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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, 2003

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. 001-14745

3TEC ENERGY CORPORATION

(Exact name of Registrant as specified in its charter)

700 MILAM, SUITE 1100

HOUSTON, TX 77002

(Address of principal executive offices)

(713) 821-7100

(Registrant’s telephone number, including area code)

N/A

(Former Name, Former Address and Former Fiscal Year,

If Changed Since Last Report)

Indicate by check mark whether the registrant (1) filed all reports required to be filed by Section 13 or 15(d) of 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 ¨

Indicate by check mark whether the registrant is an accelerated filer (as defined in rule 12b-2 of the Exchange Act). Yes x  

No ¨

Number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

Common stock, $0.02 par value

16,696,597 shares as of April 30, 2003

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3TEC ENERGY CORPORATION AND SUBSIDIARIES

INDEX

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P ART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

3TEC ENERGY CORPORATION AND SUBSIDIARIES

CO NSOLIDATED BALANCE SHEETS

(in thousands, except per share data)

SEE ACCOMPANYING NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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3TEC ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except share and per share data)

SEE ACCOMPANYING NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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3TEC ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

SEE ACCOMPANYING NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)    BASIS OF PRESENTATION

In management’s opinion, the accompanying unaudited consolidated financial statements contain all adjustments (consisting primarily of normal recurring adjustments) necessary to present fairly the consolidated financial position of the Company as of March 31, 2003 and December 31, 2002 and consolidated results of operations and consolidated cash flows for the periods ended March 31, 2003 and 2002.

These consolidated financial statements should be read in conjunction with the Company’s financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002. The results of operations for the three months ended March 31, 2003, are not necessarily indicative of the results which may be expected for any other interim period or for the entire fiscal year ending December 31, 2003.

Recent Developments

On February 2, 2003, the Company entered into a definitive merger agreement with Plains Exploration & Production Company (“Plains”) whereby Plains will acquire the Company for a combination of cash and stock. Under the terms of the agreement, the Company’s shareholders will receive $8.50 in cash and 0.85 of a share of Plains’s Common Stock for each share of the Company’s Common Stock, subject to certain adjustments if the average share price of Plains’s Common Stock (as determined during a twenty-day trading period prior to closing) is less than $7.65 per share or greater than $12.35 per share. The transaction is subject to a shareholder vote on June 3, 2003, and is expected to close during the second quarter of 2003.

Significant Accounting Policies

The Company’s accounting policies reflect industry standards and conform to generally accepted accounting principles. The more significant of such policies are described below.

Reclassifications

Certain prior-year amounts have been reclassified to conform with current year presentation.

Oil and Gas Properties

The Company follows the successful efforts method of accounting for oil and natural gas properties, and accordingly, capitalizes all direct costs incurred in connection with the acquisition, drilling and development of productive oil and natural gas properties. Costs associated with unsuccessful exploration are charged to expense currently. Geological and geophysical costs and costs of carrying and retaining unevaluated properties are charged to expense. Depreciation, depletion and amortization of capitalized costs are computed separately for each field based on the unit-of-production method using only proved oil and natural gas reserves. In arriving at such rates, commercially recoverable reserves have been estimated by an independent petroleum engineering firm. The Company reviews its undeveloped properties continually and charges them to expense on a property-by-property basis when it is determined that they have been condemned by dry holes, or have otherwise diminished in value.

Proved oil and natural gas reserves are the estimated quantities of oil, natural gas and natural gas liquids which are expected to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proved if economic productability is supported by either actual production or conclusive formation tests.

The Company reviews long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such an asset may not be recoverable. This review consists of a comparison of the carrying value of the asset to the asset’s expected future undiscounted cash flows. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions and projections. If the expected future cash flows, assuming escalated prices, are less than the carrying value of the asset, an impairment exists and is measured as the excess of the carrying value over the estimated fair value of the asset. The Company estimates the discounted future net cash flows of its oil and gas properties to determine their fair value. Any impairment provisions recognized are permanent and may not be restored in the future. For the three months ended March 31, 2003, the Company’s proved properties were assessed for impairment on an individual field basis and the Company recorded impairment provisions on certain producing properties of $2.9 million.

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3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Revenue Recognition of Production Imbalances

Oil and natural gas revenues are recorded using the sales method, whereby the Company recognizes revenues based on the amount of oil and natural gas sold to purchasers on its behalf notwithstanding its ownership percentage. At March 31, 2003, the Company’s net imbalance position was immaterial.

Hedging

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”). In June 2000, the FASB issued SFAS 138, Accounting for Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133. SFAS 133, as amended, establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair market value. The statement requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge criteria are met. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. The Company adopted SFAS 133 effective January 1, 2001.

SFAS 133, in part, allows hedge accounting. SFAS 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings.

To qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows due to changes in the underlying items being hedged. In addition, all hedging relationships must be designated, documented, and reassessed periodically. The Company’s natural gas derivative instruments entered into during the periods presented were not designated as hedges at the time the instruments were executed. In accordance with provisions of SFAS 133, these instruments were marked-to-market through earnings at March 31, 2003, resulting in an increase of $583,358.

Earnings Per Share

Basic earnings and loss per common share are based on the weighted average shares outstanding without any dilutive effects considered. Diluted earnings and loss per share reflect dilution from all potential common shares, including options, warrants and convertible preferred stock and convertible notes. Diluted loss per share does not include the effect of any potential common shares if the effect would be to decrease the loss per share.

At March 31, 2003, the Company had a weighted average of 2,370,806 combined stock options, warrants and convertible preferred stock and notes outstanding included in the Company’s fully diluted per share calculation, respectively. At March 31, 2002, the Company had a weighted average of 2,557,775 stock options, warrants and convertible preferred stock outstanding which were not included in the computation of diluted earnings per share, because the effect of the assumed exercise of these stock options, warrants and convertible securities would have an antidilutive effect on the computation of diluted loss per share.

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3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Basic and diluted earnings per share for the three-month period ended March 31, 2003 and March 31, 2002, was determined as follows (in thousands):

Accounting Pronouncements

In August, 2001, the FASB issued SFAS 143, “Accounting for Asset Retirement Obligations”, which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The Company adopted SFAS 143 as of January 1, 2003. The impact of adoption is discussed in more detail in Note 4.

During second quarter 2002 the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. This statement rescinds SFAS No. 4, Reporting Gains and Losses from Extinguishment of Debt, and requires that all gains and losses from extinguishment of debt should be classified as extraordinary items only if they meet the criteria in APB No. 30. Applying APB No. 30 will distinguish transactions that are part of an entity’s recurring operations from those that are unusual or infrequent or that meet the criteria for classification as an extraordinary item. Any gain or loss on extinguishment of debt that was classified as an extraordinary item in prior periods presented that does not meet the criteria in APB No. 30 for classification as an extraordinary item must be reclassified. The Company does not expect that there will be any current impact from SFAS No. 145.

The FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, in June 2002. This statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). SFAS No. 146 applies to costs incurred in an “exit activity,” which includes, but is not limited to, a restructuring, or a “disposal activity” covered by SFAS No. 144. There is no current impact of SFAS 146 on the Company’s financial position or results of operations.

In December 2002, SFAS No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FASB Statement No. 123 was issued. SFAS 148 amends SFAS 123, Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of SFAS 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported

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3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

results. The provisions of SFAS 148 are effective for financial statements for fiscal years ending after December 15, 2002. SFAS 148 does not change the provisions of SFAS 123 that permit entities to continue to apply the intrinsic value method of Accounting Principles Bulletin No. 25, Accounting for Stock Issued to Employees. We have and will continue to account for stock-based compensation in accordance with the provisions of APB No. 25.

For the periods ending March 31, 2003 and 2002, the exercise price of the options granted is equal to the quoted market price of the Company’s stock at the grant date, and therefore, no compensation costs have been recognized for its stock option plans. Had compensation cost for the Company’s plans been determined based on the fair market value at the grant date for stock options granted for the periods ending March 31, 2003 and 2002, the Company’s net income and income per share would have been adjusted to the pro forma amounts listed below (in thousands, except per share amounts):

During 2002, the FASB issued two interpretations: FIN 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others and FIN 46, Consolidation of Variable Interest Entities. There is no current impact of FIN 45 or FIN 46 on the Company’s financial position or results of operations.

(2)    STOCKHOLDERS’ EQUITY

Preferred Stock—Series B

In connection with the merger with Shore Oil Company, effective June 30, 1997, the Company issued 266,667 shares of Series B Preferred Stock (“Series B”). The Series B is nonvoting and pays no dividends. The Series B has a liquidation value of $7.50 per share. During the first quarter of 2002, 58,762 shares of Series B were converted into 34,065 shares of Company Common Stock (“Common”). On December 31, 2002, the remaining 207,905 Series B shares were converted into 152,165 shares of Common. The conversion calculation was calculated as 88,889 shares plus the result of multiplying (i) (the value of approximately 40,000 net mineral acres owned by the Company in South Louisiana (the “Mineral Acres”) minus $2,000,000) divided by $8,000,000 times (ii) 355,555.

Restricted Stock

During May 2002, the Company issued 95,000 shares of restricted stock to certain members of the Company’s management valued at $1.6 million. During the quarter ended March 31, 2003, the Company recognized approximately $47,000 as restricted stock compensation expense. Of the 95,000 shares that were issued, 10,832 shares had vested and were outstanding as of March 31, 2003. The remaining shares will vest either over a two-year period, when the Company’s stock price meets a certain price target or when there is a change of control, as defined by the plan documents.

(3)    DERIVATIVE ACTIVITIES

The following table details the Company’s derivative contract positions in place at March 31, 2003, which had a fair value liability of $3.0 million at that date.

Through March 31, 2003, the Company has paid net cash settlements of approximately $15.0 million related to its derivative activities.

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3TEC ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

In August, 2001, the FASB issued SFAS 143, Accounting for Asset Retirement Obligations. SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and (or) normal use of the asset. The Company currently has legal obligations to plug and abandon wells at the end of the assets’ useful lives.

SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. Upon adoption of this statement on January 1, 2003, the Company recorded a cumulative effect accounting adjustment of $0.4 million, net of deferred tax expense of $0.3 million. Additionally, the Company established a liability for asset retirement obligations of $4.9 million, a corresponding increase in property, plant and equipment of $3.6 million and a decrease in accumulated DD&A of $0.6 million.

The following table describes the changes in the Company’s asset retirement obligations for the first quarter of 2003 (in thousands):

The following table summarizes the pro forma net income and earnings per share for the three months ended March 31, 2002 for the change in accounting principle had it been implemented on January 1, 2002:

In addition, on a pro forma basis as required by SFAS No. 143, had we adopted the provisions of SFAS No. 143 on January 1, 2002, the amount of the asset retirement obligations would have been as follows:

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Cautionary Statement About Forward-Looking Statements

Some of the information in this Quarterly Report on Form 10-Q, including information incorporated by reference, contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities and Exchange Act of 1934. The forward-looking statements speak only as of the date made and the Company undertakes no obligation to update such forward-looking statements. These forward-looking statements may be identified by the use of the words “believe,” “expect,” “anticipate,” “will,” “contemplate,” “would” and similar expressions that contemplate future events. These future events include the following matters:

Numerous important factors, risks and uncertainties may affect the Company’s operating results, including:

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Any of the factors listed above and other factors mentioned in this Form 10-Q could cause the Company’s actual results to differ materially from the results implied by these or any other forward-looking statements made by the Company or on its behalf. The Company cannot assure you that future results will meet its expectations.

OVERVIEW

We are engaged in the acquisition, development, production and exploration of oil and natural gas reserves. Our properties are concentrated in East Texas and the Gulf Coast region, both onshore and in the shallow waters of the Gulf of Mexico. Our management and technical staff have substantial experience in each of these areas. As of December 31, 2002, we had at that date estimated total net proved reserves of 296 Bcfe, of which approximately 87% were natural gas and approximately 81% were proved developed, with an estimated PV-10 value of $488 million.

Historically, we have increased our reserves and production principally through acquisitions. We focus on properties that have a substantial proved reserve component and which management believes to have additional exploitation opportunities. Recently, we have also acquired a number of drilling prospects covered by an extensive 3-D seismic database that we believe have exploration potential. We have assembled an experienced management team and technical staff with expertise in property acquisitions and development, reservoir engineering, exploration and financial management.

Recent Developments. On February 2, 2003, the Company entered into a definitive merger agreement with Plains Exploration & Production Company (“Plains”) whereby Plains will acquire the Company for a combination of cash and stock. Under the terms of the agreement, the Company’s shareholders will receive $8.50 in cash and 0.85 of a share of Plains’s Common Stock for each share of the Company’s Common Stock, subject to certain adjustments if the average share price of Plains’s Common Stock (as determined during a twenty-day trading period prior to closing) is less than $7.65 per share or greater than $12.35 per share. The transaction is subject to a shareholder vote on June 3, 2003, and is expected to close during the second quarter of 2003.

DESCRIPTION OF CRITICAL ACCOUNTING POLICIES

Oil and Natural Gas Properties. We utilize the successful efforts method of accounting for our oil and natural gas properties. Under this method, all development and acquisition costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of proved developed reserves or proved reserves, as applicable. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs of drilling exploratory wells are initially capitalized, but charged to expense if and when the well is determined to be unsuccessful. Expenditures for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different or additional proven or unproven reservoir are capitalized pending determination that economic reserves have been added. If the recompletion to an unproven reservoir is not successful, the expenditures are charged to expense. Expenditures for redrilling or directional drilling in a previously abandoned well are classified as drilling costs to a proven or unproven reservoir for determination of capital or expense. Significant tangible equipment added or replaced is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reserves are capitalized. Internal costs directly associated with the development and exploitation of properties are capitalized as a cost of the property and are classified accordingly in the Company’s financial statements. Crude oil volumes are converted to equivalent Mcfe’s at the rate of one barrel to six Mcfe.

The Company is required to assess the need for an impairment of capitalized costs of oil and natural gas properties and other long-lived assets whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then it is recognized to the extent that the carrying value exceeds fair value. Any impairment charge incurred is recorded in accumulated depletion, depreciation, and amortization (“DD&A”) to reduce our recorded basis in the asset. Each part of this calculation is subject to a large degree of management judgment, including the determination of property’s reserves, future cash flows, and fair value.

Management’s assumptions used in calculating oil and natural gas reserves or regarding the future cash flows or fair value of our properties are subject to change in the future. Any change could cause impairment expense to be

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recorded, reducing our net income and our basis in the related asset. Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of calculating reserve estimates. Actual production may not equal the estimated amounts used in the preparation of reserve projections. As these estimates change, the amount of calculated reserves change. Any change in reserves directly impacts our estimate of future cash flows from the property, as well as the property’s fair value. Additionally, as management’s views related to future prices change, this changes the calculation of future net cash flows and also affects fair value estimates. Changes in either of these amounts will directly impact the calculation of impairment.

DD&A expense is also directly affected by the Company’s reserve estimates. Any change in reserves directly impacts the amount of DD&A expense the Company recognizes in a given period. Assuming no other changes, such as an increase in depreciable base, as the Company’s reserves increase, the amount of DD&A expense in a given period decreases and vice versa. Changes in future commodity prices would likely result in increases or decreases in estimated recoverable reserves.

The Company also uses estimates to record its accrual for oil and natural gas revenues. The volume portion of the accrual of revenue for a given period is based upon field production reports (both operated and non-operated), estimates of production added via drilling or acquisitions, historical production averages and natural production declines of the Company’s properties. The price component of the Company’s accrual for revenue incorporates historical averages of the Company’s sales as compared to the monthly closing NYMEX price for natural gas and the West Texas Intermediate index price for crude oil.

Several factors can impact the Company’s ability to estimate its production volume such as the fact that a significant portion of the Company’s production is operated by third parties. The Company’s working and royalty interests, which are operated by third parties, are governed by joint operating agreements with the third party operators and contain customary industry standard terms and conditions. Wagner & Brown, Ltd., is the Company’s largest single third party operator, operating approximately 15% of the Company’s total produced oil and gas volumes on a monthly basis. No other third party operator operates greater than 5% of the Company’s monthly production. Reliance on accurate and timely data from the operators of these properties can change the actual amounts of production for which the Company receives payment. Additionally, production meters that are manually read can be different than the volume metered at the Company’s sales points.

Both the Company’s estimate of sold volumes and the estimate of the price received for these sales is adjusted on an on-going basis as the Company receives payment for the accrued volumes. Changes in the estimates of the accrual are adjusted for in the subsequent periods as payment is received or additional supporting data is obtained.

Bad Debt Expense. The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectibility. The Company historically has not required collateral or other performance guarantees from creditworthy counterparties. Many of our receivables are from joint interest owners on property of which we are the operator. Thus, we may have the ability to withhold future revenue disbursements to cover any non-payment of joint interest billings. Our oil and natural gas receivables typically turnover quickly, usually one month for oil and two months for gas; thus, signaling any problem accounts in a timely manner. Counterparties to our derivative commodity contracts are routinely reviewed for creditworthiness to determine the realizability of any related derivative assets we might carry on our books. This review of receivables and counterparties is heavily dependent on the judgment of management. If it is determined that the carrying value of a receivable or financial instrument might not be recoverable, we record an allowance to the extent we believe the receivable or asset is not recoverable. The determination as to what extent a receivable or asset might be impaired is also heavily dependent on the judgment of management. As more information becomes known related to a particular counterparty or customer, management will continually reassess previous judgments and any resulting change in the related allowance could have a material positive or negative effect on our financial position and results of operations in the period of the change.

Derivative Activities. We use various financial instruments in the normal course of our business to manage and reduce price volatility and other market risks associated with our crude oil and natural gas production. This activity is referred to as risk management. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases. Our risk management activity is generally accomplished through over-the-counter forward derivative contracts executed with large financial institutions.

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Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133 (“SFAS 133”), Accounting for Derivative Instruments and Hedging Activities. This standard requires us to recognize all of our derivative and hedging instruments in our consolidated balance sheets as either assets or liabilities and measure them at fair value. If a derivative does not qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative does qualify for hedge accounting, depending on the nature of the hedge, changes in fair value can be offset against the change in fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings.

To qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows due to changes in the underlying items being hedged. In addition, all hedging relationships must be designated, documented, and reassessed periodically. The Company’s natural gas derivative financial instruments were not designated as hedges at the time the instruments were executed. According to the provisions of SFAS 133, these instruments are marked-to-market through earnings each period.

Asset Retirement Obligations. In August, 2001, the FASB issued SFAS 143, Accounting for Asset Retirement Obligations. SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and (or) normal use of the asset. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. Upon adoption of this statement on January 1, 2003, the Company recorded a cumulative effect accounting adjustment of $0.4 million, net of deferred tax expense of $0.3 million. Additionally, the Company established a liability for asset retirement obligations of $4.9 million, a corresponding increase in property, plant and equipment of $3.6 million and a decrease in accumulated DD&A of $0.6 million.

SFAS 143 additionally requires that the liability be accreted at the end of each period through charges to operating expense. If the obligation is settled for other than the carrying amount of the liability, the Company recognizes a gain or loss on settlement. For the three months ended March 31, 2003, the Company recorded $84,000 of accretion expense. No assets were retired during the three months ended March 31, 2003, and therefore, no gain or loss was recognized.

LIQUIDITY AND CAPITAL RESOURCES

We believe that our cash flows from operations are adequate to meet the requirements of operating our business. However, future cash flows are subject to a number of variables, including our level of production and prices, and we cannot assure that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures. Our principal operating source of cash is the sale of natural gas and oil production.

For the year 2003, anticipated capital expenditures have been reduced as management has made the decision to manage for a better balance between volumes and returns. As a result, the Company will defer approximately $10 million of the $63 million that was previously anticipated into 2004.

We are obligated to pay dividends of approximately $740,000 per year on the Series D Preferred Stock which we may pay in either cash or in additional shares of Series D Preferred Stock during the three years ending February 1, 2003.

Credit Facility. We have a $250 million credit facility (the “Credit Facility”) with Bank One, NA as agent and seven other banks. The Credit Facility matures August 31, 2004. The borrowing base is to be redetermined semi-annually on May 1 and November 1 and provides for interest as revised under the Credit Facility to accrue at a rate calculated at the Company’s option as either the bank’s prime rate plus a low of 37.5 basis points or LIBOR plus basis points increasing from a low of 150 to a high of 200 as loans outstanding increase as a percentage of the borrowing base. As of March 31, 2003, the borrowing base was set at $160 million and the Company was paying an average of 3.08% per annum interest on the principal balance of $106 million under the Credit Facility. Prior to maturity, no payments of principal are required so long as the borrowing base exceeds the

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loan balance. The borrowings under the Credit Facility are secured by substantially all of the Company’s oil and natural gas properties. At March 31, 2003, the amount available to be borrowed under the Credit Facility was approximately $54 million.

In connection with the Credit Facility we are required to adhere to certain affirmative and negative covenants. The loan agreement contains a number of dividend restrictions and restrictive covenants which, among other things, require the maintenance of minimum current and interest coverage ratios. As of March 31, 2003 we were in compliance with the covenants contained in the Credit Facility and expect to be in compliance during the balance of 2003.

Market Risk. We generally sell our oil at local field prices paid by the principal purchasers of oil. The majority of our natural gas production is sold at spot prices. Accordingly, we are generally subject to the commodity prices for these resources as they vary from time to time.

Inflation and Changes in Prices. Our revenues and the value of our oil and gas properties have been and will be affected by changes in natural gas and crude oil prices. Additionally, costs and expenses are affected by inflationary pressures, which could have a significant impact on the costs necessary to operate our business. Our ability to maintain current borrowing capacity and to obtain additional capital on attractive terms is also substantially dependent on natural gas and crude oil prices. These prices are subject to significant seasonal and other fluctuations that are beyond our ability to control or predict. We use various financial instruments in the course of our business to manage and reduce price volatility risks. During the first three months of 2003, we received an average of $31.23 per barrel of crude oil and $6.69 per Mcf of gas.

Results of Operations. You should read the following discussion and analysis together with our audited consolidated financial statements and the related notes for the fiscal year ended December 31, 2002, filed in our 2002 Form 10-K. Our revenue, profitability, and future rate of growth are dependent upon prevailing prices for oil and gas, which, in turn, depend upon numerous factors such as economic, political, and regulatory developments as well as competition from other sources of energy. The energy markets historically have been highly volatile, and future decreases in prices could have an adverse effect on our financial position, results of operations, quantities of reserves that may be economically produced, and access to capital.

The following table reflects certain summary operating data for the periods presented:

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Three Months Ended March 31, 2003 Compared to Three Months Ended March 31, 2002

Oil and Gas Revenues. Revenues from oil and gas operations increased by 170% to $48.4 million for the three months ended March 31, 2003, compared to $17.9 million for the same period during 2002. The increase is attributable to higher commodity prices received by the Company during the period ($6.44/Mcfe in 2003 versus $2.41/Mcfe in 2002), as well as slightly higher daily production volumes due to recent drilling successes, particularly in South Louisiana.

Derivatives fair value and settlements. The gain on derivatives fair value of $0.6 million for the three months ended March 31, 2003 represents the fair value mark-to-market adjustment made related to the Company’s open positions at December 31, 2002 versus the open positions at March 31, 2003. During the first quarter of 2003, approximately $15.0 million in cash settlements were paid by the Company for derivative contracts that covered the contractual period of January 2003 through March 2003.

Production Expense. Production expense for the three months ended March 31, 2003, increased by 45% to $8.0 million compared to $5.5 million during the same period of 2002. Lease operating expenses increased to $0.55/Mcfe from $0.47/Mcfe, while production, severance and ad valorem taxes increased to $0.36/Mcfe from $0.17/Mcfe and gathering, transportation and other expenses increased to $0.15/Mcfe from $0.11/Mcfe. High workover costs during the period led to the increase in lease operating expenses, while higher commodity prices of $6.44/Mcfe during the first three months of 2003 compared to $2.41/Mcfe during the first three months of 2002 led to an increase in production, severance and ad valorem taxes.

Geological and Geophysical Expenses. Geological and geophysical expenses for the three months ended March 31, 2003, increased by 1700% to $3.6 million compared to $0.2 million during the same period of 2002. The increase is attributed primarily to seismic costs related to the Company’s exploratory activities in South Louisiana.

Dry hole and impairments. For the three months ended March 31, 2003, dry hole and impairment expense increased by 3902%, or $2.1 million, compared to the same period of 2002. The increase is a result of an impairment charge taken on certain properties in South Louisiana in which operational activities gave rise to a reduction in value.

General and Administrative Expense. General and administrative expense for the three months ended March 31, 2003 increased by 14% to $2.5 million from $2.2 million compared to the same period in 2002. The increase was primarily attributable to bonuses paid in connection with the execution of the merger agreement with Plains Exploration discussed on page 10.

Interest. Interest expense during the three-month period ended March 31, 2003 decreased to $0.8 million compared to $1.0 million for the same period ending March 31, 2002. The decrease is attributable to lower interest rates quarter over quarter (approximately 3.08% in 2003 versus 3.69% in 2002).

Merger Costs. Other expense for the three months ended March 31, 2003 was $0.8 million compared to zero during the same period of 2002. Other expense relates to legal and other various costs incurred in connection with the pending merger with Plains Exploration (see discussion on page 10) that were not present in 2002.

Depreciation, Depletion and Amortization Expense. Depreciation, depletion and amortization expense (“DD&A”) for the three months ended March 31, 2003, increased by 20% to $10.6 million compared to $8.8 million for the same period of 2002. The increase in DD&A recorded is attributed to both the impact of the Company’s developmental drilling activities whereby the Company converts proved undeveloped reserves into proved developed producing reserves as well as the increase in South Louisiana volumes, which carry a higher DD&A rate.

Dividends to Preferred Stockholders. Dividends to preferred stockholders of approximately $0.2 million in the three months ended March 31, 2003 are comparable to the $0.2 million for the three months ended March 31, 2002. The Company currently has only the Series D Dividend to pay which is paid semi-annually on March 31 and September 30.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in the Company’s 2002 Annual Report on Form 10-K, as well as with the consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q.

Interest Rate Risk

The Company is exposed to changes in interest rates. Changes in interest rates affect the interest earned on cash, cash equivalents and short-term investments and the interest rate paid on borrowings under the Credit Facility. The Company does not currently use interest rate derivative instruments to manage exposure to interest rate changes, but may do so in the future.

Commodity Price Risk

The Company’s revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil. Prices also affect the amount of cash flow available for capital expenditures and the Company’s ability to borrow and raise additional capital. Lower prices may also reduce the amount of natural gas and oil production under fixed or floating market price contracts. The Company enters into commodity derivative arrangements from time to time to reduce its exposure to fluctuations in natural gas and oil prices and to achieve more predictable cash flow. However, these contracts also limit the benefits the Company would realize if prices increase. These financial arrangements take the form of swap contracts or costless collars and are placed with major trading counterparties the Company believes represent minimum credit risks. The Company cannot provide assurance that these trading counterparties will not become credit risks in the future. Under its current derivative practice, the Company generally does not hedge more than 75 percent of its estimated twelve-month production quantities.

The Company enters into New York Mercantile Exchange (“NYMEX”) related swap contracts and collar arrangements from time to time. The Company’s swap contracts will settle based on the reported settlement price on the NYMEX for the last three trading days of each month for natural gas. In a swap transaction, the counterparty is required to make a payment to the Company for the difference between the fixed price and the settlement price if the settlement price is below the fixed price. As of March 31, 2003, the Company’s commodity price risk management positions in fixed price natural gas and crude oil swap, put and call contracts were as follows:

Based upon the fair value of the Company’s derivative contracts outstanding at March 31, 2003, we reported a net current liability of $3.0 million. The Company did not elect to classify these derivative contracts as hedges and therefore is required to mark the contracts to market at the end of each period and recognize the resulting gain or loss through current period earnings. In connection with the derivative contract settlements during the three months ended March 31, 2003, the Company recognized a loss in revenues of $15.0 million. Since March 31, 2003, the Company had paid net cash settlements of approximately $ 0.6 million related to the closed contract months. The $0.6 million net cash paid for settlements will be recognized in the 2003 statements of operations as a loss on derivative settlements. As of April 30, 2003, the Company only has contracts from May 2003 forward open, which represent a fair value liability of $11 million. A 10% increase to the April 30, 2003 NYMEX prices would result in settlements of the open contract months (May 2003 through December 2004) for the Company’s derivatives to increase by $10.9 million, while a 10% decrease in such prices would result in a $13.6 million decrease to these contract settlements versus the April 30, 2003 mark-to-market loss. Although these derivatives were not designated by the Company as hedges for accounting purposes, the economic volatility of these positions is substantially offset by the physical prices being received for its production.

ITEM 4. CONTROLS AND PROCEDURES

Within 90 days of the filing date of this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the Company’s disclosure controls and procedures (as defined in Rule 13a-14(c) of the Securities and Exchange Act of 1934). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective.

There have been no significant changes in the Company’s internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation, including any corrective actions with regard to significant deficiencies and material weakness.

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PART II. OTHER INFORMATION

ITEMS 1. THROUGH 5.

Not Applicable.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits: The following documents are filed as exhibits to this report:

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* Filed herewith.

(b) The following reports were filed on Form 8-K during the first quarter of 2003:

On February 4, 2003, the Company filed a Form 8-K under item 5 describing the announcement of the proposed merger with Plains Exploration & Production Company.

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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, thereunto duly authorized, as of May 13, 2003.

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CERTIFICATIONS

I, Floyd C. Wilson, certify that:

1.    I have reviewed this quarterly report on Form 10-Q of 3TEC Energy Corporation;

2.    Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3.    Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4.    The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a)    Designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b)    Evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c)    Presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.    The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a)    All significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b)    Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6.    The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 13, 2003

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I, R.A. Walker, certify that:

1.    I have reviewed this quarterly report on Form 10-Q of 3TEC Energy Corporation;

2.    Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3.    Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4.    The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a)    Designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b)    Evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c)    Presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.    The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a)    All significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b)    Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6.    The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 13, 2003

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