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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION  FORM 10-Q þ
    
    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OFTHE SECURITIES EXCHANGE ACT OF 1934
 For the quarterly period ended September 30, 2004 OR o
    
    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OFTHE SECURITIES EXCHANGE ACT OF 1934
 For the transition period from  to Commission File No. 001-11899   THE HOUSTON EXPLORATION COMPANY (Exact name of registrant as specified in its charter)
 Delaware
    
    22-2674487(State or other jurisdiction of
    
    (IRS Employer Identification No.)incorporation or organization)
 1100 Louisiana Street, Suite 2000
Houston, Texas 77002-5215
(Address of principal executive offices and zip code) (713) 830-6800
(Registrants telephone number, including area code) 
 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). þ o
 As of November 4, 2004, 28,229,624 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  September 30, 2004 and December 31, 2003 (unaudited)
    
    
    4Consolidated Statements of Operations  Three Month and Nine Month Periods Ended
September 30, 2004 and 2003 (unaudited)
    
    
    5Consolidated Statements of Cash Flows  Nine Months Ended September 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
    
    
    18Item 3. Quantitative and Qualitative Disclosures about Market Risk
    
    
    28Item 4. Controls and Procedures
    
    
    29Part II. Other Information.
    
    
    29Item 5. Other Information
    
    
    30Item 6. Exhibits
    
    
    30Signatures
    
    
    31Exhibit
IndexForm of waiver to employment agreementStatement of computation of ratio of earningsCertification of CEO pursuant to Section 302Certification of Senior VP and CFO pursuant to Sec. 302Certification of CEO pursuant to Section 906Certification of Senior VP and CFO pursuant to Sec. 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, may, project, will, or similar expressions.
Forward-looking statements will include all discussions under the caption Item
2. Managements Discussion and Analysis of Financial Condition and Results of
Operations relating to:  
    
    future production;
    
    expected costs and expenses;
    
    anticipated capital expenditure;
    
    future cash flows and borrowings;
    
    pursuit of potential future acquisition opportunities; and
    
    sources of funding and the timing of exploration and development. 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;
    
    the relatively short production lives of our reserves;
    
    our ability to find, develop and acquire natural gas and oil reserves;
    
    acquisition and investment risks;
    
    our ability to meet our substantial capital requirements;
    
    our outstanding indebtedness;
    
    the uncertainty of estimates of natural gas and oil reserves and production rates;
    
    the inherent hazards and risks involved in our operations;
    
    dependence upon operations concentrated in three primary areas;
    
    drilling risks;
    
    our hedging activities;
    
    compliance with environmental and other governmental regulations;
    
    the competitive nature of our industry;
    
    weather risks and other natural disasters;
    
    our customers ability to meet their obligations; and,
    
    the 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 on Form 10-K for 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
 THE HOUSTON EXPLORATION COMPANY 
 CONSOLIDATED BALANCE SHEETS
 (in thousands, except share data)
 (unaudited)
 September 30,
    
    December 31,2004
    
    2003Assets:Cash and cash equivalents
    
    $
    4,321
    
    
    $
    2,569Accounts receivable
    
    
    99,147
    
    
    
    87,949Accounts receivable  Affiliate
    
    
    5,284
    
    
    
    6,733Derivative financial instruments
    
    
    
    
    
    
    3,458Inventories
    
    
    1,254
    
    
    
    1,071Deferred tax asset
    
    
    41,825
    
    
    
    19,644Prepayments and other
    
    
    5,299
    
    
    
    5,818Total current assets
    
    
    157,130
    
    
    
    127,242Natural gas and oil properties, full cost methodUnevaluated properties
    
    
    151,259
    
    
    
    134,491Properties subject to amortization
    
    
    2,533,937
    
    
    
    2,324,011Other property and equipment
    
    
    11,189
    
    
    
    12,6172,696,385
    
    
    
    2,471,119Less: Accumulated depreciation, depletion and amortization
    
    
    1,293,206
    
    
    
    1,099,9901,403,179
    
    
    
    1,371,129Other non-current assets
    
    
    26,429
    
    
    
    10,694Total Assets
    
    $
    1,586,738
    
    
    $
    1,509,065Liabilities:Accounts payable and accrued expenses
    
    $
    118,992
    
    
    $
    83,983Derivative financial instruments
    
    
    119,501
    
    
    
    35,592Asset retirement obligations
    
    
    3,679
    
    
    
    7,703Total current liabilities
    
    
    242,172
    
    
    
    127,278Long-term debt and notes
    
    
    255,000
    
    
    
    302,000Derivative financial instruments
    
    
    31,241
    
    
    
    4,728Deferred federal income taxes
    
    
    276,054
    
    
    
    251,425Asset retirement obligations
    
    
    87,861
    
    
    
    84,654Other deferred liabilities
    
    
    12,036
    
    
    
    3,446Total Liabilities
    
    
    904,364
    
    
    
    773,531Commitments and Contingencies (see Note 3)Stockholders Equity:Preferred Stock, $0.01 par value, 5,000,000 shares authorized,
no shares issued
    
    
    
    
    
    
    Common Stock, $0.01 par value, 50,000,000 shares authorized and
28,187,424 shares issued and outstanding at September 30,
2004, and
31,437,581 shares issued and outstanding at December 31,
2003, respectively
    
    
    281
    
    
    
    315Additional paid-in capital
    
    
    255,161
    
    
    
    366,781Unearned compensation
    
    
    (900
    )
    
    
    (808
    )Retained earnings
    
    
    523,412
    
    
    
    395,374Accumulated other comprehensive income
    
    
    (95,580
    )
    
    
    (26,128
    )Total Stockholders Equity
    
    
    682,374
    
    
    
    735,534Total Liabilities and Stockholders Equity
    
    $
    1,586,738
    
    
    $
    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
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003(unaudited)
    
    (unaudited)Revenues:Natural gas and oil revenues
    
    $
    162,472
    
    
    $
    118,459
    
    
    $
    486,684
    
    
    $
    367,245Other
    
    
    288
    
    
    
    428
    
    
    
    734
    
    
    
    1,277Total revenues
    
    
    162,760
    
    
    
    118,887
    
    
    
    487,418
    
    
    
    368,522Operating expenses:Lease operating
    
    
    14,301
    
    
    
    10,221
    
    
    
    39,506
    
    
    
    33,536Severance tax
    
    
    3,356
    
    
    
    3,468
    
    
    
    10,304
    
    
    
    10,995Transportation expense
    
    
    3,006
    
    
    
    2,576
    
    
    
    8,911
    
    
    
    7,764Asset retirement accretion expense
    
    
    1,098
    
    
    
    827
    
    
    
    3,576
    
    
    
    2,479Depreciation, depletion and amortization
    
    
    66,926
    
    
    
    47,327
    
    
    
    195,082
    
    
    
    140,705General and administrative, net
    
    
    5,679
    
    
    
    5,437
    
    
    
    21,528
    
    
    
    13,525Total operating expenses
    
    
    94,366
    
    
    
    69,856
    
    
    
    278,907
    
    
    
    209,004Income from operations
    
    
    68,394
    
    
    
    49,031
    
    
    
    208,511
    
    
    
    159,518Other (income) expense
    
    
    (1,588
    )
    
    
    (6,238
    )
    
    
    (1,856
    )
    
    
    (13,200
    )Interest expense, net
    
    
    2,000
    
    
    
    1,842
    
    
    
    6,593
    
    
    
    6,268Income before income taxes
    
    
    67,982
    
    
    
    53,427
    
    
    
    203,774
    
    
    
    166,450Provision for taxes
    
    
    24,984
    
    
    
    18,708
    
    
    
    75,736
    
    
    
    58,339Income before cumulative effect of change in
accounting principle
    
    
    42,998
    
    
    
    34,719
    
    
    
    128,038
    
    
    
    108,111Cumulative effect of change in accounting principle
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2,772
    )Net income
    
    $
    42,998
    
    
    $
    34,719
    
    
    $
    128,038
    
    
    $
    105,339Earnings per share:Net income per share  basicIncome before cumulative effect of change in
accounting principle
    
    $
    1.53
    
    
    $
    1.12
    
    
    $
    4.26
    
    
    $
    3.48Cumulative effect of change in accounting
principle
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (0.09
    )Net income per share  basic
    
    $
    1.53
    
    
    $
    1.12
    
    
    $
    4.26
    
    
    $
    3.39Net income per share  fully dilutedIncome before cumulative effect of change in
accounting principle
    
    $
    1.51
    
    
    $
    1.11
    
    
    $
    4.22
    
    
    $
    3.47Cumulative effect of change in accounting
principle
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (0.09
    )Net income per share  fully diluted
    
    $
    1.51
    
    
    $
    1.11
    
    
    $
    4.22
    
    
    $
    3.38Weighted average shares outstanding  basic
    
    
    28,082
    
    
    
    31,117
    
    
    
    30,068
    
    
    
    31,022Weighted average shares outstanding  fully diluted
    
    
    28,486
    
    
    
    31,236
    
    
    
    30,330
    
    
    
    31,134
 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)
 Nine Months Ended September 30,2004
    
    2003(unaudited)Operating Activities:Net income
    
    $
    128,038
    
    
    $
    105,339Adjustments to reconcile net income to net cash provided by
operating activities:Depreciation, depletion and amortization
    
    
    195,082
    
    
    
    140,705Deferred income tax expense
    
    
    43,114
    
    
    
    56,425Asset retirement accretion expense
    
    
    3,576
    
    
    
    2,479Ineffectiveness of derivative instruments
    
    
    2,600
    
    
    
    Amortization of premium on derivative instruments
    
    
    4,432
    
    
    
    Stock compensation expense
    
    
    2,044
    
    
    
    514Debt extinguishment
    
    
    211
    
    
    
    1,626Cumulative effect of change in accounting principle
    
    
    
    
    
    
    2,772Changes in operating assets and liabilities:(Increase) decrease in accounts receivable
    
    
    (9,749
    )
    
    
    407(Increase) in inventories
    
    
    (183
    )
    
    
    (100
    )(Increase) decrease in prepayments and other
    
    
    519
    
    
    
    (508
    )(Increase) in other assets
    
    
    (2,784
    )
    
    
    (17,136
    )Increase in accounts payable and accrued expenses
    
    
    35,009
    
    
    
    4,100(Decrease) in ARO liability for assets retired and abandoned
    
    
    (2,569
    )
    
    
    Increase in other deferred liabilities
    
    
    8,590
    
    
    
    1,468Net cash provided by operating activities
    
    
    407,930
    
    
    
    298,091Investing Activities:Investment in property and equipment
    
    
    (302,380
    )
    
    
    (212,933
    )Deposit paid for property acquisition
    
    
    (11,350
    )
    
    
    (15,000
    )Proceeds from dispositions
    
    
    73,425
    
    
    
    Net cash used in investing activities
    
    
    (240,305
    )
    
    
    (227,933
    )Financing Activities:Proceeds from long-term borrowings
    
    
    247,000
    
    
    
    246,000Repayments of long-term borrowings
    
    
    (294,000
    )
    
    
    (323,000
    )Debt issue costs
    
    
    (1,555
    )
    
    
    (4,586
    )Proceeds from issuance of common stock from exercise of stock options
    
    
    20,934
    
    
    
    6,596Proceeds from issuance of common stock
    
    
    310,727
    
    
    
    79,200Exchange of common stock
    
    
    (448,979
    )
    
    
    Repurchase of common stock
    
    
    
    
    
    
    (79,200
    )Net cash used in financing activities
    
    
    (165,873
    )
    
    
    (74,990
    )Increase (decrease) in cash and cash equivalents
    
    
    1,752
    
    
    
    (4,832
    )Cash and cash equivalents, beginning of period
    
    
    2,569
    
    
    
    18,031Cash and cash equivalents, end of period
    
    $
    4,321
    
    
    $
    13,199Supplemental Information:Cash paid for interest
    
    $
    8,649
    
    
    $
    11,278Cash paid for income taxes
    
    $
    35,900
    
    
    $
    14,800
 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 a current focus on the Uinta
Basin of Northeastern Utah and the DJ Basin of Eastern Colorado. In February
2004, we divested our South Louisiana assets and in June 2004, we divested our
Appalachian Basin assets 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s ownership interest in our common
stock was further reduced to 23% at September 30, 2004 as a result of the
dilutive effect of stock options exercised during the third quarter of 2004.
KeySpan has publicly announced it does not consider its investment in our
company to be a core asset and that it may therefore decide from time
to time to sell part of its investment in our shares. 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 for a total 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. 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.
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 still remains on the Board. 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 is 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. As of December 31, 2003, we had
50.5 Bcfe of estimated proved reserves in the Appalachian Basin. Because we
account 7




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited) 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
the Financial Accounting Standards Board (FASB) Statement of Financial
Accounting Standards (SFAS) 144. Interim Financial Statements Our balance sheet at September 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. Estimates of our
remaining proved natural gas and oil reserves are one of our most significant
financial estimates. 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 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 at the lowest of (i) the price in effect at the time of
production; (ii) the current market price; or (iii) the contract price, if a
contract is in hand. 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
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003(in thousands, except per share data)Numerator:Income before cumulative effect of change
in accounting principle
    
    $
    42,998
    
    
    $
    34,719
    
    
    $
    128,038
    
    
    $
    108,111Cumulative effect of change in accounting principle
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2,772
    )Net income
    
    $
    42,998
    
    
    $
    34,719
    
    
    $
    128,038
    
    
    $
    105,339Denominator:Weighted average shares outstanding
    
    
    28,082
    
    
    
    31,117
    
    
    
    30,068
    
    
    
    31,022Add dilutive securities: Stock options
    
    
    404
    
    
    
    119
    
    
    
    262
    
    
    
    112Total weighted average shares outstanding and
dilutive securities
    
    
    28,486
    
    
    
    31,236
    
    
    
    30,330
    
    
    
    31,134Earnings per share  basic:Income before cumulative effect of change in
accounting principle
    
    $
    1.53
    
    
    $
    1.12
    
    
    $
    4.26
    
    
    $
    3.48Cumulative effect of change in accounting principle
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (0.09
    )Net income per share  basic
    
    $
    1.53
    
    
    $
    1.12
    
    
    $
    4.26
    
    
    $
    3.39Earnings per share  fully diluted:Income before cumulative effect of change in
accounting principle
    
    $
    1.51
    
    
    $
    1.11
    
    
    $
    4.22
    
    
    $
    3.47Cumulative effect of change in accounting principle
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (0.09
    )Net income per share  fully diluted
    
    $
    1.51
    
    
    $
    1.11
    
    
    $
    4.22
    
    
    $
    3.38
 The calculation of shares outstanding for fully diluted EPS does not include
the effect of outstanding stock options to purchase 404,001 and 1,843,150
shares for the three months ended September 30, 2004 and 2003, respectively,
and 907,956 and 1,880,107 shares for the nine months ended September 30, 2004
and 2003, respectively, because to include would have an antidilutive effect on
earnings per share. Comprehensive Income Comprehensive Income includes Net Income and certain items recorded directly to
Stockholders Equity and Classified as Other Comprehensive Income. The table
below summarizes Comprehensive Income and provides the components of the change
in Accumulated Other Comprehensive Income for the three-month and nine-month
periods ended September 30, 2004 and 2003, respectively. Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003(in thousands)Net income
    
    $
    42,998
    
    
    $
    34,719
    
    
    $
    128,038
    
    
    $
    105,339Other comprehensive income (loss)Derivative instruments settled and reclassified, net of tax
    
    
    7,034
    
    
    
    6,276
    
    
    
    23,153
    
    
    
    39,066Ineffectiveness of open derivative instruments, net of tax.
    
    
    585
    
    
    
    
    
    
    
    1,690
    
    
    
    Change in fair value of open derivative instruments, net
of tax
    
    
    (35,309
    )
    
    
    19,906
    
    
    
    (94,295
    )
    
    
    (25,297
    )Total other comprehensive income (loss)
    
    
    (27,690
    )
    
    
    26,182
    
    
    
    (69,452
    )
    
    
    13,769Comprehensive income
    
    $
    15,308
    
    
    $
    60,901
    
    
    $
    58,586
    
    
    $
    119,108
 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 (including assets associated with retirement obligations); 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 SEC guidelines, we
include estimated future cash flows from our hedging program in our ceiling
test calculation. In addition, subsequent to the adoption of SFAS 143,
Accounting for Asset Retirement Obligations, the future cash outflows
associated with settling asset retirement obligations are not included in the
computation of the discounted present value of future net revenues for the
purposes of the 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 In September 2004, FASB issued FASB Staff Position (FSP) FAS 142-2,
Application of FASB Statement 142, Goodwill and Other Intangible Assets to Oil
and Gas Producing Entities. This FSP was issued as a result of questions
arising as to whether the scope exception in paragraph 8(b) of SFAS 142
includes the balance sheet classification and disclosures for drilling and
mineral rights of oil and gas producing entities. The FSP FAS 142-2 concludes
that the scope 10




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited) exception in SFAS 142 does extend to the balance sheet classification and
disclosure provisions for drilling and mineral rights of oil and gas producing
entities that are within the scope of SFAS 19, Financial Accounting and
Reporting by Oil and Gas Producing Companies. As a result, mineral rights
held under lease or other contractual arrangements together with cash costs for
the acquisition of natural gas and oil leasehold interests are not required to
be separately classified as intangibles on the balance sheet. Historically, we
have included these types of intangible leasehold costs as a component of
natural gas and oil properties, which is consistent with the FSP. As such, our
consolidated financials statements were not affected. 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. Subsequent to our
adoption of SFAS 143, the ARO assets, which are carried on the balance sheet as
part of the full cost pool, have been included in our amortization base for the
purposes of calculating depreciation, depletion and amortization expense. For
the purposes of calculating the ceiling test, the future cash outflows
associated with settling the ARO liability have been excluded from the
computation of the discounted present value of estimated future net revenues. The following table describes the various components of our ARO liability
during each of the nine-month periods ending September 30, 2004 and 2003,
respectively. ARO liability includes amounts classified as both current and
long-term. Nine Months Ended September 30,2004
    
    2003(in thousands)ARO liability at January 1
    
    $
    92,357
    
    
    $
    57,197Additions from drilling
    
    
    4,982
    
    
    
    4,852ARO accretion expense
    
    
    3,576
    
    
    
    2,478Assets acquired
    
    
    7,626
    
    
    
    Assets sold
    
    
    (12,714
    )
    
    
    Assets retired and abandoned
    
    
    (4,287
    )
    
    
    ARO liability at September 30
    
    $
    91,540
    
    
    $
    64,527
 Derivative Instruments and Hedging Activities Our hedging policy does not permit us to hold derivative instruments for
trading purposes. In our hedging program, we utilize a variety of derivative
instruments, including swaps, collars and options. We generally place
contracts with major financial institutions and other credit-worthy
counterparties. Although our hedging program protects a portion of our cash
flows from downward price movements, certain hedging strategies, specifically
the use of swaps and collars, may also limit our ability to realize the full
benefit of future price increases. In addition, because our derivative
instruments are typically indexed to New York Mercantile Exchange (NYMEX)
prices as opposed to the index price where the gas is actually sold, our
hedging strategy may not protect our cash flows if the price differential
increases between the NYMEX price and index price for the point of sale. Our derivative instruments are designated cash flow hedges and qualify for
hedge accounting under SFAS 133, Accounting for Derivative Instruments and
Hedging Activities, as amended, and, accordingly, we carry the fair market
value of our derivative instruments on the balance sheet as either an asset or
liability and defer unrealized gains or losses in accumulated other
comprehensive income. Gains and losses are reclassified from accumulated other
comprehensive income to the income statement as a component of natural gas and
oil revenues in the period the hedged production occurs. If any 11




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited) ineffectiveness occurs, amounts are recorded directly to the income statement.
For the first nine months of 2004, our net income includes an unrealized loss
of $2.6 million ($1.7 million net of tax), of which $0.9 million ($0.6 million
net of tax) was incurred during the third 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 September 30, 2004, we recorded an unrealized loss in
Accumulated Other Comprehensive Income of $95.6 million, net of tax,
representing the fair value of our open contracts. Any loss be 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 recorded for
grants made in previous years. For the three months ended September 30, 2004 and 2003, we recognized gross
compensation expense of $0.7 million and $0.4 million, respectively, for stock
options and restricted stock granted during these periods of which we
capitalized $0.2 million and $7,000, in each of the respective three-month
periods. For the corresponding nine-month periods ended September 30, 2004 and
2003, gross compensation expense for stock options was $2.0 million and $0.5
million, respectively, of which we capitalized $0.5 million and $24,000,
respectively. 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 nine-month periods ended
September 30, 2004 and 2003. Amounts are in thousands, except per share data. Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003(in thousands, except per share data)Net income  as reported
    
    $
    42,998
    
    
    $
    34,719
    
    
    $
    128,038
    
    
    $
    105,339Add: Stock-based compensation expense
included in net income, net of tax
    
    
    361
    
    
    
    268
    
    
    
    1,016
    
    
    
    334Less: Stock-based compensation expense using
fair value method, net of tax
    
    
    (1,266
    )
    
    
    (1,107
    )
    
    
    (3,999
    )
    
    
    (2,189
    )Net income  pro forma
    
    $
    42,093
    
    
    $
    33,880
    
    
    $
    125,055
    
    
    $
    103,484Net income per share  as reported
    
    $
    1.53
    
    
    $
    1.12
    
    
    $
    4.26
    
    
    $
    3.39Net income per share  fully diluted  as
reported
    
    
    1.51
    
    
    
    1.11
    
    
    
    4.22
    
    
    
    3.38Net income per share  pro forma
    
    $
    1.50
    
    
    $
    1.09
    
    
    $
    4.16
    
    
    $
    3.34Net income per share  fully diluted  pro forma
    
    
    1.48
    
    
    
    1.08
    
    
    
    4.12
    
    
    
    3.32
 The pro forma results for each of the periods presented above is not
necessarily indicative of future effects on Net Income and Earnings per Share. 12




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited) NOTE 2  Long-Term Debt and Notes September 30, 2004
    
    December 31, 2003(in thousands)Senior Debt:Revolving bank credit facility, due April 1, 2008
    
    $
    80,000
    
    
    $
    127,000Subordinated Debt:7% senior subordinated notes, due June 15, 2013
    
    
    175,000
    
    
    
    175,000Total long-term debt and notes
    
    $
    255,000
    
    
    $
    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 September 30, 2004, the quoted market value of our $175
million of 7% senior subordinated notes was 98.0% of the $175 million carrying
value or $171.5 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. Effective October 15, 2004, the $340
million borrowing base was increased to $400 million, which is expected to
remain in effect until the next scheduled redetermination on April 1, 2005. Up
to $40 million of the borrowing base is available for the issuance of letters
of credit. Outstanding borrowings are unsecured and rank senior in right of
payment to our $175 million 7% subordinated notes. The amended facility
matures on April 1, 2008. At September 30, 2004, we had $80 million in
outstanding borrowings under the credit facility and $0.4 million in
outstanding letter of credit obligations. Subsequent to September 30,
2004, we borrowed an additional $95 million under the credit facility
and issued additional letters of credit totaling $8.1 million (see
Note 7  Subsequent Events). As of the date of our
report, outstanding borrowings under our credit facility were $175
million and letter of credit obligations were $8.5 million. 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. At September 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. NOTE 5  Acquisitions and Dispositions BP Acquisition On September 30, 2004, we completed the purchase of two producing offshore
fields from BP Exploration & Production Inc. The net purchase price of $30.0
million was paid in cash and financed by borrowings under our revolving bank
credit facility. The $31.5 million purchase price was reduced by $1.5 million
for various customary closing items, including revenues received by and
expenditures made by the seller related to the properties acquired for the
period between the effective date of the transaction, August 1, 2004, and the
closing date, September 30, 2004. The properties acquired are located at
Eugene Island 240 and Main Pass 264 and each block has one producing platform.
Total proved reserves associated with the interests acquired are approximately
16.2 Bcfe as of September 30, 2004, of which 85% are natural gas. Our average
working interest is 85% and we will operate both blocks. Orca Acquisition On September 17, 2004, we entered into a definitive purchase and sale agreement
to acquire natural gas and oil producing properties primarily located in the
shallow waters of the Gulf of Mexico from Orca Energy, L.P. for a cash purchase
price of approximately $113.5 million, subject to certain post-closing
adjustments. The purchase price consists of the payment of (i) a deposit of
$11.4 million, which was paid on September 17, 2004 (which deposit generally is
nonrefundable, except upon certain breaches of the agreement by the seller) and
(ii) an additional $102.1 million payable upon closing of the transaction,
which is subject to certain post-closing adjustments. We borrowed the amount
of the deposit under our revolving bank credit facility. At September 30,
2004, the deposit of $11.4 million was included in the line item Other Assets
on our Balance Sheet. The acquisition was completed on October 29, 2004. See
Note 7  Subsequent Events  Orca Acquisition. 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. Based on internal estimates at June 1, 2004, our Appalachian
Basin properties had 51.2 Bcfe of estimated proved reserves, and our average
daily production was 15




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited) 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. NOTE 6  Stockholders Rights Plan On August 12, 2004, we adopted a stockholder rights plan designed to assure
that our stockholders receive fair and equal treatment in the event of an
unsolicited attempt to takeover our company and to protect against abusive or
coercive takeover tactics that are not in the best interest of our company or
its stockholders. To implement the rights plan, the Board of Directors
declared a dividend of one preferred share purchase right for each outstanding
share of our common stock to stockholders of record as of the close of business
on August 23, 2004, and directed the issuance of one preferred share purchase
right with respect to each share of our common stock that shall become
outstanding thereafter until the rights become exercisable or they expire as
described below. Each right initially represents a contingent right to
purchase, under certain circumstances, one one-thousandth of a share of our
Series A Junior Participating Preferred Stock, par value $.01 per share, at an
initial exercise price of $275.00 per one one-thousandth of a share, subject to
adjustment under certain circumstances. The rights will become exercisable and
trade independently from our common stock upon the public announcement of the
acquisition by a person or group of 10% or more of our common stock, or ten
days after commencement of a tender or exchange offer that would result in the
acquisition of 10% or more of our common stock (or, in the case of KeySpan and
its affiliates, more than 24% of our common stock). Each share purchased upon exercise of the rights will be entitled to a minimum
quarterly preferential dividend payment of the greater of (i) $10.00 per share
and (ii) an amount equal to 1,000 times the dividend declared per share of
common stock. Each share will be entitled to 1,000 votes, voting together with
the common stock. In the event of our liquidation, each share of the Series A
Junior Participating Preferred Stock will be entitled to a minimum preferential
payment of the greater of (a) $10.00 per share (plus any accrued but unpaid
dividends) and (b) an amount equal to 1,000 times the payment made per share of
common stock. If we are acquired in a merger or other business combination transaction after
a person or group has acquired 10% or more of our common stock, each right will
entitle its holder to purchase, at the rights exercise price, that number of
the acquiring companys shares of common stock having a market value of twice
the rights exercise price. In addition, if a person or group acquires 10% or
more of our common stock, each right will entitle its holder (other than the
acquiring person or group) to purchase, at the rights exercise price, a number
of fractional shares of the Series A Junior Participating Preferred Stock or
shares of our common stock having a market value of twice the rights exercise
price. The rights expire on August 12, 2014, unless redeemed earlier by our Board of
Directors. The Board of Directors can redeem the rights at a price of $.01 per
right at any time before the rights become exercisable, and thereafter only in
limited circumstances. NOTE 7  Subsequent Events Orca Acquisition On October 29, 2004, we completed the acquisition of certain producing
properties from Orca Energy, L.P. (see Note 5  Acquisitions and Dispositions 
Orca Acquisition). At closing, we borrowed $70 million on our revolving bank
credit facility and used cash on hand of $28.4 million, for a
total of $98.4 million, to fund the remaining
portion of the $109.8 million net purchase price. In September 2004, we paid a
cash deposit of $11.4 million towards the purchase price of $113.5 million
which was reduced at closing by $3.7 million for various customary closing
items, including revenues received by and expenditures made by 16




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THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited) the seller related to the properties acquired for the period between the
effective date of the transaction, August 1, 2004, and the closing date,
October 29, 2004. The Orca properties consist of 12 producing fields, two of which are
non-operated and located onshore in central Mississippi: the Wausau Field
located in Wayne County and the Oakvale Dome Field located in Jefferson Davis
County. The offshore fields are a mix of state and federal leases located in
less than 50 feet of water and include seven blocks in federal waters and three
blocks in state waters. Total acreage acquired covers 23,777 gross (17,973
net) acres. The properties include 15 platforms, five production caissons and
28 producing wells. Based on internal estimates, proved reserves are an
estimated 62.5 Bcfe, of which 81% are natural gas. Our average working
interest in the properties acquired is 68% and we will operate approximately
85% of the proved reserves acquired. Letter of Credit Issued for Hedging Activities Subsequent to the balance sheet date, the fair value of our open derivative
contracts increased beyond our available credit limit with one counterparty.
As a result, in October 2004, we were required to issue letters of credit
totaling $8.1 million to further guarantee our performance on open derivative
contracts. Shelf Registration Statement Filed On October 27, 2004, we filed a second shelf registration statement with the
SEC to register the sale from time to time of up to an additional $477.4
million of our common stock, preferred stock, depositary shares and debt
securities, or any combination thereof. The SEC has not declared this
registration statement effective. The prospectus for the second shelf
registration statement will include the unused portion of the shelf
registration statement filed in March 2004 of $272.4 million together with the
registration of the remaining 6,580,392 shares of our common stock held by
KeySpan. The combination of the two shelf registrations statements will
provide an aggregate of $750 million for the offering of our common stock,
preferred stock, depositary shares and debt securities, or a combination of any
of these securities. 17




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##### Table of Contents



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 a current focus on the Uinta
Basin of Northeastern Utah and the DJ Basin of Eastern Colorado. In February
2004, we divested our South Louisiana assets and in June 2004, we divested our
Appalachian Basin assets in connection with the KeySpan Exchange transaction
described in Note 1  Our Business  KeySpan Exchange and Offering. We operate
as one segment as each of our operating areas has similar economic
characteristics and each meets the criteria for aggregation as defined in the
Financial Accounting Standards Board (FASB) Statement of Financial Accounting
Standards (SFAS) 131. 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. As of December 31, 2003, we had 50.5
Bcfe of estimated proved reserves in the Appalachian Basin and 12.3 Bcfe of
estimated proved reserves in South Louisiana. 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 nine 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. 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
depreciation, depletion and amortization expense. Generally, if reserve
quantities are revised up or down, the depreciation, depletion and
amortization rate per unit of production will change inversely. When
the depreciable base increases or decreases, the depreciation, depletion
and amortization rate will move in the same direction.
    
    Asset Retirement Accretion Expense.The systematic, monthly
accretion of the future abandonment costs of tangible assets such as
platforms, wells, service assets, pipelines, and other facilities.
    
    General and Administrative.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 18




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general and administrative expense. We capitalize general and
administrative expense 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 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. Unevaluated Properties. The balance of unevaluated properties is comprised of
capital costs incurred for undeveloped acreage, seismic data, wells and
production facilities in progress, wells pending determination and related
capitalized interest. These costs are initially excluded from our amortization
base until the outcome of the project has been determined, or generally, until
it is known whether proved reserves will or will not be assigned to the
property. We assess all items in our unevaluated property balance 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. 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 In September 2004, the FASB issued FASB Staff Position (FSP) FAS 142-2,
Application of FASB Statement 142, Goodwill and Other Intangible Assets to Oil
and Gas Producing Entities. This FSP was issued as a result of questions
arising as to whether the scope exception in paragraph 8(b) of SFAS 142
includes the balance sheet classification and disclosures for drilling and
mineral rights of oil and gas producing entities. The FSP FAS 142-2 concludes
that the scope exception in SFAS 142 does extend to the balance sheet
classification and disclosure provisions for drilling and mineral rights of oil
and gas producing entities that are within the scope of SFAS 19, Financial
Accounting and Reporting by Oil and Gas Producing Companies. As a result,
mineral rights held under lease or other contractual arrangements together with
cash costs for the acquisition of natural gas and oil leasehold interests are
not required to be separately classified as intangibles on the balance sheet.
Historically, we have included these types of intangible leasehold costs as a
component of natural gas and oil properties, which is consistent with the FSP.
As such, our consolidated financials statements were not affected. 19




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##### Table of Contents



Overview of Third Quarter 2004 Continued strong energy commodity prices combined with production growth in all
of our primary areas (South Texas, offshore Gulf of Mexico and the Arkoma
Basin) were the primary factors behind results for operations, earnings and
cash flows during the third quarter of 2004. The increase in our cash flows
allowed for continued deployment of capital for drilling, an increase in our
capital expenditure budget and the continued repayment of bank debt. During
the third quarter of 2004:  
    
    We generated $43.0 million in net income, an increase of 24% from the
third quarter of 2003;
    
    We produced a total of 31.5 Bcfe and increased our average daily
production rate by 19% quarter-over-quarter to 343 MMcfe per day, while
production decreased by 9 MMcfe per day or 3% sequentially from an
average of 351 MMcfe per day during the second quarter of 2004 primarily
as a result of the divesture of our Appalachian Basin assets in June
2004 as part of the KeySpan Exchange transaction (see Note 1  KeySpan
Exchange and Offering);
    
    We generated $162.6 million in net cash flows from operating
activities, invested a net $136.7 million in natural gas and oil
properties including $30 million for producing property acquisitions and
we reduced borrowings under our revolving bank credit facility by a net
$30 million;
    
    We completed the acquisition of 330,000 net acres in Colorados DJ
Basin and drilled the first two of the 20 wells planned during the
remainder of 2004;
    
    We completed the acquisition of two offshore producing blocks from BP
Exploration & Production Inc for a net $30.0 million and added estimated
proved reserves of 16.2 Bcfe (see Note 5  Acquisitions and
Dispositions);
    
    We entered into a definitive purchase and sale agreement with Orca
Energy, L.P to acquire 12 producing fields located primarily in the
shallow waters of the central Gulf of Mexico with an estimated 62.5 Bcfe
of proved reserves for $113.5 million (see Note 7  Subsequent Events);
    
    We drilled 68 wells, of which 58 or 85% were successful, with 21
successful wells in Arkoma, 19 in South Texas, 12 in the Rockies and 6
offshore;
    
    We increased our 2004 capital expenditure budget by $185 million from
the $315 million established at the beginning of 2004 to $500 million,
of which $55 million is expected to provide for additional exploration,
and development and $130 million provided for the BP and Orca producing
property acquisitions; and
    
    We adopted a shareholder rights plan designed to assure that our
stockholders receive fair and equal treatment in the event of an
unsolicited takeover attempt and to protect against abusive or coercive
takeover tactics that are not in the best interest of our company or its
stockholders (see Note 6  Stockholders Rights Plan). 20




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##### Table of Contents



Three Months Ended September 30,
    
    Nine Months Ended September 30,Summary Operating Information:
    
    2004
    
    2003
    
    Variance
    
    2004
    
    2003
    
    Variance(in thousands)Operating revenues
    
    $
    162,760
    
    
    $
    118,887
    
    
    $
    43,873
    
    
    
    37
    %
    
    $
    487,418
    
    
    $
    368,522
    
    
    $
    118,896
    
    
    
    32
    %Operating expenses
    
    
    94,366
    
    
    
    69,856
    
    
    
    24,510
    
    
    
    35
    %
    
    
    278,907
    
    
    
    209,004
    
    
    
    69,903
    
    
    
    33
    %Income from operations
    
    
    68,394
    
    
    
    49,031
    
    
    
    19,363
    
    
    
    39
    %
    
    
    208,511
    
    
    
    159,518
    
    
    
    48,993
    
    
    
    31
    %Net income
    
    
    42,998
    
    
    
    34,719
    
    
    
    8,279
    
    
    
    24
    %
    
    
    128,038
    
    
    
    105,339
    
    
    
    22,699
    
    
    
    22
    %Production:Natural gas (MMcf)
    
    
    29,465
    
    
    
    24,554
    
    
    
    4,911
    
    
    
    20
    %
    
    
    87,735
    
    
    
    73,573
    
    
    
    14,162
    
    
    
    16
    %Oil (MBbls)
    
    
    343
    
    
    
    331
    
    
    
    12
    
    
    
    4
    %
    
    
    995
    
    
    
    916
    
    
    
    79
    
    
    
    9
    %Total (MMcfe) (1)
    
    
    31,523
    
    
    
    26,540
    
    
    
    4,983
    
    
    
    19
    %
    
    
    93,705
    
    
    
    79,069
    
    
    
    14,636
    
    
    
    19
    %Average daily production (MMcfe/d)
    
    
    343
    
    
    
    288
    
    
    
    55
    
    
    
    19
    %
    
    
    342
    
    
    
    290
    
    
    
    52
    
    
    
    18
    %Average Sales Prices:Natural Gas (per Mcf) realized (2)
    
    $
    5.06
    
    
    $
    4.45
    
    
    $
    0.61
    
    
    
    14
    %
    
    $
    5.15
    
    
    $
    4.64
    
    
    $
    0.51
    
    
    
    11
    %Natural Gas (per Mcf) unhedged
    
    
    5.46
    
    
    
    4.84
    
    
    
    0.62
    
    
    
    13
    %
    
    
    5.59
    
    
    
    5.45
    
    
    
    0.14
    
    
    
    3
    %Oil (per Bbl) realized (2)
    
    
    38.69
    
    
    
    27.70
    
    
    
    10.99
    
    
    
    40
    %
    
    
    34.98
    
    
    
    28.24
    
    
    
    6.74
    
    
    
    24
    %Oil (per Bbl) unhedged
    
    
    38.69
    
    
    
    27.70
    
    
    
    10.99
    
    
    
    40
    %
    
    
    34.98
    
    
    
    28.68
    
    
    
    6.30
    
    
    
    22
    %
   (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. Natural Gas and Oil Revenues For the third quarter of 2004, the 37% increase in operating revenues was a
result of the combination of the 19% increase in production and the 14%
increase in realized natural gas prices. Correspondingly, for the first nine
months of 2004, the 32% increase in operating revenues was a combination of the
19% increase in production and the 11% increase in realized natural gas prices
as our loss from hedging activities narrowed for the nine-month period by $21.8
million. Production Volume The 19% 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
from Transworld Exploration and Production Inc. Onshore, our daily production rates increased 8% from an average of 172 MMcfe
per day during the third quarter of 2003 to 185 MMcfe per day during the third
quarter of 2004 despite our loss of approximately 8 MMcfe per day or 5% for the
current quarter as a result of the divesture of our South Louisiana and
Appalachian Basin properties during the first half of 2004. In the Arkoma
Basin, we are experiencing the full impact of the accelerated drilling program
initiated in 2003 as we added 14 MMcfe per day in newly developed production.
With three rigs drilling since the beginning of 2004, Arkoma production reached
a record of 38 MMcfe per day during the third quarter compared to 24 MMcfe per
day during the third quarter of 2003. In South Texas, with six rigs drilling,
we also experienced production growth as we added approximately 7 MMcfe per
day. South Texas production increased to an average of 145 MMcfe per day
during the third quarter of 2004 compared to 138 MMcfe per day in the third
quarter of 2003. Offshore, our production increased 36% from an average of 116 MMcfe per day
during the third quarter of 2003 to an average of 158 MMcfe per day during the
third quarter of 2004. We added 51 MMcfe per day in newly developed
production, of which 28 MMcfe per day was attributable to development drilling
at High Island A283. During the quarter, we completed and brought on-line our
seventh 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 30 MMcfe per day of our third quarter
offshore production increase. Offsetting the increases from the newly
developed and the acquired production were declines 21




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from existing and maturing fields totaling 39 MMcfe per day. Sequentially,
from second quarter 2004 to third quarter 2004, offshore production declined
from an average of 160 MMcfe per day to 158 MMcfe per day. The third quarter
decline is a direct result of the deferral of approximately 210,000 or 2 MMcfe
per day caused by shut-ins for Hurricane Ivan in September 2004. All of our
shut-in production has been fully restored. For the nine-month period ended September 30, 2004, our total average daily
production increased 18% from 290 MMcfe per day during the first nine months of
2003 to 342 MMcfe per day during the corresponding nine-month period of 2004.
During the first nine months of 2004, we divested of a net 3 MMcfe per day with
the sale of our South Louisiana properties in February and the exchange of our
Appalachian Basin properties in June and we added 12 MMcfe per day in Arkoma, 6
MMcfe per day in South Texas and 37 MMcfe per day offshore. Offshore, the
increase is comprised of:  
    
    46 MMcfe per day in newly developed production from new wells brought
on-line since the end of the third quarter of 2003 at High Island 47,
A283 and 115; Galveston Island 389/424 and 390; Eugene Island 159 and
East Cameron 280;
    
    30 MMcfe per day in acquired production as a result of the Transworld
acquisition in mid-October 2003; offset in part by,
    
    a decline of 39 MMcfe per 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 $4.84
per Mcf during the third quarter of 2003 to $5.46 per Mcf during the third
quarter 2004. Included in natural gas revenues for the third quarter of 2004 is a loss of
$11.7 million from natural gas hedging activities, which includes an unrealized
loss of $0.9 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 third quarter of 2004 of $5.06 per Mcf that was 93% or $0.40 lower
than our average sales price. For the third quarter of 2003, we incurred a
hedge loss from natural gas derivatives of $9.7 million resulting in an average
realized price of $4.45 per Mcf that was 92% or $0.39 per Mcf lower than our
sales price. For the first nine months of 2004, the increase in our realized price for
natural gas was primarily a result of the narrowing of our losses from hedging
activities for the period as average sales prices increased slightly by 3% from
an average of $5.45 per Mcf during the first nine months of 2003 to $5.59 Mcf
during the first nine months of 2004. Our natural gas hedge loss for the first
nine months of 2004 of $38.2 million decreased by 36% or by $21.5 million from
the loss of $59.7 million during the first nine months of 2003. For the first
nine months of 2004, our realized price was 92% or $0.44 per Mcf lower than our
average unhedged natural gas price, which compares to a realized price during
the first nine months of 2003 that was 85% or $0.81 per Mcf lower than the
unhedged price. Operating Expenses Overall, on an absolute dollar basis, our total operating expenses increased by
35% during the third quarter of 2004 and by 33% for the current nine-month
period and on a unit of production basis, by 14% for the quarter and 13% for
the period. The increase in total operating expenses is a result of continued
growth and expansion of operations as our production base has grown on a
compound basis through drilling and acquisitions. Lease operating expense is
higher primarily as a result of our fourth quarter 2003 Gulf of Mexico
acquisition. Severance taxes are slightly lower primarily as a result of the
disposition of our Appalachian Basin and South Louisiana assets during the
first half of 2004. Depreciation, amortization and depletion expense is higher
due to higher finding and development costs. And, general and administrative
expenses are higher due to expansion of our workforce combined with an increase
in employee benefit and incentive compensation expenses. 22




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##### Table of Contents



Three Months Ended September 30,
    
    Nine Months Ended September 30,Operating Expenses per Mcfe
    
    2004
    
    2003
    
    Variance
    
    2004
    
    2003
    
    VarianceLease operating expense
    
    $
    0.45
    
    
    $
    0.39
    
    
    $
    0.06
    
    
    
    15
    %
    
    $
    0.42
    
    
    $
    0.42
    
    
    $
    
    
    
    
    
    %Severance tax
    
    
    0.11
    
    
    
    0.13
    
    
    
    (0.02
    )
    
    
    -15
    %
    
    
    0.11
    
    
    
    0.14
    
    
    
    (0.03
    )
    
    
    -21
    %Transportation expense
    
    
    0.10
    
    
    
    0.10
    
    
    
    
    
    
    
    
    %
    
    
    0.10
    
    
    
    0.10
    
    
    
    
    
    
    
    
    %Asset retirement accretion expense
    
    
    0.03
    
    
    
    0.03
    
    
    
    
    
    
    
    
    %
    
    
    0.04
    
    
    
    0.03
    
    
    
    0.01
    
    
    
    33
    %Depreciation, depletion and amortization
    
    
    2.12
    
    
    
    1.78
    
    
    
    0.34
    
    
    
    19
    %
    
    
    2.08
    
    
    
    1.78
    
    
    
    0.30
    
    
    
    17
    %General and administrative, net
    
    
    0.18
    
    
    
    0.20
    
    
    
    (0.02
    )
    
    
    -10
    %
    
    
    0.23
    
    
    
    0.17
    
    
    
    0.06
    
    
    
    35
    %Total operating expenses per unit of
production
    
    $
    2.99
    
    
    $
    2.63
    
    
    $
    0.36
    
    
    
    14
    %
    
    $
    2.98
    
    
    $
    2.64
    
    
    $
    0.34
    
    
    
    13
    %
 Lease Operating Expense. On an absolute dollar basis, lease operating expense
increased by 40% for the third quarter of 2004 and by 18% for the nine-month
period. During 2004, we have experienced higher lease operating expenses
primarily as a result of our fourth quarter 2003 Gulf of Mexico acquisition and
the continuing maturation of our existing property base. While expenses during
2004 are at higher levels than in the previous year, the 19 % increase in
production volume for both the current quarter and nine-month period has
resulted in lower than expected per unit expense as expenses are spread over a
greater production base. For the third quarter of 2004, the $0.06 or 15%
increase in lease operating expense per Mcfe was due to workover expenses
incurred during the current quarter and an increase in ad valorem taxes. Ad
valorem taxes are higher as property valuations have increased during 2004 as a
result of sustained higher commodity prices. For the nine-month period, lease
operating expense per Mcfe is unchanged at $0.42. Severance Tax. Severance tax is a function of volume and revenues generated
from onshore production. Severance tax decreased by 3% quarter-over-quarter
and by 6% period-over-period. On an Mcfe basis, severance tax decreased by
$0.02 or 15% for the quarter and by $0.03 of 21% for the nine-month period.
Despite the increase in Arkoma production (our South Texas properties are
exempt or taxed at reduced rates because of their high-cost/tight-sand
designation received in July 2002) and higher wellhead prices, severance tax
expense is lower primarily as a result of the disposition of our Appalachian
Basin and South Louisiana assets during the first half of 2004. Depreciation, Depletion and Amortization. The increase in our depreciation,
depletion and amortization expense for the current quarter and the first nine
months of 2004 was primarily a result of a higher depletion rate combined with
a 19% increase in production for the current quarter and for the current
nine-month period. The increase in our depletion rate is primarily a result of
higher finding costs and fewer reserve additions. During the first nine months
of 2004, we drilled a total of 25 dry holes, of which 19 were development wells
and six were exploratory. In addition, for the third 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 based on interim internal reserves
estimates, represented 51.2 Bcfe in total net proved reserves as of June 1,
2004. Asset Retirement Accretion Expense.The increase in ARO accretion expense
during the third quarter of 2004 and the nine month period is primarily a
result of additions to our ARO liability since the end of the third quarter of
2003 of approximately $36.8 million from the acquisition of the Gulf of Mexico
properties in October 2003, West Virginia properties in December 2003 and Gulf
of Mexico properties during the third quarter of 2004 offset in part by $17.0
million in reductions during the first nine months of 2004 as a result of
abandonment of offshore properties and the disposition of our South Louisiana
properties in February 2004 and our Appalachian Basin properties in June 2004. General and Administrative Expenses, Net of Overhead Reimbursements and
Capitalized General and Administrative Expenses Three Months Ended September 30,
    
    Nine Months Ended September 30,General and Administrative per Mcfe
    
    2004
    
    2003
    
    Variance
    
    2004
    
    2003
    
    VarianceGross general and administrative expense
    
    $
    0.32
    
    
    $
    0.34
    
    
    $
    (0.02
    )
    
    
    -6
    %
    
    $
    0.37
    
    
    $
    0.31
    
    
    $
    0.06
    
    
    
    19
    %Operating overhead reimbursements
    
    
    (0.02
    )
    
    
    (0.01
    )
    
    
    (0.01
    )
    
    
    100
    %
    
    
    (0.02
    )
    
    
    (0.01
    )
    
    
    (0.01
    )
    
    
    100
    %Capitalized general and administrative
    
    
    (0.12
    )
    
    
    (0.12
    )
    
    
    
    
    
    
    
    %
    
    
    (0.12
    )
    
    
    (0.12
    )
    
    
    
    
    
    
    
    %General and administrative expense, net
    
    $
    0.18
    
    
    $
    0.21
    
    
    $
    (0.03
    )
    
    
    -14
    %
    
    $
    0.23
    
    
    $
    0.18
    
    
    $
    0.05
    
    
    
    28
    %
 23




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##### Table of Contents



For the quarter, net general and administrative expenses on an absolute dollar
basis are up by 4%. Aggregate general and administrative expenses are 13%
higher for the third quarter of 2004 primarily as a result of increases in
employee benefits and incentive and stock compensation expenses. The increase
in incentive compensation is a function of the companys performance and our
ability to meet established objectives for the year. The increase in stock
compensation expense is a result of our adoption of the fair value expense
provisions for stock options under SFAS 123, as amended, in January 2003.
While general and administrative expenses are increasing as our company
continues to grow, the decrease in general and administrative expense per Mcfe
of $0.02 for the current quarter is a result of the increase in production
volume. For the nine-month period, net general and administrative expenses are up by
59% on an absolute dollar basis. In addition to increases in payroll,
benefits, stock option and incentive compensation expenses, more than half of
the percentage increase for the current nine-month period was due to
approximately $4.4 million in additional compensation expenses incurred during
the second quarter of 2004 as a result of the KeySpan Exchange transaction.
The additional compensation expenses 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 $0.05 increase for the first nine months of 2004.
Excluding the effect of the additional compensation expenses, gross general and
administrative expense for the first nine months of 2004 would have been $0.32
per Mcfe and net general and administrative expense would have been $0.18
reflecting increases of $0.01 or 3% for gross general and administrative
expense per Mcfe and no change for net general and administrative expenses per
Mcfe. Other Income and Expense, Interest and Taxes Other Income and Expense. For the third quarter of 2004, other income and
expense is comprised of refunds relating to prior years severance tax expense
of $1.6 million ($1.0 million net of tax) that compares to $6.2 million ($4.0
million net of tax) recorded during the third quarter of 2003. 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. For 2004,
the recognition of other income as a result of the recoupment of prior years
expense is considerably less than in 2003 as we are nearing the end of the
recoupment process. For the nine month period of 2004, Other Income and
Expense includes two items: (i) income of $2.1 million ($1.4 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 during the second quarter of 2004. 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 corresponding nine months of
2003, Other Income and Expense includes: (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 8?% senior subordinated notes due
2008; and (ii) income of $19.1 million ($12.4 million net of tax) related to
refunds of prior years severance tax expense. Interest Expense, Net of Capitalized Interest. Three Months Ended September 30,
    
    Nine Months Ended September 30,Interest and Average Borrowings
    
    2004
    
    2003
    
    Variance
    
    2004
    
    2003
    
    Variance(in thousands)Gross interest
    
    $
    4,162
    
    
    $
    3,868
    
    
    $
    294
    
    
    
    8
    %
    
    $
    12,771
    
    
    $
    11,486
    
    
    $
    1,285
    
    
    
    11
    %Capitalized interest
    
    
    (2,162
    )
    
    
    (2,026
    )
    
    
    (136
    )
    
    
    7
    %
    
    
    (6,178
    )
    
    
    (5,218
    )
    
    
    (960
    )
    
    
    18
    %Interest expense, net of capitalized
    
    $
    2,000
    
    
    $
    1,842
    
    
    $
    158
    
    
    
    9
    %
    
    $
    6,593
    
    
    $
    6,268
    
    
    $
    325
    
    
    
    5
    %Average borrowings
    
    $
    265,207
    
    
    $
    194,908
    
    
    $
    70,299
    
    
    
    36
    %
    
    $
    269,920
    
    
    $
    224,665
    
    
    $
    45,255
    
    
    
    20
    %Average interest rate
    
    
    5.79
    %
    
    
    7.20
    %
    
    
    (1.41
    )%
    
    
    -20
    %
    
    
    5.69
    %
    
    
    6.29
    %
    
    
    (0.60
    )%
    
    
    -10
    %
 For the third quarter of 2004, the increase in gross interest expense is due to
an increase in bank borrowings offset in part by a decrease in our average
interest rate. Bank debt averaged $90 million at a rate of 3.6 % during the
third quarter of 2004 compared to an average of $20 million at 2.50% during the
third quarter of 2003. Bank debt was higher during the current quarter
primarily as a result of borrowings during the second quarter of 2004 used to
fund a portion of the KeySpan Exchange transaction completed in June. For the
nine-month period of 2004, the increase in gross interest expense is due to an
increase in both fixed debt and bank debt offset in part by a decrease in
average interest rates. Our fixed debt increased 24




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##### Table of Contents



in June 2003 when we replaced our existing senior subordinated notes of $100
million at 8?% with new senior subordinated notes of $175 million at 7%. Bank
borrowings averaged $95 million at a rate if 3.46% during the first nine months
of 2004 compared to an average of $85 million at 3.42% for the first nine
months of 2003. Bank debt has increased as we utilized our revolving bank
credit facility to fund not only a portion of the KeySpan Exchange in June 2004
but also several producing property acquisitions since the end of the third
quarter of 2003. Capitalized interest is a function of unevaluated properties
and the increase for the current quarter and the nine-month period of 2004
corresponds to the increase in our average unevaluated property balance for
these periods. The increase in unevaluated property is primarily a result of
our October 2003 acquisition of Gulf of Mexico producing properties from
Transworld combined with an increase in projects in-progress as of the end of
the current period. Income Tax Provision.Our provision for taxes includes both state and federal
taxes. For the current year, our state tax obligations have increased as our
onshore revenues have increased and as we have expanded our operations into
several Rocky Mountain States. The 34% increase in income taxes for the third
quarter of 2004 corresponds to the 27% increase in income before taxes. Our
current provision increased to $7.9 million as we utilized all of our net
operating loss carryforwards during 2003 and moved to a tax paying status.
Prior to the third quarter of 2003, the majority of our federal income taxes
were deferred. For the nine-month period of 2004 income taxes increased by
30%, which corresponds to the 22% increase in income before taxes. Our current
provision for the nine-month period increased to $32.6 million and 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. 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. At the regular quarterly meeting of our Board of Directors held on October 22,
2004, the 2004 capital expenditure budget was increased by $185 million from an
initial level of $315 million to $500 million. The increase will cover
additional exploration and development expenditures as well as the BP and Orca
producing property acquisitions. 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. However, with increasing service
costs we may find it advantageous in the future to contract a drilling rig or
well service with some type of guarantee that would obligate us to a minimum
level of activity. 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 nine months of 2004, we invested $301.4 million in natural gas
and oil properties, which includes $30 million for the BP acquisition completed
in September, and $1.0 million in other property and equipment. We divested
$73.4 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. In addition, we invested $11.4 million in the form of a
deposit toward the acquisition of additional producing natural gas and oil
properties that was completed on October 29, 2004 (see Note 5  Acquisitions
and Dispositions  Orca Acquisition.) During the first nine months of 2004, we completed the drilling of 167 gross
wells (139.6 net) of which 85% or 142 (119.0 net) were successful and 25 (20.6
net) were unsuccessful, with an additional 10 wells (8.5 net) in progress at
the end of the period. During the third quarter, we drilled 68 gross wells
(58.2 net) of which 85% or 58 (49.8 net) were successful and 10 (8.4 net) were
unsuccessful. The table below details the components of our natural gas and
oil expenditures during each of three-month and nine-month periods ended
September 30, 2004 and 2003.  25




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##### Table of Contents



Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,Natural Gas and Oil Expenditures:
    
    2004
    
    2003
    
    2004
    
    2003(in thousands)Producing property acquisitions
    
    $
    30,042
    
    
    $
    
    
    
    $
    32,742
    
    
    $
    Leasehold and lease acquisition costs (1)
    
    
    17,427
    
    
    
    17,186
    
    
    
    44,063
    
    
    
    45,458Development
    
    
    63,858
    
    
    
    44,139
    
    
    
    180,558
    
    
    
    122,906Exploration
    
    
    25,327
    
    
    
    12,630
    
    
    
    44,026
    
    
    
    43,347Total natural gas and oil capital expenditures
    
    
    136,654
    
    
    
    73,955
    
    
    
    301,389
    
    
    
    211,711Producing property dispositions
    
    
    (287
    )
    
    
    
    
    
    
    (72,854
    )
    
    
    Net natural gas and oil capital expenditures
    
    $
    136,367
    
    
    $
    73,955
    
    
    $
    228,535
    
    
    $
    211,711
   (1)
    
    For the three months ended September 30, 2004 and 2003, leasehold costs
include capitalized interest and general and administrative expenses of
$6.0 million and $5.1 million, respectively. For the corresponding
nine-month periods of 2004 and 2003, capitalized interest and general and
administrative expenses included in leasehold costs totaled $17.8 million
and $14.9 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 September 30, 2004. In
addition to the contractual obligations listed on the table below, our balance
sheet at September 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 $7 million to $10
million during the fourth quarter of 2004. At September 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
    
    $
    80,000
    
    
    $
    
    
    
    $
    
    
    
    $
    80,000
    
    
    $
    7% senior subordinated notes, due June 2013
    
    
    175,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    175,000Operating leases
    
    
    7,437
    
    
    
    394
    
    
    
    4,499
    
    
    
    2,544
    
    
    
    Producing property acquisition  Orca, payable
October 29, 2004 (1)
    
    
    109,800
    
    
    
    109,800
    
    
    
    
    
    
    
    
    
    
    
    372,237
    
    
    
    110,194
    
    
    
    4,499
    
    
    
    82,544
    
    
    
    175,000Other Long-Term Obligations:Asset retirement obligations
    
    
    91,540
    
    
    
    3,679
    
    
    
    8,284
    
    
    
    16,303
    
    
    
    63,274Total contractual obligations and commitments
    
    $
    463,777
    
    
    $
    113,873
    
    
    $
    12,783
    
    
    $
    98,847
    
    
    $
    238,274
   (1)
    
    See Note 7  Subsequent Events  Orca Acquisition. 26




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##### Table of Contents



Capital Resources We intend to fund our capital expenditure program and contractual commitments
through cash flows from our operations and borrowings under our revolving bank
credit facility. If 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 nine 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, producing property acquisitions and to reduce debt
under our revolving bank credit facility. We made aggregate cash payments of
$8.6 million for interest and $35.9 million for taxes. The following table summarizes the sources of cash during each of the
nine-month periods ended September 30, 2004 and 2003: Nine Months Ended September 30,2004
    
    2003
    
    Variance
    
    % change(in thousands)Net income
    
    $
    128,038
    
    
    $
    105,339
    
    
    $
    22,699
    
    
    
    22
    %Non-cash charges
    
    
    251,059
    
    
    
    204,521
    
    
    
    46,538
    
    
    
    23
    %Cash from operations before changes in operating
assets and liabilities
    
    
    379,097
    
    
    
    309,860
    
    
    
    69,237
    
    
    
    22
    %Decrease (increase) in operating assets and liabilities
    
    
    28,833
    
    
    
    (11,769
    )
    
    
    40,602
    
    
    
    -345
    %Net cash provided by operating activities
    
    
    407,930
    
    
    
    298,091
    
    
    
    109,839
    
    
    
    37
    %Net cash (used) for investments in property and
equipment
    
    
    (240,305
    )
    
    
    (227,933
    )
    
    
    (12,372
    )
    
    
    5
    %Net cash (used) in financing activities
    
    
    (165,873
    )
    
    
    (74,990
    )
    
    
    (90,883
    )
    
    
    121
    %Net increase (decrease) in cash
    
    $
    1,752
    
    
    $
    (4,832
    )
    
    $
    6,584
    
    
    
    -136
    %
 At September 30, 2004, we had a working capital deficit of $85.0 million,
long-term debt of $255 million (which includes $80 million in bank debt), and
$259.6 million of borrowing capacity available under our revolving bank credit
facility. The working capital deficit was primarily a result of a current
liability of $119.5 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 nine
months of 2004 was primarily attributable to the increase in operating income
primarily as a result of the 19% increase in production for the current year
combined with the 11% 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 $272.4 million of capacity remaining under this shelf
registration statement. On October 27, 2004, we filed a second shelf registration statement with the
SEC for the offering, from time to time, of up to an additional $477.4 million
of our stock or debt securities, which registration has not been declared
effective by the SEC. The prospectus for the second shelf registration
statement will include the unused portion of the shelf registration statement
filed in March 2004 of $272.4 million together with the registration of the
remaining 6,580,392 shares of our common stock held by KeySpan. The
combination of the two shelf registrations statements will provide an aggregate
of $750 million for the offering of our common stock, preferred stock,
depositary shares and debt securities, or a combination of any of these
securities. 27




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##### Table of Contents



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
future property acquisitions, should attractive opportunities arise, we believe
we could finance the additional capital expenditures with cash on hand,
operating cash flow, additional borrowing under our revolving bank credit
facility, issuances of additional equity or debt securities or development with
industry partners. 
 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 nine months of
2004, we recognized $2.6 million of ineffectiveness, of which $0.9 million was
recognized during the third 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. Subsequent to the balance sheet date, the fair value of our open derivative
contracts increased beyond our available credit limit with one counterparty.
As a result, in October 2004, we were required to issue letters of credit
totaling $8.1 million to further guarantee our performance on open derivative
contracts. 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 nine-month periods from January 1 to September 30,
2004 and 2003, and provides the fair value at the end of each period. Nine Months Ended
    
    Nine Months EndedSeptember 30, 2004
    
    September 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
    
    
    35,620
    
    
    
    23,153
    
    
    
    60,102
    
    
    
    39,066Unrealized (gain) loss due to ineffectiveness of contracts
    
    
    2,600
    
    
    
    1,690
    
    
    
    
    
    
    
    Fair value of new contracts when entered into during
period
    
    
    
    
    
    
    
    
    
    
    5,288
    
    
    
    3,437(Decrease) in fair value of all open contracts
    
    
    (152,100
    )
    
    
    (98,865
    )
    
    
    (38,919
    )
    
    
    (25,297
    )Fair value of contracts outstanding at September 30
    
    $
    (150,742
    )
    
    $
    (97,982
    )
    
    $
    (12,301
    )
    
    $
    (7,996
    )
 28




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##### Table of Contents



Derivatives in Place as of the Date of Our Report The following table summarizes, our natural gas hedges in place for 2004, 2005,
2006, 2007 and 2008. For the remaining three months of 2004, we estimate that
approximately 70% of our expected future production is hedged and for calendar
2005, we have hedged approximately 74% of our expected future production.
Volumes listed in the table below represent daily volumes. Natural Gas Hedges
    
    Fixed Price Swaps
    
    CollarsNYMEX
    
    
    
    
    
    NYMEXDaily
    
    
    
    
    
    DailyVolume
    
    Contract
    
    Volume
    
    Contract Price(1)Period
    
    (MMBtu)
    
    Price
    
    (MMBtu)
    
    Floor
    
    CeilingOctober  December 2004
    
    
    40,000
    
    
    $
    4.960
    
    
    
    200,000
    
    
    $
    4.125
    
    
    $
    6.023January  December 2005
    
    
    80,000
    
    
    
    5.304
    
    
    
    180,000
    
    
    
    4.833
    
    
    
    6.434January  December 2006
    
    
    30,000
    
    
    
    5.893
    
    
    
    60,000
    
    
    
    5.500
    
    
    
    7.248January  December 2007
    
    
    
    
    
    
    
    
    
    
    30,000
    
    
    
    5.000
    
    
    
    6.597January  December 2008
    
    
    
    
    
    
    
    
    
    
    20,000
    
    
    
    5.000
    
    
    
    5.720
   (1)
    
    For collars, price represents a weighted average for outstanding
contracts. 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 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 September 30, 2004, our
disclosure controls and procedures are functioning effectively as designed.
There have been no significant 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 5. Other information. On October 22, 2004, the Compensation Committee of our Board of Directors
granted to each of our nine executive officers a combination of restricted
stock and options. These grants were annual grants made as part of each
executives annual 29




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##### Table of Contents



compensation package as defined under the terms of each executives employment
agreement with our company. The grants were made pursuant to the terms of our
2004 Long-Term Incentive Plan that was approved by stockholders in June 2004.
We received waivers from all nine of our executive officers that under terms of
the waiver allowed us to issue to each executive a combination of restricted
stock and stock options that was equal in value to a grant of only stock
options. Waivers were received from Messrs. Hargett, Adcock, Karnes, Lindsey,
Mueller, Price, Rice, Schwartz and Westmoreland. 
 Item 6. Exhibits: Exhibits
    
    
    
    Description10.1
    
    
    
    Purchase and Sale Agreement, dated September 17, 2004, between
The Houston Exploration Company and Orca Energy, L.P. (filed
as exhibit 2.1 to our Current Report on Form 8-K dated
November 1, 2004 (File No. 007-11899) and incorporated by
reference).10.2
    
    
    
    Rights Agreement, dated as of August 12, 2004, between The
Houston Exploration Company and The Bank of New York, as
Rights Agent (filed as exhibit 4.1 to our Current Report on
Form 8-K dated August 13, 2004 (File No. 007-11899) and
incorporated by reference).10.3
    
    
    
    Form of Certificate of Designation of Series A Junior
Participation Preferred Stock of The Houston Exploration
Company (filed as exhibit 4.2 to our Current Report on Form
8-K dated August 13, 2004 (File No. 007-11899) and
incorporated by reference).10.4(*)
    
    
    
    Form of waiver to employment agreement between The Houston
Exploration Company and its executive officers allowing
restricted stock awards in addition to stock option awards.12.1(*)
    
    
    
    Statement of computation of ratio of earnings to fixed charges.31.1(*)
    
    
    
    Certification of William G. Hargett, Chief Executive Officer,
as required pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.31.2(*)
    
    
    
    Certification of John H. Karnes, Senior Vice President and
Chief Financial Officer, as required pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.32.1(*)
    
    
    
    Certification of William G. Hargett, Chief Executive Officer,
as required pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.32.2(*)
    
    
    
    Certification of John H. Karnes, Senior Vice President and
Chief Financial Officer, as required pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.(*)
    
    
    
    filed herewith
 30




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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: November 4, 2004
    
    
    
    William G. HargettChairman, President and Chief Executive OfficerBy:
    
    /s/ John H. KarnesDate: November 4, 2004
    
    
    
    John H. KarnesSenior Vice President and Chief Financial OfficerBy:
    
    /s/ James F. WestmorelandDate: November 4, 2004
    
    
    
    James F. WestmorelandVice President and Chief Accounting Officer
 31




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##### Table of Contents



Exhibit Index Exhibits
    
    
    
    Description10.1
    
    
    
    Purchase and Sale Agreement, dated September 17, 2004, between
The Houston Exploration Company and Orca Energy, L.P. (filed
as exhibit 2.1 to our Current Report on Form 8-K dated
November 1, 2004 (File No. 007-11899) and incorporated by
reference).10.2
    
    
    
    Rights Agreement, dated as of August 12, 2004, between The
Houston Exploration Company and The Bank of New York, as
Rights Agent (filed as exhibit 4.1 to our Current Report on
Form 8-K dated August 13, 2004 (File No. 007-11899) and
incorporated by reference).10.3
    
    
    
    Form of Certificate of Designation of Series A Junior
Participation Preferred Stock of The Houston Exploration
Company (filed as exhibit 4.2 to our Current Report on Form
8-K dated August 13, 2004 (File No. 007-11899) and
incorporated by reference).10.4
    
    
    
    Form of waiver to employment agreement between The Houston
Exploration Company and its executive officers allowing
restricted stock awards in addition to stock option awards.12.1(*)
    
    
    
    Statement of computation of ratio of earnings to fixed charges.31.1(*)
    
    
    
    Certification of William G. Hargett, Chief Executive Officer,
as required pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.31.2(*)
    
    
    
    Certification of John H. Karnes, Senior Vice President and
Chief Financial Officer, as required pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.32.1(*)
    
    
    
    Certification of William G. Hargett, Chief Executive Officer,
as required pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.32.2(*)
    
    
    
    Certification of John H. Karnes, Senior Vice President and
Chief Financial Officer, as required pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.(*)
    
    
    
    filed herewith