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SECURITIES AND EXCHANGE
Washington, D.C. 20549

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FORM 8-K/A
(Amendment No. 1)

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934

Date of Report (Date of earliest event reported) July 30, 2003 (June 27, 2003)

Tom Brown, Inc.
(Exact name of registrant as specified in its charter)

Delaware (State or Other Jurisdiction of Incorporation or Organization)		001-31308 (Commission File Number)		95-1949781 (I.R.S. Employer Identification No.)
555 Seventeenth Street, Suite 1850 Denver, Colorado (Address of Principal Executive Offices)				80202 (Zip Code)
(303) 260-5000 (Registrant's Telephone Number, Including Area Code)
Not Applicable (Former name, former address and former fiscal year, if changed since last report)

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ITEM 2. ACQUISITION OR DISPOSITION OF ASSETS

        On June 27, 2003, Tom Brown, Inc. ("Tom Brown") completed its acquisition of Matador Petroleum Corporation, a Texas corporation ("Matador"), for approximately $388 million in cash and assumed debt at closing. A Current Report on Form 8-K was filed on July 11, 2003 to report this transaction.

ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS.

(a)

FINANCIAL STATEMENTS OF BUSINESS ACQUIRED

        Audited financial statements for Matador as of December 31, 2002 and 2001 and for the three years ended December 31, 2002, 2001 and 2000 and unaudited financial statements for Matador as of March 31, 2003 and for the three months ended March 31, 2003 and 2002 are included herein.

(b)

PRO FORMA FINANCIAL INFORMATION

        Pro forma financial statements as of March 31, 2003 and for the year ended December 31, 2002 and for the three months ended March 31, 2003 are included herein.

(c)

EXHIBITS


23—Consent

of KPMG LLP

1

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Tom Brown, Inc.

Index to Financial Statements

Matador Petroleum Corporation
	Independent Auditors' Report		3
	Consolidated Balance Sheet, March 31, 2003 (unaudited) and December 31, 2002 and 2001		4
	Consolidated Statements of Operations, three months ended March 31, 2003 and 2002 (unaudited) and years ended December 31, 2002, 2001 and 2000		5
	Consolidated Statements of Changes in Shareholders' Equity, three months ended March 31, 2003 (unaudited) and years ended December 31, 2002, 2001 and 2000		6
	Consolidated Statements of Cash Flows, three months ended March 31, 2003 and 2002 (unaudited) and years ended December 31, 2002, 2001 and 2000		7
	Notes to Consolidated Financial Statements		8
Pro Forma Financial Statements (unaudited)			26
	Pro Forma Balance Sheet, March 31, 2003		27
	Pro Forma Statements of Operations, year ended December 31, 2002 and three months ended March 31, 2003		28

2

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Independent Auditors' Report

The Board of Directors and Stockholders
Matador Petroleum Corporation:

We have audited the accompanying consolidated balance sheets of Matador Petroleum Corporation (a Texas Corporation) and subsidiaries (the Company) as of December 31, 2002 and 2001, and the related consolidated statements of operations, shareholders' equity and cash flows for each of the years in the three-year period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Matador Petroleum Corporation and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP
March 6, 2003

3

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MATADOR PETROLEUM CORPORATION
AND SUBSIDIARIES

Consolidated Balance Sheets

								December 31,
					March 31, 2003
								2002			2001
					(Unaudited)
Assets
Current assets:
	Cash and cash equivalents				$	3,432,500		$	1,729,921		$	5,173,635
	Accounts receivable:
		Oil and natural gas revenues				14,554,234			7,154,399			5,083,623
		Joint interest billings				9,493,532			8,244,069			4,839,630
		Other				131,602			962,392			7,000
	Prepaid expenses and other					729,074			753,467			603,281
			Total current assets			28,340,942			18,844,248			15,707,169
Property and equipment:
	Oil and natural gas properties, at cost, using the full cost method of accounting					328,583,605			298,203,082			217,173,798
	Unevaluated property costs					12,382,509			12,173,497			14,673,338
	Other property and equipment					3,856,073			3,445,408			3,031,694
	Less accumulated depreciation, depletion, and amortization					(89,358,974	)		(85,709,644	)		(64,955,626	)
			Total property and equipment, net			255,463,213			228,112,343			169,923,204
Other assets, net						668,780			495,625			418,323
			Total assets		$	284,472,935		$	247,452,216		$	186,048,696
Liabilities and Shareholders' Equity
Current liabilities:
	Accounts payable				$	17,853,212		$	17,706,468		$	13,690,646
	Revenues payable					7,532,860			5,388,333			2,571,724
	Drilling advances					—			—			687,813
	Accrued interest					488,115			336,317			541,980
	Dividends payable					219,090			219,090			—
	Other current liabilities					19,078			9,534			5,582
			Total current liabilities			26,112,355			23,659,742			17,497,745
Noncurrent liabilities:
	Notes payable (note 4)					107,480,000			96,280,000			85,680,000
	Asset retirement liability					4,522,459			—			—
	Deferred income taxes (note 5)					33,277,522			26,741,080			20,241,869
			Total noncurrent liabilities			145,279,981			123,021,080			105,921,869
			Total liabilities			171,392,336			146,680,822			123,419,614
Commitments and contingencies (note 12)
Shareholders' equity:
	Common stock, $0.10 par value. Authorized 100,000,000 shares; issued 15,080,791, 15,080,791 and 13,021,989 shares at March 31, 2003, December 31, 2002 and 2001					1,508,079			1,508,079			1,302,199
	Additional paid-in capital					73,415,041			73,416,531			45,968,049
	Deferred compensation (note 7)					(299,653	)		(381,402	)		(851,363	)
	Retained earnings					42,287,402			30,070,595			20,635,866
	Treasury stock at cost, 473,308, 474,808 and 553,848 shares at March 31, 2003, December 31, 2002 and 2001					(3,830,270	)		(3,842,409	)		(4,425,669	)
			Total shareholders' equity			113,080,599			100,771,394			62,629,082
			Total liabilities and shareholders' equity		$	284,472,935		$	247,452,216		$	186,048,696

See accompanying notes to consolidated financial statements.

4

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MATADOR PETROLEUM CORPORATION
AND SUBSIDIARIES

Consolidated Statements of Operations

					Three Months Ended March 31						Years Ended December 31,
					2003			2002			2002			2001			2000
					(Unaudited)			(Unaudited)
Revenues:
	Natural gas revenues				$	26,456,368		$	7,258,264		$	43,903,215		$	45,069,044		$	32,097,165
	Oil revenues					5,139,338			3,004,067			16,032,378			18,804,626			16,727,148
			Total revenues			31,595,706			10,262,331			59,935,593			63,873,670			48,824,313
Operating costs and expenses:
	Lease operating expense					2,926,478			1,732,488			8,586,441			8,088,269			5,019,205
	Production taxes					2,067,682			907,198			4,939,476			5,023,833			3,868,685
	Depreciation, depletion, and amortization					5,833,287			4,684,560			20,766,268			16,738,226			10,179,365
	General and administrative					1,710,218			1,559,523			6,550,462			7,484,814			3,874,839
	Asset retirement expense					96,233			—			—			—			—
			Total operating costs and expenses			12,633,898			8,883,769			40,842,647			37,335,142			22,942,094
			Operating income			18,961,808			1,378,562			19,092,946			26,538,528			25,882,219
Other income (expense):
	Interest expense, net					(914,299	)		(897,927	)		(3,202,347	)		(3,372,922	)		(3,675,432	)
	Interest and other income					44,537			124,991			267,759			128,282			100,952
			Total other income (expense)			(869,762	)		(772,936	)		(2,934,588	)		(3,244,640	)		(3,574,480	)
			Income before income taxes			18,092,046			605,626			16,158,358			23,293,888			22,307,739
Income tax benefit (provision):
	Current					340			(322,954	)		671,178			(845,062	)		(212,715	)
	Deferred					6,237,027			606,949			(6,499,211	)		(7,567,164	)		(7,586,436	)
			Total income tax provision			6,237,367			283,995			(5,828,033	)		(8,412,226	)		(7,799,151	)
			Net income			11,854,679			321,631			10,330,325			14,881,662			14,508,588
			Cumulative effect of change in accounting principle			581,217			—			—			—			—
Accretion of puttable common stock (note 11) and preferred stock dividends (note 10)						—			—			—			—			773,409
			Net income available to common shareholders		$	12,435,896		$	321,631		$	10,330,325		$	14,881,662		$	13,735,179
Income per common share—basic:
	Income before cumulative effect of change in accounting principle				$	0.81		$	0.03		$	0.74		$	1.20		$	1.28
	Cumulative effect of change in accounting principle					0.04			—			—			—			—
Net income attributable to common stock					$	0.85		$	0.03		$	0.74		$	1.20		$	1.28
Income per common share—diluted:
	Income before cumulative effect of change in accounting principle				$	0.78		$	0.03		$	0.72		$	1.14		$	1.10
	Cumulative effect of change in accounting principle					0.04			—			—			—			—
Net income attributable to common stock					$	0.82		$	0.03		$	0.72		$	1.14		$	1.10
Weighted average number of common shares used in computation:
	Basic					14,606,216			12,468,743			13,945,986			12,426,197			10,727,622
	Diluted					15,160,650			13,004,810			14,438,814			13,022,252			13,177,917
Cash dividends per share of common stock					$	0.015		$	0.012		$	0.050		$	0.048		$	0.040

See accompanying notes to consolidated financial statements.

5

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MATADOR PETROLEUM CORPORATION
AND SUBSIDIARIES

Consolidated Statements of Changes in Shareholders' Equity

Years ended December 31, 2002, 2001, and 2000
Three months ended March 31, 2003 (unaudited)

					Common stock														Treasury stock
										Additional paid-in capital			Deferred compensation			Retained earnings (deficit)								Total shareholders' equity
					Shares		Amount												Shares		Amount
Balance, December 31, 1999					10,684,449		$	1,068,445		$	15,597,852		$	—		$	(6,982,715	)	—		$	—		$	9,683,582
Comprehensive income:
	Net income				—			—			—			—			14,508,588		—			—			14,508,588
			Total comprehensive income		—			—			—			—			14,508,588		—			—			14,508,588
Expiration of put on common stock (note 11)					—			—			22,000,000			—			—		—			—			22,000,000
Issuance of common stock — employee benefit plans					4,200			420			19,273			—			—		—			—			19,693
Conversion of preferred stock (note 10)					2,333,340			233,334			6,382,993			—			—		—			—			6,616,327
Purchase of treasury stock (note 11)					—			—			—			—			—		(666,669	)		(5,333,352	)		(5,333,352	)
Issuance of treasury stock (note 11)					—			—			(88,869	)		—			—		52,413			419,304			330,435
Common stock dividends					—			—			—			—			(409,638	)	—			—			(409,638	)
Preferred stock dividends					—			—			—			—			(792,853	)	—			—			(792,853	)
Balance, December 31, 2000					13,021,989			1,302,199			43,911,249			—			6,323,382		(614,256	)		(4,914,048	)		46,622,782
Comprehensive income:
	Net income				—			—			—			—			14,881,662		—			—			14,881,662
			Total comprehensive income		—			—			—			—			14,881,662		—			—			14,881,662
Paid-in capital stock options (note 7)					—			—			2,003,360			(2,003,360	)		—		—			—			—
Amortization of deferred compensation (note 7)					—			—			—			1,151,997			—		—			—			1,151,997
Issuance of treasury stock (note 11)					—			—			53,440			—			—		64,786			515,172			568,612
Purchase of treasury stock (note 11)					—			—			—			—			—		(4,378	)		(26,793	)		(26,793	)
Common stock dividends					—			—			—			—			(569,178	)	—			—			(569,178	)
Balance, December 31, 2001					13,021,989			1,302,199			45,968,049			(851,363	)		20,635,866		(553,848	)		(4,425,669	)		62,629,082
Comprehensive income:
	Net income				—			—			—			—			10,330,325		—			—			10,330,325
			Total comprehensive income		—			—			—			—			10,330,325		—			—			10,330,325
Issuance of common stock					2,058,802			205,880			27,198,720			—			—		—			—			27,404,600
Amortization of deferred compensation (note 7)					—			—			—			469,961			—		—			—			469,961
Issuance of treasury stock (note 11)					—			—			249,762			—			—		87,592			706,553			956,315
Purchase of treasury stock (note 11)					—			—			—			—			—		(8,552	)		(123,293	)		(123,293	)
Common stock dividends					—			—			—			—			(895,596	)	—			—			(895,596	)
Balance, December 31, 2002					15,080,791		$	1,508,079		$	73,416,531		$	(381,402	)	$	30,070,595		(474,808	)	$	(3,842,409	)	$	100,771,394
Comprehensive income:
	Net income				—			—			—			—			12,435,896		—			—			12,435,896
			Total comprehensive income		—			—			—			—			12,435,896		—			—			12,435,896
Amortization of deferred compensation					—			—			—			81,749			—		—			—			81,749
Issuance of treasury stock					—			—			(1,490	)		—			—		1,500			12,139			10,649
Common stock dividends					—			—			—			—			(219,089	)	—			—			(219,089	)
Balance, March 31, 2003					15,080,791		$	1,508,079		$	73,415,041		$	(299,653	)	$	42,287,402		(473,308	)	$	(3,830,270	)	$	113,080,599

See accompanying notes to consolidated financial statements.

6

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MATADOR PETROLEUM CORPORATION
AND SUBSIDIARIES

Consolidated Statements of Cash Flows

						Three Months Ended March 31,						Years Ended December 31
						2003			2002			2002			2001			2000
						(Unaudited)			(Unaudited)
Cash flows from operating activities:
	Net income					$	12,435,896		$	321,631		$	10,330,325		$	14,881,662		$	14,508,588
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation, depletion, and amortization					5,833,287			4,684,560			20,766,268			16,738,226			10,179,365
		Asset retirement expense					96,233			—			—			—			—
		Deferred income tax provision					6,237,027			606,951			6,499,211			7,567,164			7,586,436
		Noncash stock-based compensation					81,749			155,678			727,578			1,151,997			—
		Cumulative effect of change in accounting principle					(581,217	)		—			—			—			—
		Other					6,000			16,500			71,721			65,939			203,377
		Change in operating assets and liabilities:
			(Increase) decrease in accounts receivable				(7,818,508	)		103,020			(6,286,813	)		1,064,821			(5,910,382	)
			Increase in prepaid expenses and other				(156,112	)		(201,428	)		(455,253	)		(590,407	)		(94,110	)
			Increase (decrease) in accounts and revenues payable				2,291,273			(3,047,428	)		6,832,431			7,414,225			3,925,426
			Increase (decrease) in other current liabilities				161,342			(635,614	)		(889,524	)		(37,005	)		515,065
			Decrease in other long-term liabilities				—			—			—			—			(509,782	)
				Net cash provided by operating activities			18,586,970			2,003,870			37,595,944			48,256,622			30,403,983
Cash flows from investing activities:
	Oil and natural gas property capital expenditures						(26,827,063	)		(12,574,906	)		(75,144,692	)		(66,576,590	)		(38,549,178	)
	Oil and natural gas property acquisitions						(638,222	)		(97,540	)		(3,389,091	)		(4,756,245	)		(6,375,320	)
	Other property and equipment capital expenditures						(410,665	)		(16,431	)		(413,714	)		(650,350	)		(717,679	)
	Proceeds from sale of oil and natural gas properties						—			—			4,340			301,802			880,559
				Net cash used in investing activities			(27,875,950	)		(12,688,877	)		(78,943,157	)		(71,681,383	)		(44,761,618	)
Cash flows from financing activities:
	Principal payments on notes payable						(800,000	)		(8,400,000	)		(41,200,000	)		(29,850,000	)		(19,840,000	)
	Net proceeds from borrowings						12,000,000			15,300,000			51,800,000			57,150,000			40,450,000
	Payments of dividends						(219,090	)		(155,852	)		(676,506	)		(569,178	)		(1,202,491	)
	Issuances of common and treasury stock						10,650			175,327			28,103,298			568,613			350,128
	Purchase of treasury stock						—			(70,800	)		(123,293	)		(26,793	)		(5,333,352	)
				Net cash provided by financing activities			10,991,560			6,848,675			37,903,499			27,272,642			14,424,285
				Net increase (decrease) in cash and cash equivalents			1,702,580			(3,836,332	)		(3,443,714	)		3,847,881			66,650
Cash and cash equivalents, beginning of period							1,729,921			5,173,635			5,173,635			1,325,754			1,259,104
Cash and cash equivalents, end of period						$	3,432,500		$	1,337,303		$	1,729,921		$	5,173,635		$	1,325,754
Supplemental disclosures of cash flow information:
	Cash paid (received) during the period for:
		Interest				$	744,501		$	921,907		$	3,411,147		$	3,373,276		$	3,675,432
		Income taxes					—			—			(671,178	)		845,062			112,715
	Noncash transactions during the period for:
		Stock issued to retirement plan					—			—			371,550			289,110			245,702

See accompanying notes to consolidated financial statements.

7

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MATADOR PETROLEUM CORPORATION
AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2002 and 2001

(Unaudited with respect to March 31, 2003 and 2002)

(1)   Organization

        Matador Petroleum Corporation (the Company), a Texas corporation, engages in the exploration, development, and production of oil and natural gas reserves in the United States. The Company's operations are located primarily in the East Texas Basin and the Permian Basin of West Texas and Southeastern New Mexico.

        Beginning in 1983, Company Chairman and CEO, Joseph Wm. Foran, founded a series of drilling partnerships and affiliated companies for the purpose of investing in oil and gas properties. Foran Oil Company served as the operating company for purposes of drilling and producing the wells that these partnerships and affiliated companies owned. The partnerships and affiliated companies were rolled up in 1988 to form Matador Petroleum Corporation, with Foran Oil Company changing its name to Matador Operating Company. Matador Petroleum Corporation held the primary assets of the Company while its now wholly owned subsidiary, Matador Operating Company, served as the operating company.

(2)   Summary of Significant Accounting Policies

(a)

Principles of Consolidation

        The consolidated financial statements include the accounts of Matador Petroleum Corporation and its two wholly owned subsidiaries, Matador E&P Company and NZX Corporation. Matador E&P Company includes four wholly owned subsidiaries, Matador Operating Company, Matador Royalty Corporation, Serenity Petroleum, Inc., and Pilot Production Company. All intercompany balances and transactions have been eliminated in consolidation.

(b)

Unaudited Interim Information

        The unaudited interim financial statements as of March 31, 2003 and for the three months ended March 31, 2003 and 2002, included herein, have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, they do not include all the information and footnotes required by accounting principles generally accepted in the United States of America for complete financial statements. In the opinion of management, the unaudited interim financial statements contain all adjustments (consisting of normal recurring adjustments) considered necessary for a fair presentation. The interim financial statements are not necessarily indicative of operating results for an entire year.

(c)

Cash and Cash Equivalents

        The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents.

(d)

Property and Equipment

        The Company follows the full-cost method of accounting for oil and natural gas properties. Accordingly, all costs associated with the acquisition, exploration, and development of oil and natural gas reserves are capitalized as incurred. Internal costs are capitalized only to the extent they are directly related to acquisition, exploration, or development activities and do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $2,374,613, $1,789,034, and $1,361,923 of these internal costs in 2002, 2001, and 2000, respectively. If the net capitalized costs of evaluated oil and natural gas properties less related deferred income taxes exceed the estimated present value of after-tax future net cash flows from proved oil and natural gas reserves, discounted at 10%, such excess is charged to operations as an oil and natural gas property impairment. No impairment of net capitalized costs due to the full-cost limitation was necessary in 2002, 2001, or 2000.

8

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        The changes in our unevaluated property costs are shown below:

			December 31,
			2002			2001			2000
Beginning balance			$	14,673,338		$	14,760,462		$	7,678,881
Exploration				6,951,295			16,925,250			12,069,330
Development				47,896,482			18,839,135			14,520,304
Interest				74,858			353,344			330,776
	Total additions to unevaluated properties			54,922,635			36,117,729			26,920,410
Reclasses to full-cost pool				(57,422,476	)		(36,204,853	)		(19,838,829	)
Ending balance			$	12,173,497		$	14,673,338		$	14,760,462

        Of the $12,173,497 balance of unevaluated property costs as of December 31, 2002, $4,896,296, $3,086,814, and $2,663,631 were incurred in 2002, 2001, and 2000, respectively. The remaining $1,526,756 was incurred prior to 2000.

        Capitalized costs of oil and natural gas properties, including the estimated future costs to develop proved reserves, are amortized on the unit-of-production method based upon production and estimates of proved reserve quantities. Depreciation, depletion, and amortization (DD&A) per Mcfe was $1.09 in 2002, $1.02 in 2001, and $0.87 in 2000. Unevaluated property costs are excluded from the amortization base used to determine DD&A. Unevaluated properties are assessed for impairment on an annual basis or more often if deemed necessary based upon changes in operating or economic conditions. Upon impairment, the costs of the unevaluated properties are immediately included in the amortization base. Exploratory dry hole costs are included in the amortization base immediately upon determination that the well is not productive. Geological and geophysical costs not associated with a specific unevaluated property are included in the amortization base as incurred.

        Sales of oil and natural gas properties, except for those held for resale, are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs relating to production activities and maintenance and repairs are charged to expense when incurred. Significant workovers that increase the properties' reserves are capitalized.

(e)

Capitalized Interest

        Pursuant to Statement of Financial Accounting Standards (SFAS) No. 34, Capitalization of Interest Costs, interest is capitalized on assets, during work in process, that have been excluded from the amortization base. Capitalized interest costs were $74,858, $353,344, and $330,776 for the years ended December 31, 2002, 2001, and 2000, respectively.

(f)

Revenue Recognition

        Revenue is generally recognized from properties as oil and natural gas is produced and sold net of royalties. Revenues from natural gas production are generally recorded using the sales method, net of royalties. Under this method, revenue is recognized based on the cash received rather than the proportionate share of natural gas produced. Natural gas imbalances at December 31, 2002, 2001, and 2000 were insignificant.

        The Company has no allowance for doubtful accounts related to its trade accounts receivable for any period.

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(g)

Accounting for Stock-Based Employee Compensation Arrangements

        The Company has chosen to continue to account for employee stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, and the related interpretations in accounting for option plans. Accordingly, compensation cost for stock options is measured as the excess, if any, of the estimated market price of the Company's common stock at the date of the grant over the amount an employee must pay to acquire the stock.

        Had compensation cost for the Company's options been determined based on the fair value at the grant dates consistent with SFAS No. 123, the Company's net income would have been decreased to the pro forma amounts indicated below:

					Three months ended March 31,						Year ended December 31,
					2003			2002			2002			2001			2000
Net income, available to common shareholders, as reported					$	12,435,896		$	321,631		$	10,330,325		$	14,881,662		$	13,735,179
	Less total stock-based compensation expense determined under fair value-based method for all awards, net of related tax effects					(75,677	)		(88,598	)		(404,234	)		(476,158	)		(264,840	)
			Pro forma net income		$	12,360,219		$	233,033		$	9,926,091		$	14,405,504		$	13,470,339
Earnings per share:
	Basic—as reported				$	0.85		$	0.03		$	0.74		$	1.20		$	1.28
	Basic—pro forma				$	0.84		$	0.02		$	0.71		$	1.16		$	1.26
	Diluted—as reported				$	0.82		$	0.03		$	0.72		$	1.14		$	1.10
	Diluted—pro forma				$	0.82		$	0.02		$	0.69		$	1.11		$	1.08

        The calculated value of stock options granted under these plans, following calculation methods prescribed by SFAS No. 123, uses the Black-Scholes stock option pricing model with the following weighted average assumptions used:

		2002		2001		1999
Expected option life		5 years		7 years		7 years
Risk-free interest rate		4.59%		5.10%		6.16%
Dividend yield		0.25%		0.25%		0.25%

(h)

Earnings Per Share

        Pursuant to SFAS No. 128, Earnings Per Share, basic earnings per share is computed based upon the weighted average number of common shares outstanding during the periods. Diluted earnings per share is computed based upon the weighted average number of common shares outstanding plus the assumed issuance of common shares for all potentially dilutive securities. See note 6 for a reconciliation of the basic and diluted earnings per share computations.

        On October 1, 1999, the Company declared a two-for-one stock split in the form of a 100% stock dividend on the Company's common stock. On July 1, 2001, the Company declared a three-for-one stock split, also in the form of a stock dividend, related to the Company's common stock. All common share and per common share amounts in the accompanying consolidated financial statements and notes have been restated to retroactively effect the 100% stock dividend declared in 1999 and the three-for-one stock split declared on July 1, 2001.

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(i)

New Accounting Pronouncements

        Effective January 1, 2001, the Company adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. SFAS No. 133, as amended, requires the Company to recognize all derivative instruments (including certain derivative instruments embedded in other contracts) on the balance sheet as either an asset or a liability measured at fair value. At December 31, 2002 and 2001, the Company had not entered into any contracts or utilized any derivative instruments that meet the criteria as defined in this pronouncement.

        In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 141, Business Combinations. SFAS No. 141 addresses the accounting and reporting for business combinations. SFAS No. 141 requires that all business combinations be accounted for under the purchase method of accounting. SFAS No. 141 also changes the criteria for the separate recognition of intangible assets acquired in a business combination. SFAS No. 141 is effective for all business combinations initiated after June 30, 2001. The adoption of SFAS No. 141 as of July 1, 2001 had no impact on the Company's consolidated financial statements.

        Also in June 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets. SFAS No. 142 addresses accounting and reporting for intangible assets acquired, except for those acquired in a business combination. SFAS No. 142 presumes that goodwill and certain intangible assets have indefinite useful lives. Accordingly, goodwill and certain intangibles will not be amortized, but rather will be tested at least annually for impairment. SFAS No. 142 also addresses accounting and reporting for goodwill and other intangible assets subsequent to their acquisition. SFAS No. 142 is effective for fiscal years beginning after December 15, 2001. The adoption of SFAS No. 142 had no impact on the Company's consolidated financial statements.

        The Company has been made aware of an issue that has arisen in the industry regarding the application of certain provisions of SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," to companies in the extractive industries, including oil and gas companies. The issue is whether the provisions of SFAS No. 141 and SFAS No. 142 require registrants to classify costs associated with mineral rights, including both proved and unproved lease acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and to provide specific footnote disclosures.

        Historically, the Company has included oil and gas lease acquisition costs as a component of oil and gas properties. In the event it is determined that costs associated with mineral rights are required to be classified as intangible assets, a substantial portion of the Company's oil and gas property acquisition costs since the June 30, 2001 effective date of SFAS Nos. 141 and 142 would be separately classified on its balance sheets as intangible assets. However, the Company's results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with full cost accounting rules. Further, the Company does not believe the classification of oil and gas lease acquisition costs as intangible assets would have any impact on the Company's compliance with covenants under its debt agreements.

        In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 is effective for financial statements issued for fiscal years beginning after June 15, 2002. The adoption of SFAS No. 143 as of January 1, 2003 resulted in an increase to oil and natural gas properties of approximately $3.0 million and a reduction of accumulated depreciation, depletion, and amortization of approximately $2.2 million. The asset retirement obligation was approximately $4.3 million. The cumulative effect of the change in accounting principle was a gain of approximately $0.6 million, net of taxes of $0.3 million.

        In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated With Exit or Disposal Activities. This statement addresses significant issues relating to the recognition, measurement, and reporting

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of costs associated with exit and disposal activities, including restructuring activities. This statement is not expected to have a significant effect on the Company's consolidated financial statements.

        In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure, which amends SFAS No. 123. This statement provides alternative methods of transition for entities that voluntarily change to the fair value-based method of accounting for stock-based employee compensation, as well as amends certain disclosure requirements of SFAS No. 123. The Company has retained the intrinsic value method of accounting for stock-based employee compensation arrangements, but has adopted the additional disclosure requirements of SFAS No. 148.

(j)

Management's Use of Estimates

        The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

        The Company's consolidated financial statements are based on a number of significant estimates including oil and natural gas reserve quantities that are the basis for the calculations of depletion and impairment of oil and natural gas properties. The Company's reserve estimates, which are inherently imprecise, are determined by independent outside petroleum engineers.

(k)

Reclassifications

        Certain reclassifications have been made to prior year amounts to conform to the current year presentation.

(l)

Risk and Uncertainties

        Historically, the market for oil and natural gas has experienced significant price fluctuations. Prices are impacted by supply and demand, seasonal variations, and other factors. Increases or decreases in prices received could have a significant impact on the Company's future results of operations, financial position, and the Company's allowed borrowing base under its credit facility, which was $105.0 million and $95.0 million at December 31, 2002 and 2001, respectively (see note 4).

(m)

Concentrations of Credit Risk

        Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of trade accounts receivable. Management believes that the credit risk posed by this concentration is offset by the creditworthiness of the Company's customer base.

(n)

Fair Value of Financial Instruments

        The carrying amounts of the Company's cash and cash equivalents, receivables, payables, and accrued expenses approximate fair value due to the short-term maturities of these assets and liabilities. The carrying amount of the Company's notes payable approximates fair value due to the variable, floating interest rate structure of the notes.

(3)   Acquisitions

        On January 22, 2000, the Company acquired proved oil and natural gas properties valued at approximately $6.1 million for cash equal to the property values. Pro forma results of operations for the Company for the year ended December 31, 2000, assuming the transaction had occurred on January 1, 2000, would not have been materially different and, as such, pro forma results for the year ended December 31, 2000 have not been provided.

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(4)   Notes Payable

        Notes payable of the Company consist of the following:

        The aggregate maturities of principal on notes payable at December 31, 2002 are $19,040,000 for 2004, $19,040,000 for 2005, $19,040,000 for 2006, $38,080,000 for 2007, and $1,080,000 thereafter.

        The current bank credit facility is limited to the lesser of $200.0 million or the borrowing base, which is determined by the banks semiannually based primarily on proved oil and natural gas reserves. At December 31, 2002, the borrowing base was $105.0 million. Under the terms of the loan agreement, the Company is prohibited from incurring additional debt and declaring and paying common stock dividends in excess of $950,000 a year. The transaction to purchase 666,669 shares of the Company's common stock from a converting preferred shareholder received the consent of the banks on December 19, 2000, prior to consummation (see note 11). In addition, the Company's ratio of current assets to current liabilities cannot be less than 1.0 to 1.0 with any unused borrowing base added to current assets. The tangible net worth as of the end of any fiscal quarter commencing with the quarter ending March 31, 1999 cannot be less than $25.0 million, plus 60% of the Company's consolidated net income for each quarter from and after January 1, 1999, in which such net income was positive (quarters in which the Company's consolidated net income was negative shall be disregarded), plus the net proceeds received by the Company for capital stock issued by the Company after March 31, 1999. In addition, earnings before interest, tax, and depreciation (EBITDA) must exceed interest expense by 2.75x on a rolling four-quarter basis. The Company was in compliance with all debt covenants at December 31, 2002 and 2001.

(5)   Income Taxes

        The Company follows the provisions of SFAS No. 109, Accounting for Income Taxes, which provides for recognition of a deferred tax liability or asset for deductible temporary timing differences, operating loss carryforwards, statutory depletion carryforwards, and tax credit carryforwards net of a valuation allowance.

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        The components of income tax expense consist of the following:

        A reconciliation of income tax expense to tax at the federal statutory rate is as follows:

        The principal components of the Company's deferred income tax liability are as follows:

        For tax reporting purposes, the Company had operating loss carryforwards of approximately $9.0 million at December 31, 2002. If not utilized, such carryforwards will begin to expire in 2009 and will completely expire by the year 2019. No valuation allowance has been provided for the deferred tax assets above, as management does not expect the Company's net operating loss carryforwards to expire without being utilized.

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(6)   Earnings Per Share

        Basic and diluted net income per share is computed based on the following information:

					Year ended December 31,
					2002			2001			2000
Numerator:
	Basic:
		Net income			$	10,330,325		$	14,881,662		$	14,508,588
		Preferred stock dividend				—			—			(773,409	)
			Income available to common shareholders		$	10,330,325		$	14,881,662		$	13,735,179
	Diluted:
		Net income available to common shareholders			$	10,330,325		$	14,881,662		$	13,735,179
		Effect of assumed conversion of preferred stock				—			—			773,409
			Income available to common shareholders after assumed conversions		$	10,330,325		$	14,881,662		$	14,508,588
Denominator:
		Denominator for basic earnings per share—weighted average shares				13,945,986			12,426,197			10,727,622
		Effect of dilutive securities:
			Preferred stock			—			—			2,269,413
			Stock options			492,828			596,055			180,882
			Dilutive potential common shares			492,828			596,055			2,450,295
	Denominator for dilutive earnings per share—adjusted weighted average shares and assumed conversion					14,438,814			13,022,252			13,177,917
Basic earnings per share					$	0.74		$	1.20		$	1.28
Diluted earnings per share						0.72			1.14			1.10

(7)   Stock Options

        The Company has an incentive stock option plan for its key employees that was adopted in 1998 and will remain in effect until 2008. The 1998 Omnibus Stock and Incentive Plan (Option Plan) provides that options may be granted to purchase no more than 1.2 million shares in the aggregate to employees of the Company that are eligible to receive option grants. To date, most options have been granted with a four-year vesting schedule and a ten-year term. All options granted in 2002 have a three-year vesting schedule and a five-year term. The Option Plan also authorizes the granting of stock appreciation rights either in tandem with or independent of the options. These rights allow the optionee to tender vested options and receive the difference between the option price and the price of the Company's common stock at the time of exercise. At the Company's option, these may be paid to the optionee in the equivalent value of common stock or cash. Any stock appreciation rights issued under the Option Plan would be canceled upon the completion of an initial public offering of the Company's common stock and listing on a national exchange. No stock appreciation rights are currently outstanding under the Option Plan and none were outstanding during the years ended December 31, 2002, 2001, and 2000.

        In 1998, the Company instituted the NonStatutory Director Stock Option Plan designed to encourage nonemployee directors to participate in the ownership of the Company. The total number of options available for grant under the director stock option plan is 600,000.

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        Summarized information about the Company's stock option plans is as follows:

		2002					2001					2000
		Number of options		Weighted average exercise price			Number of options		Weighted average exercise price			Number of options		Weighted average exercise price
Outstanding at beginning of year		1,267,940		$	8.06		892,950		$	5.52		784,374		$	5.27
Granted		58,700			13.53		465,785			12.51		157,476			6.40
Exercised		(60,783	)		5.18		(45,036	)		6.05		(26,400	)		3.75
Canceled		(8,801	)		10.13		(45,759	)		5.68		(22,500	)		5.38
Outstanding at end of year		1,257,056			8.44		1,267,940			8.06		892,950			5.52
Exercisable at end of year		864,148			7.40		669,831			6.64		465,876			5.27
Available for grant at end of year		1,108,225					1,158,124					1,579,350
Weighted average fair value of options granted during the year					2.59					3.44					2.15

        The following table summarizes information about stock options outstanding as December 31, 2002:

        During the year ended December 31, 2001, the Company granted 465,785 stock options to employees and directors with exercise prices ranging from $8.33 to $17.00. All options granted to employees vest over four years and all options granted to directors vest immediately. The Company recorded compensation expense of $1,151,997 during the year ended December 31, 2001 related to 428,385 of these options granted between February and June 2001. The expense represents the excess of the estimated fair value of the Company's common stock over the exercise price, recognized over the vesting period of the options. For purposes of determining compensation expense for the options granted between February and June 2001, the Company estimated the fair value of its common stock to be equal to the expected offering price of the Company's common stock in its proposed initial public offering. The Company recorded additional compensation expense of $469,961 during the year ended December 31, 2002 related to these options. As of December 31, 2002, the Company had deferred compensation expense of $381,402, which will be recognized ratably over the remaining related option vesting period.

        During the year ended December 31, 2002, the Company granted 58,700 stock options to employees and directors with exercise prices ranging from $13.50 to $17.00. All options granted to employees vest over three years and all options granted to directors vest immediately. All options granted in 2002 were at exercise prices that equaled estimated fair value at grant date.

        In April 2002, several managerial employees exercised stock options. Loans of up to 75% of the exercise price of the options were made available to these employees (see note 13). Because the loans were granted interest free, in accordance with FASB Interpretation No. 44, Accounting for Certain Transactions Involving Stock Compensation, the exercise price of the options was effectively altered, triggering variable accounting. As such, the Company recorded $257,617 in noncash compensation expense, representing the difference between the fair value of the stock on the date of exercise and the present value of the future cash flow payments from the loans.

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(8)   Employee Incentive Plans

        During April 1997, the Company began a compensation plan (the 1997 Plan) to compensate all eligible employees (those employed by the Company on or before September 1997). The 1997 Plan disbursements were to begin in 2001, and were to be based on achieving certain publicly traded stock price thresholds before January 1, 2001. All award amounts payable under the 1997 Plan could not exceed 5.0% of the total increase in value of the Company to the shareholders from the effective date of April 3, 1997. During 1999, the employees participating in the 1997 Plan were given the option to continue in the 1997 Plan or convert their participation to a revised compensation plan (the Millennium Plan). All participating employees converted to the Millennium Plan, which included a cash bonus equal to 25% of salary as calculated pursuant to the original 1997 Plan to be paid when the Company achieves a public or private stock price of $8.33 per share as determined by the board of directors or public markets. During August 2000, the board of directors determined that such criteria had been met and the cash bonus was paid to participating employees. Consequently, the Company recorded compensation expense during 2000 of $586,216 related to the Incentive Plan.

        During the first quarter of 2001, the Company established a share price appreciation plan (the Appreciation Plan) to provide key employees with added incentives to maximize the Company's share price and to attract and retain qualified personnel. The amount of the disbursements will be based on whether the Company achieves a threshold of $16.67 per share of the Company's common stock before January 1, 2004 and maintains such share price for a period of 30 trading days (which need not be consecutive) within 90 consecutive trading days. The compensation committee determines the terms and conditions of each grant, but vesting of awards under the plan is subject to the conditions that (1) the Company completes an initial public offering and be listed and traded on a national or regional stock exchange or on the NASDAQ National Market System, prior to January 1, 2004, or (2) the Company is sold or merged prior to January 1, 2004. The total award amounts payable under the Appreciation Plan cannot exceed 5.0% of the total increase in value of the Company to the shareholders from the effective date of March 1, 2001. It has been determined that this 5.0% limitation will be based upon an assumed price per share of $8.33 as of March 1, 2001. During March 2001, the Company granted an award under the Appreciation Plan, whereby if the conditions above are met, participating employees would immediately receive a bonus payable in cash or common stock at the discretion of the Company, equal to 25% of the participating employees' annual salary. The amount payable under this award if the conditions above are met is approximately $1.2 million.

        Upon meeting the vesting conditions, the Company will record compensation expense of approximately $1.2 million in the period such conditions are met. No compensation expense has been recorded for this award as of December 31, 2002, because the vesting conditions have not been met.

(9)   Retirement Plan

        Effective January 1, 1992, the Company began a defined contribution retirement plan. All Company employees with a minimum of six months of service are eligible. Each employee may contribute between 1% and 15% of annual compensation, up to the maximum allowable amount under the Internal Revenue Code. The board of directors determines the Company's matching contributions. The Company's matched employee compensation amounted to $400,902, $318,784, and $245,810 in 2002, 2001, and 2000, respectively. The Company funded its matching contribution in cash and 24,770 shares of the Company's common stock in 2002, 19,274 shares of common stock in 2001, and 29,496 shares of common stock in 2000. It is anticipated that future company matching contributions will be made in common stock.

(10) Convertible Preferred Stock

        During May 1996, the Company sold 388,890 shares of Series A Convertible Preferred Stock (the Preferred Stock) (par value $0.10 per share and liquidation preference and redemption amount of $18.00 per share) for $18.00 per share.

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        The Preferred Stock was redeemable at the option of the holder beginning in April 2001, unless the Company had completed a qualifying initial public offering on or before May 2000. The Preferred Stock was convertible into the Company's common stock at a $3.00 per common share price at any time prior to redemption and was subject to customary antidilution provisions. Prior to May 2000, the preferred shareholders were entitled to receive a dividend commensurate and concurrent with any per share dividend declared on the Company's common stock. Subsequent to May 2000, the preferred shareholders were entitled to receive an additional dividend at an annual rate of $1.80 per share. During the year ended December 31, 2000, Preferred Stock dividends related to these requirements were $480,281.

        On December 22, 2000, all the outstanding Preferred Stock was converted into 2,333,340 shares of the Company's common stock, in accordance with the original conversion terms of the agreement. In connection with the conversion, the Company paid additional preferred dividends of $293,128, representing the discounted value of certain future dividends. All preferred dividends paid on the Preferred Stock during the year ended December 31, 2000 have been deducted in the determination of net income available to common shareholders and for purposes of computing earnings per share for 2000.

(11) Common Stock

(a) Puttable Common Stock

        The stock purchase agreement, pursuant to which the Company issued 4,020,000 shares of common stock in 1998 in exchange for oil and natural gas properties acquired from Unocal, gave Unocal the right to put such stock back to the Company for $22.0 million in cash if such put right was not otherwise extinguished pursuant to the terms of the agreement. The put right was first exercisable on January 2, 1999, and if not exercised on such date, the holder had the right to exercise the put option on January 2, 2000. If the put option was not exercised on January 2, 2000, it expired on such date.

        The holder of the puttable common stock did not exercise the put option and, accordingly, the put option expired on January 2, 2000.

        The Company classified the puttable common stock outside of shareholders' equity for all periods prior to expiration of the put as the ability to extinguish the put was not considered to be completely within the control of the Company. Further, in accordance with the Securities and Exchange Commission rules and regulations, the Company has accreted the difference between the value of the common stock issued in exchange for the oil and natural gas properties to the cash put amount of $22.0 million over the period from the closing date of the purchase transaction (January 20, 1998) to the earliest date the holder had the right to exercise the put (January 2, 1999). Such accretion has been charged to retained earnings in the amount of $4,991,066 in 1998 and $28,934 in 1999, and has been deducted in the determination of net income available to common shareholders for such periods.

(b) Stock Offering

        During 2002, the Company sold 2,058,802 shares of common stock in a private offering and received net proceeds of $27,404,600.

(c) Stock Rights

        During May 2001, the Company adopted a shareholder rights plan under which it declared a dividend of one common share purchase right for each outstanding share of common stock. The purchase rights entitle shareholders to purchase one share of common stock for an exercise price of $91.67, subject to adjustment. The rights are not immediately exercisable and will generally become exercisable only if a person or group acquires beneficial ownership of 15% or more of the Company's common stock or commences a tender or exchange offer, upon completion of which that person or group would beneficially own 15% or more of the Company's common stock. The rights will become exercisable by holders, other than the unsolicited third-party acquirer, for shares of

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the Company or of the third-party acquirer having a value of two times the rights' then-current exercise price. The Company may redeem the rights within ten days of the date on which a person or group acquires more than 15% of the Company's common stock, at a redemption price of $0.01 per right. The rights expire on May 16, 2011, unless otherwise extended.

(d) Treasury Stock

        On December 22, 2000, the Company purchased 666,669 shares of common stock at $8.00 per share from a previous holder of the Preferred Stock (see note 10).

        On December 29, 2000, the Company contributed 30,213 shares of common stock, issued out of treasury stock, at $8.33 per share to the Company's 401(k) Plan to fund the employer's matching contribution to the Retirement Plan (see note 9) and to certain shareholders for dividend reinvestment.

        Also issued out of treasury stock on December 29, 2000, the Company sold 22,200 shares of common stock to employees representing vested stock options exercised during December 2000.

        During 2001, the Company purchased 4,378 shares of common stock out of the Matador 401(k) Plan for $26,793, representing the vested shares held in the plan by certain terminated employees. The purchase price of the shares was equal to the most recent fair market value prior to the distribution of proceeds to the former employees.

        During 2001, the Company sold 45,036 shares of common stock, issued out of treasury stock, representing vested employee and director stock options exercised during the year.

        On December 31, 2001, the Company contributed 19,750 shares of common stock, issued out of treasury stock, at $15.00 per share to the Company's 401(k) Plan to fund a portion of the employer's matching contribution to the Retirement Plan (see note 9) and to certain shareholders for dividend reinvestment.

        During 2002, the Company purchased 1,402 shares of common stock out of the Matador 401(k) Plan for $20,768, representing the vested shares held in the plan by certain terminated employees. The purchase price of the shares was equal to the most recent fair market value prior to the distribution of proceeds to the former employees.

        During 2002, the Company purchased 7,150 shares of common stock from certain shareholders.

        During 2002, the Company sold 62,783 shares of common stock, issued out of treasury stock, representing vested employee and director stock options exercised during the year.

        On December 31, 2002 the Company contributed 24,809 shares of common stock, issued out of treasury stock, at $15.00 per share to the Company's 401(k) Plan to fund a portion of the employer's matching contribution to the Retirement Plan (see note 9) and to certain shareholders for dividend reinvestment.

(e) Stock Split

        On July 1, 2001, the Company declared a three-for-one split in the form of a stock dividend. All common shares and per common share amounts in the accompanying consolidated financial statements and notes have been restated to retroactively effect this stock split.

(12) Commitments and Contingencies

        As of December 31, 2002 and 2001, there were no contingent liabilities or litigation noted or provided for in the consolidated financial statements. From time to time, the Company is a party to litigation; however, there are no pending claims or other circumstances that are expected by management to lead to material litigation or to otherwise have a material impact on the Company's financial condition or results of operations.

19

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        The Company leases administrative offices under noncancelable operating leases expiring in 2004. Future minimum lease commitments are $108,108 and $3,206 in 2003 and 2004, respectively. Total rent expense incurred in the years ended December 31, 2002, 2001, and 2000 was $341,787, $282,788, and $213,849, respectively.

(a) General Federal and State Regulation

        Oil and natural gas exploration, production, and related operations are subject to extensive federal and state laws, rules, and regulations. Failure to comply with these laws, rules, and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases the cost of doing business and affects profitability. Because these rules and regulations are frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with these laws.

(b) Environmental Regulation

        The exploration, development, and production of oil and natural gas, including the operation of saltwater injection and disposal wells, are subject to various federal, state, and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing, and operating oil and natural gas wells. The Company's activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990, or OPA, the Clean Water Act, or CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Safe Drinking Water Act, or SDWA, as well as comparable state statutes and regulations. The Company is also subject to regulations governing the handling, transportation, storage, and disposal of naturally occurring radioactive materials, or NORM, that may result from its oil and natural gas operations. Civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, limit or prohibit other activities because of protected areas or species, and require investigation and cleanup of pollution. The Company has no outstanding material environmental remediation liabilities and believes that it is in compliance with currently applicable environmental laws and regulations and that these laws and regulations will not have a material adverse impact on the financial position or results of operations of the Company.

(13) Transactions With Related Parties

        During 2002, the Company granted interest-free loans to a number of its managerial employees allowing them to purchase additional shares of the Company's common stock. The loans are limited to $250,000 in aggregate outstanding amount and to 75% of the value of shares purchased. As of December 31, 2002, the balance of the loans outstanding was $108,930.

        Effective September 5, 2000, the Company entered into an agreement with Unocal in which the Company conveyed to Unocal an undivided 25% working interest in certain leasehold positions in the East Texas Bossier trend in exchange for reimbursement of land, geophysical, geological, and other related costs totaling approximately $3.6 million.

        Certain members of the Company's board of directors have invested as working interest owners in some of the wells that the Company has drilled. The wells in which these directors participated were generally the result of the Company's decision, on a well-by-well basis, to sell or farm-out a portion of the working interest in the well to reduce the Company's overall drilling risk level. These directors are billed monthly for expenses, and receive distributions of revenues on the same terms as other, nonaffiliated working interest owners. Since January 1, 1998, the Company drilled and currently operates 14 producing wells that include participation by directors. Except for wells that may be drilled within the existing contract areas of joint operating agreements of prospects in which directors currently hold working interests, the Company expects that no further working interest participation will be offered to directors. The sum of all revenues received by all directors for wells operated by the Company during the year 2002 totaled $430,011. A total of five directors have participated in Matador operated wells, with such participation ranging from 1% to 10% working interest, with an average individual participation of approximately 4%.

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(14) Major Customers

        During fiscal year 2002, the Company had two customers accounting for 11% and 20% of total revenues. During fiscal year 2001, the Company had three customers accounting for 10%, 12%, and 15% of total revenues. During fiscal year 2000 the Company had one customer accounting for 21% of total revenues. Due to the nature of the markets for oil and natural gas, the Company does not believe that the loss of any one customer would have a material adverse effect on the Company's financial condition or results of operations.

(15) Adoption of SFAS 143, "Accounting for Asset Retirement Obligations"

        Effective January 1, 2003, the Company adopted SFAS 143, "Accounting for Asset Retirement Obligations." 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 associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the asset's useful life. The adoption of SFAS 143 resulted in an increase in total liabilities as retirement obligations were required to be recognized, the recorded cost of assets increased to include the retirement costs added to the carrying amount of the asset and operating expenses increased subsequent to January 1, 2003 due to the accretion of the retirement obligation. Depletion and depreciation recognized in 2003 and subsequent periods will decrease since the salvage values assigned to these assets (now excluded from depreciation and depletion) exceeded the asset retirement costs recorded. The asset retirement obligations recorded by the Company relate to the plugging and abandonment of gas and oil wells. The Company adopted SFAS No. 143 on January 1, 2003, and recorded a discounted liability of $4.3 million for the future retirement obligation, an increase to property and equipment of $3.0 million and a gain of $0.6 million (net of a deferred tax benefit of $0.3 million) as the cumulative effect of change in accounting principle. There was no impact on the Company's cash flows as a result of adopting SFAS 143. Subsequent to the adoption of SFAS 143, there has been no significant current period activity with respect to additional asset retirement liabilities, settled liabilities or revisions of estimated cash flows other than additional asset retirement obligation of $0.2 million for wells drilled. Accretion expense of $0.1 million was recognized in the three months ended March 31, 2003.

        The following unaudited pro forma information has been prepared to give effect to the adoption of SFAS 143 as if it had been adopted on January 1, 2000.

						Year Ended
			Three Months Ended March 31, 2002			December 31, 2002			December 31, 2001			December 31, 2000
Net (loss) income
	As reported		$	321,631		$	10,330,325		$	14,881,662		$	14,508,588
	Accretion of retirement obligation (net of tax)			(58,269	)		(233,078	)		(213,833	)		(196,177	)
	Reduction of depreciation and depletion (net of tax)			63,394			253,574			332,010			350,945
	Pro forma		$	326,756		$	10,350,821		$	14,999,839		$	14,663,356
Basic net income (loss) per common share:
	As reported		$	0.03		$	0.74		$	1.20		$	1.28
	Pro forma		$	0.03		$	0.74		$	1.21		$	1.29
Diluted net income (loss) per common share:
	As reported		$	0.03		$	0.72		$	1.14		$	1.10
	Pro forma		$	0.03		$	0.72		$	1.15		$	1.11

(16) Events Subsequent to Date of Independent Auditor's Report (Unaudited)

        In March 2003 the bank credit facility was amended. The amendment extended the final maturity date to February 28, 2008 and the conversion date to a term loan from February 28, 2004 to February 28, 2005. The borrowing base was also increased to $115 million.

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        On May 14, 2003, a definitive merger agreement between the Company and Tom Brown, Inc., a Denver, Colorado based independent energy company, was executed. Tom Brown, Inc. agreed to acquire all of the outstanding shares of the Company for $17.53 per share and all outstanding options at $17.53 per option share less the exercise price of the options. Tom Brown also agreed to assume all outstanding debt. The boards of both companies approved the acquisition and the transaction closed on June 27, 2003.

(17) Supplemental Information Related to Oil and Natural Gas Exploration, Development, and Production Activities

        The following tables set forth certain historical costs and operating information related to the Company's oil and natural gas producing activities as of and for the years ended December 31, 2002, 2001, and 2000:

(a) Costs Incurred

        Costs incurred in oil and natural gas property acquisition, exploration, and development activities are summarized below:

				December 31,
				2002			2001			2000
Property acquisition costs:
	Proved, excluding deferred income taxes			$	3,389,091		$	4,756,245		$	6,375,320
Exploration costs					7,557,721			28,521,259			9,304,953
Development costs					67,586,971			38,055,331			29,244,225
		Total costs incurred		$	78,533,783		$	71,332,835		$	44,924,498

(b) Oil and Natural Gas Reserves (Unaudited)

        Reserves have been classified as proved, proved developed and proved undeveloped pursuant to the following definitions:

        Proved gas and oil reserves.    Proved gas and oil reserves are the estimated quantities of natural gas, crude oil and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contracts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

        Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (B) crude oil, natural gas and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors; (C) crude oil, natural gas and natural gas liquids that may occur in undrilled prospects; and (D) crude oil, natural gas and natural gas liquids that may be recovered from oil shales, coal, gilsonite and other such sources.

        Proved developed gas and oil reserves.    Proved developed gas and oil reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

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        Proved undeveloped reserves.    Proved undeveloped gas and oil reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production where drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.

        The Company's net ownership in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized below:

			Gas (Mmcf)		Oil (Mbbls)
Proved reserves at December 31, 1999			69,049		5,698
Revisions of estimates			640		(405	)
Improved recovery			14		33
Extensions and discoveries			36,950		822
Purchase of reserves			13,723		229
Sale of reserves			(105	)	(110	)
Production			(8,373	)	(554	)
Proved reserves at December 31, 2000			111,898		5,713
Revisions of estimates			(7,439	)	(9	)
Improved recovery			9		11
Extensions and discoveries			66,668		960
Purchase of reserves			8,731		22
Sale of reserves			(18	)	(13	)
Production			(11,822	)	(755	)
Proved reserves at December 31, 2001			168,027		5,929
Revisions of estimates			(13,593	)	(535	)
Improved recovery			40		199
Extensions and discoveries			95,404		2,252
Purchase of reserves			3,414		40
Production			(15,130	)	(648	)
Proved reserves at December 31, 2002			238,162		7,237
Proved developed reserves at:
	December 31, 2000		89,446		5,145
	December 31, 2001		108,452		5,260
	December 31, 2002		133,614		5,352

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Standardized Measure (Unaudited)

        The standardized measure of discounted future net cash flows relating to the Company's proved reserves as of year-end is shown below:

			December 31,
			2002			2001			2000
Future cash flows			$	1,279,884,973		$	511,735,030		$	1,214,431,163
Future production costs				(276,037,244	)		(129,536,419	)		(193,500,966	)
Future development costs				(107,250,657	)		(56,692,979	)		(25,886,677	)
	Future net cash flows before taxes			896,597,072			325,505,632			995,043,520
Future income taxes				(233,146,222	)		(69,035,539	)		(292,706,451	)
	Future net cash flows after taxes			663,450,850			256,470,093			702,337,069
Annual discount at 10%				(345,689,805	)		(127,253,937	)		(357,837,172	)
	Standardized measure of discounted future cash flows		$	317,761,045		$	129,216,156		$	344,499,897

        The average prices for oil and natural gas used to calculate future cash inflows at December 31, 2002, 2001, and 2000 were $30.32, $18.78, and $25.92 per Bbl and $4.54, $2.38, and $9.53 per Mcf, respectively. Future cash flows are computed by applying year-end prices of oil and natural gas to year-end quantities of proved oil and natural gas reserves. Future operating expenses, including overhead costs attributable to producing activities, and development costs are computed primarily by the Company's petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company's proved oil and natural gas reserves at the end of the year, based on the year-end costs and assuming continuation of existing economic conditions. Future income taxes are based on year-end statutory rates. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of the Company's oil and natural gas properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

        The Company estimates that it will incur the following amounts to develop proved undeveloped and proved developed non-producing reserves over the next three years (in thousands):

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Changes in Standardized Measure (Unaudited)

        Changes in standardized measure of future net cash flows relating to proved oil and natural gas reserves are summarized below:

		December 31,
		2002			2001			2000
Standardized measure, beginning of year		$	125,903,156		$	341,186,897		$	85,987,724
Oil and natural gas sales, net of production costs			(46,409,676	)		(50,761,568	)		(39,936,423	)
Net change in prices and production costs			147,840,779			(400,957,208	)		203,387,036
Extensions, discoveries, additions, and improved recovery, less related costs			152,611,776			43,705,406			150,815,048
Previously estimated development costs incurred during period			20,853,072			15,557,689			7,164,688
Revision of quantity estimates			(25,474,719	)		(5,835,523	)		(6,071,011	)
Purchases of minerals in place			6,173,403			7,442,289			13,745,110
Sales of minerals in place			—			(227,800	)		(2,592,317	)
Accretion of discount			15,856,284			49,671,263			10,891,628
Net change in income taxes			(79,846,562	)		122,867,051			(132,597,175	)
Changes due to timing and other			(3,059,468	)		3,254,660			50,392,589
Standardized measure, end of year		$	314,448,045		$	125,903,156		$	341,186,897

        Sales of oil and natural gas, net of production costs, are based on historical pretax results. All other amounts are reported on a pretax discounted basis.

        The actual costs incurred for the development of proved undeveloped and proved non-producing properties were as follows (in thousands):

		Proved Undeveloped			Proved Developed Non-producing			Total
2000		$	8,772		$	2,397		$	11,169
2001			13,541			1,886			15,427
2002			19,733			706			20,439

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Tom Brown, Inc.

PRO FORMA FINANCIAL INFORMATION

        On May 14, 2003, Tom Brown, Inc. ("Tom Brown" or the "Company") entered into an agreement to acquire all of the outstanding common stock of Matador Petroleum Corporation ("Matador"). Matador is an independent energy company based in Dallas, Texas engaged in oil and gas exploration, production, development and acquisition activities in the Southwestern United States. Approximately 85 percent of Matador's reserves are natural gas and Matador's primary focus has been the East Texas Basin and the Permian Basin of West Texas and Southeastern New Mexico.

        Under the terms of the definitive merger agreement, the Matador shareholders received a net price of $17.53 per common share and all option holders received $17.53 per option share less the exercise price of the options. Tom Brown also assumed approximately $121 million in net debt at closing for an aggregate purchase price of $388 million. Transaction costs of approximately $6.0 million were incurred for investment banking, legal, accounting and other direct merger-related costs. In addition, $7.7 million was incurred for payments made to officers and employees of Matador pursuant to a change in control arrangement previously entered into by Matador and $1.3 million was incurred for payments made to Matador employees under the terms of a stock appreciation plan, which provided for payments in the event of a change in control of Matador.

        In connection with the transaction, three officers of Matador entered into non-compete agreements with Tom Brown, for periods ranging from 3 to 21 months for aggregate consideration of $4.7 million.

        The following unaudited pro forma condensed combined financial information shows the pro forma effect of the acquisition. The unaudited pro forma condensed combined financial information includes pro forma statements of operations for the year ended December 31, 2002 and for the three months ended March 31, 2003, which assume the acquisition occurred on January 1, 2002. The unaudited pro forma condensed combined financial information also includes a pro forma balance sheet as of March 31, 2003, which assumes the acquisition occurred on that date.

        The unaudited pro forma condensed combined financial information has been prepared to provide an analysis of the financial effects of the acquisition. The pro forma information does not purport to represent what the financial position and results of operations of the combined company would have actually been had the acquisition in fact occurred on the dates indicated, nor is it necessarily indicative of the future results of operations.

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Tom Brown Inc.

Unaudited Pro Forma Condensed Balance Sheet

March 31, 2003

			Tom Brown, Inc. Historical			Matador Historical			Pro Forma Adjustments (Note 3)			Pro Forma Combined Company
			(In thousands)
Assets
Current assets
	Cash and cash equivalents		$	18,269		$	3,433		$	—		$	21,702
	Accounts receivable			75,785			24,180			—			99,965
	Prepaid expenses and other			5,071			729			—			5,800
Total currents assets				99,125			28,342			—			127,467
Property and equipment, at cost				1,148,084			344,822			41,304	(a)		1,534,240
	Less: Accumulated depreciation and depletion			340,274			89,359			89,359	(a)		340,274
Net property and equipment				807,810			255,463			130,663			1,193,936
										4,791	(f)
Goodwill, intangible assets and other				7,290			668			87,970	(a)		100,719
			$	914,225		$	284,473		$	223,424		$	1,422,122
Liabilities and stockholders' Equity
Current liabilities
	Accounts payable and accrued expenses		$	75,536		$	26,112		$	19,824	(a)(f)	$	121,472
	Current portion of bank debt			34,360			—			—			34,360
	Fair value of derivative instruments			16,680			—			—			16,680
Total current liabilities				126,576			26,112			19,824			172,512
Bank debt				100,881			107,480			277,573	(a)		485,934
Deferred income taxes				85,055			33,277			38,508			156,840
Other non-current liabilities				20,635			4,523			600	(f)		25,758
Total stockholders' equity				581,078			113,081			(113,081	)(a)		581,078
			$	914,225		$	284,473		$	223,424		$	1,422,122

See Notes to Unaudited Pro Forma Condensed Combined Financial Statements.

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Tom Brown, Inc.

Unaudited Pro Forma Condensed Statement of Operations

Three Months Ended
March 31, 2003

				Tom Brown, Inc. Historical			Matador Historical			Pro Forma Adjustments (Note 3)			Pro Forma Combined Company
				(In thousands)
Revenues
	Gas and oil sales			$	80,480		$	31,596		$	—		$	112,076
	Gathering and processing				6,076			—			—			6,076
	Marketing and trading, net				13,854			—			—			13,854
	Other				3,628			45			—			3,673
		Total revenues			104,038			31,641			—		$	135,679
Costs and expenses
	Gas and oil production				8,185			2,926			—			11,111
	Taxes on gas and oil production				6,538			2,068			—			8,606
	Trading				13,141			—			—			13,141
	Gathering and processing costs				2,034			—			—			2,034
	Cost of drilling operations				2,934			—			—			2,934
	Exploration costs				6,874			—			831	(c)		7,705
	Impairments of leasehold costs				1,474			—			150	(e)		1,624
	General and administrative				4,847			1,710			692	(c)		7,249
	Depreciation, depletion, and amortization				21,417			5,833			1,421	(d)		28,671
	Accretion				292			96			—			388
	Bad debt				152			—			—			152
	Amortization of non-compete agreements				—			—			538	(f)		538
	Interest expense and other				3,556			914			4,247	(b)		8,717
		Total costs and expenses			71,444			13,547			7,879			92,870
Income before income taxes and cumulative effect of change in accounting principle					32,594			18,094			(7,879	)		42,809
Income tax provision					(11,797	)		(6,237	)		2,757	(g)		(15,277	)
Income before cumulative effect of change in accounting principle				$	20,797		$	11,857		$	(5,122	)	$	27,532
Weighted average number of common shares outstanding					40,442									40,442
Net income before cumulative effect of change in accounting principle—per common share				$	0.49								$	0.68

See Notes in Unaudited Pro Forma Condensed Combined Financial Statements.

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Tom Brown, Inc.
Unaudited Pro Forma Condensed Statement of Operations

Year Ended
December 31, 2002

				Tom Brown, Inc. Historical			Matador Historical			Pro Forma Adjustments (Note 3)			Pro Forma Combined Company
				(In thousands)
Revenues
	Gas and oil sales			$	194,276		$	59,936		$	—		$	254,212
	Gathering and processing				20,467			—			—			20,467
	Marketing and trading, net				5,276			—			—			5,276
	Drilling				14,347			—			—			14,347
	Gain on sale of property				4,114			—			—			4,114
	Cash paid on derivatives				(2,061	)		—			—			(2,061	)
	Change in derivative fair value				(345	)		—			—			(345	)
	Loss on marketable security				(600	)		—			—			(600	)
	Interest income and other				171			268			—			439
		Total revenues			235,645			60,204			—			295,849
Costs and expenses
	Gas and oil production				32,151			8,586			—			40,737
	Taxes on gas and oil production				16,621			4,940			—			21,561
	Gathering and processing costs				6,918			—			—			6,918
	Cost of drilling operations				13,763			—			—			13,763
	Exploration costs				22,824			—			3,493	(c)		26,317
	Impairments of leasehold costs				5,564			—			588	(e)		6,152
	General and administrative				18,413			6,550			2,375	(c)		27,338
	Depreciation, depletion, and amortization				91,307			20,766			4,666	(d)		116,739
	Bad debt				5,222			—			—			5,222
	Amortization of non-compete agreements				—			—			3,176	(f)		3,176
	Interest expense and other				9,726			3,202			16,988	(b)		29,916
		Total costs and expenses			222,509			44,044			31,286			297,839
Income (loss) before income taxes and cumulative effect of change in accounting principle					13,136			16,160			(31,286	)		(1,990	)
Income tax (provision) benefit					(3,210	)		(5,828	)		10,950	(g)		1,912
Income (loss) before cumulative effect of change in accounting principle				$	9,926		$	10,332		$	(20,336	)	$	(78	)
Weighted average number of common shares outstanding					40,327									40,327
Income (Loss) before cumulative effect of change in accounting principle—per common share				$	0.25								$	—

See Notes to Unaudited Pro Forma Condensed Combined Financial Statements.

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Tom Brown, Inc.

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL INFORMATION

(1)    BASIS OF PRESENTATION

        The accompanying unaudited pro forma condensed combined balance sheet and condensed combined statements of operations present the pro forma effects of the acquisition. The unaudited pro forma condensed combined balance sheet is presented as though the acquisition occurred on March 31, 2003. The unaudited pro forma condensed combined statements of operations for the three months ended March 31, 2003 and the year ended December 31, 2002 are presented as though the acquisition occurred on January 1, 2002.

(2)    METHOD OF ACCOUNTING FOR THE ACQUISITION

        Tom Brown will account for the acquisition using the purchase method of accounting for business combinations. Under this method of accounting, Tom Brown is deemed to be the acquirer for accounting purposes. Matador's assets and liabilities will be revalued under the purchase method of accounting and recorded at their estimated fair values in conjunction with the merger.

(3)    PRO FORMA ADJUSTMENTS RELATED TO THE ACQUISITION

        The unaudited pro forma condensed combined balance sheet and statements of operations include the following adjustments:

(a)

The purchase price adjustment in the balance sheet restates the historical values of Matador's assets and liabilities to their estimated fair values as of March 31, 2003. The calculation of the total purchase price and the preliminary allocation of this price to the acquired assets and liabilities are shown below (in thousands):

        The following table reflects the calculation of the preliminary purchase price for Matador (in thousands):

The total preliminary purchase price includes the anticipated acquisition cost to acquire all of the outstanding common stock of Matador. Shareholders received a net price of $17.53 per common share and option holders received $17.53 per option share less the exercise price of the options or a total of

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$267 million. In addition to the amount paid for the common shares and the debt assumed by Tom Brown, the purchase price includes:

•

Transaction related merger costs of approximately $6.0 million. These costs include investment banking expenses, legal, accounting and other direct merger-related costs.



•

Additional costs incurred related to the transaction included $7.7 million incurred for payments made to officers and employees of Matador pursuant to a change in control arrangement previously entered into by Matador and $1.3 million incurred for payments made to Matador employees under the terms of a stock appreciation plan, which provided for payments in the event of a change in control of Matador. Compensation of employees who are employed during the transition period along with stay bonuses payable to those employees will be expensed in the period subsequent to the acquisition.



•

Matador's accounting policy has been to recognize gas sales as income when received in cash. Tom Brown has historically recognized gas revenues under the entitlement method whereby revenues are recognized as the Company's entitlement share of gas is produced based upon its working interests in the gas properties. Under this method, a receivable (payable) is recorded, to the extent the Company receives less (more) than its proportionate share of the revenues from the gas produced. At March 31, 2003, an adjustment of approximately $600,000 was recorded as a long-term liability to recognize the net unrecorded gas imbalance liability for Matador. The impact of the gas imbalances on the revenues recognized for the year ended December 31, 2002 and three months ended March 31, 2003 was not significant.



•

The other non-current liability of Matador assumed represents the asset retirement obligation accounted for under Financial Accounting Standards Board ("FASB") Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations." Matador and Tom Brown adopted SFAS No. 143 effective January 1, 2003 by recording a cumulative effect adjustment to recognize transition amounts for asset retirement obligations.



•

Tom Brown estimated the fair value of Matador's current assets, other assets, current liabilities and other non-current liabilities to be equivalent to Matador's historical net book value. Real estate was adjusted to an estimate of its current market value. The gas and oil properties were valued based upon proved gas and oil reserve valuations prepared in conjunction with the acquisition and an internal appraisal was made of the undeveloped leasehold interests of Matador.



•

The allocation of the purchase price to the Matador assets resulted in a difference between the book and tax basis of the Matador assets of approximately $214 million. Based upon an effective tax rate of 35 percent, deferred income taxes were recognized to the extent that the offsetting increase in the cost basis assigned to the gas and oil properties did not exceed the value of the proved reserves. This limitation resulted in the recognition of approximately $84 million of goodwill in conjunction with the acquisition.



(b)

Interest expense increased as a result of Tom Brown borrowing approximately $278 million in conjunction with the acquisition. Of this amount, $155 million was advanced from a recently negotiated senior subordinated credit facility and the balance of the funding was provided under a new revolving credit facility. Bank fees of $7.1 million were incurred to obtain these new loan facilities. Pro forma interest expense has been adjusted to include amortization of the loan fees attributable to the amounts borrowed to complete the acquisition.



(c)

Adjustment were required to expense certain items under the successful efforts method of accounting utilized by Tom Brown that were previously capitalized by Matador under the full cost method of accounting. These costs were principally associated with exploratory dry holes, delay rentals and seismic costs. Matador also previously capitalized as development cost a portion of its internal costs associated with geological and geophysical staff which are expensed under the successful efforts accounting.



(d)

The increase in the cost basis assigned to Matador's gas and oil properties resulted in an increase in depreciation, depletion and amortization expense.

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(e)

A provision was recognized for leasehold abandonments and expirations based upon the undeveloped leasehold position of Matador. These amounts had previously been capitalized under the full cost method of accounting.



(f)

Three officers of Matador entered into non-compete agreements with Tom Brown in conjunction with the transaction. One contract covered a 21 month period in exchange for $3.8 million, a portion of which was paid at closing and a portion of which is payable over the term of the contract. The other two contracts were for terms of three months in exchange for $0.5 million each which was paid at closing. A pro forma adjustment has been recorded to reflect the expense associated with these contracts over the terms of the agreements assuming the agreements were entered into on January 1, 2002.



(g)

The income tax provision was adjusted for the tax effect of the pro forma adjustments.

(4)    APPLICATION OF RECENTLY ISSUED ACCOUNTING STANDARDS ON INTANGIBLE ASSETS.

        The Company has been made aware of an issue that has arisen in the industry regarding the application of certain provisions of SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," to companies in the extractive industries, including oil and gas companies. The issue is whether the provisions of SFAS No. 141 and SFAS No. 142 require registrants to classify costs associated with mineral rights, including both proved and unproved lease acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs.

        Historically, Tom Brown and Matador have included oil and gas lease acquisition costs as a component of oil and gas properties. Also under consideration is whether SFAS No. 142 requires registrants to provide additional disclosures prescribed by SFAS No. 142 for intangible assets for costs associated with mineral rights. In the event it is determined that costs associated with mineral rights are required to be classified as intangible assets, a substantial portion of Tom Browns capitalized oil and gas property costs and a substantial portion of the acquisition costs attributable to the Matador properties acquired would be separately classified in the pro forma balance sheet as intangible assets.

        The reclassification of these amounts would not effect the method in which such costs are amortized or the manner in which the Company assesses impairment of capitalized costs. As a result, net income would not be affected by the reclassification.

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(5)    SUPPLEMENTAL PRO FORMA INFORMATION REGARDING OIL AND GAS OPERATIONS

        The following pro forma supplemental information regarding oil and gas operations is presented pursuant to the disclosure requirements of SFAS No. 69, "Disclosures About Oil and Gas Producing Activities."

        Pro Forma Costs Incurred

        The following tables reflect the costs incurred in oil and gas producing property acquisition, exploration and development activities of Tom Brown, Matador and the combined company on a pro forma basis for the year ended December 31, 2002.

				Total									United States									Canada
				Tom Brown			Matador			Combined			Tom Brown			Matador			Combined			Tom Brown
				(In thousands)
Costs incurred
	Proved property acquisition costs			$	15,878		$	3,389		$	19,267		$	15,878		$	3,389		$	19,267		$	—
	Unproved property acquisition costs				9,015			—			9,015			7,601			—			7,601			1,414
	Exploration costs				35,035			7,558			42,593			32,482			7,558			40,040			2,553
	Development costs				94,567			65,137			159,704			85,319			65,137			150,456			9,248
		Total		$	154,495		$	76,084		$	230,579		$	141,280		$	76,084		$	217,364		$	13,215

        The following tables set forth the changes in the net quantities of natural gas, oil and natural gas liquids reserves of Tom Brown, Matador and the combined company on a pro forma basis for the year ended December 31, 2002.

			Total						United States						Canada
Natural Gas			Tom Brown		Matador		Combined		Tom Brown		Matador		Combined		Tom Brown
			(Mmcf)
Proved reserves:
Estimated reserves at December 31, 2001			641,579		168,027		809,606		582,052		168,027		750,079		59,527
	Revisions of previous estimates		10,913		(13,593	)	(2,680	)	8,304		(13,593	)	(5,289	)	2,609
	Purchases of minerals in place		15,661		3,414		19,075		15,661		3,414		19,075		—
	Extensions and discoveries		84,373		95,444		179,817		79,582		95,444		175,026		4,791
	Sales of minerals in place		(6,332	)	—		(6,332	)	(6,322	)	—		(6,322	)	—
	Production		(72,167	)	(15,130	)	(87,297	)	(65,781	)	(15,130	)	(80,911	)	(6,386	)
Estimated reserves at December 31, 2002			674,027		238,162		912,189		613,496		238,162		851,658		60,541
Proved developed reserves:
	December 31, 2002		507,422		133,614		641,036		481,183		133,614		614,797		56,239

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			Total						United States						Canada
Oil			Tom Brown		Matador		Combined		Tom Brown		Matador		Combined		Tom Brown
			(Mbbls)
Proved reserves:
Estimated reserves at December 31, 2001			6,647		5,929		12,576		5,469		5,929		11,398		1,178
	Revisions of previous estimates		898		(535	)	363		580		(535	)	45		318
	Purchases of minerals in place		34		40		74		34		40		74		—
	Extensions and discoveries		451		2,451		2,902		193		2,451		2,644		258
	Sales of minerals in place		(1,162	)	—		(1,162	)	(1,162	)	—		(1,162	)	—
	Production		(843	)	(648	)	(1,491	)	(623	)	(648	)	(1,271	)	(220	)
Estimated reserves at December 31, 2002			6,025		7,237		13,262		4,491		7,237		11,728		1,534
Proved developed reserves:
	December 31, 2002		4,551		5,352		9,903		3,299		5,352		8,651		1,252

			Total						United States						Canada
Natural Gas Liquids			Tom Brown		Matador		Combined		Tom Brown		Matador		Combined		Tom Brown
			(Mbbls)
Proved reserves:
Estimated reserves at December 31, 2001			8,360		—		8,360		6,634		—		6,634		1,726
	Revisions of previous estimates		(628	)	—		(628	)	(956	)	—		(956	)	328
	Purchases of minerals in place		—		—		—		—		—		—		—
	Extensions and discoveries		305		—		305		186		—		186		119
	Sales of minerals in place		—		—		—		—		—		—		—
	Production		(1,382	)	—		(1,382	)	(1,189	)	—		(1,189	)	(193	)
Estimated reserves at December 31, 2002			6,655		—		6,655		4,675		—		4,675		1,980
Proved developed reserves:
	December 31, 2002		5,825		—		5,825		4,002		—		4,002		1,823

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        The following tables set forth the standardized measure of discounted future net cash flows relating to proved oil, natural gas and natural gas liquids reserves for Tom Brown, Matador and the combined company on a pro forma basis as of December 31, 2002.

		Total									United States									Canada
		Tom Brown			Matador			Combined			Tom Brown			Matador			Combined			Tom Brown
		(In thousands)
Future cash flows		$	2,570,168		$	1,279,885		$	3,850,053		$	2,243,751		$	1,279,885		$	3,523,636		$	326,417
Future production costs			(799,637	)		(279,350	)		(1,078,987	)		(732,739	)		(279,350	)		(1,012,089	)		(66,898	)
Future development costs			(186,363	)		(107,251	)		(293,614	)		(175,085	)		(107,251	)		(282,336	)		(11,278	)
Future net cash flows before tax			1,584,168			893,284			2,477,452			1,335,927			893,284			2,229,211			248,241
Future income taxes			(451,706	)		(233,146	)		(684,852	)		(367,271	)		(233,146	)		(600,417	)		(84,435	)
Future net cash flows after tax			1,132,462			660,138			1,792,600			968,656			660,138			1,628,794			163,806
Annual discount at 10%			(468,454	)		(345,690	)		(814,144	)		(405,487	)		(345,690	)		(751,177	)		(62,967	)
Standardized measure of discounted future net cash flows		$	664,008		$	314,448		$	978,456		$	563,169		$	314,448		$	877,619		$	100,839
Discounted future net cash flows before income taxes		$	883,353		$	426,114		$	1,309,467		$	744,608		$	426,114		$	1,170,722		$	138,745

        The following table includes the components of the changes in the standardized measure of discounted future net cash flows of Tom Brown, Matador and the combined company on a pro forma basis for the year ended December 31, 2002

		Total									United States									Canada
		Tom Brown			Matador			Combined			Tom Brown			Matador			Combined			Tom Brown
		(In thousands)
Gas and oil sales, net production costs(1)		$	(145,504	)	$	(46,410	)	$	(191,914	)	$	(122,574	)	$	(46,410	)	$	(168,984	)	$	(22,930	)
Net changes in anticipated prices and production costs			325,690			147,841			473,531			265,587			147,841			413,428			60,103
Extension and discoveries, less related costs			112,018			152,612			264,630			95,798			152,612			248,410			16,220
Changes in estimated future development costs			(1,813	)		—			(1,813	)		2,752			—			2,752			(4,565	)
Previously estimated development costs incurred			39,406			20,853			60,259			37,124			20,853			57,977			2,282
Net change in income taxes			(170,753	)		(79,847	)		(250,600	)		(140,036	)		(79,847	)		(219,883	)		(30,717	)
Purchases of minerals in place			16,970			6,173			23,143			16,970			6,173			23,143			—
Sales of minerals in place			(11,383	)		—			(11,383	)		(11,383	)		—			(11,383	)		—
Accretion of discount			50,128			15,856			65,984			42,990			15,856			58,846			7,138
Revision of quantity estimates			19,147			(25,474	)		(6,327	)		7,586			(25,474	)		(17,888	)		11,561
Changes in production rates and other			(22,594	)		(3,059	)		(25,653	)		(20,148	)		(3,059	)		(23,207	)		(2,446	)
Change in Standardized Measure		$	211,312		$	188,545		$	399,857		$	174,666		$	188,545		$	363,211		$	36,646

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(1)

Net of hedging revenue for Tom Brown of $0.2 million on production in the United States and a $0.2 million hedging loss on Canadian production.

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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 hereunto duly authorized.

Date: August 1, 2003		TOM BROWN, INC.
		By:	/s/  DANIEL G. BLANCHARD       Daniel G. Blanchard Executive Vice President and Chief Financial Officer (Principal Financial Officer)
		By:	/s/  RICHARD L. SATRE       Richard L. Satre Controller (Principal Accounting Officer)

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QuickLinks

ITEM 2. ACQUISITION OR DISPOSITION OF ASSETS
ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS.

Tom Brown, Inc. Index to Financial Statements
Independent Auditors' Report
MATADOR PETROLEUM CORPORATION AND SUBSIDIARIES Consolidated Balance Sheets
MATADOR PETROLEUM CORPORATION AND SUBSIDIARIES Consolidated Statements of Operations
MATADOR PETROLEUM CORPORATION AND SUBSIDIARIES Consolidated Statements of Changes in Shareholders' Equity Years ended December 31, 2002, 2001, and 2000 Three months ended March 31, 2003 (unaudited)
MATADOR PETROLEUM CORPORATION AND SUBSIDIARIES Consolidated Statements of Cash Flows
MATADOR PETROLEUM CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements December 31, 2002 and 2001 (Unaudited with respect to March 31, 2003 and 2002)
Tom Brown, Inc. PRO FORMA FINANCIAL INFORMATION
Tom Brown Inc. Unaudited Pro Forma Condensed Balance Sheet March 31, 2003
Tom Brown, Inc. Unaudited Pro Forma Condensed Statement of Operations Three Months Ended March 31, 2003
Tom Brown, Inc. Unaudited Pro Forma Condensed Statement of Operations Year Ended December 31, 2002
Tom Brown, Inc. NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL INFORMATION
SIGNATURES