UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2004

OR

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

For the transition period from                    to                    

Commission File No. 001-11899

THE HOUSTON EXPLORATION COMPANY

1100 Louisiana Street, Suite 2000
Houston, Texas 77002-5215
(Address of principal executive offices and zip code)

(713) 830-6800
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

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

As of May 6, 2004, 31,883,703 shares of Common Stock, par value $.01 per share, were outstanding.

THE HOUSTON EXPLORATION COMPANY

TABLE OF CONTENTS

2

Forward Looking Statements

All of the estimates and assumptions contained in this Quarterly Report constitute forward looking statements as that term is defined in Section 27A of the Securities Act of 1993,as amended and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements generally can be identified by words such as “anticipate,” “believe,” “expect,” “continue,” “estimate,” “project” or similar expressions. All statements under the caption “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” relating to our future production, expected costs and expenses, anticipated capital expenditures, future cash flows and borrowings, pursuit of potential future acquisition opportunities and sources of funding and the timing of exploration and development are forward looking statements. Although we believe that these forward-looking statements are based on reasonable assumptions, our expectations may not occur and we can not guarantee that the anticipated future results will be realized.

A number of factors could cause our actual future results to differ materially from those anticipated or implied in the forward-looking statements. These factors include, among other things:

	•		the volatility of natural gas and oil prices;
	•		the requirement to take writedowns if natural gas and oil prices decline or if our finding and development costs continue to increase;
	•		our ability to find, develop and acquire natural gas and oil reserves;
	•		the successfulness of our acquisition and investment activities;
	•		our ability to meet our substantial capital requirements;
	•		our outstanding indebtedness may restrict our financial flexibility;
	•		the uncertainty of estimates of natural gas and oil reserves and production rates;
	•		the inherent hazards and risks involved in our operations;
	•		the concentrated nature of our operations;
	•		our hedging activities could result in financial losses or reductions to income;
	•		our compliance with environmental and other governmental regulations;
	•		the competitive nature of our industry;
	•		our customers’ ability to meet their obligations; and
	•		potential conflicts with our majority stockholder, KeySpan Corporation.

For additional discussion of these risks, uncertainties and assumptions, see “Items 1. and 2. Business and Properties” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K. We undertake no obligation to publicly update or revise any forward-looking statements.

In this Quarterly Report, unless the context requires otherwise, when we refer to “we,” “us” or “our”, we are describing The Houston Exploration Company and its subsidiary on a consolidated basis.

3

Part I. Financial Information

Item 1. Consolidated Financial Statements (unaudited)

THE HOUSTON EXPLORATION COMPANY

The accompanying notes are an integral part of these consolidated financial statements.

4

THE HOUSTON EXPLORATION COMPANY

The accompanying notes are an integral part of these consolidated financial statements.

5

THE HOUSTON EXPLORATION COMPANY

The accompanying notes are an integral part of these consolidated financial statements.

6

THE HOUSTON EXPLORATION COMPANY

NOTE 1 — Summary of Organization and Significant Accounting Policies

Our Business

We are an independent natural gas and oil company engaged in the exploration, development, exploitation and acquisition of natural gas and oil reserves in North America. Natural gas is our primary focus. Our areas of operations are South Texas, offshore in the shallow waters of the Gulf of Mexico, the Arkoma Basin of Oklahoma and Arkansas and the Appalachian Basin of West Virginia. During 2003, we began operations in the Rocky Mountain Region, with an initial focus in the Uinta Basin of northeastern Utah.

We were founded in December 1985 and began exploring for natural gas and oil on behalf of KeySpan Corporation. KeySpan, a member of the Standard & Poor’s 500 Index, is a diversified energy provider whose principal natural gas distribution and electric generation operations are located in the Northeastern United States. In September 1996 we completed our initial public offering and sold approximately 31% of our shares to the public. As of March 31, 2004, THEC Holdings Corp., an indirect wholly owned subsidiary of KeySpan, owned approximately 55% of the outstanding shares of our common stock or 17.4 million shares. KeySpan has publicly announced that it considers its investment in Houston Exploration a non-core asset and that it continues to review strategic alternatives for its investment in our company including the sale of all or a portion of its investment in our common stock.

Principles of Consolidation

The consolidated financial statements include our accounts and the accounts of our wholly owned subsidiary, Seneca Upshur Petroleum Company, which is in the exploration and production business in West Virginia. All significant inter-company balances and transactions have been eliminated.

Interim Financial Statements

Our balance sheet at March 31, 2004 and the statements of operations and cash flows for the periods indicated herein have been prepared without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been condensed or omitted, although we believe that the disclosures contained herein are adequate to make the information presented not misleading. The balance sheet at December 31, 2003 is derived from the December 31, 2003 audited financial statements, but does not include all disclosures required by GAAP. The financial statements included herein should be read in conjunction with the Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2003.

In the opinion of our management, these financial statements reflect all adjustments necessary for a fair statement of the results for the interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. The results of operations for such interim periods are not necessarily indicative of the results for the full year.

Use of Estimates

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Our most significant financial estimates are based on remaining proved natural gas and oil reserves. Estimates of proved reserves are key components of our depletion rate for natural gas and oil properties and our full cost ceiling test limitation. Because there are numerous uncertainties inherent in the estimation process, actual results could differ materially from these estimates.

Business Segment Information

The Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) 131, “Disclosures about Segments of an Enterprise and Related Information” establishes standards for reporting information about operating segments. All of our operations involve the exploration, development and production of natural gas and oil

7

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

and all of our operations are located in the United States. We have a single, company-wide management team that administers all properties as a whole rather than as discrete operating segments. We measure financial performance as a single enterprise and not on an area-by-area basis. Consequently, while we compile and analyze basic operational data by area, we do not prepare separate financial statement information by area and are not, therefore, required to report separate business segment information under SFAS 131.

Revenue Recognition

We use the entitlements method of accounting for the recognition of natural gas and oil revenues. Under this method of accounting, income is recorded based on our net revenue interest in production or nominated deliveries. We incur production gas volume imbalances in the ordinary course of business. Net deliveries in excess of entitled amounts are recorded as liabilities, while net under deliveries are reflected as assets. Imbalances are reduced either by subsequent recoupment of over-and under deliveries or by cash settlement, as required by applicable contracts. Production imbalances are marked-to-market at the end of each month using market prices as of the end of the period.

Net Income Per Share

Basic earnings per share is calculated by dividing net income by the weighted average number of shares of common stock outstanding during the period. No dilution for any potentially dilutive securities is included. Fully diluted earnings per share is calculated by applying the treasury stock method to adjust the average number of common shares outstanding for the dilutive effect, if any, of the assumed conversion of potentially convertible securities.

For the three months ended March 31, 2004 and 2003, the calculation of potentially dilutive securities does not include the effect of outstanding stock options to purchase 1,585,960 and 1,903,561 shares, respectively, as the assumed conversion of these shares would have been antidulitive.

8

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

Comprehensive Income

The table below summarizes our Comprehensive Income for the three month and nine month periods ended March 31, 2004 and 2003, respectively.

Natural Gas and Oil Properties

Full Cost Accounting. We use the full cost method to account for our natural gas and oil properties. Under full cost accounting, all costs incurred in the acquisition, exploration and development of natural gas and oil reserves are capitalized into a “full cost pool.” Capitalized costs include costs of all unproved properties, internal costs directly related to our natural gas and oil activities and capitalized interest. We amortize these costs using a unit-of-production method. We compute the provision for depreciation, depletion and amortization quarterly by multiplying production for the quarter by a depletion rate. The depletion rate is determined by dividing our total unamortized cost base by net equivalent proved reserves at the beginning of the quarter. Our total unamortized cost base is the sum of our:

	•		full cost pool; plus,
	•		estimates for future development costs; less,
	•		unevaluated properties and their related costs; less,
	•		estimates for salvage.

Costs associated with unevaluated properties are excluded from the amortization base until we have made a determination as to the existence of proved reserves. We review our unevaluated properties at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and thereby subject to amortization. Sales of natural gas and oil properties are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.

Under full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of future net revenues, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties less income tax effects (the “ceiling limitation”). We perform a quarterly ceiling test to evaluate whether the net book value of our full cost pool exceeds the ceiling limitation. If capitalized costs (net of accumulated depreciation, depletion and amortization) less related deferred taxes are greater than the discounted future net revenues or ceiling limitation, a writedown or impairment of the full cost pool is required. A writedown of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation, depletion and amortization expense in future periods. Once incurred, a writedown is not reversible at a later date.

The ceiling test is calculated using natural gas and oil prices in effect as of the balance sheet date and adjusted for “basis” or location differential, held constant over the life of the reserves. We use derivative financial instruments that qualify for cash flow hedge accounting under SFAS 133 to hedge against the volatility of natural gas prices, and in accordance with Securities and Exchange Commission guidelines, we include estimated future cash flows from our hedging program in our ceiling test calculation.

Unevaluated Properties. The costs associated with unevaluated properties and properties under development are not initially included in the amortization base and relate to unproved leasehold acreage, seismic data, wells and production facilities in-progress and wells pending determination together with interest costs capitalized for these projects. Unevaluated leasehold costs are transferred to the amortization base with the costs of drilling the related well or upon expiration of a lease. Costs of seismic data are allocated to various unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis. Costs associated with successful wells in-progress and

9

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

wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. All items included in our unevaluated property balance are assessed on a quarterly basis for possible impairment or reduction in value. We estimate these costs will be evaluated within a four-year period.

Classification of Intangible Leasehold Costs

SFAS 141, “Business Combinations” and SFAS 142, “Goodwill and Intangible Assets,” became effective on July 1, 2001 and January 1, 2002, respectively. These new standards emphasize a more precise evaluation of assets and their balance sheet classification as either tangible or intangible assets. We understand that the issue is under evaluation as to whether provisions of SFAS 141 and SFAS 142 may call for mineral rights held under lease or other contractual arrangements together with cash costs for the acquisition of natural gas and oil leasehold interests to be classified in the balance sheet as intangible assets. If these types of leasehold costs (both proved and unevaluated) are determined to be intangible assets, they would be classified separately from natural gas and oil properties as intangible assets on our balance sheets. This issue relates only to balance sheet classification and presentation and we do not believe it will not have an effect on cash flows or results of operations. At March 31, 2004, if we applied the interpretation currently under discussion, undeveloped leasehold costs of $125.4 million and developed leasehold costs of $207.1 million, net of accumulated amortization, would be reclassified from tangibles to intangibles, representing costs incurred since June 30, 2001, the effective date of SFAS 141. At December 31, 2003, we had undeveloped leasehold costs of $117.1 million and developed leasehold costs of $221.3 million, net of accumulated amortization, that would be reclassified from tangibles to intangibles. Consistent with current industry practice, we will continue to classify our natural gas and oil leasehold costs as tangible natural gas and oil properties until the Emerging Issues Task Force (“EITF”) issues further guidance.

Although the EITF has not issued formal guidance to oil and gas companies, at the March 2004 meeting, the EITF reached a consensus that mineral rights for mining companies should be accounted for as tangible assets. However, the effective date of that consensus is pending until the resolution of a perceived inconsistency between the characterization of mineral rights as tangible assets in this consensus and the characterization of mineral rights as intangible assets in SFAS 141 and SFAS 142. In order to resolve this inconsistency, FASB plans to prepare a FASB Staff Position (FSP) that will amend SFAS 141 and SFAS 142. The consensus will be effective when the FSP has been finalized.

Asset Retirement Obligations

On January 1, 2003, we adopted SFAS 143, “Accounting for Asset Retirement Obligations,” which addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. For us, asset retirement obligations represent the systematic, monthly accretion and depreciation of future abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities. SFAS 143 requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized and an adjustment is made to the full cost pool. Under our previous accounting method, we included estimated future costs of abandonment and dismantlement in our full cost amortization base and amortized these costs as a component of our depletion expense.

10

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

The following table describes the various components of our asset retirement liability during each of the three month periods ending March 31, 2004 and 2003, respectively. ARO liability includes amounts classified as both current and long-term.

Derivative Instruments and Hedging Activities

To reduce our exposure to adverse price fluctuations, we plan to hedge between 70 and 80 percent of our estimated future production volume for 2004 and 2005. Our hedging policy does not permit us to hold derivative instruments for trading purposes. In our hedging program, we utilize a variety of derivative instruments, including swaps, collars and options. We generally place contracts with major financial institutions and other credit worthy counterparties. Although our hedging program protects a portion of our cash flows from downward price movements, certain hedging strategies, specifically the use of swaps and collars, may also limit our ability to realize the full benefit of future price increases. In addition, because our derivative instruments are typically indexed to New York Mercantile Exchange (“NYMEX”) prices as opposed to the index price where the gas is actually sold, our hedging strategy may not protect our cash flows if the price differential increases between the NYMEX price and index price for the point of sale.

Our derivative instruments are designated cash flow hedges and qualify for hedge accounting under SFAS 133, as amended, “Accounting for Derivative Instruments and Hedging Activities” and, accordingly, we carry the fair market value of our derivative instruments on the balance sheet as either an asset or liability and defer unrealized gains or losses in accumulated other comprehensive income. Gains and losses are reclassified from accumulated other comprehensive income to the income statement as a component of natural gas and oil revenues in the period the hedged production occurs. If any ineffectiveness occurs, amounts are recorded directly to the income statement. For the first three months of 2004, our net income includes an unrealized loss of $1.0 million ($0.7 million net of tax) representing the ineffective portion of our derivative instruments that were not eligible for deferral. The ineffectiveness was a result of changes at the end of current period in the price differentials between the index price of the derivative contract, which uses a NYMEX index, and index price for the point of sale for the cash flow that is being hedged, the majority of which is the Houston Ship Channel index.

Based on market prices at March 31, 2004, we recorded an unrealized loss in other comprehensive income of $83.8 million ($54.2 million net of tax). Any loss will be realized in future earnings at the time of the related sales of natural gas production applicable to specific hedges. If prices in effect at March 31, 2004 were to hold, a loss of $63.5 million ($41.3 million net of tax) would be realized over the next 12-month period. However, these amounts could vary materially as a result of changes in market conditions.

Accounting for Stock Options

On January 1, 2003, we adopted the fair value expense recognition provisions of SFAS 123, “Accounting for Stock Based Compensation,” as amended by SFAS 148, “Accounting for Stock — Based Compensation — Transition and Disclosure” using the “prospective method” as defined by the SFAS 148. As a result, we now record as compensation expense the fair value of all stock options issued subsequent to January 1, 2003. No expense has been or will be recorded for grants made in previous years.

For the three months ended March 31, 2004 and 2003, we recognized gross compensation expense of $455,000 and $14,000, respectively, for stock options granted during these periods.

11

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

Prior to our January 1, 2003 adoption of SFAS 123, we accounted for the incentive stock plans using the intrinsic value method prescribed under Accounting Principles Board Opinion No. 25 and accordingly, we did not recognize compensation expense for stock options granted. Had stock options been accounted for using the fair value method as recommended in SFAS 123, compensation expense would have had the following pro forma effect on our net income and earnings per share for the three month periods ended March 31, 2004 and 2003. Amounts are in thousands except per share data.

NOTE 2 — Long-Term Debt and Notes

The carrying amount of borrowings outstanding under the revolving bank credit facility approximates fair value as the interest rates are tied to current market rates. At March 31, 2004, the quoted market value of our $175 million of 7% senior subordinated notes was 97.7% of the $175 million carrying value or $170.9 million.

Revolving Bank Credit Facility

We maintain a revolving bank credit facility with a syndicate of lenders led by Wachovia Bank, National Association, as issuing bank and administrative agent, The Bank of Nova Scotia and Fleet National Bank as co-syndication agents and BNP Paribas and Comerica Bank as co-documentation agents. The credit facility was amended on April 1, 2004 and, as amended, provides us with a commitment of $400 million which may be increased at our request and with prior approval from Wachovia to a maximum of $450 million by adding one or more lenders or by allowing one or more lenders to increase their commitments. The credit facility is subject to borrowing base limitations. Pursuant to the April 1, 2004 amendment, our borrowing base was increased from $300 million to $375 million. The $375 million borrowing base is expected to remain in effect until the next scheduled redetermination on October 1, 2004. Up to $40 million of the borrowing base is now available for the issuance of letters of credit, which was increased from $25 million pursuant to the April 1, 2004 amendment. Outstanding borrowings continue to be unsecured and with the exception of trade payables, the facility ranks senior in right of payment to our $175 million 7% subordinated notes. The amended facility matures on April 1, 2008. At March 31, 2003, we had $70 million in outstanding borrowings under the credit facility and $0.4 million in outstanding letter of credit obligations.

Interest rates, margins and terms of payment remained unchanged from prior periods pursuant to the April 1, 2004 amendment. Interest is payable on borrowings under our revolving bank credit facility, as follows:

12

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

	•		on base rate loans, at a fluctuating rate, or base rate, equal to the sum of (a) the greater of the Federal funds rate plus 0.5% or Wachovia’s prime rate plus (b) a variable margin between 0% and 0.50%, depending on the amount of borrowings outstanding under the credit facility, or
	•		on fixed rate loans, a fixed rate equal to the sum of (a) a quoted LIBOR rate divided by one minus the average maximum rate during the interest period set for certain reserves of member banks of the Federal Reserve System in Dallas, Texas plus (b) a variable margin between 1.25% and 2.00%, depending on the amount of borrowings outstanding under the credit facility.

Interest is payable on base rate loans on the last day of each calendar quarter. Interest on fixed rate loans is generally payable at maturity or at least every 90 days if the term of the loan exceeds three months. In addition to interest, we must pay a quarterly commitment fee of between 0.30% and 0.50% per annum on the unused portion of the borrowing base.

Our revolving bank credit facility contains customary negative covenants that place restrictions and limits on, among other things, the incurrence of debt, guaranties, liens, leases and certain investments. The credit facility also restricts and limits our ability to pay cash dividends, to purchase or redeem our stock and to sell or encumber our assets. Financial covenants require us to, among other things:

	•		maintain a ratio of earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”) to cash interest payments of at least 3.00 to 1.00;
	•		maintain a ratio of total debt to EBITDA of not more than 3.50 to 1.00; and
	•		not hedge more than 85% of our natural gas production during any 12-month period, which was increased, pursuant to the April 1, 2004 amendment, from 80% during 2003 and 2004, and not more than 70% during any 12-month period after 2004.

At March 31, 2004 and December 31, 2003, we were in compliance with all covenants.

Senior Subordinated Notes

On June 10, 2003, we issued $175 million of 7% senior subordinated notes due June 15, 2013. The notes bear interest at a rate of 7% per annum with interest payable semi-annually on June 15 and December 15, beginning December 15, 2003. We may redeem the notes at our option, in whole or in part, at any time on or after June 15, 2008 at a price equal to 100% of the principal amount plus accrued and unpaid interest, if any, plus a specified premium which decreases yearly from 3.5% in 2008 to 0% in 2011 and thereafter. In addition, at any time prior to June 15, 2006, we may re