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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION  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, 2004 OR o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 For the transition period fromto 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 Street, Suite 2000
Houston, Texas 77002-5215
(Address of principal executive offices and zip code) (713) 830-6800
(Registrants telephone number, including area code) 
 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 Securities Exchange Act of 1934).
Yes þ No o As
of May 6, 2004, 31,883,703 shares of Common Stock, par value $.01 per
share, were outstanding.




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THE HOUSTON EXPLORATION COMPANY TABLE OF CONTENTS  
 PageForward Looking Statements
    
    
    3Part I. Financial Information
    
    
    4Item 1. Consolidated Financial Statements
    
    
    4Consolidated Balance Sheets  March 31, 2004 and December 31, 2003 (unaudited)
    
    
    4Consolidated Statements Of Operations  Three Months Ended March 31, 2004 and 2003 (unaudited)
    
    
    5Consolidated Statements Of Cash Flows  Three Months Ended March 31, 2004 and 2003 (unaudited)
    
    
    6Notes To The Consolidated Financial Statements (unaudited)
    
    
    7Item 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
    
    
    26Item 6. Exhibits and Reports On Form 8-K:
    
    
    26(A) Exhibits:
    
    
    27(B) Reports on Form 8-K:
    
    
    27Signatures
    
    
    28Amended and Restated Credit AgreementStatement of computation of ratio of earningsCertification of CEO pursuant to Section 302Certification of SVP & CFO pursuant to Section 302Certification of CEO pursuant to Section 906Certification of SVP & CFO pursuant to Section 906
  2




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Forward Looking Statements All of the estimates and assumptions contained in this Quarterly Report
constitute forward looking statements as that term is defined in Section 27A of
the Securities Act of 1993,as amended and Section 21E of the Securities
Exchange Act of 1934, as amended. These forward-looking statements generally
can be identified by words such as anticipate, believe, expect,
continue, estimate, project or similar expressions. All statements under
the caption Item 2. Managements Discussion and Analysis of Financial
Condition and Results of Operations relating to our future production,
expected costs and expenses, anticipated capital expenditures, future cash
flows and borrowings, pursuit of potential future acquisition opportunities and
sources of funding and the timing of exploration and development are forward
looking statements. Although we believe that these forward-looking statements
are based on reasonable assumptions, our expectations may not occur and we can
not guarantee that the anticipated future results will be realized. 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;
    
    our ability to find, develop and acquire natural gas and oil reserves;
    
    the successfulness of our acquisition and investment activities;
    
    our ability to meet our substantial capital requirements;
    
    our outstanding indebtedness may restrict our financial flexibility;
    
    the uncertainty of estimates of natural gas and oil reserves and production rates;
    
    the inherent hazards and risks involved in our operations;
    
    the concentrated nature of our operations;
    
    our hedging activities could result in financial losses or reductions to income;
    
    our compliance with environmental and other governmental regulations;
    
    the competitive nature of our industry;
    
    our customers ability to meet their obligations; and
    
    potential conflicts with our majority stockholder, KeySpan Corporation. For additional discussion of these risks, uncertainties and assumptions, see
Items 1. and 2. Business and Properties and Item 7. Managements
Discussion and Analysis of Financial Condition and Results of Operations
contained in our Annual Report on Form 10-K. 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 or our, we are describing The Houston Exploration Company and
its subsidiary on a consolidated basis. 3




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Part I. Financial Information 
 Item 1. Consolidated Financial Statements (unaudited) THE HOUSTON EXPLORATION COMPANY 
 CONSOLIDATED BALANCE SHEETS
 (in thousands, except share data)
 March 31,
    
    December 31,2004
    
    2003Assets:Cash and cash equivalents
    
    $
    13,720
    
    
    $
    2,569Accounts receivable
    
    
    95,368
    
    
    
    87,949Accounts receivable  Affiliate
    
    
    6,239
    
    
    
    6,733Derivative financial instruments
    
    
    
    
    
    
    3,458Inventories
    
    
    1,164
    
    
    
    1,071Deferred tax asset
    
    
    24,011
    
    
    
    19,644Prepayments and other
    
    
    5,206
    
    
    
    5,818Total current assets
    
    
    145,708
    
    
    
    127,242Natural gas and oil properties, full cost methodUnevaluated properties
    
    
    130,168
    
    
    
    134,491Properties subject to amortization
    
    
    2,397,315
    
    
    
    2,324,011Other property and equipment
    
    
    13,219
    
    
    
    12,6172,540,702
    
    
    
    2,471,119Less: Accumulated depreciation, depletion and amortization
    
    
    1,160,974
    
    
    
    1,099,9901,379,728
    
    
    
    1,371,129Other non-current assets
    
    
    13,664
    
    
    
    10,694Total Assets
    
    $
    1,539,100
    
    
    $
    1,509,065Liabilities:Accounts payable and accrued expenses
    
    $
    96,788
    
    
    $
    83,983Derivative financial instruments
    
    
    63,535
    
    
    
    35,592Asset retirement obligation
    
    
    3,642
    
    
    
    7,703Total current liabilities
    
    
    163,965
    
    
    
    127,278Long-term debt and notes
    
    
    245,000
    
    
    
    302,000Derivative financial instruments
    
    
    20,302
    
    
    
    4,728Deferred federal income taxes
    
    
    253,938
    
    
    
    251,425Asset retirement obligation
    
    
    84,930
    
    
    
    84,654Other deferred liabilities
    
    
    10,173
    
    
    
    3,446Total Liabilities
    
    
    778,308
    
    
    
    773,531Commitments and Contingencies (see Note 3)Stockholders Equity:Common Stock, $.01 par value, 50,000,000 shares authorized and 31,854,155
shares issued and outstanding at March 31, 2004 and 31,437,581 shares
issued and outstanding at December 31, 2003, respectively
    
    
    319
    
    
    
    315Additional paid-in capital
    
    
    380,392
    
    
    
    366,781Unearned compensation
    
    
    (746
    )
    
    
    (808
    )Retained earnings
    
    
    435,064
    
    
    
    395,374Accumulated other comprehensive income
    
    
    (54,237
    )
    
    
    (26,128
    )Total Stockholders Equity
    
    
    760,792
    
    
    
    735,534Total Liabilities and Stockholders Equity
    
    $
    1,539,100
    
    
    $
    1,509,065
 The accompanying notes are an integral part of these consolidated financial statements. 4




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THE HOUSTON EXPLORATION COMPANY 
 CONSOLIDATED STATEMENTS OF OPERATIONS
 (in thousands, except per share data)
 Three Months EndedMarch 31,2004
    
    2003(unaudited)Revenues:Natural gas and oil revenues
    
    $
    151,634
    
    
    $
    128,398Other
    
    
    248
    
    
    
    605Total revenues
    
    
    151,882
    
    
    
    129,003Operating expenses:Lease operating
    
    
    12,706
    
    
    
    11,646Severance tax
    
    
    3,057
    
    
    
    4,305Transportation expense
    
    
    2,736
    
    
    
    2,492Asset retirement accretion expense
    
    
    1,288
    
    
    
    826Depreciation, depletion and amortization
    
    
    60,964
    
    
    
    45,654General and administrative, net
    
    
    6,088
    
    
    
    3,884Total operating expenses
    
    
    86,839
    
    
    
    68,807Income from operations
    
    
    65,043
    
    
    
    60,196Other (income) expense
    
    
    110
    
    
    
    (10,578
    )Interest expense, net
    
    
    2,287
    
    
    
    2,266Income before income taxes
    
    
    62,646
    
    
    
    68,508Provision for taxes
    
    
    22,956
    
    
    
    24,039Income before cumulative effect of change in
accounting principle
    
    $
    39,690
    
    
    $
    44,469Cumulative effect of change in accounting principle.
    
    
    
    
    
    
    (2,772
    )Net income
    
    $
    39,690
    
    
    $
    41,697Earnings per share:Net income per share  basicIncome before cumulative effect of change in
accounting principle
    
    $
    1.26
    
    
    $
    1.44Cumulative effect of change in accounting
principle
    
    
    
    
    
    
    (0.09
    )Net income per share  basic
    
    $
    1.26
    
    
    $
    1.35Net income per share  fully dilutedIncome before cumulative effect of change in
accounting principle
    
    $
    1.25
    
    
    $
    1.43Cumulative effect of change in accounting
principle
    
    
    
    
    
    
    (0.09
    )Net income per share  fully diluted
    
    $
    1.25
    
    
    $
    1.34Weighted average shares outstanding  basic
    
    
    31,598
    
    
    
    30,960Weighted average shares outstanding  fully diluted
    
    
    31,714
    
    
    
    31,069
 The accompanying notes are an integral part of these consolidated financial statements. 5




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THE HOUSTON EXPLORATION COMPANY 
 CONSOLIDATED STATEMENTS OF CASH FLOWS
 (in thousands)
 Three Months Ended March 31,2004
    
    2003(unaudited)Operating Activities:Net income
    
    $
    39,690
    
    
    $
    41,697Adjustments to reconcile net income to net cash provided by
operating activities:Depreciation, depletion and amortization
    
    
    60,964
    
    
    
    45,654Deferred income tax expense
    
    
    14,814
    
    
    
    23,981Asset retirement accretion expense
    
    
    1,288
    
    
    
    826Ineffectiveness of derivative instruments
    
    
    1,000
    
    
    
    Amortization of premium on derivative instruments
    
    
    2,730
    
    
    
    Stock compensation expense
    
    
    517
    
    
    
    35Cumulative effect of change in accounting principle
    
    
    
    
    
    
    2,772Changes in operating assets and liabilities:Increase in accounts receivable
    
    
    (6,925
    )
    
    
    (63,374
    )Increase in inventories
    
    
    (93
    )
    
    
    (184
    )Decrease in prepayments and other
    
    
    612
    
    
    
    5,513Increase in other assets
    
    
    (2,970
    )
    
    
    (8,519
    )Increase in accounts payable and accrued expenses
    
    
    12,805
    
    
    
    13,712Increase in other liabilities
    
    
    6,727
    
    
    
    868Net cash provided by operating activities
    
    
    131,159
    
    
    
    62,981Investing Activities:Investment in property and equipment
    
    
    (85,222
    )
    
    
    (53,646
    )Assets retired and abandoned
    
    
    (2,553
    )
    
    
    Proceeds from dispositions
    
    
    13,138
    
    
    
    Net cash used in investing activities
    
    
    (74,637
    )
    
    
    (53,646
    )Financing Activities:Proceeds from long term borrowings
    
    
    20,000
    
    
    
    18,000Repayments of long term borrowings
    
    
    (77,000
    )
    
    
    (40,000
    )Proceeds from issuance of common stock from exercise of stock options
    
    
    11,629
    
    
    
    220Proceeds from issuance of common stock
    
    
    
    
    
    
    79,200Repurchase of common stock
    
    
    
    
    
    
    (79,200
    )Net cash used in by financing activities
    
    
    (45,371
    )
    
    
    (21,780
    )Increase (decrease) in cash and cash equivalents
    
    
    11,151
    
    
    
    (12,445
    )Cash and cash equivalents, beginning of period
    
    
    2,569
    
    
    
    18,031Cash and cash equivalents, end of period
    
    $
    13,720
    
    
    $
    5,586Supplemental Information:Cash paid for interest
    
    $
    876
    
    
    $
    5,564Cash paid for income taxes
    
    $
    
    
    
    $
    
 The accompanying notes are an integral part of these consolidated financial statements. 6




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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 company engaged in the exploration,
development, exploitation and acquisition of natural gas and oil reserves in
North America. Natural gas is our primary focus. Our 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 Appalachian Basin of West Virginia.
During 2003, we began operations in the Rocky Mountain Region, with an initial
focus in the Uinta Basin of northeastern Utah. We were founded in December 1985 and began exploring for natural gas and oil on
behalf of KeySpan Corporation. KeySpan, a member of the Standard & Poors 500
Index, is a diversified energy provider whose principal natural gas
distribution and electric generation operations are located in the Northeastern
United States. In September 1996 we completed our initial public offering and
sold approximately 31% of our shares to the public. As of March 31, 2004, THEC
Holdings Corp., an indirect wholly owned subsidiary of KeySpan, owned
approximately 55% of the outstanding shares of our common stock or 17.4 million
shares. KeySpan has publicly announced that it considers its investment in
Houston Exploration a non-core asset and that it continues to review strategic
alternatives for its investment in our company including the sale of all or a
portion of its investment in our common stock. Principles of Consolidation The consolidated financial statements include our accounts and the accounts of
our wholly owned subsidiary, Seneca Upshur Petroleum Company, which is in the
exploration and production business in West Virginia. All significant
inter-company balances and transactions have been eliminated. Interim Financial Statements Our balance sheet at March 31, 2004 and the statements of operations and cash
flows for the periods indicated herein have been prepared without audit,
pursuant to the rules and regulations of the Securities and Exchange
Commission. Certain information and footnote disclosures normally included in
financial statements prepared in accordance with accounting principles
generally accepted in the United States (GAAP) have been condensed or
omitted, although we believe that the disclosures contained herein are adequate
to make the information presented not misleading. The balance sheet at
December 31, 2003 is derived from the December 31, 2003 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, 2003. 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 and our full cost ceiling test
limitation. Because there are numerous uncertainties inherent in the estimation process,
actual results could differ materially from these estimates. 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. All of our operations involve the exploration, development
and production of natural gas and oil 7




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited) 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 measure financial performance as a single enterprise and not on
an area-by-area basis. Consequently, while we compile and analyze basic
operational data by area, we do not prepare separate financial statement
information by area and are not, therefore, required to report separate
business segment information under SFAS 131. Revenue Recognition 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 using market prices as of the end of the period. 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 is calculated by applying the treasury stock method to
adjust the average number of common shares outstanding for the dilutive effect,
if any, of the assumed conversion of potentially convertible securities. Three Months EndedMarch 31,2004
    
    2003Numerator:Income before cumulative effect of change
in accounting principle
    
    $
    39,690
    
    
    $
    44,469Cumulative effect of change in accounting principle
    
    
    
    
    
    
    (2,772
    )Net income
    
    $
    39,690
    
    
    $
    41,697Denominator:Weighted average shares outstanding
    
    
    31,598
    
    
    
    30,960Add dilutive securities: Stock options
    
    
    116
    
    
    
    109Total weighted average shares outstanding and
dilutive securities
    
    
    31,714
    
    
    
    31,069Earnings per share  basic:Income before cumulative effect of change in
accounting principle
    
    $
    1.26
    
    
    $
    1.44Cumulative effect of change in accounting principle
    
    
    
    
    
    
    (0.09
    )Net income per share  basic
    
    $
    1.26
    
    
    $
    1.35Earnings per share  fully diluted:Income before cumulative effect of change in
accounting principle
    
    $
    1.25
    
    
    $
    1.43Cumulative effect of change in accounting principle
    
    
    
    
    
    
    (0.09
    )Net income per share  fully diluted
    
    $
    1.25
    
    
    $
    1.34
 For the three months ended March 31, 2004 and 2003, the calculation of
potentially dilutive securities does not include the effect of outstanding
stock options to purchase 1,585,960 and 1,903,561 shares, respectively, as the
assumed conversion of these shares would have been antidulitive. 8




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited) Comprehensive Income The table below summarizes our Comprehensive Income for the three month and
nine month periods ended March 31, 2004 and 2003, respectively. Three Months EndedMarch 31,2004
    
    2003(in thousands)Net income
    
    $
    39,690
    
    
    $
    41,697Other comprehensive income, net of taxes:Unrealized gain (loss) on derivative instruments
    
    
    (28,759
    )
    
    
    (11,572
    )Comprehensive income
    
    $
    10,931
    
    
    $
    30,125
 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; plus,
    
    estimates for future development costs; 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 to hedge against the
volatility of natural gas prices, and in accordance with Securities and
Exchange Commission guidelines, we include estimated future cash flows from our
hedging program in our ceiling test calculation. 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 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 successful wells in-progress and 9




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited) 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 these costs will be
evaluated within a four-year period. Classification of Intangible Leasehold Costs SFAS 141, Business Combinations and SFAS 142, Goodwill and Intangible
Assets, became effective on July 1, 2001 and January 1, 2002, respectively.
These new standards emphasize a more precise evaluation of assets and their
balance sheet classification as either tangible or intangible assets. We
understand that the issue is under evaluation as to whether provisions of SFAS
141 and SFAS 142 may call for mineral rights held under lease or other
contractual arrangements together with cash costs for the acquisition of
natural gas and oil leasehold interests to be classified in the balance sheet
as intangible assets. If these types of leasehold costs (both proved and
unevaluated) are determined to be intangible assets, they would be classified
separately from natural gas and oil properties as intangible assets on our
balance sheets. This issue relates only to balance sheet classification and
presentation and we do not believe it will not have an effect on cash flows or
results of operations. At March 31, 2004, if we applied the interpretation
currently under discussion, undeveloped leasehold costs of $125.4 million and
developed leasehold costs of $207.1 million, net of accumulated amortization,
would be reclassified from tangibles to intangibles, representing costs
incurred since June 30, 2001, the effective date of SFAS 141. At December 31,
2003, we had undeveloped leasehold costs of $117.1 million and developed
leasehold costs of $221.3 million, net of accumulated amortization, that would
be reclassified from tangibles to intangibles. Consistent with current
industry practice, we will continue to classify our natural gas and oil
leasehold costs as tangible natural gas and oil properties until the Emerging
Issues Task Force (EITF) issues further guidance. Although the EITF has not issued formal guidance to oil and gas companies, at
the March 2004 meeting, the EITF reached a consensus that mineral rights for
mining companies should be accounted for as tangible assets. However, the
effective date of that consensus is pending until the resolution of a perceived
inconsistency between the characterization of mineral rights as tangible assets
in this consensus and the characterization of mineral rights as intangible
assets in SFAS 141 and SFAS 142. In order to resolve this inconsistency, FASB
plans to prepare a FASB Staff Position (FSP) that will amend SFAS 141 and SFAS
142. The consensus will be effective when the FSP has been finalized. Asset Retirement Obligations On January 1, 2003, we adopted SFAS 143, Accounting for Asset Retirement
Obligations, which addresses accounting and reporting for obligations
associated with the retirement of tangible long-lived assets and the associated
asset retirement costs. For us, asset retirement obligations represent the
systematic, monthly accretion and depreciation of future abandonment costs of
tangible assets such as platforms, wells, service assets, pipelines, and other
facilities. SFAS 143 requires that the fair value of a liability for an
assets retirement obligation be recorded in the period in which it is incurred
if a reasonable estimate of fair value can be made, and that the corresponding
cost is capitalized as part of the carrying amount of the related long-lived
asset. The liability is accreted to its then present value each period, and the
capitalized cost is depreciated over the useful life of the related asset. If
the liability is settled for an amount other than the recorded amount, a gain
or loss is recognized and an adjustment is made to the full cost pool. Under
our previous accounting method, we included estimated future costs of
abandonment and dismantlement in our full cost amortization base and amortized
these costs as a component of our depletion expense. 10




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited) The following table describes the various components of our asset retirement
liability during each of the three month periods ending March 31, 2004 and
2003, respectively. ARO liability includes amounts classified as both current
and long-term. Three Months Ended March 31,2004
    
    2003ARO liability at January 1,
    
    $
    92,357
    
    
    $
    57,197Additions from drilling
    
    
    1,812
    
    
    
    2,377ARO accretion expense
    
    
    1,288
    
    
    
    826Assets sold
    
    
    (2,928
    )
    
    
    Assets retired and abandoned
    
    
    (3,957
    )
    
    
    ARO liability at March 31,
    
    $
    88,572
    
    
    $
    60,400
 Derivative Instruments and Hedging Activities To reduce our exposure to adverse price fluctuations, we plan to hedge between
70 and 80 percent of our estimated future production volume for 2004 and 2005.
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, as amended, Accounting for Derivative
Instruments and Hedging Activities and, accordingly, we carry the fair market
value of our derivative instruments on the balance sheet as either an asset or
liability and defer unrealized gains or losses in accumulated other
comprehensive income. Gains and losses are reclassified from accumulated other
comprehensive income to the income statement as a component of natural gas and
oil revenues in the period the hedged production occurs. If any
ineffectiveness occurs, amounts are recorded directly to the income statement.
For the first three months of 2004, our net income includes an unrealized loss
of $1.0 million ($0.7 million net of tax) representing the ineffective portion
of our derivative instruments that were not eligible for deferral. The
ineffectiveness was a result of changes at the end of 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, 2004, we recorded an unrealized loss in
other comprehensive income of $83.8 million ($54.2 million net of tax). 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, 2004 were to hold, a loss of $63.5 million ($41.3 million net of tax)
would be realized over the next 12-month period. However, these amounts could
vary materially as a result of changes in market conditions. Accounting for Stock Options 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 now
record as compensation expense the fair value of all stock options issued
subsequent to January 1, 2003. No expense has been or will be recorded for
grants made in previous years. For the three months ended March 31, 2004 and 2003, we recognized gross
compensation expense of $455,000 and $14,000, respectively, for stock
options granted during these periods. 11




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited) Prior to our January 1, 2003 adoption of SFAS 123, we accounted for the
incentive stock plans using the intrinsic value method prescribed under
Accounting Principles Board Opinion No. 25 and accordingly, we did not
recognize compensation expense for stock options granted. Had stock options
been accounted for using the fair value method as recommended in SFAS 123,
compensation expense would have had the following pro forma effect on our net
income and earnings per share for the three month periods ended March 31, 2004
and 2003. Amounts are in thousands except per share data. Three Months EndedMarch 31,2004
    
    2003Net income  as reported
    
    $
    39,690
    
    
    $
    41,697Add: Stock-based compensation expense
included in net income, net of tax
    
    
    230
    
    
    
    23Less: Stock-based compensation expense using
fair value method, net of tax
    
    
    (1,267
    )
    
    
    (1,086
    )Net income  pro forma
    
    $
    38,653
    
    
    $
    40,634Net income per share  as reported
    
    $
    1.26
    
    
    $
    1.35Net income per share  fully diluted  as
reported
    
    
    1.25
    
    
    
    1.34Net income per share  pro forma
    
    $
    1.22
    
    
    $
    1.31Net income per share  fully diluted  pro forma
    
    
    1.21
    
    
    
    1.31
 NOTE 2  Long-Term Debt and Notes March 31, 2004
    
    December 31, 2003(in thousands)Senior Debt:Revolving bank credit facility, due April 1, 2008
    
    $
    70,000
    
    
    $
    127,000Subordinated Debt:7% senior subordinated notes, due June 15, 2013
    
    
    175,000
    
    
    
    175,000Total long-term debt and notes
    
    $
    245,000
    
    
    $
    302,000
 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, 2004, the quoted market value of our $175 million
of 7% senior subordinated notes was 97.7% of the $175 million carrying value or
$170.9 million. Revolving Bank Credit Facility We maintain a revolving bank credit facility with a syndicate of lenders led by
Wachovia Bank, National Association, as issuing bank and administrative agent,
The Bank of Nova Scotia and Fleet National Bank as co-syndication agents and
BNP Paribas and Comerica Bank as co-documentation agents. The credit facility
was amended on April 1, 2004 and, as amended, 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 by adding one or more lenders or by
allowing one or more lenders to increase their commitments. The credit
facility is subject to borrowing base limitations. Pursuant to the April 1,
2004 amendment, our borrowing base was increased from $300 million to $375
million. The $375 million borrowing base is expected to remain in effect until
the next scheduled redetermination on October 1, 2004. Up to $40 million of
the borrowing base is now available for the issuance of letters of credit,
which was increased from $25 million pursuant to the April 1, 2004 amendment.
Outstanding borrowings continue to be unsecured and with the exception of trade
payables, the facility ranks senior in right of payment to our $175 million 7%
subordinated notes. The amended facility matures on April 1, 2008. At March
31, 2003, we had $70 million in outstanding borrowings under the credit
facility and $0.4 million in outstanding letter of credit obligations. Interest rates, margins and terms of payment remained unchanged from prior
periods pursuant to the April 1, 2004 amendment. Interest is payable on
borrowings under our revolving bank credit facility, as follows: 12




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)  
    
    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% 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,
guaranties, liens, leases and certain investments. The credit facility also
restricts and limits our ability to pay cash dividends, to purchase or redeem
our stock and to sell or encumber our assets. Financial covenants require us
to, among other things:  
    
    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 natural gas production during any
12-month period, which was increased, pursuant to the April 1, 2004
amendment, from 80% during 2003 and 2004, and not more than 70% during
any 12-month period after 2004. At March 31, 2004 and December 31, 2003, 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 which 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 subsidiary to make certain distributions or payments; or
    
    guarantees by our subsidiary of certain indebtedness. In addition, upon the occurrence of a change of control, we will be required to
offer to purchase the notes at a purchase price equal to 101% of the aggregate
principal amount, plus accrued and unpaid interest and liquidated damages, if
any. 13




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited) A change of control is:  
    
    the direct or indirect acquisition by any person, other than KeySpan
or its affiliates, of beneficial ownership of 35% or more of total
voting power as long as KeySpan and its affiliates own less than the
acquiring person;
    
    the sale, lease, transfer, conveyance or other disposition, other
than by way of merger or consolidation, in one or a series of related
transactions, of all or substantially all of our assets to a third party
other than KeySpan or its affiliates;
    
    the adoption of a plan relating to our liquidation or dissolution; or
    
    if, during any period of two consecutive years, individuals who at
the beginning of the period constituted our board of directors,
including any new directors who were approved by a majority vote of
directors then in office who were either directors at the beginning of
the two-year period or who were previously so approved, cease for any
reason to constitute a majority of the members then in office. NOTE 3  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. NOTE 4  Related Party Transactions KeySpans Investment in Our Company KeySpan has publicly announced that it considers its investment in Houston
Exploration a non-core asset and that it continues to review strategic
alternatives for its investment in our company including the sale of all or a
portion of its investment in our common stock. At March 31, 2004, KeySpan held
approximately 55% of the common shares outstanding or 17.4 million shares. KeySpan Joint Venture In January 1999, we entered into a joint exploration agreement with KeySpan
Exploration & Production, LLC, a subsidiary of KeySpan, to explore for natural
gas and oil over an initial two-year term expiring December 31, 2000. Under the
terms of the joint venture, we contributed all of our then undeveloped offshore
acreage to the joint venture and we agreed that KeySpan would receive 45% of
our working interest in all prospects drilled under the program. KeySpan paid
100% of actual intangible drilling costs for the joint venture up to a
specified maximum. Further, KeySpan paid 51.75% of all additional intangible
drilling costs incurred and we paid 48.25%. Revenues are shared 55% to Houston
Exploration and 45% to KeySpan. In December 2000, KeySpan and Houston Exploration agreed to end the primary or
exploratory term of the joint venture. As a result, KeySpan has not
participated in any of our offshore exploration prospects unless the project
involved the development or further exploitation of discoveries made during the
initial term of the joint venture. In October 2002, we purchased from KeySpan a portion of the assets developed
under the joint exploration agreement. The acquisition consisted of interests
averaging between 11.25% and 45% in 17 wells covering eight of the twelve
blocks that were developed under the joint exploration agreement from 1999
through 2002. KeySpan retained a 45% interest in four blocks: South Timbalier
314 and 317 and Mustang Island 725 and 726 as these blocks were in various
stages of development at the time of the acquisition. Both Houston Exploration
and KeySpan farmed  out their interest in Mustang Island 725/726 during 2003,
leaving South Timbalier 314 and 317 as the only field in the joint venture. During the first three months of 2004 KeySpan did not incur any capital
expenditures relating to its working interests in properties developed under
the joint venture. During the first three months of 2003 KeySpan spent
approximately $3.0 million in capital costs for remaining assets. 14




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited) NOTE 5  Acquisitions and Dispositions Sale of Onshore South Louisiana Properties On February 4, 2004, we completed the sale of our onshore South Louisiana
producing properties. The sale was effective November 1, 2003 and the
properties represented 12.3 Bcfe proved reserves as of December 31, 2003, and
included interests in 33 gross (9.5 net) producing wells and covered
approximately 6,300 gross (2,300 net) acres. The sale price of $15 million was
reduced by $1.9 million for various customary closing items, including revenues
received by and expenditures made by us related to the properties sold for the
period between the effective date of the transaction and the closing date. The
net proceeds from the sale of $13.1 million were used to repay borrowings under
our revolving bank credit facility. 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-K. 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 at the
beginning of this Quarterly Report and Risk Factors Affecting Our Business
found on page 13 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 company engaged in the exploration,
development, exploitation and acquisition of natural gas and oil reserves in
North America. Natural gas is our primary focus. Our areas of operations are
South Texas, offshore in the shallow waters of the Gulf of Mexico, the Arkoma
Basin of Oklahoma and Arkansas, the Appalachian Basin of West Virginia. During
2003, we began operations in the Rocky Mountain Region, with an initial focus
in the Uinta Basin of northeastern Utah. We operate in one segment as each of
our operating areas has similar economic characteristics and each meets the
criteria for aggregation as defined in SFAS 131. At December 31, 2003, our net proved reserves were 755 billion cubic feet
equivalent or Bcfe, with a present value, discounted at 10% per annum, of cash
flows before income taxes of $2.0 billion. Our reserves are fully engineered on
an annual basis by independent petroleum engineers. Approximately 94% of our
net proved reserves at December 31, 2003 were natural gas, approximately 68% of
which were classified as proved developed. We operate approximately 85% of our
producing wells. At March 31, 2004, KeySpan held approximately 55% of our common stock. KeySpan
has indicated a desire to divest of its investment in our company. KeySpan has
publicly announced it does not consider its investment in Houston Exploration a
part of its core asset group and that it may sell or dispose of all or a
portion of its non-core assets, including its investment in 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. The use of certain types
of derivative instruments may prevent us from realizing the full benefit of
upward price movements. Principal Components of Our Cost Structure:  
    
    Lifting Costs.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.
    
    Depreciation, Depletion and Amortization (DD&A). 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 direct
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 sold through
DD&A expense. Generally, if reserve quantities are revised up or down,
the DD&A rate per unit of production will change inversely. When the
depreciable base increases or decreases, the DD&A rate will move in the
same direction.
    
    Asset Retirement Accretion Expense (ARO).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 (G&A).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 (G&A). We
capitalize G&A directly related to our acquisition, exploration and
development activities. 16




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##### Table of Contents




    
    Interest.We typically finance acquisitions with borrowings under
our revolving bank credit facility, and longer term, with public 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 and certain properties under development, which
are not being amortized.
    
    Income Taxes.We are generally subject to a 35% federal income tax
rate. For income tax purposes, we are allowed deductions for
accelerated depreciation, depletion and intangible drilling costs that
reduce our current tax liability. Prior to 2003, all of our taxes, both
federal and state, were deferred; however, during 2003, we utilized all
of our net operating loss carryforwards and as a result, we recognized
current income tax expense and will continue to recognize current tax
expense as long as we are generating taxable income. Critical Accounting Estimates Proved Reserves. Our most significant financial estimates are based on
estimates of proved natural gas and oil reserves. Estimates of proved reserves
are key components of our unevaluated properties, our rate for recording
depreciation, depletion and amortization, and our full cost ceiling limitation.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future revenues, rates of production and timing of
development expenditures, including many factors beyond our control. The
estimation process relies on assumptions and interpretations of available
geologic, geophysical, engineering and production data and the accuracy of
reserve estimates is a function of the quality and quantity of available data.
Our reserves are fully engineered on an annual basis by independent petroleum
engineers. Asset Retirement Obligation.Asset retirement obligations represent the
estimated future abandonment costs of tangible long-lived assets such as
platforms, wells, service assets, pipelines, and other facilities. We estimate
the fair value of an assets retirement obligation in the period in which the
liability is incurred, if a reasonable estimate can be made. We employ a
present value technique to estimate the fair value of an asset retirement
obligation, which reflects certain assumptions, including an inflation rate,
our credit adjusted risk free interest rate, the estimated settlement date of
the liability and the estimated current cost to settle the liability which we
compute from third party quotes. Changes in timing or to the original estimate
of cash flows will result in changes to the carrying amount of the liability. Derivative Instruments.Under SFAS 133, Accounting for Derivative Instruments
and Hedging Activities, as amended, we reflect the fair market value of our
derivative instruments on our balance sheet. Our estimates of fair value are
determined by obtaining independent market quotes from third parties, as well
as utilizing a Black-Scholes option valuation model that is based upon
underlying forward price curve data, a risk-free interest rate and estimated
volatility factors. Recent Accounting Developments SFAS 141, Business Combinations and SFAS 142, Goodwill and Intangible
Assets, became effective on July 1, 2001 and January 1, 2002, respectively.
These new standards emphasize a more precise evaluation of assets and their
balance sheet classification as either tangible or intangible assets. We
understand that the issue is under evaluation as to whether provisions of SFAS
141 and SFAS 142 may call for mineral rights held under lease or other
contractual arrangements together with cash costs for the acquisition of
natural gas and oil leasehold interests to be classified in the balance sheet
as intangible assets. If these types of leasehold costs (both proved and
unevaluated) are determined to be intangible assets, they would be classified
separately from natural gas and oil properties as intangible assets on our
balance sheets. This issue relates only to balance sheet classification and
presentation and we do not believe it will have an effect on cash flows or
results of operations. At March 31, 2004, if we applied the interpretation
currently under discussion, undeveloped leasehold costs of $125.4 million and
developed leasehold costs of $207.1 million, net of accumulated amortization,
would be reclassified from tangibles to intangibles, representing costs
incurred since June 30, 2001, the effective date of SFAS 141. At December 31,
2003, we had undeveloped leasehold costs of $117.1 million and developed
leasehold costs of $221.3 million, net of accumulated amortization, that would
be reclassified from tangibles to intangibles. Consistent with current
industry practice, we will continue to classify our natural gas and oil
leasehold costs as tangible natural gas and oil properties until the Emerging
Issues Task Force issues further guidance. Although the EITF has not issued formal guidance to oil and gas companies, at
the March 2004 meeting, the EITF reached a consensus that mineral rights for
mining companies should be accounted for as tangible assets. However, the
effective date of that consensus is pending until the resolution of a perceived
inconsistency between the characterization of mineral rights as tangible assets
in this consensus and the characterization of mineral rights as intangible
assets in SFAS 141 and 17




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SFAS 142. In order to resolve this inconsistency, FASB plans to prepare a FASB
Staff Position (FSP) that will amend SFAS 141 and SFAS 142. The consensus will
be effective when the FSP has been finalized. Overview of First Quarter 2004 Results Production growth from Gulf of Mexico properties acquired during the fourth
quarter of 2003 together with newly developed production and strong energy
commodity prices were the primary factors behind results for operations,
earnings and cash flows during the first quarter of 2004. The increase in our
cash flows allowed for increased capital spending for drilling and the
repayment of debt. During the first quarter of 2004:  
    
    We generated $39.7 million in net income, a decrease of 5% from the
first quarter of 2003; however, first quarter 2003 net income of $41.7
million includes other income of $10.6 million ($6.9 million after tax)
relating to recoupment of prior years severance tax expense pursuant to
the receipt of high-cost/tight sand designation for a portion of our
South Texas production and a $2.8 million non-cash after-tax charge for
the cumulative effect of adopting SFAS 143, Accounting for Asset
Retirement Obligations;
    
    We produced a total of 30 Bcfe and increased our average daily
production rate by 15% year-over-year to a record 332 MMcfe, and by 6%
sequentially from of average of 312 MMcfe per day during the fourth
quarter of 2003;
    
    We drilled 50 wells, approximately doubling the number drilled during
the first quarter of 2003, with 46 onshore and 4 offshore, of which 43
were successful, including 5 wells in the Uinta Basin, our new focus
area;
    
    We successfully integrated our fourth quarter 2003 Gulf of Mexico and
West Virginia producing property acquisitions;
    
    We completed the divestiture of our South Louisiana properties,
selling 12.3 Bcfe of net proved reserves for a net $13.1 million in
February 2004;
    
    We generated $131.2 million in net cash flows from operating
activities, invested a net $85.2 million in natural gas and oil
properties and paid down a net $57 million in borrowings under our
revolving bank credit facility; and
    
    We completed the renegotiation of our revolving bank credit facility,
increasing the maximum capacity from $350 million to $450 million,
increasing our borrowing base from $300 million to $375 million, and
extending the maturity from July 2005 to April 2008. These new terms
were effective April 1, 2004. 18




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For the Three Months Ended March 31,Recent Financial and Operating Results
    
    2004
    
    2003
    
    Variance
    
    % changeSummary
operating information (in thousands):Operating revenues
    
    $
    151,882
    
    
    $
    129,003
    
    
    $
    22,879
    
    
    
    18
    %Operating expenses
    
    
    86,839
    
    
    
    68,807
    
    
    
    18,032
    
    
    
    26
    %Income from operations
    
    
    65,043
    
    
    
    60,196
    
    
    
    4,847
    
    
    
    8
    %Net income
    
    $
    39,690
    
    
    $
    41,697
    
    
    $
    (2,007
    )
    
    
    -5
    %Production:Natural gas (MMcf)
    
    
    28,132
    
    
    
    24,385
    
    
    
    3,747
    
    
    
    15
    %Oil (MBbls)
    
    
    348
    
    
    
    257
    
    
    
    91
    
    
    
    35
    %Total (MMcfe) (2)
    
    
    30,220
    
    
    
    25,927
    
    
    
    4,293
    
    
    
    17
    %Average daily production (MMcfe/day)
    
    
    332
    
    
    
    288
    
    
    
    44
    
    
    
    15
    %Average Sales Prices:Natural Gas (per Mcf) realized (1)
    
    $
    4.99
    
    
    $
    4.93
    
    
    $
    0.06
    
    
    
    1
    %Natural Gas (per Mcf) unhedged
    
    
    5.43
    
    
    
    6.36
    
    
    
    (0.93
    )
    
    
    -15
    %Oil (per Bbl) realized (1)
    
    
    32.50
    
    
    
    31.57
    
    
    
    0.93
    
    
    
    3
    %Oil (per Bbl) unhedged
    
    
    32.50
    
    
    
    33.42
    
    
    
    (0.92
    )
    
    
    -3
    %
   (1)
    
    Average realized prices include the effect of hedges.(2)
    
    Mcfe is defined 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. Operating Income A 15% increase in average daily production and the narrowing of our losses from
hedging activities were the primary factors contributing to our 8% increase in
operating income for the first quarter of 2004. The 18% increase in revenues
during the current quarter was offset in part by a 26% increase in operating
expenses due primarily to the continued expansion of our operations combined
with an increase in costs to maintain our existing production base together
with higher depreciation, depletion and amortization rates. Production Volume The 15% increase in average daily production for the current quarter is a
result of production added from our acquisition of Gulf of Mexico properties
during the fourth quarter of 2003 combined with newly developed production
brought online since the end of the first quarter of 2003. Onshore, our daily production rates increased 7% from an average of 173 MMcfe
per day during the first quarter of 2003 to 185 MMcfe per day during the first
quarter of 2004. The increase in onshore production is attributable to newly
developed production in Arkoma as we continue the accelerated development
drilling program initiated in 2003. During 2003, we more than doubled the
number of wells drilled in Arkoma by successfully drilling 46 wells and during
the first quarter of 2004, we drilled and completed 13 successful wells. The
impact of the newly developed production was seen in the fourth quarter of 2003
as our average daily rate in Arkoma increased from 21 MMcfe per day at the
beginning of 2003 to 25 MMcfe per day during the fourth quarter and has
continued to increase to an average of 33 MMcfe per day during the first
quarter of 2004. In South Texas, production has remained flat at 141 MMcfe per
day compared to 142 MMcfe per day during the first quarter of 2003. The
increase in production of approximately 5 MMcfe/day from the additional West
Virginia properties acquired during the fourth quarter of 2003 was offset by
the production lost pursuant to the divesture of our South Louisiana properties
in February 2004. We expect onshore production to remain at current levels
during the second quarter of 2004. Offshore, our production increased 28% from an average of 115 MMcfe per day
during the first quarter of 2003 to an average of 147 MMcfe per day during the
first quarter of 2004. The increase is due primarily to the addition of
approximately 30 MMcfe per day from the properties acquired mid-October 2003
from Transworld Exploration and 19




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##### Table of Contents



Production Inc. In addition to the production acquired, we have added
approximately 10 MMcfe per day from development wells drilled at High Island
A283, one of the fields acquired. Since the end of the first quarter of 2003,
we have added approximately 28 MMcfe per day from new fields and wells at:
High Island 47, High Island 115, Galveston 389/424, Eugene Island 159 and East
Cameron 280. Offsetting production increases were declines from existing and
maturing fields totaling 36 MMcfe per day. For the second quarter of 2004, we
expect offshore production to remain at current levels. Commodity Prices and Effects of Hedging Due to the effects of our hedges, our average realized price for natural gas
for the first quarter of 2004 was relatively unchanged at $4.99 compared to the
$4.93 realized during the first quarter of 2003. However, our average unhedged
or wellhead price for natural gas decreased 15% from $6.36 per Mcf during the
first quarter of 2003 to $5.43 per Mcf during the first quarter 2004. Our realized average natural gas price for first quarter 2004 of $4.99 per Mcf
was 92% or $0.44 per Mcf lower than our average unhedged natural gas price or
wellhead price of $5.43 for the period. Included in natural gas revenues is a
loss of $12.5 million from natural gas hedging activities, which includes an
unrealized loss of $1.0 million representing the ineffective portion of our
derivative instruments that are not eligible for deferral under SFAS 133. For
the corresponding three-month period of 2003, our average realized price of
$4.93 per Mcf was 78% or $1.43 lower than the average unhedged natural gas
price of $6.36 for the period. This resulted in a hedge loss from natural gas
derivatives and reduction to natural gas revenues for first quarter 2003 of
$34.7 million. In addition, during the first quarter of 2003, we incurred a
loss for oil swaps of $0.5 million. Natural Gas and Oil Revenues The 18% increase in operating revenues was due to the narrowing of our loss
from hedging activities from $35.2 million in the first quarter of 2003 to
$12.5 million in the first quarter of 2004 as the increase in revenues
resulting from the 17% increase in production volume during the current quarter
was offset by the decrease in revenues resulting from realized commodity prices
remaining relatively unchanged quarter over quarter. Operating Expenses Our overall operating expenses have increased as we continue to expand our
business and operations. Lease operating expenses have increased as we
continue to add new wells and production facilities while maintaining
production from existing, maturing properties. Our depreciation, depletion and
amortization expense continues to increase as our production increases and as
we experience higher finding costs as well as higher future development costs.
Finally, general and administrative expense continues to increase as we expand
our workforce to keep pace with our expanding operations. Three Months Ended March 31,Operating Expenses per Mcfe:
    
    2004
    
    2003
    
    Variance
    
    % changeLease operating expense
    
    $
    0.42
    
    
    $
    0.45
    
    
    $
    (0.03
    )
    
    
    -7
    %Severance tax
    
    
    0.10
    
    
    
    0.17
    
    
    
    (0.07
    )
    
    
    -41
    %Transportation expense
    
    
    0.09
    
    
    
    0.10
    
    
    
    (0.01
    )
    
    
    -10
    %Asset retirement accretion expense
    
    
    0.04
    
    
    
    0.03
    
    
    
    0.01
    
    
    
    33
    %Depreciation, depletion and amortization
    
    
    2.02
    
    
    
    1.76
    
    
    
    0.26
    
    
    
    15
    %General and administrative, net
    
    
    0.20
    
    
    
    0.15
    
    
    
    0.05
    
    
    
    33
    %Total operating expenses per unit of production
    
    $
    2.87
    
    
    $
    2.66
    
    
    $
    0.21
    
    
    
    8
    %
 Lease Operating Expense. Lease operating expense during the first quarter 2003
includes non-recurring expenses associated with workovers of $1.5 million.
Taking into account these non-recurring expenses, first quarter 2003 lease
operating expense would have been approximately $0.39 compared to $0.42 for
first quarter of 2004. The increase of 8% is due primarily to the acquisition
of the offshore properties in mid-October 2003 from Transworld offset in part
by a 17% increase in production during the first quarter of 2004. The majority
of the Transworld fields were originally developed by major oil and gas
producers and due to their age and complexity, we expected that our lease
operating expenses would be higher than previous levels. For the second
quarter of 2004, we expect lease operating expense to average approximately
$0.52 per Mcfe as we are anticipating increases in expenses for workovers
scheduled during the second quarter of 2004. 20




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##### Table of Contents



Severance Tax. Severance tax is a function of volume and revenues generated
from onshore production. The decrease in severance tax expense and severance
tax per Mcfe for the first quarter of 2004 is due primarily to the effects of
the reduction in expense from the high-cost/tight-sand designation received
for a portion of our South Texas production combined with a 15% decrease in
average wellhead prices for natural gas during first quarter of 2004 and an
increase in onshore production volumes. We expect severance tax to average
approximately $0.12 per Mcfe during the second quarter of 2004. Depreciation, Depletion and Amortization. The increase in our depreciation,
depletion and amortization expense for the current quarter was primarily a
result of a higher depletion rate combined with a 17% increase in production
volumes. The increase in our depletion rate is primarily a result of adding
more costs to our depreciation base with fewer reserve additions. For the
second quarter of 2004, we expect depreciation, depletion and amortization
expense to average approximately $2.03 per Mcfe. Asset Retirement Accretion Expense.The increase in ARO accretion during the
first quarter of 2004 is primarily a result of additions to our ARO liability
during the fourth quarter of 2003 of approximately $29.2 million from the
acquisition of the Gulf of Mexico properties in October and the West Virginia
properties in December offset in part by reductions during the first quarter of
2004 of $3.9 million for offshore properties abandoned and $2.9 million for the
South Louisiana properties sold in February. General and Administrative Expenses, Net of Overhead Reimbursements and
Capitalized General and Administrative Expenses Three Months Ended March 31,General and
Administrative per Mcfe:
    
    2004
    
    2003
    
    Variance
    
    % changeGross general and administrative expense
    
    $
    0.36
    
    
    $
    0.31
    
    
    $
    0.05
    
    
    
    16
    %Operating overhead reimbursements
    
    
    (0.02
    )
    
    
    (0.02
    )
    
    
    
    
    
    
    Capitalized general and administrative expense
    
    
    (0.14
    )
    
    
    (0.14
    )
    
    
    
    
    
    
    General and administrative expense, net
    
    $
    0.20
    
    
    $
    0.15
    
    
    $
    0.05
    
    
    
    33
    %
 The increase in aggregate general and administrative expense is primarily due
to the expansion of our workforce and our office space. We have experienced an
increase in salaries and related employee benefit expenses that include
increases in our incentive compensation expense together with expense for stock
compensation as we adopted the fair value expense provisions for stock options
under SFAS 123, as amended, in January 2003. Our rent expense increased as we
expanded our leased office space in downtown Houston to accommodate our growing
workforce and opened an office in Denver to coordinate our expansion into the
Rocky Mountain region. We expect that as our company continues to grow and
expand, our general and administrative expenses will increase. For the second
quarter of 2004, we estimate that net general and administrative expenses will
average approximately $0.19 per Mcfe. Other Income and Expense, Interest and Taxes Other Income and Expense. During the first quarter of 2003, Other Income and
Expense is comprised of income of $10.6 million ($6.9 million net of tax)
related to the recoupment 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. The
recognition of other income as a result of the recoupment of prior years
expense were 2003 and fourth quarter 2002 events and for 2004, we do not expect
to recognize recoupment of prior years severance tax in excess of $1.0
million. We expect however to see the benefits of the high-cost/tight-gas
designation in the form of reduced severance tax expense for a portion of our
South Texas production during 2004 and in future periods. 21




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##### Table of Contents



Interest Expense, Net of Capitalized Interest. Three Months Ended March 31,Interest Expense and Average Borrowings
    
    2004
    
    2003
    
    Variance
    
    % changeGross interest
    
    $
    4,228
    
    
    $
    3,637
    
    
    $
    591
    
    
    
    16
    %Capitalized interest
    
    
    (1,941
    )
    
    
    (1,371
    )
    
    
    (570
    )
    
    
    42
    %Interest expense, net of amounts capitalized
    
    $
    2,287
    
    
    $
    2,266
    
    
    $
    21
    
    
    
    1
    %Average borrowings
    
    $
    281,400
    
    
    $
    250,100
    
    
    $
    31,300
    
    
    
    13
    %Average interest rate
    
    
    5.53
    %
    
    
    5.44
    %
    
    
    0.09
    %
    
    
    2
    %
 During the first quarter of 2004, gross interest increased as our average
borrowings increased and our average interest rate increased. In June 2003, we
replaced our fixed debt of $100 million at 8-5/8% with new fixed debt of $175
million at 7% and used excess proceeds from the newly issued debt to repay
outstanding borrowings under our revolving bank credit facility which bears
interest at lower rates that averaged 3.30% during both the first quarter of
2004 and 2003. Capitalized interest is a function of unevaluated properties
and the increase corresponds to the increase in our average unevaluated
property balance during the first quarter of 2004. The increase in unevaluated
property is a result of the October 2003 acquisition of Gulf of Mexico
producing properties from Transworld. Income Tax Provision.The 5% decrease in income taxes for the first quarter of
2004 corresponds to the decrease in income before taxes caused by the $10.6
million of other income recognized in the first quarter of 2003 for the
recoupment of prior periods severance tax expense. Our current provision
increased to $8.1 million as we depleted our net operating loss carryforwards
during 2003 and moved to a tax paying status, whereas during the first quarter
of 2003, all federal income taxes were deferred. 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. 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 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. Our capital expenditure budget for 2004 has been set at an initial level of
$315 million. To maintain flexibility of our capital program, we do not enter
into material long-term obligations with any of our drilling contractors or
services providers. We do not include property acquisition costs in our
capital budget because the size and timing of capital requirements for
acquisitions are inherently unpredictable. As the remainder of 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. During the first quarter of 2004, we invested $84.6 million in natural gas and
oil properties and $0.6 million for other property and equipment. Capital
expended for non-natural gas and oil properties includes the improvements to
our Houston office space, upgrades to our information technology systems and
equipment and purchases of vehicles. During the first quarter of 2004, we
spent 28% offshore and 65% onshore with the balance of 7% on capitalized
interest and general and administrative costs. We completed the drilling of 50
gross wells (42.3 net) of which 86% or 43 (36.7 net) were successful and 7 (5.6
net) were unsuccessful, with an additional 10 wells (5.3 net) in progress at
the end of the quarter. The table below details the components of our natural
gas and oil expenditures during each of three month periods ended March 31,
2004 and 2003. 22




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##### Table of Contents



Three Months EndedMarch 31,2004
    
    2003(in thousands)Natural gas and oil capital expendituresProducing property acquisitions
    
    $
    2,700
    
    
    $
    Leasehold and lease acquisition costs(1)
    
    
    13,634
    
    
    
    7,970Development
    
    
    57,536
    
    
    
    33,617Exploration
    
    
    10,768
    
    
    
    11,784Total natural gas and oil capital expenditures
    
    $
    84,638
    
    
    $
    53,371
   (1)
    
    For the first three months of 2004 and 2003 leasehold costs include
capitalized interest and general and administrative expenses of $6.1
million and $5.1 million, respectively. Future Commitments In addition to our capital expenditure program, we are committed to making cash
payments in the future on two types of contracts: note agreements and
operating leases. We do not have off-balance sheet debt or other such
unrecorded obligations, and we have not guaranteed the debt of any other party.
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, 2004. In
addition to the contractual obligations listed on the table below, our balance
sheet at March 31, 2004, reflects accrued interest payable on our revolving
bank credit facility of approximately $20,000, which is payable over the next
90-day period. We expect to make annual interest payments of $12.5 million per
year on our $175 million of 7% senior subordinated notes due June 2013. We
anticipate making income tax payments of approximately $30 million to $40
million in 2004. At March 31, 2004Payments Due by PeriodTotal
    
    1 year or less
    
    2 - 3 years
    
    4 - 5 years
    
    after 5 years(in thousands)Contractual Obligations:Revolving bank credit facility, due April 2008
    
    $
    70,000
    
    
    $
    
    
    
    $
    
    
    
    $
    70,000
    
    
    $
    7% senior subordinated notes, due June 2013
    
    
    175,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    175,000Operating leases
    
    
    8,050
    
    
    
    1,128
    
    
    
    4,422
    
    
    
    2,500
    
    
    
    253,050
    
    
    
    1,128
    
    
    
    4,422
    
    
    
    72,500
    
    
    
    175,000Other Long-Term Obligations:Asset retirement obligations
    
    
    88,572
    
    
    
    3,642
    
    
    
    7,760
    
    
    
    3,953
    
    
    
    73,217Total contractual obligations and commitments
    
    $
    341,622
    
    
    $
    4,770
    
    
    $
    12,182
    
    
    $
    76,453
    
    
    $
    248,217
 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. To the extent we make a significant acquisition, we may also
access public markets for debt. Our primary sources of cash during the first
three months of 2004 were from funds generated from operations. Cash was used
to fund exploration and development expenditures and to reduce debt under our
revolving bank credit facility. We made aggregate cash payments of $0.9
million interest and no cash payments for taxes. The table below summarizes the
sources of cash during each of the three month periods ended March 31, 2004 and
2003. Three Months Ended March 31,2004
    
    2003
    
    variance
    
    % change(in thousands)Net income
    
    $
    39,690
    
    
    $
    41,697
    
    
    $
    (2,007
    )
    
    
    -5
    %Non-cash charges
    
    
    81,313
    
    
    
    73,268
    
    
    
    8,045
    
    
    
    11
    %Cash from operations before changes in operating
assets and liabilities
    
    
    121,003
    
    
    
    114,965
    
    
    
    6,038
    
    
    
    5
    %Decrease (increase) in operating assets and
liabilities
    
    
    10,156
    
    
    
    (51,984
    )
    
    
    62,140
    
    
    
    -120
    %Net cash provided by operating activities
    
    
    131,159
    
    
    
    62,981
    
    
    
    68,178
    
    
    
    108
    %Net cash used for investments in property and equipment
    
    
    74,637
    
    
    
    53,646
    
    
    
    20,991
    
    
    
    39
    %Net cash used in financing activities
    
    
    45,371
    
    
    
    21,780
    
    
    
    23,591
    
    
    
    108
    %Net increase (decrease) in cash
    
    $
    11,151
    
    
    $
    (12,445
    )
    
    $
    23,596
    
    
    
    -190
    %
 At March 31, 2004, we had a working capital deficit of $18.3 million, long-term
debt of $245 million and $229.6 million of borrowing capacity available under
our revolving bank credit facility. The working capital deficit was due to a
current liability of $63.5 million representing the fair value of our
derivative instruments. 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. The increase in net cash provided by operating activities during the first
quarter of 2004 was attributable to the increase in operating income primarily
as a result of the 15% increase in average daily production combined with
changes in operating assets and liabilities. Fluctuations in operating assets
and liabilities are caused by the timing of cash receipts and disbursements.
The net increase in operating assets and liabilities and resulting decrease to
cash flows during the first quarter of 2003 was due primarily to the increase
in receivables during the prior period caused by higher commodity prices. Access to Capital Markets. In March 2004, we filed a shelf registration
statement with the SEC for an initial aggregate public offering price of up to
$600 million covering the sale, from time to time, of our common stock,
preferred stock, depositary shares and debt securities, or a combination of any
of these securities. In addition, the shelf filed in March 2004 registered the
17.4 million shares of our common stock held by KeySpan. 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 2004.
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
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. 24




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##### Table of Contents



Item 3. Quantitative and Qualitative Disclosures About Market Risk Natural Gas and Oil Hedging We utilize derivative commodity instruments to hedge future sales prices on a
portion of our natural gas and oil production to achieve a more predictable
cash flow, as well as to reduce our exposure to adverse price fluctuations of
natural gas. Our derivatives are not held for trading purposes. While the use
of hedging arrangements limits the downside risk of adverse price movements, it
also limits increases in future revenues as a result of favorable price
movements. The use of hedging transactions also involves the risk that the
counterparties are unable to meet the financial terms of such transactions.
Hedging instruments that we use are swaps, collars and options, which we
generally place with major investment grade financial institutions that we
believe are minimal credit risks. 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 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
2004, we recognized $1.0 million of ineffectiveness. The ineffectiveness was 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 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. Change 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,
2004 and 2003 and provides the fair value at the end of each period. Three Months Ended
    
    Three Months EndedMarch 31, 2004
    
    March 31, 2003Before Tax
    
    After Tax
    
    Before Tax
    
    After TaxChange in Fair Value of Derivatives InstrumentsFair value of contracts at January 1
    
    $
    (36,862
    )
    
    $
    (26,128
    )
    
    $
    (38,772
    )
    
    $
    (25,202
    )(Gain) loss on contracts settled and realized
    
    
    12,549
    
    
    
    8,157
    
    
    
    35,167
    
    
    
    22,859Fair value of new contracts when entered into
during period
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (Decrease) in fair value of all open contracts
    
    
    (59,524
    )
    
    
    (36,266
    )
    
    
    (52,971
    )
    
    
    (34,431
    )Fair value of contracts outstanding at March 31
    
    $
    (83,837
    )
    
    $
    (54,237
    )
    
    $
    (56,576
    )
    
    $
    (36,774
    )
 Derivatives in Place as of the Date of Our Report The following table summarizes, on a monthly basis, our natural gas hedges in
place for 2004 and 2005. Subsequent to March 31, 2004, we have not entered
into any new hedge contracts. For each month of 2004, we have hedged
approximately 70% of our estimated production or a total of 240,000 million
British thermal units per day or MMBtu/day. For the remaining nine months of
2004, our floor price will average $4.264/MMBtu on 240,000 MMBtu/day and our
ceiling price will average $5.845/MMBtu on 240,000 MMBtu/day. For each
calendar month of 2005, we have 200,000 MMBtu/day hedged with an effective
floor price of $4.567 and an effective ceiling price of $5.456. All amounts in
the table below are in thousands, except for prices. 25




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##### Table of Contents



Natural Gas Hedges
    
    Fixed Price Swaps
    
    CollarsNYMEX
    
    
    
    
    
    
    
    NYMEXVolume
    
    Contract
    
    Volume
    
    Contract PricePeriod
    
    (MMBtu)
    
    Price
    
    (MMBtu)
    
    Floor
    
    CeilingApril 2004
    
    
    1,200
    
    
    $
    4.960
    
    
    
    6,000
    
    
    $
    4.125
    
    
    $
    6.023May 2004
    
    
    1,240
    
    
    
    4.960
    
    
    
    6,200
    
    
    
    4.125
    
    
    
    6.023June 2004
    
    
    1,200
    
    
    
    4.960
    
    
    
    6,000
    
    
    
    4.125
    
    
    
    6.023July 2004
    
    
    1,240
    
    
    
    4.960
    
    
    
    6,200
    
    
    
    4.125
    
    
    
    6.023August 2004
    
    
    1,240
    
    
    
    4.960
    
    
    
    6,200
    
    
    
    4.125
    
    
    
    6.023September 2004
    
    
    1,200
    
    
    
    4.960
    
    
    
    6,000
    
    
    
    4.125
    
    
    
    6.023October 2004
    
    
    1,240
    
    
    
    4.960
    
    
    
    6,200
    
    
    
    4.125
    
    
    
    6.023November 2004
    
    
    1,200
    
    
    
    4.960
    
    
    
    6,000
    
    
    
    4.125
    
    
    
    6.023December 2004
    
    
    1,240
    
    
    
    4.960
    
    
    
    6,200
    
    
    
    4.125
    
    
    
    6.023January 2005
    
    
    1,550
    
    
    
    4.766
    
    
    
    4,650
    
    
    
    4.500
    
    
    
    5.685February 2005
    
    
    1,450
    
    
    
    4.766
    
    
    
    4,200
    
    
    
    4.500
    
    
    
    5.685March 2005
    
    
    1,550
    
    
    
    4.766
    
    
    
    4,650
    
    
    
    4.500
    
    
    
    5.685April 2005
    
    
    1,500
    
    
    
    4.766
    
    
    
    4,500
    
    
    
    4.500
    
    
    
    5.685May 2005
    
    
    1,550
    
    
    
    4.766
    
    
    
    4,650
    
    
    
    4.500
    
    
    
    5.685June 2005
    
    
    1,500
    
    
    
    4.766
    
    
    
    4,500
    
    
    
    4.500
    
    
    
    5.685July 2005
    
    
    1,550
    
    
    
    4.766
    
    
    
    4,650
    
    
    
    4.500
    
    
    
    5.685August 2005
    
    
    1,550
    
    
    
    4.766
    
    
    
    4,650
    
    
    
    4.500
    
    
    
    5.685September 2005
    
    
    1,500
    
    
    
    4.766
    
    
    
    4,500
    
    
    
    4.500
    
    
    
    5.685October 2005
    
    
    1,550
    
    
    
    4.766
    
    
    
    4,650
    
    
    
    4.500
    
    
    
    5.685November 2005
    
    
    1,500
    
    
    
    4.766
    
    
    
    4,500
    
    
    
    4.500
    
    
    
    5.685December 2005
    
    
    1,550
    
    
    
    4.766
    
    
    
    4,650
    
    
    
    4.500
    
    
    
    5.685
 For natural gas, transactions are settled based upon the NYMEX price on the
final trading day of the month. For oil, our swaps are settled against the
average NYMEX price of oil for the calendar month rather than the last day of
the month. In order to determine fair market value of our derivative
instruments, we obtain mark-to-market quotes from external counterparties. With respect to any particular swap transaction, the counterparty is required
to make a payment to us if the settlement price for any settlement period is
less than the swap price for the transaction, and we are required to make
payment to the counterparty if the settlement price for any settlement period
is greater than the swap price for the transaction. For any particular collar
transaction, the counterparty is required to make a payment to us if the
settlement price for any settlement period is below the floor price for the
transaction, and we are required to make payment to the counterparty if the
settlement price for any settlement period is above the ceiling price for the
transaction. We are not required to make or receive any payment in connection
with a collar transaction if the settlement price is between the floor and the
ceiling. For option contracts, we have the option, but not the obligation, to
buy contracts at the strike price up to the day before the last trading day for
that NYMEX contract. 
 Item 4. Controls and Procedures We maintain disclosure controls and procedures that are designed to ensure that
information required to be disclosed by us in the reports we file under the
Securities Exchange Act of 1934, as amended (Exchange Act) is communicated,
processed, summarized and reported within the time periods specified in the
Securities and Exchange Commissions rules and forms. We carried out an
evaluation under the supervision and with the participation of our management,
including our principal executive officer and principal financial officer, of
the effectiveness of our disclosure controls and procedures (as defined in Rule
13a-14 of the Exchange Act), as of the end of the period covered by this
report. Based on that evaluation, 26




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our principal executive officer and principal financial officer concluded that,
as of March 31, 2004, our disclosure controls and procedures are functioning
effectively as designed. There have been no changes in our internal control
over financial reporting that occurred during the most recent fiscal quarter
prior to the end of the period covered by this report that have materially
affected, or are reasonably likely to materially affect, our internal controls
over financial reporting. Part II. Other Information. 
 Item 6. Exhibits and Reports on Form 8-K: 
  (a)
    
    Exhibits: Exhibits
    
    
    
    Description10.1
    
    
    
    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.12.1
    
    
    
    Statement of computation of ratio of earnings to fixed charges.31.1
    
    
    
    Certification of William G. Hargett, Chief Executive Officer,
as required pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.31.2
    
    
    
    Certification of John H. Karnes, Senior Vice President and
Chief Financial Officer, as required pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.32.1
    
    
    
    Certification of William G. Hargett, Chief Executive Officer,
as required pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.32.2
    
    
    
    Certification of John H. Karnes, Senior Vice President and
Chief Financial Officer, as required pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
 
  (b)
    
    Reports on Form 8-K:Current Report on Form 8-K filed on February 5, 2004 to furnish under Item 12 -
Results of Operations and Financial Conditions our earnings release for the
three month and twelve month periods ending December 31, 2003.Current Report on Form 8-K filed on April 30, 2004 to furnish under Item 12 -
Results of Operations and Financial Conditions our earnings release for the
quarterly period ending March 31, 2004. 27




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##### Table of Contents



SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned, hereunto duly authorized. THE HOUSTON EXPLORATION COMPANYBy:
    
    /s/ William G. HargettDate: May 6, 2004
    
    
    
    William G. HargettPresident and Chief Executive OfficerBy:
    
    /s/ John H. KarnesDate: May 6, 2004
    
    
    
    John H. KarnesSenior Vice President and Chief Financial OfficerBy:
    
    /s/ James F. WestmorelandDate: May 6, 2004
    
    
    
    James F. WestmorelandVice President and Chief Accounting Officer
 28




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##### Table of Contents



EXHIBIT INDEX Exhibits
    
    
    
    Description10.1
    
    
    
    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.12.1
    
    
    
    Statement of computation of ratio of earnings to fixed charges.31.1
    
    
    
    Certification of William G. Hargett, Chief Executive Officer,
as required pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.31.2
    
    
    
    Certification of John H. Karnes, Senior Vice President and
Chief Financial Officer, as required pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.32.1
    
    
    
    Certification of William G. Hargett, Chief Executive Officer,
as required pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.32.2
    
    
    
    Certification of John H. Karnes, Senior Vice President and
Chief Financial Officer, as required pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
  (b)
    
    Reports on Form 8-K:Current Report on Form 8-K filed on February 5, 2004 to furnish under Item 12 -
Results of Operations and Financial Conditions our earnings release for the
three month and twelve month periods ending December 31, 2003.Current Report on Form 8-K filed on April 30, 2004 to furnish under Item 12 -
Results of Operations and Financial Conditions our earnings release for the
quarterly period ending March 31, 2004.