HOUSTON EXPLORATION CO - 10-K Annual Report

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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, 2002
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NO. 001-11899

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

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

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

(713) 830-6800
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

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]

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

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

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

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

PART I.

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

OVERVIEW AND ORGANIZATION

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

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

We began exploring for natural gas and oil in December 1985 on behalf of
The Brooklyn Union Gas Company. Brooklyn Union is an indirect wholly owned
subsidiary of KeySpan Corporation. KeySpan, a member of the Standard & Poor's
500 Index, is a diversified energy provider whose principal natural gas
distribution and electric generation operations are located in the Northeastern
United States. In September 1996 we completed our initial public offering and
sold approximately 34% of our shares to the public with KeySpan retaining the
balance. As of December 31, 2002, THEC Holdings Corp., an indirect wholly owned
subsidiary of KeySpan, owned approximately 66% of the outstanding shares of our
common stock.

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

2002 OPERATING HIGHLIGHTS

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

-1-

INVESTMENT STRATEGY

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

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

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

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

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

OPERATING PHILOSOPHY

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

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

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

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

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

-2-

2002 OPERATIONS REVIEW

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

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

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

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

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

-3-

ACQUISITIONS

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

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

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

OTHER RECENT DEVELOPMENTS

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

Severance Tax Refund. During July 2002, we applied for and received from the
Railroad Commission of Texas a "high-cost/tight-gas formation" designation for a
portion of our South Texas production. The "high-cost/tight-gas formation"
designation will allow us to receive an abatement of severance taxes for
qualifying wells in various fields. For qualifying wells, production will be
either exempt from tax or taxed at a reduced rate until certain capital costs
are recovered. For qualifying wells, we will also be entitled to a refund of
severance taxes paid during a designated prior 48-month period.

-4-

Applications for refund are submitted on a well-by-well basis to the State
Comptroller's Office and due to timing of the acceptance of applications, we are
unable to project the 48-month look-back period for qualifying refunds. We
currently estimate that the total refund, for 2002 and prior periods, will be
between $18 million to $23 million ($12 million to $15 million, net of tax),
although we can provide no assurances that the actual total refund amount will
fall within our current estimate. During the fourth quarter of 2002, we recorded
refunds totaling $10.4 million ($6.8 million net of tax) of which $1.3 million
relates to refund of 2002 severance tax expense and $9.1 related to refunds of
prior period expense.

2003 CAPITAL EXPENDITURE PLANS

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

-5-

NATURAL GAS AND OIL RESERVES

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

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

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

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

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

-6-

DRILLING ACTIVITY

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

PRODUCTIVE WELLS

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

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

-7-

ACREAGE DATA

The following table sets forth the approximate developed and undeveloped
acreage in which we held a leasehold mineral or other interest as of December
31, 2002. Undeveloped acreage includes leased acres on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of natural gas or oil, regardless of whether or not the acreage
contains proved reserves.

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

MARKETING AND CUSTOMERS

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

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

We transport most of our natural gas through third party gas gathering
systems and gas pipelines. Transportation space on these gathering systems and
pipelines is occasionally limited and at times unavailable because of repairs or
improvements, or as a result of priority transportation agreements with other
gas shippers. While our ability to market our natural gas has only been
infrequently limited or delayed, if transportation space is restricted or is
unavailable, our cash flow from the affected properties could be adversely
affected. Please read the section entitled "Risk Factors -- Operating Hazards
and Uninsured Risks."

ABANDONMENT COSTS

We are responsible for our working interest share of costs to abandon
natural gas and oil properties and facilities once they are depleted. We have
historically provided for our expected future abandonment liabilities by
accruing for depreciation and amortization as the properties are produced. As of
December 31, 2002, we estimate our discounted future net asset retirement
obligation for all of our natural gas and oil properties and equipment is
approximately $57 million. Our estimates of abandonment costs and their timing
may change as a result of many factors including actual drilling and production
results, inflation rates, and changes in environmental laws and regulations.
Effective January 1, 2003, we adopted Statement of Financial Accounting
Standards No. 143, "Accounting for Asset Retirement Obligations". SFAS No. 143
requires that the fair value of a liability for an asset's retirement obligation
be recorded in the period in which it is incurred and the corresponding cost
capitalized by increasing the carrying amount of the related long-lived asset.
The liability is accreted to its then present value each period, and the
capitalized cost is depreciated over the useful life of the related asset. If
the liability is settled for an amount other than the recorded amount, a gain or
loss is recognized.

-8-

The Minerals Management Service requires lessees of Outer Continental Shelf
properties to post bonds in connection with the plugging and abandonment of
wells located offshore and the removal of all production facilities. Operators
in the Outer Continental Shelf waters of the Gulf of Mexico are currently
required to post an area-wide bond of $3 million or $500,000 per producing
lease. We are presently exempt from any requirement by the Minerals Management
Service to provide supplemental bonding on our offshore leases, although we may
not be able to continue to satisfy the requirements for this exemption in the
future. We believe that even if we did not qualify for this exemption, the cost
of any bonding requirements would not materially affect our financial condition
or results of operations. The Minerals Management Service has the authority to
suspend or terminate operations on federal leases for failure to comply with
applicable bonding requirements or other regulations applicable to plugging and
abandonment. Any suspensions or terminations of our operations could have a
material adverse effect on our financial condition and results of operations.

TITLE TO PROPERTIES

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

COMPETITION

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

REGULATION

The oil and gas industry is extensively regulated by numerous federal,
state and local authorities. Legislation affecting the oil and gas industry is
under constant review for amendment or expansion, frequently increasing the
regulatory burden. Also, numerous departments and agencies, both federal and
state, are authorized by statute to issue rules and regulations binding on the
oil and gas industry and its individual members, some of which carry substantial
penalties for failure to comply. Although the regulatory burden on the oil and
gas industry increases our cost of doing business and, consequently, affects our
profitability, generally, these burdens do not appear to affect us any
differently or to any greater or lesser extent than they affect other companies
in the industry with similar types, quantities and locations of production.

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

o the location of wells;

o the method of drilling and casing wells;

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

o the plugging and abandoning of wells.

-9-

State laws regulate the size and shape of drilling and spacing units or
proration pooling of oil and gas properties. Some states allow forced pooling or
integration of tracts to facilitate exploration while other states rely on
voluntary pooling of lands and leases. In addition, state conservation laws
establish maximum rates of production from oil and gas wells, generally prohibit
the venting or flaring of natural gas and impose requirements regarding the
ratability of production. These regulations may limit the amount of oil and gas
we can produce from our wells or limit the number of wells or the locations at
which we can drill. Generally, our properties located in federal waters are
regulated by the Minerals Management Service and are not subject to regulation
by state agencies.

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

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

ENVIRONMENTAL MATTERS AND REGULATION

General. Our operations must comply with federal, state and local laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. These laws and regulations may:

o require the acquisition of a permit before drilling commences;

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

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

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

o impose substantial liabilities for pollution resulting from our
operations.

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

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

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

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

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

Oil Pollution Act. The Oil Pollution Act imposes on responsible parties
strict, joint and several, and potentially unlimited liability for removal costs
and other damages caused by an oil spill covered by the Oil Pollution Act. The
Oil Pollution Act also requires the lessee of an offshore area or a permittee
whose operations take place within a covered offshore facility to establish and
maintain financial responsibility of at least $35 million, which may be
increased to $150 million for facilities with large worst-case spill potentials
and under other circumstances, to cover liabilities related to an oil spill for
which the lessee or permitttee of the offshore area is statutorily responsible.
Owners of multiple facilities are required to maintain financial responsibility
for only the facility with the largest potential worst-case spill. We believe we
are in compliance with the financial responsibility provisions of the Oil
Pollution Act.

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

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

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

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

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

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RISK FACTORS AFFECTING OUR BUSINESS

OUR BUSINESS AND OPERATIONS COULD BE ADVERSELY AFFECTED BY RECENT TERRORIST
ACTIVITIES AND THE POTENTIAL FOR MILITARY AND OTHER ACTIONS.

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

THE VOLATILITY OF NATURAL GAS AND OIL PRICES MAY AFFECT OUR FINANCIAL RESULTS.

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

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

o the price of foreign imports;

o overall domestic and global economic conditions;

o political and economic conditions in oil producing countries;

o the level of consumer product demand;

o weather conditions;

o domestic and foreign governmental regulations; and

o the price and availability of alternative fuels.

We cannot predict future natural gas and oil price movements. If natural
gas and oil prices decline, the amount of natural gas and oil we can
economically produce may be reduced, which may result in a material decline in
our revenues.

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

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

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

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

Our business is capital intensive. To maintain or increase our base of
proved oil and gas reserves, we must invest a significant amount of cash flow
from operations in property acquisitions, development and exploration
activities. We are currently making and will continue to make substantial
capital expenditures to find, develop, acquire and produce natural gas and oil
reserves. Our capital expenditure budget for exploration, development and
leasehold acquisitions for 2003 is estimated at approximately $286 million. This
budget excludes potential property acquisitions. We believe that we will have
sufficient cash provided by operating activities and available borrowing
capacity under our bank credit facility to fund planned capital expenditures in
2003. 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

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may not be able to obtain debt or equity financing, and cash generated by
operations or available under our revolving bank credit facility may not be
sufficient to meet our capital requirements.

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

Our outstanding indebtedness at December 31, 2002 was $252 million, and as
of February 20, 2003 was $247 million. Our level of indebtedness affects our
operations in a number of ways. Our revolving 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. During 2002, we made aggregate cash
interest payments of $14.9 million. Funds dedicated to debt service payment will
not be available for other purposes. Further, other covenants in these
agreements require us to meet the financial tests specified in these agreements
and establish other restrictions that limit our ability to borrow additional
funds or dispose of assets. They may also affect our flexibility in planning
for, and reacting to, changes in business conditions. Moreover, future
acquisition and development activities may require us to significantly alter our
capitalization structure, which may alter our indebtedness. Our ability to meet
our debt service obligations and reduce our total indebtedness will depend upon
our future performance. Our future performance, in turn, is dependent upon many
factors that are beyond our control such as general economic, financial and
business conditions. Our future performance may be adversely affected by these
economic, financial and business conditions.

ESTIMATES OF PROVED RESERVES AND FUTURE NET REVENUE MAY CHANGE.

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

WE MAY NOT BE ABLE TO REPLACE RESERVES.

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

OPERATING HAZARDS AND UNINSURED RISKS.

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

o fires;

o natural disasters;

o explosions;

o encountering formations with abnormal pressures;

o blowouts;

o cratering;

o pipeline ruptures; and

o spills.

We are insured against some, but not all, of the hazards associated with
our business. We believe this is standard practice in our industry. Because of
this practice, however, we may be liable or sustain losses that could be
substantial due to events that are not insured.

Additionally, our natural gas and oil operations located in the Gulf of
Mexico may experience tropical weather disturbances, some of which can be severe
enough to cause substantial damage to facilities and possibly interrupt
production. As protection against operating hazards, we maintain insurance
coverage against some, but not all, potential

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

OUR ACQUISITION AND INVESTMENT ACTIVITIES MAY NOT BE SUCCESSFUL.

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

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

To achieve a more predicable cash flow and to reduce our exposure to
adverse fluctuations in the prices of oil and natural gas, we currently and may
in the future, enter into hedging arrangements for a portion of our natural gas
and oil production. Typically, the hedging instruments we use are fixed price
swaps, no-cost collars and options. While using these types of hedging
instruments limits the downside risk of adverse price movements, a number of
risks exist, including instances in which the benefit to revenues is limited
when natural gas prices increase. In addition, there is the risk that our actual
production is less than expected and that the counter party to the hedging
contract defaults on its contractual obligations.

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

Environmental and other governmental regulations have increased the costs
to plan, design, drill, install, operate and abandon oil and natural gas wells,
offshore platforms and other facilities. We have expended and continue to expend
significant resources, both financial and managerial, to comply with
environmental regulations and permitting requirements. Increasingly strict
environmental laws, regulations and enforcement policies and claims for damages
to property, employees, other persons and the environment resulting from our
operations, could result in substantial costs and liabilities in the future.

WE FACE STRONG COMPETITION.

As an independent natural gas and oil producer, we face strong competition
in all aspects of our business. Many of our competitors are large,
well-established companies that have substantially larger operating staffs and
greater capital resources than we do. These companies may be able to pay more
for productive natural gas and oil properties and exploratory prospects and to
define, evaluate, bid for and purchase a greater number of properties and
prospects than our financial and human resources permit.

CONCENTRATION OF CREDIT RISKS.

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

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

POTENTIAL CONFLICTS OF INTEREST WITH OUR MAJORITY STOCKHOLDER.

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

o the election of the entire Board of Directors;

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

o all matters relating to our management;

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

o payment of dividends on our common stock;

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

o hedging, drilling, operating and acquisition expenditure plans.

As KeySpan has announced in the past, they do not consider the businesses
contained in their energy investments segment, including their investment in
Houston Exploration, a part of their core asset group. KeySpan has stated in the
past that they may sell or otherwise dispose of all or a portion of their
non-core assets, including all or a portion of their common stock ownership in
our company but cannot predict when, or if, any such sale or disposition may
take place.

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

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

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

OUR SUCCESS DEPENDS ON OUR CHIEF EXECUTIVE OFFICER AND OTHER KEY EMPLOYEES

We depend to a large extent on the efforts and continued employment of our
President and Chief Executive Officer, William G. Hargett, and other key
employees. If Mr. Hargett or these other key employees resign or become unable
to continue in their present roles and if they are not adequately replaced, our
business operations could be adversely affected.

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EMPLOYEES

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

OFFICES

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

AVAILABLE INFORMATION

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

ITEM 3. LEGAL PROCEEDINGS

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

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

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

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

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PART II.

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

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

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

DIVIDENDS

We have never paid any cash dividends and do not anticipate declaring any
dividends in the foreseeable future. We plan to retain our cash for the
operation and expansion of our business, including exploration, development and
acquisition activities. Moreover, our bank credit facility and the indenture
governing our 8 5/8% Senior Subordinated Notes due 2008 contain restrictions on
the payment of dividends to holders of common stock. Accordingly, were our
dividend policy to change in the future, our ability to pay dividends would be
subject to these restrictions and our results of operations, financial
condition, capital requirements and other factors deemed relevant by the Board
of Directors. Please read Item 7. "Management's Discussion and Analysis of
Financial Condition and Results of Operations."

EQUITY COMPENSATION PLAN TABLE PURSUANT TO RULE 102 (b)
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

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(1) Comprised of our 1996 Stock Option Plan and our 2002 Incentive Stock Plan.

(2) Comprised of our 1999 Non-Qualified Stock Plan and 6,667 shares of
restricted stock remaining and granted to our Chief Executive Officer
pursuant to the terms of his employment contract dated April 4, 2001.

-18-

ITEM 6. SELECTED FINANCIAL DATA

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

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- ----------

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

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

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

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

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

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

GENERAL

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

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

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

We began exploring for natural gas and oil in December 1985 on behalf of The
Brooklyn Union Gas Company. Brooklyn Union is an indirect wholly owned
subsidiary of KeySpan Corporation. KeySpan, a member of the Standard & Poor's
500 Index, is a diversified energy provider whose principal natural gas
distribution and electric generation operations are located in the Northeastern
United States. In September 1996 we completed our initial public offering and
sold approximately 34% of our shares to the public with KeySpan retaining the
balance. As of December 31, 2002, THEC Holdings Corp., an indirect wholly owned
subsidiary of KeySpan, owned approximately 66% of the outstanding shares of our
common stock.

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

CRITICAL ACCOUNTING POLICIES AND USE OF ESTIMATES

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

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

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

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

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

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

Use of Estimates. The preparation of the consolidated financial statements
in conformity with accounting principals generally accepted in the United States
of America requires our management to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosure of contingent
assets and liabilities at the dates of the financial statements and the reported
amounts of revenues and expenses during the reporting periods. Our most
significant financial estimates are based on remaining proved natural gas and
oil reserves. Estimates of proved reserves are key components of our depletion
rate for natural gas and oil properties and our full cost ceiling limitation.

Natural gas and oil reserve quantities represent estimates only. Under full
cost accounting, we use reserve estimates to determine our full cost ceiling
limitation as well as our depletion rate. We estimate our proved reserves and
future net revenues using sales prices estimated to be in effect as of the date
we make the reserve estimates. We hold the estimates constant throughout the
life of the properties, except to the extent a contract specifically provides
for escalation. Natural gas prices, which have fluctuated widely in recent
years, affect estimated quantities of proved reserves and future net revenues.
Further, any estimates of natural gas and oil reserves and their values are
inherently uncertain for numerous reasons, including many factors beyond our
control. Reservoir engineering is a subjective process of estimating underground
accumulations of natural gas and oil that cannot be measured in an exact manner.
The accuracy of any reserve estimate is a function of the quality of available
data and of engineering and geological interpretation and judgment. In addition,
estimates of reserves may be revised based upon actual production, results of
future development and exploration activities, prevailing natural gas and oil
prices, operating costs and other factors, and these revisions may be material.
Reserve estimates are highly dependent upon the accuracy of the underlying
assumptions. Actual future production may be materially different from estimated
reserve quantities and the differences could materially affect future
amortization of natural gas and oil properties.

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

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

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

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

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

NEW ACCOUNTING PRONOUNCEMENTS

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

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

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

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

SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and
Disclosure" was issued in December 2002 and the transition guidance and annual
disclosure provisions are effective for us for the year ended December 31, 2002.
SFAS No. 148 amends SFAS Statement No. 123, "Accounting for Stock Based
Compensation" and provides alternative methods of transition for a voluntary
change to the fair value method of accounting for stock-based employee
compensation. In addition, the statement amends the disclosure requirements of
SFAS No. 123 to require prominent disclosures in both annual and interim
financial statements about the method of accounting for stock-based compensation

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and the effect of the method used. We adopted SFAS No. 148 for 2002 and on
January 1, 2003, we adopted the fair value expense recognition provisions of
SFAS No. 123 on a prospective basis and as a result, we will record as
compensation expense the fair value of all stock options issued subsequent to
January 1, 2003.

ACQUISITIONS

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

Our Board of Directors appointed a special committee, comprised entirely of
independent directors to review the proposed transaction with KeySpan. For
assistance, the special committee retained special outside legal counsel as well
as the financial advisory firm of Petrie Parkman & Co. In addition, the special
committee discussed the history and terms of the transaction with our senior
management. After completing its review, the special committee unanimously
concluded that the transaction was advisable and in our best interests and that
the terms of the transaction were at least as favorable to us as terms that
would have been obtainable at the time in a comparable transaction with an
unaffiliated party. In reaching its decision, the special committee considered
numerous factors in consultation with its financial and legal advisors. The
special committee also took into account the opinion delivered to it by Petrie
Parkman & Co. to the effect that the consideration to be paid by us in the
transaction was fair to us from a financial point of view.

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

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

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OTHER RECENT DEVELOPMENTS

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

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

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RESULTS OF OPERATIONS

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

- ----------

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

RECENT FINANCIAL AND OPERATING RESULTS

Comparison of Years Ended December 31, 2002 and 2001

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

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

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

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Venture) from 1999 through 2002. Overall, for the year 2002, increments in
production growth resulting from our acquisition and our new exploration and
development projects was offset by natural production declines in existing
properties.

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

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

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

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

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

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

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

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

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

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

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

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

Income Tax Provision. The provision for income taxes decreased 41% from
$66.8 million for 2001 to $39.1 million for 2002 due to the 42% decrease in
pre-tax income during 2002 from $189.4 million during 2001 to $109.6 million
during

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2002 as a result of the combination of a decrease in natural gas revenues and
increases in both operating expenses and net interest expense.

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

COMPARISON OF THE YEARS ENDED DECEMBER 31, 2001 AND 2000

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

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

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

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

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

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

Transportation Expense. We applied Emerging Issues Task Force ("EITF") No.
00-10 "Accounting for Shipping and Handling Fees and Costs" for all periods
presented. Pursuant to our application of EITF No. 00-10, transportation expense
previously reflected as a reduction of natural gas and oil revenues were added
back to the related revenues and reclassified as a separate component of
operating expense. For the years ended December 31, 2001 and 2000, natural gas
and oil revenues, total revenues, transportation expense and total operating
expenses were restated and reclassified, respectively. The application of EITF
No. 00-10 had no effect on operating income or net income. See Note 11 -
Restatement and

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Reclassification made to Consolidated Statements of Operations for
Transportation Expense. Transportation expense increased 12% from $6.9 million
and $0.09 per Mcfe in 2000 to $7.7 million and $0.09 per Mcfe during 2001. The
increase in expense corresponds to the 13% increase in total production for
2001.

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

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

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

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

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

Income Tax Provision. The provision for income taxes increased from $42.5
million for the year ended December 31, 2000 to $66.8 million for the year ended
December 31, 2001 due to the 48% increase in pre-tax income during 2001 from
$127.7 million during 2000 to $189.4 million during 2001 as a result of the
combination of higher natural gas prices, an increase in production, a decrease
in interest expense offset in part by an increase in operating expenses.

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

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LIQUIDITY AND CAPITAL RESOURCES

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

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

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

- ----------

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

-31-

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

Capital Structure

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

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

Senior Subordinated Notes. On March 2, 1998, we issued $100 million of
at a rate of 8 5/8% per annum with interest payable semi-annually on January 1
and July 1. We may redeem the notes at our option, in whole or in part, at any
time on or after January 1, 2003 at a price equal to 100% of the principal
amount plus accrued and unpaid interest, if any, plus a specified premium which
decreases yearly from 4.313% in 2003 to 0% in 2006. Upon the occurrence of a
change of control, we will be required to offer to purchase the notes at a
purchase price equal to 101% of the aggregate principal amount, plus accrued and
unpaid interest, if any. The notes are general unsecured obligations and rank
subordinate in right of payment to all existing and future senior debt,
including the credit facility, and will rank senior or equal in right of payment
to all existing and future subordinated indebtedness.

Contractual Obligations and Other Commercial Commitments

As of December 31, 2002, our contractual obligations and commercial
commitments are as follows:

We have no "off-balance sheet" financing arrangements.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

NATURAL GAS AND OIL HEDGING

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

During the fourth quarter of 2002, an increase in forward market prices for
natural gas caused our mark-to-market exposure with one counter party to surpass
our contractual margin threshold as established under the contract. As a result,
we were required to post margin in the amount of $5.4 million. The margin
payment earns interest at a market rate and will be refunded if our
mark-to-market exposure drops below the margin threshold as required under the
contract. This will occur if market prices decline from current levels.
Subsequent to December 31, 2002, our margin was increased by $5.9 million to a
balance of $11.3 million as of the date of our report.

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

CHANGES IN FAIR VALUE OF DERIVATIVE INSTRUMENTS

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

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DERIVATIVES IN PLACE AS OF THE DATE OF OUR REPORT

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

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

-34-

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

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

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ITEM 8. FINANCIAL STATEMENTS

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

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

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

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

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

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

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

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

-36-

PART III.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

EXECUTIVE OFFICERS

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

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

Charles W. Adcock was appointed Senior Vice President and General Manager -
Offshore Division effective October 1, 2001. From April 2000 to October 2001,
Mr. Adcock served as Senior Vice President - Operations and Engineering. Mr.
Adcock held the position of Vice President--Project Development from September
1996 until April 2000. Mr. Adcock held the same position, Vice
President--Project Development, with Fuel Resources, Inc., a subsidiary of
Brooklyn Union that previously owned our onshore properties, from 1993 to 1996.
Prior to joining Fuel Resources, Inc., Mr. Adcock worked at NERCO Oil & Gas as
Reservoir Engineering Specialist. Prior to NERCO, he held various engineering
positions with Apache, ANR Production and Aminoil U.S.A. Mr. Adcock is a
Registered Professional Engineer in the State of Texas, and received his B.S. in
Civil Engineering from Texas A&M University and an M.B.A. from the University of
St. Thomas.

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

-37-

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

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

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

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

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

-38-

BOARD OF DIRECTORS

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

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

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

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

-39-

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

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

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

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

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

James Q. Riordan has been a Director since 1996 and was a Director of
KeySpan from May 1998 until his retirement in May 2002. Mr. Riordan is the
retired Vice Chairman and Chief Financial Officer of Mobil Corp. He joined Mobil
Corp. in 1957 as Tax Counsel and was named Director and Chief Financial Officer
in 1969. Mr. Riordan served as Vice Chairman of Mobil Corp. from 1986 until his
retirement in 1989. He joined Bekaert Corporation in 1989 and was elected its
President, and served as President until his retirement in 1992. Mr. Riordan is
a Director of Tri-Continental Corporation; Director/Trustee of the mutual funds
in the Seligman Group of investment companies; Trustee for the Committee for
Economic Development and The Brooklyn Museum; and Member of the Policy Council
of the Tax Foundation.

-40-

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

COMPLIANCE WITH SECTION 16(A)

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

ITEM 11. EXECUTIVE COMPENSATION

COMPENSATION OF DIRECTORS

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

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

-41-

SUMMARY COMPENSATION TABLE

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

- ----------

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

Bonus amounts for 2000 include a special bonus of 15% of base salary paid
in April 2000 pursuant to the conclusion and termination of the strategic
review process we initiated in September 1999. Amounts include: $26,000
each for Messrs. Adcock, Westmoreland and Schwartz.

Bonus amounts for 2001 include a special bonus paid in January 2001 in
connection with the grant of non-qualified stock options. Amounts include:
$167,000 each for Messrs. Adcock, Schwartz and Westmoreland.

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

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

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

-42-

OPTIONS GRANTED IN 2002

The following table provides certain information with respect to
options granted to the Named Executive Officers during 2002 under the 2002 Stock
Options Plan:

(1) The Company has not issued any stock appreciation rights to the Named
Executive Officers.

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

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

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

- ----------

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

COMPENSATION COMMITTEE INTERLOCK AND INSIDER PARTICIPATION

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

-43-

ITEM 12. SECURITY OWNERSHIP OF BENEFICIAL OWNERS AND MANAGEMENT

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

- ----------

* Less than 1%.

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

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

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

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

(5) Mr. Hargett owns 6,667 shares of restricted common stock of which
3,333 shares vest within 60 days of the date hereof with the remaining
3,334 shares vesting on the anniversary date of the grant date or
April 4, 2004. Mr. Hargett owns 221,400 options, none of which are
exercisable within 60 days of the date hereof.

-44-

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

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

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

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

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

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

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

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

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

(15) Mr. Rice owns 55,000 options, none of which have vested.

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

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

-45-

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

TRANSACTIONS WITH KEYSPAN

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

KeySpan Joint Venture

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

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

From the inception of the joint venture in January 1999 through December
31, 2002, we drilled a total of 33 wells: 25 exploratory wells of which 21 were
successful and eight development wells of which seven were successful. KeySpan
spent a total of $118.3 million, with $19.0 million, $17.2 million and $46.5
million, respectively being spent during 2002, 2001 and 2000. Subsequent to the
termination of the primary exploratory term of the joint venture, KeySpan's
participation in additional wells was to further develop or delineate reservoirs
previously discovered.

Acquisition of KeySpan Joint Venture Assets

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

Our Board of Directors appointed a special committee, comprised entirely of
independent directors to review the proposed transaction with KeySpan. For
assistance, the special committee retained special outside legal counsel as well
as the financial advisory firm of Petrie Parkman & Co. In addition, the special
committee discussed the history and terms of the transaction with our senior
management. After completing its review, the special committee unanimously
concluded that the transaction was advisable and in our best interests and that
the terms of the transaction were at least as favorable to us as terms that
would have been obtainable at the time in a comparable transaction with an
unaffiliated party. In reaching its decision, the special committee considered
numerous factors in consultation with its financial and legal advisors. The
special committee also took into account the opinion delivered to it by Petrie
Parkman & Co. to the effect that the consideration to be paid by us in the
transaction was fair to us from a financial point of view.

-46-

KeySpan Credit Facility and Conversion

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

Review of Strategic Alternatives

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

Sale of Section 29 Tax Credits

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

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

o received a cash down payment of $1.4 million and

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

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

-47-

Registration Rights Agreement.

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

EMPLOYMENT AGREEMENTS

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

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

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

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

Under their employment agreements, each of our executive officers would be
entitled to a lump sum severance payment equal to 2.99 times their current total
annual compensation, if we terminated their employment agreements without cause
or if the employee terminates his employment agreement for good reason. Mr.
Hargett would receive approximately $2.3 million, Mr. Karnes would receive
approximately $1.3 million, Messrs. Adcock and Mueller would each receive
approximately $1.2 million, Mr. Westmoreland would receive approximately $1.1
million, Messrs. Schwartz and Rice would each receive approximately $1.0 million
and Mr. Price would receive approximately $0.9 million.

Effective as of October 26, 1999, our Board of Directors established the
Change of Control Plan under which all employees, including the executive
officers, in the event of a "change of control" will be entitled to receive a
"stay-on"

-48-

bonus in the amount of 125% of the employee's regular target bonus percentage,
and, in addition to other severance benefits, all stock options, phantom stock
and 401(k) contributions will fully vest. See "Change of Control Plan."

SUPPLEMENTAL EXECUTIVE PENSION PLAN

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

401(k) PLAN

We maintain a 401(k) Plan for our employees. Under the 401(k) Plan,
eligible employees may elect to have us contribute on their behalf up to 12.5%
of their base compensation on a before tax basis in accordance with the
limitations imposed under the Internal Revenue Code. We make a matching
contribution of $1.00 for each $1.00 of employee deferral, in accordance with
the limitations imposed by the 401(k) Plan and the Internal Revenue Code. The
amounts contributed under the 401(k) Plan are held in a trust and invested among
various investment funds in accordance with the directions of each participant.
An employee's salary deferral contributions under the 401(k) Plan are 100%
vested. Our matching contributions vest at the rate of 20% per year of service.
Participants are entitled to payment of their vested account balances upon
termination of employment.

1996 STOCK OPTION PLAN

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

1999 NON-QUALIFIED STOCK OPTION PLAN

On October 26, 1999, our Board of Directors adopted the 1999 Non-Qualified
Stock Option Plan for employees (excluding executive officers), non-employee
Directors, consultants and advisors of our company and our affiliates. With
respect to non-employee Directors only, the 1999 Non-Qualified Stock Option Plan
amends and succeeds the 1996 Plan (under which no more options may be granted to
non-employee Directors). The 1999 Non-Qualified Stock Option Plan is
administered by the Compensation Committee, which at its discretion, may grant
awards to eligible individuals with the exception of non-employee Directors who
receive automatic grants under the 1999 Non-Qualified Stock Option Plan. The
options granted under the 1999 Non-Qualified Stock Option Plan are all
non-qualified, expire 10 years from date of grant and vest immediately for
non-employee Directors and in one-fifth increments on each of the first five
anniversaries of the grant for other eligible individuals. A total of 566 shares
remain available for grant under the 1999 Plan as of December 31, 2002. During
2002, we granted a total of 145,600 options under the 1999 Non-Qualified Stock
Option Plan, of which 18,000 options were granted to non-employee directors
pursuant to our compensation plan for non-employee directors. We may adjust
options issued under the 1999 Non-Qualified Stock Option Plan in the event of
stock splits and other corporate events. In addition, we may appropriately
adjust the exercise price for options in the event that the outstanding shares
of common stock are changed into or exchanged for a different number or kind of
shares or other securities by reason of merger, stock dividend, combination of
shares or the like.

-50-

2002 LONG-TERM INCENTIVE PLAN

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

DEFERRED COMPENSATION PLAN

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

EMPLOYEE ANNUAL INCENTIVE COMPENSATION PLAN

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

-51-

CHANGE OF CONTROL PLAN

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

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

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

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

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

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

ITEM 14. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to ensure
that information required to be disclosed by us in the reports we file under the
Securities Exchange Act of 1934, as amended ("Exchange Act") is communicated,
processed, summarized and reported within the time periods specified in the
SEC's rules and forms. Within the 90 days prior to the date of this report, we
carried out an evaluation, under the supervision and with the participation of
our principal executive officer and principal financial officer, of the
effectiveness of our disclosure controls and procedures (as defined in Rule
13a-14 of the Exchange Act). Based on that evaluation, our principal executive
officer and principal financial officer concluded that our disclosure controls
and procedures are effective. There have been no significant changes in our
internal controls or in other factors that could significantly affect these
controls subsequent to the date of their evaluation, including any corrective
actions with regard to significant deficiencies or material weaknesses.

-51-

PART IV.

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

(a) Documents Filed as a Part of this Report

1. FINANCIAL STATEMENTS:

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

2. EXHIBITS:

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

(b) Reports on Form 8-K.

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

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

-52-

SIGNATURES

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

THE HOUSTON EXPLORATION COMPANY

By: /s/ William G. Hargett
-------------------------------------
William G. Hargett
Date: February 20, 2003 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

-53-

CERTIFICATIONS

I, William G. Hargett, certify that:

1. I have reviewed this annual report on Form 10-K of The Houston Exploration
Company;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;

(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and

(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and

(b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.

Date: February 20, 2003

/s/ William G. Hargett
------------------------------------------
William G. Hargett
President and Chief Executive Officer

-54-

CERTIFICATIONS

I, John H. Karnes, certify that:

1. I have reviewed this annual report on Form 10-K of The Houston Exploration
Company;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;

(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and

(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and

(b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.

Date: February 20, 2003

/s/ John H. Karnes
---------------------------------------------
John H. Karnes
Vice President and Chief Financial Officer

-55-

GLOSSARY OF OIL AND GAS TERMS

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

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

Bbl/d. One barrel per day.

Bcf. Billion cubic feet.

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

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

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

Developed acreage. The number of acres allocated or assignable to producing
wells or wells capable of production.

Developed well. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well. A well found to be incapable of producing hydrocarbons in
sufficient quantities such that proceeds from the sale of the production exceed
production expenses and taxes.

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

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

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

Gross acres or gross wells. The total acres or wells, as the case may be,
in which a working interest is owned.

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

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

MBbls/d. One thousand barrels of crude oil or other liquid hydrocarbons per
day.

Mcf. One thousand cubic feet.

G-1

GLOSSARY OF OIL AND GAS TERMS

Mcf/d. One thousand cubic feet per day.

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

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

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

MMbtu. One million Btus.

MMMbtu. One billion Btus.

MMcf. One million cubic feet.

MMcf/d. One million cubic feet per day.

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

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

Oil. Crude oil and condensate.

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

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

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

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

Proved reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.

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

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

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

G-2

GLOSSARY OF OIL AND GAS TERMS

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

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

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

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

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

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

G-3

INDEX TO FINANCIAL STATEMENTS

F-1

REPORT OF INDEPENDENT AUDITORS

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

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

In our opinion, the 2002 and 2001 consolidated financial statements
present fairly, in all material respects, the financial position of the Company
as of December 31, 2002 and 2001, and the results of its operations and its cash
flows for the years then ended in conformity with accounting principles
generally accepted in the United States of America.

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

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

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

DELOITTE & TOUCHE LLP

Houston, Texas
February 7, 2003

F-2

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

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

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

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

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

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

ARTHUR ANDERSEN LLP

New York, New York
February 4, 2002

F-3

THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS

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

F-4

THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS

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

F-5

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

F-6

- ----------

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

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

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

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

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

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

F-7

THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS

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

F-8

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 -- SUMMARY OF ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES

Organization

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

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

We began exploring for natural gas and oil in December 1985 on behalf of
The Brooklyn Union Gas Company. Brooklyn Union is an indirect wholly owned
subsidiary of KeySpan Corporation. KeySpan, a member of the Standard & Poor's
500 Index, is a diversified energy provider whose principal natural gas
distribution and electric generation operations are located in the Northeastern
United States. In September 1996 we completed our initial public offering and
sold approximately 34% of our shares to the public with KeySpan retaining the
balance. As of December 31, 2002, THEC Holdings Corp., an indirect wholly owned
subsidiary of KeySpan, owned approximately 66% of the outstanding shares of our
common stock.

Principles of Consolidation

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

Use of Estimates

The preparation of the consolidated financial statements in conformity
with accounting principals generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the dates of the financial statements and the reported amounts of
revenues and expenses during the reporting periods. Our most significant
financial estimates are based on remaining proved natural gas and oil reserves.
Estimates of proved reserves are key components of our depletion rate for
natural gas and oil properties and our full cost ceiling test limitation. See
Note 12 - Supplemental Information on Natural Gas and Oil Exploration,
Development and Production Activities (Unaudited). Because there are numerous
uncertainties inherent in the estimation process, actual results could differ
from the estimates.

F-9

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Net Income Per Share

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

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

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

Natural Gas and Oil Properties

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

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

F-10

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The ceiling test is calculated using natural gas and oil prices in effect
as of the balance sheet date, held flat over the life of the reserves. We use
derivative financial instruments that qualify for hedge accounting under SFAS
No. 133 to hedge against the volatility of natural gas prices, and in accordance
with current Securities and Exchange Commission guidelines, we include estimated
future cash flows from our hedging program in our ceiling test calculation. In
calculating the ceiling test at December 31, 2001, we estimated, using a
wellhead price of $2.38 per Mcf, that our capitalized costs exceeded the ceiling
limitation by $6.2 million ($4.0 million after tax). As a result, we reduced or
"wrote down" the carrying value of our full cost pool and incurred a charge to
earnings of $6.2 million ($4.0 million, after tax). Natural gas prices continue
to be volatile and the risk that we will be required to writedown our full cost
pool increases when natural gas prices are depressed or if we have significant
downward revisions in our estimated proved reserves.

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

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

Cash and Cash Equivalents

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

Other Property and Equipment

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

Income Taxes

We determine deferred taxes based on the estimated future tax effect of
differences between the financial statement and tax basis of assets and
liabilities given the provisions of enacted tax laws. These differences relate
primarily to

o intangible drilling and development costs associated with natural gas
and oil properties, which are capitalized and amortized for financial
reporting purposes and expensed as incurred for tax reporting purposes
and

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

Inventories

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

General and Administrative Costs and Expenses

We receive reimbursement for administrative and overhead expenses incurred
on behalf of other working interest owners on properties we operate. These
reimbursements totaling $1.8 million, $1.2 million, and $3.6 million for the
years ended December 31, 2002, 2001 and 2000, respectively, were allocated as
reductions to general and administrative expenses. Included in reimbursements
received during 2000 are general and administrative reimbursements received from
KeySpan pursuant to the joint exploration agreement with KeySpan, (see Note 6 -
Related Party Transactions - KeySpan Joint Venture) of $2.5 million. The
capitalized general and administrative costs directly related to our
acquisition, exploration and development activities, during 2002, 2001 and 2000,
aggregated $13.2 million, $12.8 million, and $9.6 million, respectively.

F-11

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Capitalization of Interest

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

Revenue Recognition and Gas Imbalances

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

Financial Instruments

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

Hedging Contracts

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

Concentration of Credit Risk

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

Further, our natural gas futures and swap contracts also expose us to
credit risk in the event of nonperformance by counterparties. Generally, these
contracts are with major investment grade financial institutions and
historically we have not experienced material credit losses. We believe that our
credit risk related to the natural gas futures and swap contracts

F-12

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

is no greater than the risk associated with the primary contracts and that the
elimination of price risk reduces volatility in our reported results of
operations, financial position and cash flows from period to period and lowers
our overall business risk; but, as a result of our hedging activities we may be
exposed to greater credit risk in the future.

Stock Options

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

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

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

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

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

New Accounting Pronouncements

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

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

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

SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal
Activities" was issued in June 2002 and addresses accounting and reporting for
costs associated with exit or disposal activities and nullifies Emerging Issues
Task Force ("EITF") Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring)." SFAS No. 146 requires that a liability for
a cost associated with an exit or disposal activity be recognized when the
liability is incurred. Under Issue 94-3, a liability for an

F-13

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

exit cost was recognized at the date of an entity's commitment to an exit plan.
Under SFAS No. 146, the objective for initial measurement of the liability is
fair value. SFAS No. 146 is effective for exit or disposal activities that are
initiated after December 31, 2002. At this time, we do not expect that the
adoption of SFAS No. 146 to have a material impact on our financial position,
results of operations or cash flows.

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

NOTE 2 -- LONG-TERM DEBT AND NOTES

The carrying amount of borrowings outstanding under the revolving bank
credit facility approximates fair value as the interest rates are tied to
current market rates. At December 31, 2002, the quoted market value of the
Company's $100 million of 8 5/8% Senior Subordinated Notes was 103.8% of the
$100 million carrying value or $103.8 million.

Credit Facility

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

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

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

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

F-14

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

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

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

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

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

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

Interest was payable at calendar quarters for base rate loans and at the earlier
of maturity or three months from the date of the loan for fixed rate loans. In
addition, the credit facility required a commitment fee of:

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

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

Senior Subordinated Notes

On March 2, 1998, we issued $100 million of 8 5/8% senior subordinated
notes due January 1, 2008. The notes bear interest at a rate of 8 5/8% per annum
with interest payable semi-annually on January 1 and July 1. We may redeem the
notes at our option, in whole or in part, at any time on or after January 1,
2003 at a price equal to 100% of the principal amount plus accrued and unpaid
interest, if any, plus a specified premium which decreases yearly from 4.313% in
2003 to 0% in 2006. Upon the occurrence of a change of control, we will be
required to offer to purchase the notes at a purchase price equal to 101% of the
aggregate principal amount, plus accrued and unpaid interest, if any. A "change
of control" is:

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

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

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

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

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

F-15

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 3 -- STOCKHOLDERS' EQUITY

KeySpan Credit Facility and Conversion

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

NOTE 4 -- EMPLOYEE BENEFIT AND STOCK AND OPTION PLANS

Deferred Compensation Plan

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

401(k) Profit Sharing Plan

We maintain a 401(k) Profit Sharing Plan for our employees. Under the
401(k) plan, eligible employees may elect to have us contribute on their behalf
up to 12.5% of their base compensation (subject to limitations imposed under the
Internal Revenue Code of 1986, as amended) on a before tax basis. We make a
matching contribution of $1.00 for each $1.00 of employee deferral, subject to
limitations imposed by the 401(k) plan and the Internal Revenue Service. The
amounts contributed under the 401(k) plan are held in a trust and invested among
various investment funds, including the Company's common stock, in accordance
with the directions of each participant. An employee's salary deferral
contributions under the 401(k) plan are 100% vested. Our matching contributions
vest at the rate of 20% per year of service. Participants are entitled to
payment of their vested account balances upon termination of employment. We made
contributions to the 401(k) plan of $0.7 million, 0.7 million, and $0.6 million,
respectively, for the years ended December 31, 2002, 2001 and 2000.

Supplemental Executive Retirement Plan

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

F-16

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Incentive Compensation Plan for Non-Employee Directors

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

Stock and Option Plans

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

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

F-17

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

- ----------

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

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

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

F-18

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Fair Value of Employee Stock-Based Compensation

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

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

F-19

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 5 -- INCOME TAXES

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

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

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

- ----------

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

Deferred Income Taxes

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

F-20

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6 -- RELATED PARTY TRANSACTIONS

TRANSACTIONS WITH KEYSPAN

KeySpan Joint Venture

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

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

From the inception of the joint venture in January 1999 through December
31, 2002, we drilled a total of 33 wells: 25 exploratory wells of which 21 were
successful and eight development wells of which seven were successful. KeySpan
spent a total of $118.3 million, with $19.0 million, $17.2 million and $46.5
million, respectively being spent during 2002, 2001 and 2000. Subsequent to the
termination of the primary exploratory term of the joint venture, KeySpan's
participation in additional wells was to further develop or delineate reservoirs
previously discovered.

Acquisition of KeySpan Joint Venture Assets

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

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

Review of Strategic Alternatives

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

F-21

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Houston Exploration a non-core asset. We incurred expenses relating to this
review of strategic alternatives totaling $0.1 million during 2001 and $1.8
million during 2000.

Sale of Section 29 Tax Credits

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

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

o received a cash down payment of $1.4 million and

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

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

TRANSACTIONS WITH OUR EXECUTIVES

Restricted Stock Grant to President and Chief Executive

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

Employment Contracts

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

Termination of Employment Agreements for Former Executives

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

F-22

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Transactions with Former President and Chief Executive Officer

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

F-23

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 7 -- HEDGING CONTRACTS

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

F-24

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

F-25

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8 -- SALES TO MAJOR CUSTOMERS

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

- ----------

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

NOTE 9 -- COMMITMENTS AND CONTINGENCIES

Severance Tax Refund

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

Legal Proceedings

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

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

F-26

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Leases

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

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

NOTE 10 -- ACQUISITIONS

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

Burlington Acquisition

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

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

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

Conoco Acquisition

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

F-27

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 11 --RESTATEMENT AND RECLASSIFICATIONS

Application of EITF No. 00-10 - Transportation Expense

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

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

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

Adoption for SFAS No. 133

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

F-28

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

Capitalized Costs of Natural Gas and Oil Properties

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

Capitalized Costs Incurred

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

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

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

F-29

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

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

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

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

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

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

F-30

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

F-31

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

F-32

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 13-- QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

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

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

F-33

INDEX TO EXHIBITS

F-34

INDEX TO EXHIBITS

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(1) Filed herewith.

(2) Management contract or compensation plan.

F-36