<PAGE>   1

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

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

                                   ----------

                                    FORM 10-K
               [X]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                       THE SECURITIES EXCHANGE ACT OF 1934
                   FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000
                                       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                             77002-5215
               HOUSTON, TEXAS                                  (ZIP CODE)
  (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)

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

                                   ----------

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

<TABLE>
<CAPTION>

                                                             NAME OF EACH
       TITLE OF EACH CLASS                          EXCHANGE ON WHICH REGISTERED
       -------------------                          ----------------------------
<S>                                                 <C>
Common Stock, $.01 par value                           New York Stock Exchange
8 5/8% Senior Subordinated Notes due 2008              New York Stock Exchange
</TABLE>

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

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

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

     The aggregate market value of the voting stock held by non-affiliates of
the registrant was approximately $316,519,974 of February 21, 2001, based on the
closing sales price of the registrant's common stock on the New York Stock
Exchange on such date of $32.95 per share. For purposes of the preceding
sentence only, all directors, executive officers and beneficial owners of ten
percent or more of the common stock are assumed to be affiliates. As of February
21, 2001, 29,986,461 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 2001 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, 2000, are
incorporated by reference into Part III of this Form 10-K.

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

<PAGE>   2


         This Annual Report on Form 10-K contains "forward-looking statements"
within the meaning of Section 27A of the Securities Act of 1993 and Section 21E
of the Securities Exchange Act of 1934. The words "anticipate," "believe,"
"expect," "estimate," "project" and similar expressions identify forward-looking
statements. Without limiting the foregoing, all statements under the caption
"Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations" relating to the Company's anticipated capital expenditures,
future cash flows and borrowings, pursuit of potential future acquisition
opportunities and sources of funding for exploration and development are
forward-looking statements. Such statements are subject to risks and
uncertainties, such as the volatility of natural gas and oil prices, uncertainty
of reserve information and future net revenue estimates, reserve replacement
risks, drilling risks, operating risks of natural gas and oil operations,
acquisition risks, substantial capital requirements, government regulation,
environmental matters and competition. If one or more of these risks or
uncertainties materialize, or if underlying assumptions prove incorrect, actual
results may vary materially from those described in this Form 10-K. 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 on Form 10-K.

         Unless otherwise indicated, references to "Houston Exploration" or the
"Company" refer to The Houston Exploration Company and its subsidiaries on a
consolidated basis. Certain terms used herein relating to the oil and gas
industry are defined in "Glossary of Oil and Gas Terms" included on pages G-1
through G-3 of this Annual Report on Form 10-K.

PART I.

ITEMS 1 AND 2.  BUSINESS AND PROPERTIES

OVERVIEW

         The Houston Exploration Company is an independent natural gas and oil
company engaged in the exploration, development, exploitation and acquisition of
domestic natural gas and oil properties. The Company's offshore properties are
located primarily in the shallow waters of the Gulf of Mexico, and its onshore
properties are located in South Texas, South Louisiana, the Arkoma Basin, East
Texas and the Appalachian Basin in West Virginia. The Company has utilized its
geological and geophysical expertise to grow its reserve base through a
combination of (i) high potential exploratory drilling in the Gulf of Mexico;
(ii) lower risk, high impact exploitation and development drilling onshore; and
(iii) selective opportunistic acquisitions both offshore and onshore. The
Company believes that the lower risk projects and more stable production
associated with its onshore properties complement its high potential exploratory
prospects in the Gulf of Mexico by balancing risk and reducing volatility.

         The Company believes that its primary strengths are its high quality
reserve base, its substantial inventory of high potential offshore exploration
prospects, its onshore portfolio of high impact exploitation and development
opportunities, its expertise in generating new prospects, the geographic focus
of its operating areas and its low-cost operating structure. At December 31,
2000, net proved reserves were 562 Bcfe with a discounted present value of cash
flows before income taxes ("PV-10%") of $2.8 billion. The Company's focus is
natural gas and approximately 94% of its net proved reserves at December 31,
2000 were natural gas and approximately 77% were classified as proved developed.
The Company operates approximately 85% of its production.

         Houston Exploration began exploring for natural gas and oil in December
1985 on behalf of The Brooklyn Union Gas Company ("Brooklyn Union") and in
September 1996 the Company completed an initial public offering of its common
stock. Brooklyn Union became an indirect wholly-owned subsidiary of KeySpan
Corporation ("KeySpan") in May 1998 through the combination of Brooklyn Union's
parent company KeySpan Energy Corporation and Long Island Lighting Company. As
of December 31, 2000, THEC Holdings Corp., an indirect wholly owned subsidiary
of KeySpan, owned approximately 68% of the outstanding shares of Houston
Exploration's common stock. KeySpan, a member of the Standard & Poor's 500
Index, is a diversified energy


                                      -1-
<PAGE>   3


provider that (i) distributes natural gas to 2.4 million customers in the
Brooklyn, Long Island, Queens and Staten Island areas of New York and to
customers in eastern and central Massachusetts and central New Hampshire; (ii)
generates and manages electricity transmission and distribution through the
ownership and operation of generating plants throughout New York State and
through its contract with the Long Island Power Authority to manage electricity
service to 1.1 million customers in the Long Island area; and (iii) through its
other subsidiaries is involved in various energy services and energy related
investments including wholesale and retail gas and electric marketing; appliance
service and installation; large energy-system installation and management; fiber
optic telecommunications and energy-related internet activities.

         The Company's principal executive offices are located at 1100
Louisiana, Suite 2000, Houston, Texas 77002 and its telephone number is (713)
830-6800.

BUSINESS STRATEGY

         The Company's strategy is to continue to increase its reserves,
production and cash flow through the application of a three-pronged approach
that combines (i) high potential offshore exploration; (ii) lower risk, high
impact exploitation and development drilling onshore; and (iii) selective
opportunistic acquisitions. From January 1, 1995 through December 31, 2000, the
Company increased its proved reserve base at a compound annual growth rate of
29% and increased its annual production at a compound annual growth rate of 20%.
During the past five years, the Company produced a total of 297 Bcfe and added
664 Bcfe of net proved reserves of which 338 Bcfe were added through exploration
and development and 326 Bcfe were added through acquisitions. In total, the
Company replaced 224% of production through drilling and acquisitions, with 114%
replaced through the drillbit alone. During the fourth quarter of 2000, daily
production averaged 237 MMcfe per day.

         The Company focuses on the following elements in implementing this
strategy:

High Potential Exploratory and Development Drilling in the Gulf of Mexico

         The Company holds interests in 106 lease blocks, representing 532,296
gross (417,294 net) acres, in federal and state waters in the Gulf of Mexico, of
which 70 blocks are undeveloped. The Company believes it has assembled a
four-year inventory of offshore prospects. Of its undeveloped leases, 15 have
been evaluated, permitted and are ready to drill. The Company plans to drill
approximately eight exploratory wells in the Gulf of Mexico in 2001. The
successful completion of any one of these wells could substantially increase the
Company's reserves. Over the past five years, the Company has drilled 28
successful exploratory wells and 17 successful development wells in the Gulf of
Mexico, representing a historical success rate of 69%. The Company anticipates
that approximately $150 million of its $225 million 2001 capital expenditure
budget (excluding acquisitions) will be spent on offshore projects. In addition,
the Company intends to continue its participation in federal lease sales and to
actively pursue attractive farm-in opportunities as they become available. The
Company's 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 41% of the Company's net proved reserves as of
December 31, 2000. During the fourth quarter of 2000, average net production
from the Company's Gulf of Mexico properties was approximately 112 MMcfe per
day.

Lower Risk, High Impact Exploitation and Development Drilling Onshore

         The Company owns significant onshore natural gas and oil properties in
the Lobo trend in South Texas, the South Lake Arthur and Lake Pagie Fields in
South Louisiana, the Arkoma Basin of Oklahoma and Arkansas, East Texas and the
Appalachian Basin in West Virginia. These properties favor exploitation and
development drilling and generate the cash flow for offshore exploration and
growth. Onshore properties account for 59% of net proved reserves at December
31, 2000. Complementing the offshore properties, the Company's onshore
properties are typically characterized by relatively longer reserve lives, more
predictable production streams and lower operating


                                      -2-
<PAGE>   4


cost structures. Over the past five years, the Company has drilled or
participated in the drilling of 140 successful development wells and seven
successful exploratory wells onshore, together representing a historical
drilling success rate of 84%. The Company has identified an extensive inventory
of more than 200 potential onshore drilling locations, of which approximately 90
are located in the Charco Field in South Texas. The Company anticipates that
approximately $75 million of its $225 million 2001 capital expenditure budget
(excluding acquisitions) will be spent on onshore projects, including the
drilling of approximately four exploratory wells and 40 development wells.
During the fourth quarter of 2000, average net production from the Company's
onshore properties was approximately 125 MMcfe per day.

Opportunistic Acquisitions

         The Company's primary strategy to grow its reserves through the
drillbit is supplemented by the Company's continuing pursuit of opportunistic
acquisitions of properties with unexploited reserve potential. The Company
targets properties (i) that it can operate; (ii) that are either in the Gulf of
Mexico or onshore in existing core operating areas or in new geographic areas in
which the Company believes it can establish a substantial concentration of
properties and operations; and (iii) that provide a base for further exploration
and development. The Company has a successful track record of building its
reserves through opportunistic acquisitions onshore and in the Gulf of Mexico
and successfully exploiting the reserves acquired.

Use of Advanced Technology for In-House Prospect Generation

         The Company generates virtually all of its exploration prospects
utilizing in-house geological and geophysical expertise. The Company uses
advanced technology, including 3-D seismic and in-house computer-aided
exploration technology, to reduce risks, lower costs and prioritize drilling
prospects. The Company has assembled a library of 3-D seismic data, covering
approximately 98% of its undeveloped offshore lease blocks and other possible
lease and acquisition prospects in the Gulf of Mexico, 148 square miles covering
the Charco Field and surrounding areas and approximately 100 square miles in
South Louisiana. The Company has 15 geologists and geophysicists with a combined
industry experience averaging over 25 years and 10 geophysical workstations for
use in interpreting 3-D seismic data. The availability of 3-D seismic data for
Gulf of Mexico properties at reasonable costs has improved the Company's ability
to identify exploration and development prospects in its 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 the Company's
strategy. Properties operated by the Company account for approximately 85% of
its production. The Company prefers to operate its properties in order to manage
production performance while controlling operating expenses and the timing and
amount of capital expenditures. The Company also pursues cost savings through
the use of outside contractors for much of its offshore field operations
activities. As a result of these and other factors, the Company achieved lease
operating expense (excluding severance taxes of $0.12 per Mcfe) of $0.30 per
Mcfe of production and net general and administrative expense of $0.11 per Mcfe
of production for the year ended December 31, 2000.

Geographically Focused Operations

         The Company currently operates in six areas of geographic concentration
- the Gulf of Mexico, South Texas, South Louisiana, the Arkoma Basin, East
Texas, and West Virginia - and continues to evaluate and may add additional core
areas in the future. The geographic focus of the Company's operations in six
core areas enable it to manage a large asset base with a relatively small number
of employees and to add and operate production at relatively low incremental
costs. Focusing drilling activities on properties in relatively concentrated
offshore and onshore areas permits the Company to utilize its base of
geological, engineering, exploration and production experience in these regions.


                                      -3-
<PAGE>   5


KEYSPAN JOINT VENTURE

         Effective January 1, 1999, the Company entered into a joint exploration
agreement (the "KeySpan Joint Venture") 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 KeySpan Joint
Venture, the Company contributed all of its then undeveloped offshore acreage to
the joint venture and KeySpan received 45% of Houston Exploration's 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, the Company received reimbursements
from KeySpan for a portion of its general and administrative costs.

         During the two year term of the joint drilling program beginning
January 1, 1999 and ending December 31, 2000, the Company, together with
KeySpan, drilled a total of 21 wells: 17 exploratory and four development, five
of which were unsuccessful. KeySpan spent a total of $82.1 million on
exploration and development and Houston Exploration received a total of $7.3
million in general and administrative cost reimbursements.

         Effective December 31, 2000, the Company and KeySpan agreed to
terminate the KeySpan Joint Venture. As a result, KeySpan will not participate
in the Company's future offshore exploration prospects nor will the Company
receive any reimbursement from KeySpan for future general and administrative
costs. However, pursuant to the terms of the agreement entered into in
connection with the KeySpan Joint Venture, KeySpan will continue to maintain its
working interest in all wells drilled under the joint venture agreement. KeySpan
has agreed to continue the development of its working interests in prospects
drilled under the drilling program and, for the year 2001, KeySpan has agreed to
commit approximately $17 million for the development of prospects successfully
drilled during 1999 and 2000.


                                      -4-
<PAGE>   6


GULF OF MEXICO PROPERTIES

         The Company holds interests in 106 offshore blocks, of which 32 are
currently producing. The Company operates 22 of these producing blocks,
accounting for approximately 80% of the Company's offshore production. The
following table lists the Company's net proved reserves, average working
interest and the operator for the Company's ten largest offshore properties as
of December 31, 2000. These properties represent over 80% of the Company's Gulf
of Mexico proved reserves and approximately 85% of its offshore production
during 2000:

<TABLE>
<CAPTION>

                                               NET PROVED RESERVES AT DECEMBER 31, 2000
                                               ----------------------------------------

                                                                                           AVERAGE
                                                  GAS             OIL         TOTAL        WORKING
          OFFSHORE FIELDS                        (MMcf)         (MBbls)      (MMcfe)       INTEREST    OPERATOR
-------------------------------------------     -------         -------      --------      --------  ------------
<S>                                             <C>             <C>          <C>           <C>       <C>
Mustang Island Blocks A-31/32 .............      65,650           178         66,718         100%     Company

West Cameron Blocks 76/77/60/61 ...........      24,509           170         25,529          15%     Third Party

East Cameron Blocks 82/83 .................      22,880           263         24,458         100%     Company

West Cameron Block 587 ....................      15,188            --         15,188          64%     Third Party

Mustang Island Blocks 858/868 .............       9,939           243         11,397          83%     Company

South Timbalier Block 317 .................         840         1,479          9,714          55%     Company

High Island Blocks 38/39 ..................       9,186            67          9,588          45%     Company

Vermilion Block 408 .......................       2,383         1,127          9,145          31%     Company

Matagorda Island Blocks 651/671/672 .......       9,594            18          9,702          67%     Company

North Padre Island Block 883 ..............       4,802            56          5,138          17%     Third Party

All Other Gulf of Mexico (13 fields) ......      36,601         1,160         43,561
                                                -------         -----        -------
Total Gulf of Mexico ......................     201,572         4,761        230,138
                                                =======         =====        =======
</TABLE>

         Drilling Activity. During 2000, the Company drilled 14 successful wells
(eight exploratory and six development) and four unsuccessful wells (two
exploratory and two development) on its Gulf of Mexico properties. KeySpan
participated in 13 of the wells drilled during 2000: all eight of the successful
exploratory wells, the two successful development wells and three of the four
unsuccessful wells. Discoveries were made at North Padre Island 883, Matagorda
Island 704, High Island 133, Mustang Island 726, Vermilion 408 and South
Timbalier 317. Four development wells were drilled on proved acreage acquired by
the Company in November 1999 at West Cameron 587. During the second half of
2000, development wells were drilled at North Padre Island 883 and Mustang
Island 726 to further delineate discoveries made earlier during 2000.

         The Company plans to drill approximately eight offshore exploratory
wells during 2001 and five development wells. At December 31, 2000, the Company
had two offshore exploratory wells in progress: East Cameron 83 and Mustang
Island 860-L. The well at East Cameron 83 is successful and is currently being
completed with initial production expected early in the second quarter of 2001.
The well at Mustang Island 860-L was found to be unproductive. As of February
21, 2000, the Company was participating in the drilling of one exploratory well
at Mustang Island 933-S. Due to the termination of the primary term of the
KeySpan Joint Venture effective as of December 31, 2000, KeySpan is not
participating in the Company's exploratory wells that are currently in progress;
however, pursuant to the terms of the KeySpan Joint Venture, KeySpan will
continue to participate in the future development of its successful prospects
drilled during 1999 and 2000.

         Development Activity. During 2000, the Company completed platform and
facilities fabrication and installation at Galveston Island 389, Galveston
Island 190, Matagorda 704, North Padre Island 883 and High Island 133. All of
these blocks are currently producing. Pipeline construction is currently in
progress at Galveston Island 144 and the Company plans to begin facility
construction at South Timbalier 317 and Vermilion 408 during 2001.


                                      -5-
<PAGE>   7


         Capital Spending. Capital spending associated with the Company's Gulf
of Mexico properties during 2000 was $121.1 million, including $31.2 million for
exploratory drilling, $48.8 million for development drilling and platform and
facilities construction and $41.1 million for property acquisition and leasehold
costs, which includes $13.9 million for the acquisition of incremental
working interests in existing production at Vermilion 203, West Cameron 76 and
Mustang Island 858 together with incremental interests in discoveries made
during 2000 at High Island 133 and Vermilion 408.

         During the initial two-year term of the KeySpan Joint Venture, KeySpan
participated with the Company in drilling 21 offshore wells and spent a total of
$82.1 million on exploration and development, with $46.5 million spent during
2000 and $35.6 million spent during 1999. The Company received from KeySpan a
total of $7.3 million in general and administrative expense reimbursements, with
$2.5 million received during 2000 and $4.8 million received during 1999.

         For 2001, pursuant to the secondary term of the KeySpan Joint Venture,
KeySpan has committed to a capital budget of $17 million for development of its
working interests in prospects drilled under the KeySpan Joint Venture during
1999 and 2000. The Company is estimating it will spend approximately $150
million of its capital expenditure budget of $225 million on offshore projects
during 2001.


                                      -6-
<PAGE>   8


ONSHORE PROPERTIES

         The Company also owns significant onshore natural gas and oil
properties in South Texas, South Louisiana, the Arkoma Basin of Oklahoma and
Arkansas, East Texas and West Virginia. These properties represent interests in
1,242 gross (844.1 net) producing wells, approximately 85% of which the Company
is the operator of record, and 175,320 gross (109,657 net) acres.

         The following table lists the Company's average working interest and
net proved reserves for its core onshore areas of operation as of December 31,
2000, representing all of the Company's onshore reserves:

<TABLE>
<CAPTION>
                                                                                     NET PROVED RESERVES AT
                                                                                        DECEMBER 31, 2000
                                                                    AVERAGE     ---------------------------------
                                                                    WORKING      GAS         OIL           TOTAL
ONSHORE OPERATING AREAS                                             INTEREST    (MMcf)      (MBbls)       (MMcfe)
-----------------------                                             --------    -------     --------      -------
<S>                                                                 <C>         <C>         <C>           <C>
Charco Field (South Texas) .................................          100%      163,333           76      163,789
South Lake Arthur and Lake Pagie (South Louisiana) .........           55%       33,038          359       35,192
Chismville/Massard Field (Arkansas) ........................           73%       85,067           --       85,067
Wilburton, Panola and Surrounding Fields (Oklahoma) ........           23%        8,121           --        8,121
Willow Springs and Surrounding Fields (East Texas) .........           53%        9,507           93       10,065
Appalachian Area (West Virginia) ...........................           60%       28,880           63       29,258
                                                                                -------      -------      -------
Total Onshore ..............................................                    327,946          591      331,492
                                                                                =======      =======      =======
</TABLE>

         The Company drilled or participated in the drilling of 44 successful
development wells and one successful exploratory well on its onshore properties
during 2000. During this same period, the Company drilled or participated in the
drilling of four development wells that were not successful. Capital spending
associated with the Company's onshore drilling program during 2000 was
approximately $62.9 million, including $54.5 million for development, $3.0
million for exploration and $5.4 million for leasehold acquisition costs. The
Company did not acquire any onshore properties during 2000.

         The Company is estimating it will spend approximately $75 million of
its 2001 capital expenditure budget of $225 million on onshore projects. For
2001, the Company plans to drill approximately four onshore exploratory wells
and 40 onshore development wells: 25 in the Charco Field, four wells in South
Louisiana, 16 wells in the Arkoma Basin. The Company believes it has identified
enough additional development and exploratory projects on its existing acreage
to maintain an active drilling program for the next four to six years.

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

         Charco Field. The Charco Field is located in Zapata County, Texas. The
Company acquired its properties in the Charco Field in July 1996. The Company
owns a 100% working interest in the approximately 239 active wells in the Charco
Field, all of which are operated by the Company. Since the acquisition of the
Charco Field in July 1996, the Company has 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 the
Company's interest, to an average of 91 MMcfe per day, net to the Company's
interest, during the fourth quarter of 2000. The Company has drilled 87
successful wells, added 165 Bcfe in reserves and produced 115 Bcfe since the
acquisition of the Charco Field. During 2000, the Company successfully drilled
25 development wells and three unsuccessful development wells. The Company is
continuing its interpretation of 3-D seismic data covering 148 square miles of
its Charco Field properties and the surrounding area. Subsequent to year end,
the Company has successfully drilled and completed four development wells and is
currently in the process of drilling three new development wells.


                                      -7-
<PAGE>   9


         South Lake Arthur and Lake Pagie Fields. The South Lake Arthur Field is
located primarily in Vermilion Parish and the Lake Pagie Field is located
primarily in Terrebonne Parish, both in South Louisiana. The Company acquired
the producing properties together with undeveloped acreage initially in April
1998 and purchased additional interests in South Lake Arthur wells in October
and November 1998. The Company owns interests in 50 producing wells, of which it
operates seven wells. Working interests in these wells range from 2% to 70% and
average 55%. During 2000, the Company drilled one development well located in
South Lake Arthur. The well, a deep test, was drilled to approximately
17,000 feet. The Company has a 52% working interest in the well. The well has
been deemed noncommercial, has been temporarily abandoned and is pending further
evaluation. During the fourth quarter of 2000, production from the South
Louisiana properties averaged approximately 9 MMcfe/d, net to the Company's
interest. At December 31, 2000, the Company was participating in the drilling of
two exploratory wells: the Latarre Co Inc., located in Terrebonne Parish with a
working interest of 15%, which was found to be unproductive and the Clara Gossen
Caillouet, located in Acadia Parish with a working interest of 33.3%, which is
still in progress and nearing its targeted depth of 17,500 feet.

         Chismville/Massard Field. The Chismville/Massard Field is located in
Logan and Sebastian Counties, Arkansas. The Company owns working interests in
approximately 196 active wells, of which it operates 112 wells. Working
interests in these wells range from 11% to 100% and average approximately 73%.
During 2000, the Company successfully completed 18 gross (11.6 net) development
wells. During the fourth quarter of 2000, production averaged 15 MMcfe/d, net to
the Company. The Company plans to maintain at least one drilling rig in Arkoma
throughout the year and plans to add an additional drilling rig for a portion of
the year. Since December 31, 2000, the Company drilled or participated in the
drilling of three (1.3 net) successful wells and two (0.9 net) unsuccessful
wells. At February 21, 2001, the Company had four (1.9 net) wells in progress.

         Willow Springs and Surrounding Fields. The Willow Springs Field is
located in Gregg County, Texas, with surrounding fields located in Panola and
Harrison Counties, Texas. The Company owns working interests in 35 active wells,
of which it operates 31 wells. Working interests in these wells range from 3% to
100% and average approximately 53%. During the fourth quarter of 2000,
production averaged 3 MMcfe/d, net to the Company.

         Wilburton, Panola and Surrounding Fields. The Wilburton and Panola
Fields are located in Latimer County, Oklahoma. The Company owns working
interests in 52 active wells, of which it operates 16 wells. Working interests
in these wells range from 1% to 63% and average approximately 23%. During 2000,
the Company participated in the successful drilling of two (0.6 net) wells, one
exploratory and one development well. During the fourth quarter of 2000,
production averaged 3 MMcfe/d, net to the Company.

         Appalachian Area. The Belington, Clarksburg and Seneca Upshur Fields
are located in Barbour, Randolph, Upshur and Mingo Counties, West Virginia. The
Company owns working interests in 668 producing wells, substantially all of
which are operated by the Company. Working interests in these wells range from
6% to 100% and average approximately 60%. During the fourth quarter of 2000,
production averaged 4 MMcfe/d, net to the Company.

ADDITIONAL FUTURE PROJECTS

         In addition to the properties described above, the Company has
accumulated a large inventory of offshore leases comprised of 70 undeveloped
blocks representing 357,7991 gross (313,576 net) acres. Of these undeveloped
leases, 15 have been evaluated by the Company's geologists and geophysicists and
are considered ready to drill. The Company plans to continue active
participation in upcoming state and federal lease sales. In addition, the
Company continues to actively pursue farm-ins from other companies, interests in
joint ventures and potential acquisitions of proved properties. The Company is
also evaluating its producing properties for workovers and recompletions which
it will undertake in the next several years.


                                      -8-
<PAGE>   10


NATURAL GAS AND OIL RESERVES

         The following table summarizes the estimates of the Company's
historical net proved reserves as of December 31, 2000, 1999 and 1998, and the
present values attributable to these reserves at such dates. The reserve data
and present values were prepared by Netherland, Sewell & Associates, Inc.
("NSA") and Miller and Lents, Ltd. ("Miller and Lents"), independent petroleum
engineering consultants.

<TABLE>
<CAPTION>

                                                                               AS OF DECEMBER  31,
                                                                  ------------------------------------------
                                                                     2000            1999            1998
                                                                  ----------      ----------      ----------
                                                                                (IN THOUSANDS)
<S>                                                               <C>             <C>             <C>
Net Proved Reserves(1):
   Natural gas (MMcf) ......................................         529,518         526,185         470,447
   Oil (MBbls) .............................................           5,352           2,470           1,650
   Total (MMcfe) ...........................................         561,630         541,005         480,347
Present value of future net revenues before income
  taxes(2) .................................................      $2,796,478      $  529,671      $  412,933
Standardized measure of discounted future net cash
  flows(3) .................................................      $2,064,027      $  469,225      $  396,060
</TABLE>

----------

(1)      NSA and Miller and Lents prepared reserve data and present values with
         respect to properties comprising approximately 78% and 22%,
         respectively, of the present values attributable to the Company's
         proved reserves as of December 31, 2000; 76% and 24%, respectively, of
         the present values attributable to proved reserves as of December 31,
         1999; and 71% and 29%, respectively, of the present values attributable
         to proved reserves as of December 31, 1998.

(2)      The present value of future net revenues attributable to the Company's
         reserves was prepared using prices in effect at the end of the
         respective periods presented, discounted at 10% per annum on a pre-tax
         basis. Average prices per Mcf of natural gas, used in making such
         present value determinations as of December 31, 2000, 1999 and 1998
         were $9.55, $2.01 and $1.83, respectively. Average prices per Bbl of
         oil used in making such present value determinations as of December 31,
         2000, 1999 and 1998 were $24.69, $22.80, and $10.65, 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.

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


                                      -9-
<PAGE>   11
DRILLING ACTIVITY

         The following table sets forth the drilling activity of the Company on
its properties for the years ended December 31, 2000, 1999 and 1998.

<TABLE>
<CAPTION>
                                                YEAR ENDED DECEMBER 31,
                                -------------------------------------------------------
                                      2000                1999               1998
                                ---------------     ---------------     ---------------
                                GROSS      NET      GROSS      NET      GROSS      NET
                                -----      ----     -----      ----     -----      ----
<S>                             <C>        <C>      <C>        <C>      <C>        <C>
OFFSHORE DRILLING ACTIVITY:
Exploratory:
     Productive ...........         8       3.0         6       1.4         2       1.3
     Non-Productive .......         2       0.9         2       1.0         5       4.2
                                 ----      ----      ----      ----      ----      ----
          Total ...........        10       3.9         8       2.4         7       5.5
 Development:
     Productive ...........         6       3.3         8       5.5         1       1.0
     Non-Productive .......         2       0.8        --        --         1       0.8
                                 ----      ----      ----      ----      ----      ----
          Total ...........         8       4.1         8       5.5         2       1.8

ONSHORE DRILLING ACTIVITY:
 Exploratory:
     Productive ...........         1       0.1         2       1.2         1       0.3
     Non-Productive .......        --        --        --        --        --        --
                                 ----      ----      ----      ----      ----      ----
          Total ...........         1       0.1         2       1.2         1       0.3
 Development:
     Productive ...........        44      36.5        31      24.3        23      18.2
     Non-Productive .......         4       3.5         6       3.1         4       3.8
                                 ----      ----      ----      ----      ----      ----
          Total ...........        48      40.0        37      27.4        27      22.0
</TABLE>

PRODUCTIVE WELLS

         The following table sets forth the number of productive wells in which
the Company owned an interest as of December 31, 2000.

<TABLE>
<CAPTION>
                              COMPANY
                              OPERATED
                              PLATFORMS      COMPANY OPERATED WELLS   NON-OPERATED WELLS   TOTAL PRODUCTIVE WELLS
                              ---------      ----------------------   ------------------   ----------------------
                                              GROSS         NET        GROSS       NET       GROSS        NET
                                             --------     ---------   -------    -------   ---------   ----------
<S>                           <C>            <C>          <C>         <C>        <C>       <C>         <C>
    OFFSHORE
        Gas ........                29             51        41.4          18        5.0          69       46.4
        Oil ........                --             --          --           4        0.5           4        0.5
                               -------        -------     -------     -------    -------     -------    -------
        Total ......                29             51        41.4          22        5.5          73       46.9
                               =======        =======     =======     =======    =======     =======    =======

    ONSHORE
        Gas ........                            1,056       805.1         182       36.1       1,238      841.2
        Oil ........                                4         2.9          --         --           4        2.9
                                              -------     -------     -------    -------     -------    -------
        Total ......                            1,060       808.0         182       36.1       1,242      844.1
                                              =======     =======     =======    =======     =======    =======
</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.


                                      -10-
<PAGE>   12
ACREAGE DATA

         The following table sets forth the approximate developed and
undeveloped acreage in which the Company held a leasehold mineral or other
interest as of December 31, 2000. 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 such acreage contains proved reserves:

<TABLE>
<CAPTION>

                                    DEVELOPED ACRES         UNDEVELOPED ACRES        UNDEVELOPED ACRES
                                   ------------------     --------------------     --------------------
                                                                                        PROFORMA(2)

                                    GROSS       NET        GROSS        NET         GROSS         NET
                                   -------    -------     -------      -------     -------      -------
<S>                                <C>        <C>         <C>          <C>         <C>          <C>
         Offshore(1) .........     174,497    103,718     369,319      226,197     357,799      313,576
         Onshore .............     160,520    102,554      14,800        7,103      14,800        7,103
                                   -------    -------     -------      -------     -------      -------
                  Total ......     335,017    206,272     384,119      233,300     372,599      320,679
                                   =======    =======     =======      =======     =======      =======
</TABLE>
----------

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

(2)      Reflects, on a proforma basis, offshore acreage that reverted back to
         the Company pursuant to the termination of the primary term of the
         KeySpan Joint Venture, effective January 1, 2001. See Note 6 -- Related
         Party Transactions.

MARKETING AND CUSTOMERS

         Substantially all of the Company's production is sold at market prices.
As is the nature of the exploration, development and production business,
production is normally sold to a relatively small number of customers. However,
based on the current demand for natural gas and oil, the Company believes that
the loss of any of the Company's major purchasers would not have a material
adverse effect on the Company. The Company sold natural gas and oil production
representing 10% or more of its natural gas and oil revenues for the year ended
December 31, 2000 to Dynegy, Inc. (22.5%) and Adams Resources and Energy, Inc.
(successor to H&N Gas Ltd.) (14.9%); for the year ended December 31, 1999 to
Adams Resources and Energy, Inc. (22.5%); and for the year ended December 31,
1998 to H&N Gas Ltd. (27%) and Columbia Energy Services Corporation (12%).

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

         Most of the Company's natural gas is transported through gas gathering
systems and gas pipelines which are not owned by the Company. Transportation
space on such gathering systems and pipelines is occasionally limited and at
times unavailable due to repairs or improvements being made to the facilities or
due to use by other gas shippers with priority transportation agreements. While
the Company's ability to market its natural gas has been subject to limitations
or delays only on an infrequent basis, if transportation space is restricted or
is unavailable, the Company's cash flow from the affected properties could be
adversely affected. See " Regulation" and "Risk Factors -- Hazard Losses May Not
be Insured."

ABANDONMENT COSTS

         The Company is responsible for its working interest share of costs to
abandon natural gas and oil properties and facilities. The Company provides for
its 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, 2000, total undiscounted abandonment costs
estimated to be incurred through the year 2012 were approximately


                                      -11-
<PAGE>   13


$13 million for properties in the federal and state waters and are not
considered significant for onshore properties. Estimates of abandonment costs
and their timing may change due to many factors including actual drilling and
production results, inflation rates, and changes in environmental laws and
regulations.

         The Minerals Management Service ("MMS") requires lessees of Outer
Continental Shelf 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. The Company is presently exempt from any
requirement by MMS to provide supplemental bonding on its offshore leases,
although no assurance can be made that it will continue to satisfy the
requirements for such exemption in the future. Whether or not the Company
qualifies for such exemption, the Company does not believe that the cost of any
such bonding requirements will materially affect the Company's financial
condition or results of operations. Under certain circumstances, the MMS has the
authority to suspend or terminate operations on federal leases for failure to
comply with applicable bonding requirements or other regulations applicable to
plugging and abandonment. Any such suspensions or terminations of the Company's
operations could have a material adverse effect on the Company's financial
condition and results of operations.

TITLE TO PROPERTIES

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

THIRD PARTY CONTRACTORS

         In an effort to control costs, the Company entered into a contract with
Operators & Consulting Services, Inc. ("OCS") pursuant to which OCS provides
professional services to the Company in the areas of drilling, production and
construction for offshore properties. OCS provides (i) engineering and field
supervision for well design, drilling, completion and workover operations; (ii)
supervision of the daily production operations and field personnel to operate
and maintain production facilities; and (iii) coordination and review of third
party engineering and fabrication work, and installation supervision of
platforms, production facilities and pipelines. The Company has maintained this
contractual relationship with OCS since 1989.

COMPETITION

         The Company encounters intense competition from other oil and gas
companies in all areas of its operations, including the acquisition of producing
properties and proved undeveloped acreage. The Company's competitors include
major integrated oil and gas companies and numerous independent oil and gas
companies, individuals and drilling and income programs. Many of its competitors
are large, well-established companies with substantially larger operating staffs
and greater capital resources than the Company's and which, in many instances,
have been engaged in the oil and gas business for a much longer time than the
Company. Such companies may be able to pay more for productive natural gas and
oil properties and exploratory prospects and to define, evaluate, bid


                                      -12-
<PAGE>   14


for and purchase a greater number of properties and prospects than the Company's
financial or human resources permit. The Company's ability to acquire additional
properties and to discover reserves in the future will be dependent upon its
ability to evaluate and select suitable properties and to consummate
transactions in this highly competitive environment.

OPERATING HAZARDS AND UNINSURED RISKS

         The Company's operations are subject to hazards and risks inherent in
drilling for, producing and transporting of natural gas and oil. These hazards
and risks include: fires, natural disasters, explosions, encountering formations
with abnormal pressures, blowouts, cratering, pipeline ruptures, and spills, any
of which can result in loss of hydrocarbons, environmental pollution, personal
injury claims, and other damage to properties of the Company and others.
Additionally, the Company's natural gas and oil operations located in the Gulf
of Mexico are subject to tropical weather disturbances, some of which can be
severe enough to cause substantial damage to facilities and possibly interrupt
production. As protection against operating hazards, the Company maintains
insurance coverage against some, but not all, potential losses. The Company's
coverages include, but are not limited to, operator's extra expense, to include
loss of well, blowouts and certain costs of pollution control, physical damage
on certain assets, employer's liability, comprehensive general liability,
automobile liability and worker's compensation. The Company believes that its
insurance is adequate and customary for companies of a similar size engaged in
operations similar to those of the Company, but losses could occur for
uninsurable or uninsured risks or in amounts in excess of existing insurance
coverage. The occurrence of an event that is not fully covered by insurance
could have a material adverse impact on the Company's 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 the Company's cost of doing business and, consequently,
affects its profitability, generally, these burdens do not appear to affect the
Company any differently or to any greater or lesser extent than other companies
in the industry with similar types, quantities and locations of production.

         DRILLING AND PRODUCTION. The Company's operations are subject to
various types of regulation at federal, state and local levels. This regulation
includes requiring permits for the drilling of wells, drilling bonds and reports
concerning operations. Most states in which the Company operates 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 nature gas and impose certain
requirements regarding the ratability of production. These regulations may limit
the amount of oil and gas the Company can produce from its wells or limit the
number of wells or the locations at which the Company can drill.

         The Company conducts its operations in the Gulf of Mexico on oil and
gas leases which are granted by the U.S. federal government and are administered
by the Minerals Management Service. The MMS issues leases through competitive
bidding. These leases contain relatively standardized terms and require
compliance with detailed MMS regulations. For offshore operations, lessees must
obtain MMS approval for exploration plans and development and production plans
prior to the commencement of such operations. In addition to permits required
from other agencies, such as the Coast Guard, the Army Corps of Engineers and
the Environmental Protection Agency, lessees must obtain a permit from the MMS
prior to the commencement of drilling. The MMS has


                                      -13-
<PAGE>   15


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 operating procedures for outer continental shelf
production platforms and pipelines. The MMS also has issued regulations
restricting the flaring or venting of natural gas, and has recently proposed to
amend such regulations to prohibit the flaring of liquid hydrocarbons and oil
without prior authorization. Similarly, the MMS has promulgated other
regulations governing the plugging and abandonment of wells located offshore and
the removal of all production facilities. To cover the various obligations of
lessees on the outer continental shelf, the MMS generally requires that lessees
post substantial bonds or other acceptable assurances that such obligations will
be met. The Outer Continental Shelf Lands Act may generally impose liabilities
on the Company for its offshore operations conducted on federal leases for costs
of clean-up and damages caused by pollution resulting from the Company's
operations. Under circumstances such as conditions deemed to be a threat or harm
to the environment, the MMS may suspend or terminate any of the Company's
operations in the affected area.

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

         The Resource Conservation and Recovery Act ("RCRA") affects oil and gas
production activities by imposing requirements for the generation,
transportation, treatment, storage, disposal and cleanup of "hazardous wastes."
However, pursuant to regulations promulgated under RCRA, drilling fluids,
produced waters, and other wastes associated with the exploration, development,
or production of crude oil, natural gas, or geothermal energy do not constitute
"hazardous wastes" subject to RCRA regulation. Nonetheless, such wastes
constitute "solid wastes" and are subject to less stringent regulation under
RCRA's non-hazardous waste provisions which are administered by the states and
typically apply to solid waste disposal facilities. Furthermore, the
Environmental Protective Agency ("EPA") has limited the disposal option for
certain hazardous wastes and may adopt more stringent disposal standards for
non-hazardous wastes. Finally, states may adopt waste handling requirements
which are more stringent than the RCRA requirements, and may treat some wastes
as hazardous wastes which are not considered hazardous under RCRA.

         The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA"), also known as the "superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes of
persons who are considered to be responsible for the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances. CERCLA also
authorizes the EPA and, in some cases, private parties to take actions in
response to threats to the public health or the environment and to seek recovery
from responsible classes of persons of the costs and these actions. In the
course of its operations, the Company generates wastes that may fall within
CERCLA's definition of "hazardous substances." The Company may be responsible
under CERCLA for all or part of the costs to clean up sites at which "hazardous
substances" have been deposited. The Company has not been named by the EPA or
alleged by any third party as


                                      -14-
<PAGE>   16


being responsible for costs and liability associated with alleged releases of
any "hazardous substance" at any "superfund" site.

         The Oil Pollution Act requires the lessee or permittee of an offshore
area in which a covered offshore facility is located to establish and maintain
financial responsibility of at least $35 million, which may be increased to $150
million for facilities with large worst-case spill potentials and under other
circumstances, to cover liabilities related to an oil spill for which the lessee
or permittee of the offshore area is statutorily responsible. Owners of
multiple facilities are required to maintain financial responsibility for only
the facility with the largest potential worst-case spill. The OPA also 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 OPA.

         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. In
addition, the federal discharge permitting program prohibits the discharge of
produced water, sand and other substances related to the oil and gas industry to
coastal waters, and the prevailing trend of water regulation is to reduce
allowable discharges.

         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 certain toxic air pollutants
are being developed by the EPA, and may increase the costs of compliance for
certain facilities.

         NATURAL GAS SALES TRANSPORTATION. Historically, the price of the
natural gas produced by the Company and the manner in which its production is
marketed was affected by federal legislation and regulatory controls. The
Federal Energy Regulatory Commission (the "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 sales by the Company of its own production.

         The FERC also regulates interstate natural gas transportation rates and
service conditions, which affect the marketing of natural gas produced by the
Company, as well as the revenues received by the Company for sales of its
natural gas. Commencing in 1985, the 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. The
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.

         Under the FERC's current regulatory regime, transmission services must
be provided on an open-access, non-discriminatory basis. However, the natural
gas industry historically has been very heavily regulated; therefore, we cannot
guarantee that the less stringent regulatory approach recently pursued by the
FERC and Congress will continue indefinitely into the future.


                                      -15-
<PAGE>   17


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, revenues generated 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 are subject to wide fluctuation in response to relatively minor changes
in the supply of and demand for natural gas and oil, market uncertainty and a
variety of additional factors that are beyond our control, such as:

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

         o        the price of foreign imports;

         o        overall domestic and global economic conditions;

         o        political and economic conditions in oil producing countries;

         o        the level of consumer product demand;

         o        weather conditions;

         o        domestic and foreign governmental regulations; and

         o        the price and availability of alternative fuels.

         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 WRITEDOWNS IF NATURAL GAS AND OIL PRICES
DECLINE.

         There is a risk that we will 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.

         Although natural gas and oil prices have recently reached high levels,
we may be required to take writedowns in future periods should prices decline
significantly.

         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 2001 is estimated at approximately $225 million. This
budget excludes potential property acquisitions. We believe that we will have
sufficient cash provided by operating activities and borrowings under our bank
credit facility to fund planned capital expenditures in 2001. 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.


                                      -16-
<PAGE>   18


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

         Our outstanding indebtedness at December 31, 2000 was $245 million, and
as of February 21, 2001 was $248 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 such 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.
Exploration, 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 subject to
liability or losses that could be substantial due to events that are not
insured.


                                      -17-
<PAGE>   19


         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.

         WE ARE SUBJECT TO RISKS RELATED TO OUR HEDGING ACTIVITIES.

         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.
Hedging instruments used are fixed price swaps, collars and options. While the
use of these types of hedging instruments limits the downside risk of adverse
price movements, they are subject to a number of risks, including instances in
which the benefit to revenues is limited when natural gas prices increase. For
example, as a result of hedges, our fourth quarter 2000 net income was $21.1
million, or $13.7 (net of taxes) million less than it would have been had we not
hedged 50% of our natural gas 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 thereunder, 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.


                                      -18-
<PAGE>   20


         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 68% of our common
stock. KeySpan may decide to sell all or part of its ownership interest in us in
a transaction that does not provide other 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:

         o        the election of entire Board of Directors;

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

         o        all matters relating to our management;

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

         o        payment of dividends on our common stock;

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

         o        hedging, drilling, operating and acquisition expenditure
                  plans.

         The Chairman of our Board of Directors, Robert B. Catell, is also the
Chairman of the Board of Directors and Chief Executive Officer of KeySpan. In
addition to Mr. Catell, four of our nine other directors are also affiliated
with KeySpan: Craig G. Matthews is President and Chief Operating Officer of
KeySpan; Gerald Luterman is Senior 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 a director of KeySpan.

EMPLOYEES

         As of December 31, 2000, the Company had 110 full time employees, 70 of
whom are located at the Company's headquarters in Houston, Texas and the
remainder of whom are located at field offices. None of the Company's employees
are represented by a labor union. The Company contracts with OCS to conduct all
of the day to day operations of the Company's offshore properties. See "Third
Party Contractors."

OFFICES

         The Company currently leases approximately 46,000 square feet of office
space in Houston, Texas, where its principal offices are located. In addition,
the Company maintains field operations offices in the areas where it operates
onshore properties.


                                      -19-
<PAGE>   21


ITEM 3.  LEGAL PROCEEDINGS

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

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

         No matters were submitted to a vote of the Company's security holders
during the last quarter of the fiscal year ended December 31, 2000.

PART II.

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

         The Company's common stock (symbol: THX) is traded on the New York
Stock Exchange. The following table sets forth the range of high and low sales
prices for each calendar quarterly period from January 1, 1999 through December
31, 2000 as reported on the New York Stock Exchange:

<TABLE>
<CAPTION>

YEAR ENDED DECEMBER 31, 2000         HIGH                  LOW
                                   -------               -------
<S>                                <C>                   <C>
First Quarter ......               $20.938               $14.500
Second Quarter .....                25.750                17.375
Third Quarter ......                28.313                21.188
Fourth Quarter .....                39.750                21.875
<CAPTION>

YEAR ENDED DECEMBER 31, 1999        HIGH                   LOW
                                   -------               -------
First Quarter ......               $20.500               $12.000
Second Quarter .....                20.625                16.625
Third Quarter ......                23.125                18.500
Fourth Quarter .....                22.875                17.688
</TABLE>

         As of February 21, 2001, 29,986,461 shares of common stock were
outstanding and the Company had approximately 45 stockholders of record and
approximately 3,300 beneficial owners.

DIVIDENDS

         The Company has not paid any cash dividends during the two most recent
fiscal years and does not anticipate declaring any dividends in the foreseeable
future. The Company expects that it will retain its cash for the operation and
expansion of its business, including exploration, development and acquisition
activities. The Company's bank credit facility and the indenture governing the
85/8% Senior Subordinated Notes contain restrictions on the payment of dividends
to holders of common stock. Accordingly, the Company's ability to pay dividends
will depend upon these restrictions and the Company's results of operations,
financial condition, capital requirements and other factors deemed relevant by
the Board of Directors. See "Item 7. -- Management's Discussion and Analysis of
Financial Condition and Results of Operations."


                                      -20-
<PAGE>   22

ITEM 6.  SELECTED FINANCIAL DATA

         The following table shows selected financial data derived from the
Company's consolidated financial statements for each of the five years in the
period ended December 31, 2000. The financial data should be read in conjunction
with Item 7. "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and the Company's Consolidated Financial Statements and
Notes thereto.


<TABLE>
<CAPTION>


                                                                                YEARS ENDED DECEMBER 31,
                                                        ----------------------------------------------------------------------
                                                          2000           1999           1998            1997           1996
                                                        ---------      ---------      ---------       ---------      ---------
                                                                        (IN THOUSANDS, EXCEPT PER SHARE DATA)
<S>                                                     <C>            <C>            <C>             <C>            <C>
CONSOLIDATED STATEMENT OF OPERATIONS DATA:
Revenues:
  Natural gas and oil revenues ...................      $ 270,595      $ 150,580      $ 127,124       $ 116,349      $  64,864
  Other ..........................................          1,738          1,147          1,123           1,297          1,040
                                                        ---------      ---------      ---------       ---------      ---------
        Total revenues ...........................        272,333        151,727        128,247         117,646         65,904
Expenses:
  Lease operating ................................         23,553         18,406         16,199          14,146         10,800
  Severance tax ..................................          9,757          5,444          4,967           4,233          1,401
  Depreciation, depletion and amortization .......         89,239         74,051         79,838          59,081         33,732
  Writedown in carrying value ....................             --             --        130,000              --             --
  General and administrative, net ................          8,928          4,150          6,086           5,825          6,249
                                                        ---------      ---------      ---------       ---------      ---------
        Total operating expenses .................        131,477        102,051        237,090          83,285         52,182
Income (loss) from operations ....................        140,856         49,676       (108,843)         34,361         13,722
Strategic review expenses(1) .....................          1,752             --             --              --             --
Interest expense, net ............................         11,361         13,307          4,597             938          2,875
                                                        ---------      ---------      ---------       ---------      ---------
Income (loss) before income taxes ................        127,743         36,369       (113,440)         33,423         10,847
Income tax provision (benefit) ...................         42,485         11,748        (40,754)         10,173          2,205
                                                        ---------      ---------      ---------       ---------      ---------
Net income (loss) ................................      $  85,258      $  24,621      $ (72,686)      $  23,250      $   8,642
                                                        =========      =========      =========       =========      =========

Net income (loss) per share ......................      $    3.06      $    1.03      $   (3.05)      $    1.00      $    0.49
                                                        =========      =========      =========       =========      =========
Net income (loss) per share--diluted .............      $    3.02      $    0.95      $   (3.05)      $    0.97      $    0.49
                                                        =========      =========      =========       =========      =========

Weighted average shares ..........................         27,860         23,906         23,768          23,337         17,532
Weighted average shares--diluted .................         28,213         28,310         23,768          24,028         17,687

Ratio of earnings to fixed charges(2) ............           5.5x           2.0x            N/M            5.0x           2.2x
</TABLE>

<TABLE>
<CAPTION>

                                                                                YEARS ENDED DECEMBER 31,
                                                        ----------------------------------------------------------------------
                                                          2000           1999           1998            1997           1996
                                                        ---------      ---------      ---------       ---------      ---------
                                                                                    (IN THOUSANDS)
<S>                                                     <C>           <C>             <C>             <C>           <C>
CONSOLIDATED BALANCE SHEET DATA:
Property, plant and equipment, net ...............      $ 705,390     $  610,116      $ 536,582       $443,738      $  359,124
Total assets .....................................        837,384        678,483        569,452        491,391         401,285
Long-term debt and notes .........................        245,000        281,000        313,000        113,000          65,000
Stockholders' equity .............................        396,742        217,590        192,530        256,187         233,300
</TABLE>

----------

(1)      Represents a nonrecurring expenses incurred in connection with
         KeySpan's and the Company's decision to review strategic alternatives
         for the Company and KeySpan's investment in the Company, including the
         possible sale of all or a portion of the Company. See 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 the estimated
         interest component of rent expense.


                                      -21-
<PAGE>   23


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

         The following discussion is intended to assist in an understanding of
the Company's historical financial position and results of operations for each
year in the three-year period ended December 31, 2000. The Company's historical
consolidated financial statements and notes thereto included elsewhere in this
Annual Report on Form 10-K contain detailed information that should be referred
to in conjunction with the following discussion.

GENERAL

         Houston Exploration is an independent natural gas and oil company
engaged in the exploration, development, exploitation and acquisition of
domestic natural gas and oil properties. The Company's operations are currently
focused offshore in the Gulf of Mexico and onshore in South Texas, South
Louisiana, the Arkoma Basin, East Texas and West Virginia. Houston Exploration's
strategy is to utilize its geological and geophysical expertise to grow its
reserve base through a combination of (i) exploratory drilling in the Gulf of
Mexico; (ii) lower risk, high impact exploitation and development drilling
onshore; and (iii) selective opportunistic acquisitions both offshore and
onshore. At December 31, 2000, the Company had net proved reserves of 562 Bcfe,
94% of which were natural gas and 77% of which were classified as proved
developed.

         Houston Exploration began exploring for natural gas and oil in December
1985 on behalf of The Brooklyn Union Gas Company ("Brooklyn Union") and in
September 1996 the Company completed an initial public offering ("IPO") of its
common stock. Brooklyn Union became an indirect wholly-owned subsidiary of
KeySpan Corporation ("KeySpan") in May 1998 through the combination of Brooklyn
Union's parent company KeySpan Energy Corporation and Long Island Lighting
Company. As of December 31, 2000, THEC Holdings Corp., an indirect wholly owned
subsidiary of KeySpan, owned approximately 68% of the outstanding shares of
Houston Exploration's common stock. KeySpan, a member of the Standard & Poor's
500 Index, is a diversified energy provider that (i) distributes natural gas to
2.4 million customers in the Brooklyn, Long Island, Queens and Staten Island
areas of New York and to customers in eastern and central Massachusetts and
central New Hampshire; (ii) generates and manages electricity transmission and
distribution through the ownership and operation of generating plants throughout
New York State and through its contract with the Long Island Power Authority to
manage electricity service to 1.1 million customers in the Long Island area; and
(iii) through its other subsidiaries is involved in various energy services and
energy related investments including wholesale and retail gas and electric
marketing; appliance service and installation; large energy-system installation
and management; fiber optic telecommunications and energy-related internet
activities.

         As an independent oil and gas producer, the Company's revenue,
profitability and future rate of growth are substantially dependent upon
prevailing prices for natural gas, oil and condensate, which are dependent upon
numerous factors beyond the Company's control, such as economic, political and
regulatory developments and competition from other sources of energy. The energy
markets have historically been 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 be subject to wide fluctuations in the future. A
substantial or extended decline in natural gas and oil prices could have a
material adverse effect on the Company's financial position, results of
operations, cash flows, quantities of natural gas and oil reserves that may be
economically produced and access to capital.

         Full Cost Accounting. The Company uses the full cost method of
accounting for its investment in natural gas and oil properties. Under the full
cost method of accounting, all costs of acquisition, exploration and development
of natural gas and oil reserves are capitalized into a "full cost pool" as
incurred, and properties in the pool are depleted and charged to operations
using the unit-of-production method based on the ratio of current production to
total proved natural gas and oil reserves. To the extent that such capitalized
costs (net of accumulated depreciation, depletion and amortization) less
deferred taxes exceed the present value (using a 10% discount rate) of estimated
future net cash flows from proved natural gas and oil reserves and the lower of
cost or fair value of unproved properties, such excess costs are charged to
operations. If a writedown is required, it would result in a


                                      -22-
<PAGE>   24


charge to earnings but would not have an impact on cash flows from operating
activities. Once incurred, a write down of oil and gas properties is not
reversible at a later date even if oil and gas prices increase.

         At December 31, 2000, the Company estimated, using an average wellhead
price of $9.55 per mcf, that a $1.4 billion (after tax) full cost ceiling
"cushion" existed whereby the carrying value of the full cost pool was less than
the ceiling limitation imposed under full cost accounting. At December 31, 1999,
the Company estimated, using a wellhead price of $2.01 per Mcf, that a $99.2
million (after tax) full cost ceiling "cushion" existed whereby the carrying
value of the full cost pool was less than the ceiling limitation imposed under
full cost accounting.

         As of December 31, 1998, the Company estimated, using a December
wellhead price of $1.83 per Mcf, that actual capitalized costs of natural gas
and oil properties exceeded the ceiling limitation imposed under full cost
accounting rules by approximately $41.2 million, after taxes. Subsequent to
December 31, 1998, natural gas prices continued to decline, such that the
Company estimated, using a February 1999 wellhead price of $1.61 per Mcf, that
the ceiling limitation exceeded actual capitalized costs of natural gas and oil
properties by approximately $84.5 million, after taxes. As a result, the Company
reduced the carrying value of its natural gas and oil properties as of December
31, 1998, by $84.5 million, after taxes.

         New Accounting Pronouncements.

         In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative
Instruments and Hedging Activities." 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. The Company
adopted SFAS No. 133 effective January 1, 2001 and recorded a liability of $75
million to reflect the then negative fair market value of its hedge position in
place, covering the months January 2001 through December 2001. Because the
Company's hedges qualify for hedge accounting and pursuant to certain transition
rules, under SFAS 133, an offsetting entry has been made to accumulated other
comprehensive income, a component of stockholders' equity. The Company
estimates, using New York Mercantile Exchange ("NYMEX") prices as of February
21, 2001, that it will incur a loss of approximately $31 million during the
first three months of 2001 relating to hedges in place at December 31, 2000. The
fair market value of its hedge position for the remainder of 2001 (April through
December) is estimated, using February 21, 2001 prices, to be a liability of
approximately $10 million. The increase in fair market value of the Company's
costless collars is due to the significant decline in NYMEX prices since
December 31, 2000.

Recent Developments

         KeySpan Joint Venture. Effective December 31, 2000, the Company and
KeySpan agreed to terminate their joint exploration agreement (the "KeySpan
Joint Venture"). Effective January 1, 1999, the Company entered into the KeySpan
Joint Venture with KeySpan Exploration & Production, LLC, a subsidiary of
KeySpan, to explore for natural gas and oil over an initial two-year term which
expired December 31, 2000. Under the terms of the KeySpan Joint Venture, the
Company contributed all of its then undeveloped offshore leases to the joint
venture and KeySpan received 45% of Houston Exploration's 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, during the initial two-year term of the joint venture,
Houston Exploration received reimbursement for a portion of its general and
administrative costs.

         During the initial two-year term of the joint venture, KeySpan and the
Company drilled a total of 21 wells, of which 17 were exploratory and four were
development. Of the wells drilled, five were dry holes (four exploratory and one
development) representing an average success rate of 76%. KeySpan spent a total
of $82.1 million on exploration and development and Houston Exploration received
a total of $7.3 million in general and administrative cost reimbursements.


                                      -23-
<PAGE>   25


         Effective December 31, 2000, as a result of the termination of the
primary term of the KeySpan Joint Venture, all undeveloped offshore acreage
contributed to the KeySpan Joint Venture by the Company reverted back to Houston
Exploration, at no cost, and KeySpan will no longer participate in exploration
prospects of the Company nor will the Company receive general and administrative
expense reimbursements from KeySpan. However under the secondary term of the
KeySpan Joint Venture, KeySpan has agreed to continue to complete the
development of wells drilled under the terms of the joint venture during 1999
and 2000 and has committed to a development budget of approximately $17 million
for 2001.

RESULTS OF OPERATIONS

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

<TABLE>
<CAPTION>
                                                                             YEARS ENDED DECEMBER 31,
                                                                  ------------------------------------------
                                                                     2000            1999            1998
                                                                  ----------      ----------      ----------
<S>                                                               <C>             <C>             <C>
        PRODUCTION:
            Natural gas (MMcf) .............................          77,861          69,679          61,479
            Oil (MBbls) ....................................             311             258             225
            Total (MMcfe) ..................................          79,727          71,227          62,829

        AVERAGE SALES PRICES:
            Natural gas (per Mcf) realized(1) ..............      $     3.37      $     2.10      $     2.02
            Natural Gas (per Mcf) unhedged .................            3.96            2.14            1.96
            Oil (per Bbl) ..................................           27.22           16.41           12.18

        EXPENSES (PER MCFE):
            Lease operating ................................      $     0.30      $     0.26      $     0.26
            Severance tax ..................................            0.12            0.08            0.08
            Depreciation, depletion and amortization .......            1.12            1.04            1.27
            Writedown in carrying value of
                 natural gas and oil properties ............              --              --            2.07
            General and administrative, net ................            0.11            0.06            0.10
</TABLE>

----------

(1)      Reflects the effects of hedging.

RECENT FINANCIAL AND OPERATING RESULTS

COMPARISON OF THE YEARS ENDED DECEMBER 31, 2000 AND 1999

         Production. Houston Exploration's 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 was attributable to 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/day
during 1999 to an average of 99 MMcfe/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, the Company
acquired incremental working interests in existing production at Vermilion 203,
Mustang Island 858 and West Cameron 76.


                                      -24-
<PAGE>   26


         Onshore production remained unchanged at 119 MMcfe/day during 2000 as
compared to 1999. During the third quarter of 2000, the Company experienced
delays in bringing new wells on-line at its 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 the Company added a third
drilling rig to expedite its drilling program. The Company plans to maintain
three drilling rigs throughout the first half of 2001 with two rigs for the
remainder of the year.

         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, the Company
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 the Company would have achieved if hedges had not been in place during
the period. For the corresponding period during 1999, the Company 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 the
Company 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 for during 1999 to $0.30 per Mcfe for
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 the Company's 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 KeySpan Joint Venture (see Note 6 -- Related Party
Transactions). The Company 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 the Company's workforce combined with an
increase in incentive compensation and benefit related


                                      -25-
<PAGE>   27


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 KeySpan Joint Venture, the Company will no longer
receive general and administrative reimbursements from KeySpan.

         Strategic Review Expenses. During the first quarter of 2000, the
Company recorded $1.8 million for expenses incurred in the review of strategic
alternatives for the Company. In September 1999, the Company and KeySpan, the
Company's majority stockholder, announced their intention to review strategic
alternatives for the Company and for KeySpan's investment in Houston
Exploration. KeySpan was assessing the role of Houston Exploration within its
future strategic plan, and was considering a full range of strategic
transactions including the possible sale of all or a portion of Houston
Exploration. In February 2000, KeySpan and the Company jointly announced that
the review of strategic alternatives for Houston Exploration had been completed.
KeySpan also announced that it planned to retain its equity position in Houston
Exploration for the foreseeable future.

         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 the Company's 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 common stock of the
Company (see Note 3 -- Stockholders' Equity), interest expense remained
unchanged due to higher interest rates during 2000 as compared to 1999. Interest
rates on the Company's 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 pretax 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.

COMPARISON OF THE YEARS ENDED DECEMBER 31, 1999 AND 1998

         Production. Houston Exploration's production increased 13% from 62,829
MMcfe for the year ended December 31, 1998 to 71,227 MMcfe for the year ended
December 31, 1999. The increase in production was primarily attributable to
production added from the acquisition of producing properties at Mustang Island
A-31/32 in November 1998 and the South Louisiana properties acquired in late
April 1998 offset in part by a production decline at the Company's Charco Field.
The production decline at Charco reflects the Company's decision to curtail
capital spending in South Texas during the fourth quarter of 1998 due to
depressed natural gas prices. Developmental drilling resumed at Charco in the
first quarter of 1999 with two rigs running and during the second quarter the
Company added a third drilling rig to expedite developmental drilling. The third
rig was released during the third quarter of 1999 and drilling resumed with two
rigs. As a result, sixteen new wells were brought on-line in the Charco Field
during the second half of 1999 compared to six new wells in the first half of
the year, causing


                                      -26-
<PAGE>   28


average daily production to increase from 74 MMcfe/day during the first half of
1999 to an average of 85 MMcfe/day during the second half of 1999.

         Natural Gas and Oil Revenues. Natural gas and oil revenues increased
18% from $127.1 million for the year ended December 31, 1998 to $150.6 million
for the year ended December 31, 1999 as a result of the 13% increase in
production and a 4% increase in average realized natural gas prices, from $2.02
per Mcf in 1998 to $2.10 per Mcf in 1999.

         As a result of hedging activities, the Company realized an average gas
price of $2.10 per Mcf, which was 98% of the unhedged natural gas price of $2.14
per Mcf that otherwise would have been received, resulting in a $2.6 million
decrease in natural gas revenues for 1999. During 1998, the average realized gas
price was $2.02 per Mcf, which was 103% of the unhedged average gas price of
$1.96, resulting in an increase to natural gas revenues of $3.8 million for the
year ended December 31, 1998.

         Lease Operating Expenses and Severance Tax. Lease operating expenses
increased 14% from $16.2 million in 1998 to $18.4 million in 1999. On an Mcfe
basis, lease operating expenses remained unchanged at $0.26 for both 1998 and
1999. The increase in lease operating expenses during 1999 is attributable to
the continued expansion of the Company's operations primarily through the 1998
acquisitions of the Mustang Island A-31/32 properties and the South Louisiana
properties. Severance tax, which is a function of volume and revenues generated
from onshore production, increased from $5.0 million in 1998 to $5.4 million in
1999. The increase in 1999 expense is due to the combination of an increase in
onshore production and an increase in price during 1999 as compared to 1998. On
an Mcfe basis, severance tax remained unchanged at $0.08 per Mcfe for both 1998
and 1999.

         Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense decreased 7% from $79.8 million in 1998 to $74.1 in 1999.
Depreciation, depletion and amortization expense per Mcfe decreased 18% from
$1.27 in 1998 to $1.04 in 1999. The decrease in depreciation, depletion and
amortization expense was primarily a result of a lower depletion rate. The lower
depletion rate is primarily a result of the $130 million ($84.5 million net of
tax) writedown in natural gas and oil properties that was taken in the fourth
quarter of 1998 due to weak natural gas prices; combined with an increase in
reserves for the year ended December 31, 1999.

         General and Administrative Expenses. General and administrative
expenses, net of overhead reimbursements received from other working interest
owners of $1.1 million and $5.7 million in 1998 and 1999, respectively,
decreased 31% from $6.1 million in 1998 to $4.2 million in 1999. Included in
reimbursements received from working interest owners during 1999 were
reimbursements totaling $4.8 million received from KeySpan pursuant to the
KeySpan Joint Venture (see Note 6 -- Related Party Transactions). The Company
capitalized general and administrative expenses directly related to oil and gas
exploration and development activities of $7.5 million and $5.5 million,
respectively, in 1998 and 1999. The decrease in capitalized general and
administrative expenses is a result of the KeySpan reimbursements. On an Mcfe
basis, general and administrative expenses decreased 40% from $0.10 in 1998 to
$0.06 in 1999. The lower rate per Mcfe during 1999 reflects a combination of an
increase in production and the effect of the KeySpan Joint Venture
reimbursements offset in part by an increase in aggregate general and
administrative expenses. Aggregate general and administrative expenses increased
in 1999 as a result of an increase in incentive compensation and expenses
incurred during the fourth quarter related to the review of strategic
alternatives for KeySpan's investment in the Company. See Note 6 -- Related
Party Transactions.

         Interest Expense, Net. Interest expense, net of capitalized interest,
increased from $4.6 million during 1998 to $13.3 million during 1999.
Capitalized interest increased from $9.8 million in 1998 to $11.9 million in
1999. The increase in aggregate interest expense was attributable to higher
average debt levels during 1999 as a result of the additional borrowings of $48
million on the revolving bank credit facility in 1999, the implementation of the
KeySpan Facility in November 1998 and the issuance of $100 million of 85/8%
senior subordinated notes in March 1998.


                                      -27-
<PAGE>   29


         Income Tax Provision. The provision for income taxes increased from a
benefit of $40.7 million in 1998 to an expense of $11.7 million for 1999 due to
the increase in pretax income in 1999. The income tax benefit in 1998 was
attributable to the $45.5 million tax effect of the $130 million writedown in
natural gas and oil properties the Company was required to take under full cost
accounting rules as a result of weak natural gas prices. The tax benefit from
the utilization of Section 29 tax credits was approximately $1.0 million for
both 1998 and 1999.

         Operating Income and Net Income. During 1998, both operating income and
net income were adversely affected by weak natural gas prices and the non-cash
charge of $130 million ($84.5 million after tax) taken to write down the
carrying value of natural gas and oil properties. During 1999 natural gas prices
recovered and the combined effect of an increase in natural gas revenues and a
decrease in operating expenses caused operating income for the year ended
December 31, 1999 to increase to $49.7 million in 1999 from an operating loss of
$108.8 million in 1998. Net income increased to $24.6 million in 1999 from a
loss of $72.7 million in 1998.

LIQUIDITY AND CAPITAL RESOURCES

         The Company has historically funded its 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, the Company converted $80 million in
outstanding borrowings under a revolving credit facility established in November
1998 with KeySpan (the "KeySpan Facility") into 5,085,177 shares of common stock
of the Company at a conversion price of $15.732 per share. The KeySpan Facility
was terminated at conversion and as a result of the conversion, KeySpan's
ownership interest in the Company has increased from 64% at December 31, 1999 to
68% as of December 31, 2000.

         Cash Flows From Operations. As of December 31, 2000, the Company had
working capital of $19.7 million and $64.6 million of borrowing capacity
available under its revolving bank credit facility. Net cash provided by
operating activities for the year ended December 31, 2000 was $200.8 million
compared to $110.1 million during the corresponding twelve month period of 1999.
The 82% increase in cash flows from operations during 2000 is primarily related
to the timing of cash receipts and payments. Receivables are higher due to the
increase in natural gas revenues caused by an increase in both natural gas price
and production volume, and payables are higher due to an increase in exploration
and development activity. The Company's cash position decreased during 2000 as a
result of a net pay down of borrowings under its revolving bank credit facility
of $36 million. In addition, cash increased by $13.9 million during 2000 due to
proceeds received from the issuance of common stock as a result of the exercise
of stock options. Funds used in investing activities consisted of $184.5 million
for investments in property and equipment. As a result of these activities, cash
and cash equivalents decreased $5.8 million from $15.5 million at December 31,
1999 to $9.7 million at December 31, 2000.

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

<TABLE>
<CAPTION>
                                                                         YEARS ENDED DECEMBER 31,
                                                                 ----------------------------------------
                                                                   2000            1999            1998
                                                                 ---------       ---------      ---------
                                                                               (IN THOUSANDS)
<S>                                                              <C>             <C>            <C>
         Net cash provided by operating activities ........      $ 200,791       $ 110,072      $ 102,378
         Net long-term (paydowns) borrowings ..............        (36,000)         48,000        200,000
         Proceeds from sale of common stock, net ..........         13,894             439            207
</TABLE>


                                      -28-
<PAGE>   30

         Natural Gas and Oil Capital Expenditures. Over the past three years,
the Company has spent $634 million (including $13.9 million in 2000 for the
purchase of incremental working interests in various offshore producing
properties, $21 million in 1999 for an interest in West Cameron Block 587 and
$162.9 million in 1998 for the acquisition of the Mustang Island A-31 Field and
the South Louisiana properties) to add 444 Bcfe of net proved reserves,
representing a three-year average finding and development cost of $1.43 per
Mcfe.

         The Company's 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,
                                                       ------------------------------------
                                                         2000          1999          1998
                                                       --------      --------      --------
                                                                  (IN THOUSANDS)
<S>                                                    <C>           <C>           <C>
                  OFFSHORE:
                  Acquisitions and leasehold ....      $ 41,164      $ 42,246      $109,209
                  Development ...................        48,836        53,941        15,983
                  Exploration ...................        31,164         8,450        55,381
                                                       --------      --------      --------
                                                        121,164       104,637       180,573
                  ONSHORE:
                  Acquisitions and leasehold ....      $  5,370      $  5,196      $ 86,677
                  Development ...................        54,499        34,024        35,063
                  Exploration ...................         2,996         3,807           230
                                                       --------      --------      --------
                                                         62,865        43,027       121,970
                                                       --------      --------      --------

                  Total .........................      $184,029      $147,664      $302,543
                                                       ========      ========      ========
</TABLE>

         Future Capital Requirements. The Company's capital expenditure budget
for 2001 has been set at $225 million including an estimated $70 million for
exploration, $120 million for development and facility construction and $35
million for leasehold acquisition costs. The Company does not include property
acquisition costs in its capital expenditure budget as the size and timing of
capital requirements for acquisitions are inherently unpredictable. The capital
expenditure budget includes development costs associated with recent discoveries
and newly acquired properties and amounts that are contingent upon drilling
success. No significant abandonment or dismantlement costs are anticipated in
2001. The Company will continue to evaluate its capital spending plans
throughout the year. Actual levels of capital expenditures may vary
significantly due to a variety of factors, including drilling results, natural
gas prices, industry conditions and outlook and future acquisitions of
properties. The Company believes cash flows from operations and borrowings under
its Credit Facility will be sufficient to fund these expenditures. The Company
intends to continue to selectively seek acquisition opportunities for proved
reserves with substantial exploration and development potential both offshore
and onshore although, there can be no assurance that the Company will be able to
identify and make acquisitions of proved reserves on terms it considers
favorable.

         Shelf Registration. On May 20, 1999, the Company 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 the Company's common stock, shares of
preferred stock or unsecured debt securities or a combination thereof. Depending
on market conditions and the Company's capital needs, the Company may utilize
the shelf registration in order to raise capital. The Company would use the net
proceeds received from the sale of any securities for the repayment of debt
and/or to fund an acquisition. There can be no assurance that the Company will
be able to consummate such offering on acceptable terms.


                                      -29-
<PAGE>   31


         Capital Structure

         Revolving Bank Credit Facility. The Company has entered into a
revolving bank credit facility with a syndicate of lenders led by Chase Bank of
Texas, National Association ("Chase"). The Credit Facility, as amended, provides
a maximum commitment of $250 million, subject to borrowing base limitations. At
December 31, 2000, the borrowing base was $210 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, 2000, $145 million was outstanding under the Credit
Facility and $0.4 million was outstanding in letter of credit obligations.
Subsequent to December 31, 2000, the Company has borrowed an additional $3.0
million, bringing total borrowings and letters of credit to $148.4 million as of
February 21, 2001.

         Interest is payable on borrowings under the Credit Facility, at the
Company's option, at (i) a fluctuating rate ("Base Rate") equal to the greater
of the Federal Funds rate plus 0.5% or Chase's prime rate, or (ii) a fixed rate
("Fixed Rate") equal to a quoted LIBOR rate plus a variable margin that
increases from 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:
(i) between 0.25% and 0.375% per annum on the unused portion of the Designated
Borrowing Base, and (ii) an unavailable commitment fee equal to 33% of the
commitment fee in (i) above on the difference between the lesser of the Facility
Amount or the Borrowing Base and the Designated Borrowing Base or the Threshold
Amount. The weighted average interest rate was 7.9%, 6.59% and 6.44%,
respectively, for the years ended December 31, 2000, 1999 and 1998.

         The Credit Facility contains covenants of the Company, including
certain restrictions on liens and financial covenants which require the Company
to, among other things, maintain (i) an interest coverage ratio of 2.5 to 1.0 of
earnings before interest, taxes and depreciation ("EBITDA") to cash interest;
(ii) a total debt to capitalization ratio of less than 60%, exclusive of
non-cash charges; and (iii) sets a maximum limit of 70% on the amount of natural
gas production the Company can hedge during any 12 month period. In addition to
maintenance of certain financial ratios, cash dividends and/or purchase or
redemption of the Company's stock is restricted as well as the encumbering of
the Company's gas and oil assets or the pledging of the assets as collateral. As
of December 31, 1999, the Company was in compliance with all such covenants.

         Pursuant to the Credit Facility, the Company may declare and pay cash
dividends to its stockholders provided that (i) no defaults exist and the
Company will not be in default with respect to any financial covenants as a
result of such dividend payment and (ii) the Company continues to have a ratio
of consolidated total debt to consolidated total capitalization of less than
60%, exclusive of non-cash charges. Accordingly, the Company's ability to pay
dividends will depend upon such restrictions and the Company's results of
operations, financial condition, capital requirements and other factors deemed
relevant by the Board of Directors. See "Item 5. Market for the Registrant's
Common Equity and Related Stockholder Matters -- Dividends."

         Senior Subordinated Notes. On March 2, 1998, the Company issued $100
million of 8 5/8% Senior Subordinated Notes (the "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. The Notes are redeemable at the option of
the Company, 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. Notwithstanding the foregoing, at any time prior to January 1, 2001, the
Company may redeem up to 35% of the original aggregate principal amount of the
Notes with the net proceeds of any equity offering, provided that at least 65%
of the original aggregate principal amount of the Notes remains outstanding
immediately after the occurrence of such redemption. Upon the occurrence of a
change of control (as defined in the indenture governing the Notes), the Company
will be required to offer to purchase the Notes at a purchase price equal to
101% of the aggregate principal amount thereof, plus accrued and unpaid
interest, if any. The Notes are general unsecured obligations of the Company 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.


                                      -30-
<PAGE>   32


ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

         Natural Gas Hedging. The Company utilizes derivative commodity
instruments to hedge future sales prices on a portion of its natural gas
production to achieve a more predictable cash flow, as well as to reduce its
exposure to adverse price fluctuations of natural gas. While the use of these
hedging arrangements limits the downside risk of adverse price movements, they
would limit future revenues from possible favorable price movements. The use of
hedging transactions also involves the risk that the counterparties will be
unable to meet the financial terms of such transactions. Hedging instruments
used are swaps, collars and options, and are generally placed with major
financial institutions that the Company believes are minimal credit risks. The
Company accounts for these transactions as hedging activities and, accordingly,
gains or losses are included in natural gas and oil revenues in the period the
hedged production occurs.

         As of January 1, 2001, the Company had entered into commodity price
hedging contracts with respect to approximately 70% of its estimated 2001
natural gas production, as listed below. Natural gas production during the month
of January 2001 was 7,799 MMcf (8,052 MMMbtu) or 252 MMcf/day (260 MMMBtu/day).

<TABLE>
<CAPTION>
                                                              COLLARS
                                                -------------------------------------------
                                                                        NYMEX
                                                 VOLUME             CONTRACT PRICE
                         PERIOD                 (MMMbtu)    AVERAGE FLOOR   AVERAGE CEILING
                  ---------------------         --------    -------------   ---------------
<S>                                             <C>         <C>             <C>
                  January 2001 ........           4,960      $    3.625      $    5.301
                  February 2001 .......           4,480           3.625           5.301
                  March 2001 ..........           4,960           3.625           5.301
                  April 2001 ..........           4,800           4.000           6.110
                  May 2001 ............           4,960           4.000           6.110
                  June 2001 ...........           4,800           4.000           6.110
                  July 2001 ...........           4,960           4.000           6.110
                  August 2001 .........           4,960           4.000           6.110
                  September 2001 ......           4,800           4.000           6.110
                  October 2001 ........           4,960           4.000           6.110
                  November 2001 .......           4,800           4.000           6.371
                  December 2001 .......           4,960           4.000           6.371
</TABLE>

         These hedging transactions are settled based upon the average of the
reported settlement prices on the New York Mercantile Exchange (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").

         For the months January 2001 through March 2001 the Company has 60,000
MMbtu/day hedged under no-cost collars with floating floors. The floating floor
structure allows for a higher floor price in exchange for a lower ceiling. For
example, during January 2001, if the settlement price is up to $2.50 the Company
will receive the settlement price plus $0.50. If the settlement price is between
$2.50 and $3.00 the Company will receive $3.00. If the settlement price is
between $3.00 and $3.63, the Company will receive the settlement price and if
market price is above $3.63, the Company will receive $3.63 (the ceiling).

         The Company adopted SFAS No. 133 "Accounting for Derivative Instruments
and Hedging Activities" effective 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 fair market value of the derivative. At January 1,
2001, the Company recorded a liability of $75 million to reflect the then
negative fair market value of its hedge position in place, covering the months
January 2001 through December 2001. Because the Company's hedges qualify for
hedge accounting and, pursuant to certain transition rules, under SFAS 133, an
offsetting entry has been made to accumulated other comprehensive income. The
Company estimates, using NYMEX prices as of February 21, 2001, that it will
incur a


                                      -31-
<PAGE>   33


loss of approximately $31 million during the first three months of 2001 relating
to hedges in place at December 31, 2000. The fair market value of its hedge
position for the remainder of 2001 (April through December) is estimated, using
February 21, 2001 prices, to be a liability of $10 million. The increase in fair
market value of the Company's costless collars is due to the significant decline
in NYMEX prices since December 31, 2000.

         With respect to any particular swap transaction, the counterparty is
required to make a payment to the Company in the event that the settlement price
for any settlement period is less than the swap price for such transaction, and
the Company is 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 such transaction. For any particular collar transaction, the counterparty is
required to make a payment to the Company if the settlement price for any
settlement period is below the floor price for such transaction, and the Company
is required to make payment to the counterparty if the settlement price for any
settlement period is above the ceiling price for such transaction. The Company
is 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, the Company has 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 certain bonding requirements related to offshore
production proposed by the Minerals Management Service, see "Items 1 and 2.
Business and Properties -- Environmental Matters."

ITEM 8.  FINANCIAL STATEMENTS

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

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

         None.


                                      -32-
<PAGE>   34


PART III.

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

         The information required by this Item as to the directors and executive
officers of the Company is hereby incorporated by reference from the information
appearing under the captions "Election of Directors" and "Executive Officers" in
the Company's definitive proxy statement which involves the election of
directors and is to be filed with the Securities and Exchange Commission
("Commission") pursuant to the Securities Exchange Act of 1934 within 120 days
of the end of the Company's fiscal year on December 31, 2000.

ITEM 11.  EXECUTIVE COMPENSATION

         The information required by this Item as to the management of the
Company is hereby incorporated by reference from the information appearing under
the captions "Executive Compensation" and "Election of Directors - Director's
Meetings and Compensation" in the Company's definitive proxy statement which
involves the election of directors and is to be filed with the Commission
pursuant to the Securities Exchange Act of 1934 within 120 days of the end of
the Company's fiscal year on December 31, 2000. Notwithstanding the foregoing,
in accordance with the instructions to Item 402 of Regulation S-K, the
information contained in the Company's proxy statement under the 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 CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

         The information required by this Item as to the ownership by management
and others of securities of the Company is hereby incorporated by reference from
the information appearing under the caption "Security Ownership of Certain
Beneficial Owners and Management" to the Company's definitive proxy statement
which involves the election of directors and is to be filed with the Commission
pursuant to the Securities Exchange Act of 1934 within 120 days of the end of
the Company's fiscal year on December 31, 2000.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

         The information required by this Item as to certain business
relationships and transactions with management and other related parties of the
Company is hereby incorporated by reference to such information appearing under
the captions "Certain Transactions" and "Executive Compensation -- Compensation
Committee Interlocks and Insider Participation" in the Company's definitive
proxy statement which involves the election of directors and is to be filed with
the Commission pursuant to the Securities Exchange Act of 1934 within 120 days
of the end of the Company's fiscal year on December 31, 2000.


                                      -33-
<PAGE>   35

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, 2000 and 1999.........................  F-3
   Consolidated Statements of Operations for the Years Ended
     December 31, 2000, 1999 and 1998 ..................................................  F-4
   Consolidated Statement of Stockholders' Equity for the Period from
     December 31, 2000 to December 31, 1998 ............................................  F-5
   Consolidated Statements of Cash Flows for the Years Ended
     December 31, 2000, 1999 and 1998 ..................................................  F-6
   Notes to Consolidated Financial Statements ..........................................  F-7
   Supplemental Information on Natural Gas and Oil Exploration, Development and
     Production Activities .............................................................  F-22
   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 notes thereto.

2.       EXHIBITS:

         See Index of Exhibits on page F-27 for a description of the exhibits
filed as a part of this report.


                                      -34-
<PAGE>   36


                                   SIGNATURES

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

                                     THE HOUSTON EXPLORATION COMPANY

                                     By:  /s/ James G. Floyd
                                        -------------------------------------
                                        James G. Floyd
Date: February 21, 2001                 President and Chief Executive Officer

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

<TABLE>
<CAPTION>

              Signature                                    Title                                Date
              ---------                                    -----                                ----
<S>                                    <C>                                                <C>
/s/ James G. Floyd                     President, Chief Executive Officer and             February 21, 2001
-----------------------------------    Director (Principal Executive Officer)
    James G. Floyd


/s/ James F. Westmoreland              Vice President, Chief Accounting Officer,          February 21, 2001
-----------------------------------    Comptroller and Secretary (Principal
    James F. Westmoreland              Financial Officer and Principal Accounting
                                       Officer)


/s/ Robert B. Catell                   Chairman of the Board of Directors                 February 21, 2001
-----------------------------------
    Robert B. Catell


/s/ Gordon F. Ahalt                    Director                                           February 21, 2001
-----------------------------------
    Gordon F. Ahalt


/s/ David G. Elkins                    Director                                           February 21, 2001
-----------------------------------
    David G. Elkins


/s/ Russell D. Gordy                   Director                                           February 21, 2001
-----------------------------------
    Russell D. Gordy


/s/ Gerald Luterman                    Director                                           February 21, 2001
-----------------------------------
    Gerald Luterman


/s/ Craig G. Matthews                  Director                                           February 21, 2001
-----------------------------------
    Craig G. Matthews


/s/ H. Neil Nichols                    Director                                           February 21, 2001
-----------------------------------
    H. Neil Nichols


/s/ James Q. Riordan                   Director                                           February 21, 2001
-----------------------------------
    James Q. Riordan


/s/ Donald C. Vaughn                   Director                                           February 21, 2001
-----------------------------------
    Donald C. Vaughn
</TABLE>

<PAGE>   37


                          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 herein
are stated at the legal pressure base of the state or area where the reserves
exist and at 60 degrees Fahrenheit and in most instances are rounded to the
nearest major multiple.

         Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used 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 such
production exceed production expenses and taxes.

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

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

         Field. An area consisting of a single reservoir or multiple reservoirs
all grouped on or related to the same individual geological structural feature
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>   38


         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 such
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.

         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.


                                      G-2
<PAGE>   39



         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 such acreage contains
proved reserves.

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

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



                                       G-3
<PAGE>   40


                          INDEX TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                                                                     Page
                                                                                                     ----
<S>                                                                                                  <C>
Report of Independent Public Accountants ......................................................      F-2
Consolidated Balance Sheets as of December 31, 2000 and 1999 ..................................      F-3
Consolidated Statements of Operations for the Years Ended December 31, 2000, 1999 and 1998 ....      F-4
Consolidated Statement of Stockholders' Equity for the Years Ended
  December 31, 2000, 1999 and 1998 ............................................................      F-5
Consolidated Statements of Cash Flows for the Years Ended  December 31, 2000, 1999 and 1998 ...      F-6
Notes to Consolidated Financial Statements ....................................................      F-7
</TABLE>

                                      F-1

<PAGE>   41


                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

         We have audited the accompanying consolidated balance sheets of The
Houston Exploration Company (a Delaware corporation and an indirect 68%-owned
subsidiary of KeySpan Corporation) as of December 31, 2000 and 1999, and the
related consolidated statements of operations, stockholders' equity and cash
flows for each of the three years in the period ended December 31, 2000. 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, as of December 31, 2000 and 1999, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.

                                           ARTHUR ANDERSEN LLP

New York, New York
January 22, 2001

                                       F-2

<PAGE>   42


                         THE HOUSTON EXPLORATION COMPANY
                           CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
                                                                                                    DECEMBER 31,
                                                                                           -----------------------------
                                                                                              2000               1999
                                                                                           -----------       -----------
                                                                                                   (IN THOUSANDS)
<S>                                                                                        <C>               <C>
ASSETS:
Cash and cash equivalents ...........................................................      $     9,675       $    15,502
Accounts receivable .................................................................          100,966            34,917
Accounts receivable -- Affiliate ....................................................           13,635            12,315
Inventories .........................................................................            1,923               969
Prepayments and other ...............................................................            1,913             1,082
                                                                                           -----------       -----------
          Total current assets ......................................................          128,112            64,785
Natural gas and oil properties, full cost method
  Unevaluated properties ............................................................          142,890           164,377
  Properties subject to amortization ................................................        1,162,000           956,484
Other property and equipment ........................................................            9,852             9,744
                                                                                           -----------       -----------
                                                                                             1,314,742         1,130,605
Less: Accumulated depreciation, depletion and amortization ..........................         (609,352)         (520,489)
                                                                                           -----------       -----------
                                                                                               705,390           610,116
Other assets ........................................................................            3,882             3,582
                                                                                           -----------       -----------
          TOTAL ASSETS ..............................................................      $   837,384       $   678,483
                                                                                           ===========       ===========
LIABILITIES:
Accounts payable and accrued expenses ...............................................      $   108,366       $    56,004
Subordinated note -- Affiliate ......................................................               --            80,000
                                                                                           -----------       -----------
          Total current liabilities .................................................          108,366           136,004
Long-term debt and notes ............................................................          245,000           281,000
Deferred federal income taxes .......................................................           87,040            43,736
Other deferred liabilities ..........................................................              236               153
                                                                                           -----------       -----------
          TOTAL LIABILITIES .........................................................          440,642           460,893
COMMITMENTS AND CONTINGENCIES (SEE NOTE 10)
STOCKHOLDERS' EQUITY:
Common Stock, $.01 par value, 50,000,000 shares authorized and 29,829,050 shares
  issued and outstanding at December 31, 2000 and 23,923,020 shares issued and
  outstanding at December 31,1999 ...................................................              298               239
Additional paid-in capital ..........................................................          325,205           231,370
Retained earnings (deficit) .........................................................           71,239           (14,019)
                                                                                           -----------       -----------
          TOTAL STOCKHOLDERS' EQUITY ................................................          396,742           217,590
                                                                                           -----------       -----------
          TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ................................      $   837,384       $   678,483
                                                                                           ===========       ===========
</TABLE>

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

                                       F-3


<PAGE>   43


                         THE HOUSTON EXPLORATION COMPANY
                      CONSOLIDATED STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>

                                                                                     YEARS ENDED DECEMBER 31,
                                                                            ---------------------------------------
                                                                               2000           1999          1998
                                                                            ---------      ---------      ---------
                                                                             (IN THOUSANDS, EXCEPT PER SHARE DATA)
<S>                                                                         <C>            <C>            <C>
REVENUES:
     Natural gas and oil revenues ....................................      $ 270,595      $ 150,580      $ 127,124
     Other ...........................................................          1,738          1,147          1,123
                                                                            ---------      ---------      ---------
             Total revenues ..........................................        272,333        151,727        128,247
OPERATING COSTS AND EXPENSES:
     Lease operating .................................................         23,553         18,406         16,199
     Severance tax ...................................................          9,757          5,444          4,967
     Depreciation, depletion and amortization ........................         89,239         74,051         79,838
     Writedown in carrying value of natural gas and oil properties ...             --             --        130,000
     General and administrative, net .................................          8,928          4,150          6,086
                                                                            ---------      ---------      ---------
             Total operating expenses ................................        131,477        102,051        237,090

Income(loss) from operations .........................................        140,856         49,676       (108,843)

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

Interest expense, net ................................................         11,361         13,307          4,597
                                                                            ---------      ---------      ---------
Income(loss) before income taxes .....................................        127,743         36,369       (113,440)
   Provision(benefit) for federal income taxes .......................         42,485         11,748        (40,754)
                                                                            ---------      ---------      ---------
NET INCOME(LOSS) .....................................................      $  85,258      $  24,621      $ (72,686)
                                                                            =========      =========      =========

Net income(loss) per share ...........................................      $    3.06      $    1.03      $   (3.05)
                                                                            =========      =========      =========
Net income(loss) per share -- assuming dilution ......................      $    3.02      $    0.95      $   (3.05)
                                                                            =========      =========      =========

Weighted average shares outstanding ..................................         27,860         23,906         23,768
Weighted average shares outstanding -- assuming dilution .............         28,213         28,310         23,768
</TABLE>


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

                                       F-4

<PAGE>   44



                         THE HOUSTON EXPLORATION COMPANY
                 CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY


<TABLE>
<CAPTION>
                                                       ADDITIONAL      RETAINED       TOTAL
                                          COMMON        PAID IN        EARNINGS    STOCKHOLDERS'
                                          STOCK         CAPITAL       (DEFICIT)       EQUITY
                                         ---------     ----------     ---------    -------------
                                                               (IN THOUSANDS)
<S>                                      <C>            <C>            <C>            <C>
Balance January 1, 1998 ...........      $     234      $ 221,907      $  34,046      $ 256,187
Common stock(1)(2) ................              5          9,024             --          9,029
Net loss ..........................             --             --        (72,686)       (72,686)
                                         ---------      ---------      ---------      ---------
Balance January 1, 1999 ...........      $     239      $ 230,931      $ (38,640)     $ 192,530
Common stock(1) ...................             --            439             --            439
Net income ........................             --             --         24,621         24,621
                                         ---------      ---------      ---------      ---------
Balance at January 1, 2000 ........      $     239      $ 231,370      $ (14,019)     $ 217,590
Common stock(1)(3) ................             59         93,835             --         93,894
Net income ........................             --             --         85,258         85,258
                                         ---------      ---------      ---------      ---------
Balance at December 31, 2000 ......      $     298      $ 325,205      $  71,239      $ 396,742
                                         =========      =========      =========      =========
</TABLE>

----------

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

(2)      Includes 520,777 shares issued in March 1998 to Smith Offshore
         Exploration Company ("Soxco") in connection with the Company's
         acquisition of the natural gas and oil assets of Soxco. See Note 3 --
         Stockholders' Equity.

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


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


                                       F-5
<PAGE>   45



                         THE HOUSTON EXPLORATION COMPANY
                      CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
                                                                                     YEARS ENDED DECEMBER 31,
                                                                            -----------------------------------------
                                                                              2000             1999           1998
                                                                            ---------       ---------       ---------
                                                                                         (IN THOUSANDS)
<S>                                                                         <C>             <C>             <C>
OPERATING ACTIVITIES:

Net income(loss) .....................................................      $  85,258       $  24,621       $ (72,686)
Adjustments to reconcile net income to net cash provided by
  operating activities:
  Depreciation, depletion and amortization ...........................         89,239          74,051          79,838
  Writedown in carrying value of natural gas and oil properties ......             --              --         130,000
  Deferred income tax expense(benefit) ...............................         43,303          12,709         (39,714)
  Changes in operating assets and liabilities:
   (Increase) decrease in accounts receivable ........................        (67,369)        (24,045)         16,014
   (Increase) decrease in inventories ................................           (954)            (54)            350
   Decrease in prepayments and other .................................           (831)           (328)           (109)
   (Increase) in other assets and other deferred liabilities .........           (217)           (143)         (1,626)
   Increase (decrease) in accounts payable and accrued expenses ......         52,362          23,261          (9,689)
                                                                            ---------       ---------       ---------
Net cash provided by operating activities ............................        200,791         110,072         102,378

INVESTING ACTIVITIES:
Investment in property and equipment .................................       (184,512)       (147,943)       (302,685)
Dispositions and other ...............................................             --             289              --
                                                                            ---------       ---------       ---------
Net cash used in investing activities ................................       (184,512)       (147,654)       (302,685)

FINANCING ACTIVITIES:
Proceeds from long-term borrowings ...................................         32,000          64,000         312,000
Repayments of long-term borrowings ...................................        (68,000)        (16,000)       (112,000)
Proceeds from issuance of common stock ...............................         13,894             439             207
                                                                            ---------       ---------       ---------
Net cash (used in) provided by financing activities ..................        (22,106)         48,439         200,207

(Decrease) increase in cash and cash equivalents .....................         (5,827)         10,857            (100)

Cash and cash equivalents, beginning of year .........................         15,502           4,645           4,745
                                                                            ---------       ---------       ---------

Cash and cash equivalents, end of year ...............................      $   9,675       $  15,502       $   4,645
                                                                            =========       =========       =========

Cash paid for interest ...............................................      $  25,490       $  23,970       $   9,452
                                                                            =========       =========       =========

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



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

                                       F-6

<PAGE>   46


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


NOTE 1 -- SUMMARY OF ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES

         Organization

         Houston Exploration is an independent natural gas and oil company
engaged in the exploration, development, exploitation and acquisition of
domestic natural gas and oil properties. The Company's operations are currently
focused offshore in the Gulf of Mexico and onshore in South Texas, South
Louisiana, the Arkoma Basin, East Texas and West Virginia. Houston Exploration's
strategy is to utilize its geological and geophysical expertise to grow its
reserve base through a combination of: (i) exploratory drilling in the Gulf of
Mexico; (ii) lower risk, high impact exploitation and development drilling
onshore; and (iii) selective opportunistic acquisitions both offshore and
onshore. At December 31, 2000, the Company had net proved reserves of 562 Bcfe,
94% of which were natural gas and 77% of which were classified as proved
developed.

         Houston Exploration began exploring for natural gas and oil in December
1985 on behalf of The Brooklyn Union Gas Company ("Brooklyn Union") and in
September 1996 the Company completed an initial public offering ("IPO") of its
common stock. Brooklyn Union became an indirect wholly-owned subsidiary of
KeySpan Corporation ("KeySpan") in May 1998 through the combination of Brooklyn
Union's parent company KeySpan Energy Corporation and Long Island Lighting
Company. As of December 31, 2000, THEC Holdings Corp., an indirect wholly owned
subsidiary of KeySpan, owned approximately 68% of the outstanding shares of
Houston Exploration's common stock. KeySpan, a member of the Standard & Poor's
500 Index, is a diversified energy provider that (i) distributes natural gas to
2.4 million customers in the Brooklyn, Long Island, Queens and Staten Island
areas of New York and to customers in eastern and central Massachusetts and
central New Hampshire; (ii) generates and manages electricity transmission and
distribution through the ownership and operation of generating plants throughout
New York State and through its contract with the Long Island Power Authority to
manage electricity service to 1.1 million customers in the Long Island area; and
(iii) through its other subsidiaries is involved in various energy services and
energy related investments including wholesale and retail gas and electric
marketing; appliance service and installation; large energy-system installation
and management; fiber optic telecommunications and energy-related internet
activities.

         Principles of Consolidation

         The consolidated financial statements include the accounts of The
Houston Exploration Company and its wholly-owned subsidiary, Seneca Upshur
Petroleum Company (collectively the "Company"). All significant intercompany
balances and transactions have been eliminated.

         Reclassifications and 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. The Company's most significant financial estimates
are based on remaining proved natural gas and oil reserves. See Note 13 --
Supplemental Information on Natural Gas and Oil Exploration, Development and
Production Activities. Because there are numerous uncertainties inherent in the
estimation process, actual results could differ from the estimates. Certain
reclassifications of prior years have been made to conform with current year
presentation.


                                       F-7



<PAGE>   47

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


         Net Income Per Share

         Basic earnings per share ("EPS") 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
EPS 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 ("SFAS") No. 128, the Company's EPS are as follows:

<TABLE>
<CAPTION>
                                                                             YEARS ENDED DECEMBER 31,
                                                                      -------------------------------------
                                                                           2000          1999          1998
                                                                      ------------- ------------- ---------
                                                                      (IN THOUSANDS, EXCEPT PER SHARE DATA)

<S>                                                                   <C>           <C>           <C>
   Net income (loss)................................................  $     85,258  $     24,621  $   (72,686)
     Interest savings on convertible debt...........................            --         2,398           --
                                                                      ------------  ------------  -----------
   Net income (loss), as adjusted...................................  $     85,258  $     27,019  $   (72,686)
                                                                      ============  ============   ===========

   Weighted average shares outstanding..............................        27,860        23,906       23,768
   Add dilutive securities:
     Options........................................................           353           206           --
     Convertible debt...............................................            --         4,198           --
                                                                      ------------  ------------  -----------
   Total weighted average shares outstanding and dilutive securities        28,213        28,310       23,768
                                                                      ============  ============  ===========

   Net income (loss) per share......................................  $      3.06   $      1.03   $    (3.05)
   Net income (loss) per share -- assuming dilution.................  $      3.02   $      0.95   $    (3.05)
</TABLE>


         The computation of diluted EPS for the year ended December 31, 1998 did
not assume the conversion of the outstanding options or any other potentially
convertible securities as their inclusion would have been antidilutive.

         Natural Gas and Oil Properties

         Natural gas and oil properties are accounted for using the full cost
method of accounting. Under this method of accounting, all costs identified with
acquisition, exploration and development of natural gas and oil properties,
including leasehold acquisition costs, geological and geophysical costs, dry
hole costs, tangible and intangible drilling costs, interest and the general and
administrative overhead directly associated with these activities are
capitalized as incurred. The Company computes the provision for depreciation,
depletion and amortization of natural gas and oil properties on a quarterly
basis using the unit-of-production method. The quarterly provision is calculated
by multiplying the natural gas and oil production each quarter by a depletion
rate determined by dividing the total unamortized cost of natural gas and oil
properties (including estimates of the costs of future development and property
abandonment and excluding the cost of significant investments in unproved and
unevaluated properties) by net equivalent proved reserves at the beginning of
the quarter. Natural gas and oil reserve quantities represent estimates only.
Actual future production may be materially different from estimated reserve
quantities and such differences could materially affect future amortization of
natural gas and oil properties. The Company believes that unevaluated properties
at December 31, 2000 will be fully evaluated within five years.


                                       F-8
<PAGE>   48


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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

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

         At December 31, 2000, the Company estimated, using a wellhead price of
$9.55 per Mcf, that a $1.4 billion (after tax) full cost ceiling "cushion"
existed whereby the carrying value of the full cost pool was less than the
ceiling limitation imposed under full cost accounting. At December 31, 1999, the
Company estimated, using a wellhead price of $2.01 per Mcf, that a $99.2 million
(after tax) full cost ceiling "cushion" existed whereby the carrying value of
the full cost pool was less than the ceiling limitation imposed under full cost
accounting.

         As of December 31, 1998, the Company estimated, using a December 1998
wellhead price of $1.83 per Mcf, that actual capitalized costs of natural gas
and oil properties exceeded the ceiling limitation imposed under full cost
accounting rules by approximately $41.2 million, after taxes. Subsequent to
December 31, 1998, natural gas prices continued to decline, such that the
Company estimated, using a February wellhead price of $1.61 per Mcf, that the
ceiling limitation exceeded actual capitalized costs of natural gas and oil
properties by approximately $84.5 million, after taxes. As a result, the Company
reduced the carrying value of its natural gas and oil properties as of December
31, 1998, by $84.5 million, after taxes.

         Other Property and Equipment

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

         Income Taxes

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

         Inventories

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

                                       F-9

<PAGE>   49

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


         General and Administrative Costs and Expenses

         The Company receives reimbursement for administrative and overhead
expenses incurred on behalf of other working interest owners on properties
operated by the Company. These reimbursements totaling $3.6 million, $5.7
million and $1.1 million for the years ended December 31, 2000, 1999 and 1998,
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 KeySpan
joint exploration agreement ("KeySpan Joint Venture"), see Note 6 -- Related
Party Transactions of $2.5 million and $4.8 million, respectively. The
capitalized general and administrative costs directly related to the Company's
acquisition, exploration and development activities, during 2000, 1999 and 1998,
aggregated $9.6 million, $5.5 million and $7.5 million, respectively.

         Capitalization of Interest

         The Company capitalizes interest related to its unevaluated natural gas
and oil properties and certain properties under development which are not
currently being amortized. For the years ended December 31, 2000, 1999 and 1998
interest costs of $13.7 million, $11.9 million and $9.8 million, respectively,
were capitalized.

         Revenue Recognition and Gas Imbalances

         The Company uses the entitlements method of accounting for the
recognition of natural gas and oil revenues. Under this method of accounting,
income is recorded based on the Company's net revenue interest in production or
nominated deliveries. The Company incurs certain 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. Production imbalances are valued using current market
prices. Production imbalances were not material as of December 31, 2000 and
1999. Also included as a component of natural gas and oil revenues are the gains
and losses recognized pursuant to natural gas hedging instruments.

         Financial Instruments

         The estimated fair value of financial instruments is the amount at
which the instrument could be exchanged currently between willing parties. Fair
value information is included in the notes to consolidated financial statements
when the fair value of the financial instruments is different from the carrying
or book value and available market information is used to estimated fair values.
In the consolidated balance sheet, the Company reports cash and cash
equivalents, accounts receivable and accounts payable at cost, which
approximates fair value due to the short maturity of these instruments.

         Hedging Contracts

         The Company utilizes derivative commodity instruments to hedge future
sales prices on a portion of its natural gas production in order to achieve a
more predictable cash flow and to reduce its exposure to adverse price
fluctuations. While the use of hedging arrangements limits the downside risk of
adverse price movements, it would also limit future revenues from possible
favorable price movements. These instruments include swaps, costless collars and
options, and are usually placed with major financial institutions that the
Company believes are minimal credit risks. The Company's hedging strategies meet
the criteria for hedge accounting treatment under Statement of Financial
Accounting Standards No. 80, "Accounting for Futures Contracts". Accordingly,
gains and losses are recognized when the underlying transaction is completed, at
which time these gains and losses are included in earnings as a component of
natural gas revenues in accordance with the underlying hedged transaction. If
hedging

                                      F-10

<PAGE>   50


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


instruments cease to meet the criteria for deferred recognition, any gains or
losses would be currently recognized in revenue. If these instruments are
terminated prior to maturity, resulting gains and losses continue to be deferred
until the hedged natural gas production is recognized in revenue. Neither the
hedging contracts nor the unrealized gains or losses on these contracts are
currently recognized in the financial statements; however, as of January 1,
2001, the Company has adopted the new accounting guidelines prescribed under
Statement of Financial Accounting Standards 133, "Accounting for Derivatives and
Hedging Activities". (See New Accounting Pronouncements, below).

         Concentration of Credit Risk

         Substantially all of the Company's accounts receivable result from
natural gas and oil sales or joint interest billings to third parties in the oil
and gas industry. This concentration of customers and joint interest owners may
impact the Company's overall credit risk in that these entities may be similarly
affected by changes in economic and other conditions. Historically, the Company
has not experienced credit losses on such receivables. The Company is exposed to
credit risk in the event of nonperformance by counterparties to futures and
swaps contracts. The Company believes that the credit risk related to the
futures and swap contracts is no greater than that associated with the primary
contracts which they hedge, as these contracts are with major investment grade
financial institutions, and that elimination of the price risk lowers the
Company's overall business risk.

         New Accounting Pronouncements

         In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative
Instruments and Hedging Activities." 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. The Company
adopted SFAS No. 133 effective January 1, 2001 and recorded a transition
adjustment of $75 million to reflect the then negative fair market value of its
hedge position at December 31, 2000, which covers the months January 2001
through December 2001. Because the Company's hedges qualify for hedge
accounting, and pursuant to certain transition rules, under SFAS 133, an
offsetting entry has been made to accumulated other comprehensive income.

NOTE 2 -- LONG-TERM DEBT AND NOTES

<TABLE>
<CAPTION>
                                                  YEARS ENDED DECEMBER 31,
                                                     2000         1999
                                                   --------      --------
                                                      (IN THOUSANDS)
<S>                                                <C>           <C>
SENIOR DEBT:
Bank revolving credit facility ..............      $145,000      $181,000
SUBORDINATED DEBT:
8 5/8% Senior Subordinated Notes due 2008 ...       100,000       100,000
                                                   --------      --------
    Total long-term debt and notes ..........      $245,000      $281,000
                                                   ========      ========
</TABLE>

         The carrying amount of borrowings outstanding under the revolving bank
credit facility approximate fair market value as interest rates are tied to
current market rates. At December 31, 2000, the quoted market value of the 85/8%
senior subordinated notes was 98% of the $100 million carrying value or $98
million.

                                      F-11
<PAGE>   51


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

         Credit Facility

         The Company has entered into a revolving bank credit facility (the
"Credit Facility") with a syndicate of lenders led by Chase Bank of Texas,
National Association ("Chase"). The Credit Facility, as amended, provides a
maximum commitment of $250 million, subject to borrowing base limitations. At
December 31, 2000, the borrowing base amount was $210 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, 2000, $145 million was outstanding under the
Credit Facility and $0.4 million was outstanding in letter of credit
obligations. Subsequent to year end December 31, 2000, the Company borrowed an
additional $3.0 million, bringing outstanding borrowings and letter of credit
obligations to $148.4 million as of February 21, 2001.

         Interest is payable on borrowings under the Credit Facility, at the
Company's option, at (i) a fluctuating rate ("Base Rate") equal to the greater
of the Federal Funds rate plus 0.5% or Chase's prime rate, or (ii) a fixed rate
("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: (i) between 0.25%
and 0.375% per annum on the unused portion of the Designated Borrowing Base, and
(ii) an unavailable commitment fee equal to 33% of the commitment fee in (i)
above on the difference between the lesser of the Facility Amount or the
Borrowing Base and the Designated Borrowing Base. The weighted average interest
rate was 7.9%. 6.59% and 6.44%, respectively, for the years ended December 31,
2000, 1999 and 1998.

         The Credit Facility contains covenants of the Company, including
certain restrictions on liens and financial covenants which require the Company
to, among other things, maintain (i) an interest coverage ratio of 2.5 to 1.0 of
earnings before interest, taxes and depreciation ("EBITDA") to cash interest;
(ii) a total debt to capitalization ratio of less than 60%, exclusive of
non-cash charges; and (iii) sets a maximum limit of 70% on the amount of natural
gas production the Company may hedge during any 12 month period. In addition to
maintenance of certain financial ratios, cash dividends and/or purchase or
redemption of the Company's stock is restricted as well as the encumbering of
the Company's gas and oil assets or the pledging of the assets as collateral. As
of December 31, 2000, the Company was in compliance with all such covenants.

         Senior Subordinated Notes

         On March 2, 1998, the Company issued $100 million of 8 5/8% senior
subordinated notes (the "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. The Notes are redeemable at the option of the Company, 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. Notwithstanding the
foregoing, at any time prior to January 1, 2001, the Company may redeem up to
35% of the original aggregate principal amount of the Notes with the net
proceeds of any equity offering, provided that at least 65% of the original
aggregate principal amount of the Notes remains outstanding immediately after
the occurrence of such redemption. Upon the occurrence of a change of control
(as defined), the Company will be required to offer to purchase the Notes at a
purchase price equal to 101% of the aggregate principal amount thereof, plus
accrued and unpaid interest, if any. The Notes are general unsecured obligations
of the Company and rank subordinate in right of payment to all existing and
future senior debt, including the Credit Facility, and will rank senior or equal
in right of payment to all existing and future subordinated indebtedness.

                                      F-12

<PAGE>   52


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


NOTE 3 -- STOCKHOLDERS' EQUITY

         KeySpan Credit Facility and Conversion.

         On November 30, 1998, the Company entered into a revolving credit
facility with KeySpan (the "KeySpan Facility"), which provided a maximum
commitment of $150 million. The Company borrowed $80 million under the KeySpan
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 the Company's common stock at a
conversion price of $15.732 per share. As a result of the conversion, KeySpan's
ownership interest in the Company has increased from 64% at December 31, 1999 to
68% at December 31, 2000. The conversion price was determined based upon the
average of the closing prices of the Company's 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 was
approved by the Company's stockholders at the Company's 1999 annual meeting held
April 27, 1999. Borrowings under the facility bore interest at LIBOR plus 1.4%
and the Company incurred a quarterly commitment fee of 0.125% on the unused
portion of the maximum commitment. The KeySpan Facility terminated on March 31,
2000. For the years ended December 31, 2000 and 1999, the Company incurred $1.5
million and $5.5 million, respectively, in interest and fees to KeySpan.

         Soxco Deferred Purchase Price.

         Concurrent with the completion of the IPO in September 1996, the
Company acquired substantially all of the natural gas and oil properties and
related assets (the "Soxco Acquisition") of Smith Offshore Exploration Company
("Soxco"). The natural gas and oil properties acquired in the Soxco Acquisition
consisted solely of working interests in properties located in the Gulf of
Mexico that are operated by the Company or in which the Company also has a
working interest. Pursuant to the Soxco Acquisition, the Company agreed to pay
Soxco, in shares of the Company's common stock, a deferred purchase price of up
to $17.6 million effective January 31, 1998. The amount of the deferred purchase
price was determined by the probable reserves of Soxco as of December 31, 1995
(approximately 17.6 Bcfe) that were produced prior to or classified as proved as
of December 31, 1996 and December 31, 1997, respectively, provided that Soxco
was entitled to receive a minimum deferred purchase price of approximately $8.8
million. On March 27, 1998, the Company issued 520,777 shares of common stock
with an aggregate value (determined by reference to the average price of the
Company's common stock over a specified period of 20 trading days) of $8.8
million to Soxco in payment of the deferred purchase price.

NOTE 4 -- STOCK OPTION PLANS

         1996 Stock Option Plan

         At the completion of the IPO in September 1996, the Company adopted the
1996 Stock Option Plan, which allows the Company, from time to time, to grant
options not to exceed 10% of the shares of the Company's common stock
outstanding. 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. During 1997, the 1996 Stock Option Plan was
amended to allow option grants to non-employee directors of the Company. Options
granted to non-employee directors vest on the date of grant and are
non-qualified. As of December 31, 2000, approximately 507,000 options were
authorized and available for grant under the 1996 Stock Option Plan. Since the
plan's inception in 1996, a total of 2,333,938 options have been granted of
which 978,750 options are incentive based options ("ISOs") and the balance of
1,355,188 are non-qualified stock options ("NQSOs"). Common stock issued through
the exercise of non-qualified options will result in a tax deduction for the
Company equivalent to the taxable gain recognized by the optionee. Generally,
the Company will not receive an income tax deduction for ISOs.

                                      F-13

<PAGE>   53


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


         1999 Stock Option Plan

         On October 26, 1999, the Company adopted the 1999 Non-Qualified Stock
Option Plan (the "1999 Stock Option Plan"). Under the 1999 Stock Option Plan,
400,000 options were initially authorized of which 224,400 options have been
granted as of December 31, 2000. All options under the 1999 Stock Option Plan
are non-qualified, expire 10 years from the grant date and vest in one-fifth
increments on each of the first five anniversaries of the grant date, with the
exception of options granted to non-employee directors which vest on the date of
grant.

         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,
                                                 -------------------------------------------------------------------------------
                                                           2000                       1999                       1998
                                                 -----------------------     -----------------------     -----------------------
                                                   SHARES       PRICE(1)      SHARES        PRICE(1)      SHARES        PRICE(1)
<S>                                              <C>          <C>            <C>           <C>           <C>          <C>
Options outstanding January 1 ...............    2,379,558    $    17.41     2,083,038     $   17.17     1,669,598    $   16.67
  Granted ...................................      106,000         22.71       327,900         18.87       426,700        19.07
  Exercised .................................     (820,853)        16.93       (28,080)        15.56       (13,260)       15.70
  Forfeited .................................       (4,460)        18.83        (3,300)        18.56            --
                                                 ---------                   ---------                   ---------
Options outstanding December 31(2) ..........    1,660,245    $    17.99     2,379,558     $   17.41     2,083,038    $   17.17
                                                 =========                   =========                   =========
Exercisable December 31 .....................      721,654    $    17.43     1,001,343     $   16.87       599,275    $   16.58
Options available for grant .................      682,698                     286,638                     208,838
Weighted average fair value of options
  granted ...................................                 $    10.22                   $   8.45                   $    8.54
</TABLE>

----------
(1)      Weighted average price.

(2)      For the year ended December 31, 2000, options outstanding as of the end
         of the year had exercise prices ranging from a low of $13.125 to a high
         of $26.1875 per share.

         Phantom Stock Rights

         On December 16, 1996, the Company granted key employees of Houston
Exploration 176,470 phantom stock rights ("PSRs") that give the holder the right
to receive a cash payment determined by reference to the fair market value of
one share of the Company's common stock. Twenty percent (20%) of the PSRs are
payable on December 16th of each of the years 1997 through 2001. On each date on
which a PSR is payable, the holder will receive a cash payment equal to (i) the
average of the closing prices per share of the Company's common stock for the
five trading days immediately preceding such payment date multiplied by (ii) the
number of PSRs payable on such date. During 2000, 1999 and 1998, the Company
made payments of $1.0 million, $0.6 million and $0.6 million, respectively for
the vested portion of PSRs. As of December 31, 2000, a total of 33,318 PSRs
remain outstanding.

         Effective October 1, 1997, the Company 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.

                                      F-14

<PAGE>   54


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


         Fair Value of Employee Stock-Based Compensation

         The Company accounts for the incentive stock plans using the intrinsic
value method prescribed under Accounting Principles Board ("APB") No. 25 and
accordingly no compensation expense has been recognized for stock options
granted. Had stock options been accounted for using the fair value method as
recommended in SFAS No. 123, compensation expense would have had the following
pro forma effect on the Company's net income and earnings per share for the
years ended December 31, 2000, 1999 and 1998.

<TABLE>
<CAPTION>

                                                                                 YEARS ENDED DECEMBER 31,
                                                                       ------------------------------------------
                                                                          2000            1999            1998
                                                                       ----------      ----------      ----------
                                                                          (IN THOUSANDS, EXCEPT PER SHARE DATA)

<S>                                                                    <C>             <C>             <C>
Net income (loss) - as reported .................................      $   85,258      $   24,621      $  (72,686)
Net income (loss) - pro forma ...................................          81,964          21,915         (74,985)

Net income (loss) per share - as reported .......................      $     3.06      $     1.03      $    (3.05)
Net income (loss) per share - assuming dilution--as reported ....            3.02            0.95           (3.05)

Net income (loss) per share - pro forma .........................      $     2.94      $     0.92      $    (3.15)
Net income (loss) per share - assuming dilution -- pro forma ....            2.91            0.77           (3.15)
</TABLE>

         The effects of applying SFAS No. 123 in this pro forma disclosure are
not indicative of future amounts. SFAS No. 123 does not apply to awards prior to
1995. The fair value of each option grant was estimated on the date of grant
using the Black-Scholes option pricing model with the following assumptions used
for grants in 2000, 1999 and 1998: (i) average risk-free interest rate of 5.91%,
5.96% and 5.97%, respectively, (ii) expected lives of 5 years; (iii) expected
dividends of zero; and (iv) expected volatility of 41%.

NOTE 5 -- INCOME TAXES

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

<TABLE>
<CAPTION>
                                       YEARS ENDED DECEMBER 31,
                               --------------------------------------
                                 2000           1999           1998
                               --------       --------       --------
                                           (IN THOUSANDS)
<S>                            <C>            <C>            <C>
     Current ............      $   (818)      $   (961)      $ (1,040)
     Deferred ...........        43,303         12,709        (39,714)
                               --------       --------       --------
               Total ....      $ 42,485       $ 11,748       $(40,754)
                               ========       ========       ========
</TABLE>

         The credit in the current provision represents Section 29 tax credits
(see Note 6 -- Related Party Transactions) together with a $60,000 adjustment
for an over accrual of 1999 tax credits. As of December 31, 2000 and 1999, the
Company had net operating loss ("NOL") carryforwards for federal income tax
purposes of approximately $34 million and $43 million, respectively, that may be
used in future years to offset taxable income.

                                      F-15

<PAGE>   55


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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

<TABLE>
<CAPTION>
                                                                             YEARS ENDED DECEMBER 31,
                                                                  -------------------------------------------
                                                                    2000             1999              1998
                                                                  ---------        ---------        ---------
                                                                                (IN THOUSANDS)
<S>                                                               <C>              <C>              <C>
Income (loss) before income taxes ..........................      $ 127,743        $  36,369        $(113,440)
Statutory rate .............................................             35%              35%              35%
Income tax expense (benefit) computed at statutory rate ....         44,710           12,729          (39,704)
Reconciling items:
     Section 29 tax credits and other tax credits(1) .......         (2,225)            (981)          (1,050)
                                                                  ---------        ---------        ---------
Tax expense (benefit) ......................................      $  42,485        $  11,748        $ (40,754)
                                                                  =========        =========        =========
</TABLE>

----------

(1)      Includes an adjustment for the over accrual of tax expense for the year
         ended December 31, 1999.

         Deferred Income Taxes

         The components of net deferred tax liabilities pursuant to SFAS No. 109
for the years ended December 31, 2000 and 1999 primarily represent temporary
differences related to depreciation of natural gas and oil properties.

NOTE 6 -- RELATED PARTY TRANSACTIONS

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

         Review of Strategic Alternatives

         In September 1999, the Company and KeySpan, the Company's majority
stockholder, announced their intention to review strategic alternatives for the
Company and for KeySpan's investment in Houston Exploration. KeySpan was
assessing the role of Houston Exploration 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. The Company's Board of Directors appointed a special committee
comprised of outside directors to assist in the review process. The Company and
the special committee retained Goldman, Sachs and Co. as financial advisor.

         On February 25, 2000, KeySpan and the Company jointly announced that
the review of strategic alternatives for Houston Exploration had been completed
and that KeySpan plans to retain its equity interest in Houston Exploration for
the foreseeable future.

         KeySpan Joint Venture

         Effective January 1, 1999, the Company entered into a joint exploration
agreement ( the "KeySpan Joint Venture") 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 KeySpan Joint
Venture, the Company contributed all of its then undeveloped offshore acreage to
the joint venture and KeySpan received 45% of Houston Exploration's 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 all additional intangible
drilling costs incurred were paid 51.75% by KeySpan and 48.25% by

                                      F-16

<PAGE>   56


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Houston Exploration. Revenues are shared 55% Houston Exploration and 45%
KeySpan. In addition, the Company received reimbursements from KeySpan for a
portion of its general and administrative costs.

         During the two year term of the joint drilling program beginning
January 1, 1999 and ending December 31, 2000, the Company, together with
KeySpan, drilled a total of 21 wells: 17 exploratory and four development, five
of which were unsuccessful. KeySpan spent a total of $82.1 million on
exploration and development, $46.5 million in 2000 and $35.6 million in 1999.
Houston Exploration received a total of $7.3 million in general and
administrative cost reimbursements, $2.5 million in 2000 and $4.8 million in
1999.

         Effective December 31, 2000, the Company and KeySpan agreed to
terminate the KeySpan Joint Venture. As a result, KeySpan will not participate
in the Company's future offshore exploration prospects nor will the Company
receive any reimbursement from KeySpan for future general and administrative
costs. However, pursuant to the terms of the agreement entered into in
connection with the KeySpan Joint Venture, KeySpan will continue to maintain its
working interest in all wells drilled under the joint venture agreement. KeySpan
has agreed to continue the development of its working interests in prospects
drilled under the drilling program and for the year 2001, KeySpan has agreed to
commit approximately $17 million for the development of prospects successfully
drilled during 1999 and 2000.

         Sale of Section 29 Tax Credits

         In January 1997, the Company entered into an agreement to sell to a
subsidiary of Brooklyn Union certain interests in onshore producing wells of the
Company that produce from formations that qualify for tax credits under Section
29 of the Internal Revenue Code ("Section 29"). 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. Brooklyn Union acquired an economic interest
in wells that are qualified for the tax credits and in exchange, the Company (i)
retained a volumetric production payment and a net profits interest of 100% in
the properties, (ii) received a cash down payment of $1.4 million and (iii)
receives a quarterly payment of $0.75 for every dollar of tax credit utilized.
The Company manages and administers the daily operations of the properties in
exchange for an annual management fee of $100,000. The income statement effect,
representing benefits received from Section 29 tax credits, was a benefit of
$0.9 million for the year ended December 31, 2000 and $1.0 million per year
during each of the years ended December 31, 1999 and 1998.

         Employment Contracts

         Prior to the IPO in September 1996, the Company maintained an
employment agreement (the "Initial Employment Agreement") with its President and
Chief Executive Officer, Mr. James G. Floyd, which provided him with the option
to participate in up to a 5% working interest in certain prospects of the
Company. In addition to the working interest option, the Initial Employment
Agreement provided for the assignment to the Company's President of a 2% net
profits interest in all prospects of the Company and a 6.75% after
program-payout working interest. In addition, the employment agreement provided
for the assignment to certain key employees designated by the Company's
President of an overriding royalty interest equivalent in the aggregate to a 4%
percent net revenue interest in certain properties acquired by the Company. No
assignments were made to the Company's President or to key employees of the
Company subsequent to 1995.

         In July 1996 and pursuant to the Initial Employment Agreement, the
Company's President and his affiliates opted to acquire a 5% working interest in
the Charco Field properties that were being acquired by the Company. With the
acquisition of the 5% working interest in the properties acquired by the
Company, Mr. Floyd and his affiliates also had the right to participate with a
5% working interest in any future wells drilled by the Company in the Charco
Field. The Company loaned its President the $3.1 million purchase price for his
purchase of a 5%

                                      F-17

<PAGE>   57


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


working interest in the Charco Field properties. In addition, the Company agreed
to loan its President, on a revolving basis, the amounts required to fund the
expenses attributable to his working interest. The Company's President is
required to repay amounts owed under the loan in the amount of 65% of all
distributions received in respect to his interests, as distributions are
received. Amounts outstanding under the loan bear interest at an interest rate
equal to the Company's cost of borrowing under its revolving bank line of
credit. Obligations under the agreement are secured by a pledge of the
President's interests in, and the production from, the properties. As of
December 31, 2000 and 1999, the outstanding balance owed by the Company's
President under the loan agreement was $0.6 million and $2.8 million,
respectively. The loan matures on July 2, 2006; and the Company estimates that
the remaining balance of $0.6 million will be repaid by February 28, 2001.

         Upon completion of the IPO in September 1996, the Initial Employment
Agreement was terminated and replaced with a new employment agreement, which
does not provide the Company's President with the option to participate in
prospects of the Company as a working interest owner or to receive or grant
assignments or after program-payout working interests. In addition to the
Company's President, the Company maintains employment contracts with certain
other key employees of the Company.

         In January 2000, the Company and Mr. Floyd agreed to exchange all of
the working interests and net profits interests Mr. Floyd had acquired in
properties of the Company 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 to
be earned by the Company and Mr. Floyd would be approximately the same
regardless of the nature of Mr. Floyd's participation in the earnings from such
properties. As of October 1, 1999, the net present value, discounted at 10%, of
the properties exchanged was approximately $13.5 million. Mr. Floyd will
continue to paydown outstanding borrowings on his loan with the Company from
monthly proceeds received from his overriding royalty interests in the Charco
Field. The loan is secured by Mr. Floyd's overriding royalty interests in the
Charco Field properties.

         During 2000, 1999 and 1998, the Company's President and his affiliates
received $5.8 million, $4.7 million and $4.7 million, respectively, in revenues
attributable to currently held overriding royalty interests and previously held
working interests and net profits interests in properties of the Company, and
paid $0.4 million, $2.5 million and $2.7 million, respectively, in costs and
expenses attributable to those properties.

NOTE 7 -- EMPLOYEE BENEFIT PLANS

         401(k) Profit Sharing Plan

         The Company maintains a 401(k) Profit Sharing Plan (the "401(k) Plan")
for its employees. Under the 401(k) Plan, eligible employees may elect to have
the Company contribute on their behalf up to 12.5% of their base compensation
(subject to certain limitations imposed under the Internal Revenue Code of 1986,
as amended) on a before tax basis. The Company makes a matching contribution of
$1.00 for each $1.00 of employee deferral, subject to limitations imposed by the
401(k) Plan and the Internal Revenue Service. The amounts contributed under the
401(k) Plan are held in a trust and invested among various investment funds in
accordance with the directions of each participant. An employee's salary
deferral contributions under the 401(k) Plan are 100% vested. The Company's
matching contributions vest at the rate of 20% per year of service. Participants
are entitled to payment of their vested account balances upon termination of
employment. The Company made contributions to the 401(k) Plan of $0.6 million,
$0.3 million and $0.2 million, respectively, for the years ended December 31,
2000, 1999 and 1998.

                                      F-18

<PAGE>   58

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


         Supplemental Executive Retirement Plan

         The Company maintains an unfunded, non-qualified Supplemental Executive
Retirement Plan (the "SERP"). Currently, the only beneficiary is the Company's
President and Chief Executive Officer. The SERP provides that if the executive
remains with the Company until age 65, upon his retirement on or after age 65,
the executive will be paid $100,000 per year for life. Under the terms of the
SERP, if Mr. Floyd retires prior to the age of 65, he would receive a reduced
annual benefit. If, after retirement, the executive predeceases his spouse, 50%
of the executive's SERP benefit will continue to be paid to the executive's
surviving spouse for her life. The Company accrued $124,000 for the year ended
December 31, 2000 and $123,000 in each of the years ended December 31, 1999 and
1998 related to the SERP.

NOTE 8 -- HEDGING CONTRACTS

         Natural Gas Price Swaps, Options and Collars

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

<TABLE>
<CAPTION>
                                 COLLARS                    FAIR VALUE
                   ----------------------------------     --------------
                                      NYMEX
                    VOLUME        CONTRACT PRICE
    PERIOD         (MMMbtu)     FLOOR         CEILING     ($ THOUSANDS)
------------       --------     ------        -------     -------------
<S>                <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)
</TABLE>

         At December 31, 2000, the fair market value of the Company's hedge
position for 2001 was a liability of $75 million. Fair market value is
calculated for the respective months using prices derived from New York
Mercantile Exchange (the "NYMEX") futures contract prices existing at December
31, 2000.

         Included in the hedged volume listed above for the months January 2001
through March 2001, the Company has 60,000 MMbtu/day hedged under no-cost
collars with floating floors. The floating floor structure allows for a higher
floor price in exchange for a lower ceiling. For example, during January 2001,
if the settlement price is up to $2.50 the Company will receive the settlement
price plus $0.50. If the settlement price is between $2.50 and $3.00 the Company
will receive $3.00. If the settlement price is between $3.00 and $3.63, the
Company will receive the settlement price and if market price is above $3.63,
the Company will receive $3.63 (the ceiling).

         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 the Company in the event that
the settlement price for any settlement period is less than the

                                      F-19

<PAGE>   59


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


swap price for such transaction, and the Company is 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 such 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 the Company if the
settlement price for any settlement period is below the floor price for such
transaction, and the Company is required to make payment to the counterparty if
the settlement price for any settlement period is above the ceiling price for
such transaction. The Company is 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, 1999, the Company had entered into commodity price
hedging contracts with respect to its production for 2000 as follows:

<TABLE>
<CAPTION>
                                 COLLARS               FAIR VALUE
                   ------------------------------    --------------
                                     NYMEX
                    VOLUME       CONTRACT PRICE
    PERIOD         (MMMbtu)    FLOOR      CEILING    ($ THOUSANDS)
------------       --------    -----      -------    -------------
<S>                <C>         <C>        <C>        <C>
January 2000        1,860      $2.55       $3.65       $(394)
February 2000       1,740       2.45        3.43        (325)
March 2000          1,860       2.35        3.11        (313)
April 2000            900       2.20        2.70         (57)
May 2000              930       2.20        2.70         (57)
June 2000             900       2.20        2.70         (50)
July 2000             930       2.20        2.70         (42)
August 2000           930       2.20        2.70         (31)
September 2000        900       2.20        2.70         (20)
</TABLE>

         At December 31, 1999, the fair market value for the Company's hedge
position was a liability of $1.3 million. Fair market value is calculated for
the respective months using prices derived from NYMEX futures contract prices
existing at December 31, 1999.

NOTE 9 -- SALES TO MAJOR CUSTOMERS

         The Company sold natural gas and oil production representing 10% or
more of its natural gas and oil revenues for the year ended December 31, 2000 to
Dynegy, Inc. (22.5%) and Adams Resources and Energy, Inc. (successor to H&N Gas
Ltd.) (14.9%); for the year ended December 31, 1999 to Adams Resources and
Energy, Inc. (successor to H&N Gas Ltd.) (22.5%); and for the year ended
December 31, 1998 to H&N Gas Ltd. (27%) and Columbia Energy Services Corporation
(12%). As is the nature of 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, the Company believes that the loss of
any of the Company's major purchasers would not have a material adverse effect
on the Company's operations.

NOTE 10 -- COMMITMENTS AND CONTINGENCIES

         Litigation

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

                                      F-20

<PAGE>   60



                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

         Leases

         The Company has entered into certain noncancellable operating lease
agreements relative to office space and equipment with various expiration dates
through 2004. Minimum rental commitments under the terms of the leases are as
follows (in thousands):

<TABLE>

                    Year ended December 31,
                    <S>                                <C>
                    2001 ...........................   392
                    2002 ...........................   460
                    2003 ...........................   554
                    2004 ...........................   323
                    Thereafter .....................    --
</TABLE>

         Net rental expense related to these leases was $0.4 million for the
year ended December 31, 2000 and $0.3 million during each of the two years ended
December 31, 1999 and 1998.

NOTE 11 -- ACQUISITIONS

         West Cameron 587 Acquisition.

         On November 1, 1999, the Company completed the acquisition of a 64%
working interest in the West Cameron 587 Field (the "West Cameron 587
Acquisition") for $21 million in cash. The acquisition was financed by
borrowings under the Credit Facility and represents interests in two undeveloped
wells.

         Chevron Acquisition

         On November 30, 1998, the Company acquired from Chevron U.S.A. Inc.
("Chevron") a 100% working interest in Chevron's Mustang Island A-31 Field in
the Gulf of Mexico (the "Chevron Acquisition"). The Mustang Island A-31 Field is
comprised of three adjacent blocks: Mustang Island A-22, A-31 and A-32. At the
time of acquisition, the field had nine producing wells and three platforms. The
net purchase price of $84.9 million was paid in cash, financed in part by
borrowings under the KeySpan Facility.

         South Louisiana Acquisition

         In April 1998, the Company completed the first phase of its acquisition
of certain natural gas and oil properties and associated gathering pipelines and
equipment, together with developed and undeveloped acreage, located in South
Louisiana. The properties and acreage acquired are located primarily in the
South Lake Arthur and Lake Pagie Fields, located primarily in Vermilion Parish
and Terrebonne Parish, respectively, and at the time of acquisition contained 57
producing wells. The net purchase price of $53.2 million was paid in cash,
financed with borrowings under the Company's Credit Facility. In October and
November 1999, the Company completed the second phase of its South Louisiana
Acquisition by purchasing additional working interests in approximately 25 wells
located in the South Lake Arthur Field. The natural gas and oil properties
acquired consisted solely of incremental working interests in properties in
which the Company had previously acquired a working interest in April 1998. The
combined net purchase price of $24.8 million was paid in cash, financed with
borrowings under the Company's Credit Facility. The Company's working interests
in these South Louisiana properties average between 50% and 60%.

                                      F-21

<PAGE>   61


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 12 -- SUBSEQUENT EVENTS

         KeySpan Joint Venture

         Effective January 1, 2001, the Company and KeySpan agreed to terminate
the primary term of their joint offshore exploration agreement, the KeySpan
Joint Venture (see Note 6 -- Related Party Transactions). Effective with the
termination of the KeySpan Joint Venture, KeySpan will no longer participate in
the Company's offshore exploration prospects and all working interests in
undeveloped acreage contributed by the Company to the KeySpan Joint Venture will
revert back to Houston Exploration at no cost. In addition, the Company will not
receive any future reimbursements for general and administrative costs from
KeySpan. KeySpan will continue to hold a working interest in prospects drilled
under the terms of the joint venture agreement during 1999 and 2000 and pursuant
to the terms of the agreement entered into in connection with the KeySpan Joint
Venture, has agreed to commit an estimated $17 million for development of those
prospects during 2001.

NOTE 13 -- SUPPLEMENTAL INFORMATION ON NATURAL GAS AND OIL EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

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

         Capitalized Costs of Natural Gas and Oil Properties

         As of December 31, 2000, 1999 and 1998, the Company's capitalized costs
of natural gas and oil properties are as follows:


<TABLE>
<CAPTION>

                                                                               YEARS ENDED DECEMBER 31,
                                                                  -----------------------------------------------
                                                                     2000               1999              1998
                                                                  -----------       -----------       -----------
                                                                                   (IN THOUSANDS)
<S>                                                               <C>               <C>               <C>
Unevaluated properties, not amortized ......................      $   142,890       $   164,377       $   145,317
Properties subject to amortization .........................        1,162,000           956,484           828,168
                                                                  -----------       -----------       -----------
Capitalized costs ..........................................        1,304,890         1,120,861           973,485
Accumulated depreciation, depletion and amortization .......         (601,034)         (512,465)         (438,974)
                                                                  -----------       -----------       -----------
          Net capitalized costs ............................      $   703,856       $   608,396       $   534,511
                                                                  ===========       ===========       ===========
</TABLE>

                                      F-22

<PAGE>   62


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


         The following is a summary of the costs (in thousands) which are
excluded from the amortization calculation as of December 31, 2000, by year of
acquisition. The Company is not able to accurately predict when these costs will
be included in the amortization base; however, the Company believes that
unevaluated properties at December 31, 2000 will be fully evaluated within five
years.


<TABLE>

<S>                                 <C>
               2000 ..........      $ 31,134
               1999 ..........        20,292
               1998 ..........        42,081
               Prior .........        49,383
                                    --------
                                    $142,890
                                    ========
</TABLE>

         Costs incurred for natural gas and oil exploration, development and
acquisition are summarized below. Costs incurred during the years ended December
31, 2000, 1999 and 1998 include interest expense and general and administrative
costs related to acquisition, exploration and development of natural gas and oil
properties, of $ $23.3 million, $17.4 million and $17.3 million, respectively.


<TABLE>
<CAPTION>
                                                YEARS ENDED DECEMBER 31,
                                         ------------------------------------
                                           2000          1999          1998
                                         --------      --------      --------
                                                    (IN THOUSANDS)
<S>                                      <C>           <C>           <C>
Property acquisition:
  Unevaluated(1) ..................      $  7,955      $ 10,337      $ 33,803
  Proved ..........................        38,579        37,105       162,083
Exploration costs .................        37,162        12,257        55,611
Development costs .................       100,333        87,965        51,046
                                         --------      --------      --------
          Total costs incurred ....      $184,029      $147,664      $302,543
                                         ========      ========      ========
</TABLE>

----------

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


                                      F-23
<PAGE>   63


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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

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

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

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

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

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

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

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

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

         The standardized measure of discounted future net cash flows does not
purport, nor should it be interpreted, to present the fair value of the
Company's natural gas and oil reserves. An estimate of fair value would also
take into account, among other things, the recovery of reserves not presently
classified as proved, anticipated future changes in prices and costs and a
discount factor more representative of the time value of money and the risks
inherent in reserve estimates.

                                      F-24

<PAGE>   64

                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


         The standardized measure of discounted future net cash flows relating
to proved natural gas and oil reserves is as follows:

<TABLE>
<CAPTION>

                                                                                AS OF DECEMBER 31,
                                                                  -----------------------------------------------
                                                                     2000              1999               1998
                                                                  -----------       -----------       -----------
                                                                                   (IN THOUSANDS)
<S>                                                               <C>               <C>               <C>
Future cash inflows ........................................      $ 5,189,328       $ 1,113,844       $   878,448
Future production costs ....................................         (542,139)         (190,900)         (153,567)
Future development costs ...................................         (153,210)         (120,071)         (103,915)
Future income taxes ........................................       (1,250,272)         (155,641)          (89,032)
                                                                  -----------       -----------       -----------
Future net cash flows ......................................        3,243,707           647,232           531,934
10% annual discount for estimated timing of cash flows .....       (1,179,680)         (178,007)         (135,874)
                                                                  -----------       -----------       -----------
Standardized measure of discounted future net
  cash flows ...............................................      $ 2,064,027       $   469,225       $   396,060
                                                                  ===========       ===========       ===========
</TABLE>


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

<TABLE>
<CAPTION>
                                                                                 AS OF DECEMBER 31,
                                                                  -----------------------------------------------
                                                                      2000             1999               1998
                                                                  -----------       -----------       -----------
                                                                                  (IN THOUSANDS)
<S>                                                               <C>               <C>               <C>
Beginning of the year ......................................      $   469,225       $   396,060       $   315,380
Revisions to previous estimates:
  Changes in prices and costs ..............................        2,163,984            47,330          (104,137)
  Changes in quantities ....................................           24,650            51,375            (4,982)
  Changes in future development costs ......................          (32,152)          (25,730)           (6,656)
Development costs incurred during the period ...............           57,046            40,563            15,891
Extensions and discoveries, net of related costs ...........          403,012            91,383            72,333
Sales of natural gas and oil, net of production costs ......         (237,286)         (126,730)         (105,958)
Accretion of discount ......................................           52,967            41,293            37,706
Net change in income taxes .................................         (672,005)          (43,572)           44,812
Purchase of reserves in place ..............................           23,118            20,973           156,122
Sale of reserves in place ..................................               --            (2,194)             (863)
Production timing and other ................................         (188,532)          (21,526)          (23,588)
                                                                  -----------       -----------       -----------
End of year ................................................      $ 2,064,027       $   469,225       $   396,060
                                                                  ===========       ===========       ===========
</TABLE>

                                      F-25

<PAGE>   65


                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


ESTIMATED NET QUANTITIES OF NATURAL GAS AND OIL RESERVES (UNAUDITED)

         The following table sets forth the Company's net proved reserves,
including changes therein, and proved developed reserves (all within the United
States) at the end of each of the three years in the period ended December 31,
2000, 1999 and 1998.

<TABLE>
<CAPTION>

                                                            NATURAL GAS                          CRUDE OIL AND CONDENSATE
                                                              (MMcf)                                      (MBbls)
                                              --------------------------------------       --------------------------------------
                                                2000           1999           1998           2000           1999           1998
                                              --------       --------       --------       --------       --------       --------
<S>                                           <C>            <C>            <C>            <C>            <C>            <C>
Proved developed and
  undeveloped reserves: ................       526,185        470,447        330,601          2,470          1,650          1,077
Revisions of previous estimates ........         3,709         45,510         (4,656)           107            237           (105)
Extensions and discoveries .............        69,564         62,700         67,272          2,424            909            249
Production .............................       (77,861)       (69,679)       (61,479)          (311)          (258)          (225)
Purchase of reserves in place ..........         7,921         20,699        139,994            662              1            665
Sales of reserves in place .............            --         (3,492)        (1,285)            --            (69)           (11)
                                              --------       --------       --------       --------       --------       --------
End of year ............................       529,518        526,185        470,447          5,352          2,470          1,650
                                              ========       ========       ========       ========       ========       ========
Proved developed reserves:
Beginning of year ......................       397,343        369,931        256,632          1,796          1,498            914
End of year ............................       420,733        397,343        369,931          1,810          1,796          1,498
</TABLE>

NOTE 14 -- QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

         Selected unaudited quarterly data is shown below:

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


1999
Total revenues ...................................      $ 26,865      $ 35,137      $ 42,477      $ 47,248
Income from operations ...........................         3,817        10,725        16,194        18,940
Net income .......................................           746         5,189         8,528        10,158

Net income per share .............................      $   0.03      $   0.22      $   0.36      $   0.42
Net income per share -- assuming dilution ........      $   0.03      $   0.21      $   0.32      $   0.38
</TABLE>

----------

(1)      Quarterly earnings per share based on the weighted average number of
         shares outstanding during the quarter. Because of the increase in the
         number of shares outstanding during the first quarter due to the
         conversion of the KeySpan Facility and during the third and fourth
         quarters due to the exercise of stock options (see Note 3 --
         Stockholders' Equity), the sum of quarterly earnings per share do not
         equal earnings per share for the year.

                                      F-26

<PAGE>   66
                                INDEX TO EXHIBITS

<TABLE>
<CAPTION>


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

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

  10.1(2)    --      Employment Agreement dated July 2, 1996 between The Houston
                     Exploration Company and James G. Floyd (filed as Exhibit
                     10.8 to the Company's Registration Statement on Form S-1
                     (Registration No. 333-4437) and incorporated by reference
                     herein).

  10.2(2)    --      Employment Agreement dated July 2, 1996 between The Houston
                     Exploration Company and Randall J. Fleming (filed as
                     Exhibit 10.9 to the Company's Registration Statement on
                     Form S-1 (Registration No. 333-4437) and incorporated by
                     reference herein).

  10.3(2)    --      Employment Agreement dated July 2, 1996 between The Houston
                     Exploration Company and Thomas W. Powers (filed as Exhibit
                     10.10 to the Company's Registration Statement on Form S-1
                     (Registration No. 333-4437) and incorporated by reference
                     herein).

  10.4(2)    --      Employment Agreement dated July 2, 1996 between The Houston
                     Exploration Company and James F. Westmoreland (filed as
                     Exhibit 10.11 to the Company's Registration Statement on
                     Form S-1 (Registration No. 333-4437) and incorporated by
                     reference herein).

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

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

  10.7(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 the Company's Registration
                     Statement on Form S-1 (Registration No. 333-4437) and
                     incorporated by reference herein).

  10.8(2)    --      Supplemental Executive Pension Plan (filed as Exhibit 10.23
                     to the Company's Registration Statement on Form S-1
                     (Registration No. 333-4437) and incorporated by reference
                     herein).

  10.9(2)    --      Employment Agreement, dated September 19, 1996, between The
                     Houston Exploration Company and Charles W. Adcock (filed as
                     Exhibit 10.26 to the Company's Annual Report on Form 10-K
                     for the year ended December 31, 1996 (File No. 001-11899)
                     and incorporated by reference herein).

  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 the Company's Annual Report on Form 10-K for the
                     year ended December 31, 1996 (File No. 001-11899) and
                     incorporated by reference herein).

  10.11(2)   --      Deferred Compensation Plan for Non-Employee Directors
                     (filed as Exhibit 10.24 to the Company's Annual Report on
                     Form 10-K for the year ended December 31, 1997 (File No.
                     001-11899) and incorporated by reference herein).
</TABLE>


                                      F-27
<PAGE>   67

<TABLE>
<CAPTION>


EXHIBIT
NUMBER               DESCRIPTION
-------              -----------
<S>                  <C>
  10.12      --      Indenture, dated as of March 2, 1998, between The Houston
                     Exploration Company and The Bank of New York, as Trustee,
                     with respect to the 8 5/8% Senior Subordinated Notes Due
                     2008 (including form of 8 5/8% Senior Subordinated Note Due
                     2008) (incorporated by reference to Exhibit 4.1 to the
                     Company's Registration Statement on Form S-4 (No.
                     333-50235)).

  10.13(2)   --      Amended and Restated 1996 Stock Option Plan (filed as
                     Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q
                     for the quarter ended June 30, 1998 (File No. 001-11899)
                     and incorporated by reference herein).

  10.14(2)   --      Employment Agreement dated May 1, 1998 between The Houston
                     Exploration Company and Thomas E. Schwartz (filed as
                     Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q
                     for the quarter ended March 31, 1998 (File No. 001-11899)
                     and incorporated by reference herein).

  10.15      --      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
                     the Company's Annual Report on Form 10-K for the year ended
                     December 31, 1998 and incorporated by reference herein).

  10.16      --      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
                     the Company's Annual Report on Form 10-K for the year ended
                     December 31, 1998 (File No. 001-11899) and incorporated by
                     reference herein).

  10.17      --      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 the Company's Annual Report on
                     Form 10-K for the year ended December 31, 1999 (File No.
                     001-11899) and incorporated by reference herein).

  10.18      --      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 the
                     Company's Quarterly Report on Form 10-Q for the quarter
                     ended March 31, 1999 (File No. 001-11899) and incorporated
                     by reference herein).

  10.19      --      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 the Company's Annual Report on Form 10-K for the
                     year ended December 31, 1999 (file No. 001-11899) and
                     incorporated by reference herein).

  10.20      --      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 the Company's Quarterly Report on Form 10-Q
                     for the quarter ended March 31, 1999 (File No. 001-11899)
                     and incorporated by reference herein).

  10.21      --      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 the
                     Company's Quarterly Report on Form 10-Q for the quarter
                     ended June 30, 1999 (File No. 001-11899) and incorporated
                     by reference herein).

  10.22      --      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 the Company's Quarterly
                     Report on Form 10-Q for the quarter ended September 30,
                     1999 (File No. 001-11899) and incorporated by reference
                     herein).
</TABLE>


                                      F-28
<PAGE>   68

<TABLE>
<CAPTION>


EXHIBIT
NUMBER               DESCRIPTION
-------              -----------
<S>                  <C>
  10.23      --      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 the
                     Company's Annual Report on Form 10-K for the year ended
                     December 31, 1999 File No. 001-11899) and incorporated by
                     reference herein).

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

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

  10.26(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 the Company's
                     Quarterly on Form 10-Q for the quarter ended September 30,
                     2000 File No. 001-11899) and incorporated by reference
                     herein).

  12.1(1)    --      Computation of ratio of earnings to fixed charges.

  21.1(1)    --      Subsidiaries of the Company.

  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-29