<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, 1999
                                       OR
            [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF
                       THE SECURITIES EXCHANGE ACT OF 1934
                        FOR THE TRANSITION PERIOD FROM TO
                          COMMISSION FILE NO. 001-11899

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

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


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

       1100 LOUISIANA, SUITE 2000
             HOUSTON, TEXAS                                              77002-5219
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)                                 (ZIP CODE)
</TABLE>


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

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


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


<TABLE>
                 <S>                                                     <C>
                                                                                 NAME OF EACH
                           TITLE OF EACH CLASS                           EXCHANGE ON WHICH REGISTERED
                 ----------------------------------------                ----------------------------
                       Common Stock, $.01 par value                         New York Stock Exchange
                 85/8% 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 $151,525,825 as of March 22, 2000, based on the
closing sales price of the registrant's common stock on the New York Stock
Exchange on such date of $17.5625 per share. For purposes of the preceding
sentence only, all directors, executive officers and beneficial owners of ten
percent or more of the common stock are assumed to be affiliates. As of March
22, 2000, 23,923,020 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 2000 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, 1999, 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,
1999, net proved reserves were 541 Bcfe with a discounted present value of cash
flows before income taxes ("PV-10%") of $530 million. The Company's focus is
natural gas and approximately 97% of its net proved reserves at December 31,
1999 were natural gas and approximately 75% were classified as proved developed.
The Company operates approximately 90% 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 ("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, 1999, THEC Holdings Corp., an indirect wholly owned
subsidiary of KeySpan, owned approximately 64% of the outstanding shares of
Houston Exploration's common stock. KeySpan is a diversified energy provider
that (i) distributes natural gas to a customer base of 1.6 million New Yorkers
in Brooklyn, Long Island, Queens and Staten Island; (ii) is contracted by Long


                                      -1-
<PAGE>   3
Island Power Authority to manage electricity service to about 1 million
customers in the Long Island area; and (iii) through its unregulated
subsidiaries, is involved in gas retailing, power plant management and energy
management services.

         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, 1994 through December 31, 1999, 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 34%.
During the past five years, the Company produced a total of 239 Bcfe and added
637 Bcfe of net proved reserves of which 325 Bcfe were added through
acquisitions and 312 Bcfe were added through exploration and development. In
total, the Company replaced 266% of production through drilling and
acquisitions, with 130% replaced through the drillbit alone. At the close of
1999 daily production averaged 213 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 527,279
gross (286,953 net) acres, in federal and state waters in the Gulf of Mexico, of
which 74 blocks are undeveloped. The Company believes it has assembled a
four-year inventory of offshore prospects and of its undeveloped leases, 20 have
been evaluated, permitted and are ready to drill. The Company plans to drill
approximately six exploratory wells in the Gulf of Mexico in 2000. 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 21
successful exploratory wells and 18 successful development wells in the Gulf of
Mexico, representing a historical success rate of 71%. The Company anticipates
that approximately $63 million of its $125 million 2000 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 44% of the Company's net proved reserves as of
December 31, 1999. At the end of 1999, average net production from the Company's
Gulf of Mexico properties was approximately 91 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 56% of net proved reserves at December
31, 1999. Complementing the offshore properties, the Company's onshore
properties are typically characterized by relatively longer reserve lives, more
predictable production streams and lower operating cost structures. Over the
past five years, the Company has drilled or participated in the drilling of 108
successful development wells and nine successful exploratory wells onshore
representing a historical drilling success rate of 80%. 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 $62 million of its $125
million 2000 capital expenditure budget (excluding acquisitions) will be spent


                                      -2-
<PAGE>   4
on onshore projects, including the drilling of approximately 50 development
wells. At the end of 1999, average net production from the Company's onshore
properties was approximately 122 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 approximately 100 square miles in South Louisiana. The
Company has 14 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 90% 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 $0.08 per Mcfe) of $0.26 per
Mcfe of production and net general and administrative expense of $0.06 per Mcfe
of production for the year ended December 31, 1999. The Company believes that
these expense levels are among the lowest within its peer group

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
RECENT ACQUISITIONS

         West Cameron 587 Acquisition

         In November 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 Company's revolving bank credit facility and represents
interests in two undeveloped wells. Net proved undeveloped reserves for the
natural gas and oil interests acquired are estimated at 21 Bcfe as of December
31, 1999.

KEYSPAN JOINT VENTURE

         In March 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 a term of three
years expiring December 31, 2001. Either party may terminate the KeySpan Joint
Venture at the end of the then current calendar quarter by giving thirty days
prior written notice. Houston Exploration is joint venture manager and operator.
Effective January 1, 1999, KeySpan agreed to commit up to $100 million per
calendar year and Houston Exploration agreed to commit its proportionate share
of the funds per calendar year necessary to fund a joint exploration and
development drilling program. Houston Exploration contributed all of its
undeveloped offshore leases as of January 1, 1999 to the joint venture. KeySpan
will receive 45% of Houston Exploration's working interest in all prospects to
be drilled under the program. Revenues will be shared 55% Houston Exploration
and 45% KeySpan. During the term of the KeySpan Joint Venture, KeySpan pays 100%
of actual intangible drilling costs up to a maximum of $20.7 million per year.
All additional intangible drilling costs incurred during such year are paid
51.75% by KeySpan and 48.25% by Houston Exploration. In addition, Houston
Exploration receives reimbursement of a portion of its general and
administrative costs during the term of the joint venture.

         During 1999, the Company, together with KeySpan, completed the drilling
of eight wells under the KeySpan Joint Venture, six of which were successful.
KeySpan incurred approximately $35.6 million in drilling costs during 1999 and
the Company received $4.8 million in general and administrative reimbursements.
KeySpan has agreed to commit approximately $30 million during 2000 for the
drilling of six exploratory wells and the development of discoveries made in
1999. The $30 million commitment will include approximately $18 million for
exploration, $10 million for development and the balance for general and
administrative reimbursements.


                                      -4-
<PAGE>   6
GULF OF MEXICO PROPERTIES

         The Company holds interests in 106 offshore blocks, of which 30 are
currently producing. The Company operates 21 of these producing blocks,
accounting for approximately 90% 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, 1999. These properties represent over 80% of the Company's Gulf
of Mexico proved reserves and approximately 85% of its offshore production
during 1999:


<TABLE>
<CAPTION>
                                             NET PROVED RESERVES AT DECEMBER 31, 1999
                                             ----------------------------------------  AVERAGE
                                                  GAS           OIL       TOTAL        WORKING
            OFFSHORE FIELDS                      (MMCF)       (MBBLS)    (MMCFE)       INTEREST     OPERATOR
            ---------------                      -------      -------    -------       --------   ------------
     <S>                                         <C>          <C>        <C>             <C>      <C>
     Mustang Island Blocks A-31/32 ........       82,546         214      83,830         100%     Company
     East Cameron Blocks 82/83 ............       26,401         304      28,225          98%     Company
     West Cameron Blocks 76/77/60/61 ......       22,767         152      23,679          12%     Third Party
     West Cameron Block 587 ...............       20,601        --        20,601          64%     Third Party
     Mustang Island Blocks 858/868 ........       13,581         214      14,865          74%     Company
     Matagorda Island Blocks 651/671/672...       11,875           7      11,917          61%     Company
     High Island Blocks 38/39 .............       11,137          71      11,563          45%     Company
     Mustang Island Block 807 .............        6,643          19       6,757         100%     Company
     East Cameron Block 84 ................        5,199         151       6,105          14%     Third Party
     Mustang Island Block 759 .............        5,221           9       5,275          25%     Third Party
     All Other Gulf of Mexico (13 fields)..       18,937         797      23,719
                                                 -------       -----     -------
     Total Gulf of Mexico .................      224,908       1,938     236,536
                                                 =======       =====     =======
</TABLE>


         During 1999, the Company drilled 14 successful wells (six exploratory
and eight development) and two unsuccessful exploratory wells on its Gulf of
Mexico properties. KeySpan participated in five of the six successful
exploratory wells, the two unsuccessful exploratory wells and one of the
successful development wells. Discoveries were made at West Cameron 76, East
Cameron 84, Galveston 190, Galveston 389, Vermilion 408 and South Timbalier 316.
Three development wells were drilled at Mustang A-31 and two development wells
were drilled at West Cameron 76 to further delineate the discovery well at West
Cameron 76 which was completed in early 1999. At December 31, 1999, two
exploratory wells were in progress: Matagorda 704 and North Padre Island 883-L.
KeySpan is participating in both of these wells and both have been determined
successful and will be completed during 2000. Capital spending associated with
the Company's Gulf of Mexico properties during 1999 was $104.6 million,
including $8.5 million for exploratory drilling, $53.9 million for development
and $42.2 million for property acquisition and leasehold costs which includes
$21 million for the acquisition of the West Cameron 587 Field.

         During 2000, the Company plans to drill approximately six exploratory
wells in the Gulf of Mexico and complete the development of discoveries made
during 1999 at Galveston 190, Galveston 389, Matagorda 704, Vermilion 408 and
North Padre 883. In addition, the Company plans to complete the installation of
facilities at Galveston 144 where a successful exploratory well was drilled in
1998 and to begin development at West Cameron 587 which was acquired in November
1999. All six of the exploratory wells planned for 2000 will be drilled under
the terms of the KeySpan Joint Venture. As of March 22, 2000, the Company had
three offshore wells in progress: Matagorda 704, North Padre Island 883-L, and
East Breaks 167. In early January 2000, a second exploratory well was spud at
East Cameron 84 to test the fault block to the south of the discovery made in
1999. Both the Company and KeySpan were participating in the well which was
drilled by a third party. The well was logged and determined to be unproductive
in mid-March 2000.


                                      -5-
<PAGE>   7
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
1,179 gross (779.1 net) producing wells, approximately 90% of which the Company
is the operator of record, and 166,450 gross (116,639 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,
1999, representing all of the Company's onshore reserves:


<TABLE>
<CAPTION>
                                                                                    NET PROVED RESERVES AT
                                                                                      DECEMBER 31, 1999
                                                                     AVERAGE    ------------------------------
                                                                     WORKING     GAS         OIL        TOTAL
ONSHORE OPERATING AREAS                                              INTEREST   (MMCF)     (MBBLS)     (MMCFE)
-----------------------                                              --------   ------     -------     -------
<S>                                                                  <C>       <C>         <C>         <C>
     Charco Field (South Texas) .............................          95%     142,971          56     143,307
     South Lake Arthur and Lake Pagie (South Louisiana) .....          55%      46,006         357      48,148
     Chismville/Massard Field (Arkansas) ....................          73%      71,889        --        71,889
     Wilburton, Panola and Surrounding Fields (Oklahoma) ....          23%       8,000        --         8,000
     Willow Springs and Surrounding Fields (East Texas) .....          53%      10,526          68      10,934
     Appalachian Area (West Virginia) .......................          60%      21,885          51      22,191
                                                                               -------     -------     -------
     Total Onshore ..........................................                  301,277         532     304,469
                                                                               =======     =======     =======
</TABLE>


         The Company drilled or participated in the drilling of 31 successful
development wells and two successful exploratory wells on its onshore properties
during 1999. During this same period, the Company drilled or participated in the
drilling of six development wells that were not successful. Capital spending
associated with the Company's onshore drilling program during 1999 was
approximately $43.0 million, including $34.0 million for development, $3.8
million for exploration and $5.2 million for leasehold acquisition costs. The
Company did not acquire any onshore properties during 1999.

         For 2000 the Company has budgeted funds to drill approximately 50
onshore development wells: 24 in the Charco Field, four wells in South
Louisiana, 18 wells in the Arkoma Basin and four wells in East Texas. 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 95% working interest in the approximately 214 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 85 MMcfe per day, net to the Company's interest, in
December 1999. The Company has drilled 62 successful wells, added 114 Bcfe in
reserves and produced 85 Bcfe since the acquisition of the Charco Field. During
1999 the Company successfully drilled 22 development wells and drilled one
unsuccessful development well. Daily production is expected to increase as new
development wells are brought on-line. The Company is continuing its
interpretation of 3-D seismic data covering 148 square miles of its Charco Field
properties. Subsequent to year end, the Company successfully drilled and
completed four development wells and is currently in the process of drilling two
new development wells.


                                      -6-
<PAGE>   8
         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 48 producing wells, of which it
operates 10 wells. Working interests in these wells range from 2% to 70% and
average 55%. During 1999, the Company participated in two wells located in Lake
Pagie: one successful exploratory well with a working interest of 60%, and one
unsuccessful development well with a working interest of 30%. At the end of
1999, production from the South Louisiana properties averaged approximately 13
MMcfe/d, net to the Company's interest. Subsequent to year end 1999, the Company
spud its first well in South Lake Arthur. Houston Exploration is operator and
holds a 52% working interest. The well is a deep development well and the
Company is drilling the well under a turnkey contract. The well is scheduled to
reach its target objective of 17,000 feet during the second quarter of 2000.

         Chismville/Massard Field. The Chismville/Massard Field is located in
Logan and Sebastian Counties, Arkansas. The Company owns working interests in
approximately 161 active wells, of which it operates 84 wells. Working interests
in these wells range from 11% to 100% and average approximately 73%. During
1999, the Company successfully completed six gross (3.2 net) development wells
and participated in the drilling of four (1.8 net) unsuccessful development
wells. Subsequent to year end 1999, the Company successfully drilled and
completed two (1.0 net) wells. At the end of 1999, production averaged 13.5
MMcfe/d, net to the Company.

         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%. At the end of 1999, production averaged 2.2
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
interest in 51 active wells, of which it operates 16 wells. Working interests in
these wells range from 1% to 63% and average approximately 23%. During 1999, the
Company participated in the successful drilling of three (0.2 net) development
wells. At year end 1999, 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%. At year end 1999, production averaged
5.3 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 74 undeveloped
blocks representing 379,065 gross (198,591 net) acres. Of these undeveloped
leases, 20 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.


                                      -7-
<PAGE>   9
NATURAL GAS AND OIL RESERVES

         The following table summarizes the estimates of the Company's
historical net proved reserves as of December 31, 1999, 1998 and 1997, 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,
                                                                 ----------------------------------
                                                                   1999         1998         1997
                                                                 --------     --------     --------
                                                                           (IN THOUSANDS)
<S>                                                               <C>          <C>          <C>
     Net Proved Reserves(1):
        Natural gas (MMcf) .................................      526,185      470,447      330,601
        Oil (MBbls) ........................................        2,470        1,650        1,077
        Total (MMcfe) ......................................      541,005      480,347      337,063
     Present value of future net revenues before income
        taxes(2) ...........................................     $529,671     $412,933     $377,065
     Standardized measure of discounted future net cash
        flows(3) ...........................................     $469,225     $396,060     $315,380
</TABLE>

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

(1)      NSA and Miller and Lents prepared reserve data and present values with
         respect to properties comprising approximately 76% and 24%,
         respectively, of the present values attributable to the Company's
         proved reserves as of December 31, 1999; 71% and 29%, respectively, of
         the present values attributable to proved reserves as of December 31,
         1998; and 76% and 24%, respectively, of the present values attributable
         to proved reserves as of December 31, 1997.
(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, 1999, 1998 and 1997
         were $2.01, $1.83 and $2.31, respectively. Average prices per Bbl of
         oil used in making such present value determinations as of December 31,
         1999, 1998 and 1997 were $22.80, $10.65 and $17.23, respectively. Such
         amounts reflect the effects of the Company's hedging contracts.
(3)      The standardized measure of discounted future net cash flows represents
         the present value of future net revenues after income tax discounted at
         10% per annum. Such amounts reflect the effects of the Company's
         hedging contracts.

         In accordance with applicable requirements of the Securities and
Exchange Commission, estimates of the Company's proved reserves and future net
revenues are made using sales prices estimated to be in effect as of the date of
such reserve estimates and are held constant throughout the life of the
properties (except to the extent a contract specifically provides for
escalation). Estimated quantities of proved reserves and future net revenues
therefrom are affected by gas prices, which have fluctuated widely in recent
years. There are numerous uncertainties inherent in estimating natural gas and
oil reserves and their estimated values, including many factors beyond the
control of the producer. The reserve data set forth in this 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.


                                      -8-
<PAGE>   10
DRILLING ACTIVITY

         The following table sets forth the drilling activity of the Company on
its properties for the years ended December 31, 1999, 1998 and 1997.


<TABLE>
<CAPTION>
                                                               YEAR ENDED DECEMBER 31,
                                     -------------------------------------------------------------------------
                                             1999                      1998                       1997
                                     ---------------------     ----------------------     --------------------
                                      GROSS         NET         GROSS          NET         GROSS         NET
                                     -------      --------     -------       --------     --------     -------
<S>                                        <C>         <C>           <C>          <C>            <C>       <C>
OFFSHORE DRILLING ACTIVITY:
Exploratory:
     Productive.....................       6           1.4           2            1.3            6         3.7
     Non-Productive.................       2           1.0           5            4.2            3         2.3
                                     -------      --------     -------       --------     --------     -------
          Total.....................       8           2.4           7            5.5            9         6.0
 Development:
     Productive.....................       8           5.5           1            1.0            1         0.2
     Non-Productive.................      --            --           1            0.8            1         0.8
                                     -------      --------     -------       --------     --------     -------
          Total.....................       8           5.5           2            1.8            2         1.0

ONSHORE DRILLING ACTIVITY:
 Exploratory:
     Productive.....................       2           1.2           1            0.3            2         0.1
     Non-Productive.................      --            --          --             --            2         0.6
                                     -------      --------     -------       --------     --------     -------
          Total.....................       2           1.2           1            0.3            4         0.7
 Development:
     Productive.....................      31          24.3          23           18.2           33        29.1
     Non-Productive.................       6           3.1           4            3.8            8         7.7
                                     -------      --------     -------       --------     --------     -------
          Total.....................      37          27.4          27           22.0           41        36.8
</TABLE>


PRODUCTIVE WELLS

         The following table sets forth the number of productive wells in which
the Company owned an interest as of December 31, 1999.


<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............          21            56           43.8            12         1.9           68          45.7
    Oil............          --            --             --             4         0.5            4           0.5
                        -------      --------       --------      --------    --------     --------     ---------
    Total..........          21            56           43.8            16         2.4           72          46.2
                        =======      ========       ========      ========    ========     ========     =========

ONSHORE
    Gas............                     1,008          741.2           167        35.5        1,175         776.7
    Oil............                         2            1.9             2         0.5            4           2.4
                                     --------       --------      --------    --------     --------     ---------
    Total..........                     1,010          743.1           169        36.0        1,179         779.1
                                     ========       ========      ========    ========     ========     =========
</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.


                                      -9-
<PAGE>   11
ACREAGE DATA

         The following table sets forth the approximate developed and
undeveloped acreage in which the Company held a leasehold mineral or other
interest as of December 31, 1999. 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
                              -------------------     -------------------
                               GROSS        NET        GROSS        NET
                              -------     -------     -------     -------
     <S>                      <C>         <C>         <C>         <C>
     Offshore(1) ........     148,214      88,362     379,065     198,591
     Onshore ............     151,493     105,977      14,957      10,662
                              -------     -------     -------     -------
              Total .....     299,707     194,339     394,022     209,253
                              =======     =======     =======     =======
</TABLE>

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

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

MARKETING AND CUSTOMERS

         Substantially all of the Company's production is sold at market prices.
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, 1999 to Adams Resources and Energy, Inc. (successor to H&N Gas
Ltd.) (22.5%); for the year ended December 31, 1998 to H&N Gas Ltd. (27%) and
Columbia Energy Services Corporation (12%); and for the year ended December 31,
1997 to H&N Gas Ltd. (38%).

         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, 1999, total undiscounted abandonment costs
estimated to be incurred through the year 2011 were approximately $9.2 million
for properties in the federal and state waters and are not considered
significant for onshore properties. Estimates of abandonment costs and their
timing may change due to many factors including actual drilling and production
results, inflation rates, and changes in environmental laws and regulations.


                                      -10-
<PAGE>   12
         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 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.


                                      -11-
<PAGE>   13
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 availability of a ready market for natural gas and oil production
depends upon numerous factors beyond the Company's control. These factors
include:

     o    regulation of natural gas and oil production;
     o    federal and state regulations governing environmental quality and
          pollution control;
     o    state limits on allowable rates of production by a well or proration
          unit;
     o    the supply of natural gas and oil available for sale; o the
          availability of adequate pipeline and other transportation and
          processing facilities; and
     o    the marketing of competitive fuels.

         For example, a productive natural gas well may be "shut-in" because of
an oversupply of natural gas or the lack of an available natural gas pipeline in
the areas in which the Company may conduct operations.

         REGULATION OF OIL AND GAS EXPLORATION AND PRODUCTION. Exploration and
production operations of the Company are subject to various types of regulation
at the federal, state and local levels. 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.

         State statutes and regulations require permits for drilling operations,
drilling bonds and reports concerning operations. Most states in which the
Company operates also have statutes and regulations governing the conservation
of oil and natural gas and the prevention of waste, including the unitization or
pooling of oil and natural gas properties and rates of production from oil and
natural gas wells. Rates of production may be regulated through the
establishment of maximum daily production allowables on a market demand or
conservation basis or both.

         In addition to regulatory oil and gas production, numerous states have
implemented statutory and regulatory initiatives requiring local distribution
companies ("LDCs") to develop to various degrees unbundled transportation and
related service options and rates. Typically, these programs are designed to
allow the LDCs' commercial, industrial, and, with increasing frequency,
residential customers to have access to transportation service on the LDC,
coupled with an ability to select third-party city-gate gas suppliers.
Similarly, several states are also addressing the


                                      -12-
<PAGE>   14
unbundling of the retail electric markets, ranging from the consideration of
initial unbundling proposals to permitting, in varying degrees, the
implementation of programs allowing direct retail access. These developments
have already led a number of industry participants to redirect significant
marketing resources to these emerging energy markets.

         NATURAL GAS MARKETING AND TRANSPORTATION. Federal legislation and
regulatory controls in the United States have historically affected the price of
the natural gas produced by the Company and the manner in which such production
is marketed. The 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
(the "NGA"). Although maximum selling prices of natural gas were formerly
regulated under the NGA and the Natural Gas Policy Act of 1978 (the "NGPA"), on
July 26, 1989, the Natural Gas Wellhead Decontrol Act of 1989 (the "Decontrol
Act") amended the NGPA to remove completely by January 1, 1993 price and
non-price controls for all "first sales" of domestic natural gas, which include
all sales by the Company of its own production.

         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 and continuing with the issuance of Order No.
636 in 1992, 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.

         All pipeline operations on or across the Outer Continental Shelf are
regulated under the Outer Continental Shelf Lands Act ("OCSLA"). Under the
FERC's current regulatory regime, transmission services must be provided on an
open-access, non-discriminatory basis, while gathering services are treated as
non-jurisdictional activities not subject to the FERC's jurisdiction. The FERC
continues to consider changes regarding the application of its jurisdiction over
facilities operating on the Outer Continental Shelf. It is not clear whether a
revised FERC policy regarding its jurisdiction over offshore natural gas
pipeline facilities would have a material effect on producers such as the
Company and the Company cannot predict what a revised policy would entail. The
Company, however, does not believe that it will be affected by any action taken
materially differently than other natural gas producers and marketers with which
the Company competes.

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

         OFFSHORE LEASING. Certain operations the Company conducts are on
federal oil and gas leases, which the MMS administers. The MMS issues such
leases through competitive bidding. These leases contain relatively standardized
terms and require compliance with detailed MMS regulations and orders pursuant
to the OCSLA (which are subject to change by the MMS). For offshore operations,
lessees must obtain MMS approval for exploration plans and development and
production plans prior to the commencement of such operations. In addition to
permits required from other agencies (such as the Coast Guard, the Army Corps of
Engineers and the Environmental Protection Agency), lessees must obtain a permit
from the MMS prior to the commencement of drilling. The MMS has promulgated
regulations requiring offshore production facilities located on the Outer
Continental Shelf 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


                                      -13-
<PAGE>   15
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 cost of such bonds or other
surety can be substantial and there is no assurance that the Company can obtain
bonds or other surety in all cases. See "-- Environmental Matters."

ENVIRONMENTAL MATTERS

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

         The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the original conduct, on certain classes of persons who are
considered to be responsible for the release of a "hazardous substance" into the
environment. These persons include the owner or operator of the disposal site or
sites where the release occurred and companies that disposed or arranged for the
disposal of the hazardous substances. Under CERCLA, these persons may be subject
to joint and several liability for the costs of cleaning up the hazardous
substances that have been released into the environment, for damages to natural
resources, and for the costs of certain health studies. Furthermore, it is not
uncommon for neighboring landowners and other third parties to file claims for
personal injury and property damage allegedly caused by the release of hazardous
substances. Finally, under CERCLA, crude oil and fractions thereof are expressly
exempt from coverage as a "hazardous waste," and so generally speaking, the oil
and gas the Company produces is not subject to CERCLA. However, some products
used in the exploration and production of oil and gas do constitute CERCLA
"hazardous substances" when disposed of, and therefore could subject the Company
to some degree of CERCLA liability. Notwithstanding that, given the fact that
the Company has only been engaged in the exploration for oil and gas since 1985,
any potential CERCLA liability is not anticipated to have a material adverse
impact on the Company.

         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.

         The Oil Pollution Act of 1990, as amended by the Coast Guard
Authorization Act of 1996, (collectively, "OPA"), and regulations thereunder,
impose a variety of requirements on "responsible parties" related to the
prevention of oil spills and liability for damages resulting from such spills in
"waters of the United States." A "responsible party" includes the owner or
operator of a facility or vessel, or the lessee or permittee of the area in
which an offshore facility is located. The term "waters of the United States"
has been broadly defined to include not only the waters of the Gulf of Mexico
but also inland water bodies, including wetlands, playa lakes and intermittent
streams. The OPA also requires owners and operators of offshore facilities to
establish and maintain evidence of oil-


                                      -14-
<PAGE>   16
spill financial responsibility ("OSFR") for costs attributable to oil spills.
Under the Coast Guard Authorization Act of 1996, the definition of offshore
facility includes facilities located in coastal inland waters, such as bays or
estuaries. OPA requires a minimum of $35 million in OSFR for offshore facilities
located on the Outer Continental Shelf and a minimum of $10 million for offshore
facilities located landward of the seaward boundary of a state. This amount is
subject to upward regulatory adjustment up to $150 million. Parties responsible
for more than one offshore facility are required to provide OSFR only for their
offshore facility requiring the highest OSFR. Regulations promulgated by the MMS
have established the amount of OSFR to be required for particular facilities,
dependent on the volume of a facility's worst-case oil spill. Accordingly, for
Outer Continental Shelf facilities with worst-case spills of less than 35,000
barrels, only $35 million in OSFR will be required; for worst-case spills of
over 35,000 barrels, but less than 70,000 barrels, $70 million will be required;
for worst-case spills of over 70,000 barrels, but not more than 105,000 barrels,
$105 million will be required; and for worst-case spills of over 105,000
barrels, $150 million will be required. In addition, all OSFR below $150 million
remains subject to upward regulatory adjustment if warranted by the particular
operational, environmental, human health or other risks involved with a
facility. Although the current environmental regulations have had no material
adverse effect of the Company, the impact of unknown future environmental
regulatory developments, such as stricter environmental regulation and
enforcement policies, cannot presently be quantified.

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

         The Federal Water Pollution Control Act ("FWPCA") imposes restrictions
and strict controls regarding the discharge of pollutants, including produced
waters, sands and other oil and gas wastes into navigable waters. Permits must
be obtained to discharge such pollutants to state and federal waters. The FWPCA
provides for civil, criminal and administrative penalties for any unauthorized
discharges of oil and other hazardous substances in reportable quantities and,
along with the OPA, imposes substantial potential liability for the costs of
removal, remediation and damages. State laws for the control of water pollution
also provide varying civil, criminal and administrative penalties and
liabilities in the case of a discharge of petroleum or its derivatives into
state waters. After January 1, 1997, with few exceptions, the U.S. Environmental
Protection Agency ("EPA") general permit applicable to coastal waters in
Louisiana and Texas prohibits the discharge of produced water and produced sand
derived from oil and gas point source facilities. In addition, some oil and gas
exploration and production facilities are required to obtain permits for their
storm water discharges. Costs may be associated with treatment of wastewater or
developing storm water pollution prevention plans. Further, the Coastal Zone
Management Act authorizes state implementation and development of programs of
management measures for nonpoint source pollution to restore and protect coastal
waters.

         The Federal Clean Air Act ("CAA") and similar state laws that regulate
emissions of pollutants to the air, affect oil and gas production. Specifically,
the OCSLA has required MMS to promulgate and administer regulations that comply
with the National Ambient Air Quality Standards ("NAAQS") pursuant to the CAA,
and to the extent that authorized activities significantly affect the air
quality of any state. In addition, pursuant to the CAA, for Outer Continental
Shelf air emission sources located within 25 miles of a state's seaward
boundaries, the requirements are the same as the requirements that would be
applicable if the source were located in the corresponding onshore area. For
sources located beyond the 25 miles of a state's boundaries, the sources are
subject to federal requirements of


                                      -15-
<PAGE>   17
the CAA's Prevention of Significant Deterioration ("PSD") program. The costs of
compliance with these CAA requirements have not and are not anticipated to have
a material adverse impact on the Company's financial conditions and operations.

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

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.

         WE MAY BE REQUIRED TO TAKE ADDITIONAL 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.

         Primarily as a result of weak natural gas prices, we recorded a
writedown in the carrying value of our natural gas and oil properties for the
year ended December 31, 1998 in the amount of $130 million ($84.5 million after
tax). Although prices have recently recovered, we cannot make assurances that we
will not be required to take additional writedowns in future periods.

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

         Our business is capital intensive and, to maintain our base of proved
oil and gas reserves, a significant amount of cash flow from operations must be
invested in property acquisitions, development and exploration activities. We
make and will continue to make substantial capital expenditures to find,
develop, acquire and produce


                                      -16-
<PAGE>   18
natural gas and oil reserves. Our capital expenditure budget for exploration,
development and leasehold acquisitions for 2000 is estimated at approximately
$125 million. This budget excludes potential property acquisitions. Our
management believes that we will have sufficient cash provided by operating
activities and borrowings under our bank credit facility to fund planned capital
expenditures in 2000. 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 cannot make assurances that debt or equity financing, cash
generated by operations or our borrowing capacity under our revolving bank
credit facility will be available to meet our capital requirements.

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

         Our outstanding indebtedness at December 31, 1999 was $361 million,
which includes $80 million in current maturities under the KeySpan credit
facility, and as of March 22, 2000 has remained unchanged. Our outstanding
indebtedness is expected to decrease by $80 million upon the planned conversion
of the outstanding borrowings under the KeySpan credit facility on March 31,
2000 into shares of the Company's common stock.

         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 certain financial tests and
establish other restrictions that limit our ability to borrow additional funds
or dispose of assets and may 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. We cannot guarantee that our future performance will not be
adversely affected by such economic conditions and financial, business and other
factors.

         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
will require significant expenditures. If our cash flow from operations is not
sufficient for this purpose, we may not be able to obtain the necessary funds
from other sources. The inability to replace reserves could reduce the amount of
credit available to us 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.


                                      -17-
<PAGE>   19
         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.

         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 and other factors. 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. Inspections may not always be performed 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.

         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; and
counterparties to our futures contract will be unable to meet the financial
terms of the transaction.

         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 KEYSPAN.

         KeySpan currently owns 64% of our common stock and is expected to own
approximately 70% of our common stock upon the planned conversion of the $80
million outstanding under the KeySpan credit facility on March 31, 2000.
Conflicts of interest may arise in the future between us and KeySpan in a number
of areas relating to our past and ongoing relationships, including the
following:

         o        the payment of dividends;
         o        acquisitions of natural gas and oil businesses or properties;
         o        transfers of assets;
         o        insurance matters;
         o        financial commitments;
         o        registration rights; and
         o        issuances and sales of our capital stock.

         Our Chairman of the Board, Robert B. Catell, is also the Chairman of
the Board of Directors and Chief Executive Officer of KeySpan. In addition to
Mr. Catell, two of our seven other directors are also affiliated with KeySpan:
Craig G. Matthews is President and Chief Operating Officer of KeySpan and James
Q. Riordan is a director of KeySpan. As a result of KeySpan's ownership of a
majority of our common stock, KeySpan is in a position to control the election
of the entire Board of Directors of Houston Exploration and is able to control
the outcome of the vote on all matters requiring the vote of our stockholders.

EMPLOYEES

         As of December 31, 1999, the Company had 109 full time employees, 73 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."


                                      -19-
<PAGE>   21
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.

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, 1999.

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, 1998 through December
31, 1999 as reported on the New York Stock Exchange:


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

YEAR ENDED DECEMBER 31, 1998                             HIGH           LOW
                                                       ---------      --------
First Quarter......................................... $  23.000      $ 14.875
Second Quarter........................................    24.563        20.000
Third Quarter.........................................    24.250        14.125
Fourth Quarter........................................    19.875        16.375
</TABLE>

         As of March 22, 2000, 23,923,020 shares of common stock were
outstanding and the Company had approximately 49 stockholders of record and
approximately 1,500 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, 1999. 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,
                                             -------------------------------------------------------------------
                                                 1999          1998          1997          1996          1995
                                             ------------  ------------   -----------   -----------  -----------
                                                             (IN THOUSANDS, EXCEPT PER SHARE DATA)
<S>                                          <C>           <C>            <C>           <C>          <C>
CONSOLIDATED STATEMENT OF OPERATIONS DATA:
Revenues:
  Natural gas and oil revenues.............. $    150,580  $    127,124   $   116,349   $    64,864  $    39,431
  Other.....................................        1,147         1,123         1,297         1,040        1,778
                                             ------------  ------------   -----------   -----------  -----------
        Total revenues......................      151,727       128,247       117,646        65,904       41,209
Expenses:
  Lease operating...........................       18,406        16,199        14,146        10,800        5,005
  Severance tax.............................        5,444         4,967         4,233         1,401          463
  Depreciation, depletion and amortization..       74,051        79,838        59,081        33,732       21,969
  Writedown in carrying value...............           --       130,000            --            --           --
  General and administrative, net...........        4,150         6,086         5,825         6,249        3,486
  Nonrecurring charge(1)....................           --            --            --            --       12,000
                                             ------------  ------------   -----------   -----------  -----------
        Total operating expenses............      102,051       237,090        83,285        52,182       42,923
Income (loss) from operations...............       49,676      (108,843)       34,361        13,722       (1,714)
Interest expense, net.......................       13,307         4,597           938         2,875        2,398
                                             ------------  ------------   -----------   -----------  -----------
Income (loss) before income taxes...........       36,369      (113,440)       33,423        10,847       (4,112)
Income tax provision (benefit)..............       11,748       (40,754)       10,173         2,205       (3,809)
                                             ------------  ------------   -----------   -----------  -----------
Net income (loss)........................... $     24,621  $    (72,686)  $    23,250   $     8,642  $      (303)
                                             ============  ============   ===========   ===========  ===========

Net income (loss) per share................. $       1.03  $      (3.05)  $      1.00   $      0.49  $     (0.02)
                                             ============  ------------   ===========   ===========  ===========
Net income (loss) per share--diluted........ $       0.95  $      (3.05)  $      0.97   $      0.49  $     (0.02)
                                             ============  ============   ===========   ===========  ===========

Weighted average shares.....................       23,906        23,768        23,337        17,532       15,295
Weighted average shares--diluted............       28,310        23,768        24,028        17,687       15,295
</TABLE>

<TABLE>
<CAPTION>
                                                                    AT YEAR END DECEMBER 31,
                                             -------------------------------------------------------------------
                                                 1999          1998          1997          1996           1995
                                             ------------  ------------   -----------   -----------   ----------
                                                                        (IN THOUSANDS)
<S>                                          <C>           <C>            <C>           <C>           <C>
CONSOLIDATED BALANCE SHEET DATA:
Property, plant and equipment, net.......... $    610,116  $    536,582   $   443,738   $   359,124   $  216,678
Total assets................................      678,483       569,452       491,391       401,285      247,496
Long-term debt and notes....................      281,000       313,000       113,000        65,000       71,862
Stockholders' equity........................      217,590       192,530       256,187       233,300      103,236
</TABLE>

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

(1)      Represents a nonrecurring non-cash charge incurred in connection with
         Brooklyn Union's February 1996 reorganization of its exploration and
         production assets. The $12 million non-cash charge represents
         remuneration to which certain employees of Fuel Resources Inc. (a
         subsidiary of Brooklyn Union) were entitled for the increase in the
         value of the properties transferred to Houston Exploration pursuant to
         the reorganization.




                                      -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, 1999. 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 exploratory drilling in the Gulf of Mexico
and lower risk, exploitation and development drilling onshore. At December 31,
1999, the Company had net proved reserves of 541 Bcfe, 97% of which were natural
gas and 75% 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, 1999, THEC Holdings Corp., an indirect wholly owned
subsidiary of KeySpan, owned approximately 64% of the outstanding shares of
Houston Exploration's common stock. KeySpan is a diversified energy provider
that (i) distributes natural gas to a customer base of 1.6 million New Yorkers
in Brooklyn, Long Island, Queens and Staten Island; (ii) is contracted by Long
Island Power Authority to manage electricity service to about 1 million
customers in the Long Island area; and (iii) through its unregulated
subsidiaries, is involved in gas retailing, power plant management and energy
management services.

         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 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, 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.


                                      -22-
<PAGE>   24
         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 ("FASB") issued Statement of Financial Accounting Standards
("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging
Activities." This statement broadens the definition of a derivative instrument
and establishes accounting and reporting standards requiring that every
derivative instrument, including certain derivative instruments embedded in
other contracts, be recorded in the balance sheet as either an asset or
liability measured at its fair market value. Derivatives that are not hedges
must be adjusted to fair value currently in earnings. If a derivative is a
hedge, depending on the nature of the hedge, special accounting allows changes
in fair value of the derivative to be either offset against the change in fair
value of the hedged asset or liability in the income statement or recorded in
comprehensive income until the hedged item is recognized in earnings. The
Company must formally document, designate and assess the effectiveness of
transactions that are recorded as hedges. The ineffective portion of a hedged
derivative's change in fair value will be immediately recognized in earnings. In
June 1999, the FASB issued SFAS No. 137, which extends the adoption requirement
of SFAS No. 133 from January 1, 2000 to January 1, 2001. The Company plans to
adopt SFAS No. 133 effective January 1, 2001. Currently, the Company cannot
quantify the impact of the statement on results of future operations; however,
it believes that the impact will not be material.

         Year 2000. Year 2000 issues result from the inability of computer
systems, software programs or computerized equipment with embedded data chips to
accurately calculate, store or use a date beyond December 31, 1999. Typically
the year 2000 is represented as the year 1900. The problem of an erroneous date
could result in a system failure or possible miscalculations causing disruptions
of operations, including, among other things, a temporary inability to process
transactions, send invoices or engage in normal business.

         The Company established a year 2000 project plan that, together with
external consultants, developed a process for addressing the year 2000 issue.
The project plan included performing an inventory, an assessment, the
remediation and testing of its all critical financial and operational systems
and equipment that contain embedded technology, as well as obtaining assurances
from all key third parties as to their own year 2000 preparedness. For the years
ended December 31, 1999 and 1998, the Company spent approximately $75,000 and
$20,000, respectively, for system and equipment remediation and replacement. The
Company does not expect to incur any material costs relating to year 2000 issues
subsequent to December 31, 1999.

         As of March 22, 2000, all of the Company's critical financial and
operational systems and equipment have been tested for year 2000 compliance and
the Company has not experienced any significant problems with its critical
systems or with any key third parties. Although the Company has not experienced
any significant year 2000 problems to date, the Company plans to monitor its
critical systems closely. The Company cannot be sure that it will be completely
successful in its efforts to address the year 2000 issue or that problems
arising from the year 2000 issue will not cause a material adverse effect on the
Company's operating results or financial condition. The Company believes,
however, that the most reasonably likely worst-case scenario would relate to
problems with the systems of third parties rather than its with internal
systems. The Company is limited in its efforts to address the year 2000 issue as
it relates to third parties and relies solely on the assurances of these third
parties as to their year 2000 preparedness.

         As part of the Company's year 2000 project plan, the Company has
established a contingency plan in the event its financial or operational systems
experience failure or malfunction due to year 2000 issues. The Company's
contingency plan will allow employees to manually complete otherwise automated
tasks or calculations. The Company believes that the potential impact, if any,
of a system failure or malfunction due to year 2000 issues will not affect the
Company's ability to continue oil and gas exploration, drilling, production and
sales activities.


                                      -23-
<PAGE>   25
However, there can be no guarantee that the Company, its business partners,
vendors or customers will successfully be able to identify and remedy all
potential year 2000 problems and that a resulting system failure would not have
a material adverse effect on the Company.

Recent Developments

         Review of Strategic Alternatives. In September 1999, the Company and
KeySpan, the Company's majority shareholder, announced their intention to review
strategic alternatives for KeySpan's investment in Houston Exploration. A full
range of strategic transactions was considered including the sale of all or a
portion of Houston Exploration. On February 25, 2000, the Company and KeySpan
jointly announced that the strategic review process was complete and that
KeySpan plans to retain its equity interest in Houston Exploration for the
foreseeable future.

         KeySpan Credit Facility. On February 25, 2000, the Company and KeySpan
announced their intention to convert the outstanding borrowings of $80 million
under the $150 million subordinated revolving credit facility with KeySpan (the
"KeySpan Facility") into shares of common stock of the Company on March 31,
2000. The conversion price will be calculated by averaging the closing prices of
the Company's common stock on the 20 consecutive trading days ending three
trading days prior to March 31, 2000. The Company estimates that between 4
million and 5 million shares of its common stock will be issued to KeySpan and
that KeySpan's ownership interest will increase from approximately 64% to
approximately 70%. Once the planned conversion is complete, the KeySpan Facility
will terminate and the Company will have no further borrowing capacity under the
KeySpan Facility.

         KeySpan Joint Venture. On February 25, 2000, the Company and KeySpan
agreed to amend their joint exploration agreement (the "KeySpan Joint Venture").
The amendment will be effective January 1, 2000 and will provide a commitment by
KeySpan for the year 2000 of approximately $30 million and a reduction to the
amount the Company will receive during 2000 for general and administrative
expense reimbursements. The $30 million commitment will include approximately
$18 million for exploratory drilling, $10 million for development of 1999
discoveries and the balance for general and administrative reimbursements.

         Revolving Credit Facility. Chase Bank of Texas has completed its
semi-annual borrowing base redetermination for the Company's revolving credit
facility and has recommended to the syndicate of lenders that the borrowing base
be set at $210 million, effective March 29, 2000. The Company anticipates that
the borrowing base will be set at $210 million. The Company's borrowing
threshold amount will be equal to the new borrowing base which will be in effect
from March 29, 2000 until the next scheduled redetermination on September 1,
2000. As of March 22, 2000, outstanding borrowings and letters of credit under
the revolving bank credit facility have remained unchanged at $181.4 million.


                                      -24-
<PAGE>   26

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,
                                                  ---------------------------
                                                   1999       1998      1997
                                                  ------     ------    ------
<S>                                               <C>        <C>       <C>
PRODUCTION:
    Natural gas (MMcf)..........................  69,679     61,479    50,310
    Oil (MBbls).................................     258        225       171
    Total (MMcfe)...............................  71,227     62,829    51,336

AVERAGE SALES PRICES:
    Natural gas (per Mcf) realized(1)........... $  2.10    $  2.02   $  2.25
    Natural Gas (per Mcf) unhedged..............    2.14       1.96      2.45
    Oil (per Bbl)...............................   16.41      12.18     18.33

EXPENSES (PER MCFE):
    Lease operating............................. $  0.26    $  0.26   $  0.28
    Severance tax...............................    0.08       0.08      0.08
    Depreciation, depletion and amortization        1.04       1.27      1.15
    Writedown in carrying value of
         natural gas and oil properties........       --       2.07        --
    General and administrative, net.............    0.06       0.10      0.11
</TABLE>

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

(1)      Reflects the effects of hedging.

RECENT FINANCIAL AND OPERATING RESULTS

COMPARISON OF THE YEAR 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 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


                                      -25-
<PAGE>   27
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.

         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


                                      -26-
<PAGE>   28
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.

COMPARISON OF YEARS ENDED DECEMBER 31, 1998 AND 1997

         Production. Houston Exploration's production increased 22% from 51,336
MMcfe in 1997 to 62,829 MMcfe in 1998. The increase in production was
attributable to added production from the continued successful development
drilling program in the Charco Field and the addition of new production from
wells acquired in South Louisiana in April 1998. Seventeen new wells were
brought on-line in the Charco Field during 1998 and daily production, net to the
Company's interest, increased approximately 52% from an average of 54 MMcfe per
day during 1997, to an average of 82 MMcfe per day during 1998. The onshore
production growth, however, was offset by offshore production curtailments
caused by tropical storms Charlie and Frances and hurricanes Earl and Georges
during August and September 1998. In addition to shut-ins for tropical weather,
High Island 38 encountered mechanical problems and was shut-in the first week of
August 1998. High Island 38 came on-line in January 1998 and was producing
approximately 10 MMcfe per day, net to the Company's interest. The combination
of tropical weather, mechanical problems and natural reservoir decline caused
offshore production to drop from an average of 60 MMcfe per day during 1997 to
56 MMcfe per day during 1998.

         Natural Gas and Oil Revenues. Natural gas and oil revenues increased 9%
from $116.3 million in 1997 to $127.1 million in 1998 as a result of the 22%
increase in production offset in part by a 10% decrease in average realized
natural gas prices, from $2.25 per Mcf in 1997 to $2.02 per Mcf for the year
ended 1998.

         As a result of hedging activities, the Company realized an average gas
price of $2.02 per Mcf for 1998, which was 103% of the $1.96 per Mcf that
otherwise would have been received, resulting in a $3.8 million increase in
natural gas revenues for the year ended December 31, 1998. During 1997, the
average realized gas price was $2.25 per Mcf which was 92% of the unhedged
average gas price of $2.45, resulting in a decrease in natural gas revenues of
$9.9 million for the year ended 1997.

         Lease Operating Expenses and Severance Tax. Lease operating expenses
increased 15% from $14.1 million in 1997 to $16.2 million in 1998. On an Mcfe
basis, lease operating expenses decreased from $0.28 in 1997 to $0.26 in 1998.
The increase in lease operating expenses during 1998 is attributable to the
continued expansion of operations in the Charco Field, combined with new
offshore producing properties and the addition of the South Louisiana properties
acquired in April 1998 and the effect of higher overall costs in the service
industry. The decrease in the lease operating expenses per Mcfe resulted from
the increase in production during 1998. Severance tax, which is a function of
volume and revenues generated from onshore production, increased 19% from $4.2
million, or $0.07 per Mcfe, in 1997 to $5.0 million, or $0.08 per Mcfe, in 1998.
The increase in both the severance tax expense and the rate per Mcfe is due to
the increase in the Company's onshore production from the Charco Field and the
addition of the onshore South Louisiana properties acquired in April, October
and November 1998.

         Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased 35% from $59.1 million in 1997 to $79.8 million
in 1998. Depreciation, depletion and amortization expense per Mcfe increased 10%
from $1.15 in 1997 to $1.27 in 1998. The increase in depreciation, depletion and
amortization expense was a result of the increased production from acquired, as
well as newly developed, properties combined with an increased depletion rate.
The increase in the depletion rate is attributable to higher costs for drilling
goods and services and a higher level of capital spending in 1998 as compared to
1997.

         Writedown in Carrying Value of Natural Gas and Oil Properties. At
December 31, 1998, the Company was required under full cost accounting rules to
write down the carrying value of its natural gas and oil properties primarily as
a result of weak natural gas prices. The Company incurred a $130.0 million
non-cash charge, $84.5 million after taxes. The Company based its ceiling test
determination on a February 1999 wellhead price of $1.61 per Mcf.


                                      -27-
<PAGE>   29
         General and Administrative Expenses. General and administrative
expenses, net of overhead reimbursements received from other working interest
owners of $0.9 million and $1.1 million, in 1997 and 1998, respectively,
increased 5% from $5.8 million in 1997 to $6.1 million in 1998. The increase in
general and administrative expense reflects continued growth and expansion of
the Company and its operations. As the Company continues to grow and expand its
operations and workforce, the Company expects aggregate general and
administrative expenses to increase. The Company capitalized general and
administrative expenses directly related to oil and gas exploration and
development activities of $7.2 million and $7.5 million, respectively, in 1997
and 1998. The increase in capitalized general and administrative expense
directly corresponds with the growth of the Company's technical workforce and
the continued expansion of exploration and drilling operations. On an Mcfe
basis, general and administrative expenses decreased 10% from $0.11 in 1997 to
$0.10 in 1998. The lower rate per Mcfe during 1998 reflects the increase in the
Company's production.

         Interest Expense, Net. Interest expense, net of capitalized interest,
increased from $0.9 million in 1997 to $4.6 million in 1998. Capitalized
interest increased from $5.9 million in 1997 to $9.8 million in 1998. The
increase in aggregate interest expense was attributable to higher average debt
levels during 1998. Interest expense was greater in 1998 as compared to 1997 due
to with the issuance of $100 million of senior subordinated indebtedness in
March 1998 and borrowings of $80 million on a revolving credit facility
established with KeySpan in November 1998.

         Income Tax Provision. The provision for income taxes decreased from an
expense of $10.2 million in 1997 to a benefit of $40.7 million in 1998. The
expense in 1997 reflects income before taxes of $33.4 million in 1997, compared
to a loss before taxes of $113.4 million in 1998, that was primarily
attributable to the $130.0 million writedown in carrying value of natural gas
and oil properties. The tax benefit from the utilization of Section 29 tax
credits was $1.2 million in 1997 compared to $1.0 million in 1998.

         Operating Income (Loss) and Net Income (Loss). Operating income
decreased from income of $34.4 million in 1997 to a loss of $108.8 million in
1998. Excluding the $130.0 million writedown in natural gas and oil properties,
operating income would have reflected a decrease of 38% from $34.4 million in
1997 to $21.2 million in 1998. Despite a 22% increase in production during 1998,
operating income declined as a result of lower natural gas prices, higher
operating expenses, primarily depreciation, depletion and amortization expense,
and higher levels of interest expense. Net income decreased from income of $23.3
million in 1997 to a loss of $72.7 million in 1998. Excluding the $84.5 million
after tax effect of the writedown in natural gas and oil properties, net income
would have been $11.8 million for 1998 compared to $23.3 million in 1997, a
decrease of 49%.

LIQUIDITY AND CAPITAL RESOURCES

         The Company has historically funded its operations, acquisitions,
capital expenditures and working capital requirements from cash flows from
operations, bank borrowings and, prior to its 1996 initial public offering of
common stock, capital contributions from KeySpan. On March 2, 1998, the Company
issued $100 million of 85/8% senior subordinated notes. Net proceeds of
approximately $97 million were used to repay a portion of the outstanding
borrowings under the Company's revolving bank credit facility (the "Credit
Facility"). In November of 1998, the Company established a $150 million
subordinated revolving credit facility with KeySpan (the "KeySpan Facility") and
borrowed $80 million under this facility to fund a portion of the November 1998
acquisition of producing natural gas and oil properties in the Gulf of Mexico
from Chevron U.S.A. Inc. (the "Chevron Acquisition").

         On February 25, 2000, the Company and KeySpan announced their intention
to convert the outstanding borrowing of $80 million under the KeySpan Facility
into shares of common stock of the Company on March 31, 2000. The conversion
price will be calculated by averaging the closing prices of the Company's common
stock on the 20 consecutive trading days ending three trading days prior to
March 31, 2000. The Company estimates that between 4 million and 5 million
shares of its common stock will be issued to KeySpan and that KeySpan's
ownership interest will increase from approximately 64% to approximately 70%.
Once the planned conversion is


                                      -28-
<PAGE>   30
complete, the KeySpan Facility will terminate and the Company will have no
further borrowing capacity under the KeySpan Facility.

         As of December 31, 1999, the Company had a working capital deficit of
$71.2 million, which includes current maturities of $80 million outstanding
under the KeySpan Facility which are due March 31, 2000. As of December 31,
1999, the Company had $58.6 million of borrowing capacity available under the
Credit Facility. Net cash provided by operating activities for the year ended
December 31, 1999 was $110.1 million compared to $102.4 million for
corresponding period of 1998. The increase in working capital during 1999 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 drilling activity. The Company's cash position was increased during
1999 by a net increase in borrowings under the Credit Facility of $48 million.
Funds used in investing activities consisted of $147.7 million for investments
in property and equipment, which includes $21 million for the acquisition of a
64% working interest in West Cameron 587. As a result of these activities, cash
and cash equivalents increased $10.9 million from $4.6 million at December 31,
1998 to $15.5 million at December 31, 1999. The Company's available cash balance
at December 31, 1999 of $15.5 million is relatively higher than normal due to
interest payments due in January 2000 on the $100 million 8 5/8% senior
subordinated notes and on the Credit Facility.

         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,
                                                    ----------------------------------
                                                      1999         1998         1997
                                                    --------     --------     --------
                                                              (IN THOUSANDS)
<S>                                                 <C>          <C>          <C>
Net cash provided by operating activities........   $110,072     $102,378     $ 97,292
Net long-term borrowings.........................     48,000      200,000       48,000
Proceeds from sale of common stock, net..........        439          207          297
</TABLE>


         Natural Gas and Oil Capital Expenditures. Over the past three years,
the Company has spent $594 million (including $21 million in 1999 for an
interest in West Cameron Block 587 and $162.9 million in 1998 for the Chevron
and South Louisiana Acquisitions with no acquisitions in 1997) to add 405 Bcfe
of net proved reserves, representing a three-year average finding and
development cost of $1.37 per Mcfe.


                                      -29-
<PAGE>   31
         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,
                                                        ------------------------------
                                                          1999       1998       1997
                                                        --------   --------   --------
                                                                (IN THOUSANDS)
<S>                                                     <C>        <C>        <C>
OFFSHORE:
Acquisitions and leasehold...........................   $ 42,246   $109,209   $ 30,700
Development..........................................     53,941     15,983     19,826
Exploration..........................................      8,450     55,381     42,219
                                                        --------   --------   --------
                                                         104,637    180,573     92,745
ONSHORE:
Acquisitions and leasehold...........................   $  5,196   $ 86,677   $  9,920
Development..........................................     34,024     35,063     39,418
Exploration..........................................      3,807        230      1,900
                                                        --------   --------   --------
                                                          43,027    121,970     51,238
                                                        --------   --------   --------
Total................................................   $147,664   $302,543   $143,983
                                                        ========   ========   ========
</TABLE>


         Future Capital Requirements. The Company's capital expenditure budget
for 2000 has been set at $125 million including $15 million for exploration, $90
million for development and facility construction and $20 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 2000. 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.

         In March 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 a term of three
years expiring December 31, 2001. Either party may terminate the KeySpan Joint
Venture at the end of the then current calendar quarter by giving thirty days
prior written notice. Houston Exploration is joint venture manager and operator.
Effective January 1, 1999, KeySpan agreed to commit up to $100 million per
calendar year and Houston Exploration agreed to commit its proportionate share
of the funds per calendar year necessary to fund a joint exploration and
development drilling program. Houston Exploration contributed all of its
undeveloped offshore leases as of January 1, 1999 to the joint venture. KeySpan
will receive 45% of Houston Exploration's working interest in all prospects to
be drilled under the program. Revenues will be shared 55% Houston Exploration
and 45% KeySpan. During the term of the KeySpan Joint Venture, KeySpan pays 100%
of actual intangible drilling costs up to a maximum of $20.7 million per year.
All additional intangible drilling costs incurred during such year are paid
51.75% by KeySpan and 48.25% by Houston Exploration. In addition, Houston
Exploration receives reimbursement of a portion of its general and
administrative costs during the term of the joint venture.

         During 1999, the Company, together with KeySpan, completed the drilling
of eight wells under the KeySpan Joint Venture, six of which were successful. At
December 31, 1999, two additional joint venture wells were drilling, and during
the first quarter of 2000, three new wells were spud. KeySpan incurred
approximately $35.6 million in drilling costs in 1999 and the Company received
$4.8 million in general and administrative reimbursements. During 2000, the
Company plans to drill approximately six offshore exploratory wells under the


                                      -30-
<PAGE>   32
terms of the KeySpan Joint Venture and to complete the development and facility
installation of the successful exploratory wells drilled in 1999.

         On February 25, 2000, the Company and KeySpan agreed to amend the
KeySpan Joint Venture. The amendment will be effective January 1, 2000 and will
provide a commitment by KeySpan for the year 2000 of approximately $30 million
and a reduction to the amount the Company will receive during 2000 for general
and administrative expense reimbursements. The $30 million commitment will
include approximately $18 million for exploratory drilling, $10 million for
development and the balance for general and administrative reimbursements.

         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.

         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, 1999, the conforming portion of the borrowing base or threshold
amount was $175 million. The Company has the option to borrow in excess of the
threshold amount up to a borrowing base of $240 million by paying an incremental
interest rate. The borrowing base will remain at $240 million until March 28,
2000. From March 29, 2000 to the next scheduled redetermination on September 1,
2000, the borrowing base will be equal to the threshold amount, which the
Company anticipates will be redetermined and set at $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, 1999 and as of March 22, 2000, $181 million
was outstanding under the Credit Facility and $0.4 million was outstanding in
letter of credit obligations.

         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 6.59%, 6.44% and 6.90%,
respectively, for the years ended December 31, 1999, 1998 and 1997.

         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


                                      -31-
<PAGE>   33
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."

         KeySpan Credit Facility. The KeySpan Facility established by the
Company and KeySpan in November 1998 provides a maximum loan commitment of $150
million. The KeySpan Facility ranks subordinate to the revolving bank credit
facility and equal in right of payment with the $100 million 8 5/8% senior
subordinated notes. Pursuant to a subordination agreement among the Company,
KeySpan and Chase, the Company may not repay any outstanding principal under the
KeySpan Facility prior to payment in full of all outstanding principal and
interest under the Credit Facility. Borrowings under the KeySpan Facility are
unsecured. On October 27, 1999, the KeySpan Facility was amended to extend the
maturity from January 1, 2000 to March 31, 2000. Any principal amount that
remains outstanding under the KeySpan Facility on March 31, 2000 will be
converted into common stock of the Company, with the number of shares to be
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. Because the
market value represents an average of the Company's common stock over twenty
consecutive trading days, ending three days prior to the maturity date of the
loan, the market price may be higher or lower than the price of the common stock
on the conversion date. Interest accrued under the KeySpan Facility is payable
monthly and borrowings bear interest at LIBOR plus 1.4%. In addition, the
Company incurs a quarterly commitment fee of 0.125% on the unused portion of the
maximum commitment and has incurred front fees of $72,000. As of December 31,
1999, outstanding borrowings under the KeySpan Facility were $80 million, all of
which were classified as current liabilities. For the years ended December 31,
1999 and 1998, the Company incurred a total $5.5 million and $0.5 million,
respectively in interest and fees to KeySpan. Borrowings were used to finance a
portion of the November 1998 acquisition of the Mustang Island A-31 Field from
Chevron USA, Inc. See Note 11 -- Acquisitions to the Company's Consolidated
Financial Statements.

         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 pari passu in right of
payment to all existing and future subordinated indebtedness including the
KeySpan Facility.


                                      -32-
<PAGE>   34
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
may limit future revenues from 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. Unrealized gains and losses on these contracts, if any, are
deferred and offset in the balance sheet against the related settlement amounts.

         As of March 22, 2000, the Company had entered into commodity price
hedging contracts with respect to its gas production as listed below. Natural
gas production during the month of February 2000 was 6,184 MMcf (6,390 MMMbtu).


<TABLE>
<CAPTION>
                                                                     COLLARS
                                                   -------------------------------------------
                                                                           NYMEX
                                                   VOLUME              CONTRACT PRICE
                 PERIOD                           (MMMBTU)    AVERAGE FLOOR    AVERAGE CEILING
--------------------------------------------      --------    -------------    ---------------
<S>                                                <C>        <C>              <C>
January 2000................................        1,860         $2.550            $3.648
February 2000...............................        1,740          2.450             3.433
March 2000..................................        3,720          2.425             2.943
April 2000..................................        4,500          2.400             2.959
May 2000....................................        4,650          2.400             2.959
June 2000...................................        4,500          2.400             2.959
July 2000...................................        4,650          2.400             2.959
August 2000.................................        4,650          2.400             2.959
September 2000..............................        4,500          2.400             2.959
October 2000................................        4,650          2.640             3.191
November 2000...............................        3,000          2.840             3.549
December 2000...............................        3,100          2.840             3.549
January  2001...............................        1,860          3.000             3.630
February 2001...............................        1,680          3.000             3.630
March 2001..................................        1,860          3.000             3.630
</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 October 2000 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).

          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


                                      -33-
<PAGE>   35
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.

         The Company periodically enters into basis swaps (either as part of a
particular hedging transaction or separately) tied to a particular NYMEX-based
transaction to eliminate basis risk. Because substantially all of the Company's
natural gas production is sold under spot contracts that have historically
correlated with the NYMEX price, the Company believes that it has no material
basis risk.

         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.

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, 1999.

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, 1999. 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, 1999.


                                      -34-
<PAGE>   36
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, 1999.

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, 1999 and 1998...........................................      F-3
Consolidated Statements of Operations for the Years Ended December 31, 1999, 1998 and 1997.............      F-4
Consolidated Statement of Stockholders' Equity for the Period from December 31, 1999 to
  December 31, 1997....................................................................................
                                                                                                             F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997.............      F-6
Notes to Consolidated Financial Statements.............................................................      F-7
Supplemental Information on Natural Gas and Oil Exploration, Development and                                 F-23
  Production Activities
Quarterly Financial Information (Unaudited).............................................................     F-27
</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-28 for a description of the exhibits
filed as a part of this report.


                                      -35-
<PAGE>   37
                                   SIGNATURES

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

                                      THE HOUSTON EXPLORATION COMPANY

                                      By:  /s/ JAMES G. FLOYD
                                         ---------------------------------------
                                           James G. Floyd
Date: March  22, 2000                      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 Director   March 22, 2000
-------------------------------------   (Principal Executive Officer)
    James G. Floyd

/s/ JAMES F. WESTMORELAND               Vice President, Chief Accounting Officer,          March 22, 2000
-------------------------------------   Comptroller and Secretary (Principal Financial
    James F. Westmoreland               Officer and Principal Accounting Officer)


/s/ ROBERT B. CATELL                    Chairman of the Board of Directors                 March 22, 2000
-------------------------------------
    Robert B. Catell

/s/ GORDON F. AHALT                     Director                                           March 24, 2000
-------------------------------------
    Gordon F. Ahalt

/s/ RUSSELL D. GORDY                    Director                                           March 20, 2000
-------------------------------------
    Russell D. Gordy

/s/ DAVID G. ELKINS                     Director                                           March 22, 2000
-------------------------------------
    David G. Elkins

/s/ CRAIG G. MATTHEWS                   Director                                           March 24, 2000
-------------------------------------
    Craig G. Matthews

/s/ JAMES Q. RIORDAN                    Director                                           March 27, 2000
-------------------------------------
    James Q. Riordan

/s/ DONALD C. VAUGHN                    Director                                           March 22, 2000
-------------------------------------
    Donald C. Vaughn
</TABLE>


                                      -36-
<PAGE>   38
                          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>   39
         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>   40
         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>   41
                          INDEX TO FINANCIAL STATEMENTS


<TABLE>
<CAPTION>
                                                                                                        Page
                                                                                                        ----
<S>                                                                                                     <C>
Report of Independent Public Accountants..............................................................   F-2
Consolidated Balance Sheets as of December 31, 1999 and 1998..........................................   F-3
Consolidated Statements of Operations for the Years Ended December 31, 1999, 1998 and 1997............   F-4
Consolidated Statement of Stockholders' Equity for the Years Ended
  December 31, 1999, 1998 and 1997....................................................................   F-5
Consolidated Statements of Cash Flows for the Years Ended  December 31, 1999, 1998 and 1997...........   F-6
Notes to Consolidated Financial Statements............................................................   F-7
</TABLE>


                                       F-1
<PAGE>   42
                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

         We have audited the accompanying consolidated balance sheets of The
Houston Exploration Company (a Delaware corporation and an indirect 64%-owned
subsidiary of KeySpan Corporation) as of December 31, 1999 and 1998, and the
related consolidated statements of operations, stockholders' equity and cash
flows for each of the three years in the period ended December 31, 1999. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

         We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

         In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of The Houston
Exploration Company, as of December 31, 1999 and 1998, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1999, in conformity with generally accepted accounting principles.


                                                ARTHUR ANDERSEN LLP


New York, New York
January 27, 2000


                                       F-2
<PAGE>   43
                         THE HOUSTON EXPLORATION COMPANY
                           CONSOLIDATED BALANCE SHEETS


<TABLE>
<CAPTION>
                                                                                            DECEMBER 31,
                                                                                    ----------------------------
                                                                                       1999             1998
                                                                                    -----------      -----------
                                                                                           (IN THOUSANDS)
<S>                                                                                 <C>              <C>
ASSETS:
Cash and cash equivalents .....................................................     $    15,502      $     4,645
Accounts receivable ...........................................................          34,917           23,050
Accounts receivable-- Affiliate ...............................................          12,315              137
Inventories ...................................................................             969              915
Prepayments and other .........................................................           1,082              754
                                                                                    -----------      -----------
          Total current assets ................................................          64,785           29,501
Natural gas and oil properties, full cost method
  Unevaluated properties ......................................................         164,377          145,317
  Properties subject to amortization ..........................................         956,484          828,168
Other property and equipment ..................................................           9,744            9,464
                                                                                    -----------      -----------
                                                                                      1,130,605          982,949
Less: Accumulated depreciation, depletion and amortization ....................        (520,489)        (446,367)
                                                                                    -----------      -----------
                                                                                        610,116          536,582
Other assets ..................................................................           3,582            3,369
                                                                                    -----------      -----------
          TOTAL ASSETS ........................................................     $   678,483      $   569,452
                                                                                    ===========      ===========
LIABILITIES:
Accounts payable and accrued expenses .........................................     $    56,004      $    32,743
Subordinated note-- Affiliate .................................................          80,000             --
                                                                                    -----------      -----------
          Total current liabilities ...........................................         136,004           32,743
Long-term debt and notes ......................................................         281,000          233,000
Subordinated note-- Affiliate .................................................            --             80,000
Deferred federal income taxes .................................................          43,736           31,027
Other deferred liabilities ....................................................             153              152
                                                                                    -----------      -----------
          TOTAL LIABILITIES ...................................................         460,893          376,922
COMMITMENTS AND CONTINGENCIES (SEE NOTE 10)
STOCKHOLDERS' EQUITY:
Common Stock, $.01 par value, 50,000 shares authorized and 23,923 shares issued
  and outstanding at December 31, 1999 and 23,897 shares issued and outstanding
  at December 31,
  1998 ........................................................................             239              239
Additional paid-in capital ....................................................         231,370          230,931
Retained earnings (deficit) ...................................................         (14,019)         (38,640)
                                                                                    -----------      -----------
          TOTAL STOCKHOLDERS' EQUITY ..........................................         217,590          192,530
                                                                                    -----------      -----------
          TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ..........................     $   678,483      $   569,452
                                                                                    ===========      ===========
</TABLE>


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


                                       F-3
<PAGE>   44
                         THE HOUSTON EXPLORATION COMPANY
                      CONSOLIDATED STATEMENTS OF OPERATIONS


<TABLE>
<CAPTION>
                                                                            YEARS ENDED DECEMBER 31,
                                                                     --------------------------------------
                                                                       1999          1998           1997
                                                                     ---------     ---------      ---------
                                                                      (IN THOUSANDS, EXCEPT PER SHARE DATA)
<S>                                                                  <C>           <C>            <C>
REVENUES:
  Natural gas and oil revenues .................................     $ 150,580     $ 127,124      $ 116,349
  Other ........................................................         1,147         1,123          1,297
                                                                     ---------     ---------      ---------
          Total revenues .......................................       151,727       128,247        117,646
OPERATING COSTS AND EXPENSES:
  Lease operating ..............................................        18,406        16,199         14,146
  Severance tax ................................................         5,444         4,967          4,233
  Depreciation, depletion and amortization .....................        74,051        79,838         59,081
  Writedown in carrying value of natural gas and oil properties           --         130,000           --
  General and administrative, net ..............................         4,150         6,086          5,825
                                                                     ---------     ---------      ---------
          Total operating expenses .............................       102,051       237,090         83,285

Income(loss) from operations ...................................        49,676      (108,843)        34,361

Interest expense, net ..........................................        13,307         4,597            938
                                                                     ---------     ---------      ---------
Income(loss) before income taxes ...............................        36,369      (113,440)        33,423
Provision(benefit) for federal income taxes ....................        11,748       (40,754)        10,173
                                                                     ---------     ---------      ---------
NET INCOME(LOSS) ...............................................     $  24,621     $ (72,686)     $  23,250
                                                                     =========     =========      =========

Net income(loss) per share .....................................     $    1.03     $   (3.05)     $    1.00
                                                                     =========     =========      =========
Net income(loss) per share-- assuming dilution .................     $    0.95     $   (3.05)     $    0.97
                                                                     =========     =========      =========
Weighted average shares outstanding ............................        23,906        23,768         23,337
Weighted average shares outstanding-- assuming dilution ........        28,310        23,768         24,028
</TABLE>


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


                                       F-4
<PAGE>   45
                         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, EXCEPT SHARE PRICE)
<S>                                        <C>           <C>            <C>            <C>
Balance January 1, 1997 ..............     $     233     $ 222,271      $  10,796      $ 233,300
Other(1) .............................          --            (660)          --             (660)
Common stock, net of issue costs(2) ..             1           296           --              297
Net income ...........................          --            --           23,250         23,250
                                           ---------     ---------      ---------      ---------
Balance January 1, 1998 ..............     $     234     $ 221,907      $  34,046      $ 256,187
Common stock, net of issue costs(2)(3)             5         9,024           --            9,029
Net loss .............................          --            --          (72,686)       (72,686)
                                           ---------     ---------      ---------      ---------
Balance January 1, 1999 ..............     $     239     $ 230,931      $ (38,640)     $ 192,530
Common stock, net of issue costs(2) ..          --             439           --              439
Net income ...........................          --            --           24,621         24,621
                                           ---------     ---------      ---------      ---------
Balance at December 31, 1999 .........     $     239     $ 231,370      $ (14,019)     $ 217,590
                                           =========     =========      =========      =========
</TABLE>

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

(1)  Non-cash charge relating to the February 1996 reorganization of KeySpan's
     natural gas and oil assets.
(2)  Common stock issued through the exercise of stock options. See Note 4--
     Stock Option Plans.
(3)  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.


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


                                       F-5
<PAGE>   46
                         THE HOUSTON EXPLORATION COMPANY
                      CONSOLIDATED STATEMENTS OF CASH FLOWS


<TABLE>
<CAPTION>
                                                                                   YEARS ENDED DECEMBER 31,
                                                                           ---------------------------------------
                                                                             1999            1998          1997
                                                                           ---------      ---------      ---------
                                                                                        (IN THOUSANDS)
<S>                                                                        <C>            <C>            <C>
OPERATING ACTIVITIES:

Net income(loss) .....................................................     $  24,621      $ (72,686)     $  23,250
Adjustments to reconcile net income to net cash provided by
  operating activities:
  Depreciation, depletion and amortization ...........................        74,051         79,838         59,081
  Writedown in carrying value of natural gas and oil properties ......          --          130,000           --
  Deferred income tax expense(benefit) ...............................        12,709        (39,714)        13,601
  Changes in operating assets and liabilities:
   (Increase) decrease in accounts receivable ........................       (24,045)        16,014         (3,356)
   (Increase) decrease in inventories ................................           (54)           350           (273)
   (Increase) decrease in prepayments and other ......................          (328)          (109)           279
   (Increase) decrease in other assets and liabilities ...............          (143)        (1,626)           (62)
   Increase (decrease) in accounts payable and accrued expenses ......        23,261         (9,689)         4,772
                                                                           ---------      ---------      ---------
Net cash provided by operating activities ............................       110,072        102,378         97,292

INVESTING ACTIVITIES:
Investment in property and equipment .................................      (147,943)      (302,685)      (145,055)
Dispositions and other ...............................................           289           --            1,360
                                                                           ---------      ---------      ---------
Net cash used in investing activities ................................      (147,654)      (302,685)      (143,695)

FINANCING ACTIVITIES:
Proceeds from long-term borrowings ...................................        64,000        312,000         79,000
Repayments of long-term borrowings ...................................       (16,000)      (112,000)       (31,000)
Proceeds from issuance of common stock, net of costs .................           439            207            297
                                                                           ---------      ---------      ---------
Net cash provided by financing activities ............................        48,439        200,207         48,297

Increase (decrease) in cash and cash equivalents .....................        10,857           (100)         1,894

Cash and cash equivalents, beginning of year .........................         4,645          4,745          2,851
                                                                           ---------      ---------      ---------
Cash and cash equivalents, end of year ...............................     $  15,502      $   4,645      $   4,745
                                                                           =========      =========      =========
Cash paid for interest ...............................................     $  23,970      $   9,452      $   6,001
                                                                           =========      =========      =========
Cash paid for taxes ..................................................     $    --        $    --        $    --
                                                                           =========      =========      =========
</TABLE>


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


                                       F-6
<PAGE>   47
                         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 exploratory drilling in the Gulf of Mexico
and lower risk, exploitation and development drilling onshore. At December 31,
1999, the Company had net proved reserves of 541 Bcfe, 97% of which were natural
gas and 75% 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, 1999, THEC Holdings Corp., an indirect wholly owned
subsidiary of KeySpan, owned approximately 64% of the outstanding shares of
Houston Exploration's common stock. KeySpan is a diversified energy provider
that (i) distributes natural gas to a customer base of 1.6 million New Yorkers
in Brooklyn, Long Island, Queens and Staten Island; (ii) is contracted by Long
Island Power Authority to manage electricity service to about 1 million
customers in the Long Island area; and (iii) through its unregulated
subsidiaries, is involved in gas retailing, power plant management and energy
management services.

         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.

         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.


                                       F-7
<PAGE>   48
                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


         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,
                                                                            -----------------------------------
                                                                              1999         1998          1997
                                                                            --------     --------      --------
                                                                           (IN THOUSANDS, EXCEPT PER SHARE DATA)
<S>                                                                         <C>          <C>           <C>
Net income (loss) .....................................................     $ 24,621     $(72,686)     $ 23,250
  Interest savings on convertible debt ................................        2,398         --            --
                                                                            --------     --------      --------
Net income (loss), as adjusted ........................................     $ 27,019     $(72,686)       23,250
                                                                            ========     ========      ========
Weighted average shares outstanding ...................................       23,906       23,768        23,337
Add dilutive securities:
  Options .............................................................          206         --             153
  Convertible debt ....................................................        4,198         --            --
  Contingent shares ...................................................         --           --             538
                                                                            --------     --------      --------
Total weighted average shares outstanding and dilutive securities .....       28,310       23,768        24,028
                                                                            ========     ========      ========

Net income (loss) per share ...........................................     $   1.03     $  (3.05)     $   1.00
Net income (loss) per share-- assuming dilution .......................     $   0.95     $  (3.05)     $   0.97
</TABLE>


         The computation of diluted EPS for the year ended December 31, 1998 did
not assume the conversion of 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, 1999 will be fully evaluated within five years.

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

         The Company limits the capitalized costs of natural gas and oil
properties, net of accumulated depreciation, depletion and amortization and
related deferred taxes to the estimated future net cash flows from proved
natural gas and oil reserves discounted at ten percent, plus the lower of cost
or fair value of unproved properties, as adjusted for


                                       F-8
<PAGE>   49
                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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, 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 cost or market value.

         General and Administrative Costs and Expenses

         The Company receives reimbursement for administrative and overhead
expenses incurred on behalf of other working interest owners on properties
operated by the Company. These reimbursements totaling $5.7 million, $1.1
million and $0.9 million for the years ended December 31, 1999, 1998 and 1997,
respectively, were allocated as reductions to general and administrative
expenses. Included in reimbursements received during 1999 is $4.8 million in
general and administrative reimbursements received from KeySpan pursuant to the
KeySpan Joint Exploration Agreement ("KeySpan Joint Venture"), see Note 6 --
Related Party Transactions. The capitalized general and administrative costs
directly related to the Company's acquisition, exploration and development
activities, during 1999, 1998 and 1997, aggregated $5.5 million, $7.5 million
and $7.2 million, respectively.


                                       F-9
<PAGE>   50
                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


         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, 1999, 1998 and 1997
interest costs of $11.9 million, $9.8 million and $5.9 million, respectively,
were capitalized.

         Gas Imbalances

         The Company incurs certain production gas volume imbalances in the
ordinary course of business and utilized the entitlements method to account for
its gas imbalances. Under this method, income is recorded based on the Company's
net revenue interest in production or nominated deliveries. Net deliveries in
excess of these amounts are recorded as liabilities, while net under deliveries
are reflected as assets. Production imbalances are valued using current market
prices. Production imbalances were not material as of December 31, 1999 and
1998.

         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 may also limit future revenues from 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 SFAS 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 instruments cease to meet the criteria
for deferral accounting, any subsequent 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 item is
recognized in revenue. Neither the hedging contracts nor the unrealized gains or
losses on these contracts are currently recognized in the financial statements.
Natural gas revenues were decreased by $2.6 million in 1999, increased by $3.8
million in 1998 and decreased by $9.9 million during 1997, relative to these
contracts. See Note 8 -- Hedging Transactions.

         From time to time the Company uses interest rate swaps to manage the
interest rate exposure arising from certain borrowings. Swaps used to hedge debt
are designated as hedges and are matched to the debt as to notional amount and
maturity. The periodic receipts or payments from each swap are recognized over
the term of the swap as an adjustment to interest expense. As of December 31,
1999, the Company had no interest rate swaps in place.

         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


                                      F-10
<PAGE>   51
                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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 ("FASB") issued
SFAS 133, "Accounting for Derivative Instruments and Hedging Activities." This
statement broadens the definition of a derivative instrument and establishes
accounting and reporting standards requiring that every derivative instrument,
including certain derivative instruments embedded in other contracts, be
recorded in the balance sheet as either an asset or liability measured at its
fair market value. Derivatives that are not hedges must be adjusted to fair
value currently in earnings. If a derivative is a hedge, depending on the nature
of the hedge, special accounting allows changes in fair value of the derivative
to be either offset against the change in fair value of the hedged asset or
liability in the income statement or recorded in comprehensive income until the
hedged item is recognized in earnings. The Company must formally document,
designate and assess the effectiveness of transactions that are recorded as
hedges. The ineffective portion of a hedged derivative's change in fair value
will be immediately recognized in earnings. In June 1999, the FASB issued SFAS
No. 137, which extends the adoption requirement of SFAS No. 133 from January 1,
2000 to January 1, 2001. The Company plans to adopt SFAS No. 133 effective
January 1, 2001. Currently, the Company cannot quantify the impact of the
statement on results of future operations; however, it believes that the impact
will not be material.

NOTE 2 -- LONG-TERM DEBT AND NOTES


<TABLE>
<CAPTION>
                                                 YEARS ENDED DECEMBER 31,
                                                    1999         1998
                                                  --------     --------
                                                      (IN THOUSANDS)
<S>                                               <C>          <C>
SENIOR DEBT:
Bank revolving credit facility ..............     $181,000     $133,000
SUBORDINATED DEBT:
85/8% Senior Subordinated Notes due 2008 ....      100,000      100,000
Subordinated Note-- KeySpan due 2000 ........         --         80,000
                                                  --------     --------
    Total long-term debt and notes ..........     $281,000     $313,000
                                                  ========     ========
</TABLE>


         As of December 31, 1999, outstanding borrowings of $80 million under
the KeySpan note were classified as current liabilities, as the note matures
March 31, 2000. The carrying amount of borrowings outstanding under the
revolving bank credit facility and the KeySpan note approximate fair value as
interest rates are tied to current market rates. At December 31, 1999, the
quoted market value of the 85/8% senior subordinated notes was 96% of the $100
million carrying value or $96 million.

         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, 1999, the conforming portion of the borrowing base or threshold
amount was $175 million. The Company has the option to


                                      F-11
<PAGE>   52
                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


borrow in excess of the threshold amount up to a borrowing base of $240 million
by paying an incremental interest rate. The borrowing base will remain at $240
million until March 28, 2000. From March 29, 2000 to the next scheduled
redetermination on September 1, 2000, the borrowing base will be equal to the
threshold amount, which the Company anticipates will be redetermined and set at
$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, 1999, $181
million was outstanding under the Credit Facility and $0.4 million was
outstanding in letter of credit obligations. As of March 22, 2000, the Company's
outstanding borrowings and letters of credit under the Credit Facility have
remained unchanged at $181.4 million.

         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 6.59%, 6.44% and 6.90%, respectively, for the years ended December 31,
1999, 1998 and 1997.

         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, 1999, the Company was in compliance with all such covenants.

         Senior Subordinated Notes

         On March 2, 1998, the Company issued $100 million of 85/8% senior
subordinated notes (the "Notes") due January 1, 2008. The Notes bear interest at
a rate of 85/8% per annum with interest payable semi-annually on January 1 and
July 1. 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
including the KeySpan Facility.


                                      F-12
<PAGE>   53
                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


         KeySpan Facility.

         On November 30, 1998, the Company entered into a revolving credit
facility with KeySpan (the "KeySpan Facility"), which provides a maximum
commitment of $150 million. The KeySpan Facility ranks subordinate to the Credit
Facility and equal in right of payment with the Subordinated Notes. Pursuant to
a subordination agreement among the Company, KeySpan and Chase, the Company may
not repay any outstanding principal under the KeySpan Facility prior to payment
in full of all outstanding principal and interest under the Credit Facility.
Borrowings under the KeySpan Facility are unsecured. On October 27, 1999, the
KeySpan Facility was amended to extend the maturity from January 1, 2000 to
March 31, 2000. Any principal amount that remains outstanding under the KeySpan
Facility on March 31, 2000 will be converted into common stock of the Company,
with the number of shares to be 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. Because the market value represents an average of the Company's common
stock over twenty consecutive trading days, ending three days prior to the
maturity date of the loan, the market price may be higher or lower than the
price of the common stock on the conversion date. Interest accrued under the
KeySpan Facility is payable monthly and borrowings bear interest at LIBOR plus
1.4%. In addition, the Company incurs a quarterly commitment fee of 0.125% on
the unused portion of the maximum commitment and has incurred upfront fees of
$72,000. As of December 31, 1999, outstanding borrowings under the facility were
$80 million, all of which were classified as current liabilities. For the years
ended December 31, 1999 and 1998, the Company incurred a total $5.5 million and
$0.5 million, respectively in interest and fees to KeySpan. Borrowings were used
to finance a portion of the November 1998 acquisition of the Mustang Island A-31
Field from Chevron USA, Inc., see Note 11 -- Acquisitions.

         On February 25, 2000, the Company and KeySpan announced their intention
to convert the outstanding borrowings of $80 million under the KeySpan Facility
into shares of common stock of the Company on March 31, 2000. The conversion
price will be calculated by averaging the closing prices of the Company's common
stock on the 20 consecutive trading days ending three trading days prior to
March 31, 2000. The Company estimates that between 4 million and 5 million
shares of its common stock will be issued to KeySpan and that KeySpan's
ownership interest will increase from approximately 64% to approximately 70%.
Once the planned conversion is complete, the KeySpan Facility will terminate and
the Company will have no further borrowing capacity under the KeySpan Facility.

NOTE 3 -- STOCKHOLDERS' EQUITY

         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.


                                      F-13
<PAGE>   54
                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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 to grant options not to exceed
10% of the shares of the Company's common stock outstanding from time to time.
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, 1999, substantially all options currently authorized under the 1996
Stock Option Plan had been granted, of which 979,330 of the options "ISOs") and
the balance of 1,354,608 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.

         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 authorized of which 111,800 options were granted during
1999. 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,
                                                  ------------------------------------------------------------------------
                                                             1999                    1998                    1997
                                                  ----------------------   ----------------------   ----------------------
                                                    SHARES        PRICE*     SHARES        PRICE*     SHARES        PRICE*
<S>                                               <C>             <C>      <C>             <C>      <C>             <C>
Options outstanding January 1 ...............      2,083,038      $17.17    1,669,598      $16.67    1,239,638      $15.53
  Granted ...................................        321,300       18.87      426,700       19.07      458,100       19.69
  Exercised .................................        (28,080)      15.56      (13,260)      15.70      (28,140)      15.50
  Forfeited .................................         (5,700)      18.56         --                       --
                                                  ----------                ---------                ---------
Options outstanding December 31 .............      2,370,558      $17.41    2,083,038      $17.17    1,669,598      $16.67
                                                  ==========                =========                =========
Exercisable December 31 .....................      1,001,343      $16.87      599,275      $16.58      268,788      $16.49
Options available for grant .................        293,238                  208,838                  635,538
Weighted average fair value of options
granted .....................................     $     8.45               $     8.54               $     8.71
</TABLE>

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

* Weighted average price.

         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 1999, 1998 and 1997, the Company
made payments of $0.6 million, $0.6 million and $0.8 million, respectively for
the vested portion of PSRs. As of December 31, 1999, 66,635 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


                                      F-14
<PAGE>   55
                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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.

         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, 1999, 1998 and 1997:


<TABLE>
<CAPTION>
                                                                          YEARS ENDED DECEMBER 31,
                                                                    -----------------------------------
                                                                     1999          1998          1997
                                                                    -------      --------       -------
                                                                   (IN THOUSANDS, EXCEPT PER SHARE DATA)
<S>                                                                 <C>          <C>            <C>
Net income (loss) - as reported .................................   $24,621      $(72,686)      $23,250
Net income (loss) - pro forma ...................................    21,915       (74,985)       21,499

Net income (loss) per share - as reported .......................   $  1.03      $  (3.05)      $  1.00
Net income (loss) per share - assuming dilution--as reported ....      0.95         (3.05)         0.97

Net income (loss) per share - pro forma .........................   $  0.92      $  (3.15)      $  0.92
Net income (loss) per share - assuming dilution-- pro forma .....      0.77         (3.15)         0.89
</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 1999, 1998 and 1997: (i) average risk-free interest rate of 5.96%,
5.97%, and 6.30%, 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:


                                      F-15
<PAGE>   56
                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


<TABLE>
<CAPTION>
                                YEARS ENDED DECEMBER 31,
                            --------------------------------
                              1999        1998        1997
                            --------    --------    --------
                                     (IN THOUSANDS)
<S>                         <C>         <C>         <C>
Current .................   $   (961)   $ (1,040)   $ (3,428)
Deferred ................     12,709     (39,714)     13,601
                            --------    --------    --------
          Total .........   $ 11,748    $(40,754)   $ 10,173
                            ========    ========    ========
</TABLE>


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

         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,
                                                               -------------------------------------
                                                                 1999          1998          1997
                                                               ---------     ---------     ---------
                                                                           (IN THOUSANDS)
<S>                                                            <C>           <C>           <C>
Income (loss) before income taxes ..........................   $  36,369     $(113,440)    $  33,423
Statutory rate .............................................          35%           35%           35%
Income tax expense (benefit) computed at statutory rate ....      12,729       (39,704)       11,698
Reconciling items:
     Section 29 tax credits ................................        (961)       (1,040)       (1,200)
     Percentage depletion ..................................         (16)          (12)          (14)
     Other .................................................          (4)            2          (311)
                                                               ---------     ---------     ---------
Tax expense (benefit) ......................................   $  11,748     $ (40,754)    $  10,173
                                                               =========     =========     =========
</TABLE>


         Deferred Income Taxes

         The components of net deferred tax liabilities pursuant to SFAS No. 109
for the years ended December 31, 1999 and 1998 primarily represent temporary
differences related to depreciation of natural gas and oil properties.

NOTE 6 -- RELATED PARTY TRANSACTIONS

         Review of Strategic Alternatives

         In September 1999, the Company and KeySpan, the Company's majority
stockholder, announced their intention to review strategic alternatives 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 was complete and
that KeySpan plans to retain its equity interest in Houston Exploration for the
foreseeable future.


                                      F-16
<PAGE>   57
                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


         KeySpan Joint Venture

         In March 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 a term of three
years expiring December 31, 2001. Either party may terminate the KeySpan Joint
Venture at the end of the then current calendar quarter by giving thirty days
prior written notice. Houston Exploration is the joint venture manager and
operator. Effective January 1, 1999, KeySpan agreed to commit up to $100 million
per calendar year and Houston Exploration agreed to commit its proportionate
share of the funds per calendar year necessary to fund a joint exploration and
development drilling program. Houston Exploration contributed all of its
undeveloped offshore leases as of January 1, 1999 to the joint venture. KeySpan
will receive 45% of Houston Exploration's working interest in all prospects to
be drilled under the program. Revenues will be shared 55% Houston Exploration
and 45% KeySpan. During the term of the KeySpan Joint Venture, KeySpan pays 100%
of actual intangible drilling costs up to a maximum of $20.7 million per year.
All additional intangible drilling costs incurred during such year are paid
51.75% by KeySpan and 48.25% by Houston Exploration. In addition, Houston
Exploration receives reimbursement of a portion of its general and
administrative costs during the term of the joint venture. During the year ended
December 31, 1999, KeySpan incurred approximately $35.6 million in drilling
costs and the Company received approximately $4.8 million in general and
administrative reimbursements pursuant to the KeySpan Joint Venture.

         On February 25, 2000, the Company and KeySpan agreed to amend the joint
exploration agreement. The amendment will be effective January 1, 2000 and will
provide a commitment by KeySpan for the year 2000 of approximately $30 million
and a reduction to the amount the Company will receive during 2000 for general
and administrative expense reimbursements. The $30 million commitment will
include approximately $18 million for exploratory drilling, $10 million for
development and the balance for general and administrative reimbursements.

         Subordinated KeySpan Facility. (See Note 2 -- Long-Term Debt and Notes
and Note 12 -- Subsequent Events).

         Sale of Section 29 Tax Credits

         Effective January 1, 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 for the years ended December 31, 1999,
1998 and 1997 was a reduction to income tax expense of approximately $1.0
million, $1.0 million and $1.2 million, respectively, representing benefits
received from the Section 29 tax credits.

         Employment Contracts

         Prior to the IPO 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. During 1999, 1998 and
1997,


                                      F-17
<PAGE>   58
                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


affiliates of the Company's President paid $2.5 million, $2.7 million and $3.3
million, respectively, in costs and expenses attributable to working interests
owned in properties operated by the Company, and received $4.7 million, $4.7
million and $3.9 million, respectively, in distributions attributable to such
working interests.

         The Initial Employment Agreement also 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 subsequent to the
year ended December 31, 1995. Upon completion of the IPO, 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 or to receive or grant assignments or after
program-payout working interests. In addition to the Company's President,
certain other key employees of the Company entered into employment agreements
upon completion of the IPO.

         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 acquired by the Company in July 1996 and 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% working interest in the Charco Field properties
acquired by the Company. 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
such working interest, as distributions are received. Amounts outstanding under
such loan bear interest at an interest rate equal to the Company's cost of
borrowing under the Credit Facility. Obligations under the agreement are secured
by a pledge of the President's working interest in, and the production from,
such properties. As of December 31, 1999 and 1998, the outstanding balance owed
by the Company's President under the loan agreement was $2.8 million and $3.5
million, respectively. The loan will mature on July 2, 2006.

         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, which will
be effective October 1, 1999, will be 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 earning from such
properties. As of October 1, 1999, the net present value, discounted at 10%, of
the properties to be 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 will be secured by Mr. Floyd's overriding royalty interests in
the Charco Field properties.


                                      F-18
<PAGE>   59
                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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 15% 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 $0.2 million in
each of the three years ended December 31, 1999, 1998 and 1997.

         Supplemental Executive 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. 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 $123,000 for each of the years ended December 31, 1999, 1998 and
1997 related to the SERP.

NOTE 8 -- HEDGING CONTRACTS

         Interest Rate Swap Agreements.

         The fair values are obtained from the financial institutions that are
counterparties to the transactions. These values represent the estimated amount
the Company would pay or receive to terminate the agreements, taking into
consideration current interest rates and the current creditworthiness of the
counterparties. The Company's interest rate swap agreements are off balance
sheet transactions and, accordingly, no respective carrying amounts for these
transactions are included in the accompanying consolidated balance sheets. As of
December 31, 1999, the Company had no interest rate swaps in place. At December
31, 1998, the Company had one interest rate swap agreement to exchange the
differential between the fixed rate of 6.025% and a market LIBOR rate using an
aggregate notional principal of $30.0 million over various 90-day periods from
November 1998 through November 1999. As of December 31, 1998, the estimated fair
value of the interest rate swap agreements was $0.4 million, in a payable
position.


                                      F-19
<PAGE>   60
                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


         Natural Gas Price Swaps, Options and Collars

         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>
                      FIXED PRICE SWAPS                     COLLARS                  FAIR VALUE
                    ----------------------     ----------------------------------   ------------
                            NYMEX                                  NYMEX
                     VOLUME       CONTRACT      VOLUME         CONTRACT PRICE
      PERIOD        (MMMBTU)       PRICE       (MMMBTU)      FLOOR       CEILING    ($ THOUSANDS)
------------------  --------      --------     --------    --------      --------   -------------
<S>                 <C>            <C>         <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>


         As of December 31, 1998, the Company had entered into commodity price
hedging contracts with respect to its production for 1999 as follows:


<TABLE>
<CAPTION>
                      FIXED PRICE SWAPS                     COLLARS                  FAIR VALUE
                    ----------------------     ----------------------------------   ------------
                            NYMEX                                  NYMEX
                     VOLUME       CONTRACT      VOLUME         CONTRACT PRICE
      PERIOD        (MMMBTU)       PRICE       (MMMBTU)      FLOOR       CEILING    ($ THOUSANDS)
------------------  --------      --------     --------    --------      --------   -------------
<S>                 <C>            <C>         <C>         <C>           <C>        <C>
January 1999           755      $    2.50         --            --            --      $    534
February 1999          355            --          280      $   2.40      $   2.90     $    126
</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"). 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. Fair market value is calculated for
the respective months using prices derived from NYMEX futures contract prices
existing at December 31, 1999 and 1998.

         The Company periodically enters into basis swaps (either as part of a
particular hedging transaction or separately) tied to a particular NYMEX-based
transaction to eliminate basis risk. Because substantially all of the


                                      F-20
<PAGE>   61
                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Company's natural gas production is sold under spot contracts that have
historically correlated with the NYMEX price, the Company believes that it has
no material basis risk.

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, 1999 to
Adams Resources and Energy, Inc. (successor to H&N Gas Ltd.) (22.5%); for the
year ended December 31, 1998 to H&N Gas Ltd. (27%) and Columbia Energy Services
Corporation (12%); and for the year ended December 31, 1997 to H&N Gas Ltd.
(38%). 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.

         Leases

         The Company has entered into certain noncancellable operating lease
agreements relative to office space and equipment with various expiration dates
through 2003. Minimum rental commitments under the terms of the leases are as
follows (in thousands):


<TABLE>
<CAPTION>
Year ended December 31,
<S>                                                     <C>
2000................................................... $     392
2001...................................................       392
2002...................................................       460
2003...................................................       554
2004...................................................       323
Thereafter.............................................        --
</TABLE>


         Net rental expense related to these leases was $0.3 million for each of
the years ended December 31, 1999, 1998 and 1997.

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. Net proved undeveloped reserves for the natural gas and oil interests
acquired are estimated at 21 Bcfe as of December 31, 1999.


                                      F-21
<PAGE>   62
                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


         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%.

NOTE 12 -- SUBSEQUENT EVENTS

         Review of Strategic Alternatives

         In September 1999, the Company and KeySpan, the Company's majority
stockholder, announced their intention to review strategic alternatives for
KeySpan's investment in Houston Exploration. A full range of strategic
transactions was considered including the sale of all or a portion of Houston
Exploration. On February 25, 2000, the Company and KeySpan jointly announced
that the strategic review process was complete and that KeySpan plans to retain
its equity interest in Houston Exploration for the foreseeable future.

         KeySpan Facility

         On February 25, 2000, KeySpan announced its intention to convert the
outstanding borrowings of $80 million under the KeySpan Facility into shares of
common stock of the Company on March 31, 2000. The conversion price will be
calculated by averaging the closing prices of the Company's common stock on the
20 consecutive trading days ending three trading days prior to March 31, 2000.
The Company estimates that between 4 million and 5 million shares of its common
stock will be issued to KeySpan and that KeySpan's ownership interest will
increase from approximately 64% to approximately 70%. Once the planned
conversion is complete, the KeySpan Facility will terminate and the Company will
have no further borrowing capacity under the KeySpan Facility.

         KeySpan Joint Venture

         On February 25, 2000, the Company and KeySpan agreed to amend the
KeySpan Joint Venture. The amendment will be effective January 1, 2000 and will
provide a commitment by KeySpan for the year 2000 of approximately $30 million
and a reduction to the amount the Company will receive during 2000 for general
and administrative expense reimbursements. The $30 million commitment will
include approximately $18 million for exploratory drilling, $10 million for
development and the balance for general and administrative reimbursements.


                                      F-22
<PAGE>   63
                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


         Credit Facility

         Chase has completed its semi annual borrowing base redetermination for
the Credit Facility and has recommended to the syndicate of lenders that the
borrowing base be set at $210 million, effective March 29, 2000. The Company
anticipates that the borrowing base will be set at $210 million. The new
borrowing base will be equal to the Company's borrowing threshold amount which
will be in effect from March 29, 2000 until the next scheduled redetermination
on September 1, 2000. As of March 22, 2000, outstanding borrowings and letters
of credit under the revolving bank credit facility have remained unchanged at
$181.4 million.

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, 1999, 1998 and 1997, the Company's capitalized costs
of natural gas and oil properties are as follows:


<TABLE>
<CAPTION>
                                                                          YEARS ENDED DECEMBER 31,
                                                                -------------------------------------------
                                                                    1999           1998            1997
                                                                ------------    -----------    ------------
                                                                                (IN THOUSANDS)
<S>                                                             <C>             <C>            <C>
Unevaluated properties, not amortized.......................... $    164,377    $   145,317    $    104,075
Properties subject to amortization.............................      956,484        828,168         566,868
                                                                ------------    -----------    ------------
Capitalized costs..............................................    1,120,861        973,485         670,943
Accumulated depreciation, depletion and amortization...........     (512,465)      (438,974)       (229,776)
                                                                ------------    -----------    ------------
          Net capitalized costs................................ $    608,396    $   534,511    $    441,167
                                                                ============    ===========    ============
</TABLE>


         The following is a summary of the costs (in thousands) which are
excluded from the amortization calculation as of December 31, 1999, 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, 1999 will be fully evaluated within five
years.


<TABLE>
<S>                                   <C>
1999................................. $ 29,894
1998.................................   66,148
1997.................................   30,691
Prior................................   37,644
                                      --------
                                      $164,377
</TABLE>


                                      F-23
<PAGE>   64
                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


         Costs incurred for natural gas and oil exploration, development and
acquisition are summarized below. Costs incurred during the years ended December
31, 1999, 1998 and 1997 include interest expense and general and administrative
costs related to acquisition, exploration and development of natural gas and oil
properties, of $17.4 million, $17.3 million and $13.1 million, respectively.


<TABLE>
<CAPTION>
                                                                         YEARS ENDED DECEMBER 31,
                                                                -------------------------------------------
                                                                   1999              1998          1997
                                                                -----------      ------------   -----------
                                                                               (IN THOUSANDS)
<S>                                                             <C>              <C>            <C>
Property acquisition:
  Unevaluated(1)............................................... $    10,337      $     33,803   $    16,613
  Proved.......................................................      37,105           162,083        24,007
Exploration costs..............................................      12,257            55,611        44,119
Development costs..............................................      87,965            51,046        59,244
                                                                -----------      ------------   -----------
          Total costs incurred................................. $   147,664      $    302,543   $   143,983
                                                                ===========      ============   ===========
</TABLE>

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

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

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

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

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

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

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

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

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


                                      F-24
<PAGE>   65
                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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

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

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

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


<TABLE>
<CAPTION>
                                                            AS OF DECEMBER 31,
                                                -----------------------------------------
                                                   1999           1998           1997
                                                -----------    -----------    -----------
                                                              (IN THOUSANDS)
<S>                                             <C>            <C>            <C>
Future cash inflows .........................   $ 1,113,844    $   878,448    $   781,336
Future production costs .....................      (190,900)      (153,567)      (135,437)
Future development costs ....................      (120,071)      (103,915)       (84,658)
Future income taxes .........................      (155,641)       (89,032)      (124,510)
                                                -----------    -----------    -----------
Future net cash flows .......................       647,232        531,934        436,731
10% annual discount for estimated timing of
cash flows ..................................      (178,007)      (135,874)      (121,351)
                                                -----------    -----------    -----------
Standardized measure of discounted future net
  cash flows ................................   $   469,225    $   396,060    $   315,380
                                                ===========    ===========    ===========
</TABLE>


         Discounted future cash inflows include the effect of hedges in place at
year end December 31, 1999, 1998 and 1997. At December 31, 1999 and 1998 the
effect of the hedges in place is an increase of $1.3 million and $0.4 million,
respectively to future cash inflows. As of December 31, 1997, the effect of the
hedges in place is a reduction to future cash inflows of $0.5 million.


                                      F-25
<PAGE>   66
                         THE HOUSTON EXPLORATION COMPANY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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


<TABLE>
<CAPTION>
                                                                        AS OF DECEMBER 31,
                                                               -----------------------------------
                                                                 1999         1998         1997
                                                               ---------    ---------    ---------
                                                                         (IN THOUSANDS)
<S>                                                            <C>          <C>          <C>
Beginning of the year ......................................   $ 396,060    $ 315,380    $ 452,582
Revisions to previous estimates:
  Changes in prices and costs ..............................      47,330     (104,137)    (223,169)
  Changes in quantities ....................................      51,375       (4,982)     (23,156)
  Changes in future development costs ......................     (25,730)      (6,656)     (20,499)
Development costs incurred during the period ...............      40,563       15,891       16,154
Extensions and discoveries, net of related costs ...........      91,383       72,333      114,893
Sales of natural gas and oil, net of production costs ......    (126,730)    (105,958)     (97,968)
Accretion of discount ......................................      41,293       37,706       57,700
Net change in income taxes .................................     (43,572)      44,812       62,733
Purchase of reserves in place ..............................      20,973      156,122        2,463
Sale of reserves in place ..................................      (2,194)        (863)        (608)
Production timing and other ................................     (21,526)     (23,588)     (25,745)
                                                               ---------    ---------    ---------
End of year ................................................   $ 469,225    $ 396,060    $ 315,380
                                                               =========    =========    =========
</TABLE>


                                      F-26
<PAGE>   67
                         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,
1999, 1998 and 1997.


<TABLE>
<CAPTION>
                                                      NATURAL GAS                  CRUDE OIL AND CONDENSATE
                                                        (MMCF)                             (MBBLS)
                                           --------------------------------    --------------------------------
                                             1999        1998        1997        1999        1998        1997
                                           --------    --------    --------    --------    --------    --------
<S>                                        <C>         <C>         <C>         <C>         <C>         <C>
Proved developed and
  undeveloped  reserves: ...............    470,447     330,601     320,474       1,650       1,077       1,131
Revisions of previous estimates ........     45,510      (4,656)    (18,743)        237        (105)        (62)
Extensions and discoveries .............     62,700      67,272      75,651         909         249         184
Production .............................    (69,679)    (61,479)    (50,310)       (258)       (225)       (171)
Purchase of reserves in place ..........     20,699     139,994       3,778           1         665           1
Sales of reserves in place .............     (3,492)     (1,285)       (249)        (69)        (11)         (6)
                                           --------    --------    --------    --------    --------    --------
End of year ............................    526,185     470,447     330,601       2,470       1,650       1,077
                                           ========    ========    ========    ========    ========    ========
Proved developed reserves:
Beginning of year ......................    369,931     256,632     236,544       1,498         914       1,013
End of year ............................    397,343     369,931     256,632       1,796       1,498         914
</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>
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

1998
Total revenues ........................................   $  33,084   $  35,511   $  30,853   $  28,799
Income (loss) from operations(1) ......................       7,208       8,700       3,927    (128,678)
Net income (loss) from operations(1) ..................       4,723       5,306       2,003     (84,718)

Net income (loss) per share ...........................   $    0.20   $    0.22   $    0.08   $   (3.55)
Net income (loss) per share-- assuming dilution .......   $    0.20   $    0.22   $    0.08   $   (3.55)
</TABLE>

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

(1)      Includes a fourth quarter 1998 non-cash charge for the writedown in the
         carrying value of natural gas and oil properties of $130.0 million,
         $84.5 million after taxes, as required under full cost accounting
         rules. See Note 1 -- Natural Gas and Oil Properties.


                                      F-27

<PAGE>   68
                                INDEX TO EXHIBITS


<TABLE>
<CAPTION>
EXHIBITS                                      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).
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 85/8% Senior Subordinated Notes Due
                    2008 (including form of 85/8% Senior Subordinated Note Due 2008) (incorporated by
                    reference to Exhibit 4.1 to 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).
</TABLE>


<PAGE>   69
                                INDEX TO EXHIBITS


<TABLE>
<CAPTION>
EXHIBITS                                      DESCRIPTION
--------                                      -----------
<S>              <C>
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(1)            -- First Amendment to Subordinated Loan Agreement and
                    Promissory Note between KeySpan Corporation and The Houston
                    Exploration Company dated effective as of October 27, 1999.
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(1)         -- First Amendment to the Exploration Agreement between The Houston Exploration Company
                    and KeySpan Exploration and Production, L.L.C. dated November 3, 1999.
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).
10.23(1)         -- 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.
10.24(1)(2)      -- 1999 Non-Qualified Stock Option Plan dated October 26, 1999.
10.25(1)(2)      -- Change of Control Plan dated October 26, 1999.
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.
27.1(1)          -- Financial Data Schedule.
</TABLE>

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

(1)      Filed herewith.
(2)      Management contract or compensation plan.