HOUSTON EXPLORATION CO - 10-Q Quarterly Report

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

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 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

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

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

1100 LOUISIANA STREET, SUITE 2001
HOUSTON, TEXAS 77002-5215
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES AND ZIP CODE)
(713) 830-6800
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)

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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
----- -----

As of August 12, 2002, 30,526,391 shares of Common Stock, par value
$.01 per share, were outstanding.

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THE HOUSTON EXPLORATION COMPANY

TABLE OF CONTENTS

2

FACTORS AFFECTING FORWARD LOOKING STATEMENTS

All of the estimates and assumptions contained in this Quarterly Report
and in the documents we have incorporated by reference into this Quarterly
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 Quarterly 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 our Annual Report on Form 10K.

In this Quarterly Report, unless the context requires otherwise, when
we refer to "we", "us" or "our", we are describing The Houston Exploration
Company and its subsidiary on a consolidated basis.

3

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)

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

4

THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)

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

5

THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

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

6

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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

o high potential offshore exploration and exploitation;

o lower risk exploitation and development drilling onshore; and

o selective acquisitions both offshore and onshore

At December 31, 2001, our net proved reserves were 608 billion cubic
feet equivalent or Bcfe, with a present value, discounted at 10% per annum, of
cash flows before income taxes of $714 million. Our reserves are fully
engineered on an annual basis by two independent petroleum engineering
companies. Our focus is natural gas. Approximately 93% of our net proved
reserves at December 31, 2001 were natural gas of which approximately 74% of our
net proved reserves were classified as proved developed. We operate
approximately 85% of our properties.

We began exploring for natural gas and oil in December 1985 on behalf
of The Brooklyn Union Gas Company. Brooklyn Union is an indirect wholly owned
subsidiary of KeySpan Corporation. KeySpan, a member of the Standard & Poor's
500 Index, is a diversified energy provider whose principal natural gas
distribution and electric generation operations are located in the Northeastern
United States. In September 1996 we completed our initial public offering and
sold approximately 34% of our shares to the public with KeySpan retaining the
balance. As of June 30, 2002, THEC Holdings Corp., an indirect wholly owned
subsidiary of KeySpan, owned approximately 67% of the outstanding shares of our
common stock.

Principles of Consolidation

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

Interim Financial Statements

Our balance sheet at June 30, 2002 and the statements of operations and
cash flows for the periods indicated herein have been prepared without audit,
pursuant to the rules and regulations of the Securities and Exchange Commission.
Certain information and footnote disclosures normally included in financial
statements prepared in accordance with generally accepted accounting principles
have been condensed or omitted, although we believe that the disclosures
contained herein are adequate to make the information presented not misleading.
The balance sheet at December 31, 2001 is derived from the December 31, 2001
audited financial statements, but does not include all disclosures required by
generally accepted accounting principles. The Interim Financial Statements
should be read in conjunction with the Consolidated Financial Statements and
Notes thereto included in our Annual Report on Form 10-K for the year ended
December 31, 2001.

In the opinion of our management, all adjustments, consisting of normal
recurring accruals, necessary to present fairly the information in the
accompanying financial statements have been included. The results of operations
for such interim periods are not necessarily indicative of the results for the
full year.

Reclassifications and Use of Estimates

The preparation of the consolidated financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and

7

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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. Certain reclassifications of prior year
items have been made to conform with current year presentation.

New Accounting Pronouncements

Statement of Financial Accounting Standards ("SFAS") No. 143,
"Accounting for Asset Retirement Obligations," addresses accounting and
reporting for obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs. SFAS No. 143 will be effective
for us January 1, 2003 and early adoption is encouraged. SFAS No. 143 requires
that the fair value of a liability for an asset's retirement obligation be
recorded in the period in which it is incurred and the corresponding cost
capitalized by increasing the carrying amount of the related long-lived asset.
The liability is accreted to its then present value each period, and the
capitalized cost is depreciated over the useful life of the related asset. If
the liability is settled for an amount other than the recorded amount, a gain or
loss is recognized. Currently, we include estimated future costs of abandonment
and dismantlement in our full cost amortization base and amortize these costs as
a component of our depletion expense. We are evaluating the impact the new
standard will have on our financial statements and at this time cannot
reasonably estimate the effect of the adoption of this statement.

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 with earlier adoption encouraged. We
do not expect the adoption of SFAS No. 145 to have a material impact on our
financial position, results of operations or cash flows.

SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal
Activities" was issued in June 2002 and addresses accounting and reporting for
costs associated with exit or disposal activities and nullifies Emerging Issues
Task Force ("EITF") Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring)." SFAS No. 146 requires that a liability for
a cost associated with an exit or disposal activity be recognized when the
liability is incurred. Under Issue 94-3, a liability for an exit cost was
recognized at the date of an entity's commitment to an exit plan. Under SFAS No.
146, the objective for initial measurement of the liability is fair value. SFAS
No. 146 is effective for exit or disposal activities that are initiated after
December 31, 2002, with early application encouraged. 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.

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.
We do not hold derivatives 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

8

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

cease to meet the criteria for deferred recognition or became ineffective as
defined by SFAS 133, any gains or losses would be currently recognized in
earnings.

At June 30, 2002, we estimated, using the New York Mercantile Exchange,
or NYMEX, index price strip as of that date that the fair market value of our
derivative instruments was a negative $1.2 million. As a result, our balance
sheet at June 30, 2002 reflects an asset of $3.8 million, representing the
current portion of our hedge position (for months July 2002 through June 2003)
and a liability of $5.0 million, representing the long-term portion (for months
July 2003 through December 2003) of our hedge position with a corresponding
credit of $773,000 (net of related deferred taxes of $416,000) in accumulated
other comprehensive income, representing the fair market value of our total
deferred hedge loss, net of tax.

At December 31, 2001, we estimated, using the NYMEX index price strip
as of that date that the fair market value of our derivative instruments was a
positive $53.8 million. As a result, our balance sheet at December 31, 2001
reflected an asset of $53.8 million with a corresponding credit of $34.9 million
(net of related deferred taxes of $18.9 million) in accumulated other
comprehensive income, representing the fair market value of our deferred hedge
gain.

Net Income Per Share

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

9

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Comprehensive Income

The table below summarizes our Comprehensive Income for the three month
and six month periods ended June 30, 2002 and 2001.

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 June 30, 2002, the quoted market value of the Company's
$100 million of 8 5/8% Senior Subordinated Notes was 102.9% of the $100 million
carrying value or $102.9 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 replaces our previous $250
million revolving credit facility maintained with JPMorgan Chase and provides us
with an initial commitment of $300 million. The initial commitment can 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 initial borrowing base has been set at $300 million and
will be redetermined semi-annually with the first redetermination scheduled for
October 1, 2002. 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 ranks senior to all existing debt. Following the closing of the
new 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. Subsequently, we repaid $10 million in borrowings under the new
facility and as of August 12, 2002, $160 million was outstanding under the new
credit facility and $0.4 million was outstanding in letter of credit
obligations.

10

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Interest is payable on borrowings under the new credit facility, as
follows:

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

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

Interest is payable on base rate loans on the last day of each calendar quarter.
Interest on fixed rate loans is generally payable on 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.

The new 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 new credit facility also
restricts and limits our ability to make 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 the July 18, 2002, the closing date of the new credit facility, 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. At June 30, 2002, the
borrowing base amount was $250 million. 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. At June 30, 2002, $180 million was
outstanding under the credit facility and $0.4 million was outstanding in letter
of credit obligations. Subsequent to June 30, 2002 and prior to entering the new
facility on July 15, 2002, we reduced our net borrowings by $10 million under
the previous credit facility.

Our previous revolving bank credit facility contained negative
covenants that placed restrictions on, among other things, the incurrence of
debt, guaranties, liens, leases and certain investments. Cash dividends and/or
purchase or redemption of our stock was restricted as well as the sale or
encumbering of our oil and gas assets or the pledging of our oil and gas assets.
Financial covenants set limits on natural gas hedging and required us to
maintain specified interest coverage and debt to equity ratios. As of June 30,
2002, we were in compliance with all covenants and restrictions under the
previous revolving bank credit facility.

Senior Subordinated Notes

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

11

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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.

NOTE 3 -- COMMITMENTS AND CONTINGENCIES

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.

NOTE 4 -- RELATED PARTY TRANSACTIONS

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% 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.

During the initial two-year term of the joint venture, we drilled a
total of 21 wells: 17 exploratory wells and four development wells. Five of the
wells drilled were unsuccessful. During 2001, KeySpan participated in the
drilling of three additional wells, all of which were successful. These wells
further developed or delineated reservoirs discovered during the initial term of
the joint venture. For 2002, KeySpan has committed to a capital budget of $15
million for development projects associated with its working interests in wells
drilled under the joint venture during 1999, 2000 and 2001. During the first
half 2002, KeySpan participated in three wells, all of which were successful and
provided further exploitation of previous discoveries, and spent $14.6 million
in capital costs compared to $10.1 million spent during the first half of 2001.
For the second quarter of 2002, KeySpan spent $5.1 million in capital costs
compared to $7.4 million spent during the corresponding quarter of 2001.

12

THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

NOTE 5 -- ACQUISITION

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. Production from the
acquired properties for the month of June 2002 averaged 14 MMcfe/day, net to the
interests acquired.

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 and average daily production of 2 Mcfe/day, net to our
interest. Proceeds from the sale were used to repay borrowings under our new
revolving bank credit facility.

We expect to retain 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.

13

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

The following discussion is intended to assist in an understanding of
our historical financial position and results of operations for the three months
ended June 30, 2002 and 2001. Our consolidated financial statements and notes
thereto included elsewhere in this report contains detailed information that
should be referred to in conjunction with the following discussion.

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

o high potential offshore exploration and exploitation;

o lower risk exploitation and development drilling onshore; and

o selective acquisitions both offshore and onshore.

At December 31, 2001, our net proved reserves were 608 billion cubic
feet equivalent or Bcfe, with a present value, discounted at 10% per annum, of
cash flows before income taxes of $714 million. Our reserves are fully
engineered on an annual basis by two independent petroleum engineering
companies. Our focus is natural gas. Approximately 93% of our net proved
reserves at December 31, 2001 were natural gas of which approximately 74% of our
net proved reserves were classified as proved developed. We operate
approximately 85% of our properties.

We began exploring for natural gas and oil in December 1985 on behalf
of The Brooklyn Union Gas Company. Brooklyn Union is an indirect wholly owned
subsidiary of KeySpan Corporation. KeySpan, a member of the Standard & Poor's
500 Index, is a diversified energy provider whose principal natural gas
distribution and electric generation operations are located in the Northeastern
United States. In September 1996 we completed our initial public offering and
sold approximately 34% of our shares to the public with KeySpan retaining the
balance. As of June 30, 2002, THEC Holdings Corp., an indirect wholly owned
subsidiary of KeySpan, owned approximately 67% of the outstanding shares of our
common stock.

As an independent oil and gas producer, our revenue, profitability and
future rate of growth are substantially dependent upon prevailing prices for
natural gas and oil, our ability to find and produce 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, as evidenced by the recent volatility of
natural gas and oil prices, 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

Full Cost Accounting. We use the full cost method to account for our
natural gas and oil properties. Under full cost accounting, all costs incurred
in the acquisition, exploration and development of natural gas and oil reserves
are capitalized into a "full cost pool". Capitalized costs include costs of all
unproved properties, internal costs directly related to our natural gas and oil
activities and capitalized interest. We amortize these costs using a
unit-of-production method. We compute the provision for depreciation, depletion
and amortization quarterly by multiplying production for the quarter by a
depletion rate. The depletion rate is determined by dividing our total
unamortized cost base by net equivalent proved reserves at the beginning of the
quarter. Unevaluated properties and related costs are excluded from our
amortization base until we have made a determination as to the existence of
proved reserves. Our amortization base includes estimates for future development
costs as well as future abandonment and dismantlement costs. 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.

14

Under full cost accounting rules, total capitalized costs are limited
to a ceiling of 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 Statement of Financial Accounting Standards ("SFAS") No. 133 to
hedge against the volatility of natural gas prices, and in accordance with
current Securities and Exchange Commission guidelines, we include estimated
future cash flows from our hedging program in our ceiling test calculation. In
calculating our ceiling test at June 30, 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 generally accepted accounting principles requires
our management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the dates of the financial statements and the reported amounts of
revenues and expenses during the reporting periods. Our most significant
financial estimates are based on remaining proved natural gas and oil reserves.
Estimates of proved reserves are key components of our depletion rate for
natural gas and oil properties and our full cost ceiling test 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, including many factors beyond our
control. Reservoir engineering is a subjective process of estimating underground
accumulations of natural gas and oil that cannot be measured in an exact manner.
The accuracy of any reserve estimate is a function of the quality of available
data and of engineering and geological interpretation and judgment. In addition,
estimates of reserves may be revised based upon actual production, results of
future development and exploration activities, prevailing natural gas and oil
prices, operating costs and other factors, which revision may be material.
Reserve estimates are highly dependent upon the accuracy of the underlying
assumptions. Actual future production may be materially different from estimated
reserve quantities and the differences could materially affect future
amortization of natural gas and oil properties.

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 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 marketers have
affected the liquidity of several of our purchasers. We estimate that our
current receivable exposure for June and July natural gas and oil sales is
approximately $1.0 million from subsidiaries of Williams Companies, Inc., $2.4
million from subsidiaries of Reliant Energy Incorporated (which is due at the
end of August 2002) and $0.4 million from Dynegy Inc. As of August 1, 2002, we
are no longer selling natural gas and oil to Williams, Reliant and Dynegy. Based
on the current demand for natural gas and oil, we do not expect that termination
of sales to these companies will limit 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

15

and historically we have not experienced credit losses. In July 2002, our
outstanding swap and option contracts with Williams were assigned to Bank of
America. We believe that the 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 lowers our overall business risk.

New Accounting Pronouncements

Statement of Financial Accounting Standards ("SFAS") No. 143,
"Accounting for Asset Retirement Obligations," addresses accounting and
reporting for obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs. SFAS No. 143 will be effective
for us January 1, 2003 and early adoption is encouraged. SFAS No. 143 requires
that the fair value of a liability for an asset's retirement obligation be
recorded in the period in which it is incurred and the corresponding cost
capitalized by increasing the carrying amount of the related long-lived asset.
The liability is accreted to its then present value each period, and the
capitalized cost is depreciated over the useful life of the related asset. If
the liability is settled for an amount other than the recorded amount, a gain or
loss is recognized. Currently, we include estimated future costs of abandonment
and dismantlement in our full cost amortization base and amortize these costs as
a component of our depletion expense. We are evaluating the impact the new
standard will have on our financial statements and at this time we cannot
reasonably estimate the effect of the adoption of this statement.

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 with earlier adoption encouraged. We
do not expect the adoption of SFAS No. 145 to have a material impact on our
financial position, results of operations or cash flows.

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

The FASB is currently considering numerous proposals for the adoption
of new accounting pronouncements. We cannot predict whether any of these
proposals will be adopted, and if adopted, what effect these proposals,
including the proposal to require the reporting of stock options grants as a
compensation expense, may have on our financial statements.

16

Recent Acquisitions

Within the last six months, we have expanded our existing operations in
South Texas with two producing property acquisitions: (i) the Conoco
Acquisition, completed December 31, 2001, and (ii) the Burlington Acquisition,
completed May 30, 2002.

Conoco Acquisition. On December 31, 2001, we completed the purchase
from Conoco Inc. of natural gas and oil properties and associated gathering
pipelines and equipment, together with developed and undeveloped acreage,
located in the Webb and Zapata counties of South Texas. The $69 million cash
purchase price was financed by borrowings under our revolving bank credit
facility. The properties purchased cover approximately 25,274 gross (16,885 net)
acres located in the Alexander, Haynes, Hubbard and South Trevino Fields, which
are in close proximity to our existing operations in the Charco Field, and
represent interests in approximately 159 producing wells. We operate
approximately 95% of the producing wells we acquired. Our average working
interest is 87%. Total net proved reserves as of January 1, 2002 were 80 Bcfe.
Beginning January 1, 2002, we initiated an active drilling and workover program.
To date we spud 18 development wells, with 15 wells successfully completed and
currently producing, one dry hole and two in progress. Average daily production
has increased from approximately 19 MMcfe/day, net to the interests acquired, in
January 2002 to 32 MMcfe/day, net to our interests, in June 2002. Currently we
have two drilling rigs under contract, which we plan to keep utilized for the
remainder of 2002.

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. Current production from
the acquired properties for the month of June 2002 is averaging 14.0 MMcfe/day,
net to the interests acquired.

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 as the effective date of the
transaction was January 1, 2002. These 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 and average daily production of 2 Mcfe/day, net to our
interest. Proceeds from the sale were used to repay borrowings under our
revolving bank credit facility.

We expect to retain 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 wells from the Wilcox formation, all
of which we operate, and 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.

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 replaces our previous $250 million revolving credit
facility maintained with JPMorgan Chase and provides us with an initial
commitment of $300 million. The initial commitment can 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 initial borrowing base has been set at $300 million and will be
redetermined semi-annually with the first redetermination scheduled for October
1, 2002. 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 ranks senior to all existing debt. Following the closing of the
new credit facility on July 18, 2002, funds were drawn on the new

17

facility and used to repay total outstanding borrowings under the previous
credit facility of $170 million. Subsequently, we repaid $10 million under the
new facility and as of August 12, 2002, $160 million was outstanding under the
new credit facility and $0.4 million was outstanding in letter of credit
obligations.

Offshore Seismic Option Agreement

In June 2002, we entered into a seismic option agreement with Union Oil
Company of California ("Unocal"). The agreement provides us with the ability to
review seismic data that we have acquired for the purposes of delineating new
exploratory prospects in the Gulf of Mexico. The agreement covers approximately
16 blocks on the Outer Continental Shelf that are currently held under lease by
Unocal. The Unocal leases are in close proximity to our existing fields and
acreage. Under the terms of the agreement, Unocal will have the right to
participate with up to a 50% working interest in any prospects we recommend for
drilling. Should Unocal elect to participate in an initial test well, we would
serve as operator. If Unocal elects not to participate in an initial test well,
they would farmout their interest to us. The seismic review period expires
between June 15, 2002 and November 1, 2002, depending on the geographic area,
and Unocal has until January 1, 2003 to elect to participate or farmout their
interests in any prospects we recommend for drilling.

18

RESULTS OF OPERATIONS

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

- ----------

(1) Reflects the effects of hedging.

(2) For the six months ended June 30, 2001, net general and administrative
expense includes one-time payments totaling $5.2 million in connection
with the termination of employment contracts for retiring executives.

RECENT FINANCIAL AND OPERATING RESULTS

COMPARISON OF THREE MONTHS ENDED JUNE 30, 2002 AND 2001

Production. Our production increased 18% from 21,889 million cubic feet
equivalent, or MMcfe, for the three months ended June 30, 2001 to 25,782 MMcfe
for the three months ended June 30, 2002. The increase in production was
primarily attributable to production from two recently completed acquisitions in
South Texas combined with newly developed offshore production brought on-line
since the end of the first half of 2001.

Onshore, our daily production rates increased 26% from an average of
118 MMcfe/day during the second quarter of 2001 to an average of 149 MMcfe/day
during the corresponding three months of 2002. The onshore production increase
is primarily attributable to newly acquired production from the South Texas
properties purchased from Conoco Inc. on December 31, 2001, which accounts for
29 MMcfe/day of the increase, and from the properties purchased on May 30, 2002
from Burlington Resources, which accounts for 5 MMcfe/day of the increase for
the quarter. Production at our Charco Field remained unchanged at 82 MMcfe/day
during both the second quarter of 2002 and the second quarter of 2001.
Production from our Arkoma, East Texas and West Virginia fields remained
unchanged at approximately 26 MMcfe/day. Production in South Louisiana decreased
by 3 MMcfe/day from 10 MMcfe/day during the second quarter of 2001 to 7
MMcfe/day during the second quarter of 2002.

Offshore, our production increased 9% from an average of 123 MMcfe/day
during the second quarter of 2001 to an average of 134 MMcfe/day during the
second quarter of 2002. This increase is primarily attributable to new natural
gas production at South March Island 253 and High Island 39, both of which came
on-line during the second half of 2001, successful recompletion of four existing
wells at Mustang Island 785 during the third quarter of 2001, combined with new
oil production at Vermilion 408, which came on-line during January 2002 and new

19

natural gas production at East Cameron 81 with new wells coming on-line during
both the first and second quarters of 2002.

Natural Gas and Oil Revenues. Natural gas and oil revenues decreased
16% from $98.9 million for the second quarter of 2001 to $83.4 million for the
second quarter of 2002 as a result of a 30% decrease in average realized natural
gas prices, from $4.54 per Mcf during the second quarter of 2001 to $3.19 per
Mcf in the second quarter of 2002, offset in part by an 18% increase in
production for the same period.

Natural Gas Prices. For the second quarter of 2002, we realized an
average gas price of $3.19 per Mcf that was equal to our average unhedged
natural gas price. Natural gas and oil revenues for the second quarter of 2002
were $12,000 higher than the revenues we would have achieved if hedges had not
been in place during the period. For the corresponding period during 2001, we
realized an average gas price of $4.54 per Mcf, which was 101% of the average
unhedged natural gas price of $4.48 that otherwise would have been received,
resulting in natural gas and oil revenues that were $1.3 million higher 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 16% from $6.8 million for the three months ended June 30, 2001 to $7.9
million for the corresponding three months of 2002. On an Mcfe basis, lease
operating expenses were unchanged at $0.31 per Mcfe during both the second
quarter of 2001 and the second quarter of 2002. The increase in lease operating
expenses is attributable to the continued expansion of our operations both
onshore and offshore. Onshore operations expanded with the acquisition of
approximately 305 new producing wells in South Texas with the December 31, 2001
acquisition from Conoco and the May 30, 2002 acquisition from Burlington
Resources. Offshore, we added new production facilities since the second half of
2001 at High Island 39, Vermilion 408 and East Cameron 81. The flat rate of
$0.31 per Mcfe is a result of the 18% increase in production volume for the
second quarter of 2002. Severance tax, which is a function of volume and
revenues generated from onshore production, decreased 7% from $3.0 million for
the second quarter of 2001 to $2.8 million for the second quarter of 2002. On an
Mcfe basis, severance tax decreased 21% from $0.14 per Mcfe for the second
quarter of 2001 to $0.11 per Mcfe during the second quarter of 2002. The
decrease in severance tax expense and severance tax per Mcfe is primarily
attributable to lower natural gas prices received during the second quarter of
2002 offset only in part by the increase in our onshore production during the
current year.

Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased 40% from $30.0 million for the three months ended
June 30, 2001 to $42.0 million for the three months ended June 30, 2002.
Depreciation, depletion and amortization expense per Mcfe increased 19% from
$1.37 for the three months ended June 30, 2001 to $1.63 for the corresponding
three months in 2002. 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 during the second quarter of 2002 is a
result of higher finding and development costs together with the addition of
fewer new reserves from exploration and developmental drilling. 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 $0.3 million for both the three months ended June 30, 2001 and 2002
and capitalized general and administrative expenses directly related to oil and
gas exploration and development activities of $2.5 million and $3.1 million for
the three months ended June 30, 2001 and 2002, respectively, decreased 4% from
$2.6 million for the three months ended June 30, 2001 to $2.5 million for the
three months ended June 30, 2002. We capitalized more general and administrative
expense during the second quarter of 2002 as a result of an increase in
aggregate general and administrative expenses. Aggregate general and
administrative expenses increased 7% from $5.5 million for the second quarter of
2001 to $5.9 million for the second quarter of 2002. The increase in aggregate
expense is primarily a result of the expansion of our workforce and office space
in Houston during the first half of 2002 combined with an increase in employee
benefit expenses, legal and consulting fees.

On an Mcfe basis, net general and administrative expenses decreased 17%
from $0.12 during the second

20

quarter of 2001 to $0.10 per Mcfe during the second quarter of 2002. The lower
rate per Mcfe during the second quarter of 2002 reflects the 18% increase in
production for the second quarter of 2002 together with the 4% decrease in net
general and administrative expenses.

Other Income and Expense - Strategic Review Expenses. We recognized no
other income or expense during the second quarter of 2002, however, for the
second quarter of 2001, we paid additional expenses of $1.5 million incurred in
connection with the review of strategic alternatives for our company which was
initiated at the end of the third quarter of 1999. 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.
KeySpan was assessing our role within its future strategic plan, and was
considering a full range of strategic transactions including the possible sale
of all or a portion of our assets. On February 25, 2000, we announced, together
with KeySpan, that the review of strategic alternatives for Houston Exploration
had been completed.

KeySpan currently holds approximately 67% of our outstanding common
stock. 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, but cannot predict when, or if, any such sale or disposition
may take place.

During the first quarter of 2000, we established a reserve for
strategic review expenses of $1.8 million. At March 31, 2001, we reevaluated the
established reserve and felt that a portion of the reserve was no longer
required. As a result of this reevaluation, during the first quarter of 2001, we
recognized $1.4 million in other income relating to the reversal of a portion of
the reserve. As noted above, the reserve was ultimately required. The net effect
of the first quarter 2001 reversal of $1.4 million and the second quarter
payment and recognition of $1.5 million in additional expenses is $119,000 in
additional strategic review expenses for the six months ended June 30, 2001.

Interest Expense, Net of Capitalized Interest. Interest expense, net of
capitalized interest, increased 220% from $0.5 million for the three months
ended June 30, 2001 to $1.6 million for the corresponding three months of 2002.
The increase in net interest expense is a direct result of a decrease in
capitalized interest during the second quarter of 2002 as aggregate interest
expense was unchanged at $3.6 million during both the second quarter of 2001 and
the second quarter of 2002. Capitalized interest decreased 35% from $3.1 million
for the second quarter of 2001 to $2.0 million for the second quarter of 2002
and corresponds to the a decrease in exploratory drilling during the second
quarter of 2002 (our capitalized interest is a function of exploratory drilling
and unevaluated properties, both of which were at lower levels during the second
quarter of 2002). Aggregate interest is unchanged due to a combination of higher
average borrowings of $261 million for the second quarter of 2002 compared to
$183 million during the second quarter of 2001 and lower average interest rates
of 5.28% during the second quarter of 2002 compared to 6.16% during the second
quarter of 2001.

Income Tax Provision. The provision for income taxes decreased 52% from
$19.0 million for the second quarter of 2001 to $9.2 million for the
corresponding three months of 2002 due to the 51% decrease in pre-tax income
during the second quarter of 2002 from $54.8 million during the second quarter
of 2001 to $26.9 million during the second quarter of 2002 as a result of lower
natural gas revenues combined with both an increase in operating and interest
expenses.

Operating Income and Net Income. For the three months ended June 30,
2002, operating income decreased 50% from $56.9 million during the second
quarter of 2001 to $28.5 million during the second quarter of 2002 as a result
of a 16% decrease in total revenues caused by a 30% decrease in realized natural
gas prices offset only in part by an 18% increase in production, combined with a
30% increase in operating expenses. Corresponding to the decrease in operating
income, net income decreased 51% from $35.9 million for the second quarter of
2001 to $17.7 million for the second quarter of 2002 and includes the effects of
higher interest expense and lower taxes.

21

COMPARISON OF SIX MONTHS ENDED JUNE 30, 2002 AND 2001

Production. Our production increased 13% from 44,656 million cubic feet
equivalent, or MMcfe, for the six months ended June 30, 2001 to 50,637 MMcfe for
the six months ended June 30, 2002. The increase in production was primarily
attributable to newly acquired onshore production pursuant to our two South
Texas producing property acquisitions made since December 31, 2001 together with
newly developed offshore production brought on-line since the end of the first
half of 2001.

Onshore, our daily production rates increased 20% from an average of
122 MMcfe/day during the first half of 2001 to an average of 146 MMcfe/day
during the corresponding six months of 2002. Properties acquired from Conoco
Inc. on December 31, 2001 accounted for an increase of 24 MMcfe/day for 2002 and
properties acquired on May 30, 2002 from Burlington Resources accounted for an
increase of 3 MMcfe/day for the six month period. Production from our Charco
Field in South Texas decreased slightly by 2% or 2 MMcfe/day from 87 MMcfe/day
during the first half of 2001 to 85 MMcfe/day during the first half of 2002.
Production from all other onshore areas (Arkoma, East Texas, West Virginia and
South Louisiana) decreased slightly from an average of 35 MMcfe/day during the
first half of 2001 to 34 MMcfe/day during the corresponding period of 2002.

Offshore, our production increased 7% from an average of 125 MMcfe/day
during the first half of 2001 to an average of 134 MMcfe/day during the first
half of 2002. This increase is primarily attributable to new natural gas
production at South March Island 253 and High Island 39, both of which came
on-line during the second half of 2001, combined with new oil production at
Vermilion 408, which came on-line during January 2002 and new natural gas
production from East Cameron 81 with new wells coming on-line during both the
first and second quarters of 2002.

Natural Gas and Oil Revenues. Natural gas and oil revenues decreased
30% from $222.9 million for the first six months of 2001 to $155.8 million for
the first six months of 2002 as a result of a 39% decrease in average realized
natural gas prices, from $5.02 per Mcf during the first half of 2001 to $3.05
per Mcf in the first half of 2002, offset in part by 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 $3.05 per Mcf for the six months ended June 30, 2002, which
was 113% of the average unhedged natural gas price of $2.70 that otherwise would
have been received, resulting in natural gas and oil revenues for the six months
ended June 30, 2002 that were $17.0 million higher than the revenues we would
have achieved if hedges had not been in place during the period. For the
corresponding period during 2001, we realized an average gas price of $5.02 per
Mcf, which was 88% of the average unhedged natural gas price of $5.69 that
otherwise would have been received, resulting in natural gas and oil revenues
that were $29.2 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 18% from $13.0 million for the six months ended June 30, 2001 to $15.3
million for the corresponding six months of 2002. On an Mcfe basis, lease
operating expenses increased from $0.29 per Mcfe during the first half of 2001
to $0.30 per Mcfe during the first half of 2002. The increase in both lease
operating expenses and lease operating expense on a per unit basis for 2002 is
attributable to the continued expansion of our operations both onshore and
offshore as we acquired approximately 305 producing wells in South Texas since
the beginning of 2002 and we added new offshore production facilities since the
second half of 2001. Severance tax, which is a function of volume and revenues
generated from onshore production, decreased 42% from $7.7 million for the first
six months of 2001 to $4.5 million for the corresponding period of 2002. On an
Mcfe basis, severance tax decreased from $0.17 per Mcfe for the first half of
2001 to $0.09 per Mcfe during the first half of 2002. The decrease in severance
tax expense and severance tax per Mcfe is primarily due to lower natural gas
prices received during the first six months of 2002 as compared to prices
received during the first six months of 2001 offset only in part by the increase
in onshore production during the first half of 2002.

Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased 36% from $60.3 million for the six months ended
June 30, 2001 to $81.8 million for the six months ended June 30, 2002.
Depreciation, depletion and amortization expense per Mcfe increased 20% from
$1.35 for the six months ended June 30, 2001 to $1.62 for the corresponding six
month period of 2002. The increase in depreciation,

22

depletion and amortization expense was a result of higher production volumes
combined with a higher depletion rate. The higher depletion rate during the
first half of 2002 is a result of higher finding and development costs incurred
during 2002 together with the addition of fewer new reserves from exploration
and developmental drilling. 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 $0.6 million and $0.9 million for the six months ended June 30, 2001
and 2002, respectively, and capitalized general and administrative expenses
directly related to oil and gas exploration and development activities of $7.4
million and $6.4 million, respectively, for the six months ended June 30, 2001
and 2002, decreased 45% from $10.6 million for the six months ended June 30,
2001 to $5.8 million for the six months ended June 30, 2002. Included in general
and administrative expense for the first half of 2001 were payments totaling
$5.2 million made in connection with the termination of former executive
officers' employment contracts.

Excluding the one-time charges taken for the termination of employment
contracts totaling $5.2 million during the first half of 2001, aggregate general
and administrative expenses would have been $13.4 million for the first half of
2001 compared to $13.1 million for the first half of 2002, reflecting a small
decrease of 2% for the current six month period which was due primarily to a
decrease in incentive compensation expense during 2002 as the first half of 2001
included the payment of a special bonus in January 2001. Excluding these same
one-time charges of $5.2 million during the first half of 2001, net general and
administrative expenses would have been $5.4 million during the first six months
of 2001 compared to $5.8 million for the corresponding period of 2002,
reflecting a 7% increase in net general and administrative expenses for the
first six months of 2002. The increase in net general and administrative
expenses during 2002 is due primarily to a decrease in capitalized general and
administrative expenses from $7.4 million during the first half of 2001 to $6.4
million during the second half of 2002. The decrease in capitalized general and
administrative expense during the first half of 2002 is a result of a change in
the mix of types of expenses being incurred. We incurred more expenses such as
consulting and legal fees that are not directly related to our natural gas and
oil finding and development activities.

On an Mcfe basis, net general and administrative expenses decreased 50%
from $0.24 during the first half of 2001 to $0.12 per Mcfe during the first half
of 2002. Excluding the one-time charges taken in the first half 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
$0.12 for both the first half of 2001 and the first half of 2002. The flat rate
per Mcfe reflects the increase in net general and administrative expenses during
2002 as result of a reduction in capitalized general and administrative expenses
during the second half of 2002 combined with an increase in production volume
for the current period.

Other Income and Expense - Strategic Review Expenses. During the first
six months of 2001, we incurred an additional $119,000 in strategic review
expenses. 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. KeySpan was assessing our role within its
future strategic plan, and was considering a full range of strategic
transactions including the possible sale of all or a portion of our assets. On
February 25, 2000, we announced, together with KeySpan, that the review of
strategic alternatives for Houston Exploration had been completed.

KeySpan currently holds approximately 67% of our outstanding common
stock. 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, but cannot predict when, or if, any such sale or disposition
may take place.

Interest Expense, Net of Capitalized Interest. Interest expense, net of
capitalized interest, increased 20% from $2.5 million for the first six months
of 2001 to $3.0 million for the first six months of 2002. Aggregate interest
expense decreased 17% from $8.7 during the first half of 2001 to $7.2 million
during the corresponding six month

23

period of 2002. The decrease in aggregate interest is due to a decrease in
interest rates from an average borrowing rate of 7.20% during the first half of
2001 to an average borrowing rate of 5.32% during the first half of 2002 offset
in part by an increase in our average borrowings from $210 million during the
first six months of 2001 to an average of $256 million for the corresponding
period of 2002. Capitalized interest decreased 32% from $6.2 million for the
first half of 2001 to $4.2 million for the first half of 2002 and corresponds to
the decrease in aggregate interest expense combined with a decrease in
exploratory drilling during the first half of 2002 (our capitalized interest is
a function of exploratory drilling and unevaluated properties, both of which
were at lower levels during the first half of 2002).

Income Tax Provision. The provision for income taxes decreased 66% from
$46.3 million for the first six months of 2001 to $15.7 million for the first
six months of 2002 due to the 65% decrease in pre-tax income during the first
half of 2002 from $129.5 million during the first half of 2001 to $45.9 million
during the first half of 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. For the six months ended June 30,
2002, operating income decreased 63% from $132.1 million during the first half
of 2001 to $48.9 million as a result of a decrease in revenues caused by a 39%
decrease in realized natural gas prices offset only in part by the 13% increase
in production combined with a 17% increase in operating expenses. Corresponding
to the decrease in operating income, net income decreased 64% from $83.2 million
for the first half of 2001 to $30.2 million for the first half of 2002 and
includes the effects of higher interest expense and lower taxes.

LIQUIDITY AND CAPITAL RESOURCES

We have historically funded our operations, acquisitions, capital
expenditures and working capital requirements from cash flows from operations,
equity capital from KeySpan as well as public sources, public debt and bank
borrowings. 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 2002.

Cash Flows From Operations. As of June 30, 2002, we had working capital
of $23.5 million and $69.6 million of borrowing capacity available under our
revolving bank credit facility. Net cash provided by operating activities for
the six months ended June 30, 2002 was $108.0 million compared to $218.1 million
during the corresponding period of 2001. The decrease in net cash provided by
operating activities was due to (i) a decrease in net income caused primarily by
lower realized natural gas prices during the first half of 2002, offset in part
by an increase in production for the corresponding period combined with (ii) a
decrease in current assets and current liabilities which is related to the
timing of cash receipts and payments. Funds used in investing activities
consisted of $130.7 million for net investments in property and equipment, which
compares to $147.0 million spent during the corresponding period of 2001. Our
cash position increased during the first half of 2002 as a result of net
borrowings under our revolving bank credit facility of $36 million compared to
repayments totaling $85 million during the first half of 2001. Cash increased by
$1.2 million and $8.1 million, respectively, during the first six months of 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 $14.5 million from $8.6 million at December 31, 2001 to
$23.1 million at June 30, 2002.

Capital Expenditures. During the first six months of 2002, we invested
$129.6 million in natural gas and oil properties and $1.3 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.
Included in our natural gas and oil property additions was $9.2 million for
exploration, $57.4 million for development drilling, workovers and construction
of platforms and pipelines, $44.5 million for producing property acquisitions
and $18.5 million for other leasehold and leasehold acquisition costs which
includes seismic, capitalized interest and capitalized general and
administrative costs.

Our capital expenditure budget for 2002, set by our Board of Directors,
is $250 million. Typically, we do not include property acquisition costs in our
capital expenditure budget as the size and timing of capital requirements for
property acquisitions are inherently unpredictable. However, we have allocated a
portion of our 2002 capital expenditure budget to include the May 30, 2002
acquisition of producing properties in South Texas

24

from Burlington Resources as we plan to repay the borrowings made under our
credit facility for the $44.5 million purchase price from cash flows generated
from operations. The capital expenditure budget includes development costs
associated with recent acquisitions and discoveries and amounts are contingent
upon drilling success. No significant abandonment or dismantlement costs are
anticipated in 2002. We will continue to evaluate our capital spending plans
throughout the year. Actual levels of capital expenditures may vary
significantly due to a variety of factors, including drilling results, natural
gas prices, industry conditions and outlook and future acquisitions of
properties. We intend to continue to selectively seek acquisition opportunities
for proved reserves with substantial exploration and development potential both
offshore and onshore, although we may not be able to identify and make
acquisitions of proved reserves on terms we consider favorable.

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

Capital Structure

Revolving Bank Credit Facility. We 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 replaces our previous
$250 million revolving credit facility maintained with JPMorgan Chase and
provides us with an initial commitment of $300 million. The initial commitment
can 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 initial borrowing base has been set at $300
million and will be redetermined semi-annually with the first redetermination
scheduled for October 1, 2002. 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 ranks senior to all existing debt.

At June 30, 2002, outstanding borrowings under our previous revolving
credit facility were $180 million together with $0.4 million in outstanding
letter of credit obligations. Subsequent to June 30, 2002 and prior to entering
the new facility on July 15, 2002, we reduced our net borrowings under the
previous credit facility by $10 million. Following the July 18, 2002 closing of
the new credit facility, funds were drawn on the new facility and used to repay
total outstanding borrowings under our previous credit facility of $170 million.
Subsequently, we repaid $10 million under the new facility and as of August 12,
2002, total borrowings under the new facility were $160 million and $0.4 million
was outstanding under letter of credit obligations.

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

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Natural Gas Hedging

We utilize derivative commodity instruments to hedge future sales
prices on a portion of our natural gas production to achieve a more predictable
cash flow, as well as to reduce our exposure to adverse price fluctuations of
natural gas. Our derivatives are not held for trading purposes. While the use of
hedging arrangements limits the downside risk of adverse price movements, it
also limits increases in future revenues as a result of favorable price
movements. The use of hedging transactions also involves the risk that the
counterparties are unable to meet the financial terms of such transactions.
Hedging instruments that we use are swaps, collars and options, which we
generally place with major investment grade financial institutions that we
believe are minimal credit risks and historically, we have not experienced
credit losses. Due to the downgrading of the credit rating of Williams
Companies, Inc., our outstanding swap and option contracts held with
subsidiaries Williams were assigned to Bank of America in July 2002. We believe
that the 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 lowers our overall business risk.

Our hedges are cash flow hedges and qualify for hedge accounting under
SFAS 133 and, accordingly, we carry the fair market value of our derivative
instruments on the balance sheet as either an asset or liability and defer
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.

The following table summarizes the change in the fair value of our
derivative instruments for the six month periods from January 1 to June 30, 2002
and 2001, respectively, and does not include the effects of taxes.

26

The following table summarizes, on a monthly basis, our hedges for 2002
and 2003. All amounts are in thousands, except for prices. For the remaining
months of 2002, we have hedged approximately 64% of our estimated production or
a total of 190,000 MMBtu/day at an effective floor of $3.389 and an effective
ceiling of $4.801. For the year 2003, we have 110,000 MMBtu/day hedged at an
effective floor of $3.352 and an effective ceiling of $4.324.

These hedging transactions are settled based upon the New York
Mercantile Exchange or NYMEX price on the final trading 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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PART II. OTHER INFORMATION

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

On May 12, 2002, the company held its annual meeting of stockholders.
All matters brought for a vote before the shareholders as listed in the
Company's proxy statement were approved as follows:

1. The election of the following nine Directors of the Company to serve
until the Company's next annual meeting:

2. The appointment of Deloitte & Touche LLP as the Company's
independent public accountants for the fiscal year ending December 31, 2002.

3. Approval of the 2002 Incentive Stock Plan.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K:

(a) Exhibits:

EXHIBITS DESCRIPTION

10.1(1) -- Revolving Credit Facility between The Houston Exploration
Company and Wachovia Bank, National Association, as issuing
bank and administrative agent, Bank of Nova Scotia and Fleet
National Bank as co-syndication agents and BNP Paribas as
documentation agent dated July 15, 2002.

10.2(1)(2) -- First Amendment to Employment Agreement between The Houston
Exploration Company and William G. Hargett dated May 17, 2002.

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99.1(1) -- Certification of William G. Hargett, Chief Executive Officer,
as required pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.

99.2(1) -- Certification of James F. Westmoreland, Chief Accounting
Officer, as required pursuant to Section 906 of the Sarbanes -
Oxley Act of 2002.

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

(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.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned, hereunto duly authorized.

THE HOUSTON EXPLORATION COMPANY

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

By: /s/ JAMES F. WESTMORELAND
------------------------------------------------
Date: August 12, 2002 James F. Westmoreland
Vice President, Chief Accounting Officer
and Secretary

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EXHIBIT INDEX

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