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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
 FORM 10-Q þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2005
OR
 o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
 For the transition period from  to
 Commission File No. 001-11899 
 THE HOUSTON EXPLORATION COMPANY (Exact name of registrant as specified in its charter)
 Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
    
    22-2674487
(IRS Employer Identification No.)1100 Louisiana, Suite 2000Houston, Texas
(Address of Principal Executive Offices)
    
    77002-5215
(Zip Code)
 (713) 830-6800
(Registrants Telephone Number, including Area Code) 
 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 þ No o Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of
the Act).
Yes þ No o As of May 4, 2005, 28,665,620 shares of Common Stock, par value $0.01 per share, were outstanding.




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TABLE OF CONTENTS Forward-Looking Statements and Other Information
    
    
    2Part I. Financial Information
    
    
    3Item 1. Consolidated Financial Statements
    
    
    3Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
    
    
    16Item 3. Quantitative and Qualitative Disclosures About Market Risk
    
    
    25Item 4. Controls and Procedures
    
    
    27Part II. Other Information
    
    
    27Item 5. Other Information
    
    
    28Item 6. Exhibits
    
    
    28SIGNATURES
    
    
    30Restated Certificate of IncorporationFirst Amendment to Rights Agmt.Second Amendment to Amended and Restated Credit Agmt.Computation of ratio of earnings to fixed chargesSubsidiaries of the Houston Exploration CompanyCertification of CEO pursuant to Section 302Certification of CFO pursuant to Section 302Certification of CEO pursuant to Sectin 906Certification of CFO pursuant to Section 906
  -1-




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Forward-Looking Statements and Other Information All of the estimates and assumptions contained in this Quarterly Report on Form 10-Q (Quarterly
Report) constitute forward-looking statements as that term is defined in Section 27A of the
Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities
Exchange Act of 1934, as amended (the Exchange Act). These statements use forward-looking words
such as anticipate, believe, continue, expect, estimate, intend, may, plan,
potential, predict, project, should, target, goal, objective or other similar
expressions and discuss forward-looking information. Forward-looking statements include all
statements under the caption Item 2. Managements Discussion and Analysis of Financial Condition
and Results of Operations involving the discussion of the following:  §
    business strategy;§
    natural gas and oil reserves;§
    future production;§
    expected realized natural gas and oil prices;§
    expected costs and expenses;§
    anticipated capital expenditures;§
    future operating results;§
    future cash flows and borrowings;§
    pursuit of potential future acquisition opportunities;§
    identified drilling locations; and§
    sources of funding and the timing of exploration and development activities. 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
those anticipated or implied in the forward-looking statements. 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 or if
our finding and development costs continue to increase;§
    the relatively short production lives of our reserves;§
    our ability to find, replace, develop and acquire natural gas and oil reserves;§
    the maturity of North American gas basins;§
    acquisition and investment risks;§
    our ability to meet our substantial capital requirements;§
    our outstanding indebtedness;§
    the uncertainty of estimates of natural gas and oil reserves and production rates;§
    the inherent hazards and risks involved in our operations;§
    dependence upon operations concentrated in three primary areas;§
    drilling risks;§
    our hedging activities;§
    compliance with environmental and other governmental regulations;§
    the competitive nature of our industry;§
    weather risks and other natural disasters; and§
    our customers ability to meet their obligations. For additional discussion of these and other 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 for the year ended
December 31, 2004. We undertake no obligation to publicly update or revise any forward-looking
statements. In this Quarterly Report, unless the context requires otherwise, when we refer to we, us, our
and Houston Exploration, we are describing The Houston Exploration Company including, through May
31, 2004, our former subsidiary Seneca-Upshur Petroleum, Inc., and subsequent to October 8, 2004,
THEC, LLC and THEC, LP on a consolidated basis. If you are not familiar with the natural gas and oil terms used in this Quarterly Report, please
refer to the explanations of the terms under the caption Glossary of Natural Gas and Oil Terms
included on pages G-1 through G-2 of our Annual Report on Form 10-K for the year ended December 31,
2004. When we refer to equivalents, we are doing so to compare quantities of oil with quantities
of natural gas or to express these different commodities in a common unit. In calculating
equivalents, we use a generally recognized standard in which one barrel of oil is equal to six
thousand cubic feet of natural gas. Unless otherwise stated, all reserve and production quantities
are expressed net to our interests. -2-




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Part I. Financial Information 
 Item 1. Consolidated Financial Statements THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
(Unaudited) March 31,
    
    
    December 31,2005
    
    
    2004Assets:Cash and cash equivalents
    
    $
    13,760
    
    
    $
    18,577Accounts receivable
    
    
    95,298
    
    
    
    103,069Inventories
    
    
    1,357
    
    
    
    976Deferred tax asset
    
    
    68,623
    
    
    
    24,101Prepayments and other
    
    
    7,724
    
    
    
    9,107Total current assets
    
    
    186,762
    
    
    
    155,830Natural gas and oil properties, full cost methodUnevaluated properties
    
    
    148,421
    
    
    
    122,691Properties subject to amortization
    
    
    2,899,779
    
    
    
    2,777,097Other property and equipment
    
    
    12,053
    
    
    
    11,7403,060,253
    
    
    
    2,911,528Less: Accumulated depreciation, depletion and amortization
    
    
    1,433,875
    
    
    
    1,363,2721,626,378
    
    
    
    1,548,256Other non-current assets
    
    
    17,360
    
    
    
    18,491Total Assets
    
    $
    1,830,500
    
    
    $
    1,722,577Liabilities:Accounts payable and accrued expenses
    
    $
    131,972
    
    
    $
    118,971Derivative financial instruments
    
    
    193,849
    
    
    
    68,081Asset retirement obligation
    
    
    2,141
    
    
    
    662Total current liabilities
    
    
    327,962
    
    
    
    187,714Long-term debt and notes
    
    
    340,000
    
    
    
    355,000Derivative financial instruments
    
    
    80,406
    
    
    
    7,068Deferred income taxes
    
    
    278,182
    
    
    
    288,069Asset retirement obligation
    
    
    93,177
    
    
    
    91,084Other non-current liabilities
    
    
    11,568
    
    
    
    10,722Total Liabilities
    
    
    1,131,295
    
    
    
    939,657Commitments and Contingencies (see Note 4)Stockholders Equity:Preferred Stock, $0.01 par value, 5,000,000 shares authorized and no shares issued
    
    
    
    
    
    
    Common Stock, $.01 par value, 50,000,000 shares authorized and 28,665,620 and
28,380,207 shares issued and outstanding at March 31, 2005 and December 31, 2004,
respectively
    
    
    287
    
    
    
    284Additional paid-in capital
    
    
    285,057
    
    
    
    273,002Unearned compensation
    
    
    (4,046
    )
    
    
    (2,537
    )Retained earnings
    
    
    591,636
    
    
    
    558,198Accumulated other comprehensive (loss)
    
    
    (173,729
    )
    
    
    (46,027
    )Total Stockholders Equity
    
    
    699,205
    
    
    
    782,920Total Liabilities and Stockholders Equity
    
    $
    1,830,500
    
    
    $
    1,722,577
 The accompanying notes are an integral part of these consolidated financial statements. -3-




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THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
(Unaudited) Three Months Ended March 31,2005
    
    
    2004Revenues:Natural gas and oil revenues
    
    $
    165,490
    
    
    $
    151,634Other
    
    
    230
    
    
    
    248Total revenues
    
    
    165,720
    
    
    
    151,882Operating expenses:Lease operating
    
    
    15,368
    
    
    
    12,706Severance tax
    
    
    2,934
    
    
    
    3,057Transportation expense
    
    
    2,766
    
    
    
    2,736Asset retirement accretion expense
    
    
    1,325
    
    
    
    1,288Depreciation, depletion and amortization
    
    
    70,603
    
    
    
    60,964General and administrative, net of amounts capitalized
    
    
    11,123
    
    
    
    6,088Total operating expenses
    
    
    104,119
    
    
    
    86,839Income from operations
    
    
    61,601
    
    
    
    65,043Other (income) expense
    
    
    1,454
    
    
    
    110Interest expense, net of amounts capitalized
    
    
    3,434
    
    
    
    2,287Income before income taxes
    
    
    56,713
    
    
    
    62,646Provision for taxes
    
    
    23,275
    
    
    
    22,956Net income
    
    $
    33,438
    
    
    $
    39,690Earnings per share:Net income per share  basic
    
    $
    1.17
    
    
    $
    1.26Net income per share  diluted
    
    $
    1.16
    
    
    $
    1.25Weighted average shares outstanding  basic
    
    
    28,499
    
    
    
    31,598Weighted average shares outstanding  diluted
    
    
    28,871
    
    
    
    31,714
 The accompanying notes are an integral part of these consolidated financial statements. -4-




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THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited) Three Months Ended March 31,2005
    
    
    2004Operating Activities:Net income
    
    $
    33,438
    
    
    $
    39,690Adjustments to reconcile net income to net cash provided by
operating activities:Deferred income tax expense
    
    
    15,571
    
    
    
    13,282Depreciation, depletion and amortization
    
    
    70,603
    
    
    
    60,964Asset retirement accretion expense
    
    
    1,325
    
    
    
    1,288Stock compensation expense
    
    
    1,012
    
    
    
    517Tax benefit non-qualified stock options
    
    
    1,724
    
    
    
    1,532Unrealized loss due to ineffectiveness of derivative instruments
    
    
    1,424
    
    
    
    1,000Amortization of premiums paid on derivative contracts
    
    
    
    
    
    
    2,730Changes in operating assets and liabilities:(Increase) decrease in accounts receivable
    
    
    7,771
    
    
    
    (6,925
    )(Increase) decrease in inventories
    
    
    (381
    )
    
    
    (93
    )(Increase) decrease in prepayments and other
    
    

    1,383
    
    
    
    612(Increase) decrease in other assets
    
    
    1,131
    
    
    
    (2,970
    )Increase (decrease) in deferred liabilities
    
    
    846
    
    
    
    6,727Increase (decrease) in accounts payable and accrued expenses
    
    
    13,001
    
    
    
    12,805Decrease in ARO liability for assets abandoned
    
    
    
    
    
    
    (2,553
    )Net cash provided by operating activities
    
    
    148,848
    
    
    
    128,606Investing Activities:Investment in property and equipment
    
    
    (146,627
    )
    
    
    (85,222
    )Dispositions
    
    
    150
    
    
    
    13,138Net cash used in investing activities
    
    
    (146,477
    )
    
    
    (72,084
    )Financing Activities:Proceeds from long-term borrowings
    
    
    85,000
    
    
    
    20,000Repayments of long-term borrowings
    
    
    (100,000
    )
    
    
    (77,000
    )Proceeds from issuance of common stock from exercise of stock options
    
    
    7,812
    
    
    
    11,629Net cash used in financing activities
    
    
    (7,188
    )
    
    
    (45,371
    )(Decrease) increase in cash and cash equivalents
    
    
    (4,817
    )
    
    
    11,151Cash and cash equivalents, beginning of year
    
    
    18,577
    
    
    
    2,569Cash and cash equivalents, end of year
    
    $
    13,760
    
    
    $
    13,720Supplemental Information:Cash paid during period for:Interest
    
    $
    2,107
    
    
    $
    876Federal and state income taxes
    
    
    
    
    
    
    
 The accompanying notes are an integral part of these consolidated financial statements. -5-




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) NOTE 1  Summary of Organization and Significant Accounting Policies Our Business We are an independent natural gas and oil producer concentrating on growing reserves and production
through the exploration, development, exploitation and acquisition of natural gas and oil reserves
in North America. Our core areas of operations are South Texas, offshore in the shallow waters of
the Gulf of Mexico, the Arkoma Basin of Oklahoma and Arkansas and the Rocky Mountain region where,
during 2003, we began operations with an initial focus in the Uinta Basin of northeastern Utah and
during 2004, we expanded our focus to the DJ Basin in Eastern Colorado. We were founded in December 1985 as a Delaware corporation and began exploring for natural gas and
oil on behalf of KeySpan Corporation, our then parent company. 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 31% of our shares to the public.
Through a series of three separate transactions, the first in February 2003 and the last in
November 2004, KeySpan completely divested of its interest in the common stock of our company. Principles of Consolidation Our consolidated financial statements for the period ended March 31, 2005, include our accounts and
the accounts of our wholly-owned subsidiaries. All significant inter-company balances and
transactions have been eliminated. Our consolidated financial statements for the period ended March 31, 2004, include our accounts and
the accounts of Seneca-Upshur Petroleum, Inc., which was our wholly-owned subsidiary until June 2,
2004, when we conveyed all of the shares of Seneca-Upshur to KeySpan in connection with an asset
exchange transaction. Seneca-Upshur was previously our only subsidiary. Seneca-Upshur is a
natural gas exploration and production company located in West Virginia. All significant
inter-company balances and transactions were eliminated. Interim Financial Statements Our balance sheet at March 31, 2005, 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 (SEC). 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. Our balance sheet at December 31, 2004, is derived from our December 31, 2004 audited
financial statements, but does not include all disclosures required by GAAP. The financial
statements included herein 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, 2004. In the opinion of our management, these financial statements reflect all adjustments necessary for
a fair statement of the results for the interim periods, on a basis consistent with the annual
audited financial statements. All such adjustments are of a normal recurring nature. The results
of operations for such interim periods are not necessarily indicative of the results for the full
year. Use of Estimates 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, our unevaluated properties and our full cost ceiling test. In addition, estimates are
used in computing taxes, preparing accruals of operating costs and production revenues, asset
retirement obligations, fair value and effectiveness of derivative instruments and fair value of
stock options and the related compensation expense. Because there are numerous uncertainties
inherent in the estimation process, actual results could differ materially from these estimates. -6-




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) Business Segment Information The Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards
(SFAS) 131, Disclosures about Segments of an Enterprise and Related Information establishes
standards for reporting information about operating segments. Operating segments are defined as
components of an enterprise that engages in activities from which it may earn revenues and incur
expenses. Separate financial information is available, and this information is regularly evaluated
by the chief decision maker for the purpose of allocating resources and assessing performance. Segment reporting is not applicable for us as each of our operating areas has similar economic
characteristics and each meets the criteria for aggregation as defined in SFAS 131. All of our
operations involve the exploration, development and production of natural gas and oil, and all of
our operations are located in the United States. We have a single, company-wide management team
that administers all properties as a whole rather than as discrete operating segments. We track
only basic operational data by area, and do not maintain separate financial statement information
by area. We measure financial performance as a single enterprise and not on an area-by-area basis.
Throughout the year, we freely allocate capital resources on a project-by-project basis across our
entire asset base to maximize profitability without regard to individual areas or segments. Revenue Recognition and Gas Imbalances We use the entitlements method of accounting for the recognition of natural gas and oil revenues.
Under this method of accounting, income is recorded based on our net revenue interest in production
or nominated deliveries. We incur production gas volume imbalances in the ordinary course of
business. Net deliveries in excess of entitled amounts are recorded as liabilities, while net under
deliveries are reflected as assets. Imbalances are reduced either by subsequent recoupment of
over-and-under deliveries or by cash settlement, as required by applicable contracts. Production
imbalances are marked-to-market at the end of each month at the lowest of (i) the price in effect
at the time of production; (ii) the current market price; or (iii) the contract price, if a
contract is in hand. At March 31, 2005, we had production imbalances representing assets of $4.1 million and liabilities
of $4.4 million. At December 31, 2004, we had production imbalances representing assets of $3.3
million and liabilities of $4.0 million. The primary sources of our production imbalances relate
to Eugene Island 331, acquired in October 2003 from Transworld Exploration and Production Inc., and
to various Arkoma wells. Production imbalances are included in the line items other non-current
assets and other non-current liabilities on the balance sheet. Net Income Per Share Basic earnings per share is calculated by dividing net income by the weighted average number of
shares of common stock outstanding during the period. No dilution for any potentially dilutive
securities is included. Fully diluted earnings per share assumes the conversion of all potentially
dilutive securities and is calculated by dividing net income by the sum of the weighted average
number of shares of common stock outstanding plus all potentially dilutive securities. Three Months EndedMarch 31,2005
    
    
    2004(in thousands)Numerator:Net income
    
    $
    33,438
    
    
    $
    39,690Denominator:Weighted average shares outstanding
    
    
    28,499
    
    
    
    31,598Add dilutive securities: Stock options
    
    
    372
    
    
    
    116Total weighted average shares outstanding and dilutive securities
    
    
    28,871
    
    
    
    31,714Earnings per share  basic:
    
    $
    1.17
    
    
    $
    1.26Earnings per share  diluted:
    
    $
    1.16
    
    
    $
    1.25
 For the three months ended March 31, 2005 and 2004, the calculation of shares outstanding for
diluted earnings per share does not include the effect of outstanding stock options to purchase
377,725 and 1,585,960 shares, respectively, because the -7-




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) exercise price of these shares was greater than the average market price for the year, which would
have an antidulitive effect on earnings per share. Comprehensive Income (Loss) Comprehensive income includes net income and certain items recorded directly to stockholders
equity and classified as other comprehensive income. The table below summarizes comprehensive
income and provides the components of the change in accumulated other comprehensive income for the
three-month periods ended March 31, 2005 and 2004. Three Months EndedMarch 31,2005
    
    
    2004(in thousands)Net income
    
    $
    33,438
    
    
    $
    39,690Other comprehensive income (loss)Derivative instruments settled and reclassified, net of tax
    
    
    9,157
    
    
    
    7,461Change in unrealized (loss) fair value of open contracts,
net of tax
    
    
    (136,859
    )
    
    
    (36,216
    )Total other comprehensive (loss)
    
    
    (127,702
    )
    
    
    (28,109
    )Comprehensive income (loss)
    
    $
    (94,264
    )
    
    $
    11,581
 Natural Gas and Oil Properties Full Cost Accounting. We use the full cost method to account for our natural gas and oil
properties. Under full cost accounting, all costs incurred in the acquisition, exploration and
development of natural gas and oil reserves are capitalized into a full cost pool. Capitalized
costs include costs of all unproved properties, internal costs directly related to our natural gas
and oil activities and capitalized interest. We amortize these costs using a unit-of-production
method. We compute the provision for depreciation, depletion and amortization quarterly by
multiplying production for the quarter by a depletion rate. The depletion rate is determined by
dividing our total unamortized cost base by net equivalent proved reserves at the beginning of the
quarter. Our total unamortized cost base is the sum of our:  §
    full cost pool (including assets associated with retirement obligations); plus,§
    estimates for future development costs (excluding asset retirement obligations); less,§
    unevaluated properties and their related costs; less,§
    estimates for salvage. Costs associated with unevaluated properties are excluded from the amortization base until we have
made a determination as to the existence of proved reserves. We review our unevaluated properties
at the end of each quarter to determine 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 related 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 and adjusted for basis or location differential, held constant over the life of the
reserves. We use derivative financial instruments that qualify for cash flow hedge accounting under
SFAS 133, Accounting for Derivative Instruments and Hedging Activities, to hedge against the
volatility of natural gas prices, and in accordance with SEC guidelines, we include estimated
future cash flows from our hedging program in our ceiling test calculation. In addition,
subsequent to the adoption of SFAS 143, Accounting for Asset Retirement Obligations, the future
cash outflows associated with settling asset retirement obligations are excluded from the
computation of the discounted present value of future net revenues for the purposes of the ceiling
test calculation. -8-




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) Unevaluated Properties. The costs associated with unevaluated properties and properties under
development are not initially included in the amortization base and relate to unproved leasehold
acreage, seismic data, wells and production facilities in progress and wells pending determination
together with interest costs capitalized for these projects. Unevaluated leasehold costs are
transferred to the amortization base with the costs of drilling the related well once a
determination has been made or upon expiration of a lease. Costs of seismic data are allocated to
various unproved leaseholds and transferred to the amortization base with the associated leasehold
costs on a specific project basis. Costs associated with wells in progress and wells pending
determination are transferred to the amortization base once a determination is made whether or not
proved reserves can be assigned to the property. Costs of dry holes are transferred to the
amortization base immediately upon determination that the well is unsuccessful. All items included
in our unevaluated property balance are assessed on a quarterly basis for possible impairment or
reduction in value. We estimate that these costs will be evaluated within a four-year period. Asset Retirement Obligations For us, asset retirement obligations (ARO) represent the future abandonment costs of tangible
assets such as platforms, wells, service assets, pipelines, and other facilities. SFAS 143,
Accounting for Asset Retirement Obligations, 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, an adjustment is
made 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. We carry ARO
assets on the balance sheet as part of our full cost pool, and include these ARO assets in our
amortization base for the purposes of calculating depreciation, depletion and amortization expense.
For the purposes of calculating the ceiling test, the future cash outflows associated with
settling the ARO liability are excluded from the computation of the discounted present value of
estimated future net revenues. The following table describes changes in our ARO liability during the three-month periods ended
March 31, 2005 and 2004. The ARO liability in the table below includes amounts classified as both
current and long-term at period end. Three Months EndedMarch 31,2005
    
    
    2004(in thousands)ARO liability at January 1
    
    $
    91,746
    
    
    $
    92,357Accretion expense
    
    
    1,325
    
    
    
    1,288Liabilities incurred from drilling
    
    
    1,449
    
    
    
    1,812Liabilities settled   assets sold
    
    
    
    
    
    
    (2,928
    )Liabilities settled  assets abandoned
    
    
    
    
    
    
    (3,957
    )Changes in estimates
    
    
    798
    
    
    
    ARO liability at March 31
    
    $
    95,318
    
    
    $
    88,572
 Derivative Instruments and Hedging Activities Our hedging policy does not permit us to hold derivative instruments for trading purposes. In our
hedging program, we utilize a variety of derivative instruments, including swaps, collars and
options. We generally place contracts with major financial institutions and other credit-worthy
counterparties. Although our hedging program protects a portion of our cash flows from downward
price movements, certain hedging strategies, specifically the use of swaps and collars, may also
limit our ability to realize the full benefit of future price increases. In addition, because our
derivative instruments are typically indexed to New York Mercantile Exchange (NYMEX) prices, as
opposed to the index price where the gas is actually sold, our hedging strategy may not protect our
cash flows if the price differential increases between the NYMEX price and index price for the
point of sale. Our derivative instruments are designated cash flow hedges and qualify for hedge accounting under
SFAS 133, Accounting for Derivative Instruments and Hedging Activities, as amended, 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 -9-




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) ineffectiveness occurs, amounts are recorded directly to the income statement. During the
three-month periods ended March 31, 2005 and 2004, our net income includes an unrealized loss of
$1.4 million ($0.9 million net of tax) and $1.0 million ($0.7 million net of tax), respectively,
which represents the ineffective portion of our open derivative contracts that were not eligible
for deferral. The ineffectiveness was primarily a result of changes at the end of the current
period in the price differentials between the index price of the derivative contract, which uses a
NYMEX index, and index price for the point of sale for the cash flow that is being hedged, the
majority of which is the Houston Ship Channel index. Based on market prices at March 31, 2005, we recorded an unrealized loss in accumulated other
comprehensive income of $173.7 million, net of tax, representing the fair value of our open
contracts. Any loss will be realized in future earnings at the time of the related sales of
natural gas production applicable to specific hedges. If prices in effect at March 31, 2005, were
to remain unchanged, over the next 12-month period, we would expect to reclassify from accumulated
other comprehensive income to earnings a loss of $122.4 million, net of tax, relating to our open
derivative contracts. However, these amounts could vary materially as a result of changes in
market conditions. From time to time, if the fair value of an open contract or contracts exceeds our available credit
limit with a particular counterparty, we could be required to post a letter of credit to further
guarantee our performance. As of March 31, 2005, we did not have any outstanding letters of credit
issued relating to derivative contracts. Accounting for Stock Options and Restricted Stock On January 1, 2003, we adopted the fair value expense recognition provisions of SFAS 123,
Accounting for Stock-Based Compensation, as amended by SFAS 148, Accounting for StockBased
Compensation  Transition and Disclosure using the prospective method as defined by the SFAS
148. As a result, we recorded as compensation expense the fair value of all stock options issued
subsequent to January 1, 2003. No expense for stock options has been recorded for grants made in
years prior to January 1, 2003. Prior to 2003, we accounted for stock-based compensation using the
intrinsic value method prescribed in Accounting Principles Board (APB) Opinion 25, Accounting
for Stock Issued to Employees, and related interpretations. Accordingly, compensation cost for
stock options was measured as the excess, if any, of the fair value of common stock at the date of
the grant over the amount the employee must pay to acquire the common stock. If the exercise price
of a stock option was equal to the fair market value at the time of grant, no compensation expense
was incurred. If we had accounted for all stock options using the fair value method as recommended
in SFAS 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, 2005 and 2004. Three Months EndedMarch 31,2005
    
    
    2004(in thousands)Net income  as reported
    
    $
    33,438
    
    
    $
    39,690Add: Stock-based compensation expense included in
net income, net of tax
    
    
    446
    
    
    
    230Less: Stock-based compensation expense determined
using fair value method, net of tax
    
    
    (802
    )
    
    
    (1,267
    )Net income  pro forma
    
    $
    33,082
    
    
    $
    38,653Net income per share  basic  as reported
    
    $
    1.17
    
    
    $
    1.26Net income per share  diluted  as reported
    
    
    1.16
    
    
    
    1.25Net income per share  basic  pro forma
    
    $
    1.16
    
    
    $
    1.22Net income per share  diluted  pro forma
    
    
    1.15
    
    
    
    1.22
 The effects of applying SFAS 123 in this pro forma disclosure may not be representative of future
amounts.
The weighted average fair value of options at their grant date for the first three months of 2005
and 2004 were $21.89 and $12.20, respectively. The fair value of each option grant was estimated
on the date of grant using the Black-Scholes option-pricing model with the following assumptions
used for grants during the three months ended March 31, 2005 and 2004: -10-




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) Three Months EndedMarch 31,2005
    
    
    2004Risk-free interest rate
    
    
    3.97
    %
    
    
    4.21
    %Expected years until exercise
    
    
    5
    
    
    
    5Expected stock volatility
    
    
    35.60
    %
    
    
    37.08
    %Expected dividends
    
    
    
    
    
    
    
 For the risk-free interest rate, we utilize daily rates for five-year United States treasury bills
with constant maturity. The expected life is based on historical exercise activity over the
previous nine-year period. The expected volatility is based on historical volatility and measured
using the average closing price of our stock over a 60-month period. We believe historical
volatility is the most accurate measure of future volatility of our common stock. The following table provides the detail of stock compensation expenses incurred during each of the
three-month periods ended March 31, 2005 and 2004. Three Months EndedMarch 31,2005
    
    
    2004(in thousands)Options
    
    $
    817
    
    
    $
    455Restricted stock
    
    
    195
    
    
    
    62Stock compensation expense, gross
    
    
    1,012
    
    
    
    517Amounts capitalized
    
    
    (322
    )
    
    
    (163
    )Stock compensation expense, net
    
    $
    690
    
    
    $
    354
 Recent Accounting Pronouncements On December 16, 2004, the FASB revised Statement 123 (revised 2004), Share-Based Payment that
will require compensation costs related to share-based payment transactions (e.g., issuance of
stock options and restricted stock) to be recognized in the financial statements. With limited
exceptions, the amount of compensation cost will be measured based on the grant date fair value of
the equity or liability instruments issued. In addition, liability awards will be remeasured each
reporting period. Compensation cost will be recognized over the period that an employee provides
service in exchange for the award. Statement 123(R) replaces SFAS 123, Accounting for Stock-Based
Compensation, and supersedes Accounting Principles Board (APB) Opinion No. 25, Accounting for
Stock Issued to Employees. For us, SFAS 123(R), as amended by SEC Release 34-51558, is effective
for our first fiscal year beginning after June 15, 2005, or January 1, 2006. Entities that use the
fair-value-based method for either recognition or disclosure under SFAS 123 are required to apply
SFAS 123(R) using a modified version of prospective application. Under this method, an entity
records compensation expense for all awards it grants after the date of adoption. In addition, the
entity is required to record compensation expense for the unvested portion of previously granted
awards that remain outstanding at the date of adoption. In addition, entities may elect to adopt
SFAS 123 (R) using a modified retrospective method whereby previously issued financial statements
are restated based on the expense previously calculated and reported in their pro forma footnote
disclosures. On January 1, 2003, we adopted the fair value expense recognition provisions of SFAS 123 as amended
by SFAS 148, Accounting for Stock-Based Compensation  Transition and Disclosure using the
prospective method as defined by the SFAS 148. As a result, we have recognized compensation
expense for all stock options granted subsequent to January 1, 2003, with no expense recognized for
grants made prior to 2003. Adoption of SFAS 123(R) will require us to recognize compensation
expense over the remaining service period for the unvested portion of all options granted during
2000, 2001 and 2002. All options granted prior to 2000 are fully vested. We expect to adopt SFAS
123(R) on January 1, 2006, using the modified version of the prospective application. We are
currently evaluating the effect adopting SFAS 123(R) will have to our financial statements. On March 29, 2005, the SEC released Staff Accounting Bulletin (SAB) 107 providing additional
guidance in applying the provisions of SFAS 123(R), Share-Based Payment. SAB 107 should be
applied when adopting SFAS 123(R) and -11-




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) addresses a wide range of issues, focusing on valuation methodologies and the selection of
assumptions. In addition, SAB 107 addresses the interaction of SFAS 123(R) with existing SEC

guidance. NOTE 2  Long-Term Debt and Notes March 31, 2005
    
    
    December 31, 2004(in thousands)Senior Debt:Revolving bank credit facility, due April 1, 2008
    
    $
    165,000
    
    
    $
    180,000Subordinated Debt:7% senior subordinated notes, due June 15, 2013
    
    
    175,000
    
    
    
    175,000Total long-term debt and notes
    
    $
    340,000
    
    
    $
    355,000
 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, 2005, the quoted
market value of our $175 million of 7% senior subordinated notes was 99% of the $175 million
carrying value, or $173 million. At December 31, 2004, the quoted market value of our $175 million
of 7% senior subordinated notes was 101% of the $175 million carrying value, or $177 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 and Comerica Bank as co-documentation
agents. The facility provides us with a commitment of $400 million, which may be increased at our
request and with prior approval from Wachovia to a maximum of $450 million. Amounts available for
borrowing under the credit facility are limited to a borrowing base. Our borrowing base is $400
million, which is expected to remain in effect until the next scheduled redetermination on October
1, 2005. Up to $40 million of the borrowing base is available for the issuance of letters of
credit. Outstanding borrowings are unsecured and rank senior in right of payment to our $175
million 7% subordinated notes. The facility matures on April 1, 2008. At March 31, 2005, we had
$165 million in outstanding borrowings under the credit facility and $0.4 million in outstanding
letter of credit obligations. Interest is payable on borrowings under our revolving bank credit facility, as follows:  §
    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 0.5% or Wachovias prime rate plus (b) a variable
margin between 0.00% and 0.50%, depending on the amount of borrowings outstanding under the
credit facility, or§
    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 customary negative covenants that place restrictions
and limits on, among other things, the incurrence of debt, guarantees, liens, leases and certain
investments. Our subsidiaries are guarantors under the credit facility, and we are restricted and
limited in 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:  §
    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;§
    maintain a ratio of total debt to EBITDA of not more than 3.50 to 1.00; and§
    not hedge more than 85% of our production during any calendar year. -12-




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) At March 31, 2005, and December 31, 2004, we were in compliance with all covenants. Senior Subordinated Notes On June 10, 2003, we issued $175 million of 7% senior subordinated notes due June 15, 2013. The
notes bear interest at a rate of 7% per annum with interest payable semi-annually on June 15 and
December 15, beginning December 15, 2003. We may redeem the notes at our option, in whole or in
part, at any time on or after June 15, 2008, at a price equal to 100% of the principal amount plus
accrued and unpaid interest, if any, plus a specified premium that decreases yearly from 3.5% in
2008 to 0% in 2011 and thereafter. In addition, at any time prior to June 15, 2006, we may redeem
up to a maximum of 35% of the aggregate principal amount with the net proceeds of one or more
equity offerings at a price equal to 107% of the principal amount, plus accrued and unpaid interest
and liquidated damages, if any. The notes are general unsecured obligations and rank subordinate
in right of payment to all existing and future senior debt, including the revolving bank credit
facility, and will rank senior or equal in right of payment to all existing and future subordinated
indebtedness. The indenture governing the notes contains covenants that, among other things, restrict or limit:  §
    incurrence of additional indebtedness and issuance of preferred stock;§
    repayment of certain other indebtedness;§
    payment of dividends or certain other distributions;§
    investments and repurchases of equity;§
    use of the proceeds of assets sales;§
    transactions with affiliates;§
    creation, incurrence or assumption of liens;§
    merger or consolidation and sales or other dispositions of all or substantially all of our assets;§
    entering into agreements that restrict the ability of our subsidiaries to make
certain distributions or payments; or§
    guarantees by our subsidiaries of certain indebtedness. In addition, upon the occurrence of a change of control (as defined in the indenture), 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 and liquidated damages, if any. NOTE 3  Stockholders Equity Increase in Number of Shares Outstanding At our annual meeting of stockholders on April 26, 2005, our Board of Directors received
shareholder approval to increase the number of shares we are authorized to issue to up to
105,000,000 shares of stock, including up to 100,000,000 shares of common stock and up to 5,000,000
shares of preferred stock. An amendment to our Restated Certificate of Incorporation was filed
with the Secretary of State of the State of Delaware on April 26, 2005 to reflect the increase. NOTE 4 Commitments and Contingencies Legal Proceedings 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. Operating Leases We have entered into non-cancelable operating lease agreements in the ordinary course of our
business activities. These leases include those for our office space at 1100 Louisiana Street in
Houston, Texas, and at 700 17th Street in Denver, Colorado, together with various types
of office equipment (telephones, copiers and faxes). The terms of these agreements have various
expiration dates from 2005 through 2009. Future minimum lease payments for the remainder of 2005
and -13-




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) each of the subsequent four years from 2006 through 2009 are $1.2 million, $1.5 million, $1.6
million, $1.6 million and $0.9 million, respectively. Purchase Obligations We have committed to acquire additional offshore seismic data under an existing license agreement
for up to $7.7 million which is payable in January 2006. Letters of Credit We had $0.4 million of letters of credit outstanding at March 31, 2005, and December 31, 2004.
These letters of credit were issued for natural gas and oil operating activities, none of which
were collateralized. Drilling Contract In February 2005, we entered into a one-year contract for the use of a drilling rig in the Uinta
Basin. Under the terms of the contract, we are obligated for up to an estimated $3.4 million in
fees for use of the rig during the one-year term. NOTE 5  Related Party Transactions Employment Agreements On February 10, 2005, we entered into an employment agreement with Joanne C. Hresko, our Vice
President and General Manager-Onshore Division. On March 10, 2005, we entered into an employment
agreement with John E. Bergeron, Jr., our new Vice President and General Manager  Offshore
Division. On April 13, 2005, we entered into an employment agreement with Jeffrey B. Sherrick, our
new Senior Vice President of Corporate Development. On February 8, 2005, we entered into amended and restated employment agreements with William G.
Hargett, our President and Chief Executive Officer, Steven L. Mueller, our Executive Vice President
and Chief Operating Officer, John H. Karnes, our Senior Vice President and Chief Financial Officer,
James F. Westmoreland, our Vice President and Chief Accounting Officer, and Roger B. Rice, our
Senior Vice President-Administration. Each agreement is for a term of three years, with automatic
one-year extensions thereafter unless we or the executive provide notice of termination at least 90
days prior to the end of the applicable term. By entering into the amended and restated employment agreements and terminating their prior
employment agreements with us, Messrs. Hargett, Mueller, Karnes, Westmoreland and Rice gave up
certain rights, including the right to receive severance for a termination of employment following
a change of control of our company absent the existence of good reason and the right to
guaranteed annual stock option grants and incentive compensation bonuses (which will now be subject
to the discretion of our Compensation and Management Development Committee. In addition to these
rights, Mr. Hargett gave up the right to receive a transaction bonus upon the occurrence of certain
corporate transactions involving our company, and all of the executives have agreed to broader
non-competition provisions under the amended and restated agreements. In consideration of their entering into the amended and restated agreements and foregoing such
rights, we paid to each of these executives during the first quarter of 2005 cash and/or restricted
stock as follows: for Mr. Hargett, $4,220,043 in cash; for Mr. Mueller, $353,866 in cash and 6,553
shares of restricted stock; for Mr. Karnes, 12,892 shares of restricted stock; for Mr.
Westmoreland, $291,300 in cash and 5,394 shares of restricted stock; and for Mr. Rice, $284,349 in
cash and 5,266 shares of restricted stock. The restricted stock will vest over a period of five
years in accordance with the terms of our 2004 Long-Term Incentive Compensation Plan. All of the employment agreements provide that if we terminate an executives agreement without
cause (as defined in the employment agreement), or if the executive terminates his or her
employment with us for good reason (as defined in the agreement, which includes the occurrence of
certain events following a change in control of our company), we are obligated to pay the executive
a lump-sum severance payment equal to 2.99 times his or her then current annual rate of total
compensation and to continue certain welfare benefits. The agreements further provide that if any
payments made to the executives, whether or not under the agreement, would result in an excise tax
being imposed on the executives under Section 4999 of the Internal Revenue Code, we will make each
of the executives whole on a net after-tax basis. -14-




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) We may terminate any employment agreement for cause or upon the death or disability of the
executive without financial obligation (other than payment of any accrued obligations). Each
executive may terminate his or her employment agreement at any time for any reason upon at least 30
days prior written notice. In the event the executives employment is terminated by us without
cause or upon death or disability, or if the executive terminates his or her employment with us for
good reason, any unvested shares of restricted stock, unvested options or similar deferred
compensation automatically will vest and any other conditions to such awards shall be deemed
satisfied. Termination of Employment Agreements On February 17, 2005, Timothy R. Lindsey, Senior Vice President of Exploration, and Tracy Price,
Senior Vice President  Land, resigned from the company, effective March 1, 2005. Their
resignations were prompted by an organizational change made in November 2004, in which they were
given new reporting responsibilities. Upon resignation, their employment agreements were
terminated and each received a lump-sum severance payment in the amount of 2.99 times his total
compensation, the continuation of certain health and medical benefits for a period of at least 12
months and accelerated vesting of all outstanding stock options and restricted stock. During the
fourth quarter of 2004, we recognized additional general and administrative expense of $3.1 million
relating to the entitlements under these employment agreements. NOTE 6  Acquisitions East Texas Acquisitions On March 15, 2005, we completed the purchase of certain natural gas and oil producing properties
and associated gathering pipelines and equipment, together with developed and undeveloped acreage,
located in the Rusk County, Texas, from Dale Gas Partners, L.P. The $22.0 million purchase price
was paid in cash and financed by borrowings under our revolving bank credit facility. The
properties purchased cover approximately 5,776 gross acres located in South Oak Hill Field, which
is in close proximity to our existing operations in the Willow Springs Field, and represents
interests in three producing wells and one well in the completion stage. We operate all of the
wells acquired and our working interest is 100%. Total proved reserves associated with the
interests acquired were 9.1 Bcfe as of March 15, 2005, the effective date of the transaction. In
addition, we entered into a letter agreement with Dale Resources East Texas L.L.C. to acquire a
second group of seven producing wells together with undeveloped acreage in the adjacent North
Blocker Field, located in Harrison County, Texas. The letter agreement covers the acquisition of a
50% working interest in the seven wells, all of which will be operated by us, and 4,679 gross
acres, for a purchase price of $9.2 million. Total proved reserves associated with the interests
to be acquired are estimated at 7.7 Bcfe, as of April 1, 2005, the effective date of the
transaction. NOTE 7  Subsequent Events East Texas North Blocker Field Acquisition On April 5, 2005, we completed the acquisition of a 50% working interest in seven producing wells
together with undeveloped acreage located in the North Blocker Field located in Harrison County,
Texas from Dale Resources East Texas L.L.C. as described above in Note 6  Acquisitions. The $9.2
million purchase price was paid in cash and financed with borrowings under our revolving bank
credit facility. Letters of Credit Issued for Hedging Activities Subsequent to the balance sheet date and as a result of increases in the market price of natural
gas, the fair value of our open derivative contracts increased beyond our available credit limit
with one counterparty. As a result, in April 2005, we were required to issue letters of credit
totaling $3.3 million to further guarantee our performance on open derivative contracts. -15-




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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 you in understanding our business and the results of
operations together with our present financial condition. This section should be read in
conjunction with our Consolidated Financial Statements and the accompanying notes included
elsewhere in this Quarterly Report on Form 10-Q, as well as our Annual Report on Form 10-K for the
year ended December 31, 2004. Statements in our discussion may be forward-looking. These forward-looking statements involve
risks and uncertainties. We caution that a number of factors could cause future production,
revenues and expenses to differ materially from our expectations. See Forward-Looking Statements
and Other Information at the beginning of this Quarterly Report and Risk Factors Affecting Our
Business beginning on page 15 of our Annual Report on Form 10-K for additional discussion of some
of these factors and risks. Overview of Our Business We are an independent natural gas and oil producer concentrating on growing reserves and production
through the exploration, development, exploitation and acquisition of natural gas and oil reserves
in North America. Our core areas of operations are South Texas, offshore in the shallow waters of
the Gulf of Mexico and the Arkoma Basin of Oklahoma and Arkansas. During 2003, we initiated
operations in the Rocky Mountain Region, with an initial focus in the Uinta Basin of northeastern
Utah, and during 2004, we expanded our focus to include the DJ Basin of Eastern Colorado. We
operate as one segment as each of our operating areas has similar economic characteristics and each
meets the criteria for aggregation as defined in the Financial Accounting Standards Board (FASB)
Statement of Financial Accounting Standards (SFAS) 131, Disclosures about Segments of an
Enterprise and Related Information. At December 31, 2004, net proved reserves were 793 billion cubic feet equivalent, or Bcfe, with a
standardized measure of future net cash flows including income taxes, discounted at 10% per annum,
of $1.4 billion. Our reserves are fully engineered on an annual basis by independent petroleum
engineers. Approximately 94% of our proved reserves at December 31, 2004, were natural gas,
approximately 63% of which were classified as proved developed. As of December 31, 2004, we
operated approximately 77% of our producing wells. Daily production averaged 339 million cubic
feet of natural gas equivalent or MMcfe in 2004. We were founded in December 1985 as a Delaware corporation and began exploring for natural gas and
oil on behalf of KeySpan Corporation, our then parent company. 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 31% of our shares to the public.
Through three separate transactions, the first in February 2003 and the last in November 2004,
KeySpan completely divested of its investment in the common stock of our company. Source of Our Revenues We derive our revenues from the sale of natural gas and oil that is produced from our natural gas
and oil properties. Revenues are a function of the volume produced and the prevailing market price
at the time of sale. The price of natural gas is the primary factor affecting our revenues. To
achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we
utilize derivative instruments to hedge future sales prices on a significant portion of our natural
gas production. During the first three months of both 2005 and 2004, the use of derivative
instruments prevented us from realizing the full benefit of upward price movements and may continue
to do so in future periods. Principal Components of Our Cost Structure  §
    Lease Operating Expenses.The day-to-day costs incurred to bring hydrocarbons
out of the ground and to the market together with the daily costs incurred to maintain our
producing properties. These costs include: lease operating expense, severance tax and
transportation expense, which costs are expected to increase.§
    Depreciation, Depletion and Amortization. The systematic expensing of the
capital costs incurred to acquire, explore and develop natural gas and oil. As a full cost
company, we capitalize all costs associated with our acquisition, exploration and
development efforts, including interest and certain general and administrative costs, and
apportion these costs to each unit of production through depreciation, depletion and
amortization expense. Generally, if reserve quantities are revised up or down, the
depreciation, depletion and amortization rate per unit of production will change inversely. -16-




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§
    Asset Retirement Accretion Expense.The systematic, monthly accretion of the
future abandonment costs of tangible assets such as platforms, wells, service assets,
pipelines, and other facilities.§
    General and Administrative Expense.Overhead, including payroll and benefits
for our corporate staff, costs of maintaining our headquarters, managing our production and
development operations and legal compliance are included in our general and administrative
expense. We capitalize general and administrative expense directly related to our
acquisition, exploration and development activities.§
    Interest.We typically finance our working capital requirements and
acquisitions with borrowings under our revolving bank credit facility, and longer term, with
publicly traded debt instruments. As a result, we incur substantial interest expense that
correlates to both fluctuations in interest rates and our acquisition activity.
Acquisitions are a critical element of our growth strategy. We expect to continue to incur
significant interest expense as we continue to grow. We capitalize interest directly
related to our unevaluated properties that are not being amortized.§
    Income Taxes.We are subject to state and federal income taxes and are
currently in a tax paying position. We expect to continue to recognize current tax expense
as long as we are generating taxable income. Critical Accounting Estimates and Significant Accounting Policies The discussion and analysis of our financial condition and results of operations are based upon our
consolidated financial statements, which have been prepared in accordance with GAAP. The
preparation of our financial statements requires us to make assumptions and prepare estimates that
affect the reported amounts of assets and liabilities, the disclosure of contingent assets and
liabilities and revenues and expenses. We base our estimates on historical experience and various
other assumptions that we believe are reasonable; however, actual results may differ. We evaluate
our assumptions and estimates on a regular basis and discuss the development and disclosure process
with our Audit Committee. Estimates of proved reserves are key components of our most significant
financial estimates involving unevaluated properties, depreciation, depletion and amortization and
our full cost ceiling limitation. In addition, estimates are used to accrue production revenues
and operating expenses, drilling costs, federal and state taxes, the fair value of derivative
contracts, including the calculation of ineffectiveness and the fair value of our stock options.
There has been no change in our critical accounting policies and use of estimates since our Annual
Report. Recent Accounting Pronouncements On December 16, 2004, the FASB revised Statement 123 (revised 2004), Share-Based Payment that
will require compensation costs related to share-based payment transactions (e.g., issuance of
stock options and restricted stock) to be recognized in the financial statements. With limited
exceptions, the amount of compensation cost will be measured based on the grant-date fair value of
the equity or liability instruments issued. In addition, liability awards will be remeasured each
reporting period. Compensation cost will be recognized over the period that an employee provides
service in exchange for the award. Statement 123(R) replaces SFAS 123, Accounting for Stock-Based
Compensation, and supersedes Accounting Principles Board (APB) Opinion No. 25, Accounting for
Stock Issued to Employees. For us, SFAS 123(R), as amended by SEC Release 34-51558, is effective
for our first fiscal year beginning after June 15, 2005, or January 1, 2006. Entities that use the
fair-value-based method for either recognition or disclosure under SFAS 123 are required to apply
SFAS 123(R) using a modified version of prospective application. Under this method, an entity
records compensation expense for all awards it grants after the date of adoption. In addition, the
entity is required to record compensation expense for the unvested portion of previously granted
awards that remain outstanding at the date of adoption. In addition, entities may elect to adopt
SFAS 123 (R) using a modified retrospective method where by previously issued financial statements
are restated based on the expense previously calculated and reported in their pro forma footnote
disclosures. On January 1, 2003, we adopted the fair value expense recognition provisions of SFAS 123 as amended
by SFAS 148, Accounting for Stock-Based Compensation  Transition and Disclosure using the
prospective method as defined by the SFAS 148. As a result, we have recognized compensation
expense for all stock options granted subsequent to January 1, 2003, with no expense recognized for
grants made prior to 2003. Adoption of SFAS 123(R) will require us to recognize compensation
expense over the remaining service period for the unvested portion of all options granted during
2000, 2001 and 2002. All options granted prior to 2000 are fully vested. We expect to adopt SFAS
123(R) on January 1, 2006, using the modified version of the prospective application. We are
currently evaluating the effect adopting SFAS 123(R) will have to our financial statements. On March 29, 2005, the SEC released Staff Accounting Bulletin (SAB) 107 providing additional
guidance in applying the provisions of SFAS 123(R), Share-Based Payment. SAB 107 should be
applied when adopting SFAS 123(R) and -17-




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##### Table of Contents



addresses a wide range of issues, focusing on valuation methodologies and the selection of
assumptions. In addition, SAB 107 addresses the interaction of SFAS
123(R) with existing SEC
guidance. Overview of Results for the First Quarter of 2005 The sustained strength of commodity prices throughout the first three months of 2005, nearly flat
average daily production quarter-over-quarter and a 20% increase in operating expenses were the
primary factors behind results for operations, earnings and cash flows during the first quarter of
2005. During the first three months of 2005:  §
    We generated $33.4 million in net income, a decrease of 16% from first quarter
2004;§
    We produced approximately 30 Bcfe and our average daily production rate was 331
MMcfe per day during the first quarter of 2005 compared to 332 MMcfe per day during the
first quarter of 2004, primarily as a result of shut-in production since the fourth quarter
of 2004 at High Island 115 and the depletion of a well at High Island 47, two key producing
properties during 2004;§
    We generated $148.8 million in net cash flows from operating activities and
invested $146.3 million in natural gas and oil properties, which included $22.6 million for
producing property acquisitions;§
    We drilled 80 wells, of which 60, or 75%, were successful with 25 successful
wells in South Texas, 14 in Arkoma and 21 in the Rockies;§
    We expanded our East Texas acreage position in March 2005 through the
acquisition of a 100% working interest in 5,776 gross acres and three producing wells for
$22.0 million with proved reserves of approximately 9.1 Bcfe as of March 15, 2005, and on
April 5, 2005 acquired a 50% working interest in an additional 4,679 acres and seven
producing wells for $9.2 million with proved reserves of approximately 7.7 Bcfe as of April
1, 2005;§
    We successfully integrated the Gulf of Mexico producing properties acquired in
September and October 2004 from BP Exploration & Production Inc. and Orca Energy, L.P.,
respectively;§
    We incurred $2.8 million in expense as a result of a payout settlement at East
Cameron 82 whereby our working interest in the A3 well has subsequently been reduced from
50% to 35%;§
    We renegotiated employment agreements with five of our key executive officers,
including our Chief Executive Officer, Chief Operating Officer and Chief Financial Officer,
and incurred additional general and administrative expense of $5.0 million;§
    We decreased our outstanding borrowings under our revolving bank credit facility
by a net $15 million; and§
    As a result of higher market prices for natural gas at March 31, 2005, the fair
value of our open derivative contracts increased from a liability of $75.1 million ($48.5
million net of tax) at December 31, 2004, to a liability of $274.3 million ($177.2 million
net of tax) at March 31, 2005. -18-




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Operating and Financial Results for the Three Months Ended March 31, 2005 Compared to the Three
Months Ended March 31, 2004 Three Months Ended March 31,Summary Operating Information:
    
    2005
    
    
    2004
    
    
    Variance(in thousands)Operating revenues
    
    $
    165,720
    
    
    $
    151,882
    
    
    $
    13,838
    
    
    
    9
    %Operating expenses
    
    
    104,119
    
    
    
    86,839
    
    
    
    17,280
    
    
    
    20
    %Income from operations
    
    
    61,601
    
    
    
    65,043
    
    
    
    (3,442
    )
    
    
    -5
    %Net income
    
    
    33,438
    
    
    
    39,690
    
    
    
    (6,252
    )
    
    
    -16
    %Production:Natural gas (MMcf)
    
    
    27,357
    
    
    
    28,132
    
    
    
    (775
    )
    
    
    -3
    %Oil (MBbls)
    
    
    406
    
    
    
    348
    
    
    
    58
    
    
    
    17
    %Total (MMcfe) (1)
    
    
    29,793
    
    
    
    30,220
    
    
    
    (427
    )
    
    
    -1
    %Average daily production (MMcfe/d)
    
    
    331
    
    
    
    332
    
    
    
    (1
    )
    
    
    Average Sales Prices:Natural Gas (per Mcf) realized (2)
    
    $
    5.42
    
    
    $
    4.99
    
    
    $
    0.43
    
    
    
    9
    %Natural Gas (per Mcf) unhedged
    
    
    5.99
    
    
    
    5.43
    
    
    
    0.56
    
    
    
    10
    %Oil (per Bbl) realized (2)
    
    
    42.17
    
    
    
    32.50
    
    
    
    9.67
    
    
    
    30
    %Oil (per Bbl) unhedged
    
    
    42.17
    
    
    
    32.50
    
    
    
    9.67
    
    
    
    30
    %
   (1)
    
    Mcfe is defined as one million cubic feet equivalent of natural gas,
determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or
natural gas liquids.(2)
    
    Average realized prices include the effect of hedges. Income from Operations Operating income for the first quarter of 2005 decreased by $3.4 million, or 5%, as compared to the
first quarter of 2004, primarily as a result of a 20% increase in operating expenses. Operating
revenues were 9% higher compared to the first quarter 2004 due to higher average realized prices
for both natural gas and oil as production volumes remained approximately unchanged, declining by
just 1%. Production Volume We experienced a 1% decrease in production volume for the first three months of 2005 as compared to
the first three months of 2004, primarily as a result of a mechanical problem at High Island 115
and a depleted well at High Island 47. For the first three months of 2005, we added production
from offshore properties acquired during September and October 2004 and experienced production
growth in Arkoma and the Rockies from drilling. Onshore.Daily production rates increased 1% from an average of 185 MMcfe per day during the first
quarter of 2004 to 187 MMcfe per day during the first quarter of 2005. The Arkoma Basin and the
Rockies were our onshore growth areas during the first quarter of 2005. In Arkoma, we added 10
MMcfe per day in newly developed production, increasing our average daily rate by 30% from 33 MMcfe
per day during the first quarter of 2004 to 43 MMcfe per day during the first quarter of 2005. In
the Rockies, we added 5 MMcfe per day from wells completed since the end of the first quarter of
2004. In South Texas, our average daily production declined by 6 MMcfe per day from 141 MMcfe per
day during the first quarter of 2004 to 135 MMcfe per day during the first quarter of 2005. The
decline in South Texas production was due in part to our curtailment of drilling operations during
the fourth quarter of 2004. As a result of rising rig rates and service costs, we reduced our
onshore drilling rig activity late in the fourth quarter of 2004 to keep capital spending within
our 2004 budgeted levels. Offshore. Daily production rates decreased by 2%, or 3 MMcfe per day, from an average of 147 MMcfe
per day during the first quarter of 2004 to an average of 144 MMcfe per day during the first
quarter of 2005. Declining rates from existing and maturing properties outpaced production added
from our September and October 2004 acquisitions and from new wells placed on-line during the first
quarter of 2005. According to our current drilling and workover schedule for 2005, we expect most
of our offshore production growth to occur during the second half of 2005. Quarter-over-quarter,
the decline in -19-




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##### Table of Contents



our average daily production rate was magnified by the depletion of a well at High Island 47 and a
mechanical problem at High Island 115, which on a combined basis contributed approximately 20 MMcfe
per day to our production during the first quarter of 2004. At High Island 47, a sidetrack of the
No. 1 well is currently in the completion stage, and we expect initial production from the new well
during May 2005. At High Island 115, a sidetrack of the No. 1 well is scheduled to begin drilling
during the second quarter of 2005, with the goal of restoring production late in the third quarter
of 2005. Commodity Prices and Effects of Hedging Our average unhedged or sales price for natural gas increased by 10% from $5.43 per Mcf during the
first three months of 2004 to $5.99 per Mcf during the first three months of 2005. Included in
natural gas revenues for the first three months of 2005 is a loss of $15.6 million from natural gas
hedging activities, which is $3.1 million higher than our loss from hedging activities incurred in
the first quarter of 2004. For the current quarter, the $15.6 million hedge loss includes an
unrealized loss of $1.4 million representing the ineffective portion of our derivative instruments
that are not eligible for deferral under SFAS 133. The ineffectiveness was a result of changes
during the period in the price differentials between the index price of the derivative contract,
which uses a New York Mercantile Exchange (NYMEX) index, and the index price for the point of sale
for the cash flow that is being hedged, the majority of which is the Houston Ship Channel index.
As a result of the loss from hedging activities, we realized an average natural gas price during
the first quarter of 2005 of $5.42 per Mcf that was 90% of, or $0.57 per Mcf lower than our average
sales price. During the first quarter of 2004, we incurred a hedge loss from natural gas
derivatives of $12.5 million, which is included in natural gas revenues and includes an unrealized
loss of $1.0 million recognized for ineffectiveness, resulting in an average realized price of
$4.99 per Mcf that was 92% of, or $0.44 per Mcf lower than our average sales price during the first
quarter of 2004. Operating Expenses Three Months Ended March 31,Operating Expenses per Mcfe
    
    2005
    
    
    2004
    
    
    VarianceLease operating expense
    
    $
    0.52
    
    
    $
    0.42
    
    
    $
    0.10
    
    
    
    24
    %Severance tax
    
    
    0.10
    
    
    
    0.10
    
    
    
    
    
    
    
    Transportation expense
    
    
    0.09
    
    
    
    0.09
    
    
    
    
    
    
    
    Asset retirement accretion expense
    
    
    0.04
    
    
    
    0.04
    
    
    
    
    
    
    
    Depreciation, depletion and amortization
    
    
    2.37
    
    
    
    2.02
    
    
    
    0.35
    
    
    
    17
    %General and administrative, net
    
    
    0.37
    
    
    
    0.20
    
    
    
    0.17
    
    
    
    85
    %Total operating expenses per unit of production
    
    $
    3.49
    
    
    $
    2.87
    
    
    $
    0.62
    
    
    
    22
    %
 Total operating expenses on an absolute dollar basis increased 20% during the first quarter of 2005
as compared to the first quarter of 2004 primarily as a result of higher lease operating expenses,
higher depreciation, depletion and amortization expense and non-recurring general and
administrative expenses. On a unit of production basis, operating expenses increased $0.62 per
Mcfe produced, or 22%, for first quarter 2005 compared to first quarter 2004. Depreciation,
depletion and amortization combined with asset retirement expense accounted for $0.35 of the
increase, additional general and administrative expense as a result of payments made pursuant to
the renegotiation of executive employment agreements contributed $0.17 per Mcfe and rising lease
operating expenses added $0.10 to the total per unit increase. Lease Operating Expense. On an absolute dollar basis, lease operating expense increased by 21%
during the first quarter of 2005 as compared to the first quarter of 2004. This increase relates
primarily to properties acquired, rising service costs and continued expansion of our operating
base. During 2004 we successfully drilled and completed 177 new wells and acquired 12 new blocks
in the central Gulf of Mexico pursuant to the September and October Gulf of Mexico acquisitions. We
remain committed to minimizing our operating cost structure; however, we expect to experience
higher lease operating expense throughout the remainder of 2005 as service costs are increasing and
as we plan to continue our acquisition activities. Severance Tax. Severance tax is a function of volume and revenues generated from onshore
production. On an absolute dollar basis, severance tax decreased by 4% from the first quarter of
2004 to the first quarter of 2005 primarily as a result of the continued benefit of the
high-cost/tight-gas formation designation for a portion of our South Texas production. For
qualifying wells, production is either exempt from tax or taxed at a reduced rate until certain
capital costs are recovered. On a unit of production basis, severance tax was unchanged at $0.10
per Mcfe quarter-over-quarter. Depreciation, Depletion and Amortization. The increase in our depreciation, depletion and
amortization expense for first quarter of 2005 was primarily a result of a higher depletion rate
combined with additional expense of $2.9 million resulting -20-




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##### Table of Contents



from our decision not to exercise our option to acquire an interest in an exploration project in
Romanias Carpathian Basin based on our evaluation of the first exploratory well. We decided not
to exercise the option and as a result, wrote off our $2.9 million investment in the project.
This additional expense added approximately $0.10 per Mcfe to our depletion rate for the first
quarter of 2005. In addition to the additional $0.10 per Mcfe, our depletion rate for the first
quarter of 2005 of $2.27 per Mcfe is 12% higher than the $2.02 per Mcfe during the first quarter of
2004. The higher rate for the first quarter of 2005 is primarily as a result of a 48% increase in
our estimated future development costs at December 31, 2004, as compared to estimates at December
31, 2003. Asset Retirement Accretion Expense.ARO accretion expense was unchanged at $1.3 million during
both the first quarter of 2005 and 2004. The increase of $0.01 per unit of production was due to a
decrease in production volume quarter-over-quarter. General and Administrative Expenses, Net of Overhead Reimbursements and Capitalized General and
Administrative Expenses Absolute Dollars
    
    
    Unit of Production - McfeThree Months Ended March 31,
    
    
    Three Months Ended March 31,General and Administrative Expense
    
    2005
    
    
    2004
    
    
    Variance
    
    
    2005
    
    
    2004
    
    
    Variance(in thousands)Gross general and administrative expense
    
    $
    15,962
    
    
    $
    10,803
    
    
    $
    5,159
    
    
    
    48
    %
    
    $
    0.53
    
    
    $
    0.36
    
    
    $
    0.17
    
    
    
    47
    %Operating overhead reimbursements
    
    
    (550
    )
    
    
    (513
    )
    
    
    (37
    )
    
    
    7
    %
    
    
    (0.02
    )
    
    
    (0.02
    )
    
    
    
    
    
    
    Capitalized general and administrative
    
    
    (4,289
    )
    
    
    (4,202
    )
    
    
    (87
    )
    
    
    2
    %
    
    
    (0.14
    )
    
    
    (0.14
    )
    
    
    
    
    
    
    General and administrative expense, net
    
    $
    11,123
    
    
    $
    6,088
    
    
    $
    5,035
    
    
    
    83
    %
    
    $
    0.37
    
    
    $
    0.20
    
    
    $
    0.17
    
    
    
    85
    %
 For the first three months of 2005, aggregate general and administrative expenses increased by 48%,
or $5.2 million, as compared to the first three months of 2004. Net general and administrative
expenses increased by 83%, or $5.0 million, during this period. Of the increase, $5.0 million was
attributable to additional expense incurred pursuant to the February 2005 renegotiation of
executive employment agreements (see Note 5  Related Party Transactions  Employment Agreements)
with the remaining portion of the increase attributable to incremental stock compensation expense
offset in part by a decrease in incentive compensation expense quarter-over-quarter. For general and administrative expense on a per-unit of production basis, the additional expense
related to the renegotiation of employment agreements resulted in a $0.17 per Mcfe increase for the
first quarter of 2005. After giving effect to the additional expense, gross general and
administrative expense for the first quarter of 2005 would have been $0.36 per Mcfe, unchanged from
$0.36 per Mcfe during the first quarter of 2004. Net general and administrative expense would have
been $0.20 per Mcfe for the first quarter of 2005, unchanged from $0.20 per Mcfe for the first
quarter of 2004. Other Income and Expense, Interest and Taxes Other Income and Expense. For the first quarter of 2005, other income and expense includes (i)
expense of $2.8 million incurred as a result of a payout settlement at East Cameron 82/83 and (ii)
income of $1.3 million related to refunds of prior years severance tax expense. 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. For qualifying wells, production is
either exempt from tax or taxed at a reduced rate until certain capital costs are recovered. Interest Expense, Net of Capitalized Interest. Three Months Ended March 31,Interest and Average Borrowings
    
    2005
    
    
    2004
    
    
    Variance(in thousands)Gross interest
    
    $
    5,424
    
    
    $
    4,228
    
    
    $
    1,196
    
    
    
    28
    %Capitalized interest
    
    
    (1,990
    )
    
    
    (1,941
    )
    
    
    (49
    )
    
    
    3
    %Interest expense, net of capitalized interest
    
    $
    3,434
    
    
    $
    2,287
    
    
    $
    1,147
    
    
    
    50
    %Average borrowings
    
    $
    344,744
    
    
    $
    281,400
    
    
    $
    63,344
    
    
    
    23
    %Average interest rate
    
    
    5.82
    %
    
    
    5.53
    %
    
    
    0.29
    %
    
    
    5
    %
 During the first quarter of 2005, the increase in gross interest expense is due to an increase in
outstanding borrowings under our revolving bank credit facility and an increase in average interest
rates associated with our bank debt. Bank borrowings averaged $170.0 million at a rate of 4.6%
during the first quarter of 2005 compared to an average of $106.0 million at 3.27% during the first
quarter of 2004. Our average bank debt increased during the second half of 2004 and the first
quarter of 2005 as we utilized our revolving facility to fund a portion of the asset exchange
transaction with KeySpan in June 2004, -21-




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##### Table of Contents



two producing property acquisitions in September and October 2004 and the East Texas acquisition in
March 2005. Although the majority of our bank debt bears interest at LIBOR-based rates, we do
expect to see an increase in rates during 2005 if the Federal Reserve continues its expected plan
to slowly increase Federal interest rates in an effort to curb inflation. Federal rates were
increased in February and March 2005, by one quarter of a percent during each period. Capitalized
interest is a function of unevaluated properties and the 3% increase during the first quarter of
2005 compared to the first quarter of 2004 corresponds to the increase in our average unevaluated
property balance during the first three months of 2005. Income Tax Provision.Our provision for taxes includes both state and federal taxes. Our current
provision for the first quarter of 2005 includes $1.4 million relating to nondeductible excess
executive compensation expense incurred as a result of the contract renegotiation payment made to
our Chief Executive Officer in February 2005 (see Note 5  Related Party Transactions  Employment
Agreements). Our provision for the first quarter of 2005 includes additional expense of $2.0
million, primarily related to adjustments to estimates for federal and state liabilities. Liquidity Capital Requirements Our principal requirements for capital are to fund our capital investment program and to satisfy
our contractual obligations, primarily the repayment of long-term debt and any amounts owing in the
period relating to our hedging positions. Our capital investments include the following:  §
    Costs of acquiring and maintaining our lease acreage position and our seismic resources;§
    Costs of drilling and completing new natural gas and oil wells;§
    Costs of acquiring additional reserves;§
    Costs of installing new production infrastructure;§
    Costs of maintaining, repairing, and enhancing existing natural gas and oil wells;§
    Costs related to plugging and abandoning unproductive or uneconomic wells; and§
    Indirect costs related to our exploration activities, including payroll and
other expense attributable to our exploration professional staff. On April 26, 2005, our Board of Directors increased our capital expenditure budget for 2005 from an
initial level of $446 million to $512 million. The $66 million increase was made in part to
accommodate our $31.2 million East Texas acquisition. We are the designated operator of
approximately 77% of our wells. Operating allows us the ability to exercise control over the
magnitude and timing of our capital program and provides us significant latitude to increase or
decrease our spending in response to changes in price, operational developments or acquisition
opportunities. To maintain flexibility of our capital program, we typically do not enter into
material long-term obligations with any of our drilling contractors or service providers with
respect to our operated properties; however, we may choose to do so if an opportunity is
economically beneficial. Going forward, we have not included property acquisition costs in our
capital budget because the size and timing of capital requirements for acquisitions are inherently
unpredictable. As the year progresses, we will continue to evaluate our capital spending. Actual
levels may vary due to a variety of factors, including drilling results, natural gas prices,
economic conditions and future acquisitions. Our total company capital expenditures during the first three months of 2005 were $146.6 million.
We invested $146.3 million in natural gas and oil properties, which included $22.6 million for
producing property acquisitions, and we spent $0.3 million for non-oil and gas property and
equipment. Non-oil and gas property and equipment includes expenditures to upgrade our information
technology systems and office equipment and compares to $0.6 million spent during the first three
months of 2004. For the first three months of 2005, we spent 38% offshore and 58% onshore with the
balance of 4% on capitalized interest and general and administrative costs. We completed the
drilling of 80 gross wells (69.6 net), of which 75%, or 60 (51.7 net), were successful and 25%, or
20 (17.9 net), were unsuccessful, with an additional 8 wells (5.6 net) in progress at March 31,
2005. The following table provides a summary of our capital expenditures for natural gas and oil
properties during each of the three-month periods ended March 31, 2005 and 2004. -22-




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##### Table of Contents



Three Months Ended March 31,Natural gas and oil capital expenditures
    
    2005
    
    
    2004(in thousands)Producing property acquisitions
    
    $
    22,615
    
    
    $
    2,700Leasehold and lease acquisition costs (1)
    
    
    25,237
    
    
    
    13,634Development
    
    
    73,223
    
    
    
    57,536Exploration
    
    
    25,239
    
    
    
    10,768Total natural gas and oil capital expenditures
    
    
    146,314
    
    
    
    84,638Producing property dispositions
    
    
    (150
    )
    
    
    (13,138
    )Net natural gas and oil capital expenditures
    
    $
    146,164
    
    
    $
    71,500
   (1)
    
    For the three months ended March 31, 2005 and 2004, leasehold costs
include capitalized interest and general and administrative expenses of $6.3 million
and $6.1 million, respectively. Future Commitments As of March 31, 2005, we had committed to acquire additional East Texas producing properties for
$9.2 million, which we paid in April 2005, and have a purchase obligation under an existing seismic
license agreement to acquire additional seismic data for up to $7.7 million payable in January
2006. During February 2005, we entered into a one-year contract for a drilling rig in the Uinta
Basin. As of March 31, 2005, we do not have any capital leases nor have we entered into any
additional long-term contracts for drilling rigs or equipment. The table below provides estimates
of the timing of future payments that we were obligated to make based on agreements in place at
March 31, 2005. In addition to the contractual obligations listed on the table below, our balance
sheet at March 31, 2005, reflects accrued interest payable on our bank credit facility of
approximately $57,000 which is payable over the next 90-day period. We expect to make annual
interest payments of $12.3 million per year on our $175 million of 7% senior subordinated notes due
June 2013, and we anticipate making income tax payments of approximately $50 million during 2005. As of March 31, 2005Payments Due by PeriodReference
    
    
    Total
    
    
    1 year or less
    
    
    2  3 years
    
    
    4  5 years
    
    
    after 5 years(in thousands)Contractual Obligations:Revolving bank credit facility, due April 2008
    
    Note 2
    
    $
    165,000
    
    
    $
    
    
    
    $
    
    
    
    $
    165,000
    
    
    $
    7% senior subordinated notes, due June 2013
    
    Note 2
    
    
    175,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    175,000Derivative instruments
    
    Note 1
    
    
    274,255
    
    
    
    193,849
    
    
    
    71,997
    
    
    
    8,409
    
    
    
    Operating leases
    
    Note 4
    
    
    6,869
    
    
    
    1,170
    
    
    
    3,142
    
    
    
    2,557
    
    
    
    East Texas producing property acquisition
    
    Note 6
    
    
    9,246
    
    
    
    9,246
    
    
    
    
    
    
    
    
    
    
    
    Seismic data purchase
    
    Note 4
    
    
    7,749
    
    
    
    7,749
    
    
    
    
    
    
    
    
    
    
    
    Drilling contract
    
    Note 4
    
    
    3,560
    
    
    
    3,560
    
    
    
    
    
    
    
    
    
    
    
    641,679
    
    
    
    215,574
    
    
    
    75,139
    
    
    
    175,966
    
    
    
    175,000Other Long-Term Obligations:Asset retirement obligations
    
    Note 1
    
    
    95,318
    
    
    
    2,141
    
    
    
    11,754
    
    
    
    6,869
    
    
    
    74,554Total contractual obligations and
commitments
    
    
    
    
    
    $
    736,997
    
    
    $
    217,715
    
    
    $
    86,893
    
    
    $
    182,835
    
    
    $
    249,554
 -23-




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##### Table of Contents



Capital Resources We intend to fund our capital expenditure program and contractual commitments through cash flows
from our operations and borrowings under our revolving bank credit facility. If a significant
acquisition opportunity arises, we may also access public markets for debt or to issue additional
equity securities. Our primary sources of cash during the first quarter of 2005 were from funds
generated from operations. Cash was used to fund acquisitions, exploration and development
expenditures and to reduce debt under our revolving bank credit facility. We made aggregate cash
payments of $2 million for interest during the first three months of 2005 with no cash payments for
federal or state income taxes during the same three-month period. The table below summarizes the
sources of cash during 2005 and 2004. Three Months Ended March 31,2005
    
    
    2004
    
    
    variance
    
    
    % change(in thousands)Net cash provided by operating activities
    
    $
    148,848
    
    
    $
    128,606
    
    
    $
    20,242
    
    
    
    16
    %Net cash (used) for investments in property and equipment
    
    
    (146,477
    )
    
    
    (72,084
    )
    
    
    (74,393
    )
    
    
    103
    %Net cash (used in) provided by financing activities
    
    
    (7,188
    )
    
    
    (45,371
    )
    
    
    38,183
    
    
    
    -84
    %Net (decrease) increase in cash
    
    $
    (4,817
    )
    
    $
    11,151
    
    
    $
    (15,968
    )
    
    
    -143
    %
 At March 31, 2005, we had a working capital deficit of $141.2 million, long-term debt of $340
million and $234.6 million of borrowing capacity available under our revolving bank credit
facility. The working capital deficit at March 31, 2005, was due to a current liability of $193.8
million representing the fair value of our derivative instruments estimated to be payable over the
next 12 months, offset in part by the associated deferred tax asset of $68.6 million. As a result
of higher natural gas prices, the fair value of our open derivative contracts payable within the
next 12 months increased by $125.2 million from a liability of $68.1 million at December 31, 2004,
to a liability of $193.8 million at March 31, 2005. Corresponding to the increase in the
liability, the associated deferred tax asset increased by $44.5 million during this same
three-month period. The fair value of our derivative instruments will fluctuate with commodity
prices, and as commodity prices increase, our liquidity exposure tends to increase as a result of
open derivative instruments. Consequently, we are more likely to have the largest unfavorable
mark-to-market position in a high commodity price environment. Our working capital balance
fluctuates as a result of the timing and amount of cash receipts and disbursements for operating
activities and borrowings or repayments under our revolving bank credit facility. As a result, we
often have a working capital deficit or a relatively small amount of positive working capital,
which is typical of companies of our size in the exploration and production industry. The 16% increase in net cash provided by operating activities during the first three months of 2005
was primarily attributable to fluctuations in operating assets and liabilities, which are caused by
the timing of cash receipts and disbursements. During the first three months of 2005, total long-term debt decreased by a net $15 million, as we
used cash generated from operations to repay borrowings under our revolving bank credit facility.
Subsequent to March 31, 2005, we repaid an additional $9.0 million under our revolving bank credit
facility, reducing outstanding bank borrowings to $156 million as of May 4, 2005. In addition, as
a result of rising natural gas prices, we issued letters of credit totaling $3.3 million to further
guarantee our performance under open derivative contracts, increasing outstanding letters of credit
to $3.7 million as of May 4, 2005. Access to Capital Markets. In March 2004 and October 2004 we filed shelf registration statements
with the SEC for the offering, from time to time, of up to $750 million, on a combined basis, of
our common stock, preferred stock, depositary shares and debt securities, or a combination of any
of these securities. We believe that operating cash flow and our credit facility will be adequate to meet our capital
and operating requirements for the remaining portion of 2005. We continuously monitor our working
capital and debt position as well as coordinate our capital expenditure program with expected cash
flows and projected debt repayment schedules. Although we have no specific budget for future
property acquisitions, should attractive opportunities arise, we believe we could finance the
additional capital expenditures with cash on hand, operating cash flow, additional borrowing under
our revolving bank credit facility, issuances of additional equity or debt securities or
development with industry partners. Off-Balance Sheet Arrangements We do not currently utilize any off-balance sheet arrangements to enhance liquidity and capital
resource positions, or for any other purpose. Any future transactions involving off-balance sheet
arrangements would be scrutinized and disclosed. -24-




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##### Table of Contents



Item 3. Quantitative and Qualitative Disclosures About Market Risk Market Risk Our major market risk exposure continues to be the prices applicable to our natural gas and oil
production. Our sales price is primarily driven by the prevailing market price. Historically,
prices received for our natural gas and oil production have been volatile and unpredictable. Interest Rate Market Risk At March 31, 2005, total debt was $340 million, of which approximately 51%, or $175 million, is
fixed at an interest rate of 7%. The remaining 49% of our total debt balance at March 31, 2005, or
$165 million, represents our bank debt that is tied to floating or market interest rates.
Fluctuations in floating interest rates will cause our annual interest costs to fluctuate. During
the first quarter of 2005, the interest rate on our outstanding bank debt averaged 4.60%. If the
balance of our bank debt at March 31, 2005, were to remain constant, a 10% change in market
interest rates would impact our cash flow by approximately $189,750 per quarter. Commodity 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. 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. 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, net of tax, 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 natural gas and
oil revenues. During the first three months of 2005 and 2004, we recognized $1.4 million and $1.0
million, respectively, for ineffectiveness. The ineffectiveness was primarily a result of changes
at the end of each period in the price differentials between the index price of the derivative
contract, which uses a NYMEX index, and the index price for the point of sale for the cash flow
that is being hedged, the majority of which is the Houston Ship Channel index. Subsequent to the balance sheet date and as a result of increases in the market price of natural
gas, the fair value of our open derivative contracts increased beyond our available credit limit
with one counterparty. As a result, in April 2005, we were required to issue letters of credit
totaling $3.3 million to further guarantee our performance on open derivative contracts. Changes in Fair Value of Derivative Instruments The following table summarizes the change in the fair value of our derivative instruments for each
of the three-month periods from January 1 to March 31, 2005 and 2004, and provides the fair value
at the end of each period. Three Months Ended March 31,2005
    
    
    2004Change in Fair Value of Derivatives Instruments:
    
    Before Tax(in thousands)Fair value of contracts at January 1
    
    $
    (75,149
    )
    
    $
    (36,862
    )Realized loss on contracts settled
    
    
    14,175
    
    
    
    11,549(Decrease) in fair value of all open contracts
    
    
    (213,281
    )
    
    
    (58,524
    )Net (decrease) increase during periodFair value of contracts outstanding at March 31
    
    $
    (274,255
    )
    
    $
    (83,837
    )
 -25-




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##### Table of Contents



Derivatives in Place as of the Date of Our Report As of May 4, 2005, the following table summarizes, on a daily basis, our natural gas hedges in
place for 2005, 2006, 2007 and 2008. For the remaining nine months of 2005, we have hedged
approximately 70% of our estimated production, or a total of 260,000 million British thermal units
per day (MMBtu/day). Daily Volume
    
    
    NYMEX Price
    
    
    Floor Price
    
    
    Ceiling PriceYear
    
    Transaction Type
    
    (MMBtu/day)
    
    
    ($/MMBtu)
    
    
    ($/MMBtu)
    
    
    ($/MMBtu)2005
    
    Swap
    
    
    20,000
    
    
    $
    4.75
    
    
    
    
    
    
    
    2005
    
    Swap
    
    
    10,000
    
    
    
    4.77
    
    
    
    
    
    
    
    2005
    
    Swap
    
    
    20,000
    
    
    
    4.78
    
    
    
    
    
    
    
    2005
    
    Swap
    
    
    20,000
    
    
    
    6.15
    
    
    
    
    
    
    
    2005
    
    Swap
    
    
    10,000
    
    
    
    6.30
    
    
    
    
    
    
    
    Total swaps
    
    
    80,0002005
    
    Costless collar
    
    
    100,000
    
    
    
    
    
    
    $
    4.50
    
    
    $
    5.502005
    
    Costless collar
    

    
    30,000
    
    
    
    
    
    
    
    4.50
    
    
    
    6.052005
    
    Costless collar
    
    
    10,000
    
    
    
    
    
    
    
    4.50
    
    
    
    6.062005
    
    Costless collar
    
    
    10,000
    
    
    
    
    
    
    
    4.50
    
    
    
    6.072005
    
    Costless collar
    
    
    10,000
    
    
    
    
    
    
    
    6.50
    
    
    
    10.152005
    
    Costless collar
    
    
    20,000
    
    
    
    
    
    
    
    6.50
    
    
    
    10.19Total collars
    
    
    180,000Total daily volume 2005
    
    
    260,0002006
    
    Swap
    
    
    20,000
    
    
    $
    5.87
    
    
    
    
    
    
    
    2006
    
    Swap
    
    
    10,000
    
    
    
    5.94
    
    
    
    
    
    
    
    Total swaps
    
    
    30,0002006
    
    Costless collar
    
    
    10,000
    
    
    
    
    
    
    $
    5.50
    
    
    $
    7.202006
    
    Costless collar
    
    
    10,000
    
    
    
    
    
    
    
    5.50
    
    
    
    7.252006
    
    Costless collar
    
    
    40,000
    
    
    
    
    
    
    
    5.50
    
    
    
    7.262006
    
    Costless collar
    
    
    20,000
    
    
    
    
    
    
    
    5.75
    
    
    
    7.202006
    
    Costless collar
    
    
    30,000
    
    
    
    
    
    
    
    5.80
    
    
    
    7.002006
    
    Costless collar
    
    
    50,000
    
    
    
    
    
    
    
    5.82
    
    
    
    7.002006
    
    Costless collar
    
    
    30,000
    
    
    
    
    
    
    
    6.00
    
    
    
    7.002006
    
    Costless collar
    
    
    20,000
    
    
    
    
    
    
    
    6.00
    
    
    
    7.022006
    
    Costless collar
    
    
    10,000
    
    
    
    
    
    
    
    6.00
    
    
    
    7.05Total collars
    
    
    220,000Total daily volume 2006
    
    
    250,0002007
    
    Costless collar
    
    
    20,000
    
    
    
    
    
    
    $
    5.00
    
    
    $
    6.502007
    
    Costless collar
    
    
    10,000
    
    
    
    
    
    
    
    5.00
    
    
    
    6.79Total daily volume 2007
    
    
    30,0002008
    
    Costless collar
    
    
    20,000
    
    
    
    
    
    
    $
    5.00
    
    
    $
    5.72Total daily volume 2008
    
    
    20,000
 For natural gas, transactions are settled based upon the 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 -26-




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##### Table of Contents



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 Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures Under the supervision and with the participation of our management, including our Chief Executive
Officer and our Chief Financial Officer, we conducted an evaluation of our disclosure controls and
procedures, as this term is defined under Rule 13a-15(e) promulgated under the Securities Exchange
Act of 1934, as amended (the Exchange Act). Based on this evaluation, our Chief Executive Officer
and our Chief Financial Officer concluded that our disclosure controls and procedures were
effective as of the end of the period covered by this Quarterly Report. Changes in Internal Control Over Financial Reporting No change in our internal control over financial reporting (as defined in Rule 13a-15(f) under the
Exchange Act) occurred during the first quarter of our fiscal year ended December 31, 2005, that
has materially affected, or is reasonably likely to materially affect, our internal control over
financial reporting. 
 Part II. Other Information Item 4. Submission of Matters to a Vote of Security Holders On April 26, 2005, we held our annual meeting of stockholders. All matters brought for a vote
before the shareholders as listed in our proxy statement were approved as follows:  1.
    The election of the following eight Directors of our company to serve until our next annual
meeting: Director
    
    Votes For
    
    
    Votes WithheldRobert B. Catell
    
    
    25,221,926
    
    
    
    1,949,490John U. Clarke
    
    
    25,917,350
    
    
    
    1,254,066David G. Elkins
    
    
    25,882,983
    
    
    
    1,288,433William G. Hargett
    
    
    25,533,653
    
    
    
    1,637,763Harold R. Logan, Jr.
    
    
    25,919,180
    
    
    
    1,252,236Thomas A. McKeever
    
    
    25,920,280
    
    
    
    1,251,136Stephen W. McKessy
    
    
    25,918,080
    
    
    
    1,253,336Donald C. Vaughn
    
    
    25,915,100
    
    
    
    1,256,316
  2.
    An amendment to our Restated Certificate of Incorporation increasing the number of authorized
            shares of common stock, par value $0.01 per share, from 50,000,000 to 100,000,000 shares: Votes For
    
    Votes Against
    
    Abstained21,539,994
    
    5,601,533
    
    29,889
  3.
    The ratification and approval of Deloitte & Touche LLP as our independent public accountants
for the fiscal year ending December 31, 2005: Votes For
    
    Votes Against
    
    Abstained27,100,748
    
    37,174
    
    33,494
 -27-




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##### Table of Contents



Item 5. Other Information In accordance with SEC rules, the following information in this Item 5 is provided in lieu of a
Current Report on Form 8-K, Item 1.01. Entry into a Material Definitive Agreement and Item 3.03.
Material Modification to Rights of Security Holders, that would otherwise be due within four
business days after the May 2, 2005 date noted below on which the Rights Agreement was amended. On May 2, 2005, The Houston Exploration Company (the Company) and The Bank of New York, as Rights
Agent, amended the Rights Agreement, dated as of August 12, 2004, by executing the First Amendment
to the Rights Agreement (Amendment No. 1), in connection with rights to purchase Series A Junior
Participating Preferred Stock of the Company. Amendment No. 1 amends the Rights Agreement as
follows: (1) the definition of Acquiring Person set forth in Section 1 of the Rights Agreement is
amended to increase the threshold of common stock ownership required for a stockholder to be deemed
an Acquiring Person from 10% to 15%; (2) the definition of Exempt Person is amended to delete
references to KeySpan Corporation, the Companys former significant stockholder; and (3) Exhibit C
to the Rights Agreement, the Summary of Rights to Purchase Shares of Preferred Stock of The Houston
Exploration Company, is amended to make conforming changes. The original Rights Agreement was filed as Exhibit 1 to the Companys Registration Statement on
Form 8-A dated August 12, 2004, and is incorporated by reference herein. The foregoing description
of Amendment No. 1 is qualified in its entirety by Amendment No. 1, which is attached hereto as
Exhibit 4.1 and incorporated by reference herein. 
 Item 6. Exhibits EXHIBITS
    
    
    
    DESCRIPTION3.1(1)
    
    
    
    Restated Certificate of Incorporation, as amended, including the
Certificate of Amendment filed April 26, 2005.4.1(1)
    
    
    
    First Amendment dated as of May 2, 2005, to the Rights Agreement dated as of
August 12, 2004 between The Houston Exploration Company and The Bank of New York, as Rights
Agent.10.1(1)
    
    
    
    Second Amendment dated effective as of October 8, 2004, to the Amended and
Restated Credit Agreement dated April 1, 2004, among The Houston Exploration Company and
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 and Comerica
Bank as Co-Documentation Agents.10.2(2)
    
    
    
    Employment agreement dated March 10, 2005, between The Houston Exploration
Company and John E. Bergeron (filed as exhibit 99.2 to our Current Report on Form 8-K on March
10, 2005, (File No. 001-11899) and incorporated by reference).10.3(2)
    
    
    
    Employment agreement dated April 13, 2005, between The Houston Exploration
Company and Jeffrey B. Sherrick (filed as exhibit 99.2 to our Current Report on Form 8-K on
April 13, 2005, (File No. 001-11899) and incorporated by reference).12.1(1)
    
    
    
    Computation of ratio of earnings to fixed charges.21.1(1)
    
    
    
    Subsidiaries of The Houston Exploration Company.31.1(1)
    
    
    
    Certification of William G. Hargett, Chief Executive Officer, as required pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.31.2(1)
    
    
    
    Certification of John H. Karnes, Chief Financial Officer, as required pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.32.1(1)
    
    
    
    Certification of William G. Hargett, Chief Executive Officer, as required pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.32.2(1)
    
    
    
    Certification of John H. Karnes, Chief Financial Officer, as required pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002.
   (1)
    
    Filed herewith.(2)
    
    Management contract or compensation plan. -28-




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##### Table of Contents



SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized. THE HOUSTON EXPLORATION COMPANYBy:
    
    /s/ William G. HargettWilliam G. HargettDate: May 4, 2005
    
    
    
    Chairman, President and Chief Executive OfficerBy:
    
    /s/ John H. KarnesJohn H. KarnesDate: May 4, 2005
    
    
    
    Senior Vice President and Chief Financial OfficerBy:
    
    /s/ James F. WestmorelandJames F. WestmorelandDate: May 4, 2005
    
    
    
    Vice President and Chief Accounting Officer
 -29-




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##### Table of Contents



Exhibit Index EXHIBITS
    
    
    
    DESCRIPTION3.1(1)
    
    
    
    Restated Certificate of Incorporation, as amended, including the
Certificate of Amendment filed April 26, 2005.4.1(1)
    
    
    
    First Amendment dated as of May 2, 2005, to the Rights Agreement dated as of
August 12, 2004 between The Houston Exploration Company and The Bank of New York, as Rights
Agent.10.1(1)
    
    
    
    Second Amendment dated effective as of October 8, 2004, to the Amended and
Restated Credit Agreement dated April 1, 2004, among The Houston Exploration Company and
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 and Comerica
Bank as Co-Documentation Agents.10.2(2)
    
    
    
    Employment agreement dated March 10, 2005, between The Houston Exploration
Company and John E. Bergeron (filed as exhibit 99.2 to our Current Report on Form 8-K on March
10, 2005, (File No. 001-11899) and incorporated by reference).10.3(2)
    
    
    
    Employment agreement dated April 13, 2005, between The Houston Exploration
Company and Jeffrey B. Sherrick (filed as exhibit 99.2 to our Current Report on Form 8-K on
April 13, 2005, (File No. 001-11899) and incorporated by reference).12.1(1)
    
    
    
    Computation of ratio of earnings to fixed charges.21.1(1)
    
    
    
    Subsidiaries of The Houston Exploration Company.31.1(1)
    
    
    
    Certification of William G. Hargett, Chief Executive Officer, as required pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.31.2(1)
    
    
    
    Certification of John H. Karnes, Chief Financial Officer, as required pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.32.1(1)
    
    
    
    Certification of William G. Hargett, Chief Executive Officer, as required pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.32.2(1)
    
    
    
    Certification of John H. Karnes, Chief Financial Officer, as required pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002.
   (1)
    
    Filed herewith.(2)
    
    Management contract or compensation plan.