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

                                    FORM 10-K
              |X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                       THE SECURITIES EXCHANGE ACT OF 1934
                   FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001
                                       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
    (ADDRESS OF PRINCIPAL EXECUTIVE                      77002-5215
                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
   85/8% Senior Subordinated Notes due 2008          New York Stock Exchange

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

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

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

      The aggregate market value of the voting stock held by non-affiliates of
the registrant was approximately $313,317,825 of March 13, 2002, based on the
closing sales price of the registrant's common stock on the New York Stock
Exchange on such date of $30.99 per share. For purposes of the preceding
sentence only, all directors, executive officers and beneficial owners of ten
percent or more of the common stock are assumed to be affiliates. As of March
13, 2002, 30,490,680 shares of common stock were outstanding.

                     INCORPORATION OF DOCUMENTS BY REFERENCE

      Portions of The Houston Exploration Company's definitive proxy statement
relating to the registrant's 2002 annual meeting of stockholders, which proxy
statement will be filed under the Securities Exchange Act of 1934 within 120
days of the end of the registrant's fiscal year ended December 31, 2001, are
incorporated by reference into Part III of this Form 10-K.
================================================================================
<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

      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 offshore properties are located primarily in the shallow
waters of the Gulf of Mexico, and our onshore properties are located in South
Texas, the Arkoma Basin of Oklahoma and Arkansas, South Louisiana, the
Appalachian Basin in West Virginia and East Texas.

      At December 31, 2001, our net proved reserves were 608 billion cubic feet
equivalent, or Bcfe, with a discounted present value of cash flows before income
taxes of $714 million. Our focus is natural gas and approximately 93% of our net
proved reserves at December 31, 2001 were natural gas and approximately 74% of
our net proved reserves 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. As of
December 31, 2001, THEC Holdings Corp., an indirect wholly owned subsidiary of
KeySpan, owned approximately 67% of the outstanding shares of our common stock.

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


                                       -1-
<PAGE>

BUSINESS STRATEGY

      Our strategy is to use our technical expertise to grow our reserves,
production and cash flow through the application of a three-pronged approach
that combines:

      -     high potential offshore exploration and exploitation;
      -     lower risk, high impact exploitation and development drilling
            onshore; and
      -     selective opportunistic acquisitions both offshore and onshore.

We believe that the lower risk projects and more stable production typically
associated with our onshore properties complement our high potential exploratory
prospects in the Gulf of Mexico by balancing risk and reducing volatility.

      From January 1, 1997 through December 31, 2001, we increased our proved
reserve base at a compound annual growth rate of 13% and increased our annual
production at a compound annual growth rate of 23%. During the past five years,
we produced a total of 355 Bcfe and added 641 Bcfe of net proved reserves. Of
the total reserves added, we added 376 Bcfe through exploration and development
and 265 Bcfe through acquisitions. In total, we replaced 181% of production
through drilling and acquisitions, with 106% replaced through the drillbit
alone. During December 2001, our daily production averaged 259 million cubic
feet equivalent, or MMcfe, per day.

      We focus on the following elements in implementing our strategy:

High Potential Exploratory and Development Drilling in the Gulf of Mexico

      We hold interests in 101 lease blocks, representing 496,955 gross (391,737
net) acres, in federal and state waters in the Gulf of Mexico, of which 59
blocks are undeveloped. We believe we have assembled a four-year inventory of
offshore prospects. We plan to drill approximately eight exploratory wells in
the Gulf of Mexico during 2002. Over the past five years, we have drilled 29
successful exploratory wells and 23 successful development wells in the Gulf of
Mexico, representing a historical success rate of 70%. Of our $250 million 2002
capital expenditure budget, we anticipate that approximately $96 million, which
excludes capitalized interest, capitalized general and administrative costs and
property acquisitions costs, will be spent on offshore projects. In addition, we
intend to continue our participation in federal lease sales and to actively
pursue attractive farm-in opportunities as they become available. Our management
believes that the Gulf of Mexico remains attractive for future exploration and
development activities due to the availability of geologic data, remaining
reserve potential and the infrastructure of gathering systems, pipelines,
platforms and providers of drilling services and equipment. Offshore properties
account for approximately 40% of our net proved reserves as of December 31,
2001. Our average daily production during December 2001 was 147 MMcfe per day,
net to our interests.

Lower Risk, High Impact Exploitation and Development Drilling Onshore

      We own significant onshore natural gas and oil properties in the following
areas:

      -     the Lobo trend in South Texas,
      -     the Arkoma Basin of Oklahoma and Arkansas,
      -     the South Lake Arthur and Lake Pagie Fields in South Louisiana,
      -     the Appalachian Basin in West Virginia, and
      -     East Texas.

      These properties favor exploitation and development drilling. Our onshore
properties account for approximately 60% of our net proved reserves at December
31, 2001. Complementing the offshore properties, our onshore properties are
typically characterized by relatively longer reserve lives, more predictable
production streams and lower operating cost structures. Over the past five
years, we have drilled or participated in the drilling of 191 successful
development wells and seven successful exploratory wells onshore, together
representing a historical


                                      -2-
<PAGE>

drilling success rate of 84%. We have identified an extensive inventory of more
than 200 potential onshore drilling locations, of which approximately 125 are
located in South Texas. Of our $250 million 2002 capital expenditure budget, we
anticipate that approximately $128 million, which excludes capitalized interest,
capitalized general and administrative costs and property acquisition costs,
will be spent on onshore projects, including the drilling of approximately 86
wells. Production from our onshore properties averaged 112 MMcfe per day, net to
our interests, during December 2001.

Opportunistic Acquisitions

      Our primary strategy to grow our reserves through the drillbit is
supplemented by our continuing pursuit of opportunistic acquisitions of
properties with unexploited reserve potential. We believe we have a successful
track record of building our reserves through acquisitions onshore and in the
Gulf of Mexico and successfully exploiting the reserves acquired. We target
properties that:

      -     we can operate;
      -     are either in the Gulf of Mexico or onshore in our existing
            operating areas or in new geographic areas in which we believe we
            can establish a substantial concentration of properties and
            operations; and
      -     provide a base for further exploration and development.

Use of Advanced Technology for In-House Prospect Generation

      We generate virtually all of our exploration prospects through our
in-house geological and geophysical expertise. We use advanced technology,
including 3-D seismic and in-house computer-aided exploration technology, to
reduce risks, lower costs and prioritize drilling prospects. We have assembled a
library of 3-D seismic data, covering approximately 98% of our undeveloped
offshore lease blocks and other possible lease and acquisition prospects in the
Gulf of Mexico. Onshore, our library of seismic data covers approximately 1,330
square miles of our South Texas acreage and surrounding areas and approximately
100 square miles in South Louisiana. We employ 11 geologists and geophysicists
with a combined industry experience averaging over 20 years. We use 14
geophysical workstations for interpretation of 3-D seismic data. The
availability of 3-D seismic data at reasonable costs has improved our ability to
identify exploration and development prospects in our existing inventory of
properties and to define possible lease and acquisition prospects.

High Percentage of Operated Properties

      Acquiring operating positions is a key component of our strategy.
Currently, we operate approximately 85% of our properties which accounted for
approximately 80% of our production during 2001. We prefer to operate our
properties in order to manage production performance while controlling operating
expenses and the timing and amount of capital expenditures. We also pursue cost
savings through the use of outside contractors for a portion of our offshore
field operations activities. During 2001, we realigned our internal operations
into two distinctive operating divisions, offshore and onshore, so that we could
effectively manage specific projects and growth strategies for each area. As a
result of these operating strategies combined with our close monitoring of costs
and expenses, we achieved lease operating expense (excluding severance taxes of
$0.12 per thousand cubic feet equivalent, or Mcfe) of $0.28 per Mcfe of
production and net general and administrative expense of $0.19 per Mcfe of
production for the year ended December 31, 2001.

Geographically Concentrated Operations

      We currently operate in six areas of geographic concentration: the Gulf of
Mexico, South Texas, the Arkoma Basin, South Louisiana, West Virginia and East
Texas. We continue to evaluate additional areas with the goal of adding them in
the future. By concentrating our operations into geographically focused areas,
we are able to manage a large asset base with a relatively small number of
employees and to add and operate production at relatively low incremental costs.
Our strategy of focusing drilling activities on properties in relatively
concentrated


                                      -3-
<PAGE>

offshore and onshore areas permits us to more efficiently utilize our base of
geological, engineering, exploration and production experience in these regions.

RECENT ACQUISITION

      Conoco Acquisition. On December 31, 2001, we completed the purchase of
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 Charco Field, and
represent interests in approximately 159 producing wells. We operate
approximately 95% of the producing wells we acquired and our average working
interest is 87%. With this acquisition, we have expanded and expect to improve
our operations in South Texas which have been an area of strategic growth for us
over the last five years. During February 2002, the properties we acquired
produced approximately 19.0 MMcfe per day, net to our interests.

KEYSPAN JOINT VENTURE

      Effective January 1, 1999, we entered into a joint exploration agreement
with KeySpan Exploration & Production, LLC, a subsidiary of our majority
stockholder, KeySpan, to explore for natural gas and oil over an initial
two-year term expiring on December 31, 2000. Under the terms of the joint
venture, we contributed all of our then undeveloped offshore acreage to the
joint venture and KeySpan was entitled to 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 per year and all
additional intangible drilling costs incurred were paid 51.75% by KeySpan and
48.25% by Houston Exploration. Revenues are shared 55% Houston Exploration and
45% 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
will not participate in any of our offshore exploration prospects unless the
project involves 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 will not receive
any reimbursement from KeySpan for general and administrative costs.

         Since the beginning of our joint venture with KeySpan in January 1999,
KeySpan has spent a total of $99.3 on exploration and development, with $ 17.2
million spent during 2001, $46.5 million spent during 2000 and $35.6 million
spent during 1999. During the initial two-year exploratory term of the joint
venture, we received from KeySpan a total of $7.3 million in general and
administrative expense reimbursements, with $2.5 million paid during 2000 and
$4.8 million paid during 1999. Reimbursement for general and administrative
expenses terminated in 2000 with the expiration of the exploratory term of the
joint venture.

         During the initial two-year term of the joint drilling program
beginning January 1, 1999 and ending December 31, 2000, we drilled a total of 21
wells under the terms of the joint venture: 17 exploratory wells and four
development wells. Five of the wells drilled were unsuccessful. During 2001,
KeySpan participated in three additional wells, all of which were successful,
and further developed or delineated reservoirs discovered during the initial
term of the joint venture. For 2002, KeySpan has committed to a capital budget
of $15 million for development projects associated with its working interests in
wells drilled under the joint venture during 1999, 2000 and 2001.


                                      -4-
<PAGE>

GULF OF MEXICO PROPERTIES

      We hold interests in 101 offshore blocks, of which 33 are currently
producing. We operate 24 of these producing blocks, accounting for approximately
75% of our offshore production. The following table lists our net proved
reserves, average working interest and the operator for our largest offshore
fields as of December 31, 2001. These properties represent over 80% of our Gulf
of Mexico proved reserves and approximately 75% of our offshore production
during 2001:

<TABLE>
<CAPTION>
                                                NET PROVED RESERVES AT DECEMBER 31, 2001
                                              --------------------------------------------    AVERAGE
                                                    GAS           OIL           TOTAL         WORKING
              OFFSHORE FIELDS                     (MMCF)        (MBBLS)        (MMCFE)       INTEREST     OPERATOR
----------------------------------------------------------------------------------------------------------------------
<S>                                           <C>               <C>           <C>            <C>          <C>
Mustang Island Blocks A-31/32..............       63,077           188         64,205           100%      Company
West Cameron Blocks 76/77/60/61............       25,048           182         26,140            15%      Third Party
South Timbalier Blocks 314/317.............        4,323         3,020         22,443            55%      Company(1)
East Cameron Blocks 82/83..................       14,917           120         15,637           100%      Company
Mustang Island Blocks 858/868..............        9,743           214         11,027            83%      Company
High Island Blocks 38/39...................       10,737           142         11,589           100%      Company
West Cameron Block 587.....................       10,594            --         10,594            64%      Third Party
Vermilion Block 408........................        2,316         1,102          8,928            31%      Company(1)
East Cameron Blocks 81/84..................        4,885           129          5,659            14%      Third Party
Matagorda Island Blocks 651/671/672........        5,595             2          5,607            67%      Company
North Padre Island Block 883...............        4,859           116          5,555            17%      Third Party
All Other Gulf of Mexico (13 fields).......       30,657           807         35,499
                                              -----------------------------------------

Total Gulf of Mexico.......................      186,751         6,022        222,883
                                              =========================================
</TABLE>

---------------------------
(1)   Facility construction in progress at December 31, 2001.

      Offshore Drilling and Development. During 2001, we drilled fourteen
successful offshore wells: seven exploratory wells and seven development wells.
Unsuccessful wells totaled six: five exploratory wells and one development well.
Under the terms of our joint venture agreement with KeySpan, KeySpan opted to
participate in three wells during the year, all of which were prospects designed
to extend or further delineate prior discoveries. These projects consisted of a
fourth development well at North Padre Island 883, a second exploratory well at
South Timbalier 314/317 and a second exploratory well at East Cameron 81/84, all
of which were successful. In addition to these KeySpan joint venture projects,
we had exploratory success at East Cameron 83, South Marsh Island 253, Galveston
Island 241, High Island 39 and Matagorda Island 682. Development projects during
2001 included the drilling of four development wells at our Mustang A-31/32
Field, one well at Galveston 252 and one well at the West Cameron 76/77 Field.

      For 2002, we plan to drill approximately eight offshore exploratory wells
and approximately two to three development wells. At December 31, 2001, we had
one offshore well in progress: our third development well at Vermilion 408. The
well was successfully completed, tied-in and put on-line in early February 2002.
Facilities and pipelines were completed at Vermilion 408 during December 2001
and initial production from the two wells drilled during 2000 began in early
January 2002. Production from all three wells is currently averaging 10.5
MMcfe/day, net to our interest. KeySpan has an interest in all three of these
wells. We are currently drilling a fourth well at this location. This well is
exploratory and will test a new fault block to the southwest of our current
discoveries.

      Other offshore wells currently in progress include two wells at East
Cameron 81/84, both of which are exploratory and are being drilled by third
parties. KeySpan is participating in both of these wells because the prospects
could possibly extend previously discovered reservoirs. Facility installation
and hook-up of East Cameron 81 #13 is currently in progress and initial
production is expected by the end of March 2002. East Cameron 81


                                      -5-
<PAGE>

#13 was an exploratory well drilled by a third party during 2001 and was the
second well drilled at this location. The first well, East Cameron 84 #1, was
drilled and completed by a third party during 1999 and is currently producing.
KeySpan also has an interest in both East Cameron 81 #13 and East Cameron 84 #1.
A fourth development well, East Cameron 81 #16 is planned for the second quarter
of 2002. Facility construction is currently in progress at South Timbalier
314/317. The first discovery well was drilled at South Timbalier 317 during 2000
and a second exploratory well was drilled at South Timbalier 314 during 2001.
KeySpan also has an interest in these wells. A third well is planned for 2002.
Initial production is expected during the first quarter of 2003.

      Offshore Capital Spending. Capital spending associated with our Gulf of
Mexico properties during 2001 was $201.6 million, including $67.2 million for
exploratory drilling, $97.3 million for development drilling, workovers and
facilities construction and $37.1 million for leasehold costs, which includes
capitalized interest and capitalized general and administrative costs. We did
not acquire any offshore producing properties during 2001. Of our $250 million
2002 capital expenditure budget, we currently estimate we will spend
approximately $96 million, which excludes capitalized interest, capitalized
general and administrative costs and property acquisition costs of our capital
expenditure budget of $250 million on offshore projects. KeySpan has committed
to a capital budget of $15 million in 2002 for development projects associated
with its working interests in wells drilled under the joint venture during
1999, 2000 and 2001.


                                      -6-
<PAGE>

ONSHORE PROPERTIES

      We own significant onshore natural gas and oil properties in South Texas,
the Arkoma Basin of Oklahoma and Arkansas, South Louisiana, the Appalachian
Basin in West Virginia and East Texas. These properties represent interests in
1,330 gross (1,042.7 net) producing wells, approximately 85% of which we are the
operator of record, and 198,781 gross (126,448 net) acres.

      The following table lists our average working interest and net proved
reserves for our onshore areas of operation as of December 31, 2001,
representing all of our onshore reserves:

<TABLE>
<CAPTION>
                                                                                        NET PROVED RESERVES AT
                                                                                           DECEMBER 31, 2001
                                                                        AVERAGE   -----------------------------------
                                                                        WORKING       GAS          OIL        TOTAL
ONSHORE OPERATING AREAS                                                INTEREST      (MMCF)      (MBBLS)     (MMCFE)
--------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>       <C>             <C>         <C>
SOUTH TEXAS:
  Charco Field.....................................................     100%         149,824        60       150,184
  Alexander, Haynes, Hubberd and South Trevino Fields .............     87%           78,936        97        79,518
                                                                                 -----------------------------------
     Total South Texas.............................................                  228,760       157       229,702
ARKOMA BASIN:
  Chismville/Massard Field (Arkansas)..............................     73%           94,099        --        94,099
  Wilburton, Panola and Surrounding Fields (Oklahoma)..............     23%            6,812        --         6,812
                                                                                 -----------------------------------
     Total Arkoma Basin............................................                  100,911        --       100,911
OTHER ONSHORE:
  South Louisiana..................................................     55%           21,690       269        23,304
  Appalachian Basin................................................     60%           21,984        47        22,266
  East Texas.......................................................     53%            8,112       110         8,772
                                                                                 -----------------------------------
     Total Other Onshore...........................................                   51,786       426        54,342

TOTAL ONSHORE......................................................                  381,457       583       384,955
                                                                                 ===================================
</TABLE>

      Onshore Capital Spending. We drilled or participated in the drilling of 61
successful onshore wells during 2001: 60 successful development wells and one
successful exploratory well. During this same period, we drilled or participated
in the drilling of 15 unsuccessful wells: three exploratory and 12 development
wells. Capital spending associated with our onshore drilling program during 2001
was approximately $164.7 million, including $79.9 million for development, $4.9
million for exploration and $79.9 million for leasehold and producing property
acquisition costs, which includes $69 million spent to acquire producing
properties located in South Texas from Conoco Inc. in December 2001 (see
Alexander, Haynes, Hubberd and South Trevino Fields, below).

      Of our $250 million 2002 capital expenditure budget, we currently estimate
we will spend approximately $128 million, which excludes capitalized interest,
capitalized general and administrative costs and property acquisition costs, on
onshore projects. For 2002, we plan to drill approximately 86 onshore wells: 56
wells in South Texas and 30 wells in the Arkoma Basin. We believe we have
identified enough additional development and exploratory projects on our
existing acreage to maintain an active drilling program for four years.


                                      -7-
<PAGE>

      The following is a description of our onshore operating areas:

      South Texas

      Charco Field. The Charco Field is located in Zapata County, Texas. We
acquired properties in the Charco Field in July 1996. We own a 100% working
interest in approximately 268 active wells in the Charco Field, all of which we
operate. Since the acquisition of the Charco Field in July 1996, we have used an
active drilling and workover program to increase production and reserves from
the field. Production has more than doubled since July 1996, from an average of
38 MMcfe per day, net to our interest, to an average of 83 MMcfe per day, net to
our interest, during 2001. We have drilled 116 successful wells, added 182 Bcfe
in reserves and produced 145 Bcfe since the acquisition of the Charco Field.
During 2001, we successfully drilled 29 development wells and seven unsuccessful
development wells. Production during December 2001 averaged approximately 78
MMcfe/day, net to our interests. Subsequent to year end, we have successfully
drilled and completed five development wells, drilled two dry holes and are
currently in the process of drilling three new development wells. Our production
has increased to an average of 89 MMcfe/day, net to our interests, during
February 2002. We are planning to keep two to three drilling rigs operating in
the Charco Field during 2002.

      Alexander, Haynes, Hubberd and S. Trevino Fields. On December 31, 2001,we
acquired from Conoco Inc. interests in 159 producing wells together with
developed and undeveloped acreage covering approximately 25,274 gross (16,885
net) acres. The properties we purchased are located in close proximity to our
existing operations in the Charco Field. The Alexander and Hubberd leases are in
Webb County and the Haynes and South Trevino leases are in Zapata County in
South Texas. We are operator of approximately 95% of the wells we acquired and
our average working interest is 87%. A recompletion and drilling program began
immediately after the closing of our acquisition and currently we have three
rigs in operation. Since January 1, 2002, we have commenced drilling of six
wells: four have been successfully completed, one was dry and one is
currently drilling. Production from the newly acquired wells is currently
averaging approximately 19.0 MMcfe/day, net to our interests.

      Arkoma Basin

      Chismville/Massard Field. The Chismville/Massard Field is located in Logan
and Sebastian Counties, Arkansas. We own working interests in approximately 240
active wells, 150 of which we operate. Working interests in these wells range
from 11% to 100% and average approximately 73%. During 2001, we successfully
completed 26 gross (17.1 net) development wells. In addition, we drilled or
participated in four (1.7 net) unsuccessful wells. During December 2001,
production averaged 17 MMcfe per day, net to our interests. We plan to maintain
at least one drilling rig in the Arkoma Basin for the remainder of 2002.

      Wilburton, Panola and Surrounding Fields. The Wilburton and Panola Fields
are located in Latimer County, Oklahoma. We own working interests in 58 active
wells, of which we operate 18 wells. Working interests in these wells range from
1% to 63% and average approximately 23%. During 2001, we drilled or participated
in the drilling of five (0.8 net) successful development wells. At December 31,
2001, we had a 1% working interest in one well in progress in the South Panola
Field that was a deep test of the Spiro formation. The well was drilled to
15,800 feet and subsequently deemed uneconomical. During December 2001,
production averaged 4 MMcfe per day, net to our interest.

      Other Onshore Areas

      South Louisiana. Our South Louisiana properties are primarily located in
the South Lake Arthur and Lake Pagie Fields which are located in Vermilion and
Terrebonne Parishes, respectively. We own interests in 53 producing wells, eight
of which we operate. Working interests in these wells range from 2% to 70% and
average 55%. During 2001, we drilled or participated in the drilling of three
South Louisiana wells: one successful


                                      -8-
<PAGE>

exploratory well located in Acadia Parish with a working interest of 33% and two
unsuccessful wells, one development well with a working interest of 53% located
in South Lake Arthur and one exploratory well with a working interest of 15%
located in Lake Pagie. During December 2001, production from our South Louisiana
properties averaged approximately 7 MMcfe/day, net to our interests.

      Appalachian Area. The Belington, Clarksburg and Seneca Upshur Fields are
located in Barbour, Randolph, Upshur and Mingo Counties, West Virginia. We own
working interests in 668 producing wells, substantially all of which we operate.
Working interests in these wells range from 6% to 100% and average approximately
60%. During December 2001, production averaged 4 MMcfe per day, net to our
interests.

      East Texas. Our East Texas properties are primarily located in the Willow
Springs and surrounding fields. The Willow Springs Field is located in Gregg
County, Texas, with the surrounding fields located in Panola and Harrison
Counties, Texas. We own working interests in 33 active wells, 28 of which we
operate. Working interests in these wells range from 3% to 100% and average
approximately 53%. During December 2001, production averaged 2 MMcfe per day,
net to our interests.


                                      -9-
<PAGE>

NATURAL GAS AND OIL RESERVES

      The following table summarizes the estimates of our historical net proved
reserves as of December 31, 2001, 2000 and 1999, and the present values
attributable to these reserves at these dates. The reserve data and present
values were prepared by Netherland, Sewell & Associates, Inc. and Miller and
Lents, Ltd., independent petroleum engineering consultants.

<TABLE>
<CAPTION>
                                                                          AS OF DECEMBER 31,
                                                            --------------------------------------------
                                                                2001            2000            1999
                                                            ------------  -----------------  -----------
                                                                           (IN THOUSANDS)
<S>                                                         <C>           <C>                <C>
Net Proved Reserves(1):
   Natural gas (MMcf)................................          568,208         529,518         526,185
   Oil (MBbls).......................................            6,605           5,352           2,470
   Total (MMcfe).....................................          607,838         561,630         541,005
Present value of future net revenues before income
  taxes(2)...........................................
                                                              $714,416      $2,725,913        $529,671
Standardized measure of discounted future net cash
  flows(3)...........................................
                                                              $551,525      $2,064,027        $469,225
</TABLE>

---------------------------
(1)   Netherland, Sewell & Associates prepared reserve data for our Gulf of
      Mexico properties and our South Texas properties which represent present
      values of approximately 79%, 78% and 76%, respectively, of our reserves at
      December 31, 2001, 2000 and 1999. Miller and Lents prepared reserve data
      for the remainder of our onshore properties which represent approximately
      21%, 22% and 24%, respectively, of the present values attributable to our
      proved reserves at December 31, 2001, 2000 and 1999.
(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 on a pre-tax basis. Average prices
      per Mcf of natural gas used in making the present value determinations as
      of December 31, 2001, 2000 and 1999 were $2.38, $9.55 and $2.01,
      respectively. Average prices per Bbl of oil used in making the present
      value determinations as of December 31, 2001, 2000 and 1999 were $17.78,
      $24.69 and $22.80, respectively. Amounts include the discounted present
      value of our hedges in place at December 31, 2001, 2000 and 1999 of a
      positive $65.8 million, a negative $70.6 million and a positive $1.6
      million, 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.


                                      -10-
<PAGE>

DRILLING ACTIVITY

      The following table sets forth our drilling activity on our properties for
the years ended December 31, 2001, 2000 and 1999.

<TABLE>
<CAPTION>
                                                                  YEAR ENDED DECEMBER 31,
                                      -----------------------------------------------------------------------------
                                                2001                       2000                      1999
                                      -----------------------   ------------------------   ------------------------
                                         GROSS         NET         GROSS         NET          GROSS         NET
                                      ----------   ----------   -----------   ----------   -----------  -----------
<S>                                   <C>          <C>          <C>           <C>          <C>          <C>
OFFSHORE DRILLING ACTIVITY:
  Exploratory:
     Productive.....................        7           4.4           8            3.0           6           1.4
     Non-Productive.................        5           3.9           2            0.9           2           1.0
                                      -------      --------     -------       --------     -------      --------
          Total.....................       12           8.3          10            3.9           8           2.4
  Development:
     Productive.....................        7           4.9           6            3.3           8           5.5
     Non-Productive.................        1           1.0           2            0.8          --            --
                                      -------      --------     -------       --------     -------      --------
          Total.....................        8           5.9           8            4.1           8           5.5

ONSHORE DRILLING ACTIVITY:
  Exploratory:
     Productive.....................        1           0.3           1            0.1           2           1.2
     Non-Productive.................        3           1.0          --             --          --            --
                                      -------      --------     -------       --------     -------      --------
          Total.....................        4           1.3           1            0.1           2           1.2
  Development:
     Productive.....................       60          46.9          44           36.5          31          24.3
     Non-Productive.................       12           9.2           4            3.5           6           3.1
                                      -------      --------     -------       --------     -------      --------
          Total.....................       72          56.1          48           40.0          37          27.4
</TABLE>

PRODUCTIVE WELLS

      The following table sets forth the number of productive wells in which we
owned an interest as of December 31, 2001.

<TABLE>
<CAPTION>
                          PRODUCING                COMPANY
                          PLATFORMS             OPERATED WELLS           NON-OPERATED WELLS      TOTAL PRODUCTIVE WELLS
                  ----------------------   ------------------------   -----------------------   ------------------------
                   OPERATED      NON-OP       GROSS         NET         GROSS          NET        GROSS          NET
                  ----------   ---------   ----------   -----------   ----------   ----------   ----------   -----------
<S>               <C>          <C>         <C>          <C>           <C>          <C>          <C>          <C>
OFFSHORE
    Gas.........       29           11           50         41.3            23          5.7           73          47.0
    Oil.........       --           --            2          1.1            --           --            2           1.1
                  -------      -------     --------     --------      --------     --------     --------     ---------
    Total.......       29           11           52         42.4            23          5.7           75          48.1
                  =======      =======     ========     ========      ========     ========     ========     =========

ONSHORE
    Gas.........                              1,274        997.4           203         39.8        1,477       1,037.2
    Oil.........                                  4          2.9            --           --            4           2.9
                                           --------     --------      --------     --------     --------     ---------
    Total.......                              1,278      1,000.3           203         39.8        1,481       1,040.1
                                           ========     ========      ========     ========     ========     =========
</TABLE>

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


                                      -11-
<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, 2001. 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>
                           TOTAL ACRES         DEVELOPED ACRES      UNDEVELOPED ACRES
                       -------------------  --------------------   -------------------
                         GROSS       NET      GROSS       NET        GROSS       NET
                       --------   --------  --------   ---------   --------   --------
<S>                    <C>        <C>       <C>        <C>         <C>        <C>
Offshore(1)..........   496,995    391,737   208,359     125,659    288,636    266,078
Onshore..............   198,781    126,448   184,060     119,759     14,721      6,689
                       --------   --------  --------   ---------   --------   --------
         Total.......   695,776    518,185   392,419     245,418    303,357    272,767
                       ========   ========  ========   =========   ========   ========
</TABLE>

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

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

MARKETING AND CUSTOMERS

      We sell substantially all of our production 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. During the last three fiscal years, we sold
natural gas and oil production representing 10% or more of our natural gas and
oil revenues as follows:

<TABLE>
<CAPTION>
                                                FOR THE YEAR ENDED DECEMBER 31,
                                        ---------------------------------------------
MAJOR PURCHASER                         2001               2000                 1999
-------------------------------------------------------------------------------------
<S>                                     <C>                 <C>                 <C>
Dynegy Inc.                             16.4%               22.5%               18.0%
Adams Resources and Energy, Inc         12.5%               14.9%               22.5%
El Paso Corporation(1)                   9.5%                9.1%                7.7%
</TABLE>

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

(1)   Amount purchased was less than 10% of our natural gas and oil sales
      revenues and is included for information purposes only.

      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. 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 transport most of our natural gas through third party gas gathering
systems and gas pipelines. Transportation space on these gathering systems and
pipelines is occasionally limited and at times unavailable because of repairs or
improvements as a result of priority transportation agreements with gas shippers
other than us. 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 " Regulation" and "Risk Factors --
Hazard Losses May Not Be Insured."


                                      -12-
<PAGE>

ABANDONMENT COSTS

      We are responsible for our working interest share of costs to abandon
natural gas and oil properties and facilities. We provide for our expected
future abandonment liabilities by accruing for abandonment costs as a component
of depletion, depreciation and amortization as the properties are produced. As
of December 31, 2001, total undiscounted abandonment costs estimated to be
incurred through the year 2013 were approximately $21 million for properties in
the federal and state waters and we do not consider them significant for our
onshore properties. 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. See
Note 1 -- Summary of Organization and Significant Accounting Policies -- New
Accounting Pronouncements, for a discussion of prospective changes for
accounting for abandonment costs under Statement of Financial Accounting
Standards No. 143, "Accounting for Asset Retirement Obligations".

      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 conduct only a cursory
review of title to farm-out acreage and to undeveloped natural gas and oil
leases upon execution of the asset purchase contracts. 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 the value of the properties.

THIRD PARTY CONTRACTORS

      In an effort to control offshore operating costs, we entered into a
contract with Grasso Production Management, Inc. pursuant to which Grasso
provides us with professional services relating to the supervision of the daily
production operations and field personnel to operate and maintain production
facilities. Our contract with Grasso was effective December 2001. From 1989 to
December 2001, we maintained a similar contractual arrangement for offshore
services with Operators & Consulting Services. In addition to assisting us with
daily production operations, Operators & Consulting Services provided
engineering and field supervision for well design, drilling, completion and
workover operations and coordination and review of third party engineering and
fabrication work, and installation supervision of platforms, production
facilities and pipelines. These functions are now performed by our own offshore
engineering department.


                                      -13-
<PAGE>

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.

OPERATING HAZARDS AND UNINSURED 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:

      -     fires,
      -     natural disasters,
      -     explosions,
      -     encountering formations with abnormal pressures,
      -     blowouts,
      -     cratering,
      -     pipeline ruptures, and
      -     spills.

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. As
protection against operating hazards, we maintain insurance coverage against
some, but not all, potential losses. Our coverage includes, but is not limited
to, the operator's extra expense to include loss of well, blowouts and costs of
pollution control, physical damage on assets, employer's liability,
comprehensive general liability, automobile liability and worker's compensation.
We believe that our insurance is adequate and customary for companies of a
similar size engaged in operations similar to ours, but losses could occur for
uninsurable or uninsured risks or in amounts in excess of existing insurance
coverage. The occurrence of an event that is not fully covered by insurance
could have a material adverse impact on our financial condition and results of
operations.

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.


                                      -14-
<PAGE>

      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:

      -     the location of wells,
      -     the method of drilling and casing wells,
      -     the surface use and restoration of properties upon which wells are
            drilled, and
      -     the plugging and abandoning of wells.

      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.

      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 has promulgated regulations requiring
offshore production facilities located on the outer continental shelf to meet
stringent engineering and construction specifications, and has recently proposed
additional safety-related regulations concerning the design and the operating
procedures for outer continental shelf production platforms and pipelines. The
Minerals Management Service also has issued regulations restricting the flaring
or venting of natural gas, and has recently proposed to amend these regulations
to prohibit the flaring of liquid hydrocarbons and oil without prior
authorization. Similarly, the Minerals Management Service has promulgated other
regulations governing the plugging and abandonment of wells located offshore and
the removal of all production facilities. To cover the various obligations of
lessees on the 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.


                                      -15-
<PAGE>

      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:

      -     require the acquisition of a permit before drilling commences,
      -     restrict the types, quantities and concentration of various
            substances that can be released into the environment in connection
            with drilling and production activities,
      -     limit or prohibit drilling activities on lands lying within
            wilderness, wetlands and other protected areas,
      -     require remedial measures to prevent pollution from former
            operations, such as pit closure and plugging of abandoned wells, and
      -     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.

      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.


                                      -16-
<PAGE>

      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 permitttee 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 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.

      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 nonjurisdictional gathering Facilities, which has the
tendency to increase our costs of getting gas to point-of-sale locations.


                                      -17-
<PAGE>

RISK FACTORS AFFECTING OUR BUSINESS

      THE VOLATILITY OF NATURAL GAS AND OIL PRICES MAY 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:

     -     the domestic and foreign supply of natural gas and oil;
     -     the price of foreign imports;
     -     overall domestic and global economic conditions;
     -     political and economic conditions in oil producing countries;
     -     the level of consumer product demand;
     -     weather conditions;
     -     domestic and foreign governmental regulations; and
     -     the price and availability of alternative fuels.

      We cannot predict future natural gas and oil price movements. 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 not significantly
improve from current 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. Our capital expenditure budget for exploration, development and
leasehold acquisitions for 2002 is estimated at approximately $250 million. This
budget excludes potential property acquisitions. We believe that we will have
sufficient cash provided by operating activities and available borrowing
capacity under our bank credit facility to fund planned capital expenditures in
2002. If our revenues or borrowing base under the bank 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 bank credit facility may not be sufficient to
meet our capital requirements.


                                      -18-
<PAGE>

      THE AMOUNT OF OUR OUTSTANDING INDEBTEDNESS IS SUBSTANTIAL AND COULD HAVE
ADVERSE CONSEQUENCES.

      Our outstanding indebtedness at December 31, 2001 was $244 million, and as
of March 14, 2002 was $251 million.

      Our level of indebtedness affects our operations in a number of ways. Our
bank 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.
Accordingly, these funds will not be available for other purposes. 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. Our future
performance, in turn, is dependent upon many factors that are beyond our control
such as general economic, financial and business conditions. Our future
performance may be adversely affected by these economic, financial and business
conditions.

      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, natural gas
liquids 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, natural gas liquids
and natural gas prices after the date of the estimate may result in substantial
upward or downward revisions.

      WE MAY NOT BE ABLE TO REPLACE RESERVES.

      Our future success depends on our ability to find, develop and acquire
natural gas and oil reserves. Without successful exploration, development or
acquisition activities, our reserves and 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 bank credit facility is based, at least
in part, on the estimated quantities of our proved reserves.

      HAZARD LOSSES MAY NOT BE INSURED.

      The natural gas and oil business involves many types of operating and
environmental hazards and risks. We are insured against some, but not all, of
the hazards associated with our business. We believe this is standard practice
in our industry. Because of this practice, however, we may be liable or sustain
losses that could be substantial due to events that are not insured.


                                      -19-
<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. We review the
properties we intend to acquire in a fashion that we believe is generally
consistent with industry practice. This review typically includes on-site
inspections and the review of environmental compliance reports filed with the
Minerals Management Service. This review, however, will not reveal all existing
or potential problems nor will it permit us to become sufficiently familiar with
the properties to fully assess their deficiencies and capabilities. We may not
always perform inspections on every platform 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.

      OUR HEDGING ACTIVITIES MAY LIMIT THE BENEFIT OF INCREASED PRICES.

      Almost all our revenues are generated from the sale of the natural gas we
produce. Periodically, we enter into hedging arrangements relating to a portion
of our natural gas production to achieve a more predicable cash flow, as well as
to reduce our exposure to adverse price fluctuations of natural gas. The hedging
instruments we use are fixed price swaps, collars and options. While using these
types of hedging instruments limits the downside risk of adverse price
movements, a number of risks exist, including instances in which the benefit to
revenues is limited when natural gas prices increase. For example, as a result
of hedges, during the first quarter 2001 our average realized natural gas price
was $5.48 per Mcf which was 80% of the average unhedged natural gas price of
$6.86 per Mcf that otherwise would have been received, resulting in natural gas
and oil revenues that were $30.5 million lower that the revenues we would have
achieved if we had not hedged approximately 70% of our production. In addition,
counter parties to our futures contract may not be able to meet the financial
terms of the hedging transactions with us.

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

      Environmental and other governmental regulations have increased the costs
to plan, design, drill, install, operate and abandon oil and natural gas wells,
offshore platforms and other facilities. We have expended and continue to expend
significant resources, both financial and managerial, to comply with
environmental regulations and permitting requirements. 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.

      WE FACE STRONG COMPETITION.

      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.


                                      -20-
<PAGE>

      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 ownership of approximately 67%
of our common stock. KeySpan does not consider our company a core asset and may
decide to sell all or part of its ownership interest in us in a transaction that
does not provide our public stockholders the opportunity to sell their shares to
the purchaser for a price reflecting a change-of-control premium. Further,
KeySpan is in a position to control:

      -     the election of the entire Board of Directors;
      -     the outcome of the vote on all matters requiring the vote of our
            stockholders;
      -     all matters relating to our management;
      -     the acquisition or disposition of our assets, including the sale of
            our business as a whole;
      -     payment of dividends on our common stock;
      -     the future issuance of our common stock or other securities; and
      -     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: Craig G. Matthews is former Vice Chairman,
President and Chief Operating Officer of KeySpan, retired March 1, 2002; 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; and James Q. Riordan is currently a director of KeySpan
who intends to retire from KeySpan's Board in May 2002.

EMPLOYEES

      As of December 31, 2001, we had 128 full time employees, 78 of whom are
located at our headquarters in Houston, Texas and the remainder of whom are
located at field offices. None of our employees are represented by a labor
union. During 2001 and 2000, we contracted with Operators & Consulting Services
to conduct all of the day to day operations of our offshore properties. In
December 2001, we contracted with Grasso Production Management, Inc. to conduct
these same offshore operations. Please read the section entitled "Third Party
Contractors."

OFFICES

      We currently lease approximately 69,000 square feet of office space in
Houston, Texas, where our principal offices are located. In addition, we
maintain field operations offices in the areas where we operate onshore
properties.


                                      -21-
<PAGE>

ITEM 3. LEGAL PROCEEDINGS

      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, 2001.

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, 2001 as
reported on the New York Stock Exchange:

<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>

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 2000                                HIGH           LOW
--------------------------------------------------------------------------------
<S>                                                      <C>            <C>
First Quarter.........................................   $   20.94      $  14.50
Second Quarter........................................       25.75         17.38
Third Quarter.........................................       28.31         21.19
Fourth Quarter........................................       39.75         21.88
</TABLE>

      As of March 13, 2002, 30,490,680 shares of common stock were outstanding
and we had approximately 44 stockholders of record and approximately 3,300
beneficial owners.

DIVIDENDS

      We have not paid any cash dividends during the two most recent fiscal
years and do not anticipate declaring any dividends in the foreseeable future.
We expect that we will retain our cash for the operation and expansion of our
business, including exploration, development and acquisition activities. Our
bank credit facility and the indenture governing our 8 5/8% senior subordinated
notes contain restrictions on the payment of dividends to holders of common
stock. Accordingly, our ability to pay dividends will depend upon 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."


                                      -22-
<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, 2001. 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,
                                              -------------------------------------------------------------------
                                                  2001           2000          1999          1998          1997
                                              ------------  ------------  ------------  ------------  -----------
                                                               (IN THOUSANDS, EXCEPT PER SHARE DATA)
<S>                                           <C>           <C>           <C>           <C>           <C>
CONSOLIDATED STATEMENT OF OPERATIONS DATA:
Revenues:
  Natural gas and oil revenues..............  $    379,504  $    270,595  $    150,580  $    127,124  $   116,349
  Other.....................................         1,353         1,738         1,147         1,123        1,297
                                              ------------  ------------  ------------  ------------  -----------
        Total revenues......................       380,857       272,333       151,727       128,247      117,646
Expenses:
  Lease operating...........................        25,291        23,553        18,406        16,199       14,146
  Severance tax.............................        11,035         9,757         5,444         4,967        4,233
  Depreciation, depletion and amortization..       128,736        89,239        74,051        79,838       59,081
  Writedown in carrying value...............         6,170            --            --       130,000           --
  General and administrative, net...........        17,110         8,928         4,150         6,086        5,825
                                              ------------  ------------  ------------  ------------  -----------
        Total operating expenses............       188,342       131,477       102,051       237,090       83,285
Income (loss) from operations...............       192,515       140,856        49,676      (108,843)      34,361
Strategic review expenses(1)................           119         1,752            --            --           --
Interest expense, net.......................         2,992        11,361        13,307         4,597          938
                                              ------------  ------------  ------------  ------------  -----------
Income (loss) before income taxes...........       189,404       127,743        36,369      (113,440)      33,423
Income tax provision (benefit)..............        66,803        42,485        11,748       (40,754)      10,173
                                              ------------  ------------  ------------  ------------  -----------
Net income (loss)...........................  $    122,601  $     85,258  $     24,621  $    (72,686) $    23,250
                                              ============  ============  ============  ============  ===========

Net income (loss) per share.................  $       4.06  $       3.06  $       1.03  $      (3.05) $      1.00
                                              ============  ============  ============  ============  ===========
Net income (loss) per share--diluted........  $       4.00  $       3.02  $       0.95  $      (3.05) $      0.97
                                              ============  ============  ============  ============  ===========

Weighted average shares.....................        30,228        27,860        23,906        23,768       23,337
Weighted average shares--diluted............        30,645        28,213        28,310        23,768       24,028

Ratio of earnings to fixed charges(2).......         12.8x          5.5x          2.0x           N/M         5.0x
</TABLE>

<TABLE>
<CAPTION>
                                                                     AT YEAR END DECEMBER 31,
                                              -------------------------------------------------------------------
                                                  2001           2000          1999          1998          1997
                                              ------------  ------------  ------------  ------------  -----------
                                                                          (IN THOUSANDS)
<S>                                           <C>           <C>           <C>           <C>           <C>
CONSOLIDATED BALANCE SHEET DATA:
Property, plant and equipment, net..........  $    938,761  $    705,390  $    610,116  $    536,582  $   443,738
Total assets................................     1,059,092       837,384       678,483       569,452      491,391
Long-term debt and notes....................       244,000       245,000       281,000       313,000      113,000
Stockholders' equity........................       565,881       396,742       217,590       192,530      256,187
</TABLE>

---------------------------
(1)   Represents nonrecurring expenses incurred in connection with the decision
      to review strategic alternatives for Houston Exploration and KeySpan's
      investment in our Company, including the possible sale of all or a portion
      of Houston Exploration. Please read Note 6 -- Related Party Transactions.

(2)   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)


                                      -23-
<PAGE>

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

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 currently focused offshore in the Gulf of
Mexico and onshore in South Texas, the Arkoma Basin of Oklahoma and Arkansas,
South Louisiana, the Appalachian Basin in West Virginia and East Texas. Our
strategy is to utilize our technical expertise to continue to increase reserves,
production and cash flows through the application of a three-pronged approach
that combines an effective mix of:

      -     high potential offshore exploration and exploitation;
      -     lower risk, high impact exploitation and development drilling
            onshore; and
      -     selective opportunistic acquisitions both offshore and onshore

      At December 31, 2001, our net proved reserves were 608 Bcfe, with a
discounted present value of cash flows before income taxes of $714 million. Our
focus is natural gas. Approximately 93% of our net proved reserves at December
31, 2001 were natural gas of which approximately 74% of our net proved reserves
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. As of
December 31, 2001, THEC Holdings Corp., an indirect wholly owned subsidiary of
KeySpan, owned approximately 67% 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 hydrocarbons 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, as evidenced by the recent volatility of
natural gas and oil prices, and there can be no assurance that commodity prices
will not widely fluctuate 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

      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. Our amortization base includes estimates for future development
costs as well as future abandonment and dismantlement costs.

      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


                                      -24-
<PAGE>

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
Statement of Financial Accounting Standards ("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 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 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.

      In calculating our ceiling test at December 31, 2000 and 1999, we
estimated, using a wellhead price of $9.55 per Mcf and $2.01 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 $1.4 billion (after tax) for 2000 and
$99.2 million (after tax) for 1999. No writedown is required when a cushion
exists.

      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. Because there are numerous uncertainties
inherent in the estimation process, actual results could differ from the
estimates.

      Use of Estimates. The preparation of the consolidated financial statements
in conformity with generally accepted accounting principles 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.

      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. 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. 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, which revision 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.

      New Accounting Pronouncements.

      SFAS No. 133. We adopted the Financial Accounting Standards Board ("FASB")
Statement of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" on


                                      -25-
<PAGE>
January 1, 2001. The statement, as amended, requires companies to report the
fair market value of derivatives on the balance sheet and record in income or in
accumulated other comprehensive income, as appropriate, any changes in the fair
market value of the derivative. We utilize cash flow hedges to reduce the risk
of price volatility for our future natural gas production. Our hedges qualify
for hedge accounting under SFAS 133 because they are highly effective as they
are tied to the same indexes at which our natural gas production is sold. As a
result, when we mark-to-market our derivative instruments at the end of each
quarter, we are able to defer the gain or loss on the change in fair value in
accumulated other comprehensive income, a component of stockholders' equity. At
December 31, 2001, we estimated, using the New York Mercantile Exchange, or
NYMEX, index price strip as of that date, that the fair market value of our
hedges was $53.8 million. As a result, our balance sheet at December 31, 2001
reflects an asset of $53.8 million with a corresponding credit of $34.9 million
(net of related deferred taxes of $18.9 million) in accumulated other
comprehensive income, representing the fair market value of our deferred hedge
gain. See Note 8 -- Hedging Contracts.

      The FASB has recently issued SFAS No. 141, "Business Combinations," SFAS
No. 142, "Goodwill and Other Intangible Assets," SFAS No. 143, "Accounting for
Asset Retirement Obligations" and SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets."

      SFAS No. 141, "Business Combinations," requires the use of the purchase
method of accounting for all business combinations initiated after June 30,
2001. SFAS No. 142, "Goodwill and Other Intangible Assets", addresses accounting
for the acquisition of intangible assets and accounting for goodwill and other
intangible assets after they have been initially recognized in the financial
statements. We do not currently have goodwill or other similar intangible
assets; therefore, the adoption of the new standard on January 1, 2002, has not
had a material effect on our financial statements.

      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 will be effective for us January 1, 2003 and early adoption is encouraged.
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. Currently, we include 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 are evaluating
the impact the new standard will have on our financial statements.

      SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets," is effective for us January 1, 2002, and addresses accounting and
reporting for the impairment or disposal of long-lived assets. SFAS No. 144
supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of" and APB Opinion No. 30, "Reporting the
Results of Operations-Reporting the Effects of Disposal of a Segment of a
Business." SFAS No. 144 retains the fundamental provisions of SFAS No. 121 and
expands the reporting of discontinued operations to include all components of an
entity with operations that can be distinguished from the rest of the entity and
that will be eliminated from the ongoing operations of the entity in a disposal
transaction. We believe that the new standard will not have a material impact on
our financial statements.

Recent Developments

      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 Webb
and Zapata counties of South Texas. 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 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


                                      -26-
<PAGE>
87%. With this acquisition, we have expanded and expect to improve our
operations in South Texas which have been an area of strategic growth for us
over the past five years. Current production (for the month of February 2002) is
averaging 19.0 MMcfe/day, net to our interest.

      Appointment of New Executive Officer. Effective March 1, 2002, Roger B.
Rice was appointed to the newly created position of Senior Vice President Human
Resources and Administration. Mr. Rice has worked at Houston Exploration as a
paid consultant since June 2001. Prior to joining Houston Exploration, Mr. Rice
was Vice President and General Manager for Santa Fe Snyder Corporation from 1999
to 2001 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 Bachelor of Arts
degree and Masters degree in Business Administration from Texas Technological
University.


                                      -27-
<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,
                                              ---------------------------------------------
                                                   2001            2000            1999
                                              -------------   -------------   -------------
<S>                                           <C>             <C>             <C>
PRODUCTION:
    Natural gas (MMcf)......................     87,095          77,861          69,679
    Oil (MBbls).............................        459             311             258
    Total (MMcfe)...........................     89,849          79,727          71,227

AVERAGE SALES PRICES:
    Natural gas (per Mcf) realized(1).......  $    4.24       $    3.37       $    2.10
    Natural Gas (per Mcf) unhedged..........       4.09            3.96            2.14
    Oil (per Bbl)...........................      22.83           27.22           16.41

EXPENSES (PER MCFE):
    Lease operating.........................  $    0.28       $    0.30       $    0.26
    Severance tax...........................       0.12            0.12            0.08
    Depreciation, depletion and amortization       1.43            1.12            1.04
    Write down in carrying value of
      natural gas and oil properties........       0.07              --              --
    General and administrative, net.........       0.19            0.11            0.06
</TABLE>

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

(1)   Reflects the effects of hedging.

RECENT FINANCIAL AND OPERATING RESULTS

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. 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 $270.6 million for the year ended December 31, 2000 to $379.5 million for
the year ended December 31, 2001 as a result of a 26% increase in average
realized natural gas prices, from $3.37 per Mcf in 2000 to $4.24 per Mcf in
2001, combined with a 13% increase in production for the same period.


                                      -28-
<PAGE>

      Natural Gas Prices. As a result of hedging activities, we realized an
average gas price of $4.24 per Mcf for the year ended December 31, 2001, which
was 104% of the average unhedged natural gas price of $4.09 that 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 $3.37 per
Mcf, which was 85% of the average unhedged natural gas price of $3.96 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. 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.

      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


                                      -29-
<PAGE>

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 paydown 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 shares of our common stock (see Note 6 -- Related
Party Transactions -- 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
$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.

COMPARISON OF THE YEARS ENDED DECEMBER 31, 2000 AND 1999

      Production. Our production increased 12% from 71,227 MMcfe for the year
ended December 31, 1999 to 79,727 MMcfe for the year ended December 31, 2000.
The increase in production resulted from newly developed offshore production
brought on-line since the end of the second quarter of 1999.

      Offshore production increased 30% from an average of 76 MMcfe per day
during 1999 to an average of 99 MMcfe per day during 2000. The increase is
attributable to a full year of production from new wells drilled during 1999 at
Mustang Island A-31 and West Cameron 76 and new wells drilled and completed
during the second half of 2000 at West Cameron 587, North Padre Island 883,
Matagorda Island 704 and High Island 133. In addition, in May 2000, we acquired
incremental working interests in existing production at Vermilion 203, Mustang
Island 858 and West Cameron 76.

      Onshore production remained unchanged at 119 MMcfe per day during 2000 as
compared to 1999. During the third quarter of 2000, we experienced delays in
bringing new wells on-line at the Charco Field due to a shortage of completion
equipment and crews. By the middle of the fourth quarter of 2000, crews and
equipment became more readily available and we added a third drilling rig to
expedite our drilling program.


                                      -30-
<PAGE>

      Natural Gas and Oil Revenues. Natural gas and oil revenues increased 80%
from $150.6 million for the year ended December 31, 1999 to $270.6 million for
the year ended December 31, 2000 as a result of a 60% increase in average
realized natural gas prices, from $2.10 per Mcf in 1999 to $3.37 per Mcf in
2000, combined with a 12% increase in production for the same period.

      Natural Gas Prices. As a result of hedging activities, we realized an
average gas price of $3.37 per Mcf for the year ended December 31, 2000, which
was 85% of the average unhedged natural gas price of $3.96 that otherwise would
have been received, resulting in natural gas and oil revenues for the year ended
December 31, 2000 that were $46.3 million lower than the revenues we would have
achieved if hedges had not been in place during the period. For the
corresponding period during 1999, we realized an average gas price of $2.10 per
Mcf, which was 98% of the average unhedged natural gas price of $2.14 that
otherwise would have been received, resulting in natural gas and oil revenues
that were $2.6 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 28% from $18.4 million for the year ended December 31, 1999 to $23.6
million for the year ended December 31, 2000. On an Mcfe basis, lease operating
expenses increased from $0.26 per Mcfe during 1999 to $0.30 per Mcfe during
2000. The increase in lease operating expenses and lease operating expenses on a
per unit basis for the year ended December 31, 2000 is attributable to the
continued expansion of our operations, particularly offshore, combined with an
increase in service costs across the industry. Severance tax, which is a
function of volume and revenues generated from onshore production, increased
from $5.4 million for the year ended December 31, 1999 to $9.8 million for the
year ended December 31, 2000. On an Mcfe basis, severance tax increased from
$0.08 per Mcfe for the year ended December 31, 1999 to $0.12 per Mcfe for the
corresponding twelve month period of 2000. The increase in severance tax expense
and the rate per Mcfe reflects the higher natural gas prices received during
2000 as compared to 1999.

      Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased 20% from $74.1 million for the year ended
December 31, 1999 to $89.2 million for the year ended December 31, 2000.
Depreciation, depletion and amortization expense per Mcfe increased 8% from
$1.04 during 1999 to $1.12 during 2000. 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 2000 as compared to the corresponding
period of 1999 combined with the addition of fewer new reserves in 2000.

      General and Administrative Expenses. General and administrative expenses,
net of overhead reimbursements received from other working interest owners, of
$5.7 million and $3.6 million for the years ended December 31, 1999 and 2000,
respectively, increased 119% from $4.2 million for the year ended December 31,
1999 to $8.9 million for the year ended December 31, 2000. Included in
reimbursements received from working interest owners were reimbursements
totaling $2.5 million during 2000 and $4.8 million during 1999 received from
KeySpan pursuant to the joint venture with KeySpan (please read Note 6 --
Related Party Transactions). We capitalized general and administrative expenses
directly related to oil and gas exploration and development activities of $5.5
million and $9.6 million, respectively, for the years ended December 31, 1999
and 2000. The increase in capitalized general and administrative expenses is a
result of higher aggregate general and administrative expenses during 2000 as
compared to 1999. Aggregate general and administrative expenses are higher
during 2000 due to expansion of our workforce combined with an increase in
incentive compensation and benefit related expenses. On an Mcfe basis, general
and administrative expenses increased 83% from $0.06 for the year ended December
31, 1999 to $0.11 for the year ended December 31, 2000. The higher rate per Mcfe
during 2000 reflects an increase in aggregate general and administrative
expenses and the effect of the reduction in the KeySpan joint venture
reimbursements offset in part by an increase in capitalized expenses. Effective
December 31, 2000, pursuant to the termination of the primary term of the joint
venture, we will no longer receive general and administrative reimbursements
from KeySpan.


                                      -31-
<PAGE>

      Strategic Review Expenses. During the first quarter of 2000, we recorded
$1.8 million for expenses incurred in the 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 our role
within its future strategic plan, and was considering a full range of strategic
transactions including the possible sale of all or a portion of its interest in
us. In February 2000, we jointly announced that the review of strategic
alternatives had been completed. KeySpan also announced that it planned to
retain its equity position in us for the foreseeable future, however, they do
not consider their investment in our company a core asset.

      Interest Expense, Net. Interest expense, net of capitalized interest,
decreased 14% from $13.3 million for the year ended December 31, 1999 to $11.4
million for the year ended December 31, 2000. As a result of an increase in
exploratory drilling during the year ended December 31, 2000, capitalized
interest increased 15% from $11.9 million during 1999 to $13.7 million during
2000. For the year ended December 31, 2000, aggregate interest expense remained
unchanged at $25 million. Despite a decrease in average borrowings during 2000
due to a net pay down on our revolving bank line of credit totaling $36 million
and the March 31, 2000 conversion of $80 million in outstanding borrowings under
the KeySpan credit facility into shares of our common stock (please read Note 3
-- Stockholders' Equity), interest expense remained unchanged due to higher
interest rates during 2000 as compared to 1999. Interest rates on our total
outstanding borrowings averaged 8.07% during 2000 compared to 7.23% in 1999.

      Income Tax Provision. The provision for income taxes increased from $11.7
million for the year ended December 31, 1999 to $42.5 million for the year ended
December 31, 2000 due to the 251% increase in pre-tax income during 2000 from
$36.4 million during 1999 to $127.7 million during 2000 as a result of the
combination of higher natural gas prices and increased production offset in part
by the increase in operating expenses.

      Operating Income and Net Income. Despite the 29% increase in operating
expenses, the 12% increase in production and the 60% increase in realized
natural gas prices were significant enough to cause operating income to increase
184% from $49.7 million for the year ended December 31, 1999 to $140.9 million
for the year ended December 31, 2000. Correspondingly, net income increased 247%
from $24.6 million for the year ended December 31, 1999 to $85.3 million for the
year ended 2000.

LIQUIDITY AND CAPITAL RESOURCES

      We have historically funded our operations, acquisitions, capital
expenditures and working capital requirements from cash flows from operations,
equity capital from KeySpan as well as public sources, public debt and bank
borrowings. On March 31, 2000, we converted $80 million in outstanding
borrowings under a revolving credit facility established in November 1998 with
KeySpan into 5,085,177 shares of our common stock at a conversion price of
$15.732 per share. The credit facility with KeySpan was terminated at conversion
and resulted in an increase in their ownership percentage. As of December 31,
2001, KeySpan owned 67% of our outstanding common stock.

      Cash Flows From Operations. As of December 31, 2001, we had working
capital of $34.3 million and $105.6 million of borrowing capacity available
under our revolving bank credit facility. Net cash provided by operating
activities for the year ended December 31, 2001 was $358.0 million compared to
$200.8 million during the corresponding twelve month period of 2000. The
increase in net cash provided by operating activities was due to an increase in
net income combined with a decrease in working capital, excluding the non-cash
impact of the fair value of our derivative instruments. The decrease in working
capital is related to the timing of cash receipts and payments and is primarily
a result of the decrease in receivables, offset in part by a decrease in
payables. Receivables for natural gas and oil revenues are down at year end 2001
due to lower average commodity prices during the fourth quarter of 2001 as
compared to the corresponding period of 2000. Payables are lower at December
2001 due to a lower level of drilling activity and associated capital spending
during the fourth quarter of 2001 as compared to the fourth quarter of 2000. Our
cash position decreased during 2001 as a result of repayment


                                      -32-
<PAGE>

of borrowings under our revolving bank credit facility of $1 million. In
addition, cash increased by $10.2 million during 2001 due to proceeds received
from the issuance of common stock from the exercise of stock options. Funds used
in investing activities consisted of $368.3 million for investments in property
and equipment, which includes $69 million for the acquisition of producing
properties in South Texas from Conoco Inc. in December 2001. As a result of
these activities, cash and cash equivalents decreased $1.1 million from $9.7
million at December 31, 2000 to $8.6 million at December 31, 2001.

      Our primary sources of funds for each of the past three years are
reflected in the following table:

<TABLE>
<CAPTION>
                                                          YEARS ENDED DECEMBER 31,
                                                   ------------------------------------
                                                      2001         2000         1999
                                                   ---------    ---------    ----------
                                                              (IN THOUSANDS)
<S>                                                <C>          <C>          <C>
Net cash provided by operating activities........  $ 358,032    $ 200,791    $ 110,072
Net long-term (repayments) borrowings............     (1,000)     (36,000)      48,000
Proceeds from sale of common stock, net..........     10,189       13,894          439
</TABLE>

      Natural Gas and Oil Capital Expenditures. Over the past three years, we
have spent $698 million, which includes acquisition costs of: (i) $69 million in
2001 for the acquisition of additional producing properties in South Texas from
Conoco Inc. in December 2001; (ii) $13.9 million in 2000 for the purchase of
incremental working interests in various offshore producing properties; and
(iii) $21 million in 1999 for an interest in West Cameron Block 587, to add 372
Bcfe of net proved reserves, representing a three-year average finding and
development cost of $1.87 per Mcfe. During 2001, we spent a total of $366.4
million on the acquisition, development and exploration of natural gas and oil
properties and added 136 Bcfe of net proved reserves, representing a one year
average finding cost of $2.69 per Mcfe.

      Our natural gas and oil capital expenditures for each of the past three
years are reflected in the following table:

<TABLE>
<CAPTION>
                                                          YEARS ENDED DECEMBER 31,
                                                   ------------------------------------
                                                      2001         2000         1999
                                                   ---------    ---------    ----------
                                                              (IN THOUSANDS)
<S>                                                <C>          <C>          <C>
OFFSHORE:
Acquisitions and leasehold.......................  $  37,133    $  41,164    $   42,246
Development......................................     97,341       48,836        53,941
Exploration......................................     67,172       31,164         8,450
                                                   ---------    ---------    ----------
                                                     201,646      121,164       104,637

ONSHORE:
Acquisitions and leasehold.......................  $  79,945    $   5,370    $    5,196
Development......................................     79,915       54,499        34,024
Exploration......................................      4,884        2,996         3,807
                                                   ---------    ---------    ----------
                                                     164,744       62,865        43,027
                                                   ---------    ---------    ----------

Total............................................  $ 366,390    $ 184,029    $  147,664
                                                   =========    =========    ==========
</TABLE>

      Future Capital Requirements. Our capital expenditure budget for 2002 has
been set at $250 million including an estimated $80 million for exploration,
$145 million for development and facility construction and $25 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 2002. 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


                                      -33-
<PAGE>

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.

      Shelf Registration. On May 20, 1999, we filed a "shelf" registration with
the Securities and Exchange Commission to offer and sell in one or more
offerings up to a total offering amount of $250 million in securities which
could include shares of our common stock, shares of preferred stock or unsecured
debt securities or a combination thereof. Depending on market conditions and our
capital needs, we may utilize the shelf registration in order to raise capital.
We would use the net proceeds received from the sale of any securities for the
repayment of debt and/or to fund an acquisition. We may not be able to
consummate any offerings under the shelf registration statement on acceptable
terms.

      Capital Structure

      Revolving Bank Credit Facility. We maintain a revolving bank credit
facility with a syndicate of lenders led by JP Morgan Chase, National
Association. The credit facility provides a maximum commitment of $250 million,
which may be limited by the amount of the borrowing base. At December 31, 2001,
the borrowing base was $250 million. Up to $2.0 million of the borrowing base is
available for the issuance of letters of credit to support performance
guarantees. The credit facility matures on March 1, 2003 and is unsecured. At
December 31, 2001, $144 million was outstanding under the credit facility and
$0.4 million was outstanding in letter of credit obligations. Subsequent to
December 31, 2001, we have borrowed an additional $7 million, bringing total
borrowings and letters of credit to $151.4 million as of March 14, 2002.

Interest is payable on borrowings under the credit facility, at our option, 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
      -     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 is 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 requires a commitment fee of:

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

The weighted average interest rate was 6.22%, 7.9% and 6.59%, respectively, for
the years ended December 31, 2001, 2000 and 1999.

The credit facility contains covenants, including restrictions on liens and
financial covenants which require us to, among other things, maintain:

      -     an interest coverage ratio of 2.5 to 1.0 of earnings before
            interest, taxes and depreciation to cash interest;
      -     a total debt to capitalization ratio of less than 60%, exclusive of
            non-cash charges; and
      -     sets a maximum limit of 70% on the amount of natural gas production
            we may hedge during any 12 month period.

In addition to maintenance of financial ratios, the credit facility restricts
cash dividends and/or purchase or redemption of our stock. The credit facility
also restricts the encumbering of our oil and gas assets or the pledging of
those assets as collateral. As of December 31, 2001, we were in compliance with
all covenants.


                                      -34-
<PAGE>

      Senior Subordinated Notes. On March 2, 1998, we issued $100 million of
8 5/8% Senior Subordinated Notes due January 1, 2008. The notes bear interest at
a rate of 85/8% 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% after January 1, 2006 if the notes
are redeemed prior to January 1, 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:

      -     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;

      -     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;

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

      -     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.


                                      -35-
<PAGE>

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

      Natural Gas Hedging. We utilize derivative commodity instruments to hedge
future sales prices on a portion of our natural gas 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 financial institutions that we believe are
minimal credit risks. Our hedges are cash flow hedges and qualify for hedge
accounting under SFAS 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 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. At December 31, 2001 we estimated,
using a New York Mercantile Exchange (NYMEX) index price strip as of that date,
that the fair market value of our hedges represented an asset of $53.8 million
or $34.9 million net of deferred taxes.

      The following table summarizes the change in the fair value of our
derivative instruments from our adoption of SFAS 133 on January 1, 2001 to year
end December 31, 2001.

<TABLE>
<CAPTION>
CHANGE IN FAIR VALUE OF DERIVATIVES INSTRUMENTS                          2001
-------------------------------------------------------------------------------
<S>                                                                   <C>
Fair value of contracts at January 1 and adoption of SFAS 133 .....   $ (75,069)
Gain on contracts realized ........................................      12,926
Fair value of new contracts when entered ..........................       5,931
Changes in fair values due to changes in valuation assumptions ....          --
Other changes in fair values ......................................     109,983
                                                                      ---------
Fair value of contracts outstanding at December 31 ................   $  53,771
                                                                      =========
</TABLE>

      The following table summerize on a monthly basis our hedges for 2002 and
2003. All amounts are in thousands, except for prices. For 2002, we have hedged
approximately 60% of our estimated production or a total of 170,000 MMBtu/day at
an effective floor of $3.436 and an effective ceiling of $4.942 for the months
January through March. For the months April through December 2002, we have
hedged approximately 70% of our estimated production or a total of 190,000
MMBtu/day at an effective floor of $3.389 and an effective ceiling of $4.801.
Our effective floor for 2002 includes premiums paid for derivative instruments
totaling $5.9 million. We will amortize the premiums to expense during 2002 at a
rate of approximately $0.5 million per month. For the year 2003, we have 60,000
MMBtu/day hedged at an effective floor of $3.229 and an effective ceiling of
$3.486.


                                      -36-

<PAGE>

<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 2002                 930            $3.010             4,340            $3.643            $5.356
February 2002                840             3.010             3,920             3.643             5.356
March 2002                   930             3.010             4,340             3.643             5.356
April 2002                   900             3.010             4,200             3.643             5.356
May 2002                     930             3.010             4,340             3.643             5.356
June 2002                    900             3.010             4,200             3.643             5.356
July 2002                    930             3.010             4,340             3.643             5.356
August 2002                  930             3.010             4,340             3.643             5.356
September 2002               900             3.010             4,200             3.643             5.356
October 2002                 930             3.010             4,340             3.643             5.356
November 2002                900             3.010             4,200             3.643             5.356
December 2002                930             3.010             4,340             3.643             5.356

January 2003               1,240            $3.194               620             3.300             4.070
February 2003              1,120             3.194               580             3.300             4.070
March 2003                 1,240             3.194               620             3.300             4.070
April 2003                 1,200             3.194               600             3.300             4.070
May 2003                   1,240             3.194               620             3.300             4.070
June 2003                  1,200             3.194               600             3.300             4.070
July 2003                  1,240             3.194               620             3.300             4.070
August 2003                1,240             3.194               620             3.300             4.070
September 2003             1,200             3.194               600             3.300             4.070
October 2003               1,240             3.194               620             3.300             4.070
November 2003              1,200             3.194               600             3.300             4.070
December 2003              1,240             3.194               620             3.300             4.070
</TABLE>

      These hedging transactions are settled based upon the NYMEX price on the
final trading day of the month. In order to determine fair market value of our
derivative instruments, we obtain market 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.

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


                                      -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

      None.

PART III.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

      The information required by this Item 10 that relates to our directors and
executive officers is incorporated by reference from the information appearing
under the captions "Election of Directors" and "Executive Officers" in our
definitive proxy statement which involves the election of directors and is to be
filed with the Securities and Exchange Commission pursuant to the Securities
Exchange Act of 1934 within 120 days of the end of our fiscal year on December
31, 2001.

ITEM 11. EXECUTIVE COMPENSATION

      The information required by this Item 11 that relates to the management is
incorporated by reference from the information appearing under the captions
"Executive Compensation" and "Election of Directors - Director's Meetings and
Compensation" in our definitive proxy statement which involves the election of
directors and is to be filed with the Securities and Exchange Commission
pursuant to the Securities Exchange Act of 1934 within 120 days of the end of
our fiscal year on December 31, 2001. Notwithstanding the foregoing, in
accordance with the instructions to Item 402 of Regulation S-K, the information
contained in our proxy statement under the subheading "Report of the
Compensation Committee of the Board of Directors" and "Performance Graph" shall
not be deemed to be filed as part of or incorporated by reference into this Form
10-K.

ITEM 12. SECURITY OWNERSHIP OF BENEFICIAL OWNERS AND MANAGEMENT

      The information required by this Item 12 that relates to the ownership by
management and others of securities is incorporated by reference from the
information appearing under the caption "Security Ownership of Certain
Beneficial Owners and Management" in our definitive proxy statement which
involves the election of directors and is to be filed with the Securities and
Exchange Commission pursuant to the Securities Exchange Act of 1934 within 120
days of the end of our fiscal year on December 31, 2001.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

      The information required by this Item 13 that relates to business
relationships and transactions with management and other related parties is
incorporated by reference from the information appearing under the captions
"Certain Transactions" and "Executive Compensation -- Compensation Committee
Interlocks and Insider Participation" in our definitive proxy statement which
involves the election of directors and is to be filed with the Securities and
Exchange Commission pursuant to the Securities Exchange Act of 1934 within 120
days of the end of our fiscal year on December 31, 2001.


                                      -38-
<PAGE>

PART IV.

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

      (a) Documents Filed as a Part of this Report

1. FINANCIAL STATEMENTS:

<TABLE>
<CAPTION>
                                                                                                       PAGE
                                                                                                       ----
<S>                                                                                                    <C>
Index to Financial Statements.......................................................................   F-1
Report of Independent Public Accountants............................................................   F-2
Consolidated Balance Sheets as of December 31, 2001 and 2000........................................   F-3
Consolidated Statements of Operations for the Years Ended December 31, 2001, 2000 and 1999..........   F-4
Consolidated Statement of Stockholders' Equity for the Period from December 31, 2001 to
  December 31, 1999.................................................................................   F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999..........   F-6
Notes to Consolidated Financial Statements..........................................................   F-7
Supplemental Information on Natural Gas and Oil Exploration, Development and                           F-23
  Production Activities (Unaudited).................................................................
Quarterly Financial Information (Unaudited).........................................................   F-26
</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:

      See Index of Exhibits on page F-29 for a description of the exhibits filed
as a part of this report.


                                      -39-
<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 report to be signed on
its behalf by the undersigned, thereunto duly authorized.

                                    THE HOUSTON EXPLORATION COMPANY

                                    By:  /s/ William G. Hargett
                                       ----------------------------------
                                       William G. Hargett
Date: March 12, 2002                   President and Chief Executive Officer

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

<TABLE>
<CAPTION>
                 Signature                                     Title                                      Date
                 ---------                                     -----                                      ----
<S>                                         <C>                                                       <C>
/s/ William G. Hargett                      President, Chief Executive Officer and Director           March 12, 2002
---------------------------------------     (Principal Executive Officer)
    William G. Hargett

/s/ James F. Westmoreland                   Vice President, Chief Accounting Officer and              March 11, 2002
---------------------------------------     Secretary (Principal Financial Officer and
    James F. Westmoreland                   Principal Accounting Officer)

/s/ Robert B. Catell                        Chairman of the Board of Directors                        March 11, 2002
--------------------------------------
    Robert B. Catell

/s/ Gordon F. Ahalt                         Director                                                  March 13, 2002
--------------------------------------
    Gordon F. Ahalt

/s/ David G. Elkins                         Director                                                  March 11, 2002
--------------------------------------
    David G. Elkins

/s/ Russell D. Gordy                        Director                                                  March 13, 2002
--------------------------------------
    Russell D. Gordy

/s/ Gerald Luterman                         Director                                                  March 13, 2002
--------------------------------------
    Gerald Luterman

/s/ Craig G. Matthews                       Director                                                  March 13, 2002
--------------------------------------
    Craig G. Matthews

/s/ H. Neil Nichols                         Director                                                  March 13, 2002
--------------------------------------
    H. Neil Nichols

/s/ James Q. Riordan                        Director                                                  March 13, 2002
--------------------------------------
    James Q. Riordan

/s/ Donald C. Vaughn                        Director                                                  March 11, 2002
--------------------------------------
    Donald C. Vaughn
</TABLE>


                                      -40-
<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.


                                       G-1

<PAGE>

      Mcf. One thousand cubic feet.

      Mcf/d. One thousand cubic feet per day.

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

      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.

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


                                       G-2

<PAGE>

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

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

      Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible oil 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>
Report of Independent Public Accountants.................................................................    F-2
Consolidated Balance Sheets as of December 31, 2001 and 2000.............................................    F-3
Consolidated Statements of Operations for the Years Ended December 31, 2001, 2000 and 1999...............    F-4
Consolidated Statement of Stockholders' Equity for the Years Ended
  December 31, 2001, 2000 and 1999.......................................................................    F-5
Consolidated Statements of Cash Flows for the Years Ended  December 31, 2001, 2000 and 1999..............    F-6
Notes to Consolidated Financial Statements...............................................................    F-7
</TABLE>


                                      F-1
<PAGE>

                    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-2

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                           CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
                                                                                                       DECEMBER 31,
                                                                                            ---------------------------------
                                                                                                2001                 2000
                                                                                            ------------         ------------
                                                                                            (IN THOUSANDS, EXCEPT SHARE DATA)
<S>                                                                                         <C>                  <C>
ASSETS:
Cash and cash equivalents ..........................................................        $      8,619         $      9,675
Accounts receivable ................................................................              43,847              100,966
Accounts receivable -- Affiliate ...................................................                 635               13,635
Derivative financial instruments ...................................................              53,771                   --
Inventories ........................................................................               1,149                1,923
Prepayments and other ..............................................................               2,959                1,913
                                                                                            ------------         ------------
          Total current assets .....................................................             110,980              128,112
Natural gas and oil properties, full cost method
  Unevaluated properties ...........................................................             177,987              142,890
  Properties subject to amortization ...............................................           1,493,293            1,162,000
Other property and equipment .......................................................               8,265                9,852
                                                                                            ------------         ------------
                                                                                               1,679,545            1,314,742
Less: Accumulated depreciation, depletion and amortization .........................            (740,784)            (609,352)
                                                                                            ------------         ------------
                                                                                                 938,761              705,390
Other assets .......................................................................               9,351                3,882
                                                                                            ------------         ------------
          TOTAL ASSETS .............................................................        $  1,059,092         $    837,384
                                                                                            ============         ============
LIABILITIES:
Accounts payable and accrued expenses ..............................................        $     76,666         $    108,366
                                                                                            ------------         ------------
          Total current liabilities ................................................              76,666              108,366

Long-term debt and notes ...........................................................             244,000              245,000
Deferred federal income taxes ......................................................             172,169               87,040
Other deferred liabilities .........................................................                 376                  236
                                                                                            ------------         ------------
          TOTAL LIABILITIES ........................................................             493,211              440,642
COMMITMENTS AND CONTINGENCIES (SEE NOTE 10)
STOCKHOLDERS' EQUITY:
Common Stock, $.01 par value, 50,000,000 shares authorized and 30,463,230 shares
  issued and outstanding at December 31, 2001 and 29,829,050 shares issued and
  outstanding at December 31, 2000 .................................................                 305                  298
Additional paid-in capital .........................................................             336,977              325,205
Unearned compensation ..............................................................                (192)                  --
Retained earnings ..................................................................             193,840               71,239
Accumulated other comprehensive income .............................................              34,951                   --
                                                                                            ------------         ------------
          TOTAL STOCKHOLDERS' EQUITY ...............................................             565,881              396,742
                                                                                            ------------         ------------
          TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ...............................        $  1,059,092         $    837,384
                                                                                            ============         ============

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

</TABLE>

                                       F-3

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                      CONSOLIDATED STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
                                                                                   YEARS ENDED DECEMBER 31,
                                                                          ----------------------------------------
                                                                            2001            2000            1999
                                                                          --------        --------        --------
                                                                            (IN THOUSANDS, EXCEPT PER SHARE DATA)
<S>                                                                       <C>             <C>             <C>
REVENUES:
  Natural gas and oil revenues ...................................        $379,504        $270,595        $150,580
  Other ..........................................................           1,353           1,738           1,147
                                                                          --------        --------        --------
          Total revenues .........................................         380,857         272,333         151,727
OPERATING EXPENSES:
  Lease operating ................................................          25,291          23,553          18,406
  Severance tax ..................................................          11,035           9,757           5,444
  Depreciation, depletion and amortization .......................         128,736          89,239          74,051
  Writedown in carrying value of natural gas and oil properties ..           6,170              --              --
  General and administrative, net ................................          17,110           8,928           4,150
                                                                          --------        --------        --------
          Total operating expenses ...............................         188,342         131,477         102,051

Income from operations ...........................................         192,515         140,856          49,676

Strategic review expenses ........................................             119           1,752              --

Interest expense, net ............................................           2,992          11,361          13,307
                                                                          --------        --------        --------
Income before income taxes .......................................         189,404         127,743          36,369

Provision for federal income taxes ...............................          66,803          42,485          11,748
                                                                          --------        --------        --------
NET INCOME .......................................................        $122,601        $ 85,258        $ 24,621
                                                                          ========        ========        ========

Net income per share .............................................        $   4.06        $   3.06        $   1.03
                                                                          ========        ========        ========

Net income per share-- assuming dilution .........................        $   4.00        $   3.02        $   0.95
                                                                          ========        ========        ========

Weighted average shares outstanding ..............................          30,228          27,860          23,906
Weighted average shares outstanding -- assuming dilution .........          30,645          28,213          28,310

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

</TABLE>


                                       F-4

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
              CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND
                              COMPREHENSIVE INCOME

<TABLE>
<CAPTION>
                                                                                         ACCUMULATED
                                                   ADDITIONAL   RETAINED     UNEARNED       OTHER            TOTAL
                                        COMMON      PAID-IN-    EARNINGS     COMPEN-    COMPREHENSIVE     STOCKHOLDER
         STOCKHOLDERS' EQUITY            STOCK      CAPITAL    (DEFICIT)      SATION       INCOME           EQUITY
-----------------------------------    ---------   ---------   ---------    ---------     ---------        ---------
                                                                         (IN THOUSANDS)
<S>                                    <C>         <C>         <C>          <C>         <C>               <C>
Balance December 31, 1998 .........    $     239   $ 230,931   $ (38,640)   $      --     $      --        $ 192,530

Common stock(1) ...................           --         439          --           --            --              439
Net income ........................           --          --      24,621           --            --           24,621
                                       ---------   ---------   ---------    ---------     ---------        ---------

Balance at December 31, 1999 ......    $     239   $ 231,370   $ (14,019)   $      --     $      --        $ 217,590

Common stock(1)(2) ................           59      93,835          --           --            --           93,894
Net income ........................           --          --      85,258           --            --           85,258
                                       ---------   ---------   ---------    ---------     ---------        ---------

Balance December 31, 2000 .........    $     298   $ 325,205   $  71,239    $      --     $      --        $ 396,742

Common stock(1)(3) ................            7      10,438          --           --            --           10,445
Unamortized value of restricted
   stock ..........................           --          --          --         (192)           --             (192)
Tax benefit from non-qualified
   stock options ..................           --       1,334          --           --            --            1,334
Unrealized gains on derivative
   instruments, net of taxes ......           --          --          --           --        34,951           34,951
Net income ........................           --          --     122,601           --            --          122,601
                                       ---------   ---------   ---------    ---------     ---------        ---------
Balance December 31, 2001 .........    $     305   $ 336,977   $ 193,840    $    (192)    $  34,951        $ 565,881
                                       =========   =========   =========    =========     =========        =========
</TABLE>

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

(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.

(3)   Includes 10,000 shares of restricted stock issued to our President and
      Chief Executive Officer in April 2001 at $25.58 per share. See Note 6 --
      Related Party Transactions.

<Table>
<Caption>
                                           YEARS ENDED DECEMBER 31,
                                       --------------------------------
COMPREHENSIVE INCOME                     2001        2000        1999
--------------------                   --------    --------    --------
<S>                                    <C>         <C>         <C>
Net income.........................    $122,601    $85,258     $24,621

Other comprehensive income, net
  of tax

  Unrealized gain on derivative
    instruments, net of taxes(1)...      34,951         --          --
                                       --------    -------     -------
Comprehensive income...............    $157,552    $85,258     $24,621
                                       ========    =======     =======
--------------
(1) Unrealized gain on derivative instruments net of $18.8 million in tax
    expense.

</Table>

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


                                       F-5

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                      CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
                                                                                   (IN THOUSANDS)
                                                                                YEARS ENDED DECEMBER 31,
                                                                       ----------------------------------------
                                                                          2001           2000           1999
                                                                       ----------     ----------     ----------
<S>                                                                    <C>            <C>            <C>
OPERATING ACTIVITIES:

Net income ........................................................    $  122,601     $   85,258     $   24,621
Adjustments to reconcile net income to net cash provided by
  operating activities:
  Depreciation, depletion and amortization ........................       128,736         89,239         74,051
  Writedown in carrying value of natural gas and oil properties ...         6,170             --             --
  Deferred income tax expense .....................................        67,643         43,303         12,709
  Stock compensation expense ......................................            64             --             --
Changes in operating assets and liabilities:
  Decrease (increase) in accounts receivable ......................        70,119        (67,369)       (24,045)
  Decrease (increase) in inventories ..............................           774           (954)           (54)
  Increase in prepayments and other ...............................        (1,046)          (831)          (328)
  Increase in other assets and other deferred liabilities .........        (5,329)          (217)          (143)
  (Decrease) increase in accounts payable and accrued expenses ....       (31,700)        52,362         23,261
                                                                       ----------     ----------     ----------
Net cash provided by operating activities .........................       358,032        200,791        110,072

INVESTING ACTIVITIES:
Investment in property and equipment ..............................      (368,277)      (184,512)      (147,943)
Dispositions and other ............................................            --             --            289
                                                                       ----------     ----------     ----------
Net cash used in investing activities .............................      (368,277)      (184,512)      (147,654)

FINANCING ACTIVITIES:
Proceeds from long-term borrowings ................................       172,000         32,000         64,000
Repayments of long-term borrowings ................................      (173,000)       (68,000)       (16,000)
Proceeds from issuance of common stock ............................        10,189         13,894            439
                                                                       ----------     ----------     ----------
Net cash provided by (used in) financing activities ...............         9,189        (22,106)        48,439

(Decrease) increase in cash and cash equivalents ..................        (1,056)        (5,827)        10,857

Cash and cash equivalents, beginning of year ......................         9,675         15,502          4,645
                                                                       ----------     ----------     ----------

Cash and cash equivalents, end of year ............................    $    8,619     $    9,675     $   15,502
                                                                       ==========     ==========     ==========

Cash paid for interest ............................................    $   14,777     $   25,490     $   23,970
                                                                       ==========     ==========     ==========

Cash paid for federal income taxes ................................    $      475     $       --     $       --
                                                                       ==========     ==========     ==========
</TABLE>

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


                                      F-6

<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 currently focused offshore in the Gulf of
Mexico and onshore in South Texas, the Arkoma Basin of Oklahoma and Arkansas,
South Louisiana, the Appalachian Basin in West Virginia and East Texas. Our
strategy is to utilize our technical expertise to continue to increase reserves,
production and cash flows through the application of a three-pronged approach
that combines an effective mix of:

      - high potential offshore exploration and exploitation;
      - lower risk, high impact exploitation and development drilling onshore;
        and
      - selective opportunistic acquisitions both offshore and onshore

      At December 31, 2001, our net proved reserves were 608 Bcfe, with a
discounted present value of cash flows before income taxes of $714 million. Our
focus is natural gas. Approximately 93% of our net proved reserves at December
31, 2001 were natural gas of which approximately 74% of our net proved reserves
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. As of
December 31, 2001, THEC Holdings Corp., an indirect wholly owned subsidiary of
KeySpan, owned approximately 67% 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 intercompany balances and transactions have been eliminated.

      Reclassifications

      We have made some reclassifications of prior years to conform with current
year presentation.

      Use of Estimates

      The preparation of the consolidated financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the dates of
the financial statements and the reported amounts of revenues and expenses
during the reporting periods. 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.
Because there are numerous uncertainties inherent in the estimation process,
actual results could differ from the estimates.


                                       F-7

<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. 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 Statement of Financial Accounting Standards No.
128, our earnings per share are as follows:

<TABLE>
<CAPTION>
                                                                                  YEARS ENDED DECEMBER 31,
                                                                            ------------------------------------
                                                                              2001          2000          1999
                                                                            --------      --------      --------
                                                                            (IN THOUSANDS, EXCEPT PER SHARE DATA)
<S>                                                                         <C>           <C>           <C>
Net income ...........................................................      $122,601      $ 85,258      $ 24,621
  Interest savings on convertible debt ...............................            --            --         2,398
                                                                            --------      --------      --------
Net income, as adjusted ..............................................      $122,601      $ 85,258      $ 27,019
                                                                            ========      ========      ========

Weighted average shares outstanding ..................................        30,228        27,860        23,906
Add dilutive securities:
  Options ............................................................           417           353           206
  Convertible debt ...................................................            --            --         4,198
                                                                            --------      --------      --------
Total weighted average shares outstanding and dilutive securities ....        30,645        28,213        28,310
                                                                            ========      ========      ========

Net income per share .................................................      $   4.06      $   3.06      $   1.03
Net income per share -- assuming dilution ............................      $   4.00      $   3.02      $   0.95
</TABLE>

      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. Our amortization base includes estimates for future development
costs as well as future abandonment and dismantlement costs.

      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.


                                       F-8

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

      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
Statement of Financial Accounting Standards ("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 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, 2000 and 1999, we
estimated, using a wellhead price of $9.55 per Mcf and $2.01 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 $1.4 billion (after tax) for 2000 and
$99.2 million (after tax) for 1999. No writedown is required when a cushions
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.

      Other Property and Equipment

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

      Income Taxes

      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

      -     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

      -     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.


                                       F-9

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

      General and Administrative Costs and Expenses

      We receive reimbursement for administrative and overhead expenses incurred
on behalf of other working interest owners on properties we operate. These
reimbursements totaling $1.2 million, $3.6 million and $5.7 million for the
years ended December 31, 2001, 2000 and 1999, respectively, were allocated as
reductions to general and administrative expenses. Included in reimbursements
received during 2000 and 1999 are general and administrative reimbursements
received from KeySpan pursuant to the joint exploration agreement with KeySpan,
see Note 6 -- Related Party Transactions of $2.5 million and $4.8 million,
respectively. The capitalized general and administrative costs directly related
to our acquisition, exploration and development activities, during 2001, 2000
and 1999, aggregated $12.8 million, $9.6 million and $5.5 million, respectively.

      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, 2001, 2000 and 1999 we capitalized
interest costs of $12.0 million, $13.7 million and $11.9 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 liabilities of $376,000 and
$236,000, respectively, at December 31, 2001 and 2000.

      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. Pursuant to our adoption of SFAS 133 on
January 1, 2001, our derivative financial instruments are reported on the
balance sheet at fair market value.

      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 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


                                      F-10

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. At December 31, 2001, we estimated, using the New York Mercantile
Exchange, or NYMEX, index price strip as of that date, that the fair market
value of our derivative instruments was $53.8 million. As a result, our balance
sheet at December 31, 2001 reflects an asset of $53.8 million with a
corresponding credit of $34.9 million (net of related deferred taxes of $18.9
million) in accumulated other comprehensive income, representing the fair market
value of our deferred hedge gain. See Note 8 -- Hedging Contracts.

      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. We are exposed to credit risk in the event
of nonperformance by counterparties to futures and swaps contracts. We believe
that the credit risk related to the futures and swap contracts is no greater
than that associated with the primary contracts which we hedge, as these
contracts are with major investment grade financial institutions, and that
elimination of the price risk lowers our overall business risk.

      Stock Options

      We account 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 -- Stock Options -- Fair Value of Employee Stock-Based
Compensation for disclosure had stock options been accounted for based upon the
fair value provisions of the Financial Accounting Standards Board ("FASB")
SFAS No. 123, "Accounting for Stock-Based Compensation."

      New Accounting Pronouncements

      We adopted the FASB SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities" on January 1, 2001. The statement, as amended, requires
companies to report the fair market value of derivatives on the balance sheet
and record in income or in accumulated other comprehensive income, as
appropriate, any changes in the fair market value of the derivative. We utilize
cash flow hedges to reduce the risk of price volatility for our future natural
gas production. Our hedges qualify for hedge accounting under SFAS 133 because
they are highly effective as they are tied to the same indexes at which our
natural gas production is sold. As a result, when we mark-to-market our
derivative instruments at the end of each quarter, we are able to defer the gain
or loss on the change in fair value in Accumulated Other Comprehensive Income, a
component of shareholders' equity.

      The FASB has recently issued SFAS No. 141, "Business Combinations," SFAS
No. 142, "Goodwill and Other Intangible Assets," SFAS No. 143, "Accounting for
Asset Retirement Obligations" and SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets."

      SFAS No. 141, "Business Combinations," requires the use of the purchase
method of accounting for all business combinations initiated after June 30,
2001. SFAS No. 142, "Goodwill and Other Intangible Assets", addresses accounting
for the acquisition of intangible assets and accounting for goodwill and other
intangible assets after they have been initially recognized in the financial
statements. We do not currently have goodwill or other similar intangible


                                      F-11

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

assets; therefore, the adoption of the new standard on January 1, 2002, has not
had a material effect on our financial statements.

      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 will be effective for us January 1, 2003 and early adoption is encouraged.
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. Currently, we include 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 are evaluating
the impact the new standard will have on our financial statements.

      SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets," is effective for us January 1, 2002, and addresses accounting and
reporting for the impairment or disposal of long-lived assets. SFAS No. 144
supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of" and APB Opinion No. 30, "Reporting the
Results of Operations-Reporting the Effects of Disposal of a Segment of a
Business." SFAS No. 144 retains the fundamental provisions of SFAS No. 121 and
expands the reporting of discontinued operations to include all components of an
entity with operations that can be distinguished from the rest of the entity and
that will be eliminated from the ongoing operations of the entity in a disposal
transaction. We believe that the new standard will not have a material impact on
our financial statements.

NOTE 2 -- LONG-TERM DEBT AND NOTES

<TABLE>
<CAPTION>
                                                           AS OF DECEMBER 31,
                                                        ------------------------
                                                          2001            2000
                                                        --------        --------
                                                             (IN THOUSANDS)
<S>                                                     <C>             <C>
SENIOR DEBT:
Bank revolving credit facility .................        $144,000        $145,000

SUBORDINATED DEBT:
85/8% Senior Subordinated Notes due 2008 .......         100,000         100,000
                                                        --------        --------
    Total long-term debt and notes .............        $244,000        $245,000
                                                        ========        ========
</TABLE>

      The carrying amount of borrowings outstanding under the revolving bank
credit facility approximates fair market value as interest rates are tied to
current market rates. At December 31, 2001, the quoted market value of the 85/8%
senior subordinated notes was 102% of the $100 million carrying value or $102
million.

      Credit Facility

      We maintain a revolving bank credit facility with a syndicate of lenders
led by JPMorgan Chase, National Association. The credit facility, as amended,
provides a maximum commitment of $250 million, subject to borrowing base
limitations. At December 31, 2001, the borrowing base amount was $250 million.
Up to $2.0 million of the borrowing base is available for the issuance of
letters of credit to support performance guarantees. The credit facility matures
on March 1, 2003 and is unsecured. At December 31, 2001, $144 million was
outstanding under the credit


                                      F-12

<PAGE>

facility and $0.4 million was outstanding in letter of credit obligations.
Subsequent to year end December 31, 2001, we borrowed an additional $7.0
million, bringing outstanding borrowings and letter of credit obligations to
$151.4 million as of March 14, 2002.

Interest is payable on borrowings under the credit facility, at our option, at:

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

      -     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

      -     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 is 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 requires a commitment fee of:

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

      -     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.

The weighted average interest rate was 6.22%, 7.9% and 6.59%, respectively, for
the years ended December 31, 2001, 2000 and 1999.

The credit facility contains covenants, including restrictions on liens and
financial covenants which require us to, among other things, maintain:

      -     an interest coverage ratio of 2.5 to 1.0 of earnings before
            interest, taxes and depreciation to cash interest;
      -     a total debt to capitalization ratio of less than 60%, exclusive of
            non-cash charges; and
      -     sets a maximum limit of 70% on the amount of natural gas production
            we may hedge during any 12 month period.

In addition to maintenance of financial ratios, the credit facility restricts
cash dividends and/or purchase or redemption of our stock. The credit facility
also restricts the encumbering of our oil and gas assets or the pledging of
those assets as collateral. As of December 31, 2001, we were in compliance with
all covenants.

      Senior Subordinated Notes

      On March 2, 1998, we issued $100 million of 8 5/8% senior subordinated
notes due January 1, 2008. The notes bear interest at a rate of 8 5/8% 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 if the notes are redeemed prior to
January 1, 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:

      -     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;

      -     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;


                                      F-13

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 3 -- STOCKHOLDERS' EQUITY

      KeySpan Credit Facility and Conversion

      On November 30, 1998, we entered into a revolving credit facility with
KeySpan, which provided a maximum commitment of $150 million. We borrowed $80
million under the credit facility to finance a portion of the November 1998
acquisition of the Mustang Island A-31 Field. On March 31, 2000, the outstanding
borrowings of $80 million were converted into 5,085,177 shares of our common
stock at a conversion price of $15.732 per share. As a result of the conversion,
KeySpan's ownership interest in us increased from 64% at December 31, 1999 to
67% at December 31, 2001. 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 KeySpan 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 years
ended December 31, 2000 and 1999, we incurred $1.5 million and $5.5 million,
respectively, in interest and fees to KeySpan.

NOTE 4 -- STOCK OPTION PLANS

      1996 Stock Option Plan

      The 1996 Stock Option Plan was adopted at the completion of our initial
public offering in September 1996, and amended in 1997. The 1996 Plan limits the
number of options authorized for grant to 10% of the outstanding shares of our
common stock. The 1996 Plan allows us to grant both incentive stock options and
non-qualified options. 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 whose options vest immediately upon grant. As
of December 31, 2001, approximately 14,509 options were authorized and available
for grant under the 1996 Stock Option Plan. Since the plan's inception in 1996,
a total of 3,027,203 options have been granted of which 1,532,890 were
unexercised as of December 31, 2001. Of the options outstanding at December 31,
2001, 357,385 are incentive based options and the balance of 1,175,505 are
non-qualified stock options. Common stock issued through the exercise of
non-qualified options will result in a tax deduction for us, equivalent to the
taxable gain recognized by the optionee. Generally, we will not receive an
income tax deduction for incentive based options.

      1999 Stock Option Plan

      In October 1999, we adopted the 1999 Non-Qualified Stock Option Plan.
Under the 1999 Stock Option Plan, a total of 800,000 options have been
authorized of which 661,006 options have been granted and 631,058 are
outstanding as of December 31, 2001. At December 31, 2001, the 1999 Stock Option
Plan had 140,942 options available for grant. All options under the 1999 Stock
Option Plan are non-qualified, expire 10 years


                                      F-14
<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 vest on the date of grant.

      Phantom Stock Rights

      1996 Phantom Stock Grant. In December 1996, we granted our key employees
176,470 phantom stock rights that give the holder the right to receive a cash
payment determined by reference to the fair market value of one share of our
common stock. Twenty percent (20%) of the phantom stock rights were payable on
December 16th of each of the years 1997 through 2001. On each date on which a
phantom stock right is payable, the holder received a cash payment equal to the
average of the closing prices per share of our common stock for the five trading
days immediately preceding the payment date multiplied by the number of phantom
stock rights payable on the date. During 2001, 2000 and 1999, we made payments
of $1.0 million, $1.0 million and $0.6 million, respectively for the vested
portion of phantom stock rights. Payments made in December 2001 represented the
final payments pursuant to the 1996 grant.

      Incentive Compensation Plan for Non-Employee Directors. In October 1997,
we adopted an incentive compensation plan for non-employee, non-affiliated
directors under which they 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.

      The table below sets forth a summary of activity during the respective
years for both the 1996 and 1999 Stock Option Plans.

<TABLE>
<CAPTION>
                                                                       YEARS ENDED DECEMBER 31,
                                              -------------------------------------------------------------------------------
                                                      2001                       2000                       1999
                                              ----------------------- -------------------------  ----------------------------
                                               SHARES      PRICE(1)       SHARES      PRICE(1)      SHARES         PRICE(1)
<S>                                           <C>          <C>           <C>          <C>           <C>          <C>
Options outstanding January 1 ............    1,660,245    $  17.99      2,379,558    $  17.41      2,083,038    $      17.17
  Granted ................................    1,129,871       30.15        106,000       22.71        327,900           18.87
  Exercised ..............................     (624,180)      16.32       (820,853)      16.93        (28,080)          15.56
  Forfeited ..............................       (1,988)      29.02         (4,460)      18.83         (3,300)          18.56
                                              ---------                  ---------                  ---------
Options outstanding December 31 ..........    2,163,948    $  24.81      1,660,245    $  17.99      2,379,558    $      17.41
                                              =========                  =========                  =========

Options exercisable December 31 ..........      940,929    $  21.83        721,654    $  17.43      1,001,343    $      16.87

Options available for grant December 31 ..      155,451                    682,698                    286,638
</TABLE>

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

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


                                      F-15

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

      The table below sets forth a summary of options granted and outstanding,
their remaining contractual lives, a weighted average exercise price and number
vested and exercisable as of December 31, 2001.

<TABLE>
<CAPTION>
                               DECEMBER 31, 2001
----------------------------------------------------------------------------------
                                             WEIGHTED AVERAGE
   OPTIONS           REMAINING            EXERCISE PRICE OPTIONS       OPTIONS
 OUTSTANDING     CONTRACTUAL LIFE               OUTSTANDING          EXERCISABLE
----------------------------------------------------------------------------------
<S>              <C>                      <C>                        <C>
    168,269           5 years                     $15.54               168,269
    219,060           6 years                      20.03               166,640
    261,696           7 years                      19.06               167,676
    282,980           8 years                      18.85               185,720
    103,100           9 years                      22.65                41,100
  1,128,843          10 years                      30.15               211,524
----------------------------------------------------------------------------------

  2,163,948                                       $24.81               940,929
==================================================================================
</TABLE>

      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, 2001, 2000 and
1999.

<TABLE>
<CAPTION>
                                                                    YEARS ENDED DECEMBER 31,
                                                            ---------------------------------------
                                                              2001           2000           1999
                                                            --------       --------       --------
                                                            (IN THOUSANDS, EXCEPT PER SHARE DATA)
<S>                                                         <C>            <C>            <C>
Net income  - as reported ...........................       $122,601       $ 85,258       $ 24,621
Net income  - pro forma .............................        118,226         81,964         21,915

Net income per share - as reported ..................       $   4.06       $   3.06       $   1.03
Net income per share - assuming dilution--as reported           4.00           3.02           0.95

Net income per share - pro forma ....................       $   3.91       $   2.94       $   0.92
Net income per share - assuming dilution-- pro forma            3.86           2.91           0.77
</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 2001, 2000 and 1999, where the exercise price equaled
the market price on the grant date, were $13.45, $10.22 and $8.45, 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 2001, 2000 and 1999:

<TABLE>
<CAPTION>
                                                       YEARS ENDED DECEMBER 31,
                                                     ---------------------------
                                                     2001       2000       1999
                                                     ----       ----       ----
<S>                                                  <C>        <C>      <C>
Risk-free interest rate .......................      5.80%      5.91%    $ 5.96%
Expected years until exercise .................         5          5          5
Expected stock volatility .....................        41%        41%        41%
Expected dividends ............................        --         --         --
</TABLE>


                                      F-16

<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,
                                           ------------------------------------
                                             2001          2000          1999
                                           --------      --------      --------
                                                      (IN THOUSANDS)
<S>                                        <C>           <C>           <C>
Current ..............................     $   (840)     $   (818)     $   (961)
Deferred .............................       67,643        43,303        12,709
                                           --------      --------      --------
          Total ......................     $ 66,803      $ 42,485      $ 11,748
                                           ========      ========      ========
</TABLE>

      The credit in the current provision primarily represents Section 29 tax
credits (see Note 6--Related Party Transactions). As of December 31, 2001,
2000 and 1999, we had net operating loss carryforwards for federal income tax
purposes of approximately $29 million, $34 million and $43 million,
respectively, that may be used in future years to offset taxable income.

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

<TABLE>
<CAPTION>
                                                                  YEARS ENDED DECEMBER 31,
                                                           ------------------------------------
                                                             2001          2000          1999
                                                           --------     ---------      --------
                                                                      (IN THOUSANDS)
<S>                                                        <C>          <C>            <C>
Income before income taxes ............................    $189,404     $ 127,743      $ 36,369
Statutory rate ........................................          35%           35%           35%
Income tax expense computed at statutory rate .........      66,291        44,710        12,729
Reconciling items:
     Section 29 tax credits and other tax credits(1) ..         512        (2,225)         (981)
                                                           --------     ---------      --------
Tax expense ...........................................    $ 66,803     $  42,485      $ 11,748
                                                           ========     =========      ========
</TABLE>

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

(1)   Year ended 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, 2001 and 2000 primarily represent temporary
differences related to depreciation of natural gas and oil properties.

NOTE 6 -- RELATED PARTY TRANSACTIONS

TRANSACTIONS WITH KEYSPAN

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


                                      F-17

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

      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. We retained Goldman, Sachs and Co. as financial
advisor. 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.

      KeySpan Joint Venture

      Effective January 1, 1999, together with KeySpan, 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 KeySpan
received 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 and
KeySpan paid 51.75% of all additional intangible drilling costs incurred and we
paid 48.25%. Revenues are shared 55% 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 will
not participate in any of our offshore exploration prospects unless the project
involves 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 will not receive any
reimbursement from KeySpan for general and administrative costs.

      Since the beginning of our joint venture with KeySpan in January 1999,
KeySpan has spent a total of $99.3 on exploration and development, with $ 17.2
million spent during 2001, $46.5 million spent during 2000 and $35.6 million
spent during 1999.  During the initial two-year exploratory term of the joint
venture, we received from KeySpan a total of $7.3 million in general and
administrative expense reimbursements, with $2.5 million paid during 2000 and
$4.8 million paid during 1999.  Reimbursement for general and administrative
expenses terminated in 2000 with the expiration of the exploratory term of the
joint venture.

      During the initial two-year term of the joint drilling program beginning
January 1, 1999 and ending December 31, 2000, we drilled a total of 21 wells
under the terms of the joint venture:  17 exploratory wells and four development
wells.  Five of the wells drilled were unsuccessful.  During 2001, KeySpan
participated in three additional wells, all of which were successful and further
developed or delineated reservoirs discovered during the initial term of the
joint venture.  For 2002, KeySpan has committed to a capital budget of $15
million for development projects associated with its working interests in wells
drilled under the joint venture during 1999, 2000 and 2001.

      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:

      -     retained a volumetric production payment and a net profits interest
            of 100% in the properties,
      -     received a cash down payment of $1.4 million and
      -     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


                                      F-18

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

$0.8 million, $0.9 million and 1.0 million, respectively, for each of the years
ended December 31, 2001, 2000, and 1999.

TRANSACTIONS WITH OUR EXECUTIVES

      Restricted Stock Grant to New 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. The stock is restricted from
transfer and subject to forfeiture in the event Mr. Hargett's employment is
terminated prior to April 4, 2004 and will otherwise vest, be 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 2001, we
recognized stock compensation expense of $64,000 related to this restricted
stock grant.

      Employment Contracts

      We have entered into employment contracts with all seven 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-19

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

      Transactions with Former President and Chief Executive Officer

      Prior to our initial public offering in September 1996, we were party to
an employment agreement with our former President and Chief Executive Officer,
Mr. Floyd. Under this employment agreement, we had:

      -     granted Mr. Floyd an option to obtain up to a 5% working interest in
            specified exploration prospects, exercisable at the time of
            acquisition of the prospect or prior to the commencement of drilling
            of the initial well on any of the prospects;
      -     assigned to Mr. Floyd a 2% net profits interest in all exploration
            prospects at the time the properties were acquired;
      -     assigned to key employees designated by Mr. Floyd overriding royalty
            interests equivalent to a 4% net revenue interest in specified
            properties at the time we acquired the properties; and
      -     assigned to Mr. Floyd a 6.75% after program-payout working interest
            in the leases upon which we began drilling an exploratory well
            (whether or not successful) during a calendar year.

      Mr. Floyd and his affiliates opted to acquire a 5% working interest in the
Charco Field properties we acquired in July 1996 and the right to participate
with a 5% working interest in any future wells we drilled in the Charco Field.
We loaned to Mr. Floyd the $3.1 million purchase price for the purchase of a 5%
working interest in the Charco Field properties. In addition, we agreed to loan
to Mr. Floyd, on a revolving basis, the amounts required to fund the expenses
attributable to his working interest. Mr. Floyd was required to repay amounts
owed under the loan in the amount of 65% of all distributions received in
respect to the working interest, as distributions are received. Amounts
outstanding under the loan accrued interest at an interest rate equal to our
cost of borrowing under our credit facility. Obligations under the agreement
were secured by a pledge of Mr. Floyd's working interest in, and the production
from, the properties. As of December 31, 2000, the outstanding balance owed by
Mr. Floyd under the loan was $0.6 million. Mr. Floyd repaid the loan in full as
of February 28, 2001.

      No assignments were made to Mr. Floyd or to key employees subsequent to
1995 and upon completion of our initial public offering in September 1996, Mr.
Floyd's employment agreement was replaced with a new employment agreement which
did not provide Mr. Floyd with the option to participate in our prospects as a
working interest owner or to receive or grant assignments or after
program-payout working interests; however, due to the nature of an overriding
royalty interest, Mr. Floyd and any employees receiving assignments will
continue to receive payments pursuant to their overriding interest until
production from the related property ends.

      In January 2000, we agreed to exchange all of the working interests and
net profits interests Mr. Floyd had acquired in our properties pursuant to the
initial employment agreement for an overriding royalty interest in those same
properties. The exchange, was effective October 1, 1999, and was structured such
that the net present value we would earn and that Mr. Floyd would earn would be
approximately the same regardless of the nature of Mr. Floyd's participation in
the earnings from the properties. As of October 1, 1999, the net present value,
discounted at 10%, of the properties exchanged was approximately $13.5 million.

      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. During 1999, Mr. Floyd and his
affiliates received $4.7 million in revenues attributable to his previously held
working interests and net profits interests in our properties and paid $2.5
million in costs and expenses attributable to those properties.

NOTE 7 -- EMPLOYEE BENEFIT PLANS

      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


                                      F-20

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, $0.6 million and $0.3 million, respectively, for the years ended
December 31, 2001, 2000 and 1999.

      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 is 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
$113,000, $123,000 and $123,000, respectively, during the years ended December
31, 2001, 2000 and 1999 related to this retirement plan.


                                      F-21

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8 -- HEDGING CONTRACTS

      Natural Gas Price Swaps, Options and Collars

      As of 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.

<TABLE>
<CAPTION>
                              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>

      At December 31, 2001, the fair market value of our derivative instruments
was an asset of $53.8 million. Fair market value is calculated for the
respective months using prices derived from NYMEX futures contract prices
existing at December 31, 2001 and from market quotes received from
counterparties.

      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 (excluding
the no-cost collars with floating floors discussed above), 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


                                      F-22

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

      As of December 31, 2000, we had entered into commodity price hedging
contracts with respect to our production for 2001 as follows:

<TABLE>
<CAPTION>
                              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 2001                 --       $       --            4,960       $     3.63       $ 5.30      $  (23,208)
February 2001                --               --            4,480             3.63         5.30         (20,052)
March 2001                   --               --            4,960             3.63         5.30         (17,524)
April 2001                   --               --            4,800             4.00         6.11          (2,981)
May 2001                     --               --            4,960             4.00         6.11          (1,303)
June 2001                    --               --            4,800             4.00         6.11          (1,221)
July 2001                    --               --            4,960             4.00         6.11          (1,341)
August 2001                  --               --            4,960             4.00         6.11          (1,386)
September 2001               --               --            4,800             4.00         6.11          (1,350)
October 2001                 --               --            4,960             4.00         6.11          (1,491)
November 2001                --               --            4,800             4.00         6.37          (1,419)
December 2001                --               --            4,960             4.00         6.37          (1,793)
                                                                                                     ----------
                                                                                                     $  (75,069)
                                                                                                     ==========
</TABLE>

      At December 31, 2000, the fair market value of our derivative instruments
was a liability of $75 million. Fair market value is calculated for the
respective months using prices derived from NYMEX futures contract prices
existing at December 31, 2000 and from market quotes received from
counterparties.


                                      F-23

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 9 -- 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, 2001, 2000 and
1999 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                                2001          2000          1999
-------------------------------------------------------------------------------
<S>                                            <C>           <C>           <C>
Dynegy Inc.                                    16.4%         22.5%         18.0%
Adams Resources and Energy, Inc                12.5%         14.9%         22.5%
El Paso Corporation(1)                          9.5%          9.1%          7.7%
</TABLE>

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

(1)   Amount purchased was less than 10% of our natural gas and oil sales
      revenues, and is included for information purposes only.

NOTE 10 -- COMMITMENTS AND CONTINGENCIES

      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.

      Leases

      We have entered into noncancellable 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>
2002 ..................................................................   $     942
2003 ..................................................................       1,044
2004 ..................................................................       1,094
2005 ..................................................................       1,139
2006 ..................................................................       1,113
Thereafter ............................................................       3,326
</TABLE>

      Net rental expense related to these leases was $0.6 million, $0.5 million
and $0.5 million, respectively, for the years ended December 31, 2001, 2000 and
1999.

NOTE 11 -- ACQUISITIONS

      Conoco Acquisition.


                                      F-24

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

      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 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%. With this
acquisition, we have expanded and will improve our operations in South Texas
which has been an area of strategic growth for us over the last five years.
During February 2002, the properties we acquired produced approximately
19.0 MMcfe per day, net to our interests.

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, 2001, 2000 and 1999, our capitalized costs of natural
gas and oil properties are as follows:

<TABLE>
<CAPTION>
                                                         AS OF DECEMBER 31,
                                             -----------------------------------------
                                                 2001           2000           1999
                                             -----------------------------------------
                                                           (IN THOUSANDS)
<S>                                          <C>            <C>            <C>
Unevaluated properties, not amortized ....   $   177,987    $   142,890    $   164,377
Properties subject to amortization .......     1,493,293      1,162,000        956,484
                                             -----------    -----------    -----------
Capitalized costs ........................     1,671,280      1,304,890      1,120,861
Accumulated depreciation, depletion and
   amortization ..........................      (735,257)      (601,034)      (512,465)
                                             -----------    -----------    -----------
          Net capitalized costs ..........   $   936,023    $   703,856    $   608,396
                                             ===========    ===========    ===========
</TABLE>

      Unevaluated Cost Additions. The following is a summary of the costs (in
thousands) which are excluded from the amortization calculation as of December
31, 2001, by year of acquisition. We are not able to accurately predict when
these costs will be included in the amortization base; however, we believe that
unevaluated properties at December 31, 2001 will be fully evaluated within five
years.

<TABLE>
<CAPTION>
                                                                       UNEVALUATED
YEAR INCURRED                                                              COSTS
----------------------------------------------------------------------------------
<S>                                                                    <C>
2001 ...............................................................    $ 72,522
2000 ...............................................................      20,325
1999 ...............................................................      16,957
Prior ..............................................................      68,183
                                                                        --------
                                                                        $177,987
                                                                        ========
</TABLE>


                                      F-25

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

      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, 2001, 2000 and 1999 include interest expense
and general and administrative costs related to acquisition, exploration and
development of natural gas and oil properties, of $24.9 million, $23.3 million
and $17.4 million, respectively.

<TABLE>
<CAPTION>
                                             AS OF DECEMBER 31,
                                      ------------------------------
                                        2001       2000       1999
                                      ------------------------------
                                              (IN THOUSANDS)
<S>                                   <C>        <C>        <C>
Property acquisition:
  Unevaluated(1) ..................   $ 31,711   $  7,955   $ 10,337
  Proved ..........................     85,367     38,579     37,105
Exploration costs .................     72,056     37,162     12,257
Development costs .................    177,256    100,333     87,965
                                      --------   --------   --------
          Total costs incurred ....   $366,390   $184,029   $147,664
                                      ========   ========   ========
</TABLE>

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

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

      The following summarizes the policies 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 principally prepared by independent petroleum
consultants. Proved reserves are estimated quantities of natural gas and crude
oil which geological and engineering data demonstrate with reasonable certainty
to be recoverable in future years from known reservoirs under existing economic
and operating conditions.

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

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

      2.    The estimated future cash flows are compiled by applying year-end
            prices of natural gas and oil relating to 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.


                                      F-26

<PAGE>

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

      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.

      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,
                                                            --------------------------------------------
                                                                2001            2000            1999
                                                            --------------------------------------------
                                                                           (IN THOUSANDS)
<S>                                                         <C>             <C>             <C>
Future cash inflows .....................................   $  1,471,557    $  5,189,328    $  1,113,844
Future production costs .................................       (302,145)       (542,139)       (190,900)
Future development costs ................................       (189,480)       (153,210)       (120,071)
Future income taxes .....................................       (211,191)     (1,250,272)       (155,641)
                                                            ------------    ------------    ------------
Future net cash flows ...................................        768,741       3,243,707         647,232
10% annual discount for estimated timing of cash flows
cash flows...............................................       (217,216)     (1,179,680)       (178,007)
                                                            ------------    ------------    ------------
Standardized measure of discounted future net
  cash flows ............................................   $    551,525    $  2,064,027    $    469,225
                                                            ============    ============    ============
</TABLE>

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

<TABLE>
<CAPTION>
                                                                        AS OF DECEMBER 31,
                                                            --------------------------------------------
                                                                2001            2000            1999
                                                            --------------------------------------------
                                                                           (IN THOUSANDS)
<S>                                                         <C>             <C>             <C>
Beginning of the year ...................................   $  2,064,027    $    469,225    $    396,060
Revisions to previous estimates:
  Changes in prices and costs ...........................     (2,088,576)      2,163,984          47,330
  Changes in quantities .................................        (52,928)         24,650          51,375
  Changes in future development costs ...................        (18,001)        (32,152)        (25,730)
Development costs incurred during the period ............         65,940          57,046          40,563
Extensions and discoveries, net of related costs ........        116,710         403,012          91,383
Sales of natural gas and oil, net of production costs ...       (343,181)       (237,286)       (126,730)
Accretion of discount ...................................        279,648          52,967          41,293
Net change in income taxes ..............................        635,400        (672,005)        (43,572)
Purchase of reserves in place ...........................         51,674          23,118          20,973
Sale of reserves in place ...............................           (133)             --          (2,194)
Production timing and other .............................       (159,055)       (188,532)        (21,526)
                                                            ------------    ------------    ------------
End of year .............................................   $    551,525    $  2,064,027    $    469,225
                                                            ============    ============    ============
</TABLE>


                                      F-27

<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, 2001, 2000 and 1999.

<TABLE>
<CAPTION>
                                                NATURAL GAS               CRUDE OIL AND CONDENSATE
                                                   (MMCF)                         (MBBLS)
                                      --------------------------------  ----------------------------
                                        2001        2000        1999      2001      2000      1999
                                      --------    --------    --------  --------    ------    ------
<S>                                   <C>         <C>         <C>       <C>         <C>       <C>
Proved developed and
  undeveloped  reserves: ..........    529,518     526,185     470,447     5,352     2,470     1,650
Revisions of previous estimates ...    (41,914)      3,709      45,510      (174)      107       237
Extensions and discoveries ........     83,551      69,564      62,700     1,800     2,424       909
Production ........................    (87,095)    (77,861)    (69,679)     (459)     (311)     (258)
Purchase of reserves in place .....     84,148       7,921      20,699       115       662         1
Sales of reserves in place ........         --          --      (3,492)      (29)       --       (69)
                                      --------    --------    --------  --------    ------    ------
End of year .......................    568,208     529,518     526,185     6,605     5,352     2,470
                                      ========    ========    ========  ========    ======    ======
Proved developed reserves:
Beginning of year .................    420,733     397,343     369,931     1,810     1,796     1,498
End of year .......................    438,538     420,733     397,343     2,123     1,810     1,796
</TABLE>


NOTE 13-- QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

      Selected unaudited quarterly data is shown below:

<TABLE>
<CAPTION>
                                                 1ST QUARTER   2ND QUARTER   3RD QUARTER   4TH QUARTER
                                                 -----------   -----------   -----------   -----------
                                                         (IN THOUSANDS, EXCEPT PER SHARE DATA)
<S>                                              <C>           <C>           <C>           <C>
2001
Total revenues ..............................    $   124,342   $    99,308   $    78,495   $    78,712
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(1) .....................    $      1.58   $      1.19   $      0.74   $      0.55
Net income per share--assuming dilution(1) ..    $      1.55   $      1.17   $      0.73   $      0.55

2000
Total revenues ..............................    $    49,348   $    57,930   $    62,903   $   102,152
Income from operations ......................         18,419        27,301        32,479        62,657
Net income ..................................          8,449        16,328        19,666        40,815

Net income per share(1) .....................    $      0.35   $      0.56   $      0.67   $      1.40
Net income per share--assuming dilution(1) ..    $      0.35   $      0.56   $      0.66   $      1.38
</TABLE>

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

(1)   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 or the issuance of common stock (see Note 3--Stockholders'
      Equity), the sum of quarterly earnings per share do not equal earnings per
      share for the year.


                                      F-28

<PAGE>

                               INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBITS                                   DESCRIPTION
--------          --------------------------------------------------------------
<S>         <C>   <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(2)     --    Employment Agreement dated July 2, 1996 between The Houston
                  Exploration Company and James G. Floyd (filed as Exhibit 10.8
                  to our Registration Statement on Form S-1 (Registration No.
                  333-4437) and incorporated by reference).
10.2(2)     --    Employment Agreement dated July 2, 1996 between The Houston
                  Exploration Company and Randall J. Fleming (filed as Exhibit
                  10.9 to our Registration Statement on Form S-1 (Registration
                  No. 333-4437) and incorporated by reference).
10.3(2)     --    Employment Agreement dated July 2, 1996 between The Houston
                  Exploration Company and Thomas W. Powers (filed as Exhibit
                  10.10 to our Registration Statement on Form S-1 (Registration
                  No. 333-4437) and incorporated by reference).
10.4(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).
10.5        --    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).
10.6        --    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).
10.7(2)     --    Registration Rights Agreement dated as of September 25, 1996
                  between The Houston Exploration Company and James G. Floyd
                  (filed as Exhibit 10.22 to our Registration Statement on Form
                  S-1 (Registration No. 333-4437) and incorporated by
                  reference).
10.8(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).
10.9(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).
10.10(2)    --    Form of Letter Agreement from The Houston Exploration Company
                  to each of James G. Floyd, Randall J. Fleming, Thomas W.
                  Powers, Charles W. Adcock, James F. Westmoreland and Sammye L.
                  Dees evidencing grants of Phantom Stock Rights effective as of
                  December 16, 1996 (filed as Exhibit 10.27 to our Annual Report
                  on Form 10-K for the year ended December 31, 1996 (File No.
                  001-11899) and incorporated by reference).
10.11(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).
10.12       --    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).
10.13(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).
10.14       --    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).
</TABLE>


                                      F-29

<PAGE>

                                INDEX TO EXHIBITS

<TABLE>
<CAPTION>
EXHIBITS                                   DESCRIPTION
--------          --------------------------------------------------------------
<S>         <C>   <C>
10.15       --    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).
10.16       --    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).
10.17       --    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).
10.18       --    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).
10.19       --    Amended and Restated Credit Agreement among The Houston
                  Exploration Company and Chase Bank of Texas, National
                  Association, as agent, dated March 30,1999, (filed as Exhibit
                  10.2 to our Quarterly Report on Form 10-Q for the quarter
                  ended March 31, 1999 (File No. 001-11899) and incorporated by
                  reference).
10.20       --    First Amendment and Supplement to Amended and Restated Credit
                  Agreement dated May 4, 1999 by and among The Houston
                  Exploration Company and Chase Bank of Texas, National
                  Association, as agent, (filed as Exhibit 10.1 to our Quarterly
                  Report on Form 10-Q for the quarter ended June 30, 1999 (File
                  No. 001-11899) and incorporated by reference).
10.21       --    Second Amendment to Amended and Restated Credit Agreement
                  between The Houston Exploration Company and Chase Bank of
                  Texas, National Association, as agent, dated October 6, 1999,
                  (filed as Exhibit 10.32 to our Quarterly Report on Form 10-Q
                  for the quarter ended September 30, 1999 (File No. 001-11899)
                  and incorporated by reference).
10.22       --    Third Amendment and Supplement to Amended and Restated Credit
                  Agreement between The Houston Exploration Company and Chase
                  Bank of Texas, National Association, as agent, dated December
                  9, 1999 (filed as Exhibit 10.23 to our Annual Report on Form
                  10-K for the year ended December 31, 1999 File No. 001-11899)
                  and incorporated by reference).
10.23(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).
10.24(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).
10.25(2)    --    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).
10.26(2)    --    First Amendment to Employment Agreement dated March 8, 2001
                  between The Houston Exploration Company and Thomas W. Powers
                  (filed as Exhibit 10.1 to our Quarterly Report on Form 10-Q
                  for the quarter ended March 31, 2001 File No. 001-11899).
10.27(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).
10.28(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).
10.29(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).
</TABLE>


                                      F-30

<PAGE>

                                INDEX TO EXHIBITS

<TABLE>
<CAPTION>
EXHIBITS                                     DESCRIPTION
--------            --------------------------------------------------------------
<S>           <C>   <C>
10.30(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).
10.31(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).
10.32(1)(2)   --    Employment Agreement dated October 22, 2001 between The
                    Houston Exploration Company and Steven L. Mueller.
10.33(1)(2)   --    Employment Agreement dated March 1, 2002 between The Houston
                    Exploration Company and Roger B. Rice.
12.1(1)       --    Computation of ratio of earnings to fixed charges.
21.1(1)       --    Subsidiaries of Houston Exploration.
23.1(1)       --    Consent of Arthur Andersen LLP.
23.2(1)       --    Consent of Netherland, Sewell & Associates.
23.3(1)       --    Consent of Miller and Lents.
</TABLE>
---------------------------

(1)   Filed herewith.

(2)   Management contract or compensation plan.


                                      F-31