================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2002 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM__________ TO__________ COMMISSION FILE NO. 001-11899 --------------------------------- THE HOUSTON EXPLORATION COMPANY (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) DELAWARE 22-2674487 (STATE OR OTHER JURISDICTION OF (IRS EMPLOYER IDENTIFICATION NO.) INCORPORATION OR ORGANIZATION) 1100 LOUISIANA STREET, SUITE 2001 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 [X] No [ ] As of April 29, 2002, 30,498,580 shares of Common Stock, par value $.01 per share, were outstanding. ================================================================================ THE HOUSTON EXPLORATION COMPANY TABLE OF CONTENTS Page ---- FACTORS AFFECTING FORWARD LOOKING STATEMENTS..................................................................... 3 Part I. FINANCIAL INFORMATION................................................................................... 4 Item 1. Consolidated Financial Statements (unaudited)........................................................... 4 CONSOLIDATED BALANCE SHEETS -- March 31, 2002 and December 31, 2001..................................... 4 CONSOLIDATED STATEMENTS OF OPERATIONS -- Three Months Ended March 31, 2002 and 2001.............................................................................. 5 CONSOLIDATED STATEMENTS OF CASH FLOWS -- Three Months Ended March 31, 2002 and 2001.............................................................................. 6 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations...................13 Item 3. Quantitative and Qualitative Disclosures About Market Risk...............................................19 PART II. OTHER INFORMATION.......................................................................................22 Item 6. Exhibits and Reports on Form 8-K:.......................................................................22 (a) Exhibits:.........................................................................................22 (b) Reports on Form 8-K:..............................................................................22 SIGNATURES.......................................................................................................23 -2- FACTORS AFFECTING FORWARD LOOKING STATEMENTS All of the estimates and assumptions contained in this Quarterly Report and in the documents we have incorporated by reference into this Quarterly Report constitute forward looking statements as that term is defined in Section 27A of the Securities Act of 1993 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements generally are accompanied by words such as "anticipate," "believe," "expect," "estimate," "project" or similar expressions. All statements under the caption "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" relating to our anticipated capital expenditures, future cash flows and borrowings, pursuit of potential future acquisition opportunities and sources of funding for exploration and development are forward looking statements. Although we believe that these forward-looking statements are based on reasonable assumptions, our expectations may not occur and we cannot guarantee that the anticipated future results will be achieved. A number of factors could cause our actual future results to differ materially from the anticipated future results expressed in this Quarterly Report. These factors include, among other things, the volatility of natural gas and oil prices, the requirement to take write downs if natural gas and oil prices decline, our ability to meet our substantial capital requirements, our substantial outstanding indebtedness, the uncertainty of estimates of natural gas and oil reserves and production rates, our ability to replace reserves, and our hedging activities. 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 10K. 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 CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA) MARCH 31, DECEMBER 31, 2002 2001 ----------- ----------- (UNAUDITED) ASSETS: Cash and cash equivalents........................................................... $ 182 $ 8,619 Accounts receivable................................................................. 56,652 43,847 Accounts receivable -- Affiliate.................................................... 2,021 635 Derivative financial instruments.................................................... 7,257 53,771 Inventories......................................................................... 1,202 1,149 Prepayments and other............................................................... 1,193 2,959 ------------ ------------ Total current assets........................................................... 68,507 110,980 Natural gas and oil properties, full cost method Unevaluated properties........................................................... 156,609 177,987 Properties subject to amortization............................................... 1,561,338 1,493,293 Other property and equipment........................................................ 9,142 8,265 ------------ ------------ 1,727,089 1,679,545 Less: Accumulated depreciation, depletion and amortization.......................... (780,618) (740,784) ---------- ---------- 946,471 938,761 Other assets........................................................................ 7,724 9,351 ------------ ------------ TOTAL ASSETS................................................................... $ 1,022,702 $ 1,059,092 =========== =========== LIABILITIES: Accounts payable and accrued expenses............................................... $ 62,006 $ 76,666 ------------ ----------- Total current liabilities...................................................... 62,006 76,666 Long-term debt and notes............................................................ 249,000 244,000 Derivative financial instruments.................................................... 5,128 -- Deferred federal income taxes....................................................... 160,733 172,169 Other deferred liabilities.......................................................... 333 376 -------------- ------------- TOTAL LIABILITIES.............................................................. 477,200 493,211 COMMITMENTS AND CONTINGENCIES (SEE NOTE 3) STOCKHOLDERS' EQUITY: Common Stock, $.01 par value, 50,000,000 shares authorized and 30,498,580 shares issued and outstanding at March 31, 2002 and 30,463,230 shares issued and outstanding at December 31, 2001, respectively........................ 305 305 Additional paid-in capital.......................................................... 337,610 336,977 Unearned compensation............................................................... (171) (192) Retained earnings................................................................... 206,374 193,840 Accumulated other comprehensive income.............................................. 1,384 34,951 ----------- ------------- TOTAL STOCKHOLDERS' EQUITY..................................................... 545,502 565,881 ---------- ---------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY..................................... $1,022,702 $1,059,092 ========== ========== The accompanying notes are an integral part of these consolidated financial statements. -4- THE HOUSTON EXPLORATION COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE DATA) THREE MONTHS ENDED MARCH 31, 2002 2001 --------- --------- (UNAUDITED) REVENUES: Natural gas and oil revenues............................................... $ 72,446 $ 123,996 Other...................................................................... 194 346 --------- --------- Total revenues........................................................... 72,640 124,342 OPERATING EXPENSES: Lease operating............................................................ 7,413 6,245 Severance tax.............................................................. 1,692 4,714 Depreciation, depletion and amortization................................... 39,804 30,219 General and administrative, net............................................ 3,340 7,965 --------- --------- Total operating expenses................................................. 52,249 49,143 Income from operations........................................................ 20,391 75,199 Other (income) and expense.................................................... -- (1,381) Interest expense, net......................................................... 1,410 1,927 --------- --------- Income before income taxes.................................................... 18,981 74,653 Provision for federal income taxes............................................ 6,447 27,309 --------- --------- NET INCOME.................................................................... $ 12,534 $ 47,344 ========= ========= Net income per share.......................................................... $ 0.41 $ 1.58 ========= ========= Net income per share -- assuming dilution..................................... $ 0.41 $ 1.55 ========= ========= Weighted average shares outstanding........................................... 30,485 29,963 Weighted average shares outstanding -- assuming dilution...................... 30,837 30,502 The accompanying notes are an integral part of these consolidated financial statements -5- THE HOUSTON EXPLORATION COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS) THREE MONTHS ENDED MARCH 31, 2002 2001 ----------- --------- (UNAUDITED) OPERATING ACTIVITIES: Net income................................................................... $ 12,534 $ 47,344 Adjustments to reconcile net income to net cash provided by Operating activities: Depreciation, depletion and amortization..................................... 39,804 30,219 Deferred income tax expense.................................................. 6,639 27,519 Stock compensation expense................................................... 21 -- Changes in operating assets and liabilities: (Increase)decrease in accounts receivable................................. (14,191) 39,437 Increase in inventories................................................... (53) (324) Decrease(increase) in prepayments and other............................... 1,766 (862) Decrease in other assets and liabilities.................................. 1,584 78 Decrease in accounts payable and accrued expenses......................... (14,660) (30,274) ----------- --------- Net cash provided by operating activities.................................... 33,444 113,137 INVESTING ACTIVITIES: Investment in property and equipment......................................... (47,760) (63,024) Dispositions ................................................................ 246 -- ----------- --------- Net cash used in investing activities........................................ (47,514) (63,024) FINANCING ACTIVITIES: Proceeds from long term borrowings........................................... 9,000 57,000 Repayments of long term borrowings........................................... (4,000) (102,000) Proceeds from issuance of common stock....................................... 633 2,882 ----------- --------- Net cash used in financing activities........................................ 5,633 (42,118) Decrease(increase) in cash and cash equivalents.............................. (8,437) 7,995 Cash and cash equivalents, beginning of period............................... 8,619 9,675 Cash and cash equivalents, end of period..................................... $ 182 $ 17,670 =========== ========= Cash paid for interest....................................................... $ 5,553 $ 7,280 =========== ========= Cash paid for taxes.......................................................... $ -- $ -- =========== ========= The accompanying notes are an integral part of these consolidated financial statements. -6- THE HOUSTON EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) NOTE 1 -- SUMMARY OF ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES Organization We are an independent natural gas and oil company engaged in the exploration, development, exploitation and acquisition of domestic natural gas and oil properties. Our operations are currently focused offshore in the Gulf of Mexico and onshore in South Texas, the Arkoma Basin of Oklahoma and Arkansas, South Louisiana, the Appalachian Basin in West Virginia and East Texas. Our strategy is to utilize our technical expertise to continue to increase reserves, production and cash flows through the application of a three-pronged approach that combines an effective mix of: o high potential offshore exploration and exploitation; o lower risk, high impact exploitation and development drilling onshore; and o selective opportunistic acquisitions both offshore and onshore At December 31, 2001, our net proved reserves were 608 billion cubic feet equivalent or Bcfe, with a discounted present value of cash flows before income taxes of $714 million. Our focus is natural gas. Approximately 93% of our net proved reserves at December 31, 2001 were natural gas of which approximately 74% of our net proved reserves were classified as proved developed. We operate approximately 85% of our properties. We began exploring for natural gas and oil in December 1985 on behalf of The Brooklyn Union Gas Company. Brooklyn Union is an indirect wholly owned subsidiary 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. As of March 31, 2002, THEC Holdings Corp., an indirect wholly owned subsidiary of KeySpan, owned approximately 67% of the outstanding shares of our common stock. Principles of Consolidation The consolidated financial statements include the accounts of The Houston Exploration Company and its wholly owned subsidiary, Seneca Upshur Petroleum Company (collectively the "Company"). All significant intercompany balances and transactions have been eliminated. Interim Financial Statements Our balance sheet at March 31, 2002 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 generally accepted accounting principles 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, 2001 is derived from the December 31, 2001 audited financial statements, but does not include all disclosures required by generally accepted accounting principles. The Interim Financial Statements 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, 2001. In the opinion of our management, all adjustments, consisting of normal recurring accruals, necessary to present fairly the information in the accompanying financial statements have been included. The results of operations for such interim periods are not necessarily indicative of the results for the full year. Reclassifications and Use of Estimates The preparation of the consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and -7- THE HOUSTON EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 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. Certain reclassifications of prior year items have been made to conform with current year presentation. New Accounting Pronouncements Statement of Financial Accounting Standards "SFAS" No. 143, "Accounting for Asset Retirement Obligations," addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 will be effective for us January 1, 2003 and early adoption is encouraged. SFAS No. 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 and the corresponding cost capitalized by increasing 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. Currently, we include estimated future costs of abandonment and dismantlement in our full cost amortization base and amortize these costs as a component of our depletion expense. We are evaluating the impact the new standard will have on our financial statements. Hedging Contracts We utilize derivative commodity instruments to hedge future sales prices on a portion of our natural gas production in order to achieve a more predictable cash flow and to reduce our exposure to adverse price fluctuations. 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 from possible favorable price movements. Hedging instruments that we use include swaps, costless collars and options, which we generally place with major financial institutions that we believe are minimal credit risks. Our hedging strategies meet the criteria for hedge accounting treatment under SFAS No. 133, "Accounting for Derivative and Hedging Activities". Accordingly, we mark-to-market our derivative instruments at the end of each quarter, and defer the effective portion of the gain or loss on the change in fair value of our derivatives in Accumulated Other Comprehensive Income, a component of Stockholders' Equity. We recognize gains and losses when the underlying transaction is completed, at which time these gains and losses are reclassified from accumulated other comprehensive income and included in earnings as a component of natural gas revenues in accordance with the underlying hedged transaction. If hedging instruments cease to meet the criteria for deferred recognition, any gains or losses would be currently recognized in earnings. At March 31, 2002, we estimated, using the New York Mercantile Exchange, or NYMEX, index price strip as of that date that the fair market value of our derivative instruments was $2.1 million. As a result, our balance sheet at March 31, 2002 reflects an asset of $7.2 million, representing the current portion of our hedge position and a liability of $5.1, representing the long-term portion of our hedge position with a corresponding credit of $1.4 million (net of related deferred taxes of $0.7 million) in accumulated other comprehensive income, representing the fair market value of our total deferred hedge gain. At December 31, 2001, we estimated, using the NYMEX, index price strip as of that date that the fair market value of our derivative instruments was $53.8 million. As a result, our balance sheet at December 31, 2001 reflects an asset of $53.8 million with a corresponding credit of $34.9 million (net of related deferred taxes of $18.9 million) in accumulated other comprehensive income, representing the fair market value of our deferred hedge gain. -8- THE HOUSTON EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) Net Income Per Share Basic earnings per share ("EPS") 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. Diluted EPS assumes the conversion of all potentially dilutive securities and is calculated by dividing net income, as adjusted, by the weighted average number of shares of common stock outstanding plus all potentially dilutive securities. THREE MONTHS ENDED MARCH 31, 2002 2001 --------------- -------------- (IN THOUSANDS, EXCEPT PER SHARE DATA) Net income....................................... $ 12,534 $ 47,344 =============== ============== Weighted average shares outstanding.............. 30,485 29,963 Add dilutive securities: Options..................................... 352 539 --------------- -------------- Total weighted average shares outstanding and dilutive securities....................................... 30,837 30,502 =============== ============== Net income per share............................. $ 0.41 $ 1.58 ============== ============== Net income per share - assuming dilution......... $ 0.41 $ 1.55 ============== ============== Comprehensive Income The table below summarizes our Comprehensive Income for the three months ended March 31, 2002 and 2001. THREE MONTHS ENDED MARCH 31, 2002 2001 --------------- -------------- (IN THOUSANDS) Net income....................................... $ 12,534 $ 47,344 Other comprehensive income, net of taxes: Unrealized loss on derivative instruments (33,567) (5,298) --------------- -------------- Comprehensive income............................. $ (21,033) $ 42,046 =============== ============== NOTE 2 -- LONG-TERM DEBT AND NOTES MARCH 31, 2002 DECEMBER 31, 2001 -------------- ----------------- (IN THOUSANDS) SENIOR DEBT: Bank revolving credit facility, due 2003......... $ 149,000 $ 144,000 SUBORDINATED DEBT: 8 5/8% Senior Subordinated Notes, due 2008....... 100,000 100,000 --------------- ----------------- Total long-term debt and notes.............. $ 249,000 $ 244,000 =============== ================= The carrying amount of borrowings outstanding under the revolving bank credit facility approximates fair value as the interest rates are tied to current market rates. At March 31, 2002, the quoted market value of the Company's $100 million of 8 5/8% Senior Subordinated Notes was 99.6% of the $100 million carrying value or $99.6 million. -9- THE HOUSTON EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) Credit Facility We maintain a revolving bank credit facility with a syndicate of lenders led by JPMorgan Chase, National Association. The credit facility, as amended, provides a maximum commitment of $250 million, subject to borrowing base limitations. At March 31, 2002, the borrowing base amount was $250 million. Up to $2.0 million of the borrowing base is available for the issuance of letters of credit to support performance guarantees. The credit facility matures on April 15, 2003 and is unsecured. At March 31, 2002, $149 million was outstanding under the credit facility and $0.4 million was outstanding in letter of credit obligations. Subsequent to March 31, 2002, we increased our net borrowings by an additional $1 million, bringing total borrowings and letters of credit to $150.4 million as of April 26, 2002. Interest is payable on borrowings under the credit facility, at our option, at: o a fluctuating rate, or base rate, equal to the greater of the Federal Funds rate plus 0.5% or JP Morgan Chase's prime rate, or o a fixed rate equal to a quoted LIBOR rate plus a variable margin of 0.875% to 1.625%, depending on the amount outstanding under the credit facility. Interest is payable at calendar quarters for base rate loans and at the earlier of maturity or three months from the date of the loan for fixed rate loans. In addition, the credit facility requires a commitment fee of: o between 0.25% and 0.375% per annum on the unused portion of the designated borrowing base, and o an additional fee equal to 33% of the commitment fee on the daily average amount by which the total amount of commitments exceeds the designated borrowing base. The credit facility contains covenants, including restrictions on liens and financial covenants which require us to, among other things, maintain: o an interest coverage ratio of 2.5 to 1.0 of earnings before interest, taxes and depreciation to cash interest; o a total debt to capitalization ratio of less than 60%, exclusive of non-cash charges; and o sets a maximum limit of 70% on the amount of natural gas production we may hedge during any 12-month period. In addition to maintenance of financial ratios, the credit facility restricts cash dividends and/or purchase or redemption of our stock. The credit facility also restricts the encumbering of our oil and gas assets or the pledging of those assets as collateral. As of March 31, 2002, we were in compliance with all covenants. Senior Subordinated Notes On March 2, 1998, we issued $100 million of 8 5/8% senior subordinated notes due January 1, 2008. The notes bear interest at a rate of 8 5/8% per annum with interest payable semi-annually on January 1 and July 1. We may redeem the notes at our option, in whole or in part, at any time on or after January 1, 2003 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 4.313% in 2003 to 0% after January 1, 2006 if the notes are redeemed prior to January 1, 2006. 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, if any. A "change of control" is: o 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; -10- THE HOUSTON EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) o 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; o the adoption of a plan relating to our liquidation or dissolution; or o if, during any period of two consecutive years, individuals who at the beginning of this period constituted our board of directors, including any new directors who were approved by a majority vote of the stockholders, cease for any reason to constitute a majority of the members then in office. The notes are general unsecured obligations and rank subordinate in right of payment to all existing and future senior debt, including the credit facility, and will rank senior or equal in right of payment to all existing and future subordinated indebtedness. NOTE 3 -- COMMITMENTS AND CONTINGENCIES We are involved from time to time in various claims and lawsuits incidental to our business. In the opinion of management, the ultimate liability, if any, will not have a material adverse effect on our financial position or results of operations. NOTE 4 -- RELATED PARTY TRANSACTIONS KeySpan Joint Venture Effective January 1, 1999, together with KeySpan, we entered into a joint exploration agreement with KeySpan Exploration & Production, LLC, a subsidiary of KeySpan, to explore for natural gas and oil over an initial two-year term expiring December 31, 2000. Under the terms of the joint venture, we contributed all of our then undeveloped offshore acreage to the joint venture and KeySpan received 45% of our working interest in all prospects drilled under the program. KeySpan paid 100% of actual intangible drilling costs for the joint venture up to a specified maximum of $7.7 million in 2000 and $20.7 million during 1999 and KeySpan paid 51.75% of all additional intangible drilling costs incurred and we paid 48.25%. Revenues are shared 55% Houston Exploration and 45% to KeySpan. In addition, we received reimbursements from KeySpan for a portion of our general and administrative costs. Effective December 31, 2000, KeySpan and Houston Exploration agreed to end the primary or exploratory term of the joint venture. As a result, KeySpan will not participate in any of our offshore exploration prospects unless the project involves the development or further exploitation of discoveries made during the initial term of the joint venture. In addition, effective with the termination of the exploratory term of the joint venture, we will not receive any reimbursement from KeySpan for general and administrative costs. During the initial two-year term of the joint drilling program, we drilled a total of 21 wells under the terms of the joint venture: 17 exploratory wells and four development wells. Five of the wells drilled were unsuccessful. During 2001, KeySpan participated in three additional wells, all of which were successful and further developed or delineated reservoirs discovered during the initial term of the joint venture. For 2002, KeySpan has committed to a capital budget of $15 million for development projects associated with its working interests in wells drilled under the joint venture during 1999, 2000 and 2001. During the first three months of 2002, KeySpan participated in three wells and spent $9.5 million in capital costs compared to $2.7 million spent during the first three months of 2001. All three wells were successful and provided further exploitation of previous discoveries. -11- THE HOUSTON EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) NOTE 5 -- SUBSEQUENT EVENTS Burlington Acquisition. On April 19, 2002, we agreed to purchase from Burlington Resources Inc. natural gas and oil producing properties and associated gathering pipelines, together with undeveloped acreage, located in the Webb, Jim Hogg, Wharton and Calhoun counties of South Texas. The properties purchased cover approximately 24,800 gross (10,800 net) acres located in the North East Thompsonville, South Laredo, McFarlan and Maude Traylor Fields. The properties purchased represent interests in approximately 146 producing wells and total proved reserves of 42 Bcfe as of January 1, 2002, the effective date of the transaction. Our average working interest is 35% and we will operate approximately 23% of the producing wells acquired. The $48.1 million purchase price, which is subject to a purchase price adjustment at the closing of the transaction scheduled for May 31, 2002, will be financed by borrowings under our revolving bank credit facility. Current production (for the month of March 2002) is averaging 16.0 MMcfe/day, net to the interests acquired. -12- ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion is intended to assist in an understanding of our historical financial position and results of operations for the three months ended March 31, 2002 and 2001. Our consolidated financial statements and notes thereto included elsewhere in this report contains detailed information that should be referred to in conjunction with the following discussion. GENERAL We are an independent natural gas and oil company engaged in the exploration, development, exploitation and acquisition of domestic natural gas and oil properties. Our operations are currently focused offshore in the Gulf of Mexico and onshore in South Texas, the Arkoma Basin of Oklahoma and Arkansas, South Louisiana, the Appalachian Basin in West Virginia and East Texas. Our strategy is to utilize our technical expertise to continue to increase reserves, production and cash flows through the application of a three-pronged approach that combines an effective mix of: o high potential offshore exploration and exploitation; o lower risk, high impact exploitation and development drilling onshore; and o selective opportunistic acquisitions both offshore and onshore At December 31, 2001, our net proved reserves were 608 billion cubic feet equivalent or Bcfe, with a discounted present value of cash flows before income taxes of $714 million. Our focus is natural gas. Approximately 93% of our net proved reserves at December 31, 2001 were natural gas of which approximately 74% of our net proved reserves were classified as proved developed. We operate approximately 85% of our properties. We began exploring for natural gas and oil in December 1985 on behalf of The Brooklyn Union Gas Company. Brooklyn Union is an indirect wholly owned subsidiary 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. As of March 31, 2002, THEC Holdings Corp., an indirect wholly owned subsidiary of KeySpan, owned approximately 67% of the outstanding shares of our common stock. As an independent oil and gas producer, our revenue, profitability and future rate of growth are substantially dependent upon prevailing prices for natural gas and oil, our ability to find and produce hydrocarbons and our ability to control and reduce costs, all of which are dependent upon numerous factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. The energy markets have historically been very volatile, as evidenced by the recent volatility of natural gas and oil prices, and there can be no assurance that commodity prices will not widely fluctuate in the future. A substantial or extended decline in natural gas and oil prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of natural gas and oil reserves that may be economically produced and access to capital. Critical Accounting Policies and Use of Estimates 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. Unevaluated properties and related costs are excluded from our amortization base until we have made a determination as to the existence of proved reserves. Our amortization base includes estimates for future development costs as well as future abandonment and dismantlement costs. -13- Under full cost accounting rules, total capitalized costs are limited to a ceiling of the present value of future net revenues, discounted at 10%, 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 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, held constant over the life of the reserves. We use derivative financial instruments that qualify for hedge accounting under Statement of Financial Accounting Standards ("SFAS") No. 133 to hedge against the volatility of natural gas prices, and in accordance with current Securities and Exchange Commission guidelines, we include estimated future cash flows from our hedging program in our ceiling test calculation. In calculating our ceiling test at March 31, 2002, we estimated that we had a full cost ceiling "cushion", whereby the carrying value of our full cost pool was less that the ceiling limitation. No writedown is required when a cushion exists. Natural gas prices continue to be volatile and the risk that we will be required to write down our full cost pool increases when natural gas prices are depressed or if we have significant downward revisions in our estimated proved reserves. Use of Estimates. The preparation of the consolidated financial statements in conformity with generally accepted accounting principles requires our 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 Natural gas and oil reserve quantities represent estimates only. Under full cost accounting, we use reserve estimates to determine our full cost ceiling limitation as well as our depletion rate. We estimate our proved reserves and future net revenues using sales prices estimated to be in effect as of the date we make the reserve estimates. We hold the estimates constant throughout the life of the properties, except to the extent a contract specifically provides for escalation. Natural gas prices, which have fluctuated widely in recent years, affect estimated quantities of proved reserves and future net revenues. Any estimates of natural gas and oil reserves and their values are inherently uncertain, including many factors beyond our control. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based upon actual production, results of future development and exploration activities, prevailing natural gas and oil prices, operating costs and other factors, which revision may be material. Reserve estimates are highly dependent upon the accuracy of the underlying assumptions. Actual future production may be materially different from estimated reserve quantities and the differences could materially affect future amortization of natural gas and oil properties. New Accounting Pronouncements Statement of Financial Accounting Standards "SFAS" No. 143, "Accounting for Asset Retirement Obligations," addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 will be effective for us January 1, 2003 and early adoption is encouraged. SFAS No. 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 and the corresponding cost capitalized by increasing 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. Currently, we include estimated future costs of abandonment and dismantlement in our full cost amortization base and amortize these costs as a component of our depletion expense. We are evaluating the impact the new standard will have on our financial statements. -14- Recent Acquisitions Within the last four months, we have expanded our existing operations in South Texas with two producing property acquisitions. Over the last five years, South Texas has been an area providing strategic growth in both reserves and production for our company. Together, these two acquisitions have added approximately 122 Bcfe in total proved reserves and will add an estimated 35 MMcfe/day in average daily production Burlington Acquisition. On April 19, 2002, we agreed to purchase from Burlington Resources Inc. natural gas and oil producing properties and associated gathering pipelines, together with undeveloped acreage, located in the Webb, Jim Hogg, Wharton and Calhoun counties of South Texas. The properties purchased cover approximately 24,800 gross (10,800 net) acres located in the North East Thompsonville, South Laredo, McFarlan and Maude Traylor Fields. The properties purchased represent interests in approximately 146 producing wells and total proved reserves of 42 Bcfe as of January 1, 2002, the effective date of the transaction. Our average working interest will be 35% and we will operate approximately 23% of the producing wells acquired. The $48.1 million purchase price, which is subject to a purchase price adjustment at the closing of the transaction scheduled for May 31, 2002, will be financed by borrowings under our revolving bank credit facility. Current production (for the month of March 2002) is averaging 16.0 MMcfe/day, net to the interests acquired. Conoco Acquisition. On December 31, 2001, we completed the purchase from Conoco Inc. of natural gas and oil properties and associated gathering pipelines and equipment, together with developed and undeveloped acreage, located in the Webb and Zapata counties of South Texas. The $69 million cash purchase price was financed by borrowings under our revolving bank credit facility. The properties purchased cover approximately 25,274 gross (16,885 net) acres located in the Alexander, Haynes, Hubbard and South Trevino Fields, which are in close proximity to our existing operations in the Charco Field, and represent interests in approximately 159 producing wells. We operate approximately 95% of the producing wells we acquired. Our average working interest is 87%. Total proved reserves as of January 1, 2002 were 80 Bcfe and current production (for the month of March 2002) is averaging 19.0 MMcfe/day, net to our interest. Beginning January 1, 2002, we initiated an active drilling and workover program. To date we drilled nine development wells, with six wells successfully completed, one dry hole and two in progress. Currently we have two drilling rigs under contract, which we plan to keep utilized for the remainder of 2002. -15- RESULTS OF OPERATIONS The following table sets forth our historical natural gas and oil production data during the periods indicated: THREE MONTHS ENDED MARCH 31, 2002 2001 -------- -------- PRODUCTION: Natural gas (MMcf).......................... 23,895 22,095 Oil (MBbls)................................. 160 112 Total (MMcfe)............................... 24,855 22,767 Average daily production (MMcfe/day)........ 276 253 AVERAGE SALES PRICES: Natural gas (per Mcf) realized(1)........... $ 2.90 $ 5.48 Natural gas (per Mcf) unhedged.............. 2.19 6.86 Oil (per Bbl)............................... 19.28 25.58 OPERATING EXPENSES (PER MCFE): Lease operating............................. $ 0.30 $ 0.27 Severance tax............................... 0.07 0.21 Depreciation, depletion and amortization.... 1.60 1.33 General and administrative, net(2).......... 0.13 0.35 ----------------------- (1) Reflects the effects of hedging. (2) For the three months ended March 31, 2001, includes one-time payments in connection with the termination of employment contracts for retiring executives. RECENT FINANCIAL AND OPERATING RESULTS COMPARISON OF THREE MONTHS ENDED MARCH 31, 2002 AND 2001 Production. Our production increased 9% from 22,767 million cubic feet equivalent, or MMcfe, for the three months ended March 31, 2001 to 24,855 MMcfe for the three months ended March 31, 2002. The increase in production was primarily attributable to newly developed offshore production brought on-line since the end of the first quarter of 2001 combined with newly acquired onshore production pursuant to the December 31, 2001 acquisition of properties in South Texas from Conoco Inc. Offshore, our production increased 6% from an average of 126 MMcfe/day during the first quarter of 2001 to an average of 134 MMcfe/day during the first quarter of 2002. This increase is primarily attributable to new natural gas production at South March Island 253 and High Island 39, both of which came on-line during the second half of 2001, combined with new oil production at Vermilion 408, which came on-line during January 2002. Onshore, our daily production rates increased 12% from an average of 127 MMcfe/day during the first quarter of 2001 to an average of 142 MMcfe/day during the corresponding three months of 2002. The onshore production increase is primarily attributable to newly acquired production from the South Texas properties purchased from Conoco Inc. on December 31, 2001, which accounts for 19 MMcfe/day of the increase, offset in part by a combined 4 MMcfe/day decrease in production from our existing onshore properties, primarily as a result of a drop in production from our Charco Field which produced at an average rate of 93 MMcfe/day during the first quarter of 2001 compared to an average of 87 MMcfe/day during the first quarter of 2002. Natural Gas and Oil Revenues. Natural gas and oil revenues decreased 42% from $124.0 million for the first three months of 2001 to $72.4 million for the first three months of 2002 as a result of a 47% decrease in average realized natural gas prices, from $5.48 per Mcf during the first quarter of 2001 to $2.90 per Mcf in the first quarter -16- of 2002, offset in part by a 9% increase in production for the same period. Natural Gas Prices. As a result of hedging activities, we realized an average gas price of $2.90 per Mcf for the three months ended March 31, 2002, which was 132% of the average unhedged natural gas price of $2.19 that otherwise would have been received, resulting in natural gas and oil revenues for the three months ended March 31, 2002 that were $17.0 million higher than the revenues we would have achieved if hedges had not been in place during the period. For the corresponding period during 2001, we realized an average gas price of $5.48 per Mcf, which was 80% of the average unhedged natural gas price of $6.86 that otherwise would have been received, resulting in natural gas and oil revenues that were $30.5 million lower than the revenues we would have achieved if hedges had not been in place during the period. Lease Operating Expenses and Severance Tax. Lease operating expenses increased 17% from $6.3 million for the three months ended March 31, 2001 to $7.4 million for the corresponding three months of 2002. On an Mcfe basis, lease operating expenses increased from $0.27 per Mcfe during the first quarter of 2001 to $0.30 per Mcfe during 2001 the first quarter of 2002. The increase in both lease operating expenses and lease operating expense on a per unit basis for 2002 is attributable to the continued expansion of our operations both offshore and onshore as new offshore production facilities have been added since the second half of 2001 and onshore operations have expanded with the purchase of approximately 159 new wells in South Texas on December 31, 2001. Specific increases were in the areas of well control insurance premiums and onshore ad valorem taxes. Severance tax, which is a function of volume and revenues generated from onshore production, decreased from $4.7 million for the first three months of 2001 to $1.7 million for the corresponding period of 2002. On an Mcfe basis, severance tax decreased from $0.21 per Mcfe for the first quarter of 2001 to $0.07 per Mcfe during the first quarter of 2002. The decrease in severance tax expense and severance tax per Mcfe is primarily due to higher natural gas prices received during the first three months of 2001 as compared to prices received during the first three months of 2002 offset in part by an increase in onshore production for the first quarter of 2002. Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased 32% from $30.2 million for the three months ended March 31, 2001 to $39.8 million for the three months ended March 31, 2002. Depreciation, depletion and amortization expense per Mcfe increased 20% from $1.33 for the three months ended March 31, 2001 to $1.60 for the corresponding three months in 2002. The increase in depreciation, depletion and amortization expense was a result of higher production volumes combined with a higher depletion rate. The higher depletion rate during the first quarter of 2002 is a result of the addition of fewer new reserves from exploration and developmental drilling. General and Administrative Expenses. General and administrative expenses, net of overhead reimbursements received from other working interest owners of $0.3 million and $0.6 million for the three months ended March 31, 2001 and 2002, respectively, decreased 59% from $8.0 million for the three months ended March 31, 2001 to $3.3 million for the three months ended March 31, 2002. Included in general and administrative expense for the first quarter of 2001 were payments totaling $5.2 million made in connection with the termination of former executive officers' employment contracts. We capitalized general and administrative expenses directly related to oil and gas exploration and development activities of $4.9 million and $3.3 million, respectively, for the three months ended March 31, 2001 and 2002. The decrease in capitalized general and administrative expenses is a result of lower aggregate general and administrative expenses during the first quarter of 2002. Excluding the one-time charges taken for the termination of employment contracts totaling $5.2 million during the first quarter of 2001, aggregate general and administrative expenses would have been $7.9 million for the first quarter of 2001 compared to $7.2 million for the first quarter of 2002, reflecting a decrease of 9% which was due primarily to a decrease in incentive compensation (first quarter of 2001 included the payment of a special bonus in January 2001) combined with the reorganization of our geologic and geophysical department during the first quarter of 2002. On an Mcfe basis, general and administrative expenses decreased 63% from $0.35 during the first quarter of 2001 to $0.13 per Mcfe during the first quarter of 2002. Excluding the one-time charges taken for the termination of employment contracts totaling $5.2 million, general and administrative expenses on a per Mcfe basis would have increased 8% from $0.12 for the first quarter of 2001 to $0.13 for the first quarter of 2002. The higher rate per Mcfe during the first quarter of 2002 reflects a decrease in the amount of general and administrative expenses capitalized during the first quarter of 2002 offset in part by an increase in production for the first quarter of 2002. -17- Other Income and Expense. For the first quarter of 2001, we recognized other income of $1.4 million relating to the reversal of a portion of $1.8 million in certain reserves that had been established during the first quarter of 2000 in connection with the review of strategic alternatives for our company. In September 1999, together with KeySpan, our majority stockholder, we announced our intention to review strategic alternatives for our company and KeySpan's investment in our company. KeySpan was assessing our role within its future strategic plan, and was considering a full range of strategic transactions including the possible sale of all or a portion of our assets. On February 25, 2001, we announced, together with KeySpan, that the review of strategic alternatives for Houston Exploration was complete. KeySpan announced that it planned to retain its equity position in our company for the foreseeable future; however, KeySpan considers its investment in Houston Exploration a non-core asset. Interest Expense, Net. Interest expense, net of capitalized interest, decreased 26% from $1.9 million for the first three months of 2001 to $1.4 million for the first three months of 2002. Aggregate interest expense decreased 29% from $5.1 during the first quarter of 2001 to $3.6 million during the corresponding period of 2002. The decrease in aggregate interest is due to a decrease in interest rates from an average borrowing rate of 8.17% during the first quarter of 2001 to 5.36% during the first quarter of 2002. Capitalized interest decreased 29% from $3.1 million for the first quarter of 2001 to $2.2 million for the first quarter of 2002 and corresponds to the decrease in aggregate interest expense combined with a decrease in exploratory drilling during the first quarter of 2002 (our capitalized interest is a function of exploratory drilling and unevaluated properties, both of which were at lower levels during the first quarter of 2002). Income Tax Provision. The provision for income taxes decreased 77% from $27.3 million for the first three months of 2001 to $6.4 million for the first three months of 2002 due to the 75% decrease in pre-tax income during the first quarter of 2002 from $74.7 million during the first quarter of 2001 to $19.0 million during the first quarter of 2002 as a result of the combination of lower natural gas prices, an increase in production, a decrease in interest expense offset in part by a marginal increase in operating expenses. Operating Income and Net Income. For the three months ended March 31, 2002, the 47% decrease in realized natural gas prices combined with the 9% increase in production, offset in part by a 6% increase in operating expenses, caused operating income to decrease 73% from $75.2 million during the first quarter of 2001 to $20.4 million during the first quarter of 2002. Correspondingly, net income decreased 74% from $47.3 million for the first quarter of 2001 to $12.5 million for the first quarter of 2002 and reflects lower interest expense and lower taxes. LIQUIDITY AND CAPITAL RESOURCES We have historically funded our operations, acquisitions, capital expenditures and working capital requirements from cash flows from operations, equity capital from KeySpan as well as public sources, public debt and bank borrowings. We believe cash flows from operations and borrowings under our revolving bank credit facility will be sufficient to fund our planned capital expenditures and operating expenses during 2002. Cash Flows From Operations. At of March 31, 2002, we had working capital of $6.5 million and $100.6 million of borrowing capacity available under our revolving bank credit facility. Net cash provided by operating activities for the three months ended March 31, 2002 was $33.4 million compared to $113.1 million during the corresponding period of 2001. The decrease in net cash provided by operating activities was due to (i) a decrease in net income and deferred taxes due to the decrease in realized natural gas prices from an average $5.48 per Mcf during the first quarter of 2001 to $2.90 during the first quarter of 2002, offset in part by a 9% increase in production for the corresponding period combined with (ii) a decrease in current assets and current liabilities which is related to the timing of cash receipts and payments. Funds used in investing activities consisted of $47.5 million for net investments in property and equipment, which compares to $63.0 million spent during the corresponding period of 2001. Our cash position increased during the first quarter of 2002 as a result of net borrowings under our revolving bank credit facility of $5 million compared to repayments totaling $45 million during the first quarter of 2001. Cash increased by $0.6 million and $2.9 million, respectively, during the first three months of 2002 and 2001 due to proceeds received from the issuance of common stock from the exercise of stock options. As a result of these activities, cash and cash equivalents decreased $8.4 million from $8.6 million at December 31, 2001 to $0.2 million at March 31, 2002. -18- Capital Expenditures. During the first three months of 2002, we invested a $46.9 million in natural gas and oil properties and $0.9 million for other property and equipment, which includes the expansion of our Houston office space. Included in our natural gas and oil property additions was $7.5 million for exploration, $28.5 million for development drilling, workovers and construction of platforms and pipelines and $10.9 million for leasehold and leasehold acquisition costs which includes seismic, capitalized interest and capitalized general and administrative costs. Our capital expenditure budget for 2002 has been set at $250 million. Typically, we do not include property acquisition costs in our capital expenditure budget as the size and timing of capital requirements for property acquisitions are inherently unpredictable. However, we will allocate a portion of our 2002 capital expenditure budget to include the April 19, 2002 acquisition of producing properties in South Texas from Burlington Resources as we plan to repay the borrowings made under our credit facility for the $48.1 million purchase price from cash flows generated from operations. The capital expenditure budget includes development costs associated with recent acquisitions and discoveries and amounts are contingent upon drilling success. No significant abandonment or dismantlement costs are anticipated in 2002. We will continue to evaluate our capital spending plans throughout the year. Actual levels of capital expenditures may vary significantly due to a variety of factors, including drilling results, natural gas prices, industry conditions and outlook and future acquisitions of properties. We intend to continue to selectively seek acquisition opportunities for proved reserves with substantial exploration and development potential both offshore and onshore, although there can be no assurance that we will be able to identify and make acquisitions of proved reserves on terms it considers favorable. Shelf Registration. On May 20, 1999, we filed a "shelf" registration with the Securities and Exchange Commission to offer and sell in one or more offerings up to a total offering amount of $250 million in securities which could include shares of our common stock, shares of preferred stock or unsecured debt securities or a combination thereof. Depending on market conditions and our capital needs, we may utilize the shelf registration in order to raise capital. We would use the net proceeds received from the sale of any securities for the repayment of debt and/or to fund an acquisition. We may not be able to consummate any offerings under the shelf registration statement on acceptable terms. Capital Structure Revolving Bank Credit Facility. We maintain a revolving bank credit facility with a syndicate of lenders led by JP Morgan Chase, National Association. The credit facility provides a maximum commitment of $250 million, which may be limited by the amount of the borrowing base. At March 31, 2002, the borrowing base was $250 million. Up to $2.0 million of the borrowing base is available for the issuance of letters of credit to support performance guarantees. The credit facility matures on April 15, 2003 and is unsecured. At March 31, 2002, $149 million was outstanding under the credit facility and $0.4 million was outstanding in letter of credit obligations. Subsequent to March 31, 2002, we increased our net borrowings by an additional $1 million, bringing total borrowings and letters of credit to $150.4 million as of April 26, 2002. Senior Subordinated Notes. On March 2, 1998, we issued $100 million of 8 5/8% Senior Subordinated Notes due January 1, 2008. The notes bear interest at a rate of 8 5/8% per annum with interest payable semi-annually on January 1 and July 1. We may redeem the notes at our option, in whole or in part, at any time on or after January 1, 2003 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 4.313% in 2003 to 0% after January 1, 2006 if the notes are redeemed prior to January 1, 2006. 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, if any. The notes are general unsecured obligations and rank subordinate in right of payment to all existing and future senior debt, including the credit facility, and will rank senior or equal in right of payment to all existing and future subordinated indebtedness. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Natural Gas Hedging. We utilize derivative commodity instruments to hedge future sales prices on a portion of our natural gas 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 -19- 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 financial institutions that we believe are minimal credit risks. 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 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 other income or expense. The following table summarizes the change in the fair value of our derivative instruments from January 1, 2002 to March 31, 2002. CHANGE IN FAIR VALUE OF DERIVATIVES INSTRUMENTS 2002 -------------------------------------------------------------------------- (in thousands) Fair value of contracts at January 1........................... $ 53,771 Gain on contracts realized..................................... 16,966 Change or decrease in fair values.............................. (68,608) --------- Fair value of contracts outstanding at March 31................ $ 2,129 ========= -20- The following table summarizes on a monthly basis our hedges for 2002 and 2003. All amounts are in thousands, except for prices. For the remaining months of 2002, we have hedged approximately 70% of our estimated production or a total of 190,000 MMBtu/day at an effective floor of $3.389 and an effective ceiling of $4.801. For the year 2003, we have 60,000 MMBtu/day hedged at an effective floor of $3.229 and an effective ceiling of $3.486. FIXED PRICE SWAPS COLLARS -------------------- ----------------------------------- NYMEX NYMEX VOLUME CONTRACT VOLUME CONTRACT PRICE PERIOD (MMBTU) PRICE (MMBTU) AVG FLOOR AVG CEILING ------ ------- -------- ------- --------- ----------- April 2002 900 3.010 4,800 3.561 5.137 May 2002 930 3.010 4,960 3.561 5.137 June 2002 900 3.010 4,800 3.561 5.137 July 2002 930 3.010 4,960 3.561 5.137 August 2002 930 3.010 4,960 3.561 5.137 September 2002 900 3.010 4,800 3.561 5.137 October 2002 930 3.010 4,960 3.561 5.137 November 2002 900 3.010 4,800 3.561 5.137 December 2002 930 3.010 4,960 3.561 5.137 January 2003 1,240 3.194 620 3.300 4.070 February 2003 1,120 3.194 580 3.300 4.070 March 2003 1,240 3.194 620 3.300 4.070 April 2003 1,200 3.194 600 3.300 4.070 May 2003 1,240 3.194 620 3.300 4.070 June 2003 1,200 3.194 600 3.300 4.070 July 2003 1,240 3.194 620 3.300 4.070 August 2003 1,240 3.194 620 3.300 4.070 September 2003 1,200 3.194 600 3.300 4.070 October 2003 1,240 3.194 620 3.300 4.070 November 2003 1,200 3.194 600 3.300 4.070 December 2003 1,240 3.194 620 3.300 4.070 These hedging transactions are settled based upon the New York Mercantile Exchange or NYMEX price on the final trading day of the month. In order to determine fair market value of our derivative instruments, we obtain market-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. -21- PART II. OTHER INFORMATION ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K: (a) Exhibits: EXHIBITS DESCRIPTION -------- ----------- *10.1 -- Fourth Amendment to the Amended and Restated Revolving Credit Facility between The Houston Exploration Company and JPMorgan Chase Bank, National Association, as agent, dated April 19, 2002. --------------------------- * Filed herewith. (b) Reports on Form 8-K: Current Report on Form 8-K filed on March 25, 2002 to provide new information regarding hedges for the years ended December 31, 2002 and 2003 in Item 5 - Other Events. Current Report on Form 8-K filed April 5, 2002 to provide information regarding change of certifying accountant in Item 4. Changes in Registrant's Certifying Accountant. -22- 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 COMPANY By: /s/ William G. Hargett -------------------------------------- Date: April 29, 2002 William G. Hargett President and Chief Executive Officer By: /s/ James F. Westmoreland -------------------------------------- Date: April 29, 2002 James F. Westmoreland Vice President, Chief Accounting Officer and Secretary -23- INDEX TO EXHIBITS EXHIBITS DESCRIPTION -------- ----------- *10.1 -- Fourth Amendment to the Amended and Restated Revolving Credit Facility between The Houston Exploration Company and JPMorgan Chase Bank, National Association, as agent, dated April 19, 2002. --------------------------- * Filed herewith.