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 MARCH 31, 2003

OR

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

FOR THE TRANSITION PERIOD FROM TO
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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 2000
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 [ ]

Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Securities Exchange Act of 1934).
Yes [X] No [ ]

As of May 5, 2003, 30,968,118 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
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 2. 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 writedowns 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
10-K.

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 THE 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 offshore operations are focused in the shallow waters of
the Gulf of Mexico and our onshore core operations are focused in South Texas
and in the Arkoma Basin with additional production located in East Texas, South
Louisiana and West Virginia.

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 March 31, 2003 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 accounting principles generally
accepted in the United States ("GAAP") 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, 2002 is
derived from the December 31, 2002 audited financial statements, but does not
include all disclosures required by accounting principles generally accepted in
the United States. 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, 2002.

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.

Use of Estimates and Restatements

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 for the
three months ended March 31, 2002 were added back to revenues and reflected as a
separate component of operating expense and accordingly, the Statement of
Operations has been restated for the three months ended March 31, 2002. The
application of EITF No. 00-10 has no effect on income from operations or net
income. The table below provides a summary of the effects of application of EITF
No. 00-10 for amounts reported in for the three month period ended March 31,
2002.

-7-

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

The preparation of the consolidated financial statements in conformity
with GAAP 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.

Derivative Instruments

Our hedges are designated cash flow hedges and qualify for hedge
accounting under Statements of Financial Accounting Standards ("SFAS") No. 133,
as amended, "Accounting for Derivative Instruments and Hedging Activities" 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.

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.

For the three months ended March 31, 2003 and 2002, the calculation of
shares outstanding for fully diluted EPS does not include the effect of
outstanding stock options to purchase 1,903,561 and 1,255,343 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.

Comprehensive Income (Loss)

The table below summarizes our comprehensive income for the three
months ended March 31, 2003 and 2002. Comprehensive income consists of net
income and other gains and losses affecting stockholders' equity that, under
GAAP, are excluded from net income. For our company, other comprehensive income
consists only of unrealized gain or loss, net of tax effects, of the change in
the fair market value of our derivative instruments from period to period.

-8-

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

Stock Option Expense

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." Under the fair value method, compensation expense for stock
options is recognized when stock options are issued. SFAS No. 148 proposes three
alternative transition methods for a voluntary change to 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, we now
recognize as compensation expense the fair value of all stock options issued
subsequent to December 31, 2002. For the three months ended March 31, 2003, we
recognized compensation expense of $14,000 for stock options granted during the
period.

Prior to our January 1, 2003 adoption of SFAS No. 123, we accounted for
the incentive stock plans using the intrinsic value method prescribed under
Accounting Principles Board Opinion No. 25 and accordingly we did not recognize
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 three months ended March 31, 2003 and 2002.

-9-

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

Asset Retirement Obligations

On January 1, 2003, we adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations," which addresses accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. For us, asset retirement obligations
represent the systematic, monthly accretion and depreciation of future
abandonment costs of tangible assets such as platforms, wells, service assets,
pipelines, and other facilities. 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 if a reasonable estimate of fair value can be made, and
that the corresponding cost is capitalized as part of 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. Under our previous accounting method, we
included estimated future costs of abandonment and dismantlement in our full
cost amortization base and amortized these costs as a component of our depletion
expense.

Pursuant to the January 1, 2003 adoption of SFAS No. 143 we:

o recognized a charge to income during the first quarter of 2003
of $2.8 million, net of tax, for the cumulative effect of the
change in accounting principle;

o increased our total liabilities by $57.2 million to record the
asset retirement obligations ("ARO");

o increased our assets by $42.5 million to add the asset
retirement costs to the carrying amount of our natural gas and
oil properties; and

o reduced our accumulated depreciation, depletion and
amortization by $10.4 million for the amount of expense
previously recognized.

Adopting SFAS No. 143 had no impact on our reported cash flows. The
following table describes on a pro forma basis our asset retirement liability as
if SFAS No. 143 had been adopted on January 1, 2002.

The following table describes the pro forma effect on net income and
earnings per share for the three months ended March 31, 2002 as if SFAS No. 143
had been adopted on January 1, 2002.

-10-

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

Recent Accounting Pronouncements

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 No. 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. Our adoption of SFAS No. 145 on
January 1, 2003 had no effect on our financial statements.

In June 2002, FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" which addresses accounting and
reporting for costs associated with exit or disposal activities and nullifies
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. Our adoption of SFAS No. 146 on January 1, 2003 had no effect on our
financial statements.

In November 2002, FASB issued Financial Interpretation ("FIN") No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others." FIN 45 requires certain
guarantees to be recorded at fair value, which is different from the current
practice of recording a liability only when a loss is probable and reasonably
estimable, as those terms are defined in SFAS No. 5, "Accounting for
Contingencies." FIN 45 has a dual effective date. The initial recognition and
measurement provisions are applicable on a prospective basis to guarantees
issued or modified after December 31, 2002. The disclosure requirements in the
interpretation are effective for financial statements for interim or annual
periods ending after December 15, 2002. As of our December 31, 2002 and March
31, 2003 balance sheet dates, we did not have any guarantees of indebtedness of
others and as a result, our adoption of FIN 45 did not have an effect on our
financial statements.

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 March 31, 2003, the quoted market value of our
$100 million of 8 5/8 Senior Subordinated Notes was 99.9% of the $100 million
carrying value or $99.9 million.

Revolving Bank Credit Facility

We maintain a revolving bank credit facility 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 credit
facility provides us with a commitment of $300 million which 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 credit facility is subject to borrowing base limitations.
Our current borrowing base is $300 million and is redetermined semi-annually,
with the next redetermination scheduled for October 1, 2003. Up to $25 million
of the borrowing base is available for the issuance of letters of credit. The
credit facility matures July 15, 2005, is unsecured and with the exception of
trade payables, ranks senior to all of our existing debt. At March 31, 2003,
$130 million in borrowings were outstanding under the credit facility and $15.5
million was outstanding in letter of credit obligations. Subsequent to March 31,
2003, we repaid a net $35 million under the facility

-11-

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

and reduced our letter of credit obligations to $9.4 million. Currently,
outstanding borrowings and letter of credit obligations under our revolving bank
credit facility total $104.4 million.

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.

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 March 31, 2003 and December 31, 2002, we were in compliance with all
covenants.

Senior Subordinated Notes

On March 2, 1998, we issued $100 million of 8 5/8 senior subordinated
notes due January 1, 2008. The notes bear interest at a rate of 8 5/8 per annum
with interest payable semi-annually on January 1 and July 1. We may redeem the
notes at our option, in whole or in part, at any time on or after January 1,
2003 at a price equal to 100% of the principal amount plus accrued and unpaid
interest, if any, plus a specified premium 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 the 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.

-12-

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

NOTE 3 -- 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 will
be between $18 million to $24.5 million ($12 million to $15.9 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) and during the
first quarter of 2003, we recorded refunds totaling $10.6 million ($6.9 million
net of tax) for total refunds recorded of $21.0 million ($13.7 million net of
tax). Currently, we estimate that we could record additional refunds of up to
$3.5 million ($2.3 million net of tax). Our receivables at March 31, 2003
include $26.4 million in gross refunds of which approximately $18.5 million
relates to our working interest with the balance owed to third party royalty
interests.

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.

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

NOTE 4 -- RELATED PARTY TRANSACTIONS

Issuance of 3,000,000 Shares to the Public and Concurrent Repurchase of
3,000,000 Shares from KeySpan

In connection with our initial public offering in September 1996, we
entered into a registration rights agreement with KeySpan pursuant to which we
are obligated, at KeySpan's election, to facilitate KeySpan's sale of its shares
of Company stock by registering the shares under the Securities Act of 1933 and
assisting in KeySpan's selling efforts. During February of 2003, KeySpan
notified us of its desire to sell 3,000,000 shares of their Company stock. For
the mutual convenience of the parties, we elected to effect KeySpan's sale
through our pre-existing registration statement rather than filing a separate,
new registration statement for KeySpan. To accomplish the transaction, we
simultaneously sold 3,000,000 newly issued shares of Company stock in a public
offering for net proceeds of $26.40 per share, or an aggregate $79.2 million,
and bought a like number of KeySpan's shares of Company stock for the same price
per share. We cancelled the 3,000,000 shares acquired from KeySpan immediately
following the repurchase. KeySpan reimbursed us for all costs and expenses, and
the transaction had no impact on our capitalization. The transaction was
evidenced in a stock purchase agreement, dated February 26, 2003. Our Board of
Directors approved the transaction in principle and delegated to a special,
independent committee of the Board plenary authority to negotiate the terms of,
and finally approve or veto, the transaction. In finally approving the terms of
the stock purchase agreement, the independent committee determined that the
agreement was consistent with our pre-existing obligations under our
registration rights agreement and that issuing the shares under our existing
registration statement was in the best interests of our public stockholders to
facilitate the prompt and orderly disposition of the shares. As a result of the
transactions, KeySpan's interest in our outstanding shares decreased from 66% to
56%.

-13-

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

Acquisition of KeySpan Joint Venture Assets

In October 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 (see below discussion of KeySpan Joint
Venture). 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.

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. 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.

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. During the first three months of
2003 and 2002, KeySpan spent approximately $3 million and $9.5 million,
respectively, for capital costs associated with its working interests in
properties developed under the joint venture.

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.

-14-

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

We manage and administer the daily operations of the properties in
exchange for an annual management fee of $100,000. The terms of the agreement
expired December 31, 2002 and as a result, we are required to repurchase the
interests in the producing wells from KeySpan. Subsequent to the repurchase,
ownership of the tax credits will revert back to us. We are planning to complete
the repurchase transaction in 2003 and the repurchase price is estimated at
approximately $2.0 million. The income statement effect, representing benefits
received from Section 29 tax credits, was a benefit of $0.2 million for the
three month ended March 31, 2002, with no benefit for 2003.

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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 March 31, 2003 and 2002. 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 offshore operations are focused in the shallow waters of
the Gulf of Mexico and our onshore core operations are focused in South Texas
and in the Arkoma Basin with additional production located in East Texas, South
Louisiana and West Virginia.

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 principle 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 March 31, 2003, THEC Holdings Corp., an indirect wholly owned
subsidiary of KeySpan, owned approximately 56% 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.

Derivative Instruments. Our hedges are designated cash flow hedges and
qualify for hedge accounting under Statement of Financial Accounting Standards
("SFAS") No. 133, as amended, "Accounting for Derivative Instruments and Hedging
Activities" 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 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

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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 our:

o full cost pool; plus,

o estimates for future development costs; less,

o unevaluated properties and their related costs; less,

o estimates for salvage.

Costs associated with unevaluated properties are excluded from the amortization
base until we have made a determination as the existence of proved reserves. We
review our unevaluated properties at the end of each quarter to determine
whether 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 principles generally accepted in the
United States of America ("GAAP") 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.

Accounting for Stock Option Expense

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

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and Disclosure." Under the fair value method, compensation expense for stock
options is recognized when stock options are issued. SFAS No. 148 proposes three
alternative transition methods for a voluntary change to the fair value method
under SFAS No. 123. We adopted SFAS No. 123 using the Prospective Method as
defined by SFAS No. 148, and as a result, we now recognize as compensation
expense the fair value of all stock options issued subsequent to December 31,
2002 with no expense recognized for options issued in previous periods. For the
three months ended March 31, 2003, we recognized compensation expense of $14,000
for stock options granted during the period. Prior to our January 1, 2003
adoption of SFAS No. 123, we accounted for the incentive stock plans using the
intrinsic value method prescribed under Accounting Principles Board Opinion No.
25, and accordingly, we did not recognize compensation expense for stock options
granted.

Accounting for Asset Retirement Obligations

On January 1, 2003, we adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations," which addresses accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. For us, asset retirement obligations
represent the systematic, monthly accretion and depreciation of future
abandonment costs of tangible assets such as platforms, wells, service assets,
pipelines, and other facilities. 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 if a reasonable estimate of fair value can be made, and
that the corresponding cost is capitalized as part of 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. Under our previous accounting method, we
included estimated future costs of abandonment and dismantlement in our full
cost amortization base and amortized these costs as a component of our depletion
expense.

Pursuant to the January 1, 2003 adoption of SFAS No. 143 we:

o recognized a charge to income during the first quarter of 2003
of $2.8 million, net of tax, for the cumulative effect of the
change in accounting principle;

o increased our total liabilities by $57.2 million to record the
asset retirement obligations ("ARO");

o increased our assets by $42.5 million to add the asset
retirement costs to the carrying amount of our natural gas and
oil properties; and

o reduced our accumulated depreciation, depletion and
amortization by $10.4 million for the amount of expense
previously recognized.

Adopting SFAS No. 143 had no impact on our reported cash flows.

Recent Accounting Pronouncements

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 No. 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. Our adoption of SFAS No. 145 on
January 1, 2003 had no effect on our financial statements.

In June 2002, FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" which 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. Our adoption of SFAS No. 146 on January 1,
2003 had no effect on our financial statements.

In November 2002, FASB issued Financial Interpretation ("FIN") No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others." FIN 45 requires certain
guarantees to be recorded at fair value, which is different from the current
practice of recording a liability only when a loss is probable and reasonably
estimable, as those terms are defined in SFAS No. 5, "Accounting for
Contingencies." FIN 45

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has a dual effective date. The initial recognition and measurement provisions
are applicable on a prospective basis to guarantees issued or modified after
December 31, 2002. The disclosure requirements in the interpretation are
effective for financial statements for interim or annual periods ending after
December 15, 2002. As of our December 31, 2002 and March 31, 2003 balance sheet
dates, we did not have any guarantees of indebtedness of others and as a result,
our adoption of FIN 45 did not have an effect on our financial statements.

Issuance of 3,000,000 Shares to the Public and Concurrent Repurchase of
3,000,000 Shares from KeySpan

In connection with our initial public offering in September 1996, we
entered into a registration rights agreement with KeySpan pursuant to which we
are obligated, at KeySpan's election, to facilitate KeySpan's sale of its shares
of Company stock by registering the shares under the Securities Act of 1933 and
assisting in KeySpan's selling efforts. During February of 2003, KeySpan
notified us of its desire to sell 3,000,000 shares of their Company stock. For
the mutual convenience of the parties, we elected to effect KeySpan's sale
through our pre-existing registration statement rather than filing a separate,
new registration statement for KeySpan. To accomplish the transaction, we
simultaneously sold 3,000,000 newly issued shares of Company stock in a public
offering for net proceeds of $26.40 per share, or an aggregate $79.2 million,
and bought a like number of KeySpan's shares of Company stock for the same price
per share. We cancelled the 3,000,000 shares acquired from KeySpan immediately
following the repurchase. KeySpan reimbursed us for all costs and expenses, and
the transaction had no impact on our capitalization. The transaction was
evidenced in a stock purchase agreement, dated February 26, 2003. Our Board of
Directors approved the transaction in principle and delegated to a special,
independent committee of the Board plenary authority to negotiate the terms of,
and finally approve or veto, the transaction. In finally approving the terms of
the stock purchase agreement, the independent committee determined that the
agreement was consistent with our pre-existing obligations under our
registration rights agreement and that issuing the shares under our existing
registration statement was in the best interests of our public stockholders to
facilitate the prompt and orderly disposition of the shares. As a result of the
transactions, KeySpan's interest in our outstanding shares decreased from 66% to
56%.

As KeySpan has announced in the past, it does not consider certain
businesses contained in its energy investments segment, including its investment
in Houston Exploration, a part of its core asset group. KeySpan has stated in
the past that it may sell or otherwise dispose of all or a portion of its
non-core assets, including all or a portion of its common stock ownership in our
company. As stated above, on February 20, 2003 KeySpan sold to us 3,000,000
shares of our common stock it owned, reducing its ownership percentage from
approximately 66% to 56%. KeySpan has stated that based on market conditions, it
cannot predict when, or if, any additional sales or dispositions of all or a
part of its remaining ownership interest in us may take place.

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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) Realized natural gas and oil prices include the effects of hedging.

RECENT FINANCIAL AND OPERATING RESULTS

COMPARISON OF THREE MONTHS ENDED MARCH 31, 2003 AND 2002

Production. Our production increased 4% from 24,855 million cubic feet
equivalent, or MMcfe, for the three months ended March 31, 2002 to 25,927 MMcfe
for the three months ended March 31, 2003. Average daily production was 288
MMcfe/day during the first quarter of 2003 compared to 276 MMcfe/day during the
first quarter of 2002.

Onshore, our daily production rates increased 22% from an average of
142 MMcfe/day during the first quarter of 2002 to an average of 173 MMcfe/day
during the corresponding three months of 2003. The increase in onshore
production is primarily attributable to 32 MMcfe/day in newly developed
production from our Alexander and Hubbard fields in South Texas that were
acquired in December 2001 from Conoco Inc. together with 12 MMcfe/day in
production from properties acquired in May 2002 in the North East Thompsonville
and South Laredo fields in South Texas from Burlington Resources. These
increases were offset in part by a decline of 13 MMcfe/day in all other onshore
areas with the Charco Field comprising 8 MMcfe/day of the decrease and our
Arkoma properties comprising 3 MMcfe/day of the decrease. The Charco Field
produced at an average rate of 87 MMcfe/day during the first quarter of 2002
compared to an average of 79 MMcfe/day during the first quarter of 2003. Our
Arkoma properties produced at an average rate of 23 MMcfe/day during the first
quarter of 2002 as compared to 20 MMcfe/day during the first quarter of 2003.

Offshore, our production decreased 14% from an average of 134 MMcfe/day
during the first quarter of 2002 to an average of 115 MMcfe/day during the first
quarter of 2003. Production declines due to maturing reservoirs from existing
key fields, Mustang Island A-31/32, High Island 39, West Cameron 587 and South
Marsh Island 253, were greater than incremental production added from new wells
and facilities brought on-line since the end of the first quarter of 2002 at
Vermilion 408, East Cameron 81, East Cameron 82/83, Mustang Island 785, High
Island 38, and South Timbalier 314/317. Further, we experienced a loss of an
estimated 3 MMcfe/day at Vermilion 408 during a 15 day shut-in during January
and February 2003 due to down stream pipeline shut-ins for repairs. The
year-over-year production decline is partially the result of shifting
approximately $40 million of our 2002 offshore capital expenditure program to
our onshore region to facilitate the May 2002 acquisition of producing
properties in South Texas from Burlington Resources.

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Natural Gas and Oil Revenues. Natural gas and oil revenues increased
72% from $74.6 million for the first three months of 2002 to $128.4 million for
the first three months of 2003 as a result of a 65% increase in average realized
natural gas prices, from $2.99 per Mcf during the first quarter of 2002 to $4.93
per Mcf in the first quarter of 2003 and an increase in average realized oil
prices of 64% for the same period from $19.28 per barrel, or Bbl, to $31.57 per
barrel, combined with a 4% increase in production during the current quarter.

Natural Gas Prices. As a result of hedging activities during the first
quarter of 2003, we realized an average gas price of $4.93 per Mcf, which was
78% of the average unhedged natural gas price of $6.36 for the period. As a
result, natural gas and oil revenues for the three months ended March 31, 2003
that were $34.7 million lower than the revenues we would have achieved if hedges
had not been in place during the period. For the corresponding quarter of 2002,
we realized an average gas price of $2.99 per Mcf, which was 131% of the average
unhedged natural gas price of $2.28 for the period. This resulted in natural gas
and oil revenues that were $17.0 million higher than the revenues we would have
achieved if hedges had not been in place during the period.

Oil Prices. During the first quarter of 2003, we realized an average
oil price of $31.57 per Bbl, which was 94.5% of the average unhedged price of
$33.42 per Bbl for the period. As a result, natural gas and oil revenues for the
three months ended March 31, 2003 were $0.5 million lower than the revenues we
would have achieved if hedges had not been in place during the period. We had no
oil hedges in place during first quarter of 2002 and realized an average oil
price of $19.28 per Bbl.

Lease Operating Expenses and Severance Tax. Lease operating expenses
increased 57% from $7.4 million for the three months ended March 31, 2002 to
$11.6 million for the corresponding three months of 2003. On an Mcfe basis,
lease operating expenses increased 50% from $0.30 per Mcfe during the first
quarter of 2002 to $0.45 per Mcfe during the first quarter of 2003. The increase
in both lease operating expenses and lease operating expense on a per unit basis
for 2003 is attributable to the continued expansion of our operations both
onshore and offshore combined with a slight increase in well-service costs.
Onshore, our operating costs were higher as we incurred $1.6 million in
non-recurring expenses associated with a workover in the Charco Field together
with increases in ad valorem taxes and well control insurance. Offshore, our
operating costs were higher due to 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 contract labor costs.

Severance tax, which is a function of volume and revenues generated
from onshore production, increased from $1.7 million for the first three months
of 2002 to $4.3 million for the corresponding period of 2003. On an Mcfe basis,
severance tax increased from $0.07 per Mcfe for the first quarter of 2002 to
$0.17 per Mcfe during the first quarter of 2003. Despite our reduced severance
tax rate for a portion of our South Texas production pursuant to the
"high-cost/tight-gas formation" designation received in July 2002 (see "Other
(Income) and Expense" below), severance tax expense and severance tax per Mcfe
increased during the first three months of 2003 due to the significant increase
in average wellhead prices for natural gas from $2.28 during the first quarter
of 2002 to $6.36 during the first quarter of 2003 combined with a 22% increase
in onshore production for the first quarter of 2003.

Transportation Expense. We applied 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 for the three months
ended March 31, 2002 that were 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. The application of EITF No. 00-10 had
no effect on operating income or net income. Transportation expense for the
first three months of 2003 increased 11% on an Mcfe basis from $0.09 during the
first three months of 2002 to $0.10 for the first three months of 2003. The
increase reflects an increase in production for the corresponding period.

Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased 15% from $39.8 million for the three months ended
March 31, 2002 to $45.7 million for the three months ended March 31, 2003.
Depreciation, depletion and amortization expense per Mcfe increased 10% from
$1.60 for the three months ended March 31, 2002 to $1.76 for the corresponding
three months in 2003. 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 as the costs associated with
several unproved properties designated as unevaluated were reclassified into our
amortization base without incremental reserve additions. In addition, our future
development costs increased approximately 22% from prior year estimates due to
the addition of more proved undeveloped reserves into our total proved reserve
base.

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Asset Retirement Accretion. Pursuant to our January 1, 2003 adoption of
SFAS No. 143, "Asset Retirement Obligations," we incurred asset retirement
accretion expense of $0.8 million, $0.03 per Mcfe, for the first three months of
2003. The accretion expense represents the systematic, monthly accretion and
depreciation of future abandonment costs of tangible assets such as platforms,
wells, service assets, pipelines, and other facilities.

General and Administrative Expenses, Net of Capitalized General and
Administrative and Overhead Reimbursements. Our net general and administrative
expenses increased 18% from $3.3 million for the three months ended March 31,
2002 to $3.9 million for the three months ended March 31, 2003. These amounts
are net of overhead reimbursements received from other working interest owners
of $0.6 million and $0.4 million for the three months ended March 31, 2002 and
2003, respectively, and capitalized general and administrative expenses of $3.3
million and $3.7 million for the respective periods. Aggregate general and
administrative expenses increased by $0.8 million or 11% from $7.2 million for
the first quarter of 2002 to $8.0 million for the first quarter of 2003.
However, included in aggregate expense for the first quarter of 2002 was
approximately $0.9 million in non-recurring charges relating to employee
severance payments. Without these non-recurring charges, aggregate general and
administrative expense for the first quarter of 2003 would reflect a $0.8
million or 27% increase from the first quarter of 2002 and net general and
administrative expenses for the first quarter of 2003 would reflect a $1.5
million or 63% increase. The increase in aggregate general and administrative
expense is due primarily to the expansion of our workforce which corresponds to
the continued expansion of our operations. As our workforce expands, we have
experienced an increase in salaries and related employee benefit expenses
together with an increase in our incentive compensation expense.

On an Mcfe basis, net general and administrative expenses increased 15%
from $0.13 during the first quarter of 2002 to $0.15 per Mcfe during the first
quarter of 2003. Without the non-recurring charges of $0.9 million incurred in
the first quarter of 2002 for employee severance payments, net general and
administrative expense per Mcfe would have increased by $0.05 per Mcfe or by 50%
from $0.10 in first quarter 2002 to $0.15 in the first quarter of 2003. The
higher rate per Mcfe during the first quarter of 2003 reflects the increase in
our aggregate general and administrative expenses offset in part by an increase
in capitalized expenses during the first quarter of 2003 which is a result of
the expansion of our geological and geophysical workforce.

Other Income and Expense. During the first quarter of 2003, we recorded
refunds of prior years' severance tax expense totaling $10.6 million ($6.9
million net of tax). 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. The "high-cost/tight-gas formation" designation
allows 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. As of the date of our report, we are estimating
that we could receive refunds of up to an additional $3.5 million ($2.3 million
net of tax), although there can be no assurances that actual amounts collected
will equal our estimates.

Interest Expense, Net of Capitalized Interest. Interest expense, net of
capitalized interest, increased 64% from $1.4 million for the first three months
of 2002 to $2.3 million for the first three months of 2003. Aggregate interest
expense was unchanged at $3.6 million during both the first quarter of 2002 and
the corresponding period of 2003. Our average borrowings and interest rates were
$254.9 million and 5.36% during the first quarter of 2002 compared to $250.1
million and 5.44% during the first quarter of 2003. The increase in net interest
expense for the current quarter is due to the decrease in capitalized interest.
Capitalized interest decreased 41% from $2.2 million for the first quarter of
2002 to $1.3 million for the first quarter of 2003 and is a result of a decrease
in our unevaluated property balance during the first quarter of 2003. Our
capitalized interest, which is a function of unevaluated properties, decreased
during the quarter corresponding to a decrease in our unevaluated property
balance as several properties previously designated as unevaluated were
reclassified to the amortization base or full cost pool.

Income Tax Provision. The provision for income taxes increased 275%
from $6.4 million for the first three months of 2002 to $24.0 million for the
first three months of 2003 due to the 261% increase in pre-tax income during the
first quarter of 2003 from $19.0 million during the first quarter of 2002 to
$68.5 million during the first quarter of 2003. Pre-tax income is higher as a
result of the 72% increase in revenues and the $10.6 million in other income
received from refunds of prior years severance tax payments both of which were
offset only in part by a 26% increase in operating expenses and a 64% increase
in net interest expense.

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Operating Income and Income before Cumulative Effect of Change in
Accounting Principle. For the three months ended March 31, 2003, the 65%
increase in realized natural gas prices combined with the 4% increase in
production, offset in part by a 26% increase in operating expenses, caused
operating income to increase 195% from $20.4 million during the first quarter of
2002 to $60.2 million during the first quarter of 2003. Correspondingly, income
before the cumulative effect of the change in accounting principle increased
256% from $12.5 million for the first quarter of 2002 to $44.5 million for the
first quarter of 2003.

LIQUIDITY AND CAPITAL RESOURCES

We currently fund our operations, including capital expenditures and
working capital requirements, from cash flows from operations 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 March 31, 2003, we had working capital of $8.6
million and $154.5 million of borrowing capacity available under our revolving
bank credit facility. Net cash provided by operating activities for the first
three months of 2003 was $63.0 million compared to $33.4 million during the
first three months of 2002. The increase in net cash provided by operating
activities was due to an increase in net income caused primarily by higher
realized natural gas prices and an increase in production volumes for the first
quarter of 2003 offset in part by a net decrease in current assets and current
liabilities which is related to the timing of cash receipts and payments. For
the first quarter of 2003, the decrease in current assets was caused primarily
by an increase in receivables for natural gas revenues due to comparatively
higher gas prices and production volumes. 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 first quarter of 2003 as compared to the
corresponding quarter of 2002. For the first three months of 2003, funds used in
investing activities consisted of $53.6 million for net cash investments in
property and equipment, which compares to $47.5 million spent during the first
quarter of 2002. Our cash position decreased during the first quarter of 2003 as
a result of net repayments of borrowings under our revolving bank credit
facility of $22 million compared to net borrowings of $5 million during the
corresponding quarter of 2002. Cash increased by $0.2 million and $0.6 million,
respectively, during the first three months of 2003 and 2002 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 decreased $12.4
million from $18.0 million at December 31, 2002 to $5.6 million at March 31,
2003.

Investments in Property and Equipment. During the first three months of
2003, we invested $53.4 million in natural gas and oil properties and $0.2
million for other property and office equipment. During the first quarter of
2003, we completed the drilling of 26 gross wells (20.9 net) of which 18 (15.4
net) were successful and 8 (5.5 net) were unsuccessful with an additional 14
wells (12.2 net) in progress at the end to the quarter. Our investments in
natural gas and oil properties included $11.8 million in exploration costs,
$33.6 million in development costs and $8.0 in leasehold acquisition costs.
Leasehold acquisition costs include among other things, costs incurred for
seismic, capitalized interest and capitalized general and administrative costs.
During the first quarters of 2003 and 2002, we capitalized a total of $5.1
million and $5.5 million, respectively, in interest and general and
administrative expenses.

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. We have estimated our current asset retirement
obligations to be $4.4 million. 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 both offshore and onshore
although we may not be able to identify and make acquisitions of proved reserves
on terms we consider favorable.

Revolving Bank Credit Facility. We maintain a revolving bank credit
facility 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 credit facility provides us with a commitment of $300 million which 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

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credit facility is subject to borrowing base limitations. Our current borrowing
base is $300 million and is redetermined semi-annually, with the next
redetermination scheduled for October 1, 2003. Up to $25 million of the
borrowing base is available for the issuance of letters of credit. The credit
facility matures July 15, 2005, is unsecured and with the exception of trade
payables, ranks senior to all of our existing debt.

At March 31, 2003, outstanding borrowings under our revolving bank
credit facility were $130 million together with $15.5 million in outstanding
letter of credit obligations. A $15.1 million letter of credit was issued to a
counter party to cover a margin call pursuant to a natural gas hedge contract.
Subsequent to March 31, 2003, we repaid a net $35 million under the facility and
reduced our letter of credit obligations to $9.4 million. Currently, outstanding
borrowings and letter of credit obligations under our revolving bank credit
facility total $104.4 million.

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. 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

The table below summarizes our contractual obligations and commercial
commitments at March 31, 2003. We have no "off-balance sheet" financing
arrangements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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.

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CHANGES IN FAIR VALUE OF DERIVATIVE INSTRUMENTS

The following table summarizes the change in the fair value of our
derivative instruments for the three month period from January 1 to March 31,
2003 and 2002, respectively. Stated amounts do not reflect the effects of taxes.

DERIVATIVES IN PLACE AS OF THE DATE OF OUR REPORT

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 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 which is approximately 67% of our estimated future production for the
period. For each month during 2004, we have 100,000 MMBtu/day hedged at a floor
of $3.750 and a ceiling of $5.045 which is approximately 38% of our estimated
future production for the period.

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.

-25-

Oil. We entered into an oil swap as described in the following table.
All amounts are in thousands, except for prices.

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.

ITEM 4. 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.

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PART II. OTHER INFORMATION

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

(a) Exhibits:

* Filed herewith.

(b) Reports on Form 8-K:

Current Report on Form 8-K filed on February 21, 2003 to
provide information in Item 5. - Other Events regarding a
press release issued on February 21, 2003 announcing the
offering by Houston Exploration of 3,000,000 shares of common
stock in an underwritten public offering and concurrent
repurchase of a like number of shares from KeySpan.

Current Report on Form 8-K filed February 26, 2003 to provide
information in Item 5. - Other Events regarding the
Underwriting Agreement between Houston Exploration and J.P.
Morgan Securities, Inc. dated February 20, 2003 for the
issuance and sale of 3,000,000 shares to the public and the
Stock Purchase Agreement among Houston Exploration, KeySpan
Corporation and THEC Holdings Corp. dated as of February 20,
2003 and in Item 7. - Financial Statements and Exhibits
regarding the Underwriting Agreement and the Stock Purchase
Agreement.

Current Report on Form 8-K filed on May 2, 2003 required by
Item 12 and filed under Item 9 - Regulation FD Disclosure of
our earnings release for the first quarter of 2003.

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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: May 5, 2003 William G. Hargett
President and Chief Executive Officer

By: /s/ John H. Karnes
---------------------------------------------
Date: May 5, 2003 John H. Karnes
Senior Vice President, Chief Financial Officer

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CERTIFICATIONS

I, William G. Hargett, certify that:

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

2. Based on my knowledge, this quarterly 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 quarterly report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly 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
quarterly 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 quarterly
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 quarterly report (the "Evaluation Date"); and

(c) presented in this quarterly 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
quarterly report whether or not 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: May 5, 2003

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

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CERTIFICATIONS

I, John H. Karnes, certify that:

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

2. Based on my knowledge, this quarterly 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 quarterly report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly 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
quarterly 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 quarterly
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 quarterly report (the "Evaluation Date"); and

(c) presented in this quarterly 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
quarterly report whether or not 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: May 5, 2003

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

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EXHIBIT INDEX

* Filed herewith.