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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 June 30, 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
    
    22-2674487incorporation or organization)
    
    (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 August 6, 2004, 28,059,784 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  June 30, 2004 and December 31, 2003 (unaudited)
    
    
    4Consolidated Statements of Operations  Three Month and Six Month Periods Ended June 30, 2004 and 2003 (unaudited)
    
    
    5Consolidated Statements of Cash Flows  Six Months Ended June 30, 2004 and 2003 (unaudited)
    
    
    6Notes to 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
    
    
    26Part II. Other Information
    
    
    27Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities
    
    
    27Item 4. Submission of Matters to a Vote of Security Holders
    
    
    27Item 6. Exhibits and Reports on Form 8-K
    
    
    28(A) Exhibits
    
    
    28(B) Reports on Form 8-K
    
    
    29Signatures
    
    
    301st Amend. to the Amended Credit AgreementStatement of computation of ratio of earnings to fixed chargesCertification of CEO pursuant to Section 302Certification of CFO pursuant to Section 302Certification of CEO pursuant to Section 906Certification of 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 1933,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, intend, 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 cannot 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 reserves have relatively short production lives;
    
    our ability to find, develop and acquire natural gas and oil reserves;
    
    the success 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,
    
    influence by our significant shareholder, 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 onForm 10-Kfor the year ended December 31,
2003. 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
through May 31, 2004, our subsidiary on a consolidated basis. Unless otherwise
stated, all reserve and production quantities are expressed net to our
interests. 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)
 June 30,
    
    December 31,2004
    
    2003Assets:Cash and cash equivalents
    
    $
    15,109
    
    
    $
    2,569Accounts receivable
    
    
    113,436
    
    
    
    87,949Accounts receivable  Affiliate
    
    
    5,763
    
    
    
    6,733Derivative financial instruments
    
    
    
    
    
    
    3,458Inventories
    
    
    1,117
    
    
    
    1,071Deferred tax asset
    
    
    26,408
    
    
    
    19,644Prepayments and other
    
    
    2,925
    
    
    
    5,818Total current assets
    
    
    164,758
    
    
    
    127,242Natural gas and oil properties, full cost methodUnevaluated properties
    
    
    136,699
    
    
    
    134,491Properties subject to amortization
    
    
    2,403,135
    
    
    
    2,324,011Other property and equipment
    
    
    10,898
    
    
    
    12,6172,550,732
    
    
    
    2,471,119Less: Accumulated depreciation, depletion and amortization
    
    
    1,226,281
    
    
    
    1,099,9901,324,451
    
    
    
    1,371,129Other non-current assets
    
    
    14,831
    
    
    
    10,694Total Assets
    
    $
    1,504,040
    
    
    $
    1,509,065Liabilities:Accounts payable and accrued expenses
    
    $
    100,706
    
    
    $
    83,983Derivative financial instruments
    
    
    75,450
    
    
    
    35,592Asset retirement obligations
    
    
    3,628
    
    
    
    7,703Total current liabilities
    
    
    179,784
    
    
    
    127,278Long-term debt and notes
    
    
    285,000
    
    
    
    302,000Derivative financial instruments
    
    
    30,938
    
    
    
    4,728Deferred federal income taxes
    
    
    259,343
    
    
    
    251,425Asset retirement obligations
    
    
    77,817
    
    
    
    84,654Other deferred liabilities
    
    
    10,555
    
    
    
    3,446Total Liabilities
    
    
    843,437
    
    
    
    773,531Commitments and Contingencies (see Note 3)Stockholders Equity:Common Stock, $.01 par value, 50,000,000 shares authorized and
28,033,116
shares issued and outstanding at June 30, 2004, and 31,437,581 shares
issued and outstanding at December 31, 2003, respectively
    
    
    280
    
    
    
    315Additional paid-in capital
    
    
    248,182
    
    
    
    366,781Unearned compensation
    
    
    (383
    )
    
    
    (808
    )Retained earnings
    
    
    480,414
    
    
    
    395,374Accumulated other comprehensive income
    
    
    (67,890
    )
    
    
    (26,128
    )Total Stockholders Equity
    
    
    660,603
    
    
    
    735,534Total Liabilities and Stockholders Equity
    
    $
    1,504,040
    
    
    $
    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 Ended
    
    Six Months EndedJune 30,
    
    June 30,2004
    
    2003
    
    2004
    
    2003(unaudited)
    
    (unaudited)Revenues:Natural gas and oil revenues
    
    $
    172,578
    
    
    $
    120,388
    
    
    $
    324,212
    
    
    $
    248,786Other
    
    
    198
    
    
    
    244
    
    
    
    446
    
    
    
    849Total revenues
    
    
    172,776
    
    
    
    120,632
    
    
    
    324,658
    
    
    
    249,635Operating expenses:Lease operating
    
    
    12,499
    
    
    
    11,669
    
    
    
    25,205
    
    
    
    23,315Severance tax
    
    
    3,891
    
    
    
    3,222
    
    
    
    6,948
    
    
    
    7,527Transportation expense
    
    
    3,169
    
    
    
    2,696
    
    
    
    5,905
    
    
    
    5,188Asset retirement accretion expense
    
    
    1,190
    
    
    
    826
    
    
    
    2,478
    
    
    
    1,652Depreciation, depletion and amortization
    
    
    67,192
    
    
    
    47,724
    
    
    
    128,156
    
    
    
    93,378General and administrative, net
    
    
    9,761
    
    
    
    4,204
    
    
    
    15,849
    
    
    
    8,088Total operating expenses
    
    
    97,702
    
    
    
    70,341
    
    
    
    184,541
    
    
    
    139,148Income from operations
    
    
    75,074
    
    
    
    50,291
    
    
    
    140,117
    
    
    
    110,487Other (income) expense
    
    
    (378
    )
    
    
    3,616
    
    
    
    (268
    )
    
    
    (6,962
    )Interest expense, net
    
    
    2,306
    
    
    
    2,160
    
    
    
    4,593
    
    
    
    4,426Income before income taxes
    
    
    73,146
    
    
    
    44,515
    
    
    
    135,792
    
    
    
    113,023Provision for taxes
    
    
    27,796
    
    
    
    15,592
    
    
    
    50,752
    
    
    
    39,631Income before cumulative effect of change in
accounting principle
    
    
    45,350
    
    
    
    28,923
    
    
    
    85,040
    
    
    
    73,392Cumulative effect of change in accounting principle
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2,772
    )Net income
    
    $
    45,350
    
    
    $
    28,923
    
    
    $
    85,040
    
    
    $
    70,620Earnings per share:Net income per share  basicIncome before cumulative effect of change in
accounting principle
    
    $
    1.49
    
    
    $
    0.93
    
    
    $
    2.74
    
    
    $
    2.37Cumulative effect of change in accounting
principle
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (0.09
    )Net income per share  basic
    
    $
    1.49
    
    
    $
    0.93
    
    
    $
    2.74
    
    
    $
    2.28Net income per share  fully dilutedIncome before cumulative effect of change in
accounting principle
    
    $
    1.47
    
    
    $
    0.93
    
    
    $
    2.72
    
    
    $
    2.36Cumulative effect of change in accounting
principle
    
    
    
    
    

    
    
    
    
    
    
    
    
    
    (0.09
    )Net income per share  fully diluted
    
    $
    1.47
    
    
    $
    0.93
    
    
    $
    2.72
    
    
    $
    2.27Weighted average shares outstanding  basic
    
    
    30,547
    
    
    
    30,987
    
    
    
    31,072
    
    
    
    30,974Weighted average shares outstanding  fully diluted
    
    
    30,810
    
    
    
    31,095
    
    
    
    31,262
    
    
    
    31,082
 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)
 Six Months Ended June 30,2004
    
    2003(unaudited)Operating Activities:Net income
    
    $
    85,040
    
    
    $
    70,620Adjustments to reconcile net income to net cash provided by
operating activities:Depreciation, depletion and amortization
    
    
    128,156
    
    
    
    93,378Deferred income tax expense
    
    
    26,061
    
    
    
    39,573Asset retirement accretion expense
    
    
    2,478
    
    
    
    1,652Ineffectiveness of derivative instruments
    
    
    1,700
    
    
    
    Amortization of premium on derivative instruments
    
    
    3,576
    
    
    
    Stock compensation expense
    
    
    1,329
    
    
    
    101Debt extinguishment
    
    
    211
    
    
    
    1,626Cumulative effect of change in accounting principle
    
    
    
    
    
    
    2,772Changes in operating assets and liabilities:Increase in accounts receivable
    
    
    (24,517
    )
    
    
    (34,163
    )Increase in inventories
    
    
    (46
    )
    
    
    (115
    )Decrease in prepayments and other
    
    
    2,893
    
    
    
    7,308Increase in other assets
    
    
    (2,794
    )
    
    
    (12,398
    )Increase in accounts payable and accrued expenses
    
    
    16,723
    
    
    
    13,910Increase in other deferred liabilities
    
    
    7,109
    
    
    
    1,348Net cash provided by operating activities
    
    
    247,919
    
    
    
    185,612Investing Activities:Investment in property and equipment
    
    
    (165,436
    )
    
    
    (138,348
    )Assets retired and abandoned
    
    
    (2,569
    )
    
    
    Proceeds from dispositions
    
    
    73,138
    
    
    
    Net cash used in investing activities
    
    
    (94,867
    )
    
    
    (138,348
    )Financing Activities:Proceeds from long-term borrowings
    
    
    184,000
    
    
    
    228,000Repayments of long-term borrowings
    
    
    (201,000
    )
    
    
    (185,000
    )Debt issue costs
    
    
    (1,555
    )
    
    
    (4,108
    )Proceeds from issuance of common stock from exercise of stock options
    
    
    16,455
    
    
    
    2,460Proceeds from issuance of common stock
    
    
    310,567
    
    
    
    79,200Exchange of common stock
    
    
    (448,979
    )
    
    
    Repurchase of common stock
    
    
    
    
    
    
    (79,200
    )Net cash (used in) provided by financing activities
    
    
    (140,512
    )
    
    
    41,352Increase in cash and cash equivalents
    
    
    12,540
    
    
    
    88,616Cash and cash equivalents, beginning of period
    
    
    2,569
    
    
    
    18,031Cash and cash equivalents, end of period
    
    $
    15,109
    
    
    $
    106,647Supplemental Information:Cash paid for interest
    
    $
    7,817
    
    
    $
    6,439Cash paid for income taxes
    
    $
    16,900
    
    
    $
    10,900
 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 primary areas of
operations are South Texas, offshore in the shallow waters of the Gulf of
Mexico and the Arkoma Basin of Oklahoma and Arkansas. During 2003, we began
operations in the Rocky Mountain region, with an initial focus in the Uinta
Basin of Northeastern Utah. We divested our Appalachian Basin assets on June
2, 2004 in connection with the KeySpan Exchange transaction described below. We were founded by KeySpan Corporation in December 1985 and completed an
initial public offering in 1996. KeySpan is a diversified energy provider
whose principal natural gas distribution and electric generation operations are
located in the Northeastern United States. As a result of an asset exchange
transaction with KeySpan completed on June 2, 2004 and described below,
KeySpans ownership in the outstanding shares of our common stock was reduced
from approximately 54% to 24%. KeySpan Exchange and Offering On June 2, 2004, we completed an asset exchange transaction with KeySpan
pursuant to which we redeemed and cancelled 10,800,000 shares of our common
stock owned by KeySpan in exchange for all the stock of Seneca-Upshur
Petroleum, Inc., our wholly-owned subsidiary, to which we contributed all of
our Appalachian Basin assets valued at $60 million and $389 million in cash for
a total exchange value of $449 million. This transaction is referred to as the
KeySpan Exchange. The KeySpan Exchange is intended to qualify as a tax-free
exchange under Section 355(a) of the Internal Revenue Code. To fund the cash portion of the exchange, on June 2, 2004, we sold 6,200,000
shares of our common stock in a registered public offering at $48.00 per share,
the (Offering) and contributed to Seneca-Upshur substantially all of the net
proceeds from the Offering of $282 million together with an additional $107
million of proceeds from bank borrowings. We then conveyed to KeySpan all of
the shares of Seneca-Upshur in exchange for 10,800,000 shares of our common
stock. On June 23, 2004, the underwriters of our Offering exercised a portion of their
over-allotment option and we sold an additional 620,000 shares of common stock
at $48.00 per share for net proceeds of $28.6 million. The proceeds from the
over-allotment were used to reduce bank borrowings. The net effect of our redemption and cancellation of the 10,800,000 shares
received from KeySpan and our issuance of 6,820,000 new shares resulted in a net 3,980,000 decrease in the outstanding shares of our common
stock, and thereby reduced KeySpans ownership from approximately 54% to 24%.
As a result of the KeySpan Exchange and Offering, our bank borrowings increased
by a net $79 million and we incurred approximately $5.1 million in compensation
and other expenses related to special bonuses awarded to executives and key
employees who assisted in structuring and consummating the transactions.
Finally, KeySpan agreed to reduce its representation on our Board of Directors
from five to two directors and our Chief Executive Officer, William G. Hargett, was
elected Chairman of the Board replacing Robert B. Catell, Chairman and Chief
Executive Officer of KeySpan, who remains on the Board as one of KeySpans
representatives. Principles of Consolidation On June 2, 2004, all of the shares of our wholly-owned subsidiary,
Seneca-Upshur were conveyed to KeySpan in connection with the KeySpan Exchange.
Subsequent to the transaction, Seneca-Upshur was no longer a subsidiary of
Houston Exploration but is a wholly-owned subsidiary of KeySpan, and as a
result, our financial statements reflect the consolidated results of
Seneca-Upshur through May 31, 2004. Seneca-Upshur was our only subsidiary and
prior to the KeySpan Exchange, our consolidated financial statements included
our accounts and the accounts of Seneca-Upshur. All significant inter-company
balances and transactions were eliminated. Seneca-Upshur is in the exploration and production business in West Virginia
with interests in Appalachian Basin assets. Because we account for our natural
gas and oil assets under the full cost method of accounting, the disposition of
our Appalachian Basin assets, which represented only a portion of our full cost
pool, is not considered discontinued operations under SFAS 144. 7




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited) Interim Financial Statements Our balance sheet at June 30, 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
(SEC). Certain information and footnote disclosures normally included in
financial statements prepared in accordance with accounting principles
generally accepted in the United States (GAAP) have been condensed or
omitted, although we believe that the disclosures contained herein are adequate
to make the information presented not misleading. 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 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. 8




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited) 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 Ended
    
    Six Months EndedJune 30,
    
    June 30,2004
    
    2003
    
    2004
    
    2003(in thousands, except per share data)Numerator:Income before cumulative effect of change
in accounting principle
    
    $
    45,350
    
    
    $
    28,923
    
    
    $
    85,040
    
    
    $
    73,392Cumulative effect of change in accounting principle
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2,772
    )Net income
    
    $
    45,350
    
    
    $
    28,923
    
    
    $
    85,040
    
    
    $
    70,620Denominator:Weighted average shares outstanding
    
    
    30,547
    
    
    
    30,987
    
    
    
    31,072
    
    
    
    30,974Add dilutive securities: Stock options
    
    
    263
    
    
    
    108
    
    
    
    190
    
    
    
    108Total weighted average shares outstanding and
dilutive securities
    
    
    30,810
    
    
    
    31,095
    
    
    
    31,262
    
    
    
    31,082Earnings per share  basic:Income before cumulative effect of change in
accounting principle
    
    $
    1.49
    
    
    $
    0.93
    
    
    $
    2.74
    
    
    $
    2.37Cumulative effect of change in accounting principle
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (0.09
    )Net income per share  basic
    
    $
    1.49
    
    
    $
    0.93
    
    
    $
    2.74
    
    
    $
    2.28Earnings per share  fully diluted:Income before cumulative effect of change in
accounting principle
    
    $
    1.47
    
    
    $
    0.93
    
    
    $
    2.72
    
    
    $
    2.36Cumulative effect of change in accounting principle
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (0.09
    )Net income per share  fully diluted
    
    $
    1.47
    
    
    $
    0.93
    
    
    $
    2.72
    
    
    $
    2.27
 The calculation of shares outstanding for fully diluted EPS does not include the
effect of outstanding stock options to purchase 739,444 and 1,893,611 shares
for the three months ended June 30, 2004 and 2003, respectively, and 1,156,348
and 1,898,559 shares for the six months ended June 30, 2004 and 2003,
respectively, because to include would have an antidilutive effect on earnings
per share. Comprehensive Income The table below summarizes our Comprehensive Income for the three-month and
six-month periods ended June 30, 2004 and 2003, respectively. Three Months Ended
    
    Six Months EndedJune 30,

    
    June 30,2004
    
    2003
    
    2004
    
    2003(in thousands)Net income
    
    $
    45,350
    
    
    $
    28,923
    
    
    $
    85,040
    
    
    $
    70,620Other comprehensive income, net of taxes:Unrealized gain (loss) on derivative instruments
    
    
    (13,653
    )
    
    
    (841
    )
    
    
    (41,762
    )
    
    
    (12,413
    )Comprehensive income
    
    $
    31,697
    
    
    $
    28,082
    
    
    $
    43,278
    
    
    $
    58,207
 9




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited) 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 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 believe that substantially all of the costs included in our unevaluated
property balance will be evaluated in the next four years. 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 sheet. This issue 10




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited) relates only to balance sheet classification and presentation and we do not
believe it will not have an affect on cash flows or results of operations. At
June 30, 2004, if we applied the interpretation currently under discussion,
undeveloped leasehold costs of $132.5 million and developed leasehold costs of
$148.6 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
is in the process of finalizing a FASB Staff Position (SFAS 142-b) that will
amend SFAS 141 and SFAS 142. The consensus will be effective when SFAS 142  b
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 (ARO) 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. The following table describes the various components of our asset retirement
liability during each of the six month periods ending June 30, 2004 and 2003,
respectively. ARO liability includes amounts classified as both current and
long-term. Six Months Ended June 30,2004
    
    2003(in thousands)ARO liability at January 1
    
    $
    92,357
    
    
    $
    57,197Additions from drilling
    
    
    3,281
    
    
    
    2,962ARO accretion expense
    
    
    2,478
    
    
    
    1,652Assets sold
    
    
    (12,714
    )
    
    
    Assets retired and abandoned
    
    
    (3,957
    )
    
    
    ARO liability at June 30
    
    $
    81,445
    
    
    $
    61,811
 Derivative Instruments and Hedging Activities Our hedging policy does not permit us to hold derivative instruments for
trading purposes. In our hedging program, we utilize a variety of derivative
instruments, including swaps, collars and options. We generally place
contracts with major financial institutions and other credit-worthy
counterparties. Although our hedging program protects a portion of our cash
flows from downward price movements, certain hedging strategies, specifically
the use of swaps and collars, may also limit our ability to realize the full
benefit of future price increases. In addition, because our derivative
instruments are typically indexed to New York Mercantile Exchange (NYMEX)
prices as opposed to the index price where the gas is actually sold, our
hedging strategy may not protect our cash flows if the price differential
increases between the NYMEX price and index price for the point of sale. Our derivative instruments are designated cash flow hedges and qualify for
hedge accounting under SFAS 133, as amended, Accounting for Derivative
Instruments and Hedging Activities and, accordingly, we carry the fair market
value 11




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited) 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 six months of 2004, our net income includes an unrealized loss of
$1.7 million ($1.1 million net of tax), of which $0.7 million ($.5 million net
of tax) was incurred during the second quarter of 2004, which represents the
ineffective portion of our derivative instruments that were not eligible for
deferral. 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 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 June 30, 2004, we recorded an unrealized loss in
Accumulated Other Comprehensive Income of $67.9 million, net of tax. Any loss
will realized in future earnings at the time of the related sales of natural
gas production applicable to specific hedges. However, these amounts could
vary materially as a result of changes in market conditions. Accounting for Stock Options and Restricted Stock Effective 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 June 30, 2004 and 2003, we recognized gross
compensation expense of $449,000 and $45,000, respectively, for stock options
granted during these periods together with $363,000 and $21,000, respectively,
for compensation expense relating to restricted stock. For the corresponding
six-month periods ended June 30, 2004 and 2003, gross compensation expense for
stock options was $904,000 and $59,000, respectively, and $425,000 and $21,000,
respectively, for restricted stock. 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 and six-month periods ended
June 30, 2004 and 2003. Amounts are in thousands, except per share data. Three Months Ended
    
    Six Months EndedJune 30,
    
    June 30,2004
    
    2003
    
    2004
    
    2003(in thousands except per share data)Net income  as reported
    
    $
    45,350
    
    
    $
    28,923
    
    
    $
    85,040
    
    
    $
    70,620Add: Stock-based compensation expense
included in net income, net of tax
    
    
    424
    
    
    
    43
    
    
    
    655
    
    
    
    66Less: Stock-based compensation expense using
fair value method, net of tax
    
    
    (1,466
    )
    
    
    (1,102
    )
    
    
    (2,733
    )
    
    
    (2,189
    )Net income  pro forma
    
    $
    44,308
    
    
    $
    27,864
    
    
    $
    82,962
    
    
    $
    68,497Net income per share  as reported
    
    $
    1.49
    
    
    $
    0.93
    
    
    $
    2.74
    
    
    $
    2.28Net income per share  fully diluted  as
reported
    
    
    1.47
    
    
    
    0.93
    
    
    
    2.72
    
    
    
    2.27Net income per share  pro forma
    
    $
    1.45
    
    
    $
    0.90
    
    
    $
    2.67
    
    
    $
    2.21Net income per share  fully diluted  pro forma
    
    
    1.44
    
    
    
    0.90
    
    
    
    2.66
    
    
    
    2.20
 12




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited) NOTE 2  Long-Term Debt and Notes June 30, 2004
    
    December 31, 2003(in thousands)Senior Debt:Revolving bank credit facility, due April 1, 2008
    
    $
    110,000
    
    
    $
    127,000Subordinated Debt:7% senior subordinated notes, due June 15, 2013
    
    
    175,000
    
    
    
    175,000Total long-term debt and notes
    
    $
    285,000
    
    
    $
    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 June 30, 2004, the quoted market value of our $175 million of
7% senior subordinated notes was 96.3% of the $175 million carrying value or
$168.5 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 and restated on April 1, 2004, primarily to increase the size of
the facility and was then amended again on June 2, 2004, in conjunction with
the KeySpan Exchange. As amended, the facility provides us with a commitment
of $400 million which may be increased at our request and with prior approval
from Wachovia to a maximum of $450 million. Amounts available for borrowing
under the credit facility are limited to a borrowing base. On April 1, 2004,
our borrowing base was increased from $300 million to $375 million, and on June
2, 2004, was reduced from $375 million to $340 million as a result of the
disposition of our Appalachian Basin assets. Pursuant to the reduction in our
borrowing base, we incurred $0.2 million debt extinguishment expenses during
the second quarter of 2004 relating to the write-off of a portion of our debt
issue costs. The $0.2 million is included in the line item Other (income)
expense on our Statement of Operations. The $340 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 available for the
issuance of letters of credit. Outstanding borrowings are unsecured and rank
senior in right of payment to our $175 million 7% subordinated notes. The
amended facility matures on April 1, 2008. At June 30, 2004, we had $110
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:  
    
    on base rate loans, at a fluctuating rate, or base rate, equal to the
sum of (a) the greater of the Federal funds rate plus 0.5% or Wachovias
prime rate plus (b) a variable margin between 0.00% and 0.50%, depending
on the amount of borrowings outstanding under the credit facility, or
    
    on fixed rate loans, a fixed rate equal to the sum of (a) a quoted
LIBOR rate divided by one minus the average maximum rate during the
interest period set for certain reserves of member banks of the Federal
Reserve System in Dallas, Texas, plus (b) a variable margin between
1.25% and 2.00%, depending on the amount of borrowings outstanding under
the credit facility. Interest is payable on base-rate loans on the last day of each calendar
quarter. Interest on fixed-rate loans is generally payable at maturity or at
least every 90 days if the term of the loan exceeds three months. In addition
to interest, we must pay a quarterly commitment fee of between 0.30% and 0.50%
per annum on the unused portion of the borrowing base. Our revolving bank credit facility contains customary negative covenants that
place restrictions and limits on, among other things, the incurrence of debt,
guarantees, liens, leases and certain investments. 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 13




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)  
    
    not hedge more than 85% of our production during any calendar year
(which was increased, pursuant to the April 1, 2004, amendment, from 80%
during each of the twelve-month periods of 2003 and 2004, and not more
than 70% during any 12-month period after 2004.) At June 30, 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 that decreases
yearly from 3.5% in 2008 to 0% in 2011 and thereafter. In addition, at any
time prior to June 15, 2006, we may redeem up to a maximum of 35% of the
aggregate principal amount with the net proceeds of one or more equity
offerings at a price equal to 107% of the principal amount, plus accrued and
unpaid interest and liquidated damages, if any. The notes are general
unsecured obligations and rank subordinate in right of payment to all existing
and future senior debt, including the revolving bank credit facility, and will
rank senior or equal in right of payment to all existing and future
subordinated indebtedness. The indenture governing the notes contains covenants that, among other things,
restrict or limit:  
    
    incurrence of additional indebtedness and issuance of preferred stock;
    
    repayment of certain other indebtedness;
    
    payment of dividends or certain other distributions;
    
    investments and repurchases of equity;
    
    use of the proceeds of assets sales;
    
    transactions with affiliates;
    
    creation, incurrence or assumption of liens;
    
    merger or consolidation and sales or other dispositions of all or substantially all of our assets;
    
    entering into agreements that restrict the ability of our 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. 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. 14




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited) NOTE 4  Related Party Transactions KeySpan Exchange To facilitate the KeySpan Exchange (see Note 1  KeySpan Exchange and
Offering), we entered into a Distribution Agreement with KeySpan that defines
each companys rights and obligations with respect to the exchange transaction.
The Distribution Agreement contains, among other provisions, customary
representations and warranties concerning our Appalachian Basin properties,
including title, regulatory compliance and environmental matters, along with
limited indemnification obligations. Pursuant to the Distribution Agreement,
the two companies also entered into a Tax Matters Agreement, which generally
provides that each party would be responsible for its own tax consequences if
the KeySpan Exchange fails to qualify as a tax-free transaction. In addition,
we entered into a Transition Services Agreement pursuant to which we will
provide KeySpan with transitional services with respect to the Appalachian
Basin assets for a fee of $27,000 per month until March 31, 2005. Finally, we
amended and restated our registration rights agreement with KeySpan. KeySpan

is restricted from increasing their ownership of our shares (approximately 6.6
million shares subsequent to the exchange transaction) for a period of three
years. In addition, both companies agreed with the underwriters of the
Offering not to issue or sell shares of our common stock, except in connection
with employee benefit plans, for the period ending August 24, 2004. NOTE 5  Acquisitions and Dispositions Disposition and Exchange of Appalachian Basin Assets In connection with the KeySpan Exchange on June 2, 2004 (see Note 1  KeySpan
Exchange and Offering), we divested all of our Appalachian Basin assets with an
agreed upon value of $60 million. Pursuant to an Asset Contribution Agreement,
we contributed to Seneca-Upshur all of the assets relating solely to our
Appalachian Basin assets that were not already owned by Seneca-Upshur, and
Seneca-Upshur assumed all of the liabilities relating to the Appalachian Basin
assets for which it was not already liable. In the KeySpan Exchange, all of
the stock of Seneca-Upshur was then conveyed to KeySpan and effective June 1,
2004, Seneca-Upshur became an indirect wholly-owned subsidiary of KeySpan. Our Appalachian property base was located primarily in central West Virginia
and included the Belington, Clarksburg and Seneca Upshur Fields located in
Barbour, Randolph, Upshur and Mingo Counties of West Virginia and included the
assets acquired on December 31, 2003, from EnerVest East Limited Partnership
located adjacent to our existing base in the Crawford and Pennsboro Fields in
Lewis, Harrison, Tyler and Ritchie Counties of West Virginia and the Waynesburg
and Yatesboro Fields in Greene and Armstrong Counties of southwestern
Pennsylvania. As of June 1, 2004, our Appalachian Basin properties had 51.2
Bcfe of estimated proved reserves with average daily production of
approximately 8 MMcfe/day, which represented approximately 3% of our total
daily production. We had approximately 207,000 gross (129,000 net) acres under
lease and owned working interests in approximately 1,414 gross (1,035 net)
wells, of which we operated approximately 92%. Our average working interest
was 73%. 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 of $13.1 million from the sale 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-Q, as well as our Annual Report on Form 10-K for
the year ended December 31, 2003. 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 primary areas of
operations are South Texas, offshore in the shallow waters of the Gulf of
Mexico and the Arkoma Basin of Oklahoma and Arkansas. During 2003, we began
operations in the Rocky Mountain region, with an initial focus in the Uinta
Basin of Northeastern Utah. We divested our Appalachian Basin assets on June
2, 2004, in connection with the KeySpan Exchange transaction described in Note
1  Our Business  KeySpan Exchange and Offering. 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. 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. For the first six months
of 2004, the use of certain types of derivative instruments has prevented us
from realizing the full benefit of upward price movements and may continue to
do so in future periods. Principal Components of Our Cost Structure:  
    
    Lease Operating Expenses.The day-to-day costs incurred to bring
hydrocarbons out of the ground and to the market together with the daily
costs incurred to maintain our producing properties. Combined, 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. We capitalize
G&A directly related to our acquisition, exploration and development
activities.
    
    Interest.We typically finance acquisitions with borrowings under
our revolving bank credit facility, and longer term, with publicly
traded debt instruments. As a result, we incur substantial interest
expense that correlates to both 16




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##### Table of Contents



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 Obligations.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 June 30, 2004, if we applied the interpretation
currently under discussion, undeveloped leasehold costs of $132.5 million and
developed leasehold costs of $148.6 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, which 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 (SFAS 142-b) that will amend SFAS 141
and SFAS 142. The consensus will be effective when the SFAS 142-b has been
finalized. 17




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##### Table of Contents



Overview of Second Quarter 2004 Production growth from exploration and development drilling in all of our
primary areas (South Texas, offshore and the Arkoma Basin) combined with the production
added from the Gulf of Mexico properties acquired during the fourth quarter of
2003, together with strong energy commodity prices, were the primary factors
behind results for operations, earnings and cash flows during the second
quarter of 2004. The increase in our cash flows allowed for continued
deployment of capital for drilling at levels established during the first
quarter of 2004 and the continued repayment of bank debt. During the second
quarter of 2004:  
    
    We completed the KeySpan Exchange and Offering as described in Note 1
 Our Business, and as a result, we increased the public float of our
common stock to approximately 76% and reduced KeySpans ownership
interest from approximately 54% to 24%;
    
    We generated $45.3 million in net income, an increase of 57% from the
second quarter of 2003, and an increase of 14% from the $39.7 million
generated in the first quarter of 2004;
    
    We produced a total of 32 Bcfe and increased our average daily
production rate by 20% quarter-over-quarter to a record 351 MMcfe, and
increased by 6% sequentially from of an average of 332 MMcfe per day
during the first quarter of 2004;
    
    We drilled 48 wells, 41 of which were successful, with 2 successful
wells offshore, 12 in South Texas, 19 in Arkoma, 1 in East Texas and 7
in the Uinta Basin; and,
    
    We generated $116.8 million in net cash flows from operating
activities, invested a net $80.2 million in natural gas and oil
properties, and increased borrowings under our revolving bank credit
facility by a net $40 million. Three Months Ended June 30,

    
    Six Months Ended June 30,Summary Operating Information:
    
    2004
    
    2003
    
    Variance
    
    2004
    
    2003
    
    Variance(in thousands)Operating revenues
    
    $
    172,776
    
    
    $
    120,632
    
    
    $
    52,144
    
    
    
    43
    %
    
    $
    324,658
    
    
    $
    249,635
    
    
    $
    75,023
    
    
    
    30
    %Operating expenses
    
    
    97,702
    
    
    
    70,341
    
    
    
    27,361
    
    
    
    39
    %
    
    
    184,541
    
    
    
    139,148
    
    
    
    45,393
    
    
    
    33
    %Income from operations
    
    
    75,074
    
    
    
    50,291
    
    
    
    24,783
    
    
    
    49
    %
    
    
    140,117
    
    
    
    110,487
    
    
    
    29,630
    
    
    
    27
    %Net income
    
    
    45,350
    
    
    
    28,923
    
    
    
    16,427
    
    
    
    57
    %
    
    
    85,040
    
    
    
    70,620
    
    
    
    14,420
    
    
    
    20
    %Production:Natural gas (MMcf)
    
    
    30,138
    
    
    
    24,634
    
    
    
    5,504
    
    
    
    22
    %
    
    
    58,270
    
    
    
    49,019
    
    
    
    9,251
    
    
    
    19
    %Oil (MBbls)
    
    
    304
    
    
    
    328
    
    
    
    (24
    )
    
    
    -7
    %
    
    
    652
    
    
    
    585
    
    
    
    67
    
    
    
    11
    %Total
(MMcfe) (1)
    
    
    31,962
    
    
    
    26,602
    
    
    
    5,360
    
    
    
    20
    %
    
    
    62,182
    
    
    
    52,529
    
    
    
    9,653
    
    
    
    18
    %Average daily production (MMcfe/d)
    
    
    351
    
    
    
    292
    
    
    
    59
    
    
    
    20
    %
    
    
    342
    
    
    
    290
    
    
    
    52
    
    
    
    18
    %Average Sales Prices:Natural Gas (per Mcf) realized (2)
    
    $
    5.39
    
    
    $
    4.54
    
    
    $
    0.85
    
    
    
    19
    %
    
    $
    5.19
    
    
    $
    4.73
    
    
    $
    0.46
    
    
    
    10
    %Natural Gas (per Mcf) unhedged
    
    
    5.85
    
    
    
    5.16
    
    
    
    0.69
    
    
    
    13
    %
    
    
    5.65
    
    
    
    5.76
    
    
    
    (0.11
    )
    
    
    -2
    %Oil (per Bbl) realized (2)
    
    
    33.63
    
    
    
    26.18
    
    
    
    7.45
    
    
    
    28
    %
    
    
    33.02
    
    
    
    28.55
    
    
    
    4.47
    
    
    
    16
    %Oil (per Bbl) unhedged
    
    
    33.63
    
    
    
    25.95
    
    
    
    7.68
    
    
    
    30
    %
    
    
    33.02
    
    
    
    29.24
    
    
    
    3.78
    
    
    
    13
    %
   (1)
    
    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.(2)
    
    Average realized prices include the effect of hedges. 18




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##### Table of Contents



Natural Gas and Oil Revenues For the second quarter of 2004, the 43% increase in operating revenues was
primarily a result of the combination of the 20% increase in production and the
19% increase in realized natural gas prices. Correspondingly, for the first
six months of 2004, the 30% increase in operating revenues was a combination of
the 18% increase in production, the 10% increase in realized natural gas prices
and the narrowing of our hedge loss by $23.9 million. Production Volume The 20% increase in production for the current quarter is a result of newly
developed production, both onshore and offshore, combined with the production
added from Gulf of Mexico properties acquired during the fourth quarter of
2003. Onshore, our daily production rates increased 12% from an average of 171 MMcfe
per day during the second quarter of 2003 to 191 MMcfe per day during the
second quarter of 2004. In the Arkoma Basin, we are experiencing the full
impact of the accelerated drilling program initiated in 2003 as we added 12
MMcfe per day in newly developed production. With three rigs drilling since
the beginning of 2004, Arkoma production reached a record of 35 MMcfe/day
during the second quarter compared to 23 MMcfe/day during the second quarter of
2003. In South Texas, with six rigs drilling, we also experienced production
growth as we added approximately 9 MMcfe/day. Production increased to an
average of 148 MMcfe/day during the second quarter of 2004 compared to 139
MMcfe/day in the second quarter of 2003. Offshore, our production increased 32% from an average of 121 MMcfe per day
during the second quarter of 2003 to an average of 160 MMcfe per day during the
second quarter of 2004. We added 46 MMcfe/day in newly developed production,
of which 20 MMcfe/day was attributable to development drilling at High Island
A283. During the quarter, we completed and brought on-line our sixth
development well at High Island A283 since January 2004. High Island A283 was
acquired in mid-October 2003 as part of our acquisition of Gulf of Mexico
properties from Transworld. The acquired production from the Transworld
properties accounted for approximately 34 MMcfe/day of our second quarter
increase. Offsetting the increases from the newly developed and the acquired
production were declines from existing and maturing fields totaling 41 MMcfe
per day. For the six-month period ended June 30, 2004, production increased 18% from 290
MMcfe/day during the first half of 2003 to 342 MMcfe/day during the first half
of 2004. During the first six months of 2004, we added 12 MMcfe/day in Arkoma,
5 MMcfe/day in South Texas and 35 MMcfe/day offshore. Offshore, the increase
is comprised of:  
    
    41 MMcfe/day in newly developed production from new wells brought
on-line since the end of the second quarter of 2003 at High Island 47,
A283 and 115, Galveston Island 389/424, Eugene Island 159 and East
Cameron 280;
    
    32 MMcfe/day in acquired production as a result of the Transworld
acquisition in mid-October 2003; offset in part by,
    
    a decline of 38 MMcfe/day in production from existing and maturing
fields. Commodity Prices and Effects of Hedging Our average unhedged or sales price for natural gas increased by 13% from $5.16
per Mcf during the second quarter of 2003 to $5.85 per Mcf during the second
quarter 2004. Included in natural gas
revenues for the second quarter of 2004 is a loss of $13.9 million from natural gas
hedging activities, which includes an unrealized loss of $0.7 million
representing the ineffective portion of our derivative instruments that are not
eligible for deferral under SFAS 133. As a result of the loss from hedging
activities, we realized an average natural gas price during the second quarter
of 2004 of $5.39 per Mcf that was 92% or $0.46 lower than our average sales
price. For the second quarter of 2003, we incurred a hedge loss from natural
gas derivatives of $15.4 million resulting in an average realized price of
$4.54 per Mcf that was 88% or $0.62 per Mcf lower than our sales price. For the first six months of 2004, the increase in our realized price was
primarily a result of the narrowing of our losses from hedging activities for
the period as average sales prices decreased slightly by 2% from an average of
$5.76 per Mcf during the first half of 2003 to $5.65 Mcf during the first half
of 2004. Our hedge loss for the first six months of 2004 of $26.5 million
decreased by 47% or by $23.9 million from the loss of $50.4 million during the
first six months of 2003. For the first six months of 2004, our realized price
was 92% or $0.46 per Mcf lower than our average unhedged natural gas price,
which compares a realized price during the first half of 2003 that was 82% or
$1.03 per Mcf lower than the unhedged price. 19




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##### Table of Contents



Operating Expenses Our overall operating expenses increased during the second quarter and the
current six-month period primarily as a result of higher depreciation,
depletion and amortization rates and higher general and administration expenses
that included $4.4 million in compensation expenses relating to the
consummation of the KeySpan Exchange. Lease operating expense, while up on an
absolute basis due to our fourth quarter 2003 Gulf of Mexico acquisition and
the continuing maturation of our base properties, is down on a unit basis as a
result of our increased production volume. Three Months Ended June 30,
    
    Six Months Ended June 30,Operating Expenses per Mcfe
    
    2004
    
    2003
    
    Variance
    
    2004
    
    2003
    
    VarianceLease operating expense
    
    $
    0.39
    
    
    $
    0.44
    
    
    $
    (0.05
    )
    
    
    -11
    %
    
    $
    0.41
    
    
    $
    0.44
    
    
    $
    (0.03
    )
    
    
    -7
    %Severance tax
    
    
    0.12
    
    
    
    0.12
    
    
    
    
    
    
    
    
    
    
    
    0.11
    
    
    
    0.14
    
    
    
    (0.03
    )
    
    
    -21
    %Transportation expense
    
    
    0.10
    
    
    
    0.10
    
    
    
    
    
    
    
    
    
    
    
    0.09
    
    
    
    0.10
    
    
    
    (0.01
    )
    
    
    10
    %Asset retirement accretion expense
    
    
    0.04
    
    
    
    0.03
    
    
    
    0.01
    
    
    
    33
    %
    
    
    0.04
    
    
    
    0.03
    
    
    
    0.01
    
    
    
    33
    %Depreciation, depletion and amortization
    
    
    2.10
    
    
    
    1.79
    
    
    
    0.31
    
    
    
    17
    %
    
    
    2.06
    
    
    
    1.78
    
    
    
    0.28
    
    
    
    16
    %General and administrative, net
    
    
    0.31
    
    
    
    0.16
    
    
    
    0.15
    
    
    
    94
    %
    
    
    0.25
    
    
    
    0.15
    
    
    
    0.10
    
    
    
    67
    %Total operating expenses per unit of
production
    
    $
    3.06
    
    
    $
    2.64
    
    
    $
    0.42
    
    
    
    16
    %
    
    $
    2.96
    
    
    $
    2.64
    
    
    $
    0.32
    
    
    
    12
    %
 Lease Operating Expense. Lease operating expense increased 7%
quarter-over-quarter and 8% period-over-period. The increases for both
the current quarter and the current six month period are due to the continued
expansion of our operations combined with the higher lease operating expense
associated with the offshore properties acquired in mid-October 2003 from
Transworld offset in part by reduced workover expenses for 2004. On a per unit
basis, the $0.05 or 11% decrease for the quarter is due to the 20% increase in
production during the second quarter of 2004. For the year, the $0.03 or 7%
decrease in lease operating expense is due to the 18% increase in production
during the first six months of 2004. Severance Tax. Severance tax is a function of volume and revenues generated
from onshore production. For the quarter, severance tax is higher due to the
12% increase in onshore production; primarily from our Arkoma properties, as
our South Texas properties are exempt or taxed at reduced rates because of
their high-cost/tight-sand designation, combined with the 13% increase in
wellhead prices for natural gas. On a per unit basis, severance tax is
unchanged. For the six-month period, average wellhead prices are down by 2%
and onshore production is up by 10%, resulting in a decrease in severance tax
expense and severance tax per Mcfe. Depreciation, Depletion and Amortization. The increase in our depreciation,
depletion and amortization expense for the current quarter and the first half
of 2004 was primarily a result of a higher depletion rate combined with a 20%
increase in production for the quarter and an 18% increase in production for
the six-month period. The increase in our depletion rate is primarily a result
of higher finding costs and fewer reserve additions. During the first six
months of 2004, we drilled a total of 15 dry holes, 13 of which were onshore
and two were offshore exploratory wells. In addition, for the second quarter
of 2004, we estimate that $0.05 of the increase in the rate was due to the
disposition of our Appalachian Basin assets, which represented an estimated
51.2 Bcfe in total net proved reserves as of June 1, 2004. Asset Retirement Accretion Expense.The increase in ARO accretion during the
second quarter of 2004 and the six month period 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 $16.7 million in reductions during the first six months of 2004 as a
result of abandonment of offshore properties, disposition of our South
Louisiana properties in February 2004 and our Appalachian Basin properties in
June 2004. 20




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##### Table of Contents



General and Administrative Expenses, Net of Overhead Reimbursements and
Capitalized General and Administrative Expenses Three Months Ended June 30,
    
    Six Months Ended June 30,General and Administrative per Mcfe
    
    2004
    
    2003
    
    Variance
    
    2004
    
    2003
    
    VarianceGross general and administrative expense
    
    $
    0.44
    
    
    $
    0.28
    
    
    $
    0.16
    
    
    
    57
    %
    
    $
    0.40
    
    
    $
    0.29
    
    
    $
    0.11
    
    
    
    38
    %Operating overhead reimbursements
    
    
    (0.02
    )
    
    
    (0.02
    )
    
    
    
    
    
    
    
    
    
    
    (0.02
    )
    
    
    (0.02
    )
    
    
    
    
    
    
    Capitalized general and administrative
    
    
    (0.11
    )
    
    
    (0.10
    )
    
    
    (0.01
    )
    
    
    10
    %
    
    
    (0.13
    )
    
    
    (0.12
    )
    
    
    (0.01
    )
    
    
    8
    %General and administrative expense, net
    
    $
    0.31
    
    
    $
    0.16
    
    
    $
    0.15
    
    
    
    94
    %
    
    $
    0.25
    
    
    $
    0.15
    
    
    $
    0.10
    
    
    
    67
    %
 During the second quarter of 2004 we incurred approximately $4.4 million in
compensation expenses related to the KeySpan Exchange transaction. This amount
included $4.1 million in special bonuses awarded to executives and key
employees who assisted in structuring and consummating the KeySpan Exchange and
the Offering. In addition, we incurred $0.3 million in expenses relating to
the accelerated vesting of restricted stock held by directors who resigned or
retired from our Board of Directors in June. On a per-unit of production
basis, these additional compensation expenses resulted in a $0.14 per Mcfe
increase for the quarter and a $0.07 increase for the six-month period.
Excluding the effect of the additional compensation expenses, gross general and
administrative expense would have been $0.30 per Mcfe for the second quarter of
2004 and net general and administrative expense would have been $0.17
reflecting increases of $0.02 or 7% for gross general and administrative
expense and $0.01 or 6% for net general and administrative expense from the
second quarter of 2003. Excluding the compensation expenses associated with the KeySpan Exchange, 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. Other Income and Expense, Interest and Taxes Other Income and
Expense. For the second quarter and first six months of 2004,
other income was minimal as we are near the end of our severance tax
recovery project. 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. For the second
quarter of 2004, Other Income and Expense includes two items: (i) income of
$0.5 million ($0.3 million net of tax) related to refunds of prior years
severance tax expense; and (ii) debt extinguishment expenses of $0.2 million
incurred pursuant to the reduction of the borrowing base on our revolving bank
credit facility from $375 million to $340 million. The credit facility is
reserve based and contains certain restrictions limiting the sale of assets,
and due to the disposition of our Appalachian Basin assets as a component of
the KeySpan Exchange, our borrowing base was reduced. For the second quarter
of 2003, Other Income and Expense includes two components: (i) debt
extinguishment expenses totaling $5.9 million ($3.9 million net of tax)
incurred pursuant to the call and early redemption of our
$100 million 85/8%
senior subordinated notes due 2008; and (ii) income of $2.3 million ($1.5
million net of tax) related to refunds of prior years severance tax expense.
For the first six months of 2003, Other Income and Expense includes: (i) debt
extinguishment expenses totaling $5.9 million ($3.9 million net of tax); and
(ii) income of $12.9 million ($8.4 million net of tax) related to refunds of
prior years severance tax expense. 21




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##### Table of Contents



Interest Expense, Net of Capitalized Interest. Three Months Ended June 30,
    
    Six Months Ended June 30,Interest and Average Borrowings
    
    2004
    
    2003
    
    Variance
    
    2004
    
    2003
    
    Variance(in thousands)Gross interest
    
    $
    4,381
    
    
    $
    3,981
    
    
    $
    400
    
    
    
    10
    %
    
    $
    8,609
    
    
    $
    7,618
    
    
    $
    991
    
    
    
    13
    %Capitalized interest
    
    
    (2,075
    )
    
    
    (1,821
    )
    
    
    (254
    )
    
    
    14
    %
    
    
    (4,016
    )
    
    
    (3,192
    )
    
    
    (824
    )
    
    
    26
    %Interest expense, net of capitalized
    
    $
    2,306
    
    
    $
    2,160
    
    
    $
    146
    
    
    
    7
    %
    
    $
    4,593
    
    
    $
    4,426
    
    
    $
    167
    
    
    
    4
    %Average borrowings
    
    $
    263,176
    
    
    $
    229,582
    
    
    $
    33,594
    
    
    
    15
    %
    
    $
    272,304
    
    
    $
    239,847
    
    
    $
    32,457
    
    
    
    14
    %Average interest rate
    
    
    5.81%
    
    
    
    6.43%
    
    
    
    (0.62)%
    
    
    
    -10
    %
    
    
    5.70%
    
    
    
    5.91%
    
    
    
    (0.21)%
    
    
    
    - 4
    %
 For the second quarter of 2004 and for the six-month period, the increase in
our gross interest was due in part to the increase in average borrowings offset
in part by a decrease in our average rate. In June 2003, we replaced our fixed
debt of $100 million at 85⁄8% with new fixed debt of $175 million at 7%. For the
year, average borrowings on our bank credit facility decreased by approximately
$20 million compared to average borrowings during the first half of 2003 and
our average borrowing rate decreased slightly from 3.49% for the first half of
2003 as compared to 3.41% during the first half of 2004. Capitalized interest
is a function of unevaluated properties and the increase corresponds to the
increase in our average unevaluated property balance for the quarter and the
six-month period during 2004. The increase in unevaluated property is
primarily a result of our October 2003 acquisition of Gulf of Mexico producing
properties from Transworld. Income Tax Provision.For the second
quarter of 2004, our current provision includes $1.0 million relating to
nondeductible executive compensation expense incurred as a result of a special
bonus paid to our Chief Executive Officer in connection with the KeySpan
Exchange.  The 78% increase in income taxes for the second quarter
of 2004 corresponds to the 64% increase in income before taxes. Our current
provision increased to $16.5 million as we depleted our net operating loss
carryforwards during 2003 and moved to a tax paying status, whereas during the
second quarter of 2003, all federal income taxes were deferred.  For the six-month period of 2004, income taxes increased by 28% and
corresponds to the 20% increase in income before taxes. Our current provision
for the six-month period increased to $24.7 million. 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 six months of 2004, we invested $164.7 million in natural gas
and oil properties and $0.7 million in other property and equipment, spent $2.6
million to abandon offshore assets and divested $73.1 million in onshore
assets, which included our South Louisiana assets in February and our
Appalachian Basin assets in June. 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 half of 2004, we spent 30% offshore and 22




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##### Table of Contents



63% onshore, with the
balance of 7% on capitalized interest and general and administrative costs.
During the first six months of 2004, we completed the drilling of 99 gross wells (81.4 net) of which
85% or 84 (69.2 net) were successful and 15 (12.2 net) were unsuccessful, with
an additional 9 wells (7.1 net) in progress at the end of the period. During
the second quarter, we drilled 48 gross wells (31.0 net) of which 85% or 41
(32.4 net) were successful and 7 (5.6 net) were unsuccessful. The table below
details the components of our natural gas and oil expenditures during each of
three-month and six-month periods ended June 30, 2004 and 2003. Three Months Ended
    
    Six Months EndedJune 30,
    
    June 30,Natural Gas and Oil Expenditures:
    
    2004
    
    2003
    
    2004
    
    2003(in thousands)Producing property acquisitions
    
    $
    
    
    
    $
    
    
    
    $
    2,700
    
    
    $
    Leasehold and lease acquisition costs (1)
    
    
    13,006
    
    
    
    20,304
    
    
    
    26,640
    
    
    
    28,274Development
    
    
    58,600
    
    
    
    45,835
    
    
    
    116,696
    
    
    
    79,206Exploration
    
    
    8,491
    
    
    
    18,247
    
    
    
    18,699
    
    
    
    30,278Total natural gas and oil capital expenditures
    
    $
    80,097
    
    
    $
    84,386
    
    
    $
    164,735
    
    
    $
    137,758
   (1)
    
    For the three months ended June 30, 2004 and 2003, leasehold costs
include capitalized interest and general and administrative expenses of
$5.7 million and $4.7 million, respectively. For the corresponding
six-month periods of 2004 and 2003, capitalized interest and general and
administrative expenses included in leasehold costs totaled $11.8 million
and $9.8 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
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 June 30, 2004. In
addition to the contractual obligations listed on the table below, our balance
sheet at June 30, 2004 reflects accrued interest payable on our revolving bank
credit facility of approximately $10,000, 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 $15 million to $20
million during the second half of 2004. At June 30, 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
    
    $
    110,000
    
    
    $
    
    
    
    $
    
    
    
    $
    110,000
    
    
    $
    7% senior subordinated notes, due June 2013
    
    
    175,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    175,000Operating leases
    
    
    7,831
    
    
    
    770
    
    
    
    4,501
    
    
    
    2,560
    
    
    
    292,831
    
    
    
    770
    
    
    
    4,501
    
    
    
    112,560
    
    
    
    175,000Other Long-Term Obligations:Asset retirement obligations
    
    
    81,445
    
    
    
    3,628
    
    
    
    7,999
    
    
    
    11,700
    
    
    
    58,118Total contractual obligations and commitments
    
    $
    374,276
    
    
    $
    4,398
    
    
    $
    12,500
    
    
    $
    124,260
    
    
    $
    233,118
 Capital Resources We intend to fund our capital expenditure program and contractual commitments
through cash flows from our operations and borrowings under our revolving bank
credit facility. If additional funding is needed to complete a significant
acquisition, we may also access public markets for debt or equity. Our primary
sources of cash during the first six months of 2004 were funds generated from
operations and proceeds for the issuance of common stock through our public
offering of 6.8 million shares of common stock and from the exercise of stock
options. Cash was used to fund the KeySpan Exchange, exploration and
development expenditures and to reduce debt under our revolving bank credit
facility. We made 23




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##### Table of Contents



aggregate cash payments of $7.8 million for interest and $16.9 million for
taxes. The following table summarizes the sources of cash during each of the six-month
periods ended June 30, 2004 and 2003: Six Months Ended June 30,2004
    
    2003
    
    Variance
    
    % change(in thousands)Net income
    
    $
    85,040
    
    
    $
    70,620
    
    
    $
    14,420
    
    
    
    20
    %Non-cash charges
    
    
    163,511
    
    
    
    139,102
    
    
    
    24,409
    
    
    
    18
    %Cash from operations before changes in operating
assets and liabilities
    
    
    248,551
    
    
    
    209,722
    
    
    
    38,829
    
    
    
    19
    %Decrease (increase) in operating assets and liabilities
    
    
    (632
    )
    
    
    (24,110
    )
    
    
    23,478
    
    
    
    -97
    %Net cash provided by operating activities
    
    
    247,919
    
    
    
    185,612
    
    
    
    62,307
    
    
    
    34
    %Net cash (used) for investments in property and equipment
    
    
    (94,867
    )
    
    
    (138,348
    )
    
    
    43,481
    
    
    
    -31
    %Net cash (used) provided by in financing activities
    
    
    (140,512
    )
    
    
    41,352
    
    
    
    (181,864
    )
    
    
    -440
    %Net increase (decrease) in cash
    
    $
    12,540
    
    
    $
    88,616
    
    
    $
    (76,076
    )
    
    
    -86
    %
 At June 30, 2004, we had a working capital deficit of $14.0 million, long-term
debt of $285 million (which includes $110 million in bank
debt), 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 $75.5 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 six
months of 2004 was primarily attributable to the increase in operating income
primarily as a result of the 18% increase in average daily production for the
current year combined with the 10% increase in realized natural gas prices and
a decrease in our hedge loss. The fluctuations in operating assets and
liabilities are caused by the timing of cash receipts and disbursements. Access to Capital Markets. In March 2004, we filed a shelf registration
statement with the SEC for the offering, from time to time, of up to $600
million of our common stock, preferred stock, depositary shares and debt
securities, or a combination of any of these securities, as well as for the
shares of our common stock owned by KeySpan. Subsequent to the June 2004
public offering of 6.8 million shares at $48.00 per share, the proceeds of
which were used to finance a portion of the KeySpan Exchange transaction, we
have approximately $267.4 million of capacity remaining under the shelf
registration statement. Pursuant to the terms of the 1996 registration rights agreement entered into
with KeySpan, we registered KeySpans 17.4 million shares of our common stock
with the shelf registration statement filed in March 2004. The registration
rights agreement was amended and restated pursuant to the KeySpan Exchange
transaction on June 2, 2004. The registration rights agreement, as amended,
provides KeySpan with certain registration rights with regard to its remaining
shares of our common stock. 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 six months of 2004,
we recognized $1.7 million of ineffectiveness, of which $0.7 million was
recognized during the second quarter. 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 six-month periods from January 1 to June 30, 2004
and 2003, and provides the fair value at the end of each period. Six Months Ended
    
    Six Months EndedJune 30, 2004
    
    June 30, 2003Change in Fair Value of Derivatives Instruments:
    
    Before Tax
    
    After Tax
    
    Before Tax
    
    After Tax(in thousands)Fair value of contracts at January 1
    
    $
    (36,862
    )
    
    $
    (23,960
    )
    
    $
    (38,772
    )
    
    $
    (25,202
    )Realized (gain) loss on contracts settled
    
    
    23,953
    
    
    
    15,569
    
    
    
    50,446
    
    
    
    32,790Unrealized (gain) loss due to ineffectiveness of contracts
    
    
    1,700
    
    
    
    1,105
    
    
    
    
    
    
    
    Fair value of new contracts when entered into during
period
    
    
    
    
    
    
    
    
    
    
    5,288
    
    
    
    3,437(Decrease) in fair value of all open contracts
    
    
    (95,179
    )
    
    
    (61,866
    )
    
    
    (69,542
    )
    
    
    (45,202
    )Fair value of contracts outstanding at June 30
    
    $
    (106,388
    )
    
    $
    (69,152
    )
    
    $
    (52,580
    )
    
    $
    (34,177
    )
 25




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##### Table of Contents



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 June 30, 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 six months of 2004, our floor
price will average $4.264 per MMBtu on 240,000 MMBtu per day and our ceiling
price will average $5.845 per MMBtu on 240,000 MMBtu per day. For each
calendar month of 2005, we have 200,000 MMBtu per day hedged with an effective
floor price of $4.567 per MMBtu and an effective ceiling price of $5.456 per
MMBtu. All amounts in the following table are in thousands, except for prices. Natural Gas Hedges
    
    Fixed Price Swaps
    
    CollarsNYMEX
    
    
    
    
    
    NYMEXVolume
    
    Contract
    
    Volume
    
    Contract PricePeriod
    
    (MMBtu)
    
    Price
    
    (MMBtu)
    
    Floor
    
    CeilingJuly 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. 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 26




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##### Table of Contents



defined in Rule
13a-14 of the Exchange Act), as of the end of the period covered by this
report. Based on that evaluation, our principal executive officer and
principal financial officer concluded that, as of June 30, 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 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity
Securities The following table contains information about our purchases of equity
securities during the second quarter of 2004. Our Purchases of Our Common StockTotal Number
    
    Maximum Number (orof Shares
    
    Approximate DollarPurchased as Part
    
    Value) of Shares thatTotal Number
    
    Average Price
    
    of Publicly
    
    May Yet Beof Shares
    
    Paid per
    
    Announced Plans
    
    Purchased UnderPeriod
    
    Purchased (1)
    
    Share (1)
    
    or Programs
    
    the Plans or ProgramsApril 1 to April 30, 2004
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    May 1 to May 31, 2004
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    June 1 to June 30, 2004
    
    
    10,800,000
    
    
    $
    41.57
    
    
    
    
    
    
    
    Total
    
    
    10,800,000
    
    
    $
    41.57
    
    
    
    
    
    
    
    
  (1)
    
    On May 24, 2004, we issued a press release announcing an exchange transaction with KeySpan
Corporation pursuant to which we would redeemed and cancelled 10,800,000 shares of our common
stock owned by KeySpan in exchange for all the stock of Seneca-Upshur, our wholly-owned
subsidiary, to which we contributed all of our Appalachian Basin assets valued at $60 million
and $389 million in cash for a total exchange value of $449 million. On June 2, 2004, we
announced the completion of the transaction with KeySpan. 
 Item 4. Submission of Matters to a Vote of Security Holders On June 3, 2004, we held our annual meeting of stockholders. All matters
brought for a vote before the stockholders as listed in our proxy statement
were approved as follows:  1.
    
    The election of the following 10 Directors to serve until our
next annual meeting: Director
    
    Votes For
    
    Votes WithheldRobert B. Catell
    
    
    25,622,660
    
    
    
    5,643,581John U. Clarke
    
    
    31,012,586
    
    
    
    253,675David G. Elkins
    
    
    30,933,096
    
    
    
    331,145Robert J. Fani (1)
    
    
    25,662,650
    
    
    
    5,603,591William G. Hargett
    
    
    26,662,964
    
    
    
    4,603,277Harold R. Logan, Jr.
    
    
    30,968,511
    
    
    
    297,730Gerald Luterman (1)
    
    
    26,479,784
    
    
    
    4,786,457Stephen W. McKessy
    
    
    30,938,866
    
    
    
    327,375H. Neil Nichols (1)
    
    
    26,461,240
    
    
    
    4,805,001Donald C. Vaughn
    
    
    30,950,731
    
    
    
    315,510
   (1)
    
    Messrs. Fani, Luterman and Nichols resigned from our
Board of Directors on June 2, 2004, pursuant to the
consummation of the KeySpan Exchange transaction and the 27




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##### Table of Contents



resulting reduction in KeySpans ownership interest in
our common stock from approximately 54% to 24%.2.
    
    The approval of The Houston Exploration Company 2004 Long-Term
Incentive Plan Votes For
    
    Votes Against
    
    Abstained
    
    Broker Non-Votes27,735,227
    
    
    1,260,466
    
    
    
    400,869
    
    
    
    1,869,679
  3.
    
    The appointment of Deloitte & Touche LLP as our independent
public accountants for the fiscal year ending December 31, 2004. Votes For
    
    Votes Against
    
    Abstained31,187,538
    
    
    72,716
    
    
    
    5,987
 
 Item 6. Exhibits and Reports on Form 8-K: 
  (a)
    
    Exhibits: Exhibits
    
    
    
    Description10.1(1)
    
    
    
    First Amendment dated May 26, 2004 to the Amended and Restated Credit Agreement dated April 1,
2004 among The Houston Exploration Company and Wachovia Bank, National Association, as Issuing
Bank and Administrative Agent; The Bank of Nova Scotia and Fleet National Bank as Co-Syndication
Agents; and BNP Paribas and Comerica Bank as Co-Documentation Agents dated June 2, 2004.10.2
    
    
    
    Distribution Agreement dated as of June 2, 2004 by and among The Houston Exploration Company,
Seneca-Upshur Petroleum, Inc., THEC Holdings Corp. and KeySpan Corporation (filed as Exhibit 99.2
to our Current Report on Form 8-K dated June 30, 2004 (File No. 001-11899) and incorporated by
reference).10.3
    
    
    
    Asset- Contribution Agreement dated June 2, 2004 between The Houston Exploration Company and
Seneca-Upshur Petroleum, Inc. (filed as Exhibit 99.3 to our Current Report on Form 8-K dated June
30, 2004 (File No. 001-11899) and incorporated by reference).10.4
    
    
    
    Tax Matters Agreement dated as of June 2, 2004 by and among The Houston Exploration Company,
Seneca-Upshur Petroleum, Inc., THEC Holdings Corp., and KeySpan Corporation (filed as Exhibit
99.4 to our Current Report on Form 8-K dated June 30, 2004 (File No. 001-11899) and incorporated
by reference).10.5
    
    
    
    Transition Service Agreement dated June 2, 2004 between The Houston Exploration Company and
Seneca-Upshur Petroleum, Inc. (filed as Exhibit 99.4 to our Current Report on Form 8-K dated June
30, 2004 (File No. 001-11899) and incorporated by reference).10.6
    
    
    
    Amended and Restated Registration Rights Agreement dated as of June 2, 2004 between The Houston
Exploration Company and THEC Holdings Corp. (filed as Exhibit 99.6 to our Current Report on Form
8-K dated June 30, 2004 (File No. 001-11899) and incorporated by reference).10.7(2)
    
    
    
    2004 Long-Term Incentive Plan approved by vote of stockholders on June 3, 2004 (file as Appendix
E to our Definitive Proxy Statement on Schedule 14 A dated June 3, 2004 (File No. 001-11899) and
incorporated by reference).12.1(1)
    
    
    
    Statement of computation of ratio of earnings to fixed charges.31.1(1)
    
    
    
    Certification of William G. Hargett, Chief Executive Officer, as required pursuant to Section 302
 28




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##### Table of Contents



Exhibits
    
    
    
    Descriptionof the Sarbanes-Oxley Act of 2002.31.2(1)
    
    
    
    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(1)
    
    
    
    Certification of William G. Hargett, Chief Executive Officer, as required pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.32.2(1)
    
    
    
    Certification of John H. Karnes, Senior Vice President and Chief Financial Officer, as required
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
  (1)
    
    filed herewith(2)
    
    Management contract or compensation plan. 
  (b)
    
    Reports on Form 8-K:Current Report on Form 8-K filed on April 30, 2004, to furnish under Item 12 
Results of Operations and Financial Condition our earnings release for the
quarterly period ending March 31, 2004.Current Report on Form 8-K filed on May 24, 2004, to report under Item 5 
Other Events the KeySpan Exchange transaction and the offering of 6.2 million
shares of our common stock, file as an exhibit under Item 7 our press release
announcing the exchange transaction and offering and to furnish under Item 9 
Regulation FD Disclosure a confirmation that the exchange and offering will not
change our operational and financial guidance previously announced.Current Report on Form 8-K filed on May 27, 2004, to report under Item 5 
Other Events the pricing of our offering of 6.2 million shares of common stock
and to file as an exhibit under Item 7: (i) the Underwriting Agreement dated
May 26, 2004, among The Houston Exploration Company, and Lehman Brothers Inc.
and Goldman, Sachs & Co., as representatives of the underwriters named therein;
(ii) the opinion of King & Spalding LLP with respect to the legality of the
common stock; (iii) consent of King & Spalding LLP; and (iv) our press release
announcing the pricing of the common stock being offered.Current Report on Form 8-K filed on June 4, 2004, to report under Item 5 
Other Events the completion of the KeySpan Exchange and closing of the offering
of 6.2 million shares of common stock and to file as exhibits under Item 7 the:
(i) press release announcing the closing of the KeySpan Exchange and the
Offering; (ii) Distribution Agreement dated June 2, 2004, among The Houston
Exploration Company, Seneca-Upshur Petroleum, Inc., THEC Holdings Corp. and
KeySpan Corporation; (iii) Asset Contribution Agreement dated June 2, 2004
between The Houston Exploration Company and Seneca-Upshur Petroleum, Inc.; (iv)
Tax Matters Agreement dated as of June 2, 2004, by and among The Houston
Exploration Company, Seneca-Upshur Petroleum, Inc., THEC Holding Corp. and
KeySpan Corporation; and (v) Amended and Restated Registration Rights Agreement
dated as of June 2, 2004, between The Houston Exploration Company and THEC
Holding Corp.Current Report on Form 8-K filed on June 24, 2004, to report under Item 5 
Other Events the closing of the over-allotment offering and to file as an
exhibit under Item 7 our press release announcing the closing of the
over-allotment offering.Current Report on Form 8-K filed on August 5, 2004, to furnish under Item 12 
Results of Operations and Financial Condition our earnings release for the
quarterly period ending June 30, 2004. 29




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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: August 6, 2004
    
    
    
    William G. HargettChairman, President and Chief Executive OfficerBy:
    
    /s/ John H. KarnesDate: August 6, 2004
    
    
    
    John H. KarnesSenior Vice President and Chief Financial OfficerBy:
    
    /s/ James F. WestmorelandDate: August 6, 2004
    
    
    
    James F. WestmorelandVice President and Chief Accounting Officer
 30




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##### Table of Contents



INDEX TO EXHIBITS Exhibits
    
    
    
    Description10.1(1)
    
    
    
    First Amendment dated May 26, 2004 to the Amended and Restated Credit Agreement dated April 1,
2004 among The Houston Exploration Company and Wachovia Bank, National Association, as Issuing
Bank and Administrative Agent; The Bank of Nova Scotia and Fleet National Bank as Co-Syndication
Agents; and BNP Paribas and Comerica Bank as Co-Documentation Agents dated June 2, 2004.10.2
    
    
    
    Distribution Agreement dated as of June 2, 2004 by and among The Houston Exploration Company,
Seneca-Upshur Petroleum, Inc., THEC Holdings Corp. and KeySpan Corporation (filed as Exhibit 99.2
to our Current Report on Form 8-K dated June 30, 2004 (File No. 001-11899) and incorporated by
reference).10.3
    
    
    
    Asset Contribution Agreement dated June 2, 2004 between The Houston Exploration Company and
Seneca-Upshur Petroleum, Inc. (filed as Exhibit 99.3 to our Current Report on Form 8-K dated June
30, 2004 (File No. 001-11899) and incorporated by reference).10.4
    
    
    
    Tax Matters Agreement dated as of June 2, 2004 by and among The Houston Exploration Company,
Seneca-Upshur Petroleum, Inc., THEC Holdings Corp., and KeySpan Corporation (filed as Exhibit
99.4 to our Current Report on Form 8-K dated June 30, 2004 (File No. 001-11899) and incorporated
by reference).10.5
    
    
    
    Transition Service Agreement dated June 2, 2004 between The Houston Exploration Company and
Seneca-Upshur Petroleum, Inc. (filed as Exhibit 99.4 to our Current Report on Form 8-K dated June
30, 2004 (File No. 001-11899) and incorporated by reference).10.6
    
    
    
    Amended and Restated Registration Rights Agreement dated as of June 2, 2004 between The Houston
Exploration Company and THEC Holdings Corp. (filed as Exhibit 99.6 to our Current Report on Form
8-K dated June 30, 2004 (File No. 001-11899) and incorporated by reference).10.7(2)
    
    
    
    2004 Long-Term Incentive Plan approved by vote of stockholders on June 3, 2004 (file as Appendix
E to our Definitive Proxy Statement on Schedule 14 A dated June 3, 2004 (File No. 001-11899) and
incorporated by reference).12.1(1)
    
    
    
    Statement of computation of ratio of earnings to fixed charges.31.1(1)
    
    
    
    Certification of William G. Hargett, Chief Executive Officer, as required pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.31.2(1)
    
    
    
    Certification of John H. Karnes, Senior Vice President and Chief Financial Officer, as required
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.32.1(1)
    
    
    
    Certification of William G. Hargett, Chief Executive Officer, as required pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.32.2(1)
    
    
    
    Certification of John H. Karnes, Senior Vice President and Chief Financial Officer, as required
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
  (1)
    
    filed herewith(2)
    
    Management contract or compensation plan. 31