and, accordingly, we carry the fair market value
of our derivative instruments on the balance sheet as either an asset or
liability and defer unrealized gains or losses in accumulated other
comprehensive income. Gains and losses are reclassified from accumulated other
comprehensive income to the income statement as a component of natural gas and
oil revenues in the period the hedged production occurs. If any ineffectiveness
occurs, amounts are recorded directly to other income or expense.

     Full Cost Accounting. We use the full cost method to account for our
natural gas and oil properties. Under full cost accounting, all costs incurred
in the acquisition, exploration and development of natural gas and oil reserves
are capitalized




                                      -21-
<PAGE>

into a "full cost pool." Capitalized costs include costs of all unproved
properties, internal costs directly related to our natural gas and oil
activities and capitalized interest. We amortize these costs using a
unit-of-production method. We compute the provision for depreciation, depletion
and amortization quarterly by multiplying production for the quarter by a
depletion rate. The depletion rate is determined by dividing our total
unamortized cost base by net equivalent proved reserves at the beginning of the
quarter. Our total unamortized cost base is the sum of (i) our full cost pool;
less (ii) our unevaluated properties and their related costs which are excluded
from the amortization base until we have made a determination as to the
existence of proved reserves; plus (iii) estimates for future development costs
as well as future abandonment and dismantlement costs. We review our unevaluated
properties at the end of each quarter to determine if the costs incurred should
be reclassified to the full cost pool and thereby subject to amortization. Sales
of natural gas and oil properties are accounted for as adjustments to the full
cost pool, with no gain or loss recognized, unless the adjustment would
significantly alter the relationship between capitalized costs and proved
reserves.

     Under full cost accounting rules, total capitalized costs are limited to a
ceiling equal to the present value of future net revenues, discounted at 10% per
annum, plus the lower of cost or fair value of unproved properties less income
tax effects (the "ceiling limitation"). We perform a quarterly ceiling test to
evaluate whether the net book value of our full cost pool exceeds the ceiling
limitation. If capitalized costs (net of accumulated depreciation, depletion and
amortization) less deferred taxes are greater than the discounted future net
revenues or ceiling limitation, a writedown or impairment of the full cost pool
is required. A writedown of the carrying value of the full cost pool is a
non-cash charge that reduces earnings and impacts stockholders' equity in the
period of occurrence and typically results in lower depreciation, depletion and
amortization expense in future periods. Once incurred, a writedown is not
reversible at a later date.

     The ceiling test is calculated using natural gas and oil prices in effect
as of the balance sheet date, held constant over the life of the reserves. We
use derivative financial instruments that qualify for hedge accounting under
SFAS No. 133 to hedge against the volatility of natural gas prices, and in
accordance with current Securities and Exchange Commission guidelines, we
include estimated future cash flows from our hedging program in our ceiling test
calculation. In calculating our ceiling test at December 31, 2002, we estimated
that we had a full cost ceiling "cushion", whereby the carrying value of our
full cost pool was less than the ceiling limitation. No writedown is required
when a cushion exists. Natural gas prices continue to be volatile and the risk
that we will be required to write down our full cost pool increases when natural
gas prices are depressed or if we have significant downward revisions in our
estimated proved reserves.

     Use of Estimates. The preparation of the consolidated financial statements
in conformity with accounting principals generally accepted in the United States
of America requires our 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. Our most
significant financial estimates are based on remaining proved natural gas and
oil reserves. Estimates of proved reserves are key components of our depletion
rate for natural gas and oil properties and our full cost ceiling limitation.

     Natural gas and oil reserve quantities represent estimates only. Under full
cost accounting, we use reserve estimates to determine our full cost ceiling
limitation as well as our depletion rate. We estimate our proved reserves and
future net revenues using sales prices estimated to be in effect as of the date
we make the reserve estimates. We hold the estimates constant throughout the
life of the properties, except to the extent a contract specifically provides
for escalation. Natural gas prices, which have fluctuated widely in recent
years, affect estimated quantities of proved reserves and future net revenues.
Further, any estimates of natural gas and oil reserves and their values are
inherently uncertain for numerous reasons, including many factors beyond our
control. 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. In addition,
estimates of reserves may be revised based upon actual production, results of
future development and exploration activities, prevailing natural gas and oil
prices, operating costs and other factors, and these revisions may be material.
Reserve estimates are highly dependent upon the accuracy of the underlying
assumptions. Actual future production may be materially different from estimated
reserve quantities and the differences could materially affect future
amortization of natural gas and oil properties.



                                      -22-
<PAGE>


     Accounting for Stock Option Expense. For the years ended December 31, 2002,
2001 and 2000, we accounted for stock options using the intrinsic value method
prescribed under Accounting Principles Board Opinion 25 and accordingly, we did
not recognize compensation expense for stock options. On January 1, 2003, we
adopted the fair value expense recognition provisions of SFAS No. 123
"Accounting for Stock-Based Compensation" and as amended by SFAS No. 148,
"Accounting for Stock-Based Compensation - Transition and Disclosure." SFAS No.
148 proposes three alternatives transition methods for adopting the fair value
method under SFAS No. 123:

     o    Prospective Method - recognize fair value expense for all awards
          granted in the year of adoption but not previous awards;

     o    Modified Prospective Method - recognize fair value expense for the
          unvested portion of all stock options granted, modified, or settled
          since 1994 (i.e., the unvested portion of the prior awards or those
          granted in the year of adoption must be recorded using the fair value
          method); and

     o    Retroactive Restatement Method - similar to the Modified Prospective
          Method except that all prior periods are restated.

We adopted SFAS No. 123 using the Prospective Method and as a result will record
as compensation expense the fair value of all stock options issued subsequent to
January 1, 2003. We do not expect the adoption of the provisions of SFAS No. 123
to have a material impact on our financial position, results of operations or
cash flows.

NEW ACCOUNTING PRONOUNCEMENTS

     SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and
Intangible Assets," became effective on July 1, 2001 and January 1, 2002,
respectively. These new standards emphasize a more precise evaluation of assets
and clarify that more assets should be distinguished and classified between
tangible and intangible. We understand that the issue is under evaluation as to
whether provisions of SFAS No. 141 and SFAS No. 142 may call for mineral rights
held under lease or other contractual arrangements to be classified in the
balance sheet as intangible assets together with cash costs of oil and gas
leasehold interests acquired. The issue is under review, because it is believed
that no oil and gas exploration and production company was known to have changed
their tangible asset balance sheet classification of mineral rights or leasehold
costs upon adopting of SFAS Nos. 141 and 142, including us. If these types of
leasehold costs (both proved and unevaluated) are determined to be intangible
assets, they would be classified separately from oil and natural gas properties
as intangible assets on our balance sheets. This issue relates only to balance
sheet classification and presentation and will not have an effect on cash flows
or results of operations. For the years ended December 31, 2002 and 2001, $161.0
million and $81.9 million, respectively, would be reclassified from tangibles to
intangibles representing costs incurred, net of accumulated amortization, since
June 30, 2001, the effective date of SFAS No. 141. We will continue to classify
our oil and gas leasehold costs as tangible oil and natural gas properties until
further guidance is provided.

     SFAS No. 143, "Accounting for Asset Retirement Obligations," addresses
accounting and reporting for obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement costs. SFAS No.
143 takes effect January 1, 2003. SFAS No. 143 requires that the fair value of a
liability for an asset's retirement obligation be recorded in the period in
which it is incurred and the corresponding cost capitalized by increasing the
carrying amount of the related long-lived asset. The liability is accreted to
its then present value each period, and the capitalized cost is depreciated over
the useful life of the related asset. If the liability is settled for an amount
other than the recorded amount, a gain or loss is recognized. For all periods
presented, we have included estimated future costs of abandonment and
dismantlement in our full cost amortization base and amortize these costs as a
component of our depletion expense.

     We have completed our assessment of SFAS No. 143. At December 31, 2002, we
estimate that the present value of our future Asset Retirement Obligation
("ARO") for natural gas and oil property and related equipment is approximately
$57 million. We estimate that the cumulative effect of our adoption of SFAS No.
143 and the change in the accounting principle will be a charge to net income
during the first quarter of 2003 of $4.3 million, $2.8 million net of taxes.

     In April 2002 the Financial Accounting Standards Board ("FASB") issued SFAS
No. 145, "Rescission of FASB Statements No. 4, No. 44, and No. 64, Amendment to
FASB Statement No. 13 and Technical Corrections." SFAS No. 145 streamlines the
reporting of debt extinguishments and requires that only gains and losses from
extinguishments meeting the criteria in Accounting Policies Board Opinion 30
would be classified as extraordinary. Thus, gains or losses arising from
extinguishments that are part of a company's recurring operations would not be
reported as an extraordinary item. SFAS No. 145 is effective for fiscal years
beginning after May 15, 2002. At this time, we do not expect the adoption of
SFAS No. 145 to have a material impact on our financial position, results of
operations or cash flows.

     SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal
Activities" was issued in September 2002 and addresses accounting and reporting
for costs associated with exit or disposal activities and nullifies Emerging
Issues Task



                                      -23-
<PAGE>

Force ("EITF") Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring)." SFAS No. 146 requires that a liability for
a cost associated with an exit or disposal activity be recognized when the
liability is incurred. Under Issue 94-3, a liability for an exit cost was
recognized at the date of an entity's commitment to an exit plan. Under SFAS No
146, fair value is the objective for initial measurement of the liability. SFAS
No. 146 is effective for exit or disposal activities that are initiated after
December 31, 2002. At this time, we do not expect the adoption of SFAS No. 146
to have a material impact on our financial position, results of operations or
cash flows.

     SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and
Disclosure" was issued in December 2002 and the transition guidance and annual
disclosure provisions are effective for us for the year ended December 31, 2002.
SFAS No. 148 amends SFAS Statement No. 123, "Accounting for Stock Based
Compensation" and provides alternative methods of transition for a voluntary
change to the fair value method of accounting for stock-based employee
compensation. In addition, the statement amends the disclosure requirements of
SFAS No. 123 to require prominent disclosures in both annual and interim
financial statements about the method of accounting for stock-based compensation
and the effect of the method used. We adopted SFAS No. 148 for 2002 and on
January 1, 2003, we adopted the fair value expense recognition provisions of
SFAS No. 123 on a prospective basis and as a result, we will record as
compensation expense the fair value of all stock options issued subsequent to
January 1, 2003.

ACQUISITIONS

     KeySpan Joint Venture Assets. On October 11, 2002, we purchased from
KeySpan a portion of the assets developed under the joint exploration agreement
with KeySpan Exploration & Production, LLC, a subsidiary of KeySpan. The
acquisition consisted of interests averaging between 11.25% and 45% in 17 wells
covering eight of the twelve blocks that were developed under the joint
exploration agreement from 1999 through 2002. The interests purchased were in
the following blocks: Vermilion 408, East Cameron 81 and 84, High Island 115,
Galveston Island 190 and 389, Matagorda Island 704 and North Padre Island 883.
KeySpan has retained its 45% interest in four blocks: South Timbalier 314 and
317 and Mustang Island 725 and 726, as these blocks are in various stages of
development. KeySpan has committed to continued participation in the ongoing
development of these blocks including the completion of the platform and
production facilities at South Timbalier 314/317 together with possible further
developmental drilling at both South Timbalier 314/317 and Mustang Island
725/726. As of September 1, 2002, the effective date of the purchase, the
estimated proved reserves associated with the interests acquired were 13.5 Bcfe.
The $26.5 million purchase price was paid in cash and financed with borrowings
under our revolving credit facility. Subsequent purchase price adjustments
reduced the purchase price by a total of $1.2 million. The purchase price was
adjusted for various closing items in the normal course of business, including
revenues received by and expenditures made by the seller related to the
properties acquired for the period between the effective date of the transaction
(September 1, 2002) and the closing date (October 11, 2002). Our acquisition of
the properties was accounted for as a transaction between entities under common
control. As a result, the excess fair value of the properties acquired of $3.1
million ($2.0 million net of tax) was treated as a capital contribution from
KeySpan and recorded as an increase to additional paid-in capital during the
fourth quarter of 2002.

     Our Board of Directors appointed a special committee, comprised entirely of
independent directors to review the proposed transaction with KeySpan. In
addition, the special committee discussed the history and terms of the
transaction with our senior management. After completing its review, the special
committee unanimously concluded that the transaction was advisable and in our
best interests and that the terms of the transaction were at least as favorable
to us as terms that would have been obtainable at the time in a comparable
transaction with an unaffiliated party.

     Burlington Acquisition. On May 30, 2002, we completed the purchase of
natural gas and oil producing properties, together with undeveloped acreage,
from Burlington Resources Inc. located in the Webb and Jim Hogg Counties of
South Texas. The properties purchased cover approximately 24,800 gross (10,800
net) acres located in the North East Thompsonville and South Laredo Fields. The
properties purchased represent interests in approximately 123 producing wells
and total proved reserves of 37 Bcfe as of January 1, 2002, the effective date
of the transaction. The North East Thompsonville Field has 10 wells producing
from the Wilcox formation, all of which we operate. This field represents
approximately 70% of the proved reserves and 75% of the current production
associated with the acquisition. The South Laredo Field, located in Webb County
and in the Lobo Trend, contains 113 wells, all operated by a third party. The
$39.5 million purchase price, which was reduced by a purchase price adjustment
of $3.9 million and proceeds of $5.0 million received from the subsequent sale
of a portion of the assets acquired, was financed by borrowings under our
revolving bank credit facility. The purchase price was adjusted for various
closing items in the normal course of business, including revenues received by
and expenditures made by the seller related to the properties acquired for the
period between the effective date of the transaction (January 1, 2002) and the
closing date (May 30, 2002).




                                      -24-
<PAGE>

     Conoco Acquisition. On December 31, 2001, we completed the purchase from
Conoco Inc. of natural gas and oil properties and associated gathering pipelines
and equipment, together with developed and undeveloped acreage, located in the
Webb and Zapata Counties of South Texas. The $69 million cash purchase price was
financed by borrowings under our revolving bank credit facility. The properties
purchased cover approximately 25,274 gross (16,885 net) acres located in the
Alexander, Haynes, Hubbard and South Trevino Fields, which are in close
proximity to our existing operations in the Charco Field, and represent
interests in approximately 159 producing wells. We operate approximately 95% of
the producing wells we acquired. Our average working interest is 87%. Total
proved reserves associated with the interests acquired were 85 Bcfe, as of the
October 1, 2001, the effective date of the transaction.


                                      -25-
<PAGE>


OTHER RECENT DEVELOPMENTS

     Joint Offshore Exploration Program. Effective September 1, 2002, we entered
into a joint offshore exploration agreement with El Paso Production Oil & Gas
USA, L.P., a subsidiary of El Paso Corporation. Under the terms of the
agreement, El Paso contributed approximately $50 million for land, seismic and
drilling costs in exchange for 50% of our working interest in six specified
prospects that we developed. El Paso pays 100% of the drilling costs to casing
point or 100% of the "dry hole costs", except for the High Island 115 prospect
for which we have an obligation of $5 million for dry hole costs. El Paso is the
operator of four of the wells and we are operator of the remaining two. Under
the terms of the agreement, El Paso has the option to extend the exploration
agreement beyond the initial six well program. The option expires in August
2003. As of the date of this report, four wells in the program have been
drilled. Two resulted in discoveries and have been successfully completed and
placed on-line. One well has been completed and is currently testing and the
fourth well has been temporarily abandoned and is being evaluated for further
completion. The fifth well in the program, High Island 115, is currently
drilling to a target depth of 21,000 feet. The sixth well in the program is
currently planned for the second quarter of 2003. El Paso will operate this well
and if they elect not to drill the final well, all interests in the prospect
will revert back to us.

     Severance Tax Refund. During July 2002, we applied for and received from
the Railroad Commission of Texas a "high-cost/tight-gas formation" designation
for a portion of our South Texas production. The "high-cost/tight-gas formation"
designation will allow us to receive an abatement of severance taxes for
qualifying wells in various fields. For qualifying wells, production will be
either exempt from tax or taxed at a reduced rate until certain capital costs
are recovered. For qualifying wells, we will also be entitled to a refund of
severance taxes paid during a designated prior 48-month period. Applications for
refund are submitted on a well-by-well basis to the State Comptroller's Office
and due to timing of the acceptance of applications, we are unable to project
the 48-month look-back period for qualifying refunds. We currently estimate that
the total refund, for 2002 and prior periods, will be between $18 million to $23
million ($12 million to $15 million, net of tax), although we can provide no
assurances that the actual total refund amount will fall within our current
estimate. During the fourth quarter of 2002, we recorded refunds totaling $10.4
million ($6.8 million net of tax) of which $1.3 million related to refund of
2002 severance tax expense and $9.1 related to refunds of prior period expense.




                                      -26-
<PAGE>


RESULTS OF OPERATIONS

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

<Table>
<Caption>
                                                                                      YEARS ENDED DECEMBER 31,
                                                                              ------------------------------------------
                                                                                  2002           2001           2000
                                                                              ------------   ------------   ------------
<S>                                                                           <C>            <C>            <C>
SUMMARY OPERATING INFORMATION:
Operating revenues ........................................................   $    345,381   $    388,509   $    279,225
Operating expenses ........................................................        237,467        195,994        138,369
Income from operations ....................................................        107,914        192,515        140,856
Net income ................................................................   $     70,494   $    122,601        140,856

PRODUCTION:
Natural gas (MMcf) ........................................................         97,368         87,095         77,861
Oil (MBbls) ...............................................................            859            459            311
Total (MMcfe) .............................................................        102,522         89,849         79,727
Average daily production (MMcfe/day) ......................................            281            246            218
AVERAGE SALES PRICES:
Natural gas (per Mcf) realized (1) ........................................   $       3.32   $       4.32   $       3.46
Natural Gas (per Mcf) unhedged ............................................           3.16           4.18           4.05
Oil (per Bbl) .............................................................          23.99          22.83          27.22

OPERATING EXPENSES (PER MCFE):
Lease operating expense ...................................................   $       0.33   $       0.28   $       0.30
Severance tax .............................................................           0.09           0.12           0.12
Transportation expense ....................................................           0.09           0.09           0.09
Depreciation, depletion and amortization ..................................           1.67           1.43           1.12
Writedown in carrying value of natural gas and oil properties .............             --           0.07             --
General and administrative, net ...........................................           0.13           0.19           0.11
</Table>


----------
(1) Average realized prices include the effect of hedges.

RECENT FINANCIAL AND OPERATING RESULTS

Comparison of Years Ended December 31, 2002 and 2001

     Production. Our production increased 14% from 89,849 million cubic feet
equivalent, or MMcfe, for the year ended December 31, 2001 to 102,522 MMcfe for
the year ended December 31, 2002. The increase in production was primarily
attributable to production added from properties acquired in South Texas since
December 31, 2001 together with newly developed production generated from our
subsequent development and workover programs initiated on these acquired
properties during 2002. During 2002, we successfully drilled and completed a
total of 84 new wells, consisting of 75 onshore wells and 9 offshore wells. Of
the 75 wells drilled onshore, 54 were drilled in South Texas, of which 27 were
drilled on our newly acquired acreage with the balance being drilled in our
Charco Field.

     Onshore, our daily production rates increased 32% from an average of 117
MMcfe/day during 2001 to an average of 155 MMcfe/day during 2002. Properties
acquired from Conoco Inc. on December 31, 2001 accounted for 33 MMcfe/day of the
increase for 2002 and properties acquired from Burlington Resources on May 30,
2002 accounted for 7 MMcfe/day of the increase for 2002. Production from our
Charco Field in South Texas averaged 83 MMcfe/day during the current year and
remained unchanged from 2001 rates. Production from all other onshore areas
(Arkoma, East Texas, West Virginia and South Louisiana) decreased 2 MMcfe/day or
approximately 6% from an average of 34 MMcfe/day during 2001 to 32 MMcfe/day
during 2002 primarily a result of a decrease in production in South Louisiana
due principally to natural reservoir decline.




                                      -27-
<PAGE>

     Offshore, our production decreased 2% from an average of 129 MMcfe/day
during 2001 to an average of 126 MMcfe/day during 2002. During January 2002, we
initiated production from our newly completed facilities at Vermilion 408. We
added new facilities and a series of new wells throughout 2002 at East Cameron
81, 82 and 83. During September and October 2002 we evacuated and shut-in
offshore platforms and facilities due to Tropical Storms Faye and Isidore and
Hurricane Lili. We estimate that we shut-in approximately 750 MMcfe or 2
MMcfe/day on an annualized basis. In October 2002, we acquired from KeySpan
incremental working interests in 17 offshore wells that were initially developed
under a joint exploration agreement with KeySpan (see Note 6 - Related Party
Transactions - KeySpan Joint Venture) from 1999 through 2002. Overall, for the
year 2002, increments in production growth resulting from our acquisition and
our new exploration and development projects was offset by natural production
declines in existing properties.

     Natural Gas and Oil Revenues. Natural gas and oil revenues decreased 11%
from $387.2 million for year ended December 31, 2001 to $344.3 million for the
year ended 2002 as a result of a 24% decrease in average realized natural gas
prices, from $4.32 per Mcf during 2001 to $3.32 per Mcf in 2002, offset in part
by a 14% increase in production for the same period.

     Natural Gas Prices. As a result of hedging activities, we realized an
average gas price of $3.32 per Mcf for the year ended 2002, which was 105% of
the average unhedged natural gas price of $3.16 that we otherwise would have
received, resulting in natural gas and oil revenues for 2002 that were $16.4
million higher than the revenues we would have achieved if hedges had not been
in place during the year. For the corresponding period during 2001, we realized
an average gas price of $4.32 per Mcf, which was 103% of the average unhedged
natural gas price of $4.18 that otherwise would have been received, resulting in
natural gas and oil revenues that were $12.9 million higher than the revenues we
would have achieved if hedges had not been in place during the period.

     Lease Operating Expense. Lease operating expenses increased 34% from $25.3
million in 2001 to $34.0 million in 2002. On an Mcfe basis, lease operating
expenses increased 18% from $0.28 per Mcfe during 2001 to $0.33 per Mcfe during
2002. The increase in both lease operating expenses and lease operating expenses
per unit is attributable to the continued expansion of our operations onshore
and offshore combined with an increase in expenses during 2002. Onshore
operations expanded with the acquisition of approximately 304 new producing
wells in South Texas from the December 31, 2001 acquisition from Conoco Inc. and
the May 30, 2002 acquisition from Burlington Resources. Excluding the
incremental expenses relating to newly acquired properties, the increase in our
onshore lease operating expenses is due primarily to increased ad valorem taxes
and increased compression expenses. Ad valorem taxes increased as a result of
the high natural gas prices experienced in 2001. Compression expenses increased
during the second half of 2002 as we implemented a project in the Charco Field
to boost production by adding compressors to streamline and lower gathering
system pressure. Offshore, our lease operating expenses increased due to the
addition of production facilities at Vermilion 408 and East Cameron 81, new
processing fees attributable to oil production at Vermilion 408 where we have
chosen to have a third party process our oil rather than constructing our own
oil facilities, the implementation of compression projects to enhance production
capabilities at several of our existing facilities and finally, an increase in
well control insurance premiums during the current year.

     Severance Tax. Severance tax, which is a function of volume and revenues
generated from onshore production, decreased 14% from $11.0 million during 2001
to $9.5 million during 2002. On an Mcfe basis, severance tax decreased from
$0.12 per Mcfe during 2001 to $0.09 per Mcfe during 2002. The decrease in
severance tax expense is primarily due to $1.3 million recorded during the
fourth quarter of 2002 related to refunds of expense incurred during the current
year. In July 2002, we applied for and received from the Railroad Commission of
Texas a "high-cost/tight-gas formation" designation for a portion of our South
Texas production (see Note 9 - Commitments and Contingencies - Severance Tax
Refund). In addition to the $1.3 million recorded as a reduction to current year
severance tax expense, we recorded as "other non-operating income" $9.1 million
for refunds relating to prior periods. Excluding the effect for the $1.3
million, severance tax would have been $10.8 million and $0.11 per Mcfe during
2002 compared to $11.0 million and $0.12 per Mcfe for 2001. Expense is
comparable because wellhead prices were 25% lower during 2002 as compared to
wellhead prices received during 2001; however, our onshore production increased
by 32% during 2002 which accounts for the decrease in the adjusted severance tax
on a per unit basis.

     Transportation Expense. We applied Emerging Issues Task Force ("EITF") No.
00-10 "Accounting for Shipping and Handling Fees and Costs" for all periods
presented. Pursuant to our application of EITF No. 00-10, transportation
expenses previously reflected as a reduction of natural gas and oil revenues
were added back to the related revenues and reclassified as a separate component
of operating expense. For the year ended December 31, 2001, natural gas and oil
revenues, total revenues, transportation expense and total operating expenses
were restated. The application of EITF No. 00-10 had no effect on operating
income or net income. See Note 11 - Restatement and Reclassification Made to
Consolidated Statements of Operations for Transportation Expense.




                                      -28-
<PAGE>

     Transportation expense for 2002 increased 21% from $7.7 million and $0.09
per Mcfe during 2001 to $9.3 million and $0.09 per Mcfe during 2002. The
increase in expense is due primarily to the 32% increase in our onshore
production volume during 2002 as compared to 2001.

     Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased 33% from $128.7 million during 2001 to $171.6
million for the year of 2002. Depreciation, depletion and amortization expense
per Mcfe increased 17% from $1.43 during 2001 to $1.67 during 2002. The increase
in depreciation, depletion and amortization expense was a result of higher
production volumes combined with a higher depletion rate. Our depletion rate has
increased during 2002 as we completed the evaluation of several properties that
were classified as unproved at December 31, 2001. As evaluation is completed,
the costs associated with these properties were reclassified into our
amortization base. The higher depletion rate is a result of a combination of
adding costs to the full cost pool with fewer new reserves being added from
exploration and developmental drilling together with an overall increase in our
finding and development costs. We believe that higher finding costs are being
experienced across the industry, particularly for companies our size whose
primary area of exploration is the Outer Continental Shelf or the shallow waters
of the Gulf of Mexico. Because the Outer Continental Shelf is a mature producing
area, it is becoming increasingly more difficult to find and develop new
reserves at historical costs.

     General and Administrative Expenses, Net of Capitalized General and
Administrative Expenses and Overhead Reimbursements. General and administrative
expenses, net of overhead reimbursements received from other working interest
owners of $1.2 million and $1.8 million during 2001 and 2002, respectively, and
capitalized general and administrative expenses directly related to oil and gas
exploration and development activities of $12.8 million and $13.2 million,
respectively, for 2001 and 2002, decreased 23% from $17.1 million during 2001 to
$13.1 million during 2002. Aggregate general and administrative expenses
decreased 10% from $31.2 million during 2001 to $28.1 million during 2002.
Included in aggregate and net administrative expenses during 2001 were payments
totaling $5.2 million made in connection with the termination of former
executive officers' employment contracts.

     Excluding the one-time charges during 2001 for the termination of
employment contracts, aggregate general and administrative expenses would have
been $26.0 million in 2001 compared to $28.1 million for 2002, an 8% increase
for the current year. The increase in expenses for 2002 is due to the overall
expansion of our business, our workforce and our office space. Payroll and
employee benefits, rent and utilities and legal, accounting and consulting
expenses have all increased during 2002. Excluding the effect of the one-time
charges during 2001, net general and administrative expenses reflects a
corresponding increase of 10% from $11.9 million during 2001 to $13.1 million
during 2002. The increase in overhead reimbursements during 2002 is due to an
increase in the number of producing properties that we operate that have third
party working interests. Capitalized general and administrative expenses
increased slightly by 3% during 2002 as compared to 2001 as we capitalized
approximately the same percentage of general and administrative expenses during
both 2001 and 2002.

     On an Mcfe basis, net general and administrative expenses decreased 32%
from $0.19 per Mcfe during 2001 to $0.13 per Mcfe during 2002. Excluding the
effect of the one-time charges taken in year of 2001 for the termination of
employment contracts totaling $5.2 million, net general and administrative
expenses on a per Mcfe basis would have remained unchanged at approximately
$0.13 per Mcfe for both 2001 and 2002 with an increase in expense offset by an
increase in production.

     Other Income and Expense. For the year ended 2002, we recorded other income
of $9.1 million relating to refund of severance tax paid in prior periods and
recorded pursuant to our receipt of a "high-cost/tight sand" designation for a
portion of our South Texas production (see Note 9 - Commitments and
Contingencies - Severance Tax Refund). During the year of 2001, we incurred an
additional $0.1 million in expenses relating to a strategic review initiated in
the fourth quarter of 1999 and completed in the first quarter of 2000. In
September 1999, together with KeySpan, our majority stockholder, we had
announced our intention to review strategic alternatives for our company and
KeySpan's investment in our company. Consideration was given to a full range of
strategic transactions including the possible sale of all or a portion of our
assets. On February 25, 2000, we announced, together with KeySpan, that the
review of strategic alternatives for Houston Exploration had been completed.

     Interest Expense, Net of Capitalized Interest. Interest expense, net of
capitalized interest, increased 147% from $3.0 million during 2001 to $7.4
million for 2002. Aggregate interest expense increased by 3% from $15.0 during
2001 to $15.4 million during 2002. The increase in aggregate interest is due to
a decrease in interest rates from an average borrowing rate of 7.43% during 2001
to an average borrowing rate of 5.38% during 2002 offset by an increase in our
average borrowings from $190.9 million during 2001 to an average of $263.6
million for 2002. Capitalized interest decreased 33% from $12.0 million for 2001
to $8.0 million for 2002 and corresponds to the decrease in aggregate interest
expense combined with a




                                      -29-
<PAGE>

decrease in exploratory drilling during 2002. Our capitalized interest is a
function of exploratory drilling and unevaluated properties, both of which were
at lower levels during 2002.

     Income Tax Provision. The provision for income taxes decreased 41% from
$66.8 million for 2001 to $39.1 million for 2002 due to the 42% decrease in
pre-tax income during 2002 from $189.4 million during 2001 to $109.6 million
during 2002 as a result of the combination of a decrease in natural gas revenues
and increases in both operating expenses and net interest expense.

     Operating Income and Net Income. Operating income decreased 44% from $192.5
million during 2001 to $107.9 million during 2002 as a result of a decrease in
revenues caused by a 23% decrease in realized natural gas prices offset only in
part by the 14% increase in production combined with a 21% increase in operating
expenses. Corresponding to the decrease in operating income, net income
decreased 42% from $122.6 million during 2001 to $70.5 million during 2002 and
includes the effects of higher interest expense and lower taxes.

COMPARISON OF THE YEARS ENDED DECEMBER 31, 2001 AND 2000

     Production. Our production increased 13% from 79,727 MMcfe for the year
ended December 31, 2000 to 89,849 MMcfe for the year ended December 31, 2001.
The increase in production was primarily attributable to newly developed
offshore production brought on-line since the end of the second quarter of 2000.

     Offshore, our production increased 30% from an average of 99 MMcfe/day
during 2000 to an average of 129 MMcfe/day during 2001. This increase is
primarily attributable to a full year of production at West Cameron 587, North
Padre Island 883, Matagorda 704 and High Island 133/115 combined with newly
developed production at Galveston Island 144, 190, 241 and 389, High Island 39
and East Cameron 83.

     Onshore, our daily production rates decreased slightly by 2% from an
average of 119 MMcfe/day during 2000 to an average of 117 MMcfe/day during 2001.
The onshore production decrease is primarily attributable to a decline in
production from our South Louisiana properties from an average of 11 MMcfe/day
during 2000 to an average of 8 MMcfe/day during 2001 due primarily to natural
reservoir decline. Average daily production from our Charco Field together with
production from our Arkoma, East Texas and West Virginia properties remained
unchanged at an average of 83 MMcfe/day and 26 MMcfe/day, respectively.

     Natural Gas and Oil Revenues. Natural gas and oil revenues increased 40%
from $277.5 million for the year ended December 31, 2000 to $387.2 million for
the year ended December 31, 2001 as a result of a 26% increase in average
realized natural gas prices, from $3.46 per Mcf in 2000 to $4.32 per Mcf in
2001, combined with a 13% increase in production for the same period.

     Natural Gas Prices. As a result of hedging activities, we realized an
average gas price of $4.32 per Mcf for the year ended December 31, 2001, which
was 103% of the average unhedged natural gas price of $4.18 that we otherwise
would have been received, resulting in natural gas and oil revenues for the year
ended December 31, 2001 that were $12.9 million higher than the revenues we
would have achieved if hedges had not been in place during the period. For the
corresponding period during 2000, we realized an average gas price of $3.46 per
Mcf, which was 85% of the average unhedged natural gas price of $4.05 that
otherwise would have been received, resulting in natural gas and oil revenues
that were $46.3 million lower than the revenues we would have achieved if hedges
had not been in place during the period.

     Lease Operating Expenses and Severance Tax. Lease operating expenses
increased 7% from $23.6 million for the year ended December 31, 2000 to $25.3
million for the year ended December 31, 2001. On an Mcfe basis, lease operating
expenses decreased from $0.30 per Mcfe during 2000 to $0.28 per Mcfe during
2001. The increase in lease operating expenses for 2001 is attributable to the
continued expansion of our operations, primarily from the addition of four new
offshore producing blocks during 2001 combined with a full year of operations
from another four blocks brought on-line during the second half of 2000. We saw
service costs increase during the first half 2001 and stabilize during the later
half of the year which corresponded directly with the weakening of commodity
prices and a slowdown in drilling activity across the industry. The decrease in
lease operating expenses per Mcfe reflects the 13% increase in production volume
during 2001 due primarily to newly developed offshore production. Severance tax,
which is a function of volume and revenues generated from onshore production,
increased from $9.8 million for the year ended December 31, 2000 to $11.0
million for the year ended December 31, 2001. On an Mcfe basis, severance tax
remained unchanged at $0.12 per Mcfe for each of the years ended December 31,
2000 and 2001. The increase in severance tax expense reflects higher natural gas
prices received during 2001 combined with newly developed offshore production
located in state waters brought on-line during the year.




                                      -30-
<PAGE>

     Transportation Expense. We applied Emerging Issues Task Force ("EITF") No.
00-10 "Accounting for Shipping and Handling Fees and Costs" for all periods
presented. Pursuant to our application of EITF No. 00-10, transportation expense
previously reflected as a reduction of natural gas and oil revenues were added
back to the related revenues and reclassified as a separate component of
operating expense. For the years ended December 31, 2001 and 2000, natural gas
and oil revenues, total revenues, transportation expense and total operating
expenses were restated and reclassified, respectively. The application of EITF
No. 00-10 had no effect on operating income or net income. See Note 11 -
Restatement and Reclassification made to Consolidated Statements of Operations
for Transportation Expense. Transportation expense increased 12% from $6.9
million and $0.09 per Mcfe in 2000 to $7.7 million and $0.09 per Mcfe during
2001. The increase in expense corresponds to the 13% increase in total
production for 2001.

     Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased 44% from $89.2 million for the year ended
December 31, 2000 to $128.7 million for the year ended December 31, 2001.
Depreciation, depletion and amortization expense per Mcfe increased 28% from
$1.12 during 2000 to $1.43 during 2001. The increase in depreciation, depletion
and amortization expense was a result of higher production volumes combined with
a higher depletion rate. The higher depletion rate is primarily a result of a
higher level of capital spending during 2001 as compared to 2000 combined with
the addition of fewer new reserves in 2001 from exploration and developmental
drilling.

     Writedown in Carrying Value of Natural Gas and Oil Properties. At December
31, 2001, we were required under full cost accounting rules to write down the
carrying value of our full cost pool primarily as a result of weak natural gas
prices. In calculating the ceiling test, we estimated, using a December 31, 2001
wellhead price of $2.38 per Mcf, that our capitalized costs exceeded the ceiling
limitation by $6.2 million and accordingly we recorded a writedown of our full
cost pool and a charge to earnings during the fourth quarter of $4.0 million,
net of tax.

     General and Administrative Expenses. General and administrative expenses,
net of overhead reimbursements received from other working interest owners, of
$3.6 million and $1.2 million for the years ended December 31, 2000 and 2001,
respectively, increased 92% from $8.9 million for the year ended December 31,
2000 to $17.1 million for the year ended December 31, 2001. Included in
reimbursements received from working interest owners were reimbursements
totaling $2.5 million during 2000 received from KeySpan pursuant to our joint
drilling venture with KeySpan (see Note 6 -- Related Party Transactions).
Overhead reimbursements were terminated December 31, 2000 with the expiration of
the initial exploratory term of our joint drilling venture with KeySpan, and as
a result we no longer receive reimbursement of general and administrative
expenses from KeySpan. We capitalized general and administrative expenses
directly related to oil and gas exploration and development activities of $9.6
million and $12.8 million, respectively, for the years ended December 31, 2000
and 2001. The increase in capitalized general and administrative expenses is a
result of higher aggregate general and administrative expenses during 2001.
Aggregate general and administrative expenses were higher during 2001 as a
result of: (i) one-time payments totaling $5.2 million in connection with the
termination of former executive officers' employment contracts; (ii) expansion
of our workforce; and (iii) an increase in incentive compensation and benefit
related expenses.

     On an Mcfe basis, general and administrative expenses increased 73% from
$0.11 during 2000 to $0.19 during 2001. Excluding the one-time charges taken for
the termination of employment contracts totaling $5.2 million, general and
administrative expenses on a per Mcfe basis would have increased 18% from $0.11
for 2000 to $0.13 for 2001. The higher rate per Mcfe during 2001 reflects the
increase in aggregate general and administrative expenses caused by the effects
of the termination of reimbursements received pursuant to our joint drilling
venture with KeySpan which totaled $2.5 million during 2000 combined with the
expansion of the Company's workforce and higher incentive compensation and
benefit related expenses.

     Interest Expense, Net. Interest expense, net of capitalized interest,
decreased 74% from $11.4 million for the year ended December 31, 2000 to $3.0
million for the year ended December 31, 2001. Aggregate interest expense
decreased 40% from $25.1 during 2000 to $15.0 million during 2001. The decrease
in aggregate interest is due to a decrease in interest rates combined with (i)
the repayment of $85 million in borrowings under the revolving bank credit
facility during the first nine months of 2001; and (ii) the March 31, 2000
conversion of $80 million in outstanding borrowings under a revolving credit
facility with KeySpan into 5,085,177 shares of our common stock (see Note 3 --
Stockholders' Equity - KeySpan Credit Facility and Conversion). Capitalized
interest decreased 12% from $13.7 million during 2000 to $12.0 million during
2001 and reflects the decrease in aggregate interest expense offset in part by a
higher level of exploratory drilling during 2001 Our capitalized interest is a
function of exploratory drilling and unevaluated properties. Interest rates on
our total outstanding borrowings averaged 7.43% during 2001 compared to 8.07% in
2000.

     Income Tax Provision. The provision for income taxes increased from $42.5
million for the year ended December 31, 2000 to $66.8 million for the year ended
December 31, 2001 due to the 48% increase in pre-tax income during 2001 from



                                      -31-
<PAGE>

$127.7 million during 2000 to $189.4 million during 2001 as a result of the
combination of higher natural gas prices, an increase in production, a decrease
in interest expense offset in part by an increase in operating expenses.

     Operating Income and Net Income. For the year ended December 31, 2001, the
26% increase in natural gas prices combined with the 13% increase in production,
offset in part by a 43% increase in operating expenses, caused operating income
to increase 37% from $140.9 million during 2000 to $192.5 million during 2001.
Correspondingly, net income increased 44% from $85.3 million for 2000 to $122.6
million for 2001 and reflects lower interest expense and higher taxes.



                                      -32-
<PAGE>


LIQUIDITY AND CAPITAL RESOURCES

     We currently fund our operations, acquisitions, capital expenditures and
working capital requirements from cash flows from operations, public debt and
bank borrowings. We believe cash flows from operations and borrowings under our
revolving bank credit facility will be sufficient to fund our planned capital
expenditures and operating expenses during 2003.

     Cash Flows. As of December 31, 2002, we had a working capital deficit of
$1.7 million and $147.6 million of borrowing capacity available under our
revolving bank credit facility. The working capital deficit is due to the
classification as a current liability of $35.0 million relating to the current
portion of the fair market value of our derivative instruments. Net cash
provided by operating activities for 2002 was $243.9 million compared to $358.0
million during 2001. The decrease in net cash provided by operating activities
was due to (i) a decrease in 2002 net income caused primarily by lower realized
natural gas prices, offset in part by an increase in production volumes during
the current year combined with (ii) a net increase in current assets and current
liabilities at year end 2002 which is related to the timing of cash receipts and
payments. For 2002, the increase in current assets was caused primarily by an
increase in receivables at the end of 2002 due to higher gas prices and
production volumes for the fourth quarter of 2002 as compared to the
corresponding period of 2001. Current liabilities (excluding the fair value of
derivatives which is a non-cash item) increased due to a higher level of
drilling activity in the fourth quarter of 2002 as compared to the fourth
quarter of 2001. For the year of 2002, funds used in investing activities
consisted of $252.1 million for net cash investments in property and equipment,
which compares to $368.3 million spent during 2001. Our cash position increased
during 2002 as a result of net borrowings under our revolving bank credit
facility of $8 million compared to repayments totaling $1 million during 2001.
Cash increased by $9.7 million and $10.2 million, respectively, during 2002 and
2001 due to proceeds received from the issuance of common stock from the
exercise of stock options. As a result of these activities, cash and cash
equivalents increased $9.4 million from $8.6 million at December 31, 2001 to
$18.0 million at December 31, 2002.

     Investments in Property and Equipment. During the year of 2002, we invested
$258.4 million in natural gas and oil properties and $2.4 million for other
property and equipment, which includes the expansion of our Houston office space
together with upgrades to our information technology systems and equipment. The
table below summarizes our natural gas and oil expenditures and our average
"all-in" finding and development cost on an equivalent Mcf basis. Leasehold
acquisition costs include among other things, costs incurred for seismic,
capitalized interest and capitalized general and administrative costs. During
2002, 2001, 2000, 1999 and 1998, we capitalized a total of $21.1 million, $24.9
million, $23.3 million, $17.4 million and $17.3 million respectively, in
capitalized interest and general and administrative expenses which amounts are
included in the line item "Leasehold and Lease Acquisition Costs" in the table
below. During 2002 we sold non-core natural gas and oil assets for a total of
$5.3 million, of which $5.0 million related to the sale of the McFarlan and
Maude Traylor Fields purchased in May 2002 as part of the group of properties
acquired from Burlington Resources (see Notes to Consolidated Financial
Statements, Note 10 - Acquisitions - Burlington Acquisition).


<Table>
<Caption>
                                                                              YEARS ENDED DECEMBER 31,
                                                          --------------------------------------------------------------
                                                                       (IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
                                                             2002         2001         2000        1999         1998
                                                          ----------   ----------   ----------   ----------   ----------

<S>                                                       <C>          <C>          <C>          <C>          <C>
Natural gas and oil capital expenditures
  Producing property acquisitions (1) .................   $   68,042   $   69,010   $   13,935   $   21,746   $  165,319
  Leasehold and lease acquisition costs ...............       36,458       48,068       32,599       25,696       30,567
  Development .........................................      122,036      177,256      103,335       87,965       51,046
  Exploration .........................................       26,536       72,056       34,160       12,257       55,611
                                                          ----------   ----------   ----------   ----------   ----------
    Total natural gas and oil capital expenditures ....   $  253,072   $  366,390   $  184,029   $  147,664   $  302,543
                                                          ==========   ==========   ==========   ==========   ==========

Proved reserve additions (MMcfe) ......................      144,291      136,231      100,352      135,791      207,464
Finding and development cost per Mcfe .................   $     1.75   $     2.69   $     1.83   $     1.09   $     1.46
</Table>




----------
(1)  For the year ended December 31, 2002, producing property acquisitions is
     net of dispositions of $5.3 million.





                                      -33-
<PAGE>




     Future Capital Requirements. Our capital expenditure budget for 2003 is
$286 million. This amount includes an estimated $72 million for exploration,
$193 million for development and facility construction and $21 million for
leasehold acquisition costs, which includes seismic, capitalized interest and
general and administrative expenses. We do not include property acquisition
costs in our capital expenditure budget because the size and timing of capital
requirements for acquisitions are inherently unpredictable. The capital
expenditure budget includes exploration and development costs associated with
projects in progress or planned for the upcoming year and amounts are contingent
upon drilling success. No significant abandonment or dismantlement costs are
anticipated in 2003. No assurances can be made that amounts budgeted will equal
actual amounts spent. We will continue to evaluate our capital spending plans
throughout the year. Actual levels of capital expenditures may vary
significantly due to a variety of factors, including drilling results, natural
gas prices, industry conditions and outlook and future acquisitions of
properties. We believe cash flows from operations and borrowings under our
credit facility will be sufficient to fund these expenditures. We intend to
continue to selectively seek acquisition opportunities for proved reserves with
substantial exploration and development potential both offshore and onshore
although we may not be able to identify and make acquisitions of proved reserves
on terms we consider favorable.

Capital Structure

     Revolving Bank Credit Facility. We entered into a new revolving bank credit
facility, dated as of July 15, 2002, with a syndicate of lenders led by Wachovia
Bank, National Association, as issuing bank and administrative agent, The Bank
of Nova Scotia and Fleet National Bank as co-syndication agents and BNP Paribas
as documentation agent. The new credit facility replaced our previous $250
million revolving bank credit facility, and provides us with an initial
commitment of $300 million (for description of our previous revolving bank
credit facility, see Note 2 - Long-term Debt and Notes.) The initial $300
million commitment may be increased at our request and with prior approval from
Wachovia to a maximum of $350 million by adding one or more lenders or by
allowing one or more lenders to increase their commitments. The new credit
facility is subject to borrowing base limitations; and our borrowing base has
been set at $300 million. Our borrowing base will be redetermined semi-annually,
with the next redetermination scheduled for April 1, 2003. Up to $25 million of
the borrowing base is available for the issuance of letters of credit. The new
credit facility matures July 15, 2005, is unsecured and with the exception of
trade payables, ranks senior to all of our existing debt.

     At December 31, 2002, outstanding borrowings under our revolving bank
credit facility were $152 million together with $0.4 million in outstanding
letter of credit obligations. Subsequent to December 31, 2002, we repaid a net
$6 million under the facility. At February 20, 2003, outstanding borrowings and
letter of credit obligations under our revolving bank credit facility totaled
$147.4 million.

     Senior Subordinated Notes. On March 2, 1998, we issued $100 million of 8?%
Senior Subordinated Notes due January 1, 2008. The notes bear interest at a rate
of 8?% per annum with interest payable semi-annually on January 1 and July 1. We
may redeem the notes at our option, in whole or in part, at any time on or after
January 1, 2003 at a price equal to 100% of the principal amount plus accrued
and unpaid interest, if any, plus a specified premium which decreases yearly
from 4.313% in 2003 to 0% in 2006. Upon the occurrence of a change of control,
we will be required to offer to purchase the notes at a purchase price equal to
101% of the aggregate principal amount, plus accrued and unpaid interest, if
any. The notes are general unsecured obligations and rank subordinate in right
of payment to all existing and future senior debt, including the credit
facility, and will rank senior or equal in right of payment to all existing and
future subordinated indebtedness.

Contractual Obligations and Other Commercial Commitments

     The table below summarizes our contractual obligations and commercial
commitments at December 31, 2002. We have no "off-balance sheet" financing
arrangements.

<Table>
<Caption>
                                                          AT DECEMBER 31, 2002
                                           ------------------------------------------------
                                                        PAYMENTS DUE BY PERIOD
                                           ------------------------------------------------
CONTRACTUAL OBLIGATIONS                      1 - 3 YEARS      4 - 5 YEARS     AFTER 5 YEARS
                                           --------------   --------------   --------------
                                                            (IN THOUSANDS)
<S>                                        <C>              <C>              <C>
Revolving bank credit facility .........   $      152,000   $           --   $           --
8 5/8% senior subordinated notes .......               --               --          100,000
Operating leases .......................            3,363            2,331            3,323
Section 29 tax credit repurchase .......            2,000               --               --
                                           --------------   --------------   --------------
Total contractual obligations ..........   $      157,363   $        2,331   $      103,323
                                           ==============   ==============   ==============
</Table>



                                      -34-
<PAGE>


ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

NATURAL GAS AND OIL HEDGING

     We utilize derivative commodity instruments to hedge future sales prices on
a portion of our natural gas and oil production to achieve a more predictable
cash flow, as well as to reduce our exposure to adverse price fluctuations of
natural gas. Our derivatives are not held for trading purposes. While the use of
hedging arrangements limits the downside risk of adverse price movements, it
also limits increases in future revenues as a result of favorable price
movements. The use of hedging transactions also involves the risk that the
counterparties are unable to meet the financial terms of such transactions.
Hedging instruments that we use are swaps, collars and options, which we
generally place with major investment grade financial institutions that we
believe are minimal credit risks. Historically, we have not experienced credit
losses. We believe that our credit risk related to our natural gas futures and
swap contracts is no greater than the risk associated with the primary contracts
and that the elimination of price risk reduces volatility in our reported
results of operations, financial position and cash flows from period to period
and lowers our overall business risk; however, as a result of our hedging
activities we may be exposed to greater credit risk in the future.

     During the fourth quarter of 2002, an increase in forward market prices for
natural gas caused our mark-to-market exposure with one counter party to surpass
our contractual margin threshold as established under the contract. As a result,
we were required to post margin in the amount of $5.4 million. The margin
payment earns interest at a market rate and will be refunded if our
mark-to-market exposure drops below the margin threshold as required under the
contract. This will occur if market prices decline from current levels. At
December 31, 2003, the $5.4 million paid for the margin call is classified as
restricted cash and is included in current assets on the balance sheet in the
line item "Prepayments and Other." Subsequent to December 31, 2002, our margin
was increased by $5.9 million to a balance of $11.3 million at February 20,
2003.

     Our hedges are cash flow hedges and qualify for hedge accounting under SFAS
No. 133 and, accordingly, we carry the fair market value of our derivative
instruments on the balance sheet as either an asset or liability and defer
unrealized gains or losses in accumulated other comprehensive income. Gains and
losses are reclassified from accumulated other comprehensive income to the
income statement as a component of natural gas and oil revenues in the period
the hedged production occurs. If any ineffectiveness occurs, amounts are
recorded directly to other income or expense.

CHANGES IN FAIR VALUE OF DERIVATIVE INSTRUMENTS

     The following table summarizes the change in the fair value of our
derivative instruments for the twelve month period from January 1 to December
31, 2002 and 2001, respectively. Stated amounts do not reflect the effects of
taxes.


<Table>
<Caption>
CHANGE IN FAIR VALUE OF DERIVATIVES INSTRUMENTS                       2002            2001
                                                                  ------------    ------------
                                                                         (IN THOUSANDS)

<S>                                                               <C>             <C>
Fair value of contracts at January 1 ..........................   $     53,771    $    (75,069)
(Gain) loss on contracts realized .............................        (16,358)        (12,926)
Fair value of new contracts when entered into during period ...             --           5,931
(Decrease) increase in fair value of all open contracts .......        (76,185)        135,835
                                                                  ------------    ------------
Fair value of contracts outstanding at December 31 ............   $    (38,772)   $     53,771
                                                                  ============    ============
</Table>





                                      -35-
<PAGE>


DERIVATIVES IN PLACE AS OF THE DATE OF OUR REPORT

      Oil. We entered into an oil swap as described in the following table. All
amounts are in thousands, except for prices. The swap covers the first six
months of 2003 for 1,000 barrels per day with a contract price of $28.50 for
months January through March and $29.70 for months April through June.



<Table>
<Caption>
                            FIXED PRICE SWAPS                       COLLARS
                       ---------------------------   ------------------------------------------
                                         NYMEX                                 NYMEX
                          VOLUME        CONTRACT        VOLUME            CONTRACT PRICE
PERIOD                    (MBbl)         PRICE          (MBbl)       AVG FLOOR      AVG CEILING
                       ------------   ------------   ------------   ------------   ------------

<S>                    <C>            <C>            <C>            <C>            <C>
January 2003 .......             31   $      28.50             --             --             --
February 2003 ......             28          28.50             --             --             --
March 2003 .........             31          28.50             --             --             --
April 2003 .........             30          29.70             --             --             --
May 2003 ...........             31          29.70             --             --             --
June 2003 ..........             30          29.70             --             --             --
</Table>


     Natural Gas. The following table summarizes, on a monthly basis, our hedges
currently in place for 2003 and 2004. All amounts are in thousands, except for
prices. For the first three months of 2003, we have 185,000 MMBtu/day hedged at
an effective floor of $3.428 and an effective ceiling of $4.574. For the
remaining nine months of 2003, we have 190,000 MMBtu/day hedged at an effective
floor of $3.417 and an effective ceiling of $4.548. For each month during 2004,
we have 100,000 MMBtu/day hedged at a floor of $3.750 and a ceiling of $5.045.



<Table>
<Caption>
                            FIXED PRICE SWAPS                        COLLARS
                       ---------------------------   ------------------------------------------
                                          NYMEX                                NYMEX
                          VOLUME        CONTRACT        VOLUME            CONTRACT PRICE
PERIOD                   (MMbtu)         PRICE          (MMbtu)       AVG FLOOR     AVG CEILING
--------------------   ------------   ------------   ------------   ------------   ------------

<S>                    <C>            <C>            <C>            <C>            <C>
January 2003 .......          1,240   $      3.194          4,495   $      3.493   $      4.954
February 2003 ......          1,120          3.194          4,060          3.493          4.954
March 2003 .........          1,240          3.194          4,495          3.493          4.954
April 2003 .........          1,200          3.194          4,500          3.476          4.909
May 2003 ...........          1,240          3.194          4,650          3.476          4.909
June 2003 ..........          1,200          3.194          4,500          3.476          4.909
July 2003 ..........          1,240          3.194          4,650          3.476          4.909
August 2003 ........          1,240          3.194          4,650          3.476          4.909
September 2003 .....          1,200          3.194          4,500          3.476          4.909
October 2003 .......          1,240          3.194          4,650          3.476          4.909
November 2003 ......          1,200          3.194          4,500          3.476          4.909
December 2003 ......          1,200          3.194          4,650          3.476          4.909

January 2004 .......             --             --          3,100          3.750          5.045
February 2004 ......             --             --          2,900          3.750          5.045
March 2004 .........             --             --          3,100          3.750          5.045
April 2004 .........             --             --          3,000          3.750          5.045
May 2004 ...........             --             --          3,100          3.750          5.045
June 2004 ..........             --             --          3,000          3.750          5.045
July 2004 ..........             --             --          3,100          3.750          5.045
August 2004 ........             --             --          3,100          3.750          5.045
September 2004 .....             --             --          3,000          3.750          5.045
October 2004 .......             --             --          3,100          3.750          5.045
November 2004 ......             --             --          3,000          3.750          5.045
December 2004 ......             --             --          3,100          3.750          5.045
</Table>




                                      -36-
<PAGE>

     For natural gas, transactions are settled based upon the New York
Mercantile Exchange or NYMEX price on the final trading day of the month. For
oil, our swaps are settled against the average NYMEX price of oil for the
calendar month rather than the last day of the month. In order to determine fair
market value of our derivative instruments, we obtain mark-to-market quotes from
external counterparties.

     With respect to any particular swap transaction, the counterparty is
required to make a payment to us if the settlement price for any settlement
period is less than the swap price for the transaction, and we are required to
make payment to the counterparty if the settlement price for any settlement
period is greater than the swap price for the transaction. For any particular
collar transaction, the counterparty is required to make a payment to us if the
settlement price for any settlement period is below the floor price for the
transaction, and we are required to make payment to the counterparty if the
settlement price for any settlement period is above the ceiling price for the
transaction. We are not required to make or receive any payment in connection
with a collar transaction if the settlement price is between the floor and the
ceiling. For option contracts, we have the option, but not the obligation, to
buy contracts at the strike price up to the day before the last trading day for
that NYMEX contract.



                                      -37-
<PAGE>


ITEM 8. FINANCIAL STATEMENTS

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

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

     On March 29, 2002, our Board of Directors, upon recommendation of the Audit
Committee, resolved not to renew the engagement of our independent public
accountants, Arthur Andersen LLP and to appoint Deloitte & Touche LLP as
independent public accountants.

     The audit reports of Arthur Andersen on the consolidated financial
statements of our company as of and for the fiscal years ended December 31, 2000
and 2001 did not contain any adverse opinion or disclaimer of opinion, nor were
they qualified or modified as to uncertainty, audit scope or accounting
principles.

     During the two fiscal years ended December 31, 2001, and the subsequent
interim period through March 29, 2002, there were no disagreements with Arthur
Andersen on any matter of accounting principles or practices, financial
statement disclosure, or auditing scope or procedure, which disagreements, if
not resolved to Arthur Andersen's satisfaction, would have caused Arthur
Andersen to make reference to the subject matter of the disagreement in
connection with its reports.

     None of the reportable events described under Item 304(a)(1)(v) of
Regulation S-K occurred within the fiscal years ended December 31, 2001 or
within the interim period through March 29, 2002.

     We provided Andersen with a copy of the above disclosures. A letter dated
April 5, 2002, from Arthur Andersen stating its agreement with our statements
was listed under Item 7 and filed as Exhibit 16.1 and incorporated by reference
into our report on Form 8-K filed March 29, 2002.

     During the two fiscal years ended December 31, 2001 and 2000, and the
subsequent interim period through March 29, 2002, we did not consult with
Deloitte & Touche regarding any of the matters or events set forth in Item
304(a)(2)(i) and (ii) of Regulation S-K.




                                      -38-
<PAGE>


PART III.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

EXECUTIVE OFFICERS

     The names and backgrounds of each of our executive officers are set forth
below.

<Table>
<Caption>
                                                                 WITH US
                   NAME                           AGE             SINCE                                 OFFICE
-------------------------------------------- --------------- ---------------- -----------------------------------------------------
<S>                                          <C>             <C>              <C>
William G. Hargett                                 53             2001        President and Chief Executive
Charles W. Adcock                                  49             1996        Senior Vice President and General Manager -
                                                                                 Offshore Division
John H. Karnes                                     43             2002        Senior Vice President and Chief Financial
                                                                                 Officer
Steven L. Mueller                                  49             2001        Senior Vice President and General Manager -
                                                                                 Onshore Division
Tracy Price                                        44             2001        Senior Vice President - Land
Roger B. Rice                                      58             2002        Vice President - Human Resources and
                                                                                 Administration
Thomas E. Schwartz                                 46             1990        Vice President - Geophysics
James F. Westmoreland                              47             1986        Vice President, Chief Accounting Officer and
                                                                                 Secretary
</Table>

     William G. Hargett was appointed President and Chief Executive Officer and
a Director on April 4, 2001. Immediately prior to joining Houston Exploration
and from September 2000 to March 2001, Mr. Hargett was a private investor. From
May 5, 1999 until August 29, 2000, Mr. Hargett was President-North America of
Santa Fe Snyder Corporation. Prior to that he was President and Chief Operating
Officer and a director of Snyder Oil Corporation. Prior to joining Snyder Oil
Corporation in April of 1997, Mr. Hargett served as President of Greenhill
Petroleum Corporation, the U.S. oil and gas subsidiary of Australian-based
Western Mining Corporation from 1994 to 1997, Amax Oil & Gas, Inc. from 1993 to
1994 and North Central Oil Corporation from 1988 to 1993. Mr. Hargett was
employed in various exploration capacities by Tenneco Oil Corporation from 1974
to 1988 and Amoco Production Company from 1973 to 1974. Mr. Hargett earned a
B.S. and an M.S. from the University of Alabama.

     Charles W. Adcock was appointed Senior Vice President and General Manager -
Offshore Division effective October 1, 2001. From April 2000 to October 2001,
Mr. Adcock served as Senior Vice President - Operations and Engineering. Mr.
Adcock held the position of Vice President--Project Development from September
1996 until April 2000. Mr. Adcock held the same position, Vice
President--Project Development, with Fuel Resources, Inc., a subsidiary of
Brooklyn Union that previously owned our onshore properties, from 1993 to 1996.
Prior to joining Fuel Resources, Inc., 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.

     John H. Karnes was appointed Senior Vice President and Chief Financial
Officer effective November 18, 2002. Immediately prior to joining Houston
Exploration, Mr. Karnes was Vice President and General Counsel for Encore
Acquisition Company of Fort Worth, Texas since January 2002. During 2000 and
2001, Mr. Karnes was Executive Vice President and Chief Financial Officer of
CyberCash, Inc., an internet payment software and services provider. Mr. Karnes
also served as Chief Operating Officer of CyberCash during the break up and sale
of its operating divisions through a pre-packaged Chapter 11 bankruptcy
proceeding in 2001. Mr. Karnes was Vice President and General Counsel of Snyder
Oil Corporation, an independent oil and gas exploration and production company,
during 1998 and 1999. Prior to joining Snyder in 1998, Mr. Karnes was Divisional
President/Corporate Senior Vice President at FIRSTPlus Financial Corporation, a
consumer finance and mortgage company. Mr. Karnes has Juris Doctorate from
Southern Methodist University School of Law and a Bachelor in Business
Administration - Accounting from the University of Texas at Austin.




                                      -39-
<PAGE>

     Steven L. Mueller was appointed to the newly created position of Senior
Vice President and General Manager - Onshore Division effective October 22,
2001. Immediately prior to joining Houston Exploration, Mr. Mueller had been
Senior Vice President - Exploration and Production for Belco Oil and Gas Corp.
Mr. Mueller joined Belco Oil and Gas Corp. in 1996 and held various senior
management positions involving oil and gas exploration. From 1992 to 1996 Mr.
Mueller was Exploitation Vice President for American Exploration Company. From
1988 to 1992, Mr. Mueller was Exploration Manager - South Louisiana for Fina Oil
and Chemical Company. Mr. Mueller began his career with Tenneco Oil Corporation
in 1975 and held various geological and engineering positions with Tenneco from
1975 to 1988. Mr. Mueller received his B.S. in Geological Engineering from the
Colorado School of Mines in 1975.

     Tracy Price was appointed Senior Vice President - Land effective July 16,
2001. Immediately prior to joining Houston Exploration, Mr. Price had been
Manager of Land and Business Development for Newfield Exploration Company since
September 1990. From 1986 to 1990, Mr. Price was Land Manager with Apache
Corporation. Prior to joining Apache Corporation, Mr. Price served as Senior
Landman for Challenger Minerals Inc. from 1983 to 1986 and worked as a landman
for Phillips Petroleum Company from 1981 to 1983. He received his B.B.A. in
Petroleum Land Management from The University of Texas.

     Roger B. Rice was appointed to the newly created position of Vice President
- Human Resources and Administration effective March 1, 2002. Mr. Rice worked as
a paid consultant for Houston Exploration since June 2001. From January 2001 to
June 2001, Mr. Rice was a private management consultant and oil and gas
investor. From December 1999 to December 2000, Mr. Rice was Vice President and
General Manager for Santa Fe Snyder Corporation where he was responsible for all
onshore exploration and production activities in Texas and New Mexico. Mr. Rice
had been Vice President - Human Resources with Snyder Oil Corporation from 1997
until its merger with Santa Fe Resources in 1999. From 1992 to 1997, Mr. Rice
was Vice President Human Resources and Administration with Apache Corporation.
From 1989 to 1992, he was Managing Consultant with Barton Raben, Inc., an
executive search and consulting firm specializing in the energy industry.
Previously, Mr. Rice was Vice President Administration for The Superior Oil
Company and held various management positions with Shell Oil Company. He earned
his B.A. and M.B.A. from Texas Technological University.

     Thomas E. Schwartz has been Vice President - Geophysics since May 1998.
Prior to his appointment to Vice President, Mr. Schwartz was a senior offshore
geophysicist for us from 1990 to 1998. From 1984 until 1990, Mr. Schwartz held
the positions of senior geologist and senior geophysicist for Sonat Exploration
Company. Prior to joining Sonat Exploration Company, he was an explorationist
with Eason Oil Company from 1980 to 1984. Mr. Schwartz received his B.S. in
Geology from the University of New Orleans.

     James F. Westmoreland has been Vice President, Chief Accounting Officer and
Secretary since October 1995 and was Vice President and Comptroller 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.



                                      -40-
<PAGE>


BOARD OF DIRECTORS

The names and principal occupations of each of the members of our Board of
Directors are set for below.



<Table>
<Caption>
                                                           DIRECTOR
                  NAME                        AGE           SINCE                                 OFFICE
------------------------------------------ ----------- ----------------- ---------------------------------------------------------

<S>                                        <C>         <C>               <C>
Robert B. Catell                               66            1986        Chairman of the Board
Gordon F. Ahalt                                75            1996        Director
David G. Elkins                                61            1999        Director
Robert J. Fani                                 49            2002        Director
William G. Hargett                             53            2001        Director
Harold R. Logan, Jr.                           58            2002        Director
Gerald Luterman                                59            2000        Director
H. Neil Nichols                                65            2000        Director
James Q. Riordan                               75            1996        Director
Donald C. Vaughn                               67            1997        Director
</Table>

     Robert B. Catell has been Chairman of the Board of Directors since 1986.
Mr. Catell is the Chairman and Chief Executive Officer of KeySpan Corporation, a
diversified energy provider, and has held this position since July 1998. KeySpan
owns approximately 67% of the shares our common stock. Mr. Catell joined
KeySpan's subsidiary, The Brooklyn Union Gas Company, in 1958 and was elected
Assistant Vice President in 1974, Vice President in 1977, Senior Vice President
in 1981 and Executive Vice President in 1984. Mr. Catell was elected Brooklyn
Union's Chief Operating Officer in 1986 and President in 1990. Mr. Catell served
as President and Chief Executive Officer of Brooklyn Union from 1991 to 1996
when he was elected Chairman and Chief Executive Officer and held these
positions until the formation of KeySpan in May 1998 through the combination of
Brooklyn Union's parent company, KeySpan Energy Corporation, and certain assets
of Long Island Lighting Company. Mr. Catell serves on the Boards of Alberta
Northeast Gas, Ltd., Boundary Gas Inc., Taylor Gas Liquids Fund, Ltd., Gas
Technology Institute, Edison Electric Institute, New York State Energy Research
and Development Authority, Independence Community Bank Corp., Business Council
of New York State, Inc., New York City Investment Fund, New York City
Partnership and the Long Island Association. 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.

     Gordon F. Ahalt has been a Director since 1996. Mr. Ahalt has been
President of G.F.A. Inc., a petroleum industry financial and management
consulting firm, since 1982. Mr. Ahalt was a consultant to Brooklyn Union until
May 1998. He was most recently a consultant to W.H. Reaves Co., Inc., an asset
manager specializing in large cap petroleum, public utilities and
telecommunication equities. Mr. Ahalt serves as a Director for the Bancroft and
Ellsworth Convertible Funds, which specializes in convertible bond and debenture
funds, and Cal Dive International, an offshore oil field service company that
provides subsea construction, inspection, maintenance, repair and salvage
services. 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 Corporation from 1951 to 1955, Chase Manhattan Bank from 1955 to 1972,
White Weld & Co., Inc. from 1972 to 1973, and Chase Manhattan Bank from 1974
through 1976, and served as President and Chief Executive Officer of
International Energy Bank London from 1977 through 1979 and as Chief Financial
Officer of Ashland Oil Inc. from 1980 through 1981.

     David G. Elkins has been a director since July 27, 1999. In January of
2003, Mr. Elkins retired as President and Co-CEO of Sterling Chemicals, Inc., a
chemicals producing company. Sterling Chemicals commenced voluntary
reorganization proceedings under Chapter 11 of the Bankruptcy Code in July 2001
and successfully emerged in December 2002. Prior to joining Sterling Chemicals
in 1998, Mr. Elkins was a senior partner in the law firm of Andrews & Kurth
L.L.P. where he specialized in corporate and business law, including mergers and
acquisitions, securities law matters and corporate governance matters. Mr.
Elkins serves as a director of Sterling Chemicals, Inc., Guilford Mills, Inc.
and Memorial Hermann Hospital System. He received his J.D. degree from Southern
Methodist University in 1968.




                                      -41-
<PAGE>

     Robert J. Fani was elected to our Board of Directors in May 2002. Mr. Fani
was elected President -Energy Assets and Supply of KeySpan in 2003. Mr. Fani
joined KeySpan's subsidiary, The Brooklyn Union Gas Company, in 1976 and has
held a variety of management positions. Prior to his election as President of
KeySpan Energy Assets and Supply, he was President of Energy Services and Supply
since July 2001. Prior to that he was Executive Vice President Strategic
Services. From 1996 to 2000, he was Senior Vice President, Marketing and
Sales/Strategic Marketing. Currently, Mr. Fani oversees KeySpan's electric
services business unit, its gas supply and energy management group, as well as
its asset management and development group. Mr. Fani is a trustee with City
College of New York and Neighborhood Housing Association. Mr. Fani received a
B.S. in mechanical engineering from City College of New York in 1976, an M.B.A.
from St. John's University in 1982 and a J.D. from New York Law School in 1986.

     William G. Hargett was appointed President and Chief Executive Officer and
a Director on April 4, 2001. From May 5, 1999 until August 29, 2000, Mr. Hargett
was President-North America of Santa Fe Snyder Corporation. Prior to that he was
President and Chief Operating Officer and a director of Snyder Oil Corporation.
Prior to joining Snyder Oil Corporation in April of 1997, Mr. Hargett served as
President of Greenhill Petroleum Corporation, the U.S. oil and gas subsidiary of
Australian-based Western Mining Corporation from 1994 to 1997, Amax Oil & Gas,
Inc. from 1993 to 1994 and North Central Oil Corporation from 1988 to 1993. Mr.
Hargett was employed in various exploration capacities by Tenneco Oil
Corporation from 1974 to 1988 and Amoco Production Company from 1973 to 1974.
Mr. Hargett earned a B.S. and an M.S. from the University of Alabama.

     Harold R. Logan, Jr., was appointed to our Board of Directors on December
20, 2002. Mr. Logan is presently Director and Chairman of the Finance Committee
of the Board of Directors of TransMontaigne, Inc. and from 1995 through 2002 he
was the Chief Financial Officer, Executive Vice President and Treasurer and a
Director of TransMontaigne. From 1985 to 1994, Mr. Logan was Senior Vice
President/Finance and a Director of Associated Natural Gas Corporation. Prior to
joining Associated Natural Gas Corporation, Mr. Logan was with Dillon, Read &
Co. Inc. and Rothschild, Inc. In addition, Mr. Logan is a Director of Suburban
Propane Partners, L.P., Graphic Packaging Corporation, and Rivington Capital
Advisors LLC. Mr. Logan received a B.S. in Economics from Oklahoma State
University and an M.B.A. - Finance from Columbia University Graduate School of
Business.

      Gerald Luterman has been a Director since May 2000. Mr. Luterman is
Executive Vice President and Chief Financial Officer of KeySpan. He joined
KeySpan in August 1999 as Senior Vice President and Chief Financial Officer.
Prior to being appointed to his position at KeySpan, Mr. Luterman was the Chief
Financial Officer of barnesandnoble.com, an internet bookstore, from February
1999 to August 1999; the Senior Vice President and Chief Financial Officer of
Arrow Electronics, Inc., a distributor of electronic components and computer
products, from April 1996 to February 1999. Prior to that, from 1985 to 1996,
Mr. Luterman held executive positions with American Express, including Executive
Vice President and Chief Financial Officer of the Consumer Card Division from
1991 to 1996. Mr. Luterman is a Canadian Chartered Accountant and received an
MBA from Harvard Business School.

      H. Neil Nichols has been a Director since May 2000. Mr. Nichols is Senior
Vice President of Corporate Development and Asset Management for KeySpan and has
held this position since March 1999. Mr. Nichols also serves as President of
KeySpan Energy Development Corporation, a subsidiary of KeySpan, a position to
which he was elected in March 1998. Prior to joining KeySpan in 1997, Mr.
Nichols was an owner and President of Corrosion Interventions Ltd., a company
based in Toronto, Canada, from 1996 to 1997 and Chairman, President, and Chief
Executive Officer of Battery Technologies, Inc., from 1993 to 1995. Mr. Nichols
began his career in the natural gas industry with TransCanada PipeLines Limited
in 1956 and held various development positions until 1973 at which time he
became Treasurer of TransCanada, serving as Treasurer until 1977. From 1977 to
1981, Mr. Nichols was Vice President of Finance and Treasurer of TransCanada,
Senior Vice President of Finance from 1981 to 1983, Senior Vice President of
Finance and Chief Financial Officer from 1983 to 1988 and Executive Vice
President from 1988 to 1989. Mr. Nichols currently is a director of various
KeySpan subsidiaries and is a member of the Board of Directors of Taylor Gas
Liquids and KeySpan Energy Canada. Mr. Nichols is a Certified Management
Accountant and a member of the Financial Executives Institute.

     James Q. Riordan has been a Director since 1996 and was a Director of
KeySpan from May 1998 until his retirement in May 2002. 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 Tri-Continental Corporation; Director/Trustee of the mutual funds
in the Seligman Group of investment companies; Trustee for the Committee for
Economic Development and The Brooklyn Museum; and Member of the Policy Council
of the Tax Foundation.





                                      -42-
<PAGE>

     Donald C. Vaughn has been a Director since 1997 and is retired Vice
Chairman of Halliburton Company, an oilfield services company, where he served
in that capacity from the time Dresser Industries, Inc. merged with Halliburton
in 1998 until his retirement on March 31, 2001. Prior to the merger, Mr. Vaughn
was President, Chief Operating Officer and member of the board of directors of
Dresser starting in 1996. Prior to his appointment as President and Chief
Operating Officer of Dresser, Mr. Vaughn served as Executive Vice President of
Dresser, responsible for Dresser's Petroleum Products and Services and
Engineering Services Segment, from November 1995 to December 1996; Senior Vice
President of Operations of Dresser from January 1992 to November 1995; and
Chairman, President and Chief Executive Officer of The M.W. Kellogg Company, an
international engineering and construction company, from November 1983 to June
1996. Mr. Vaughn joined M.W. Kellogg in 1958 and is a registered professional
engineer in the State of Texas. He has been recognized as a distinguished
engineering alumnus of Virginia Polytechnic Institute, from which he holds a
B.S. in civil engineering. Mr. Vaughn serves as a director of SHAWCOR Ltd., a
publicly traded Canadian oil service company.

COMPLIANCE WITH SECTION 16(a)

     Section 16(a) of the Exchange Act requires our directors and officers, and
persons who own more than 10% of the common stock, to file initial reports of
ownership and reports of changes in ownership of common stock on Forms 3, 4, and
5 with the Securities and Exchange Commission and the New York Stock Exchange.
Officers, directors and greater than 10% stockholders are required by Securities
and Exchange Commission regulations to furnish us with copies of any forms that
they file. Based solely on a review of the forms submitted to the Company, it
appears that there was no person subject to the reporting requirements of
Section 16 of the Exchange Act that filed to file on a timely basis reports
required under Section 16.

ITEM 11. EXECUTIVE COMPENSATION

COMPENSATION OF DIRECTORS

     We pay each outside Director a fee of $5,000 per calendar quarter and
$1,000 per board meeting and $1,000 per committee meeting attended. We pay
chairmen of committees of our Board of Directors an additional fee of $500 per
committee meeting. These fees are payable in cash or, at the option of the
Director, may be deferred in an unfunded phantom stock or interest-bearing
account, pursuant to our Deferred Compensation Plan for Non-Employee Directors.

     In addition to these fees, each person who becomes a non-employee Director
receives an option to purchase 5,000 shares of our common stock on the date of
his or her election to the Board. On September 20 of each year, or the next
following business day, we grant to each non-employee Director a non-qualified
option to purchase 2,000 shares of our common stock. Options granted to
Non-Employee Directors fully vest and become exercisable on the date of grant.




                                      -43-
<PAGE>


SUMMARY COMPENSATION TABLE

     The following table sets forth summary information concerning the
compensation we paid or accrued during each of the last three fiscal years to
our Chief Executive Officer and each of our four other most highly compensated
executive officers (collectively, the "Named Executive Officers"):

<Table>
<Caption>
                                                                                        LONG-TERM COMPENSATION
                                                                             ----------------------------------------
                                                                              RESTRICTED    SECURITIES                   ALL OTHER
                                                   ANNUAL COMPENSATION(1)       STOCK       UNDERLYING       LTIP      COMPENSATION
NAME AND PRINCIPAL POSITION                YEAR    SALARY($)     BONUS($)    AWARDS($)(2)  OPTIONS(#)(3) PAYOUTS($)(4)    ($)(5)
-----------------------------------------  ----  ------------  ------------  ------------  ------------  ------------  ------------

<S>                                        <C>   <C>           <C>           <C>           <C>           <C>           <C>
William G. Hargett.......................  2002  $    433,000  $    306,000  $         --        95,000  $         --  $     87,000
    President and Chief Executive Officer  2001       299,000       321,100       256,000       158,000            --        10,500
                                           2000            --            --            --            --            --            --

Charles W. Adcock........................  2002       235,000       131,000            --        39,000            --  $     46,000
    Senior Vice President and General      2001       213,000       304,000            --        47,619        48,000        10,500
    Manager--Offshore Division             2000       192,000       173,000            --            --        50,000        10,500


Steven L. Mueller........................  2002  $    235,000  $    131,000            --        39,000  $         --  $     36,000
    Senior Vice President and General      2001        45,000        27,000            --        50,000            --            --
    Manager -- Onshore Division            2000            --            --            --            --            --            --


Thomas E. Schwartz.......................  2002  $    202,000  $    135,000            --        20,000  $         --  $     77,000
    Vice President - Geophysics            2001       193,000       286,000            --        47,619        23,000       120,500
                                           2000       179,000       162,000            --            --        24,000        57,500


James F. Westmoreland....................  2002  $    203,000  $    123,000            --        20,000  $         --  $     60,000
    Vice President, Chief Accounting       2001       193,000       286,000            --        47,619        68,000        51,500
    Officer and Secretary                  2000       179,000       162,000            --            --        70,000        29,500
</Table>


----------

(1)  Annual compensation amounts exclude perquisites and other personal benefits
     because the compensation did not exceed the lesser of $50,000 or 10% of the
     total annual salary and bonus reported for each Named Executive Officer.

     Bonus amounts for 2000 include a special bonus of 15% of base salary paid
     in April 2000 pursuant to the conclusion and termination of the strategic
     review process we initiated in September 1999 (see Review of Strategic
     Alternatives on page 49 and in Note 6 - Related Party Transactions -
     Transactions with KeySpan). Amounts include: $26,000 each for Messrs.
     Adcock, Westmoreland and Schwartz.

     Bonus amounts for 2001 include a special bonus paid in January 2001 in
     connection with the grant of non-qualified stock options. Amounts include:
     $167,000 each for Messrs. Adcock, Schwartz and Westmoreland. The special
     bonus was made in lieu of annual stock option grants scheduled for 2000
     which were postponed until January 2001.

(2)  Pursuant to Mr. Hargett's employment agreement dated April 4, 2001, Mr.
     Hargett was granted 10,000 restricted shares of common stock at $25.58 per
     share, which vest in on-third increments over a three-year period on each
     anniversary date of the grant, but vest in full if Mr. Hargett terminates
     his employment for good reason or if we terminate Mr. Hargett for any
     reason other than cause, as defined in the employment agreement.

(3)  We did not issue any stock appreciation rights or stock options to Named
     Executive Officers during 2000.

(4)  Long-term Incentive Payouts ("LTIP") for 2001 and 2000 were cash payments
     pursuant to phantom stock rights granted in December 1996, of which 20%
     were payable on December 16th of each of the years 1997 through 2001. Each
     phantom stock right represented the right to receive a cash payment
     determined by the average closing price on the NYSE of one share of common
     stock for the five trading days preceding the payout date multiplied by the
     number of Phantom Stock Rights payable on the payout date.

(5)  Includes distributions attributable to overriding royalty interests in our
     properties paid to Mr. Schwartz of $36,000, $110,000 and $47,000,
     respectively, for 2002, 2001 and 2000, and paid to Mr. Westmoreland of
     $14,000, $41,000 and $19,000, respectively, for 2002, 2001 and 2000. Also
     includes matching contributions we made under our 401(k) and Deferred
     Compensation Plans.




                                      -44-

<PAGE>

OPTIONS GRANTED IN 2002

     The following table provides certain information with respect to options
granted to the Named Executive Officers during 2002 under the 2002 Long-Term
Incentive Plan.

<Table>
<Caption>
                                             INDIVIDUAL GRANTS(1)
                        ------------------------------------------------------------------
                                           PERCENT OF
                                             TOTAL                                              POTENTIAL REALIZABLE VALUE
                           NUMBER OF        OPTIONS                                                  AT ASSUMED ANNUAL
                          SECURITIES       GRANTED TO                                              RATES OF STOCK PRICE
                          UNDERLYING       EMPLOYEES         EXERCISE OR                     APPRECIATION FOR OPTION TERM(2)
                           OPTIONS         IN FISCAL         BASE PRICE       EXPIRATION     -------------------------------
        NAME              GRANTED(#)          YEAR             ($/SH)            DATE            5%($)            10%($)
---------------------   --------------   --------------    --------------   --------------   --------------   --------------
<S>                     <C>              <C>               <C>              <C>              <C>              <C>
William G. Hargett              95,000             12.6%   $        30.10       10/16/2012   $    1,798,324   $    4,557,307
Charles W. Adcock               39,000              5.2%            30.10       10/16/2012          738,259        1,870,894
Steven L. Mueller               39,000              5.2%            30.10       10/16/2012          738,259        1,870,894
Thomas E. Schwartz              20,000              2.7%            30.10       10/16/2012          378,595          959,433
James F. Westmoreland           20,000              2.7%            30.10       10/16/2012          378,595          959,433
</Table>

----------
(1)  We have not issued any stock appreciation rights to the Named Executive
     Officers.

(2)  The Securities and Exchange Commission requires disclosure of the potential
     realizable value or present value of each grant. The disclosure assumes the
     options will be held for the full ten-year term. The actual value, if any,
     an executive officer may realize will depend upon the excess of the stock
     price over the exercise price on the date the option is exercised. There
     can be no assurance that the stock price will appreciate at the rates shown
     in the table.

AGGREGATED OPTION EXERCISES IN 2002 AND FISCAL YEAR-END OPTION VALUES

     The following table provides information regarding stock options exercised
by the Named Executive Officers during the fiscal year ended December 31, 2002,
the number of shares of common stock underlying unexercised options held by each
Named Executive Officer and the value, based on the closing price of our common
stock on the NYSE of $30.60 on December 31, 2002, of exercisable and
unexercisable "in the money" stock options held by each of the Named Executive
Officers.

<Table>
<Caption>
                                                              NUMBER OF SECURITIES        VALUE OF UNEXERCISED
                                                                   UNDERLYING                 IN-THE-MONEY
                                                             UNEXERCISED OPTIONS AT             OPTIONS AT
                               SHARES                         FISCAL YEAR-END (#)            FISCAL YEAR-END ($)
                             ACQUIRED ON      VALUE       ---------------------------   ----------------------------
           NAME              EXERCISE(#)  REALIZED($)(1)   EXERCISABLE  UNEXERCISABLE   EXERCISABLE    UNEXERCISABLE
-------------------------   ------------  --------------  ------------  -------------   ------------   -------------
<S>                         <C>           <C>             <C>           <C>             <C>            <C>
William G. Hargett ......         31,600   $    206,557             --             --   $         --   $    689,068
Charles W. Adcock .......         25,800        370,446         23,848         82,871        124,499        247,175
Steven L. Mueller .......             --             --         10,000         79,000             --         19,500
James F. Westmoreland ...         40,963        556,514          8,648         64,453             --        244,681
Thomas E. Schwartz ......         41,400        489,492         14,648         63,871         45,975        237,675

</Table>

----------
(1)  The value realized upon the exercise of a stock option is equal to the
     difference between the market price on the date of exercise and exercise
     price of the stock option.

COMPENSATION COMMITTEE INTERLOCK AND INSIDER PARTICIPATION

     Robert B. Catell, a member of the Compensation Committee, is Chairman of
the Board and Chief Executive Officer of KeySpan. Mr. Riordan, a member of the
Compensation Committee, was a member of KeySpan's Board of Directors from 1998
until his retirement in May 2002. KeySpan owns approximately 66% of our common
stock.



                                      -45-
<PAGE>

ITEM 12. SECURITY OWNERSHIP OF BENEFICIAL OWNERS AND MANAGEMENT

     The following table presents information as of February 20, 2003 regarding
the beneficial ownership of our common stock by common stock equivalents
credited to each person who we know to own beneficially more than five percent
of the outstanding shares of common stock, each Director, our executive
officers, all Directors and executive officers as a group. Unless otherwise
indicated, each person shown below has the sole power to vote and the sole power
to dispose of the shares of common stock listed as beneficially owned.

<Table>
<Caption>
                                                    COMMON STOCK BENEFICIALLY OWNED
                                            ------------------------------------------------
                                                                                   OPTIONS                           TOTAL PERCENT
                                            COMMON STOCK                         TO PURCHASE        PHANTOM STOCK         OF
                                                 AND            COMMON             COMMON               RIGHTS          COMMON
          NAME OF BENEFICIAL OWNER          STOCK OPTIONS       STOCK              STOCK(1)              (2)           STOCK(17)
-----------------------------------------   -------------     -----------        -----------        -------------    -------------
<S>                                         <C>               <C>                <C>                <C>              <C>
   KeySpan Corporation (3)
       One MetroTech Center
       Brooklyn, NY 11201-3850 .........      20,380,392      20,380,392                 --                  --           66%

   Robert B. Catell ....................          21,000           4,000(4)          17,000                  --            *
   William G. Hargett ..................          17,333           3,333(5)          14,000(5)               --            *
   David G. Elkins .....................          18,000           5,000             13,000                  --            *
   James Q. Riordan ....................          17,500             500(6)          17,000               9,972            *
   Donald C. Vaughn ....................          17,000              --             17,000               2,702            *
   Gerald Luterman .....................          11,000              --(7)          11,000                  --            *
   H. Neil Nichols .....................          11,000              --(8)          11,000                  --            *
   Gordon F. Ahalt .....................           6,000           2,000              4,000                  --            *
   Robert J. Fani ......................           7,000              --(9)           7,000(9)               --            *
   Harold R. Logan, Jr .................           5,000              --              5,000                  --            *
   Charles W. Adcock ...................          26,324           2,476             23,848(10)              --            *
   James F. Westmoreland ...............           9,712           1,064              8,648(11)              --            *
   Thomas E. Schwartz ..................          14,648              --             14,648(12)              --            *
   Tracy Price .........................          12,700              --             12,700(13)              --            *
   Steven L. Mueller ...................          10,000              --             10,000(14)              --            *
   Roger B. Rice .......................           7,000              --              7,000(15)              --            *
   John H. Karnes ......................              --              --                 --(16)              --            *
                                             -----------     -----------        -----------         -----------
   All Directors and
   executive officers as a group
   (17 persons) ........................         211,217          18,373            192,844              12,674          0.6%
                                             ===========     ===========        ===========         ===========
</Table>

----------

*    Less than 1%.

(1)  The Directors and officers have the right to acquire the shares of common
     stock reflected in this column currently or within 60 days of the date
     hereof through the exercise of stock options

(2)  The term Phantom Stock Rights refers to units of value which track the
     performance of common stock. The units do not possess any voting rights or
     right to dispose of common stock and have been issued to non-employee
     Directors pursuant to our Deferred Compensation Plan for Non-Employee
     Directors.

(3)  KeySpan holds its shares through its indirect wholly owned subsidiary, THEC
     Holdings Corp.

(4)  Mr. Catell also owns 1,547,385 shares of KeySpan common stock, which
     includes (i) 1,456,601 outstanding options to purchase shares of KeySpan
     common stock that are exercisable within 60 days of the date hereof; (ii)
     13,801 shares of KeySpan restricted stock; and (iii) 5,146 deferred stock
     units. In addition, Mr. Catell owns 12.82 shares of KeySpan preferred
     stock.

(5)  Mr. Hargett owns 6,667 shares of restricted common stock of which, 3,333
     shares vest within 60 days of the date hereof with the remaining 3,334
     shares vesting on the anniversary date of the grant date or April 4, 2004.
     Mr. Hargett owns 221,400 options, 14,000 of which are exercisable within 60
     days of the date hereof.



                                      -46-
<PAGE>

(6)  Mr. Riordan also owns 24,800 shares of KeySpan common stock, which includes
     3,300 options to purchase shares of KeySpan common stock within 60 days
     from the date hereof.

(7)  Mr. Luterman also owns 169,261 shares of KeySpan common stock including
     160,800 options to purchase KeySpan common stock exercisable within 60
     days; (ii) 3,042 shares of KeySpan restricted stock; and (iii) 1,389
     deferred stock units.

(8)  Mr. Nichols also owns 130,505 shares of KeySpan common stock including (i)
     128,399 outstanding options to purchase KeySpan common stock exercisable
     within 60 days hereof and (ii) 1,775 shares of KeySpan restricted stock;
     and (iii) 1,707 deferred stock units. In addition, Mr. Nichols owns 12.82
     shares of KeySpan preferred stock.

(9)  Mr. Fani owns 179,222 shares of KeySpan common stock which includes (i)
     161,614 options to purchase KeySpan common stock exercisable within 60 days
     of the date hereof; (ii) 4,438 shares of KeySpan restricted stock; and
     (iii) 2,768 deferred stock units. In addition, Mr. Fani owns 12.82 shares
     of KeySpan preferred stock.

(10) Mr. Adcock owns 106,719 options to purchase common stock, 23,848 which are
     vested.

(11) Mr. Westmoreland owns 73,101 options to purchase common stock, 8,648 which
     are vested.

(12) Mr. Schwartz owns 78,519 options to purchase common stock, 14,648 options
     are vested.

(13) Mr. Price owns 83,500 options to purchase common stock, 12,700 options are
     vested.

(14) Mr. Mueller owns 89,000 options to purchase common stock, 10,000 options
     are vested.

(15) Mr. Rice owns 55,000 options, 7,000 of which are exercisable within 60 days
     of the date hereof.

(16) Mr. Karnes owns 60,000 options, none of which have vested.

(17) Based upon 30,961,418 shares outstanding as of February 20, 2003.



                                      -47-
<PAGE>


ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

TRANSACTIONS WITH KEYSPAN

     We began exploring for natural gas and oil in December 1985 on behalf of
The Brooklyn Union Gas Company. Brooklyn Union is an indirect wholly owned
subsidiary of our majority stockholder, KeySpan. On September 20, 1996, we
completed an initial public offering and issued 7,130,000 shares, or 31%, of our
common stock to the public. As of February 20, 2003, THEC Holdings Corp., an
indirect wholly owned subsidiary of KeySpan, owned approximately 66% of the
outstanding shares of our common stock.

     All transactions between us and KeySpan were at terms at least as favorable
to us as could have been obtained from unaffiliated third parties, as determined
by our board of directors or a committee of independent directors appointed by
our board. Pursuant to the terms of the indenture governing our 8?% senior
subordinated notes, we are prohibited from entering into any related party
transaction unless such transaction is on terms that are no less favorable to us
than those that would have been obtained in a comparable transaction by us with
an unrelated third party. Any related party transactions in excess of $2.5
million must be approved by a majority of the disinterested members of the board
of directors, and any related party transaction in excess of $10 million
requires a fairness opinion from an investment banking firm of national
standing.

KeySpan Joint Venture

     Effective January 1, 1999, we entered into a joint exploration agreement
with KeySpan Exploration & Production, LLC, a subsidiary of KeySpan, to explore
for natural gas and oil over an initial two-year term expiring December 31,
2000. Under the terms of the joint venture, we contributed all of our then
undeveloped offshore acreage to the joint venture and we agreed that KeySpan
would receive 45% of our working interest in all prospects drilled under the
program. KeySpan paid 100% of actual intangible drilling costs for the joint
venture up to a specified maximum of $7.7 million in 2000 and $20.7 million
during 1999. Further, KeySpan paid 51.75% of all additional intangible drilling
costs incurred and we paid 48.25%. Revenues are shared 55% to Houston
Exploration and 45% to KeySpan. In addition, we received reimbursements from
KeySpan for a portion of our general and administrative costs.

     Effective December 31, 2000, KeySpan and Houston Exploration agreed to end
the primary or exploratory term of the joint venture. As a result, KeySpan has
not participated in any of our offshore exploration prospects unless the project
involved the development or further exploitation of discoveries made during the
initial term of the joint venture. In addition, effective with the termination
of the exploratory term of the joint venture, we have not received any further
reimbursement from KeySpan for general and administrative costs.

     From the inception of the joint venture in January 1999 through December
31, 2002, we drilled a total of 28 wells: 21 exploratory wells of which 17 were
successful and seven development wells of which six were successful. KeySpan
spent a total of $118.3 million, with $19.0 million, $17.2 million and $46.5
million, respectively being spent during 2002, 2001 and 2000. Subsequent to the
termination of the primary exploratory term of the joint venture, KeySpan's
participation in additional wells was to further develop or delineate reservoirs
previously discovered.

Acquisition of KeySpan Joint Venture Assets

     On October 11, 2002, we purchased from KeySpan a portion of the assets
developed under the joint exploration agreement with KeySpan Exploration &
Production, LLC, a subsidiary of KeySpan. The acquisition consisted of interests
averaging between 11.25% and 45% in 17 wells covering eight of the twelve blocks
that were developed under the joint exploration agreement from 1999 through
2002. The interests purchased were in the following blocks: Vermilion 408, East
Cameron 81 and 84, High Island 115, Galveston Island 190 and 389, Matagorda
Island 704 and North Padre Island 883. KeySpan has retained its 45% interest in
four blocks: South Timbalier 314 and 317 and Mustang Island 725 and 726 as these
blocks are in various stages of development. KeySpan has committed to continued
participation in the ongoing development of these blocks which includes the
completion of the platform and production facilities at South Timbalier 314/317
together with possible further developmental drilling at both South Timbalier
314/317 and Mustang Island 725/726. As of September 1, 2002, the effective date
of the purchase, the estimated proved reserves associated with the interests
acquired were 13.5 Bcfe. The $26.5 million purchase price was paid in cash and
financed with borrowings under our revolving credit facility. Subsequent
purchase price adjustments reduced our acquisition purchase price by $1.2
million. The purchase price was adjusted for various closing items in the normal
course of business, including revenues received by and expenditures made by the
seller related to the properties acquired for the period between the effective
date of the transaction (September 1, 2002) and the closing date (October 11,
2002). Our acquisition of the properties was accounted for as a transaction
between entities under common control. As a result, the excess fair value of the
properties



                                      -48-
<PAGE>

acquired of $3.1 million ($2.0 million net of tax) was treated as a capital
contribution from KeySpan and recorded as an increase to additional paid-in
capital during the fourth quarter of 2002.

     Our Board of Directors appointed a special committee, comprised entirely of
independent directors to review the proposed transaction with KeySpan. In
addition, the special committee discussed the history and terms of the
transaction with our senior management. After completing its review, the special
committee unanimously concluded that the transaction was advisable and in our
best interests and that the terms of the transaction were at least as favorable
to us as terms that would have been obtainable at the time in a comparable
transaction with an unaffiliated party. In reaching its decision, the special
committee considered numerous factors in consultation with its financial and
legal advisors.

KeySpan Credit Facility and Conversion

     On March 31, 2000, we converted $80 million of borrowings that were
outstanding under a revolving credit facility with KeySpan into 5,085,177 shares
of our common stock at a conversion price of $15.732 per share. The revolving
credit facility was entered into in November 1998 to fund the acquisition of our
Mustang Island A31/32 Field. Upon conversion on March 31, 2000, KeySpan's
ownership interest in our company increased from 64% to 70%. At December 31,
2002 KeySpan's ownership in our company was 66% with the decrease attributable
to an increase in our common shares outstanding due to the exercise of stock
options subsequent to the conversion transaction. The conversion price was
determined based upon the average of the closing prices of our common stock,
rounded to three decimal places, as reported under "NYSE Composite Transaction
Reports" in the Wall Street Journal during the 20 consecutive trading days
ending three trading days prior to March 31, 2000. The conversion of the
revolving credit facility and the corresponding issuance of additional shares of
our common stock to KeySpan was approved by our stockholders at our annual
meeting held April 27, 1999. Borrowings under the facility bore interest at
LIBOR plus 1.4% and we incurred a quarterly commitment fee of 0.125% on the
unused portion of the maximum commitment. The credit facility terminated on
March 31, 2000. For the year ended December 31, 2000, we incurred $1.5 million
in interest and fees to KeySpan.

Review of Strategic Alternatives

     In September 1999, we, along with KeySpan, our majority stockholder,
announced our intention to review strategic alternatives for Houston Exploration
and for KeySpan's investment in Houston Exploration. KeySpan was assessing the
role of our company within its future strategic plan, and was considering a full
range of strategic transactions including the sale of all or a portion of
Houston Exploration. J.P. Morgan Securities Inc. was retained by KeySpan as
financial advisor to assist in the strategic review on behalf of KeySpan. Our
Board of Directors appointed a special committee comprised of outside directors
to assist in the review process. On February 25, 2000, together with KeySpan we
jointly announced that the review of strategic alternatives had been completed
and that KeySpan plans to retain its equity interest in us for the foreseeable
future, however, KeySpan considers its investment in Houston Exploration a
non-core asset. We incurred expenses relating to this review of strategic
alternatives totaling $0.1 million during 2001 and $1.8 million during 2000.

Sale of Section 29 Tax Credits

     In January 1997, we entered into an agreement to sell to a subsidiary of
KeySpan interests in our onshore producing wells that produce from formations
that qualify for tax credits under Section 29 of the Internal Revenue Code.
Section 29 provides for a tax credit from non-conventional fuel sources such as
oil produced from shale and tar sands and natural gas produced from geopressured
brine, Devonian shale, coal seams and tight sands formations. KeySpan acquired
an economic interest in wells that are qualified for the tax credits and in
exchange, we:

          o    retained a volumetric production payment and a net profits
               interest of 100% in the properties,

          o    received a cash down payment of $1.4 million and

          o    receive a quarterly payment of $0.75 for every dollar of tax
               credit utilized.

     We manage and administer the daily operations of the properties in exchange
for an annual management fee of $100,000. The income statement effect,
representing benefits received from Section 29 tax credits, was a benefit of
$0.8 million, $0.8 million, and $0.9 million, respectively, for each of the
years ended December 31, 2002, 2001, and 2000. The tax credits expired December
31, 2002 and under the terms of the agreement, we are required to repurchase the
interests in the producing wells for KeySpan. We are planning to complete the
repurchase transaction in 2003 and the repurchase price is estimated at
approximately $2.0 million.



                                      -49-
<PAGE>


Registration Rights Agreement.

     Under a registration rights agreement entered into as of July 2, 1996
between us and THEC Holdings Corp., we have agreed to file, upon the request of
KeySpan, a registration statement under the Securities Act for the purpose of
enabling KeySpan to offer and sell any securities we issued to THEC Holdings.
KeySpan may exercise these rights at any time. We will bear the costs of any
registered offering, except that KeySpan will pay any underwriting commissions
relating to any offering, any transfer taxes and any costs of complying with
foreign securities laws at KeySpan's request, and each party will pay for its
counsel and accountants. We have the right to require KeySpan to delay any
exercise by KeySpan of its rights to require registration and other actions for
a period of up to 180 days if, in our judgment, we or any offering we are then
conducting or about to conduct would be adversely affected. We have also granted
KeySpan the right to include its securities in registration statements covering
offerings by us, and we will pay all costs of offerings other than underwriting
commissions and transfer taxes attributable to the securities sold on behalf of
KeySpan. We have agreed to indemnify KeySpan, its officers, directors, agents,
any underwriter, and each person controlling any of the foregoing, against
liabilities under the Securities Act or the securities laws of any state or
country in which our securities are sold pursuant to the registration rights
agreement.

EMPLOYMENT AGREEMENTS

     We entered into an employment agreement with Mr. Hargett as President and
Chief Executive Officer effective April 4, 2001. Mr. Hargett's employment
agreement was amended on May 17, 2002 to clarify that Mr. Hargett would be paid
reasonable compensation in an amount between $3,000,000 and $7,500,000 as
determined under the agreement in the event of the sale of all or substantially
all of our assets or the acquisition by any person other than KeySpan of a
majority of our outstanding common stock. Currently, Mr. Hargett is entitled to
an annual base salary of $450,000 and an annual incentive bonus of 70% of base
salary if we meet financial targets established by our Board of Directors. On
the effective date of the agreement, we granted Mr. Hargett 10,000 restricted
shares of common stock, with fair value of $255,800, which vest in one-third
increments over a three-year period on each anniversary date of the grant. This
restricted stock grant vests in full if Mr. Hargett terminates his employment
for good reason or if we terminate Mr. Hargett for any reason other than cause,
as defined in the employment agreement. For the year ended December 31, 2002,
Mr. Hargett was eligible to receive 70% of his base salary as bonus under our
Employee Annual Incentive Compensation Plan if certain pre-established
objectives were achieved for the year. Mr. Hargett achieved 97% of his targeted
objectives. Mr. Hargett's year-end base salary rate of $450,000 was used in
calculating his bonus award for 2002, and accordingly, he earned a cash bonus of
$306,000.

     Effective November 18, 2002, we entered into an employment agreement with
John H. Karnes as Senior Vice President and Chief Financial Officer. Under the
agreement, we agreed to pay Mr. Karnes an annual salary of $275,000 and an
annual incentive bonus of 55% of his base salary if we meet the targets set by
our Board of Directors.

     We have entered into employment agreements with Messer. Adcock, Mueller,
Westmoreland, Rice, Schwartz and Price. Under the terms of these agreements,
these individuals receive base salaries of $245,000, $245,000, $230,000,
205,000, 205,000 and 195,000 respectively. Each individual is also entitled to
annual incentive bonuses of 55% of base salary if we meet financial targets
established by our Board of Directors.

     The initial term of all our employment agreements automatically extends to
the third anniversary of the respective effective date. The term of each
agreement is automatically extended one year on each anniversary unless either
party gives notice at least 90 days prior to the anniversary of its intention
not to extend the term of the agreement. We may terminate all of our employment
agreements for cause or upon the death or disability of the employee. The
employee may terminate the employment agreements for any reason. If we terminate
an employment agreement without cause or if the employee terminates an
employment agreement with good reason, as defined in the employment agreements,
we are obligated to pay the employee a lump-sum severance payment of 2.99 times
the employee's then current annual rate of total compensation which includes
salary, car allowance and annual bonus, which would be calculated as though our
financial targets had been met, and the continuation of welfare benefits. The
employment agreements further provide that a change of control will terminate
the employment agreements, triggering the lump-sum severance payment obligation
in the amount of 2.99 times the employee's total compensation, and termination
of the employment agreements will also terminate the non-compete provisions the
agreements contain. The agreements further provide that if any payments made to
the executives, whether or not under the agreement, would result in an excise
tax being imposed on the executives under Section 4999 of the Internal Revenue
Code, we will make each of the executives "whole" on a net after-tax basis.

     Under their employment agreements, each of our executive officers would be
entitled to a lump sum severance payment equal to 2.99 times their current total
annual compensation, if we terminated their employment agreements without cause
or if the employee terminates his employment agreement for good reason. Mr.
Hargett would receive approximately $2.3 million, Mr. Karnes would receive
approximately $1.3 million, Messrs. Adcock and Mueller would



                                      -50-
<PAGE>

each receive approximately $1.2 million. Mr. Westmoreland would receive
approximately $1.1 million, Messrs. Schwartz and Rice would each receive
approximately $1.0 million and Mr. Price would receive approximately $0.9
million.

     Effective as of October 26, 1999, our Board of Directors established the
Change of Control Plan under which all employees, including the executive
officers, in the event of a "change of control" will be entitled to receive a
"stay-on" bonus in the amount of 125% of the employee's regular target bonus
percentage, and, in addition to other severance benefits, all stock options,
phantom stock and 401(k) contributions will fully vest. See "Change of Control
Plan."

SUPPLEMENTAL EXECUTIVE PENSION PLAN

     Effective immediately prior to our initial public offering in 1996, we
adopted an unfunded, non-qualified Supplemental Executive Pension Plan under
which our former President and Chief Executive Officer, Mr. Floyd, is the only
beneficiary. Under this plan, we have agreed to pay Mr. Floyd $100,000 per year
for life. Should he predecease his spouse, Mr. Floyd's surviving spouse will be
paid $50,000 per year for her life. Mr. Floyd retired March 31, 2001 and during
2002 we paid Mr. Floyd a total of $100,000.

401(k) PLAN

     We maintain a 401(k) Plan for our employees. Under the 401(k) Plan,
eligible employees may elect to have us contribute on their behalf up to 12.5%
of their base compensation on a before tax basis in accordance with the
limitations imposed under the Internal Revenue Code. We make a matching
contribution of $1.00 for each $1.00 of employee deferral, in accordance with
the limitations imposed by the 401(k) Plan and the Internal Revenue 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. Our 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.

1996 STOCK OPTION PLAN

     We adopted the 1996 Stock Option Plan in September 1996 in conjunction with
our initial public offering. The 1996 Stock Option Plan allows us to grant
options not to exceed 10% of the shares of our common stock outstanding from
time to time. The 1996 Stock Option Plan is administered by the Compensation
Committee of the Board of Directors which, at its discretion, may grant either
incentive stock options or non-qualified stock options to eligible individuals.
All employees, including consultants and advisors of our company and our
affiliates are eligible to participate in the 1996 Stock Option Plan. Prior to
our adoption of the 1999 Stock Option Plan in October 1999, non-employee
Directors were also eligible to participate in the 1996 Stock Option Plan. All
option grants made to non-employee Directors after October 1999 are made under
terms of the 1999 Stock Option Plan or the 2002 Long-term Incentive Plan.
Options granted under the 1996 Stock Option Plan expire 10 years from the grant
date and vest in one-fifth increments on each of the first five anniversaries of
the grant date with the exception of options granted to non-employee Directors
which are fully vested on the date of grant. During 2002, options to purchase
14,509 shares of our common stock were granted under the 1996 Stock Option Plan.
At December 31, 2002, a total of 329 shares remained available for grant under
the 1996 Plan. We may adjust any options issued under the 1996 Stock Option Plan
in the event of stock splits and other corporate events. In addition, we may
appropriately adjust the exercise price for options in the event that the
outstanding shares of common stock are changed into or exchanged for a different
number or kind of shares or other securities by reason of merger, stock
dividend, combination of shares or the like.

1999 NON-QUALIFIED STOCK OPTION PLAN

     On October 26, 1999, our Board of Directors adopted the 1999 Non-Qualified
Stock Option Plan for employees (excluding executive officers), non-employee
Directors, consultants and advisors of our company and our affiliates. With
respect to non-employee Directors only, the 1999 Non-Qualified Stock Option Plan
amends and succeeds the 1996 Plan (under which no more options may be granted to
non-employee Directors). The 1999 Non-Qualified Stock Option Plan is
administered by the Compensation Committee, which at its discretion, may grant
awards to eligible individuals with the exception of non-employee Directors who
receive automatic grants under the 1999 Non-Qualified Stock Option Plan. The
options granted under the 1999 Non-Qualified Stock Option Plan are all
non-qualified, expire 10 years from date of grant and vest immediately for
non-employee Directors and in one-fifth increments on each of the first five
anniversaries of the grant for other eligible individuals. During 2002, we
granted a total of 145,600 options under the 1999 Non-Qualified Stock Option
Plan, of which 18,000 options were granted to non-employee directors pursuant to
our compensation plan for non-employee directors. At December 31, 2002, a total
of 566 shares remained available for grant under the 1999 Plan.



                                      -51-
<PAGE>

We may adjust options issued under the 1999 Non-Qualified Stock Option Plan in
the event of stock splits and other corporate events. In addition, we may
appropriately adjust the exercise price for options in the event that the
outstanding shares of common stock are changed into or exchanged for a different
number or kind of shares or other securities by reason of merger, stock
dividend, combination of shares or the like.



                                      -52-
<PAGE>


2002 LONG-TERM INCENTIVE PLAN

     In January 18, 2002, our Board of Directors adopted the 2002 Long-Term
Incentive Plan for our non-employee Directors and employees, consultants and
advisors of our company and our affiliates. The 2002 Long-Term Incentive Plan is
administered by the Compensation Committee, which at its discretion, may grant
awards of options or restricted stock to eligible individuals with the exception
of non-employee Directors who receive automatic grants under the 2002 Long-Term
Incentive Plan. Awards granted to non-employee Directors, consultants and
advisors under the 2002 Long-Term Incentive Plan are all non-qualified options,
while employees may receive incentive or non-qualified options and/or restricted
stock. Options may not be exercised after 10 years from the date they were
granted. In the case of a 10% stockholder, incentive options may not be
exercised after five years from the date the option is granted. Options vest
immediately for non-employee Directors and at the times provided in their option
agreement for other eligible individuals but in no event sooner than six months
from the date granted. Terms and conditions of the restricted stock awards,
including the duration of the restricted period during which, and the
conditions, including performance objectives, if any, under which if not
achieved, the restricted stock may be forfeited, are determined by the
Compensation Committee. Unless conditioned upon the achievement of performance
objectives or a special determination is made by the Compensation Committee as
to a shorter restricted period, the restricted period will not be less than five
years. During 2002, we granted a total of 593,950 options under the 2002
Long-Term Incentive Plan, of which 5,000 options were granted to non-employee
directors. No shares of restricted stock were granted under the plan. At
December 31, 2002, a total of 906,050 shares remained available for grant under
the 2002 Plan. We may adjust options issued under the 2002 Long-Term Incentive
Plan in the event of stock splits and other corporate events. In addition, we
may appropriately adjust the exercise price for options in the event that the
outstanding shares of common stock are changed into or exchanged for a different
number or kind of shares or other securities by reason of merger, stock
dividend, combination of shares or the like.

DEFERRED COMPENSATION PLAN

     In November 2002, our Board of Directors adopted a deferred compensation
plan for the benefit of our employees. The plan is intended to supplement our
401(k) plan by allowing highly compensated employees to save on a tax deferred
basis a portion of their eligible compensation subject to limitations imposed by
the plan. Under the terms of the plan, employees who have made the maximum
allowable contribution to their 401(k) accounts for any year ($11,000 per year
or $12,000 per year for employees over 50 years of age for 2002) may elect to
defer an additional portion of their compensation into the deferred compensation
plan. We match 100% of each employee's deferral up to an aggregate contribution
of 12.5% under both the 401(k) plan and the deferred compensation plan. During
2002, we made matching contributions totaling $0.5 million to the deferred
compensation plan. Employer contributions vest 20% per year and become fully
vested after a 5 year period. All contributions to the plan are held in trust
and invested, at the direction of the employee, in various investment funds,
including company stock. Participants are entitled to distribution of their
deferrals and the vested portion of our matching contributions at predetermined
future dates or upon termination of their employment.

EMPLOYEE ANNUAL INCENTIVE COMPENSATION PLAN

     We maintain an Annual Incentive Compensation Plan that provides an annual
incentive bonus to all full-time employees if certain performance goals are met
during the year. The plan is administered by our Chief Executive Officer on
behalf of our Board of Directors and the Compensation Committee. Annual
objectives and incentive opportunity levels are established and approved by the
Compensation Committee. Incentive awards are earned based on our actual
performance in relation to pre-established objectives and on an assessment of
individual contribution during the year.

CHANGE OF CONTROL PLAN

     Effective as of October 26, 1999, our Board of Directors established the
Change of Control Plan pursuant to which, upon a change of control all
employees, including executive officers, will be entitled to receive "stay-on"
bonuses in the amount of 125% of the employee's regular target bonus percentage.
In addition, a change of control will cause all stock options, phantom stock and
other employee benefits to become fully vested.

     Further, if we or our successor terminates employees, other than executive
officers, within one year of the change of control other than for cause, as
defined in the Change of Control Plan, or our employees suffer a significant
adverse change in employment, a reduction in salary or relocation of more than
30 miles, these employees will be entitled to severance benefits in the form of
a lump sum payment calculated pursuant to a formula based upon each employee's
base salary and years of service. The calculation of lump sum payments for
executive officers is stated in their respective employment agreements.



                                      -53-
<PAGE>

     A "change of control" is deemed to occur if either:

     o    a person, entity or group other than us or our affiliate acquires 20%
          or more of the combined voting power of our then outstanding voting
          securities,

     o    a reorganization, merger, consolidation or liquidation is approved; or

     o    the individuals constituting our Board of Directors on October 26,
          1999 cease to constitute a majority of our Board of Directors unless
          the election of each new director was approved by a vote of at least a
          majority of the directors then still in office who were directors at
          the beginning of the period.

ITEM 14. CONTROLS AND PROCEDURES

     We maintain disclosure controls and procedures that are designed to ensure
that information required to be disclosed by us in the reports we file under the
Securities Exchange Act of 1934, as amended ("Exchange Act") is communicated,
processed, summarized and reported within the time periods specified in the
SEC's rules and forms. We carried out an evaluation, with the participation of
our principal executive officer and principal financial officer, of the
effectiveness of our disclosure controls and procedures (as defined in Rule
13a-14 of the Exchange Act), as of the end of the period covered by this report.
Based on that evaluation, our principal executive officer and principal
financial officer concluded that our disclosure controls and procedures are
effective. There have been no changes in our internal control over financial
reporting that occurred during the most recent fiscal quarter prior to the end
of the period covered by this report that have materially affected, or are
reasonable likely to materially affect, our internal controls over financial
reporting.



                                      -54-
<PAGE>


PART IV.

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

     (a)  Documents Filed as a Part of this Report

1. FINANCIAL STATEMENTS:

<Table>
<Caption>
                                                                                                                        PAGE
                                                                                                                        ----
<S>                                                                                                                     <C>
Index to Financial Statements.....................................................................................       F-1
Independent Auditors' Report......................................................................................       F-2
Consolidated Balance Sheets As of December 31, 2002 and 2001......................................................       F-4
Consolidated Statements of Operations for the Years Ended December 31, 2002, 2001(as restated)                           F-5
   and 2000.......................................................................................................
Consolidated Statements of Stockholders' Equity and Comprehensive Income for the Period                                  F-6
   January 1, 2000 to December 31, 2002...........................................................................
Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000........................       F-8
Notes to Consolidated Financial Statements........................................................................       F-9
Supplemental Information on Natural Gas and Oil Exploration, Development and
   Production Activities (Unaudited) .............................................................................       F-28
Quarterly Financial Information (Unaudited).......................................................................       F-33
</Table>

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

2. EXHIBITS:

     (a)  See Index of Exhibits on page F-34 for a description of the exhibits
          filed as a part of this report.

     (b)  Reports on Form 8-K.

          Current Report on Form 8-K filed on March 25, 2002 to provide new
          information regarding hedges for the years ended December 31, 2002 and
          2003 in Item 5. - Other Events

          Current Report on Form 8-K filed April 5, 2002 to provide information
          regarding change of certifying accountant in Item 4. - Changes in
          Registrant's Certifying Accountant



                                      -55-
<PAGE>


                                   SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this amendment no.1 of this
report to be signed on its behalf by the undersigned, thereunto duly authorized.

                             THE HOUSTON EXPLORATION COMPANY


                             By: /s/ James F. Westmoreland
                                 -----------------------------------------------
                                 James F. Westmoreland
Date: November 12, 2003          Vice President and Chief Accounting Officer



                                      -56-
<PAGE>


                          GLOSSARY OF OIL AND GAS TERMS


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


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

     Bbl/d. One barrel per day.

     Bcf. Billion cubic feet.

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

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

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

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

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

     Intangible Drilling and Development Costs. Expenditures made by an operator
for wages, fuel, repairs, hauling, supplies, surveying, geological works etc.,
incident to and necessary for the preparing for and drilling of wells and the
construction of production facilities and pipelines.

     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.



                                      G-1

<PAGE>

                          GLOSSARY OF OIL AND GAS TERMS


     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.

     Mcfe/d. 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 per day.

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

     MMbtu. One million Btus.

     MMMbtu. One billion Btus.

     MMcf. One million cubic feet.

     MMcf/d. One million cubic feet per day.

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

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

     Oil. Crude oil and condensate.

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

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

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

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

     Proved reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. In addition, please refer to
the definitions of proved oil and gas reserves as provided in Rule
4-10(a)(2)(3)(4). The rule is available at the SEC website,
http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas.

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

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

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



                                      G-2

<PAGE>

                          GLOSSARY OF OIL AND GAS TERMS


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

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

     Tangible Drilling and Development Costs. Cost of physical lease and well
equipment and structures. The costs of assets that themselves have a salvage
value.

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

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

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



                                      G-3

<PAGE>




                          INDEX TO FINANCIAL STATEMENTS


<Table>
<Caption>
                                                                                                                     PAGE
                                                                                                                     ----
<S>                                                                                                                  <C>
Independent Auditors' Report...............................................................................           F-2
Consolidated Balance Sheets As of December 31, 2002 and 2001...............................................           F-4
Consolidated Statements of Operations for the Years Ended December 31, 2002, 2001 (as restated)
         and 2000..........................................................................................           F-5
Consolidated Statements of Stockholders' Equity and Comprehensive Income for the Period
        January 1, 2000 to December 31, 2002...............................................................           F-6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000.................           F-8
Notes to Consolidated Financial Statements.................................................................           F-9
</Table>



                                      F-1

<PAGE>


                          INDEPENDENT AUDITORS' REPORT

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

     We have audited the accompanying consolidated balance sheets of The Houston
Exploration Company (a Delaware corporation and an indirect 66% owned subsidiary
of KeySpan Corporation) and subsidiary (the "Company") as of December 31, 2002
and 2001, and the related consolidated statements of operations, stockholders'
equity and comprehensive income(loss) and cash flows for years then ended. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on the financial statements based on our
audits. The consolidated financial statements of the Company for the year ended
December 31, 2000 were audited by other auditors who have ceased operations.
Those auditors expressed an unqualified opinion on those financial statements in
their report dated February 4, 2002, which included an emphasis of matter
paragraph relating to the adoption of a new accounting standard. Those auditors
reported on such financial statements prior to the restatement discussed in Note
11.

     We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audits to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidences 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 2002 and 2001 consolidated financial statements present
fairly, in all material respects, the financial position of the Company as of
December 31, 2002 and 2001, and the results of its operations and its cash flows
for the years then ended in conformity with accounting principles generally
accepted in the United States of America.

     As discussed in Note 1 to the consolidated financial statements, the
Company adopted Statement of Financial Accounting Standards ("SFAS") No. 133,
"Accounting for Derivatives Instruments and Hedging Activities," as amended, on
January 1, 2001.

     As discussed in Note 11 to the consolidated financial statements, the 2001
financial statements have been restated for the effects of transportation
expenses under Emerging Issues Task Force ("EITF") Issue No. 00-10 and certain
disclosures relating to the adoption of SFAS No. 133.

     As discussed above, the consolidated financial statements of the Company
for the year ended December 31, 2000 were audited by other auditors who have
ceased operations. As described in Note 11, those consolidated financial
statements have been reclassified to effect EITF Issue No. 00-10, "Accounting
for Shipping and Handling Fees and Costs". We audited the adjustments described
in Note 11 that were applied to conform the 2000 consolidated financial
statements to comparative presentation required by EITF Issue No. 00-10. Our
audit procedures with respect to the 2000 disclosures in Note 11 included (i)
comparing the amounts shown as transportation costs to the Company's underlying
accounting analysis obtained from management, and (ii) on a test basis,
comparing the amounts comprising the transportation costs obtained from
management to independent supporting documentation, and (iii) testing the
mathematical accuracy of the underlying analysis. In our opinion, such
reclassifications have been properly applied. However, we were not engaged to
audit, review or apply any procedures to the 2000 consolidated financial
statements of the Company other than with respect to such reclassifications and,
accordingly, we do not express an opinion or any form of assurance on the 2000
financial statements taken as a whole.

                              DELOITTE & TOUCHE LLP

Houston, Texas
February 7, 2003 (February 20, 2003 as to the first paragraph of "Legal
Proceedings" in Note 9; November 13, 2003, as to the sixth paragraph of "Natural
Gas and Oil Properties," and the first paragraph of "New Accounting
Pronouncements" in Note 1, and the third paragraph of "2002" in Note 7.)



                                      F-2

<PAGE>


The following report is a copy of a report previously issued by Arthur Andersen
LLP, which has ceased operations, and has not been reissued by Arthur Andersen
LLP. Arthur Andersen LLP reported on such financial statements prior to the
restatements discussed in Note 11 for the application of Emerging Issues Task
Force Issue No. 00-10, "Accounting for Shipping and Handling Fees and Costs" and
certain disclosures relating to the adoption of Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities," as amended.

                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

     We have audited the accompanying consolidated balance sheets of The Houston
Exploration Company (a Delaware corporation and an indirect 67%-owned subsidiary
of KeySpan Corporation) and subsidiary, as of December 31, 2001 and 2000, and
the related consolidated statements of operations, stockholders' equity and
comprehensive income and cash flows for each of the three years in the period
ended December 31, 2001. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

     We conducted our audits in accordance with auditing standards generally
accepted in the United States. 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 consolidated financial statements referred to above
present fairly, in all material respects, the financial position of The Houston
Exploration Company and subsidiary, as of December 31, 2001 and 2000, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.

     As discussed in the Note 1 to the Consolidated Financial Statements, the
Company adopted Statement of Financial Accounting Standards No. 133, "Accounting
for Derivative Instruments and Hedging Activities, as amended", on January 1,
2001.

                                         ARTHUR ANDERSEN LLP

New York, New York
February 4, 2002



                                       F-3

<PAGE>


                         THE HOUSTON EXPLORATION COMPANY
                           CONSOLIDATED BALANCE SHEETS

<Table>
<Caption>
                                                                                                        DECEMBER 31,
                                                                                               ------------------------------
                                                                                                   2002              2001
                                                                                               ------------      ------------
                                                                                              (IN THOUSANDS, EXCEPT SHARE DATA)
<S>                                                                                            <C>               <C>
ASSETS:
Cash and cash equivalents ................................................................     $     18,031      $      8,619
Accounts receivable ......................................................................           81,313            43,847
Accounts receivable -- Affiliate .........................................................            3,106               635

Derivative financial instruments .........................................................               --            53,771

Inventories ..............................................................................            1,432             1,149
Prepayments and other ....................................................................            7,596             2,959
                                                                                               ------------      ------------
          Total current assets ...........................................................          111,478           110,980
Natural gas and oil properties, full cost method
  Unevaluated properties .................................................................           96,192           177,987
  Properties subject to amortization .....................................................        1,828,160         1,493,293
Other property and equipment .............................................................           10,699             8,265
                                                                                               ------------      ------------
                                                                                                  1,935,051         1,679,545
Less: Accumulated depreciation, depletion and amortization ...............................         (912,637)         (740,784)
                                                                                               ------------      ------------
                                                                                                  1,022,414           938,761
Other assets .............................................................................            4,924             9,351
                                                                                               ------------      ------------
          TOTAL ASSETS ...................................................................     $  1,138,816      $  1,059,092
                                                                                               ============      ============
LIABILITIES:
Accounts payable and accrued expenses ....................................................     $     78,175      $     76,666
Derivative financial instruments .........................................................           35,005                --
                                                                                               ------------      ------------

          Total current liabilities ......................................................          113,180            76,666
Long-term debt and notes .................................................................          252,000           244,000
Deferred federal income taxes ............................................................          175,963           172,169
Derivative financial instruments .........................................................            3,767                --
Other deferred liabilities ...............................................................            1,117               376
                                                                                               ------------      ------------
          TOTAL LIABILITIES ..............................................................          546,027           493,211
COMMITMENTS AND CONTINGENCIES (SEE NOTE 9)
STOCKHOLDERS' EQUITY:
Common Stock, $.01 par value, 50,000,000 shares authorized and 30,954,018 shares
   issued and outstanding at December 31, 2002 and
   30,463,230 shares issued and outstanding at December 31, 2001 .........................              310               305
Additional paid-in capital ...............................................................          353,454           336,977
Unearned compensation ....................................................................             (107)             (192)
Retained earnings ........................................................................          264,334           193,840
Accumulated other comprehensive income (loss) ............................................          (25,202)           34,951
                                                                                               ------------      ------------
          TOTAL STOCKHOLDERS' EQUITY .....................................................          592,789           565,881
                                                                                               ------------      ------------
          TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY .....................................     $  1,138,816      $  1,059,092
                                                                                               ============      ============
</Table>

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



                                      F-4

<PAGE>


                         THE HOUSTON EXPLORATION COMPANY
                      CONSOLIDATED STATEMENTS OF OPERATIONS


<Table>
<Caption>
                                                                           YEARS ENDED DECEMBER 31,
                                                                 -----------------------------------------------
                                                                     2002              2001             2000
                                                                 ------------      ------------     ------------
                                                                     (IN THOUSANDS, EXCEPT PER SHARE DATA)
                                                                                  As Restated
<S>                                                              <C>               <C>              <C>
REVENUES:
  Natural gas and oil revenues .............................     $    344,295      $    387,156     $    277,487
  Other ....................................................            1,086             1,353            1,738
                                                                 ------------      ------------     ------------
          Total revenues ...................................          345,381           388,509          279,225
OPERATING EXPENSES:
  Lease operating expense ..................................           33,976            25,291           23,553
  Severance tax ............................................            9,487            11,035            9,757
  Transportation expense ...................................            9,317             7,652            6,892
  Depreciation, depletion and amortization .................          171,610           128,736           89,239
  Writedown in carrying value of natural gas and oil
       properties ..........................................               --             6,170               --
  General and administrative, net ..........................           13,077            17,110            8,928
                                                                 ------------      ------------     ------------
          Total operating expenses .........................          237,467           195,994          138,369
Income from operations .....................................          107,914           192,515          140,856
Other (income) expense .....................................           (9,070)              119            1,752
Interest expense, net ......................................            7,398             2,992           11,361
                                                                 ------------      ------------     ------------
Income before income taxes .................................          109,586           189,404          127,743
Provision for federal income taxes .........................           39,092            66,803           42,485
                                                                 ------------      ------------     ------------
NET INCOME .................................................     $     70,494      $    122,601     $     85,258
                                                                 ============      ============     ============

Net income per share - basic ...............................     $       2.31      $       4.06     $       3.06
                                                                 ============      ============     ============
Net income per share - fully diluted .......................     $       2.28              4.00     $       3.02
                                                                 ============      ============     ============

Weighted average shares outstanding - basic ................           30,569            30,228           27,860
Weighted average shares outstanding - fully diluted ........           30,878            30,645           28,213
</Table>

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



                                      F-5

<PAGE>


                         THE HOUSTON EXPLORATION COMPANY
                 CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
                            AND COMPREHENSIVE INCOME
                        (IN THOUSANDS, EXCEPT SHARE DATA)

<Table>
<Caption>
                                                                                                                       ACCUMULATED
                                                         COMMON STOCK         ADDITIONAL                  RETAINED        OTHER
                                                    ------------------------   PAID-IN      UNEARNED      EARNINGS    COMPREHENSIVE
                                                      SHARES       $ VALUE     CAPITAL    COMPENSATION   (DEFICIT)    INCOME (LOSS)
                                                    ------------  ----------  ----------  ------------  ------------  -------------
<S>                                                 <C>           <C>         <C>         <C>           <C>           <C>
BALANCE JANUARY 1, 2000                               23,923,020  $      239  $ 231,370   $         --  $    (14,019)  $         --
Issuance of common stock, par value $0.01(1)(2)        5,906,030          59     93,835
Comprehensive Income:
   Net income                                                                                                 85,258

Total comprehensive income
                                                    ------------  ----------  ---------   ------------  ------------   ------------
BALANCE DECEMBER 31, 2000                             29,829,050  $      298  $ 325,205   $         --  $     71,239   $         --
Issuance of common stock, par value $0.01(1)             624,180           6     10,183
Issuance of restricted common stock,
   par value $0.01(3)                                     10,000           1        255           (256)
Amortization of restricted stock                                                                    64
Tax benefit from exercise of non-qualified
   Stock options                                                                  1,334
Comprehensive income:
   Net income                                                                                                122,601
   Other comprehensive income (as restated)(4):
      Cumulative effect of accounting change
         for derivative instruments, net of tax
         benefit of $26,274                                                                                                 (48,795)
      Derivative settlements reclassified to
         income, net of tax benefit of $4,524                                                                                (8,402)
      Unrealized gain due to change in fair value
         of derivative instruments, net of
         tax expense of $49,618                                                                                              92,148

Total comprehensive income
                                                    ------------  ----------  ---------   ------------  ------------   ------------
BALANCE DECEMBER 31, 2001                             30,463,230  $      305  $ 336,977   $       (192) $    193,840   $     34,951
Issuance of common stock, value $0.01(1)                 490,788           5      9,663
Contributed capital from KeySpan (5)                                              2,039
Amortization of restricted stock                                                                    85
Tax benefit from exercise of non-qualified
   stock options                                                                  4,775
Comprehensive income:
   Net income                                                                                                 70,494
   Other comprehensive income:
      Derivative settlements reclassified to
         income, net of tax benefit of $5,725                                                                               (10,633)
      Unrealized loss due to change in fair
         value of derivative instruments, net of
         tax benefit of $26,665                                                                                             (49,520)

Total comprehensive income
                                                    ------------  ----------  ---------   ------------  ------------   ------------
BALANCE DECEMBER 31, 2002                             30,954,018  $      310  $ 353,454   $       (107) $    264,334   $    (25,202)
                                                    ============  ==========  =========   ============  ============   ============

<Caption>

                                                         TOTAL
                                                      STOCKHOLDERS'
                                                         EQUITY
                                                      ------------
<S>                                                   <C>
BALANCE JANUARY 1, 2000                               $    217,590
Issuance of common stock, par value $0.01(1)(2)             93,894
Comprehensive Income:
   Net income                                               85,258
                                                      ------------
Total comprehensive income                                  85,258
                                                      ------------
BALANCE DECEMBER 31, 2000                             $    396,742
Issuance of common stock, par value $0.01(1)                10,189
Issuance of restricted common stock,
   par value $0.01(3)
Amortization of restricted stock                                64
Tax benefit from exercise of non-qualified
   Stock options                                             1,334
Comprehensive income:
   Net income                                              122,601
   Other comprehensive income (as restated)(4):
      Cumulative effect of accounting change
         for derivative instruments, net of tax
         benefit of $26,274                                (48,795)
      Derivative settlements reclassified to
         income, net of tax benefit of $4,524               (8,402)
      Unrealized gain due to change in fair value
         of derivative instruments, net of
         tax expense of $49,618                             92,148
                                                      ------------
Total comprehensive income                                 157,552
                                                      ------------
BALANCE DECEMBER 31, 2001                             $    565,881
Issuance of common stock, value $0.01(1)                     9,668
Contributed capital from KeySpan (5)                         2,039
Amortization of restricted stock                                85
Tax benefit from exercise of non-qualified
   stock options                                             4,775
Comprehensive income:
   Net income                                               70,494
   Other comprehensive income:
      Derivative settlements reclassified to
         income, net of tax benefit of $5,725              (10,633)
      Unrealized loss due to change in fair
         value of derivative instruments, net of
         tax benefit of $26,665                            (49,520)
                                                      ------------
Total comprehensive income                                  10,341
                                                      ------------
BALANCE DECEMBER 31, 2002                             $    592,789
                                                      ============
</Table>



                                      F-6


<PAGE>


----------

(1)  Common stock issued through the exercise of stock options. See Note 4 -
     Stock Option Plans.

(2)  Includes 5,085,177 shares issued on March 31, 2000 to our majority
     stockholder, KeySpan Corporation, pursuant to the conversion of $80 million
     in outstanding borrowings under a revolving credit facility with KeySpan.
     See Note 3 - Stockholders' Equity - KeySpan Credit Facility and Conversion.

(3)  Restricted stock issued to our President and Chief Executive Officer in
     April 2001 at $25.58 per share. See Note 6 - Related Party Transactions -
     Transactions with our Executives.

(4)  Comprehensive income for the year ended December 31, 2001 has been restated
     to present the individual components for 2001 in accordance with the
     disclosure requirements of Statement of Financial Accounting Standards No.
     133 "Accounting for Derivatives Instruments and Hedging Activities," as
     amended. See Note 11 - Restatements and Reclassifications - Adoption of
     SFAS No. 133.

(5)  Excess fair market value of oil and gas properties purchased from KeySpan
     in October 2002. See Note 6 - Related Party Transactions - Acquisition of
     KeySpan Joint Venture Assets.



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



                                      F-7

<PAGE>


                         THE HOUSTON EXPLORATION COMPANY
                      CONSOLIDATED STATEMENTS OF CASH FLOWS

<Table>
<Caption>
                                                                                        YEARS ENDED DECEMBER 31,
                                                                            ------------------------------------------------
                                                                                2002              2001                2000
                                                                            ------------      ------------      ------------
                                                                                              (IN THOUSANDS)
<S>                                                                         <C>               <C>               <C>

OPERATING ACTIVITIES:
Net income ............................................................     $     70,494      $    122,601      $     85,258
Adjustments to reconcile net income to net cash provided by
    operating activities:
  Depreciation, depletion and amortization ............................          171,610           128,736            89,239
  Writedown in carrying value of natural gas and oil properties .......               --             6,170                --
  Deferred income tax expense .........................................           39,860            67,643            43,303
  Stock compensation expense ..........................................               85                64                --
Changes in operating assets and liabilities:
  (Increase) decrease in accounts receivable ..........................          (39,937)           70,119           (67,369)
  (Increase) decrease in inventories ..................................             (283)              774              (954)
  Increase in prepayments and other ...................................           (4,637)           (1,046)             (831)
  Decrease (increase) in other assets .................................            4,427            (5,469)             (300)
  Increase in deferred liabilities ....................................              741               140                83
  Increase (decrease) in accounts payable and accrued expenses ........            1,509           (31,700)           52,362
                                                                            ------------      ------------      ------------
Net cash provided by operating activities .............................          243,869           358,032           200,791

INVESTING ACTIVITIES:
Investment in property and equipment ..................................         (257,436)         (368,277)         (184,512)
Dispositions and other ................................................            5,311                --                --
                                                                            ------------      ------------      ------------
Net cash used in investing activities .................................         (252,125)         (368,277)         (184,512)

FINANCING ACTIVITIES:
Proceeds from long-term borrowings ....................................           79,000           172,000            32,000
Repayments of long-term borrowings ....................................          (71,000)         (173,000)          (68,000)
Proceeds from issuance of common stock ................................            9,668            10,189            13,894
                                                                            ------------      ------------      ------------
Net cash provided by (used in) financing activities ...................           17,668             9,189           (22,106)

Increase (decrease) in cash and cash equivalents ......................            9,412            (1,056)           (5,827)

Cash and cash equivalents, beginning of year ..........................            8,619             9,675            15,502
                                                                            ------------      ------------      ------------

Cash and cash equivalents, end of year ................................     $     18,031      $      8,619      $      9,675
                                                                            ============      ============      ============

SUPPLEMENTAL INFORMATION:
Cash paid for interest ................................................     $     14,906      $     14,777      $     25,490
                                                                            ============      ============      ============

Cash (refund) payment of federal income taxes .........................     $       (400)     $        475      $         --
                                                                            ============      ============      ============
</Table>

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



                                       F-8


<PAGE>


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


NOTE 1 -- SUMMARY OF ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES

Organization

     We are an independent natural gas and oil company engaged in the
exploration, development, exploitation and acquisition of domestic natural gas
and oil properties. Our operations are focused in South Texas, in the Gulf of
Mexico and in the Arkoma Basin of Oklahoma and Arkansas.

     At December 31, 2002, our net proved reserves were 650 billion cubic feet
equivalent or Bcfe, with a present value, discounted at 10% per annum, of cash
flows before income taxes of $1.3 billion. Our reserves are fully engineered on
an annual basis by independent petroleum engineers. Our focus is natural gas.
Approximately 94% of our net proved reserves at December 31, 2002 were natural
gas, approximately 69% of which were classified as proved developed. We operate
approximately 85% of our properties.

     We began exploring for natural gas and oil in December 1985 on behalf of
The Brooklyn Union Gas Company. Brooklyn Union is an indirect wholly owned
subsidiary of KeySpan Corporation. KeySpan, a member of the Standard & Poor's
500 Index, is a diversified energy provider whose principal natural gas
distribution and electric generation operations are located in the Northeastern
United States. In September 1996 we completed our initial public offering and
sold approximately 31% of our shares to the public. As of December 31, 2002,
THEC Holdings Corp., an indirect wholly owned subsidiary of KeySpan, owned
approximately 66% of the outstanding shares of our common stock.

Principles of Consolidation

     The consolidated financial statements include our accounts and the accounts
of our wholly owned subsidiary, Seneca Upshur Petroleum Company. All significant
inter-company balances and transactions have been eliminated.

Use of Estimates

     The preparation of the consolidated financial statements in conformity with
accounting principals generally accepted in the United States of America
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. Our most significant
financial estimates are based on remaining proved natural gas and oil reserves.
Estimates of proved reserves are key components of our depletion rate for
natural gas and oil properties and our full cost ceiling test limitation. See
Note 12 - Supplemental Information on Natural Gas and Oil Exploration,
Development and Production Activities (Unaudited). Because there are numerous
uncertainties inherent in the estimation process, actual results could differ
from the estimates.

Business Segment Information

     SFAS No. 131, "Disclosures about Segments of an Enterprise and Related
Information" establishes standards for reporting information about operating
segments. Operating segments are defined as components of an enterprise that
engage in activities from which it may earn revenues and incur expenses.
Separate financial information is available and this information is regularly
evaluated by the chief decision maker for the purpose of allocating resources
and assessing performance. Segment reporting is not applicable for us as each of
our operating areas has similar economic characteristics and each meets the
criteria for aggregation as defined in paragraph 17 of SFAS No. 131. All of our
operations involve the exploration, development and production of natural gas
and oil and all of our operations are located in the United States. We have a
single, company-wide management team that administers all properties as a whole
rather than as discrete operating segments. We track only basic operational data
by area. We do not maintain separate financial statement information by area. We
measure financial performance as a single enterprise and not on an area-by-area
basis. Throughout the year, we freely allocate capital resources on a
project-by-project basis across our entire asset base to maximize profitability
without regard to individual areas or segments.



                                      F-9

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Net Income Per Share

     Basic earnings per share is calculated by dividing net income by the
weighted average number of shares of common stock outstanding during the period.
No dilution for any potentially dilutive securities is included. Fully diluted
earnings per share assumes the conversion of all potentially dilutive securities
and is calculated by dividing net income, as adjusted, by the sum of the
weighted average number of shares of common stock outstanding plus all
potentially dilutive securities.

     Under the requirements of the Financial Accounting Standards Board ("FASB")
Statement of Financial Accounting Standards ("SFAS") No. 128, our earnings per
share are as follows:

<Table>
<Caption>
                                                                                              YEARS ENDED DECEMBER 31,
                                                                                   ----------------------------------------------
                                                                                       2002             2001             2000
                                                                                   ------------     ------------     ------------
                                                                                       (IN THOUSANDS, EXCEPT PER SHARE DATA)
<S>                                                                                <C>              <C>              <C>
Net income ...................................................................     $     70,494     $    122,601     $     85,258
                                                                                   ============     ============     ============
Weighted average shares outstanding ..........................................           30,569           30,228           27,860
Add dilutive securities:
   Options ...................................................................              309              417              353
                                                                                   ------------     ------------     ------------
Total weighted average shares outstanding and dilutive securities ............           30,878           30,645           28,213
                                                                                   ============     ============     ============
Net income per share - basic .................................................     $       2.31     $       4.06     $       3.06
Net income per share - fully diluted .........................................     $       2.28     $       4.00     $       3.02
</Table>

     For the years ended December 31, 2002, 2001 and 2000, the calculation of
shares outstanding for fully diluted EPS does not include the effect of
outstanding stock options to purchase 1,880,029, 1,182,843 and 973,616 shares
respectively, because the exercise price of these shares was greater than the
average market price for the year, which would have an antidulitive effect on
EPS.

Natural Gas and Oil Properties

     Full Cost Accounting. We use the full cost method to account for our
natural gas and oil properties. Under full cost accounting, all costs incurred
in the acquisition, exploration and development of natural gas and oil reserves
are capitalized into a "full cost pool". Capitalized costs include costs of all
unproved properties, internal costs directly related to our natural gas and oil
activities and capitalized interest. We amortize these costs using a
unit-of-production method. We compute the provision for depreciation, depletion
and amortization quarterly by multiplying production for the quarter by a
depletion rate. The depletion rate is determined by dividing our total
unamortized cost base by net equivalent proved reserves at the beginning of the
quarter. Unevaluated properties and related costs are excluded from our
amortization base until we have made a determination as to the existence of
proved reserves. We review our unevaluated properties at the end of each quarter
to determine if the costs incurred should be reclassified to the full cost pool
and thereby subject to amortization. Our amortization base includes estimates
for future development costs as well as future abandonment and dismantlement
costs. Sales of natural gas and oil properties are accounted for as adjustments
to the full cost pool, with no gain or loss recognized, unless the adjustment
would significantly alter the relationship between capitalized costs and proved
reserves.

     Under full cost accounting rules, total capitalized costs are limited to a
ceiling of the present value of future net revenues, discounted at 10%, plus the
lower of cost or fair value of unproved properties less income tax effects (the
"ceiling limitation"). We perform a quarterly ceiling test to evaluate whether
the net book value of our full cost pool exceeds the ceiling limitation. If
capitalized costs (net of accumulated depreciation, depletion and amortization)
less deferred taxes are greater than the discounted future net revenues or
ceiling limitation, a writedown or impairment of the full cost pool is required.
A writedown of the carrying value of the full cost pool is a non-cash charge
that reduces earnings and impacts stockholders' equity in the period of
occurrence and typically results in lower depreciation, depletion and
amortization expense in future periods. Once incurred, a writedown is not
reversible at a later date. The ceiling test is calculated using natural gas and
oil prices in effect as of the balance sheet date, held flat over the life of
the reserves. We use derivative financial instruments that qualify for hedge
accounting under SFAS No. 133 to hedge against the volatility of natural gas
prices, and in accordance with current Securities and Exchange Commission
guidelines, we include estimated future cash



                                      F-10

<PAGE>


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


flows from our hedging program in our ceiling test calculation. In calculating
the ceiling test at December 31, 2001, we estimated, using a wellhead price of
$2.38 per Mcf, that our capitalized costs exceeded the ceiling limitation by
$6.2 million ($4.0 million after tax). As a result, we reduced or "wrote down"
the carrying value of our full cost pool and incurred a charge to earnings of
$6.2 million ($4.0 million, after tax). Natural gas prices continue to be
volatile and the risk that we will be required to writedown our full cost pool
increases when natural gas prices are depressed or if we have significant
downward revisions in our estimated proved reserves.

     In calculating our ceiling test at December 31, 2002 and 2000, we
estimated, using a wellhead price of $4.35 per Mcf and $9.55 per Mcf,
respectively, that we had a full cost ceiling "cushion" at each of the
respective balance sheet dates, whereby the carrying value of our full cost pool
was less that the ceiling limitation by $279.4 million (after tax) for 2002 and
$1.4 billion (after tax) for 2000. No writedown is required when a cushion
exists.

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

     Unevaluated Properties. The costs associated with unevaluated properties
and properties under development are not initially included in the amortization
base and relate to unproved leasehold acreage, seismic data, wells in-progress
and wells pending determination. Unevaluated leasehold costs are transferred to
the amortization base with the costs of drilling the related well or upon
expiration of a lease. Costs of seismic data are allocated to various unproved
leaseholds and transferred to the amortization base with the associated
leasehold costs on a specific project basis. Costs associated with wells
in-progress and wells pending determination are transferred to the amortization
base once a determination is made whether or not proved reserves can be assigned
to the property. Costs of dry holes are transferred to the amortization base
immediately upon determination that the well is unsuccessful. All items included
in our unevaluated property balance are assessed on a quarterly basis for
possible impairment or reduction in value. Of the $96.2 million of unevaluated
property costs at December 31, 2002 that have been excluded from the
amortization base, $38.8 million were incurred during 2002; $28.2 million were
incurred in 2001, $6.9 million were incurred in 2000 and $22.3 million were
incurred prior to 2000. At December 31, 2001, of the $178.0 million of
unevaluated property costs, $72.5 million, $20.3 million and $17.0 million were
incurred in 2001, 2000 and 1999, respectively, and $68.2 million was incurred
prior to 1998. We estimate these costs will be evaluated within a four-year
period.

Cash and Cash Equivalents

     We consider all highly liquid short-term investments with original
maturities of 90 days or less to be cash equivalents.

Other Property and Equipment

     Other property and equipment includes 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 computer
equipment and other office equipment which are recorded at cost and depreciated
using the straight-line method over estimated useful lives ranging between two
to five years.



                                      F-11

<PAGE>


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Income Taxes

     We determine deferred taxes 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

     o    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

     o    provisions for depreciation and amortization for financial reporting
          purposes that differ from those used for income tax reporting
          purposes.

Inventories

     Inventories consist primarily of tubular goods used in our operations and
are stated at the lower of the specific cost of each inventory item or market
value.

General and Administrative Costs and Expenses

     Under the full cost method of accounting, certain costs are capitalized
that are directly identified with acquisition, exploration and development
activities. These capitalized costs include salaries, employee benefits, costs
of consulting services and other specifically identifiable costs and do not
include costs related to production operations, general corporate overhead or
similar activities. We capitalized general and administrative costs directly
related to our acquisition, exploration and development activities, during 2002,
2001 and 2000, of $13.2 million, $12.8 million and $9.6 million, respectively.
We receive reimbursement for administrative and overhead expenses incurred on
behalf of other working interest owners on properties we operate. These
reimbursements totaling $1.8 million, $1.2 million, and $3.6 million for the
years ended December 31, 2002, 2001 and 2000, respectively, were allocated as
reductions to general and administrative expenses incurred. Included in
reimbursements received during 2000 are general and administrative
reimbursements received from KeySpan pursuant to the joint exploration agreement
with KeySpan, (see Note 6 - Related Party Transactions - KeySpan Joint Venture)
of $2.5 million Generally, we do not receive any excess of reimbursements or
fees over the costs incurred; however, if we did, we would credit the excess to
the full cost pool to be recognized through lower cost amortization as
production occurs.

Capitalization of Interest

     We capitalize interest related to our unevaluated natural gas and oil
properties and some properties under development which are not currently being
amortized. For the years ended December 31, 2002, 2001 and 2000, we capitalized
interest costs of $8.0 million, $12.0 million, $13.7 million, respectively.

Revenue Recognition and Gas Imbalances

     We use the entitlements method of accounting for the recognition of natural
gas and oil revenues. Under this method of accounting, income is recorded based
on our net revenue interest in production or nominated deliveries. We incur
production gas volume imbalances in the ordinary course of business. Net
deliveries in excess of entitled amounts are recorded as liabilities, while net
under deliveries are reflected as assets. Imbalances are reduced either by
subsequent recoupment of over-and under deliveries or by cash settlement, as
required by applicable contracts. Production imbalances are marketed-to-market
at the end of each month using market prices as of the end of the period. Our
production imbalances represented a net asset of $33,000 at December 31, 2002
and a net liability of $376,000 at December 31, 2001, respectively.

Financial Instruments

     The estimated fair value of financial instruments is the amount at which
the instrument could be exchanged currently between willing parties. On the
balance sheet, we report cash and cash equivalents, accounts receivable and
accounts payable at cost or carrying value, which approximates fair value due to
the short maturity of these instruments. See Note 2 - Long-term Debt and Notes
for fair value of our debt. Pursuant to our adoption of SFAS No. 133 on January
1, 2001, our derivative financial instruments are reported on the balance sheet
at fair market value.



                                      F-12

<PAGE>


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Hedging Contracts

     We utilize derivative commodity instruments to hedge future sales prices on
a portion of our natural gas production in order to achieve a more predictable
cash flow and to reduce our exposure to adverse price fluctuations. Our
derivatives are not held for trading purposes. While the use of hedging
arrangements limits the downside risk of adverse price movements, it also limits
increases in future revenues from possible favorable price movements. Hedging
instruments that we use include swaps, costless collars and options, which we
generally place with major financial institutions that we believe are minimal
credit risks. Our hedging strategies meet the criteria for hedge accounting
treatment under SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities". Accordingly, we mark-to-market our derivative instruments at the
end of each quarter, and defer the effective portion of the gain or loss on the
change in fair value of our derivatives in accumulated other comprehensive
income, a component of stockholders' equity. We recognize gains and losses when
the underlying transaction is completed, at which time these gains and losses
are reclassified from accumulated other comprehensive income and included in
earnings as a component of natural gas revenues in accordance with the
underlying hedged transaction. If hedging instruments cease to meet the criteria
for deferred recognition, any gains or losses would be currently recognized in
earnings. See Note 7 -- Hedging Contracts summary of our derivative contracts
and the fair market value of those contracts as of December 31, 2002 and 2001.

Concentration of Credit Risk

     Substantially all of our 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
our overall credit risk in that these entities may be similarly affected by
changes in economic and other conditions. Historically, we have not experienced
credit losses on these receivables, however, recent market conditions resulting
in downgrades to credit ratings of energy merchants have affected the liquidity
of several of our purchasers. During the third quarter of 2002, we discontinued
selling our natural gas and oil to several energy merchants that received
downgrades to their credit ratings. We are continuing to sell gas to companies
that have posted letters of credit to secure their performance under the
purchase contracts. We have not experienced credit loss from any of these
purchasers. Based on the current demand for natural gas and oil, we do not
expect that termination of sales to previous purchasers would have a material
adverse effect on our ability to sell our production at favorable market prices.

     Further, our natural gas futures and swap contracts also expose us to
credit risk in the event of nonperformance by counterparties. Generally, these
contracts are with major investment grade financial institutions and
historically we have not experienced material credit losses. We believe that our
credit risk related to the natural gas futures and swap contracts is no greater
than the risk associated with the primary contracts and that the elimination of
price risk reduces volatility in our reported results of operations, financial
position and cash flows from period to period and lowers our overall business
risk; but, as a result of our hedging activities we may be exposed to greater
credit risk in the future.

Stock Options

     Historically, we have accounted for stock-based compensation using the
intrinsic value method prescribed in Accounting Principles Board ("APB") Opinion
No. 25, "Accounting for Stock Issued to Employees," and related interpretations.
Accordingly, compensation cost for stock options is measured as the excess, if
any, of the fair value of common stock at the date of the grant over the amount
the employee must pay to acquire the common stock. If the exercise price of a
stock option is equal to the fair market value at the time of grant, no
compensation expense is incurred. See Note 4 -- Employee Benefit and Stock Plans
-- Fair Value of Employee Stock-Based Compensation for disclosure had stock
options been accounted for based upon the fair value provisions of the SFAS No.
123, as amended, "Accounting for Stock-Based Compensation." On January 1, 2003,
we adopted the fair value expense recognition provisions of SFAS No. 123 as
amended by SFAS No. 148, "Accounting for Stock-Based Compensation - Transition
and Disclosure." SFAS No. 148 proposes three alternatives transition methods for
adopting the fair value method under SFAS No. 123:

     o    Prospective Method - recognize fair value expense for all awards
          granted in the year of adoption but not previous awards;

     o    Modified Prospective Method - recognize fair value expense for the
          unvested portion of all stock options granted, modified, or settled
          since 1994 (i.e., the unvested portion of the prior awards or those
          granted in the year of adoption must be recorded using the fair value
          method); and

     o    Retroactive Restatement Method - similar to the Modified Prospective
          Method except that all prior periods are restated.



                                      F-13

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


We adopted SFAS No. 123 using the Prospective Method and as a result will record
as compensation expense the fair value of all stock options issued subsequent to
January 1, 2003. We do not expect the adoption of the provisions of SFAS No. 123
to have a material impact on our financial position, results of operations or
cash flows.

New Accounting Pronouncements

     SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and
Intangible Assets," became effective on July 1, 2001 and January 1, 2002,
respectively. These new standards emphasize a more precise evaluation of assets
and clarify that more assets should be distinguished and classified between
tangible and intangible. We understand that the issue is under evaluation as to
whether provisions of SFAS No. 141 and SFAS No. 142 may call for mineral rights
held under lease or other contractual arrangements to be classified in the
balance sheet as intangible assets together with cash costs of oil and gas
leasehold interests acquired. The issue is under review, because it is believed
that no oil and gas exploration and production company was known to have changed
their tangible asset balance sheet classification of mineral rights or leasehold
costs upon adopting of SFAS Nos. 141 and 142, including us. If these types of
leasehold costs (both proved and unevaluated) are determined to be intangible
assets, they would be classified separately from oil and natural gas properties
as intangible assets on our balance sheets. This issue relates only to balance
sheet classification and presentation and will not have an effect on cash flows
or results of operations. For the years ended December 31, 2002 and 2001, $161.0
million and $81.9 million, respectively, would be reclassified from tangibles to
intangibles representing costs incurred, net of accumulated amortization, since
June 30, 2001, the effective date of SFAS No. 141. We will continue to classify
our oil and gas leasehold costs as tangible oil and natural gas properties until
further guidance is provided.

     SFAS No. 143, "Accounting for Asset Retirement Obligations," addresses
accounting and reporting for obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement costs. SFAS No.
143 takes effect January 1, 2003. SFAS No. 143 requires that the fair value of a
liability for an asset's retirement obligation be recorded in the period in
which it is incurred and the corresponding cost capitalized by increasing the
carrying amount of the related long-lived asset. The liability is accreted to
its then present value each period, and the capitalized cost is depreciated over
the useful life of the related asset. If the liability is settled for an amount
other than the recorded amount, a gain or loss is recognized. For all periods
presented, we have included estimated future costs of abandonment and
dismantlement in our full cost amortization base and amortize these costs as a
component of our depletion expense.

     We have completed our assessment of SFAS No. 143. At December 31, 2002, we
estimate that the present value of our future Asset Retirement Obligation
("ARO") for natural gas and oil property and related equipment is approximately
$57 million. We estimate that the cumulative effect of our adoption of SFAS No.
143 and the change in accounting principle will be a charge to net income during
the first quarter of 2003 of $4.3 million, $2.8 million net of taxes.

     In April 2002 the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, No. 44, and No. 64, Amendment to FASB Statement No. 13 and Technical
Corrections." SFAS No. 145 streamlines the reporting of debt extinguishments and
requires that only gains and losses from extinguishments meeting the criteria in
Accounting Policies Board Opinion 30 would be classified as extraordinary. Thus,
gains or losses arising from extinguishments that are part of a company's
recurring operations would not be reported as an extraordinary item. SFAS No.
145 is effective for fiscal years beginning after May 15, 2002. At this time, we
do not expect the adoption of SFAS No. 145 to have a material impact on our
financial position, results of operations or cash flows.

     SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal
Activities" was issued in June 2002 and addresses accounting and reporting for
costs associated with exit or disposal activities and nullifies Emerging Issues
Task Force ("EITF") Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring)." SFAS No. 146 requires that a liability for
a cost associated with an exit or disposal activity be recognized when the
liability is incurred. Under Issue 94-3, a liability for an exit cost was
recognized at the date of an entity's commitment to an exit plan. Under SFAS No.
146, the objective for initial measurement of the liability is fair value. SFAS
No. 146 is effective for exit or disposal activities that are initiated after
December 31, 2002. At this time, we do not expect that the adoption of SFAS No.
146 to have a material impact on our financial position, results of operations
or cash flows.

     SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and
Disclosure" was issued in December 2002 and the transition guidance and annual
disclosure provisions are effective for us for the year ended December 31, 2002.
SFAS No. 148 amends SFAS Statement No. 123, "Accounting for Stock Based
Compensation" and provides alternative



                                      F-14
<PAGE>


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

methods of transition for a voluntary change to the fair value method of
accounting for stock-based employee compensation. In addition, the statement
amends the disclosure requirements of SFAS No. 123 to require prominent
disclosures in both annual and interim financial statements about the method of
accounting for stock-based compensation and the effect of the method used. We
adopted SFAS No. 148 for 2002 and on January 1, 2003, we adopted the fair value
expense recognition provisions of SFAS No. 123 on a prospective basis and as a
result, we will record as compensation expense the fair value of all stock
options issued subsequent to January 1, 2003.



                                      F-15
<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


NOTE 2 -- LONG-TERM DEBT AND NOTES

<Table>
<Caption>
                                                                                                 DECEMBER 31,
                                                                                         -----------------------------
                                                                                             2002             2001
                                                                                         ------------     ------------
                                                                                                 (IN THOUSANDS)
<S>                                                                                      <C>              <C>
 SENIOR DEBT:
 Revolving bank credit facility, due July 15, 2005 .................................     $    152,000     $    144,000
 SUBORDINATED DEBT:
 8 5/8% Senior Subordinated Notes, due January 1, 2008 .............................          100,000          100,000
                                                                                         ------------     ------------
       Total long-term debt and notes ..............................................     $    252,000     $    244,000
                                                                                         ============     ============
</Table>

     The carrying amount of borrowings outstanding under the revolving bank
credit facility approximates fair value as the interest rates are tied to
current market rates. At December 31, 2002, the quoted market value of the
Company's $100 million of 8?% Senior Subordinated Notes was 103.8% of the $100
million carrying value or $103.8 million.

     Principle payments due over the next five year period and thereafter are as
follows.

<Table>
<Caption>
                                                                                                                      THEREAFTER
                                         2003            2004           2005            2006            2007             2008
                                     ------------    ------------   ------------    ------------    ------------     ------------
<S>                                  <C>             <C>            <C>             <C>             <C>              <C>
Revolving bank credit facility ....  $         --    $         --   $    152,000    $         --    $         --     $         --
85/8% senior Subordinated Notes ...            --              --             --              --              --          100,000
                                     ------------    ------------   ------------    ------------    ------------     ------------
      Total maturities ............  $         --    $         --   $    152,000    $         --    $         --     $    100,000
                                     ============    ============   ============    ============    ============     ============
</Table>

Credit Facility

     New Credit Facility. We entered into a new revolving bank credit facility,
dated as of July 15, 2002 with a syndicate of lenders led by Wachovia Bank,
National Association, as issuing bank and administrative agent, The Bank of Nova
Scotia and Fleet National Bank as co-syndication agents and BNP Paribas as
documentation agent. The new credit facility replaced our previous $250 million
revolving bank credit facility, and provides us with an initial commitment of
$300 million. The initial $300 million commitment may be increased at our
request and with prior approval from Wachovia to a maximum of $350 million by
adding one or more lenders or by allowing one or more lenders to increase their
commitments. The new credit facility is subject to borrowing base limitations
and the borrowing base has been set at $300 million. Our borrowing base will be
redetermined semi-annually, with the next redetermination scheduled for April 1,
2003. Up to $25 million of the borrowing base is available for the issuance of
letters of credit. The new credit facility matures July 15, 2005 , is unsecured
and with the exception of trade payables, ranks senior to all of our existing
debt. Following the closing of the new revolving credit facility on July 18,
2002, funds were drawn on the new facility and used to repay total outstanding
borrowings under the previous credit facility of $170 million. At December 31,
2002, $152 million in borrowings were outstanding under the new revolving credit
facility and $0.4 million was outstanding in letter of credit obligations.

     Interest is payable on borrowings under our revolving bank credit facility,
as follows:

     o    on base rate loans, at a fluctuating rate, or base rate, equal to the
          sum of (a) the greater of the Federal funds rate plus .5% or
          Wachovia's prime rate plus (b) a variable margin between 0% and 0.50%,
          depending on the amount of borrowings outstanding under the credit
          facility, or

     o    on fixed rate loans, a fixed rate equal to the sum of (a) a quoted
          LIBOR rate divided by one minus the average maximum rate during the
          interest period set for certain reserves of member banks of the
          Federal Reserve System in Dallas, Texas plus (b) a variable margin
          between 1.25% and 2.00%, depending on the amount of borrowings
          outstanding under the credit facility.

Interest is payable on base rate loans on the last day of each calendar quarter.
Interest on fixed rate loans is generally payable at maturity or at least every
90 days if the term of the loan exceeds three months. In addition to interest,
we must pay a quarterly commitment fee of between 0.30% and 0.50% per annum on
the unused portion of the borrowing base.



                                      F-16
<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     Our revolving bank credit facility contains negative covenants that place
restrictions and limits on, among other things, the incurrence of debt,
guaranties, liens, leases and certain investments. The credit facility also
restricts and limits our ability to pay cash dividends, to purchase or redeem
our stock and to sell or encumber our assets. Financial covenants require us to,
among other things:

     o    maintain a ratio of earnings before interest, taxes, depreciation,
          depletion and amortization (EBITDA) to cash interest payments of at
          least 3.00 to 1.00;

     o    maintain a ratio of total debt to EBITDA of not more than 3.50 to
          1.00; and

     o    not hedge more than 70% of our natural gas production during any
          12-month period

As of December 31, 2002, we were in compliance with all covenants.

     Previous Credit Facility. We maintained our previous revolving bank credit
facility with a syndicate of lenders led by JPMorgan Chase, National
Association. The credit facility, as amended, provided a maximum commitment of
$250 million, subject to borrowing base limitations. Our borrowing base amount
was $250 million prior to repayment. Up to $2.0 million of the borrowing base
was available for the issuance of letters. The credit facility was due to mature
on April 15, 2003 and was unsecured.

Interest was payable on borrowings under the previous credit facility as
follows:

     o    on base rate loans, at a fluctuating rate, or base rate, equal to the
          greater of the Federal Funds rate plus 0.5% or JP Morgan Chase's prime
          rate, or

     o    on fixed rate loans, a fixed rate equal to a quoted LIBOR rate plus a
          variable margin of 0.875% to 1.625%, depending on the amount
          outstanding under the credit facility.

Interest was payable 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. In
addition, the credit facility required a commitment fee of:

     o    between 0.25% and 0.375% per annum on the unused portion of the
          designated borrowing base, and

     o    an additional fee equal to 33% of the commitment fee on the daily
          average amount by which the total amount of commitments exceeds the
          designated borrowing base.

Senior Subordinated Notes

     On March 2, 1998, we issued $100 million of 8?% senior subordinated notes
due January 1, 2008. The notes bear interest at a rate of 8?% per annum with
interest payable semi-annually on January 1 and July 1. We may redeem the notes
at our option, in whole or in part, at any time on or after January 1, 2003 at a
price equal to 100% of the principal amount plus accrued and unpaid interest, if
any, plus a specified premium which decreases yearly from 4.313% in 2003 to 0%
in 2006. Upon the occurrence of a change of control, we will be required to
offer to purchase the notes at a purchase price equal to 101% of the aggregate
principal amount, plus accrued and unpaid interest, if any. A "change of
control" is:

     o    the direct or indirect acquisition by any person, other than KeySpan
          or its affiliates, of beneficial ownership of 35% or more of total
          voting power as long as KeySpan and its affiliates own less than the
          acquiring person;

     o    the sale, lease, transfer, conveyance or other disposition, other than
          by way of merger or consolidation, in one or a series of related
          transactions, of all or substantially all of our assets to a third
          party other than KeySpan or its affiliates;

     o    the adoption of a plan relating to our liquidation or dissolution; or

     o    if, during any period of two consecutive years, individuals who at the
          beginning of this period constituted our board of directors, including
          any new directors who were approved by a majority vote of the
          stockholders, cease for any reason to constitute a majority of the
          members then in office.

The notes are general unsecured obligations and rank subordinate in right of
payment to all existing and future senior debt, including the credit facility,
and will rank senior or equal in right of payment to all existing and future
subordinated indebtedness.



                                      F-17
<PAGE>


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


NOTE 3 -- STOCKHOLDERS' EQUITY

KeySpan Credit Facility and Conversion

     On March 31, 2000, we converted $80 million of borrowings that were
outstanding under a revolving credit facility with KeySpan into 5,085,177 shares
of our common stock at a conversion price of $15.732 per share. The revolving
credit facility was entered into in November 1998 to fund the acquisition of our
Mustang Island A31/32 Field. Upon conversion on March 31, 2000, KeySpan's
ownership interest in our company increased from 64% to 70%. At December 31,
2002 KeySpan's ownership in our company was 66% with the decrease attributable
to an increase in our common shares outstanding due to the exercise of stock
options subsequent to the conversion transaction. The conversion price was
determined based upon the average of the closing prices of our common stock,
rounded to three decimal places, as reported under "NYSE Composite Transaction
Reports" in the Wall Street Journal during the 20 consecutive trading days
ending three trading days prior to March 31, 2000. The conversion of the
revolving credit facility and the corresponding issuance of additional shares of
our common stock to KeySpan was approved by our stockholders at our annual
meeting held April 27, 1999. Borrowings under the facility bore interest at
LIBOR plus 1.4% and we incurred a quarterly commitment fee of 0.125% on the
unused portion of the maximum commitment. The credit facility terminated on
March 31, 2000. For the year ended December 31, 2000, we incurred $1.5 million
in interest and fees to KeySpan.

NOTE 4 -- EMPLOYEE BENEFIT AND STOCK AND OPTION PLANS

Deferred Compensation Plan

     In November 2002, our Board of Directors adopted a deferred compensation
plan for the benefit of our employees. The plan is intended to supplement our
401(k) plan by allowing highly compensated employees to save on a tax deferred
basis a portion of their eligible compensation subject to limitations imposed by
the plan. Under the terms of the plan, employees who have made the maximum
allowable contribution to their 401(k) accounts for any year ($11,000 per year
or $12,000 per year for employees over 50 years of age for 2002) may elect to
defer an additional portion of their compensation into the deferred compensation
plan. We match 100% of each employee's deferral up to an aggregate contribution
of 12.5% under both the 401(k) plan and the deferred compensation plan. During
2002, we made matching contributions totaling $0.5 million to the deferred
compensation plan. Employer contributions vest 20% per year and become fully
vested after a 5 year period. All contributions to the plan are held in trust
and invested, at the direction of the employee, in various investment funds,
including company stock. Participants are entitled to distribution of their
deferrals and the vested portion of our matching contributions at predetermined
future dates or upon termination of their employment.

401(k) Profit Sharing Plan

     We maintain a 401(k) Profit Sharing Plan for our employees. Under the
401(k) plan, eligible employees may elect to have us contribute on their behalf
up to 12.5% of their base compensation (subject to limitations imposed under the
Internal Revenue Code of 1986, as amended) on a before tax basis. We make a
matching contribution of $1.00 for each $1.00 of employee deferral, subject to
limitations imposed by the 401(k) plan and the Internal Revenue Service. The
amounts contributed under the 401(k) plan are held in a trust and invested among
various investment funds, including the Company's common stock, in accordance
with the directions of each participant. An employee's salary deferral
contributions under the 401(k) plan are 100% vested. Our 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. We made
contributions to the 401(k) plan of $0.7 million, 0.7 million, and $0.6 million,
respectively, for the years ended December 31, 2002, 2001 and 2000.

Supplemental Executive Retirement Plan

     We maintain an unfunded, non-qualified Supplemental Executive Retirement
Plan. Currently, the only beneficiary is our former President and Chief
Executive Officer, James G. Floyd. Upon Mr. Floyd's retirement March 31, 2001,
he became entitled to receive payment of $100,000 per year for life. If Mr.
Floyd predeceases his spouse, 50% of his retirement plan benefit will continue
to be paid to his surviving spouse for her life. We incurred expenses of
approximately $105,000, $113,000, and $123,000, respectively, during the years
ended December 31, 2002, 2001 and 2000 related to this retirement plan. Annual
expense incurred is greater than annual distribution due to the actuarial
estimate of the future liability.



                                      F-18
<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Employee Annual Incentive Compensation Plan

     We maintain an Annual Incentive Compensation Plan that provides an annual
incentive bonus to all full-time employees if certain performance goals are met
during the year. The plan is administered by our Chief Executive Officer on
behalf of our Board of Directors and the Compensation Committee. Annual
objectives and incentive opportunity levels are established and approved by the
Compensation Committee. Incentive awards are earned based on our actual
performance in relation to pre-established objectives and on an assessment of
individual contribution during the year.

Incentive Compensation Plan for Non-Employee Directors

     We maintain an incentive compensation plan for non-employee, non-affiliated
directors, which was adopted by our Board of Directors in October 1997 and under
which participants may defer current compensation in the form of phantom stock
rights that are tied to the market price of the common stock on the date
services are performed. Phantom stock rights are exchanged for a cash
distribution upon retirement.

Stock and Option Plans

     We have three stock options plans, together our ("Stock Plans"): (i) 1996
Stock Option Plan which was adopted at the completion of our initial public
offering in September 1996, amended and approved by the stockholders in 1997;
(ii) 1999 Non-Qualified Stock Option Plan adopted by our Board of Directors in
October 1999; and (iii) 2002 Long-Term Incentive Plan adopted in January 2002
and approved by the stockholders in May 2002. All our employees, directors,
consultants and advisors are eligible to participate in our Stock Plans, with
the exception of executive officers who are not eligible to participate in the
1999 Plan. Options granted under our Stock Plans expire 10 years from the grant
date and vest in one-fifth increments on each of the first five anniversaries of
the grant date, with the exception of options granted to non-employee directors
whose options vest immediately upon grant. All grants are made at the closing
price of our common stock as reported on the NYSE on the date of grant. The 1996
and 2002 Plans allow for the grant of both incentive stock options and
non-qualified stock options. Common stock issued through the exercise of
non-qualified options will result in a tax deduction for us which is equal to
the taxable gain recognized by the optionee. Generally, we will not receive an
income tax deduction for incentive based options. In addition to stock options,
the 2002 Plan allows for the grant of restricted stock. In addition to stock
options, the 2002 Plan currently has 300,000 shares reserved for the grant of
restricted stock. As of December 31, 2002, no grants of restricted stock have
been made under the 2002 Plan.

     The table below summarizes all our Stock Plans at December 31, 2002.

<Table>
<Caption>
                                                     2002 PLAN      1999 PLAN      1996 PLAN     TOTAL PLANS
                                                     ----------     ----------     ----------    -----------
<S>                                                  <C>            <C>            <C>           <C>
Options authorized .............................      1,500,000        800,000      3,033,912      5,333,912
Options granted
      Incentive stock options ..................         33,268             --      1,032,302      1,065,570
      Non-qualified stock options ..............        560,682        799,434      2,001,281      3,361,397
                                                     ----------     ----------     ----------     ----------
           Total grants ........................        593,950        799,434      3,033,583      4,426,967
                                                     ----------     ----------     ----------     ----------
Options available for grant ....................        906,050            566            329        906,945
                                                     ==========     ==========     ==========     ==========

Total exercised ................................             --         85,910      1,919,391      2,005,301
                                                     ==========     ==========     ==========     ==========
</Table>



                                      F-19
<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     The table below sets forth a summary of activity during the respective
years for all of our stock option plans.

<Table>
<Caption>
                                                                         YEARS ENDED DECEMBER 31,
                                               --------------------------------------------------------------------------------
                                                         2002                       2001                        2000
                                               -------------------------   -------------------------   ------------------------
                                                 SHARES         PRICE(1)     SHARES         PRICE(1)     SHARES       PRICE(1)
                                               ----------      ---------   ----------      ---------   ----------    ----------
<S>                                            <C>             <C>         <C>             <C>         <C>           <C>
Options outstanding January 1 ...............   2,164,448      $   24.81    1,660,745      $   17.99    2,380,058    $    17.41
  Granted ...................................     754,059          30.14    1,129,871          30.15      106,000         22.71
  Exercised .................................    (490,788)         19.70     (624,180)         16.32     (820,853)        16.93
  Forfeited .................................      (6,053)         27.77       (1,988)         29.02       (4,460)        18.83
                                               ----------                  ----------                  ----------
Options outstanding December 31 .............   2,421,666      $   27.50    2,164,448      $   24.81    1,660,745    $    17.99
                                               ==========                  ==========                  ==========

Options exercisable December 31 .............     848,103      $   25.12      940,929      $   21.83      721,654    $    17.43

Options available for grant December 31 .....     906,945                     155,451                     682,698
</Table>

----------

(1)  Weighted average price. Grant price equal to closing market price on the
     NYSE on date of grant.

     The table below sets forth a summary of options granted and outstanding,
their remaining contractual lives, a weighted average exercise price and the
number vested and exercisable as of December 31, 2002.

<Table>
<Caption>
                            Options Outstanding                                      Options Exercisable/Vested      Unvested
------------------------------------------------------------------------------     ------------------------------   ------------
                        Shares                    Remaining        Weighted           Shares          Weighted         Shares
    Range of         Underlying         Year     Contractual        Average         Underlying        Average       Underlying
 Exercise Prices       Options        Granted        Life       Exercise Price       Options       Exercise Price     Options
----------------    -----------      ---------   -----------    --------------     -----------     --------------   ------------
<S>                 <C>              <C>         <C>            <C>                <C>             <C>              <C>
$15.50 - $ 17.25        105,847         1996       4 years         $  15.53            105,847          $ 15.53             --
$13.13 - $ 25.00        123,500         1997       5 years            19.90            123,500            19.90             --
$15.75 - $ 23.38        116,664         1998       6 years            19.10             70,386            18.84         46,278
$16.94 - $ 21.00        175,926         1999       7 years            18.94            112,446            19.05         63,480
$18.00 - $ 26.19         85,800         2000       8 years            22.65             47,100            23.22         38,700
$22.50 - $ 37.38      1,060,379         2001       9 years            30.44            360,824            32.73        699,555
$27.49 - $ 33.75        753,550         2002       10 years           30.14             28,000            29.58        725,550

                   ------------                                    --------        -----------         --------    -----------
                      2,421,666                                    $  27.50            848,103         $  25.12      1,573,563
</Table>

     Common stock issued through the exercise of non-qualified stock options
results in a tax deduction for us that is equivalent to the compensation income
recognized by the option holder. For financial reporting purposes, the tax
effect of this deduction is accounted for as a credit to additional
paid-in-capital rather than as a reduction of income tax expense. The exercise
of stock options during 2002 and 2001 resulted in a deferred tax benefit to us
of approximately $4.8 million and $1.3 million for, respectively, with no
deduction in 2000.



                                      F-20
<PAGE>


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Fair Value of Employee Stock-Based Compensation

     We account for the incentive stock plans using the intrinsic value method
prescribed under Accounting Principles Board No. 25 and accordingly we have not
recognized compensation expense for stock options granted. Had stock options
been accounted for using the fair value method as recommended in SFAS No. 123,
compensation expense would have had the following pro forma effect on our net
income and earnings per share for the years ended December 31, 2002, 2001 and
2000.

<Table>
<Caption>
                                                                                              YEARS ENDED DECEMBER 31,
                                                                                  ------------------------------------------------
                                                                                      2002              2001              2000
                                                                                  ------------      ------------      ------------
                                                                                         (IN THOUSANDS, EXCEPT PER SHARE DATA)
<S>                                                                               <C>               <C>               <C>
Net income - as reported ....................................................     $     70,494      $    122,601      $      5,258
Add:  Stock-based compensation expense included in
          Net income, net of tax ............................................               55                42                --
Less:  Stock-based compensation expense determined
          using fair value method, net of tax ...............................           (3,502)           (3,894)           (3,560)
                                                                                  ------------      ------------      ------------
Net income  - pro forma .....................................................     $     67,047      $    118,779      $     81,698
                                                                                  ============      ============      ============

Net income per share - as reported ..........................................     $       2.31      $       4.06      $       3.06
Net income per share - fully diluted - as reported ..........................             2.28              4.00              3.02
Net income per share - pro forma ............................................     $       2.19      $       3.93      $       2.97
Net income per share - fully diluted - pro forma ............................     $       2.17              3.88              2.93
</Table>

The effects of applying SFAS No. 123 in this pro forma disclosure may not be
representative of future amounts. The weighted average fair values of options at
their grant date during 2002, 2001 and 2000, where the exercise price equaled
the market price on the grant date were $14.08, $13.45, and $10.22,
respectively. The fair value of each option grant was estimated on the date of
grant using the Black-Scholes option pricing model with the following
assumptions used for grants in 2002, 2001 and 2000:

<Table>
<Caption>
                                                                               YEARS ENDED DECEMBER 31,
                                                                         ---------------------------------------
                                                                            2002           2001          2000
                                                                         ----------     ----------    ----------
<S>                                                                      <C>            <C>           <C>
Risk-free interest rate............................................         4.59%          5.80%         5.91%
Expected years until exercise......................................            5              5             5
Expected stock volatility..........................................           46%            41%           41%
Expected dividends.................................................           --             --            --
</Table>



                                      F-21

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


NOTE 5 -- INCOME TAXES

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

<Table>
<Caption>
                                                                                               YEARS ENDED DECEMBER 31,
                                                                                     ------------------------------------------
                                                                                        2002            2001            2000
                                                                                     ----------      ----------      ----------
                                                                                                   (IN THOUSANDS)
<S>                                                                                  <C>             <C>             <C>
 Current .......................................................................           (768)     $     (840)     $     (818)
 Deferred ......................................................................         39,860          67,643          43,303
                                                                                     ----------      ----------      ----------
    Total ......................................................................     $   39,092      $   66,803      $   42,485
                                                                                     ==========      ==========      ==========
</Table>

     The credit in the current provision primarily represents Section 29 tax
credits (see Note 6--Related Party Transactions - Section 29 Tax Credits). As of
December 31, 2002 and 2001, we had net operating loss carryforwards for federal
income tax purposes of approximately $47.5 million and $79.6 million,
respectively, that may be used in future years to offset taxable income. If not
utilized, these net operating losses will begin to expire in 2010.

     The following is a reconciliation of statutory federal income tax expense
(benefit) to our income tax provision:

<Table>
<Caption>
                                                                                      YEARS ENDED DECEMBER 31,
                                                                           -------------------------------------------------
                                                                               2002               2001              2000
                                                                           ------------       ------------      ------------
                                                                                            (IN THOUSANDS)
<S>                                                                        <C>                <C>               <C>
Income before income taxes ...........................................     $    109,586       $    189,404      $    127,743
Statutory rate .......................................................               35%                35%               35%
Income tax expense computed at statutory rate ........................           38,355             66,291            44,710
Reconciling items:
     Section 29 tax credits and other tax credits(1) .................             (804)               512            (2,225)
     Non-deductible compensation expense from 2001 ...................            1,541                 --                --
                                                                           ------------       ------------      ------------
Tax provision ........................................................     $     39,092       $     66,803      $     42,485
                                                                           ============       ============      ============
</Table>

----------

(1)  Year ended December 31, 2001 includes an adjustment for an under-accrual of
     tax expense in 2000.

Deferred Income Taxes

     The components of net deferred tax liabilities pursuant to SFAS No. 109 for
the years ended December 31, 2002 and 2001 primarily represent temporary
differences related to depreciation of natural gas and oil properties.

<Table>
<Caption>
                                                                                                     YEARS ENDED DECEMBER 31,
                                                                                                 ------------------------------
                                                                                                    2002                2001
                                                                                                 ------------      ------------
                                                                                                           (IN THOUSANDS)
<S>                                                                                              <C>               <C>
   Deferred tax assets:
       Derivative instruments ..............................................................     $     13,570      $         --
       Alternative minimum tax credit carryforwards ........................................              462               962
       Net operating loss carryforwards ....................................................           16,656            27,862
                                                                                                 ------------      ------------
            Total deferred tax assets ......................................................           30,688            28,824

   Deferred tax liabilities:
       Property and equipment ..............................................................     $   (206,651)     $   (182,173)
        Derivative instruments .............................................................               --           (18,820)
                                                                                                 ------------      ------------
            Total deferred tax liabilities .................................................         (206,651)         (200,993)

   Total deferred tax asset (liability) ....................................................     $   (175,963)     $   (172,169)
                                                                                                 ============      ============
</Table>



                                      F-22

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


NOTE 6 -- RELATED PARTY TRANSACTIONS

TRANSACTIONS WITH KEYSPAN

KeySpan Joint Venture

     Effective January 1, 1999, we entered into a joint exploration agreement
with KeySpan Exploration & Production, LLC, a subsidiary of KeySpan, to explore
for natural gas and oil over an initial two-year term expiring December 31,
2000. Under the terms of the joint venture, we contributed all of our then
undeveloped offshore acreage to the joint venture and we agreed that KeySpan
would receive 45% of our working interest in all prospects drilled under the
program. KeySpan paid 100% of actual intangible drilling costs for the joint
venture up to a specified maximum of $7.7 million in 2000 and $20.7 million
during 1999. Further, KeySpan paid 51.75% of all additional intangible drilling
costs incurred and we paid 48.25%. Revenues are shared 55% to Houston
Exploration and 45% to KeySpan. In addition, we received reimbursements from
KeySpan for a portion of our general and administrative costs.

     Effective December 31, 2000, KeySpan and Houston Exploration agreed to end
the primary or exploratory term of the joint venture. As a result, KeySpan has
not participated in any of our offshore exploration prospects unless the project
involved the development or further exploitation of discoveries made during the
initial term of the joint venture. In addition, effective with the termination
of the exploratory term of the joint venture, we have not received any further
reimbursement from KeySpan for general and administrative costs.

     From the inception of the joint venture in January 1999 through December
31, 2002, we drilled a total of 28 wells: 21 exploratory wells of which 17 were
successful and seven development wells of which six were successful. KeySpan
spent a total of $118.3 million, with $19.0 million, $17.2 million and $46.5
million, respectively being spent during 2002, 2001 and 2000. Subsequent to the
termination of the primary exploratory term of the joint venture, KeySpan's
participation in additional wells was to further develop or delineate reservoirs
previously discovered.

Acquisition of KeySpan Joint Venture Assets

     On October 11, 2002, we purchased from KeySpan a portion of the assets
developed under the joint exploration agreement with KeySpan Exploration &
Production, LLC, a subsidiary of KeySpan. The acquisition consisted of interests
averaging between 11.25% and 45% in 17 wells covering eight of the twelve blocks
that were developed under the joint exploration agreement from 1999 through
2002. The interests purchased were in the following blocks: Vermilion 408, East
Cameron 81 and 84, High Island 115, Galveston Island 190 and 389, Matagorda
Island 704 and North Padre Island 883. KeySpan has retained its 45% interest in
four blocks: South Timbalier 314 and 317 and Mustang Island 725 and 726 as these
blocks are in various stages of development. KeySpan has committed to continued
participation in the ongoing development of these blocks which includes the
completion of the platform and production facilities at South Timbalier 314/317
together with possible further developmental drilling at both South Timbalier
314/317 and Mustang Island 725/726. As of September 1, 2002, the effective date
of the purchase, the estimated proved reserves associated with the interests
acquired were 13.5 Bcfe. The $26.5 million purchase price was paid in cash and
financed with borrowings under our revolving credit facility. Subsequent
purchase price adjustments reduced our acquisition price by $1.2 million. The
purchase price was adjusted for various closing items in the normal course of
business, including revenues received by and expenditures made by the seller
related to the properties acquired for the period between the effective date of
the transaction (September 1, 2002) and the closing date (October 11, 2002). Our
acquisition of the properties was accounted for as a transaction between
entities under common control. As a result, the excess fair value of the
properties acquired of $3.1 million ($2.0 million net of tax) was treated as a
capital contribution from KeySpan and recorded as an increase to additional
paid-in capital during the fourth quarter of 2002.

KeySpan Credit Facility and Conversion (See Note 3-- Stockholders' Equity)

Review of Strategic Alternatives

     In September 1999, we, along with KeySpan, our majority stockholder,
announced our intention to review strategic alternatives for Houston Exploration
and for KeySpan's investment in Houston Exploration. KeySpan was assessing the
role of our company within its future strategic plan, and was considering a full
range of strategic transactions including the sale of all or a portion of
Houston Exploration. J.P. Morgan Securities Inc. was retained by KeySpan as
financial advisor to assist in the strategic review on behalf of KeySpan. Our
Board of Directors appointed a special committee comprised of



                                      F-23
<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


outside directors to assist in the review process. On February 25, 2000,
together with KeySpan we jointly announced that the review of strategic
alternatives had been completed and that KeySpan plans to retain its equity
interest in us for the foreseeable future, however, KeySpan considers its
investment in Houston Exploration a non-core asset. We incurred expenses
relating to this review of strategic alternatives totaling $0.1 million during
2001 and $1.8 million during 2000.

Sale of Section 29 Tax Credits

     In January 1997, we entered into an agreement to sell to a subsidiary of
KeySpan interests in our onshore producing wells that produce from formations
that qualify for tax credits under Section 29 of the Internal Revenue Code.
Section 29 provides for a tax credit from non-conventional fuel sources such as
oil produced from shale and tar sands and natural gas produced from geopressured
brine, Devonian shale, coal seams and tight sands formations. KeySpan acquired
an economic interest in wells that are qualified for the tax credits and in
exchange, we:

          o    retained a volumetric production payment and a net profits
               interest of 100% in the properties,

          o    received a cash down payment of $1.4 million and

          o    receive a quarterly payment of $0.75 for every dollar of tax
               credit utilized.

     We manage and administer the daily operations of the properties in exchange
for an annual management fee of $100,000. The income statement effect,
representing benefits received from Section 29 tax credits, was a benefit of
$0.8 million, respectively, for each of the years ended December 31, 2002, 2001,
and 2000. The tax credits expired December 31, 2002 and under the terms of the
agreement, we are required to repurchase the interests in the producing wells
for KeySpan. We are planning to complete the repurchase transaction in 2003 and
the repurchase price is estimated at approximately $2.0 million.

TRANSACTIONS WITH OUR EXECUTIVES

Restricted Stock Grant to President and Chief Executive

     On April 4, 2001, our Board of Directors appointed William G. Hargett to
serve as our President and Chief Executive Officer and to serve on its Board of
Directors. Pursuant to an employment agreement entered into on April 4, 2001
between us and Mr. Hargett, Mr. Hargett received a grant of 10,000 restricted
shares of Houston Exploration common stock with a fair market value of
approximately $256,000 at the time of grant. Until vested, the stock is
restricted from transfer and subject to forfeiture in the event Mr. Hargett's
employment is terminated. The shares vest, become nonforfeitable and freely
transferable in equal one-third increments on each anniversary of the grant
date. The cost of the restricted stock will be recognized in earnings as
compensation expense over the stock's three-year vesting period. During 2002 and
2001 we recognized stock compensation expense of $85,000 and $64,000,
respectively related to this restricted stock grant.

Employment Contracts

     We have entered into employment contracts with all eight of our executive
officers. Contracts are initially set for a three year period and automatically
extended one year on each anniversary unless either party gives notice within a
specified number of days prior to the anniversary of the employment agreement.
Executive officers receive annual salary and bonus payments pursuant to their
employment contracts and if we terminate an employment agreement without cause
or if the employee terminates an employment agreement with good reason, as
defined in the employment agreements, we are obligated to pay the employee a
lump-sum severance payment of 2.99 times the employee's then current annual rate
of total compensation, as defined in the agreement, in addition to the
continuation of welfare benefits for a specified time period.

Termination of Employment Agreements for Former Executives

     Effective March 31, 2001, our President and Chief Executive Officer and
Director, James G. Floyd, and our Senior Vice President - Exploration and
Production, Randall J. Fleming, retired. Each had served in their respective
positions since the Company's inception in 1986. In connection with their
retirement as executive officers, each of Messrs. Floyd and Fleming agreed to
the termination of their respective employment agreements. They received lump
sum severance payments of $2.3 million and $1.4 million, respectively. Effective
September 30, 2001, Thomas W. Powers, our Chief Financial Officer, left the
Company to pursue other interests. In connection with the termination of his
employment agreement with us, Mr. Powers received a lump sum severance payment
of approximately $1.5 million. In total, the Company has incurred approximately
$5.2 million in general and administrative expenses during 2001 as a result of
the termination of employment contracts with former executives.



                                      F-24
<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Transactions with Former President and Chief Executive Officer

     Prior to January 2000 our former President and Chief Executive Officer held
working interests and net profits interest in various properties of our company.
These interests were acquired pursuant to the terms of his employment contract.
In January 2000, we agreed to exchange all of the working interests and net
profits interests Mr. Floyd had acquired in our properties for an overriding
royalty interest in those same properties. During 2001 and 2000, Mr. Floyd
received $6.9 million and $5.4 million (net of $0.4 million in related
expenses), respectively, relating to his overriding royalty interests in our
properties.

NOTE 7 -- HEDGING CONTRACTS

     2002. As of December 31, 2002, we had entered into commodity price hedging
contracts with respect to our production for 2003 and 2004 as listed in the
tables below. Volumes and fair values are stated in thousands. The total
estimated fair value of our natural gas and oil derivative instruments at
December 31, 2002 was a negative $38.8 million ($25.2 million net of taxes).

<Table>
<Caption>
NATURAL GAS HEDGES                   FIXED PRICE SWAPS                            COLLARS                             FAIR VALUE
------------------------------  -----------------------------     ----------------------------------------------    --------------
                                                     NYMEX                                  NYMEX
                                   VOLUME          CONTRACT          VOLUME             CONTRACT PRICE
PERIOD                             (MMBTU)           PRICE           (MMBTU)        AVG FLOOR       AVG CEILING     $ IN THOUSANDS
------------------------------  ------------     ------------     ------------     ------------     ------------    --------------
<S>                             <C>              <C>              <C>              <C>              <C>             <C>
January 2003 .................         1,240     $      3.194            4,495     $      3.493     $      4.954     $     (2,917)
February 2003 ................         1,120            3.194            4,060            3.493            4.954           (2,908)
March 2003 ...................         1,240            3.194            4,495            3.493            4.954           (3,187)
April 2003 ...................         1,200            3.194            4,500            3.476            4.909           (2,542)
May 2003 .....................         1,240            3.194            4,650            3.476            4.909           (2,440)
June 2003 ....................         1,200            3.194            4,500            3.476            4.909           (2,446)
July 2003 ....................         1,240            3.194            4,650            3.476            4.909           (2,665)
August 2003 ..................         1,240            3.194            4,650            3.476            4.909           (2,754)
September 2003 ...............         1,200            3.194            4,500            3.476            4.909           (2,634)
October 2003 .................         1,240            3.194            4,650            3.476            4.909           (2,782)
November 2003 ................         1,200            3.194            4,500            3.476            4.909           (3,377)
December 2003 ................         1,200     $      3.194            4,650            3.476            4.909           (4,209)

January 2004 .................            --               --            1,550            3.500            4.750             (916)
February 2004 ................            --               --            1,400            3.500            4.750             (759)
March 2004 ...................            --               --            1,550            3.500            4.750             (597)
April 2004 ...................            --               --            1,500            3.500            4.750             (217)
May 2004 .....................            --               --            1,550            3.500            4.750             (103)
June 2004 ....................            --               --            1,500            3.500            4.750              (71)
July 2004 ....................            --               --            1,550            3.500            4.750              (83)
August 2004 ..................            --               --            1,550            3.500            4.750              (94)
September 2004 ...............            --               --            1,500            3.500            4.750              (72)
October 2004 .................            --               --            1,550            3.500            4.750              (97)
November 2004 ................            --               --            1,500            3.500            4.750             (277)
December 2004 ................            --               --            1,550            3.493            4.750             (480)
                                                                                                                     ------------
                                                                                                                     $    (38,627)
                                                                                                                     ============
</Table>



                                      F-25
<PAGE>


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


<Table>
<Caption>
OIL HEDGES                              FIXED PRICE SWAPS                      COLLARS                       FAIR VALUE
------------------------------         -------------------       ---------------------------------------   --------------
                                                   NYMEX                               NYMEX
                                        VOLUME    CONTRACT         VOLUME          CONTRACT PRICE
PERIOD                                  (MBbl)      PRICE          (MBbl)       AVG FLOOR    AVG CEILING   $ IN THOUSANDS
------------------------------         -------   ---------       ---------     -----------  ------------   --------------
<S>                                    <C>       <C>             <C>           <C>          <C>            <C>
January 2003 .................            31     $   28.50            --            --            --         $     (77)
February 2003 ................            28         28.50            --            --            --               (48)
March 2003 ...................            31         28.50            --            --            --               (20)
                                                                                                             ---------
                                                                                                             $    (145)
                                                                                                             =========
</Table>



                                      F-26
<PAGE>


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


For natural gas, transactions are settled based upon the New York Mercantile
Exchange or NYMEX price on the final trading day of the month. For oil, our
swaps are settled against the average NYMEX price of oil for the calendar month
rather than the last day of the month. Fair market value is calculated for the
respective months using prices derived from NYMEX futures contract prices
existing at December 31st and from market quotes received from counterparties.

     During the fourth quarter of 2002, an increase in forward market prices for
natural gas caused our mark-to-market exposure with one counter party to surpass
our contractual margin threshold as established under the contract. As a result,
we were required to post margin in the amount of $5.4 million. The margin
payment earns interest at a market rate and will be refunded if our
mark-to-market exposure drops below the margin threshold as required under the
contract. This will occur if market prices decline from current levels. At
December 31, 2002, the $5.4 million paid for the margin call is classified as
restricted cash and is included in current assets on the balance sheet in the
line item "Prepayments and Other."

     2001. At December 31, 2001, we had entered into commodity price hedging
contracts with respect to our production for 2002 and 2003 as listed in the
table below. Volumes and fair values are stated in thousands. The total
estimated fair value of our natural gas derivative instruments at December 31,
2001 was a positive $53.8 million ($34.9 million net of taxes).

<Table>
<Caption>
NATURAL GAS HEDGES                           FIXED PRICE SWAPS                           COLLARS                     FAIR VALUE
---------------------------------------  --------------------------     ----------------------------------------    -------------
                                                            NYMEX                             NYMEX
                                             VOLUME        CONTRACT      VOLUME          CONTRACT PRICE
PERIOD                                      (MMbtu)         PRICE       (MMbtu)      AVG FLOOR       AVG CEILING    ($ THOUSANDS)
---------------------------------------  ------------     ---------     --------   ------------     ------------    ------------
<S>                                      <C>              <C>           <C>        <C>              <C>             <C>
January 2002 ..........................           930     $   3.010        4,340   $      3.643     $      5.356     $      5,144
February 2002 .........................           840         3.010        3,920          3.643            5.356            4,585
March 2002 ............................           930         3.010        4,340          3.643            5.356            5,176
April 2002 ............................           900         3.010        4,200          3.643            5.356            5,054
May 2002 ..............................           930         3.010        4,340          3.643            5.356            5,041
June 2002 .............................           900         3.010        4,200          3.643            5.356            4,654
July 2002 .............................           930         3.010        4,340          3.643            5.356            4,655
August 2002 ...........................           930         3.010        4,340          3.643            5.356            4,497
September 2002 ........................           900         3.010        4,200          3.643            5.356            4,352
October 2002 ..........................           930         3.010        4,340          3.643            5.356            4,385
November 2002 .........................           900         3.010        4,200          3.643            5.356            3,424
December 2002 .........................           930         3.010        4,200          3.643            5.356            2,690

January 2003 ..........................         1,240         3.194           --             --               --               10
February 2003 .........................         1,120         3.194           --             --               --                9
March 2003 ............................         1,240         3.194           --             --               --               10
April 2003 ............................         1,200         3.194           --             --               --                9
May 2003 ..............................         1,240         3.194           --             --               --               10
June 2003 .............................         1,200         3.194           --             --               --                9
July 2003 .............................         1,240         3.194           --             --               --               10
August 2003 ...........................         1,240         3.194           --             --               --               10
September 2003 ........................         1,200         3.194           --             --               --                9
October 2003 ..........................         1,240         3.194           --             --               --                9
November 2003 .........................         1,200         3.194           --             --               --                9
December 2003 .........................         1,240         3.194           --             --               --               10
                                                                                                                     ------------
                                                                                                                     $     53,771
                                                                                                                     ============
</Table>



                                      F-27
<PAGE>


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


     These hedging transactions are settled based upon the average of the
reported settlement prices on the NYMEX for the last three trading days of a
particular contract month or the NYMEX price on the final trading day of the
month (the "settlement price"). With respect to any particular swap transaction,
the counterparty is required to make a payment to us in the event that the
settlement price for any settlement period is less than the swap price for the
transaction, and we are required to make payment to the counterparty in the
event that the settlement price for any settlement period is greater than the
swap price for the transaction. For any particular collar transaction the
counterparty is required to make a payment to us if the settlement price for any
settlement period is below the floor price for the transaction, and we are
required to make payment to the counterparty if the settlement price for any
settlement period is above the ceiling price for the transaction. We are not
required to make or receive any payment in connection with a collar transaction
if the settlement price is between the floor and the ceiling.

NOTE 8 -- SALES TO MAJOR CUSTOMERS

     We sold natural gas and oil production representing 10% or more of our
natural gas and oil revenues for the years ended December 31, 2002, 2001 and
2000 as listed below. In the exploration, development and production business,
production is normally sold to relatively few customers. However, based on the
current demand for natural gas and oil, we believe that the loss of any of our
major purchasers would not have a material adverse effect on our operations.

<Table>
<Caption>
                                                            FOR THE YEAR ENDED DECEMBER 31,
                                                       ------------------------------------------
MAJOR PURCHASER                                           2002            2001            2000
--------------------------------------------------     ----------      ----------      ----------
<S>                                                    <C>             <C>             <C>
 Anadarko Petroleum Corporation ..................           12.6%            7.3%            8.7%
 ConocoPhillips ..................................           14.9%            4.0%            0.6%
 KinderMorgan ....................................            9.8%            5.0%            2.8%
 Dynegy, Inc. ....................................            5.5%           16.4%           22.5%
 Adams Resources and Energy, Inc. ................            8.2%           12.5%           14.9%
 El Paso Corporation .............................            4.8%            9.5%            9.1%
</Table>

----------

Note: Amounts disclosed that are less than 10% are presented for information and
      comparison purposes only.

NOTE 9 -- COMMITMENTS AND CONTINGENCIES

Severance Tax Refund

     During July 2002, we applied for and received from the Railroad Commission
of Texas a "high-cost/tight-gas formation" designation for a portion of our
South Texas production. The "high-cost/tight-gas formation" designation will
allow us to receive an abatement of severance taxes for qualifying wells in
various fields. For qualifying wells, production will be either exempt from tax
or taxed at a reduced rate until certain capital costs are recovered. For
qualifying wells, we will also be entitled to a refund of severance taxes paid
during a designated prior 48-month period. Applications for refund are submitted
on a well-by-well basis to the State Comptroller's Office and due to timing of
the acceptance of applications, we are unable to project the 48-month look-back
period for qualifying refunds. We currently estimate that the total refund, for
2002 and prior periods, will be between $18 million to $23 million ($12 million
to $15 million, net of tax), although we can provide no assurances that the
actual total refund amount will fall within our current estimate. During the
fourth quarter of 2002, we recorded refunds totaling $10.4 million ($6.8 million
net of tax) of which $1.3 million related to refund of 2002 severance tax
expense and $9.1 related to refunds of prior period expense.

Legal Proceedings

     On August 18, 2002, a complaint styled Victor Ramirez, Santiago Ramirez,
Jr., Oswaldo H. Ramirez and Javier Ramirez as Co-Trustees of the Ramirez Mineral
Trust v. The Houston Exploration Company, cause number 5,207, was filed in the
district court of the 49th Judicial District in Zapata County, Texas. The
complaint alleges that we trespassed by drilling the No. 7 RMT well to a depth
in excess of our lease rights and commingled production by producing from the
excess depth. The plaintiffs claim damages for trespass and conversion in excess
of $6 million and further seek to recover exemplary damages in excess of $18
million. At February 20, 2003, the issuance date of our original report, we were
in the discovery stage of the litigation



                                      F-28
<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


process for this claim. We believe that the claim will not have a material
adverse effect on our financial condition or results of operations.

     Other Litigation. We are involved from time to time in various claims and
lawsuits incidental to our business. In the opinion of management, the ultimate
liability, if any, will not have a material adverse effect on our financial
position or results of operations.



                                      F-29
<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Leases

     We have entered into non-cancellable operating lease agreements relative to
the lease of our office space at 1100 Louisiana in Houston, Texas and various
types of office equipment (telephones, copiers and fax machines) with various
expiration dates through 2009. Minimum rental commitments under the terms of our
operating leases are as follows (in thousands):

<Table>
<Caption>
                                                                   MINIMUM
YEAR ENDED DECEMBER 31,                                            PAYMENTS
------------------------------------------------------------     ------------
<S>                                                              <C>
2003 .......................................................     $      1,071
2004 .......................................................            1,124
2005 .......................................................            1,168
2006 .......................................................            1,116
2007 .......................................................            1,215
Thereafter .................................................            3,323
</Table>

     Net rental expense related to these leases was $1.2 million, $0.6 million
and $0.5 million, respectively, for the years ended December 31, 2002, 2001 and
2000.

NOTE 10 -- ACQUISITIONS

Acquisition of KeySpan Joint Venture Assets (See Note 6 - Related Party
Transaction - Transactions with KeySpan).

Burlington Acquisition

     On May 30, 2002, we completed the purchase of natural gas and oil producing
properties and associated gathering pipelines, together with undeveloped
acreage, from Burlington Resources Inc. located in the Webb, Jim Hogg, Wharton
and Calhoun counties of South Texas. The properties purchased cover
approximately 24,800 gross (10,800 net) acres located in the North East
Thompsonville, South Laredo, McFarlan and Maude Traylor Fields. The properties
purchased represent interests in approximately 145 producing wells and total
proved reserves of 42 Bcfe as of January 1, 2002, the effective date of the
transaction. Our average working interest is 35% and we are the operator of
approximately 23% of the producing wells acquired. The $44.5 million purchase
price, which is net of a purchase price adjustment of $3.9 million, was financed
by borrowings under our revolving bank credit facility. The purchase price was
reduced for various closing items in the normal course of business, including
revenues received by and expenditures made by the seller related to the
properties acquired for the period between the effective date of the transaction
(January 1, 2002) and the closing date (May 30, 2002).

     On July 16, 2002, we sold those interests acquired from Burlington in the
McFarlan and Maude Traylor Fields for approximately $5.0 million, which was net
of a purchase price adjustment of $1.1 million. The effective date of this
transaction was January 1, 2002. These two fields, located in Wharton and
Calhoun counties, respectively, are outside our current area of focus in South
Texas. The sale represents interests in 22 producing wells with reserves of
approximately 5 Bcfe. Proceeds from the sale were used to repay borrowings under
our revolving bank credit facility.

     We retained the North East Thompsonville Field, located in Jim Hogg County,
and the South Laredo Field, located in Webb County. The North East Thompsonville
Field has 10 wells producing from the Wilcox formation, all of which we operate,
and representing approximately 70% of the proved reserves and 75% of the current
production associated with the acquisition from Burlington. The South Laredo
Field, located in Webb County and in the Lobo Trend, contains 113 wells, all
operated by a third party.

Conoco Acquisition

     On December 31, 2001, we completed the purchase of certain natural gas and
oil properties and associated gathering pipelines and equipment, together with
developed and undeveloped acreage, located in Webb and Zapata counties of South
Texas, from Conoco Inc. The $69 million purchase price was paid in cash and
financed by borrowings under our revolving bank credit facility. The properties
purchased cover approximately 25,274 gross (16,885 net) acres located in the
Alexander, Haynes, Hubbard and South Trevino Fields, which are in close
proximity to our existing operations in the



                                      F-30
<PAGE>


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Charco Field, and represent interests in approximately 159 producing wells. We
operate approximately 95% of the producing wells acquired and our average
working interest is 87%. Total proved reserves associated with the interests
acquired were 85 Bcfe, as of the October 1, 2001, the effective date of the
transaction.

NOTE 11 --RESTATEMENT AND RECLASSIFICATIONS

Application of EITF Issue No. 00-10 - Transportation Expense

     Subsequent to the issuance of our financial statements for the year ended
December 31, 2001, we determined that we had not adopted Emerging Issues Task
Force Issue ("EITF") Issue No. 00-10, "Accounting for Shipping and Handling Fees
and Costs" that was effective for us in the fourth quarter of 2000. EITF Issue
No. 00-10 reached a consensus that amounts billed to customers for shipping and
handling costs should be classified as revenues and that deducting shipping and
handling costs from revenues is not appropriate and that such costs should be
classified as an expense on the income statement. Furthermore, the EITF
determined that upon application of this Issue, comparative financial statements
for prior periods should be reclassified to comply with the guidance provided.

     Previously we reflected our shipping and handling costs as a reduction to
natural gas and oil revenues. In accordance with the application of EITF No.
00-10,we added these costs back to natural gas and oil revenues and reclassified
them to transportation expense. Our accompanying Consolidated Statement of
Operations for the year ended December 31, 2001 was restated from amounts
previously reported to reflect the application of EITF No. 00-10 and the correct
presentation of transportation expense. The restatement for 2001 has no effect
on net income or income from operations. Our Consolidated Statement of
Operations for the year ended December 31, 2000 was reflected to provide
comparative financial statements for all periods presented. The reclassification
for 2000 has no effect on net income or income from operations.

     The table below provides a summary of the effects of application of EITF
No. 00-10 for amounts reported in 2001 and 2000. See Note 13 - Selected
Quarterly Information, for the effects of the application of EITF No. 00-10 for
each of the quarterly periods during the years ended December 31, 2002 and 2001.

<Table>
<Caption>
                                                                        2001                         2000
                                                               -------------------------    ---------------------------
                                                                              PREVIOUSLY                     PREVIOUSLY
                                                                RESTATED       REPORTED     RECLASSIFIED      REPORTED
                                                               ----------     ----------    ------------     ----------
                                                                                     ($ IN THOUSANDS)
<S>                                                            <C>            <C>            <C>            <C>
      Natural gas and oil revenues .......................     $  387,156     $  379,504     $  277,487     $  270,595
      Total revenues .....................................        388,509        380,857        279,225        272,333
      Transportation expenses ............................          7,652             --          6,892             --
      Total operating expenses ...........................        195,994        188,342        138,369        131,477
      Income from operations .............................        192,515        192,515        140,856        140,856
      Net income .........................................        122,601        122,601         85,258         85,258
</Table>

Adoption of SFAS No. 133

     In connection with the adoption of SFAS No. 133, on January 1, 2001 we were
required to disclose in our Consolidated Statement of Stockholders' Equity and
Comprehensive Income the cumulative effect of the accounting change for
derivative instruments, which is equal to the unrealized loss related to the
mark-to-market valuation of our derivative instruments as of January 1, 2001
together with the value of derivative instruments settled during the period and
reclassified to income during the period and the unrealized gain or loss due to
the change in the fair value during the period. All amounts are to be reported
net of taxes. Our Consolidated Statement of Stockholder's Equity now presents
these amounts in accordance with SFAS No. 133.



                                      F-31
<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


NOTE 12-- SUPPLEMENTAL INFORMATION ON NATURAL GAS AND OIL EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

     The following information concerning our natural gas and oil operations has
been provided pursuant to Statement of Financial Accounting Standards No. 69,
"Disclosures about Oil and Gas Producing Activities." Our 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. Our natural gas
and oil reserves were estimated by independent reserve engineers.

Capitalized Costs of Natural Gas and Oil Properties

     As of December 31, 2002, 2001 and 2000, our capitalized costs of natural
gas and oil properties are as follows:

<Table>
<Caption>
                                                                                 AS OF DECEMBER 31,
                                                                 ------------------------------------------------------
                                                                      2002                2001                2000
                                                                 --------------      --------------      --------------
                                                                                    (IN THOUSANDS)
<S>                                                              <C>                 <C>                 <C>
Unevaluated properties, not amortized ......................     $       96,192      $      177,987      $      142,890
Properties subject to amortization .........................          1,828,160           1,493,293           1,162,000
                                                                 --------------      --------------      --------------
            Capitalized costs ..............................          1,924,352           1,671,280           1,304,890
Accumulated depreciation, depletion and amortization .......           (906,089)           (735,257)           (601,034)
                                                                 --------------      --------------      --------------
Net capitalized costs ......................................     $    1,018,263      $      936,023      $      703,856
                                                                 ==============      ==============      ==============
</Table>

Capitalized Costs Incurred

     Costs incurred for natural gas and oil exploration, development and
acquisition are summarized below. Costs incurred during the years ended December
31, 2002, 2001 and 2000 include interest expense and general and administrative
costs related to acquisition, exploration and development of natural gas and oil
properties of $21.1 million, $24.9 million and $23.3 million, respectively.

<Table>
<Caption>
                                                                                              AS OF DECEMBER 31,
                                                                                  ----------------------------------------
                                                                                     2002           2001           2000
                                                                                  ----------     ----------     ----------
                                                                                                (IN THOUSANDS)
<S>                                                                               <C>            <C>            <C>
Property acquisition and leasehold costs
   Unevaluated(1) ...........................................................     $   14,600     $   31,711     $    7,955
   Proved ...................................................................         89,873         85,367         38,579
Exploration costs ...........................................................         26,563         72,056         37,162
Development costs ...........................................................        122,036        177,256        100,333
                                                                                  ----------     ----------     ----------
    Total costs incurred ....................................................     $  253,072     $  366,390     $  184,029
                                                                                  ==========     ==========     ==========
</Table>

----------

(1)  These amounts represent costs we incurred during 2002 and excluded from the
     amortization base until proved reserves are established or impairment is
     determined. We estimate that these costs will be evaluated within four
     years.

     During the years ended December 2002, 2001 and 2000, we spent $11.0
million, $19.9 million and $9.7 million, respectively to develop our proved
undeveloped reserves. At December 31, 2002, our Standardized Measure of
Discounted Future Net Cash Flows includes estimated future development costs for
our proved undeveloped reserves for the next three years of $141.8 million,
$31.9 million and $7.0 million, respectively, for 2003, 2004 and 2005.



                                      F-32

<PAGE>


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Natural Gas and Oil Reserves (unaudited)

     The following summarizes the policies we used 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 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 the information in a manner comparable with industry
peers.

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

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

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

     2.   The estimated future cash flows are compiled by applying year-end
          prices of natural gas and oil relating to our proved reserves to the
          year-end quantities of those reserves.

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

     4.   Future income tax expenses are based on year-end statutory tax rates
          giving effect to the remaining tax basis in the natural gas and oil
          properties, other deductions, credits and allowances relating to our
          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 our natural
gas and oil reserves. An estimate of fair value would also take into account,
among other things, the recovery of reserves not presently classified as proved,
anticipated future changes in prices and costs and a discount factor more
representative of the time value of money and the risks inherent in reserve
estimates.



                                      F-33
<PAGE>


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


The standardized measure of discounted future net cash flows relating to proved
natural gas and oil reserves is as follows and does not include cash flows
associated with hedges outstanding at each of the respective reporting dates:

<Table>
<Caption>
                                                                                              AS OF DECEMBER 31,
                                                                           ------------------------------------------------------
                                                                                2002                2001                2000
                                                                           --------------      --------------      --------------
                                                                                                (IN THOUSANDS)
<S>                                                                        <C>                 <C>                 <C>
Future cash inflows ..................................................     $    2,845,768      $    1,471,557      $    5,189,328
Future production costs ..............................................           (486,399)           (302,145)           (542,139)
Future development costs .............................................           (241,876)           (189,480)           (153,210)
Future income taxes ..................................................           (542,782)           (211,191)         (1,250,272)
                                                                           --------------      --------------      --------------
Future net cash flows ................................................          1,574,711             768,741           3,243,707
10% annual discount for estimated timing of cash flows ...............           (516,647)           (217,216)         (1,179,680)
                                                                           --------------      --------------      --------------
Standardized measure of discounted future net cash flows .............     $    1,058,064      $      551,525      $    2,064,027
                                                                           ==============      ==============      ==============
</Table>

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

<Table>
<Caption>
                                                                                        AS OF DECEMBER 31,
                                                                         ------------------------------------------------
                                                                             2002              2001              2000
                                                                         ------------      ------------      ------------
                                                                                          (IN THOUSANDS)
<S>                                                                      <C>               <C>               <C>
Beginning of the year ..............................................     $    551,525      $  2,064,027      $    469,225
Revisions to previous estimates:
  Changes in prices and costs ......................................          629,542        (2,088,576)        2,163,984
  Changes in quantities ............................................          (36,368)          (52,928)           24,650
  Changes in future development costs ..............................           (1,970)          (18,001)          (32,152)
Development costs incurred during the period .......................           23,393            65,940            57,046
Extensions and discoveries, net of related costs ...................          242,055           116,710           403,012
Sales of natural gas and oil, net of production costs ..............         (275,157)         (343,181)         (237,286)
Accretion of discount ..............................................           64,858           279,648            52,967
Net change in income taxes .........................................         (209,807)          635,400          (672,005)
Purchase of reserves in place ......................................           99,741            51,674            23,118
Sale of reserves in place ..........................................             (170)             (133)               --
Production timing and other ........................................          (29,578)         (159,055)         (188,532)
                                                                         ------------      ------------      ------------
End of year ........................................................     $  1,058,064      $    551,525      $  2,064,027
                                                                         ============      ============      ============
</Table>



                                      F-34


<PAGE>
                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Estimated Net Quantities of Natural Gas and Oil Reserves (Unaudited)

     The following table sets forth our net proved reserves, including changes,
and proved developed reserves (all within the United States) at the end of each
of the three years in the period ended December 31, 2002, 2001 and 2000.

<Table>
<Caption>
                                                       NATURAL GAS                              CRUDE OIL AND CONDENSATE
                                                          (MMcf)                                         (MBbls)
                                        ------------------------------------------      ------------------------------------------
                                           2002           2001             2000           2002            2001            2000
                                        ----------      ----------      ----------      ----------      ----------      ----------
<S>                                     <C>             <C>             <C>             <C>             <C>             <C>

Proved developed and
  undeveloped  reserves: ..........        568,208         529,518         526,185           6,605           5,352           2,470
Revisions of previous estimates ...        (14,863)        (41,914)          3,709             (26)           (174)            107
Extensions and discoveries ........        105,798          83,551          69,564             342           1,800           2,424
Production ........................        (97,368)        (87,095)        (77,861)           (859)           (459)           (311)
Purchase of reserves in place .....         48,777          84,148           7,921             483             115             662
Sales of reserves in place ........           (143)             --              --             (12)            (29)             --
                                        ----------      ----------      ----------      ----------      ----------      ----------
End of year .......................        610,409         568,208         529,518           6,533           6,605           5,352
                                        ==========      ==========      ==========      ==========      ==========      ==========
Proved developed reserves:
Beginning of year .................        438,538         420,733         397,343           2,123           1,810           1,796
End of year .......................        435,629         438,538         420,733           2,413           2,123           1,810
</Table>



                                      F-35
<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


NOTE 13-- QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

<Table>
<Caption>
                                                            1ST QUARTER       2ND QUARTER       3RD QUARTER       4TH QUARTER
                                                           -------------     -------------     -------------     --------------
                                                                              (IN THOUSANDS, EXCEPT PER SHARE DATA)
<S>                                                        <C>               <C>               <C>               <C>

2002

Total revenues - restated .............................    $      74,816     $      85,955     $      84,205     $      100,405
Total revenues - previously reported (1) ..............           72,640            83,728            81,971             97,725
Total operating expenses - restated ...................           54,425            57,426            58,745             66,681
Total operating expenses  - previously reported (1) ...           52,249            55,209            56,511             64,181
Income from operations ................................           20,391            28,519            25,460             33,544
Net income ............................................           12,534            17,654            15,272             25,034

Net income per share(2) ...............................    $        0.41              0.58              0.50               0.81
Net income per share--fully diluted(2) ................    $        0.41              0.57              0.50               0.81

2001

Total revenues - restated .............................    $     126,418     $     101,151     $      80,320     $       80,620
Total revenues - previously reported (1) ..............          124,342            99,308            78,495             78,712
Total operating expenses - restated ...................           75,199            56,876            34,394             26,046
Total operating expenses  - previously reported (1) ...           49,143            42,432            44,101             52,666
Income from operations ................................           75,199            56,876            34,394             26,046
Net income ............................................           47,344            35,855            22,530             16,872

Net income per share(2) ...............................    $        1.58     $        1.19     $        0.74     $         0.55
Net income per share--fully diluted(2) ................    $        1.55     $        1.17     $        0.73     $         0.55
</Table>

----------

(1)  For all periods presented, we applied Emerging Issues Task Force ("EITF")
     No. 00-10 "Accounting for Shipping and Handling Fees and Costs." Pursuant
     our application of EITF No. 00-10, transportation expenses previously
     reflected as a reduction to natural gas and oil revenues were added back to
     revenues and reported as a separate component of operating expense. The
     application of EITF No. 00-10 has no effect on income from operations or
     net income. See Note 11 - Restatement and Reclassifications made to
     Statements of Operations for Transportation Expense.

(2)  Quarterly earnings per share is based on the weighted average number of
     shares outstanding during the quarter. Because of the increase in the
     number of shares outstanding during the quarters due to the exercise of
     stock options, the sum of quarterly earnings per share may not equal
     earnings per share for the year.



                                      F-36

<PAGE>



                                INDEX TO EXHIBITS

<Table>
<Caption>
EXHIBITS               DESCRIPTION
--------               -----------
<S>                    <C>
3.1         --         Restated Certificate of Incorporation (filed as Exhibit
                       3.1 to our Quarterly Report on Form 10- Q for the
                       quarterly period ended June 30, 1997 (File No. 001-11899)
                       and incorporated by reference).

3.2         --         Restated Bylaws (filed as Exhibit 3.2 to our Quarterly
                       Report on Form 10-Q for the quarterly period ended June
                       30, 1997 (File No. 001-11899) and incorporated by
                       reference).

4.1         --         Indenture, dated as of March 2, 1998, between The Houston
                       Exploration Company and The Bank of New York, as Trustee,
                       with respect to the 85/8% Senior Subordinated Notes Due
                       2008 (including form of 85/8% Senior Subordinated Note
                       Due 2008) (incorporated by reference to Exhibit 4.1 to
                       our Registration Statement on Form S-4 (No. 333-50235)).

10.1        --         Registration Rights Agreement dated as of July 2, 1996
                       between The Houston Exploration Company and THEC Holdings
                       Corp. (filed as Exhibit 10.13 to our Registration
                       Statement on Form S-1 (Registration No. 333-4437) and
                       incorporated by reference).

10.2        --         Registration Rights Agreement between The Houston
                       Exploration Company and Smith Offshore Exploration
                       Company (filed as Exhibit 10.15 to our Registration
                       Statement on Form S-1 (Registration No. 333-4437) and
                       incorporated by reference).

10.3                   Subordinated Loan Agreement dated November 30, 1998
                       between The Houston Exploration Company and MarketSpan
                       Corporation d/b/a KeySpan Energy Corporation (filed as
                       Exhibit 10.30 to our Annual Report on Form 10-K for the
                       year ended December 31, 1998 and incorporated by
                       reference).

10.4                   Subordination Agreement dated November 25, 1998 entered
                       into and among MarketSpan Corporation d/b/a KeySpan
                       Energy Corporation, The Houston Exploration Company and
                       Chase Bank of Texas, National Association (filed as
                       Exhibit 10.31 to our Annual Report on Form 10-K for the
                       year ended December 31, 1998 (File No. 001-11899) and
                       incorporated by reference).

10.5                   First Amendment to Subordinated Loan Agreement and
                       Promissory Note between KeySpan Corporation and The
                       Houston Exploration Company dated effective as of October
                       27, 1999 (filed as Exhibit 10.17 to our Annual Report on
                       Form 10-K for the year ended December 31, 1999 (File No.
                       001-11899) and incorporated by reference).

10.6        --         Exploration Agreement between The Houston Exploration
                       Company and KeySpan Exploration and Production, L.L.C.,
                       dated March 15,1999, (filed as Exhibit 10.1 to our
                       Quarterly Report on Form 10-Q for the quarter ended March
                       31, 1999 (File No. 001-11899) and incorporated by
                       reference).

10.7        --         First Amendment to the Exploration Agreement between The
                       Houston Exploration Company and KeySpan Exploration and
                       Production, L.L.C. dated November 3, 1999 (filed as
                       Exhibit 10.19 to our Annual Report on Form 10-K for the
                       year ended December 31, 1999 (File No. 001-11899) and
                       incorporated by reference).

10.8        --         Restated Exploration Agreement dated June 30, 2000
                       between The Houston Exploration Company and KeySpan
                       Exploration and Production, L.L.C (filed as Exhibit 10.1
                       to our Quarterly on Form 10-Q for the quarter ended
                       September 30, 2000 File No. 001-11899) and incorporated
                       by reference).

10.9(2)     --         Supplemental Executive Pension Plan (filed as Exhibit
                       10.23 to our Registration Statement on Form S-1
                       (Registration No. 333-4437) and incorporated by
                       reference).

10.10(2)    --         Deferred Compensation Plan for Non-Employee Directors
                       (filed as Exhibit 10.24 to our Annual Report on Form 10-K
                       for the year ended December 31, 1997 (File No. 001-11899)
                       and incorporated by reference).

10.11(2)    --         Amended and Restated 1996 Stock Option Plan (filed as
                       Exhibit 10.1 to our Quarterly Report on Form 10-Q for the
                       quarter ended June 30, 1998 (File No. 001-11899) and
                       incorporated by reference).

10.12(2)    --         1999 Non-Qualified Stock Option Plan dated October 26,
                       1999 (filed as Exhibit 10.24 to our Annual Report on Form
                       10-K for the year ended December 31, 1999 File No.
                       001-11899) and incorporated by reference).

10.13(2)    --         Change of Control Plan dated October 26, 1999 (filed as
                       Exhibit 10.25 to our Annual Report on Form 10-K for the
                       year ended December 31, 1999 File No. 001-11899) and
                       incorporated by reference).

10.14(2)    --         Employment Agreement dated July 2, 1996 between The
                       Houston Exploration Company and James F. Westmoreland
                       (filed as Exhibit 10.11 to our Registration Statement on
                       Form S-1 (Registration No. 333-4437) and incorporated by
                       reference).

10.15(2)    --         First Amendment to Employment Agreement dated April 26,
                       2001 between The Houston Exploration Company and James F.
                       Westmoreland (filed as Exhibit 10.5 to our Quarterly
                       Report on Form 10-Q for the quarter ended March 31, 2001
                       File No. 001-11899).
</Table>



                                      F-37
<PAGE>

                                INDEX TO EXHIBITS

<Table>
<Caption>
EXHIBITS               DESCRIPTION
--------               -----------
<S>                    <C>

10.16(2)    --         Employment Agreement dated May 1, 1998 between The
                       Houston Exploration Company and Thomas E. Schwartz (filed
                       as Exhibit 10.2 to our Quarterly Report on Form 10-Q for
                       the quarter ended March 31, 1998 (File No. 001-11899) and
                       incorporated by reference).

10.17(2)    --         First Amendment to Employment Agreement dated April 26,
                       2001 between The Houston Exploration Company and Thomas
                       W. Schwartz (filed as Exhibit 10.4 to our Quarterly
                       Report on Form 10-Q for the quarter ended March 31, 2001
                       File No. 001-11899)

10.18(2)    --         Employment Agreement, dated September 19, 1996, between
                       The Houston Exploration Company and Charles W. Adcock
                       (filed as Exhibit 10.26 to our Annual Report on Form 10-K
                       for the year ended December 31, 1996 (File No. 001-11899)
                       and incorporated by reference).

10.19(2)    --         First Amendment to Employment Agreement dated April 26,
                       2001 between The Houston Exploration Company and Charles
                       W. Adcock (filed as Exhibit 10.3 to our Quarterly Report
                       on Form 10-Q for the quarter ended March 31, 2001 File
                       No. 001-11899).

10.20(2)    --         Employment Agreement dated April 4, 2001 between The
                       Houston Exploration Company and William G. Hargett (filed
                       as Exhibit 10.2 to our Quarterly Report on Form 10-Q for
                       the quarter ended March 31, 2001 File No. 001-11899).

10.21(2)    --         First Amendment to Employment Agreement between The
                       Houston Exploration Company and William G. Hargett dated
                       May 17, 2002 (filed as Exhibit 10.2 to our Quarterly
                       Report on Form 10-Q for the quarter ended June 30, 2002
                       File No. 001-11899).

10.22(2)    --         Employment Agreement dated July 16, 2001 between The
                       Houston Exploration Company and Tracy Price (filed as
                       Exhibit 10.1 to our Quarterly Report on Form 10-Q for the
                       quarter ended September 30, 2001 File No. 001-11899).

10.23(2)    --         Employment Agreement dated October 22, 2001 between The
                       Houston Exploration Company and Steven L. Mueller (filed
                       as Exhibit 10.32 to our Annual Report on Form 10-K for
                       the year ended December 31, 2001 File No. 001-11899).

10.24(2)    --         Employment Agreement dated March 1, 2002 between The
                       Houston Exploration Company and Roger B. Rice (filed as
                       Exhibit 10.33 to our Annual Report on Form 10-K for the
                       year ended December 30, 2001 File No. 001-11899).

10.25(2)    --         Revolving Credit Facility between The Houston Exploration
                       Company and Wachovia Bank, National Association, as
                       issuing bank and administrative agent, Bank of Nova
                       Scotia and Fleet National Bank as co-syndication agents
                       and BNP Paribas as documentation agent dated July 15,
                       2002 (filed as Exhibit 10.1 to our Quarterly Report on
                       Form 10-Q for the quarter ended June 30, 2002 File No.
                       001-11899).

10.26(2)    --         Employment Agreement dated November 18, 2002 between The
                       Houston Exploration Company and John H. Karnes
                       (incorporated by reference from Exhibit 10.26 to the
                       original filing on February 20, 2003 of our Annual Report
                       on Form 10-K for the year ended December 30, 2002 File
                       No. 001-11899).

10.27(2)    --         Second Amendment to Employment Agreement dated January
                       10, 2003 between The Houston Exploration Company and
                       James F. Westmoreland (incorporated by reference from
                       Exhibit 10.27 to the original filing on February 20, 2003
                       of our Annual Report on Form 10-K for the year ended
                       December 30, 2002 File No. 001-11899).

10.28(2)               Executive Deferred Compensation Plan dated January 1,
                       2002 (incorporated by reference from Exhibit 10.28 to the
                       original filing on February 20, 2003 of our Annual Report
                       on Form 10-K for the year ended December 30, 2002 File
                       No. 001-11899).

10.29(2)               2002 Long-Term Incentive Plan effective May 17, 2002
                       (filed as Exhibit 1 to our Definitive Proxy Statement on
                       Schedule 14A (File No. 001-11899) and incorporated by
                       reference).

12.1        --         Computation of ratio of earnings to fixed charges
                       (incorporated by reference from Exhibit 12.1 to the
                       original filing on February 20, 2003 of our Annual Report
                       on Form 10-K for the year ended December 30, 2002 File
                       No. 001-11899).

21.1        --         Subsidiaries of Houston Exploration (incorporated by
                       reference from Exhibit 21.1 to our the original filing on
                       February 20, 2003 of Annual Report on Form 10-K for the
                       year ended December 30, 2002 File No. 001-11899).

23.1(1)     --         Consent of Deloitte & Touche LLP.

23.2(1)     --         Consent of Netherland, Sewell & Associates.

23.3(1)     --         Consent of Miller and Lents.

31.1(1)     --         Certification of William G. Hargett, Chief Executive
                       Officer, as required pursuant to Section 302 of the
                       Sarbanes-Oxley Act of 2002.

31.2(1)     --         Certification of John H. Karnes, Chief Financial Officer,
                       as required pursuant to Section 302 of the Sarbanes-Oxley
                       Act of 2002
</Table>



                                      F-38
<PAGE>

<Table>
<S>                    <C>
32.1(1)     --         Certification of William G. Hargett, Chief Executive
                       Officer, as required pursuant to Section 906 of the
                       Sarbanes-Oxley Act of 2002.

32.2(1)     --         Certification of John H. Karnes, Chief Financial Officer,
                       as required pursuant to Section 906 of the Sarbanes-Oxley
                       Act of 2002.
</Table>

----------

(1)  Filed herewith.

(2)  Management contract or compensation plan.



                                      F-39