BROWN TOM INC /DE - 10-Q Quarterly Report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2004

OR

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

COMMISSION FILE NUMBER 001-31308

TOM BROWN, INC.

(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

DELAWARE		95-1949781
(STATE OR OTHER JURISDICTION OF INCORPORATION OR ORGANIZATION)		(I.R.S. EMPLOYER IDENTIFICATION NO.)

555 SEVENTEENTH STREET SUITE 1850 DENVER, COLORADO		80202
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)		(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)

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

Indicate by check mark whether the Registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). YES ý NO o

APPLICABLE ONLY TO CORPORATE ISSUERS:

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of May 4, 2004.

CLASS OF COMMON STOCK		OUTSTANDING AT MAY 4, 2004

$.10 PAR VALUE		46,221,871

TOM BROWN, INC. AND SUBSIDIARIES
QUARTERLY REPORT FORM 10-Q

INDEX

Part I.	Item 1. Financial Information (Unaudited)
	Consolidated Balance Sheets, March 31, 2004 and December 31, 2003
	Consolidated Statements of Operations, Three Months Ended March 31, 2004 and 2003
	Consolidated Statements of Cash Flows, Three Months Ended March 31, 2004 and 2003
	Notes to Consolidated Financial Statements
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 3. Quantitative and Qualitative Disclosure about Market Risk
	Item 4. Controls and Procedures
Part II.	Other Information
	Item 4. Submission of Matters to a Vote of Security Holders
	Item 5. Other Information
	Item 6. Exhibits and Reports on Form 8-K
	Signatures

TOM BROWN, INC.
555 Seventeenth Street, Suite 1850
Denver, Colorado 80202

QUARTERLY REPORT

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

FORM 10-Q

PART I OF TWO PARTS

FINANCIAL INFORMATION

TOM BROWN, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except per share amounts)

	March 31, 2004			December 31, 2003
	(Unaudited)

ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	16,586		$	34,256
Accounts receivable, net of allowance for doubtful accounts	141,421			117,073
Fair value of derivative instruments	957			1,230
Inventories	1,908			1,045
Other	6,245			7,772

Total current assets	167,117			161,376
PROPERTY AND EQUIPMENT, AT COST:
Gas and oil properties, successful efforts method of accounting	1,614,169			1,563,680
Gas gathering, processing and other plant	121,610			119,592
Other	47,080			44,956

Total property and equipment	1,782,859			1,728,228
Less: Accumulated depreciation and depletion	433,966			423,661
Net property and equipment	1,348,893			1,304,567
OTHER ASSETS:
Goodwill, net	84,484			84,484
Deferred loan fees and other assets	18,352			18,007

	$	1,618,846		$	1,568,434

LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable	$	91,727		$	98,248
Accrued expenses	56,974			42,263
Fair value of derivative instruments	17,282			2,301

Total current liabilities	165,983			142,812

BANK DEBT	138,000			169,080
SENIOR SUBORDINATED NOTES	225,000			225,000
DEFERRED INCOME TAXES	203,755			189,131
OTHER NON-CURRENT LIABILITIES	30,893			29,459

STOCKHOLDERS’ EQUITY:
Convertible preferred stock, $.10 par value, Authorized 2,500,000 shares; none issued	—			—
Common stock, $.10 par value, Authorized 55,000,000 shares; Issued and outstanding 46,123,780 and 45,669,313 shares, respectively	4,612			4,567
Additional paid-in capital	704,256			693,414
Unearned stock compensation	(1,987		)	(2,148		)
Retained earnings	154,573			112,415
Accumulated other comprehensive (loss) income	(6,239		)	4,704

Total stockholders’ equity	855,215			812,952

	$	1,618,846		$	1,568,434

See accompanying notes to consolidated financial statements.

TOM BROWN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

	Three Months Ended March 31,
	2004			2003
	(Unaudited)

REVENUES:
Gas, oil and natural gas liquids sales	$	143,343		$	80,480
Gathering and processing	5,936			6,076
Marketing and trading	5,517			13,854
Drilling	4,789			3,077
Loss on sale of properties	(632		)	—
Interest income and other	42			551

Total revenues	158,995			104,038

COSTS AND EXPENSES:
Gas and oil production	11,364			8,185
Taxes on gas and oil production	11,293			6,538
Gathering and processing costs	2,010			2,034
Trading.	5,745			13,141
Drilling operations	4,031			2,934
Exploration costs	5,938			6,874
Impairments of leasehold costs	2,492			1,474
General and administrative	7,613			4,847
Depreciation, depletion and amortization	36,450			21,417
Accretion of asset retirement obligation	432			292
Bad debts	153			152
Interest expense and other	6,171			3,556

Total costs and expenses	93,692			71,444

Income before income taxes, and cumulative effect of change in accounting principle	65,303			32,594

Income tax provision :
Current	(537		)	(222		)
Deferred	(22,609		)	(11,575		)

Income before cumulative effect of change in accounting principle	42,157			20,797
Cumulative effect of change in accounting principle	—			(929		)

Net income	$	42,157		$	19,868

Weighted average number of common shares outstanding:
Basic	46,341			39,482

Diluted	48,078			40,442

Earnings per common share-Basic:
Income before cumulative effect of change in accounting principle	$	.91		$	.53
Cumulative effect of change in accounting principle	—			(.02		)

Net income attributable to common stock	$	.91		$	.51

Earnings per common share-Diluted:
Income before cumulative effect of change in accounting principle	$	.88		$	.51
Cumulative effect of change in accounting principle	—			(.02		)

Net income attributable to common stock	$	.88		$	.49

See accompanying notes to consolidated financial statements.

TOM BROWN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three Months Ended March 31,
	2004			2003
	(In thousands – unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	42,157		$	19,868
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	36,450			21,417
Accretion of asset retirement obligation	432			292
Loss on sale of properties	632			—
Stock compensation	161			—
Dry hole costs	213			3,037
Impairments of leasehold costs	2,492			1,474
Deferred tax provision	22,609			11,575
Cumulative effect of changes in accounting principle	—			929
Changes in operating assets and liabilities
(Increase) in accounts receivable	(24,157		)	(27,905		)
(Increase) decrease in inventories	(872		)	57
Decrease in other current assets	1,452			622
Increase in accounts payable and accrued expenses	13,628			4,688
Decrease in other assets, net	1,154			860

Net cash provided by operating activities	96,351			36,914

CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sales of assets	3,412			54
Capital and exploration expenditures	(90,095		)	(33,745		)
Changes in accounts payable and accrued expenses for capital expenditures	(5,251		)	5,249

Net cash used in investing activities	(91,934		)	(28,442		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of long-term bank debt	(31,080		)	(5,299		)
Proceeds from exercise of stock options	9,032			1,276

Net cash used in financing activities	(22,048		)	(4,023		)
Effect of exchange rate changes on cash	(39		)	265
NET CHANGE IN CASH AND CASH EQUIVALENTS	(17,670		)	4,714
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	34,256			13,555

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	16,586		$	18,269

Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest	$	9,450		$	1,392
Income taxes	185			205

See accompanying notes to consolidated financial statements.

TOM BROWN, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(1) Summary of Significant Accounting Policies

The consolidated financial statements included herein have been prepared by Tom Brown, Inc. (the “Company”) and are unaudited. The financial statements reflect necessary adjustments, all of which were of a recurring nature, and are, in the opinion of management, necessary for a fair presentation. Certain reclassifications have been made to amounts reported in previous years to conform to the current presentation. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. The Company believes that the disclosures presented are adequate to allow the information presented not to be misleading. Users of financial information produced for interim periods are encouraged to refer to the footnotes contained in the Annual Report to Stockholders when reviewing interim financial results.

Proposed Accounting Standards

The Emerging Issues Task Force (“EITF”) currently is deliberating on EITF No. 03-S “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil and Gas Companies.” This proposed statement will determine whether contract-based oil and gas mineral rights are classified as tangible or intangible assets based on the EITF’s interpretation of SFAS No. 141 and SFAS No. 142. In March 2004, the EITF reached a consensus that mineral rights for mining companies are tangible assets and amendments to SFAS No. 141 and SFAS No. 142 were proposed that are awaiting approval by the FASB. Historically, the Company has classified all of its contract-based mineral rights within property, plant and equipment and has generally not identified these amounts separately.

If the FASB were to determine that mineral rights should be presented as intangible assets, the Company would have to reclassify its contract-based oil and gas mineral rights to intangible assets and make additional disclosures in accordance with SFAS No. 142. The amounts that would be reclassified are as follows:

	March 31, 2004		December 31, 2003
	(In thousands)

INTANGIBLE ASSETS:
Proved leasehold acquisition costs	$	695,373	$	711,544
Unproved leasehold acquisition costs	99,041		98,165
Total leasehold acquisition costs	794,414		809,709
Less: Accumulated depletion	124,002		141,000
Net leasehold acquisition costs	$	670,412	$	668,709

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.

Change in Accounting Principles

In July 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity reports a gain or loss upon settlement to the extent the actual costs differ from the recorded liability. The Company adopted SFAS No. 143 on January 1, 2003, and recorded a discounted liability of $14.5 million for the future retirement obligation, an increase to property and equipment of $13.0 million and a charge of $.9 million (net of a deferred tax benefit of $.6 million) as the cumulative effect of change in accounting principle. The majority of the asset retirement obligation recognized related to the projected cost to plug and abandon gas and oil wells. Liabilities were also be recorded for processing plants, compressors and other field facilities.

(2) Acquisitions and Divestures

Acquisition of Matador

On June 27, 2003, the Company completed its acquisition of Matador Petroleum Corporation, a Texas corporation (“Matador”). Matador was an exploration and production company active primarily in the East Texas Basin and Permian Basin of Southeastern New Mexico and West Texas. The acquisition increased Tom Brown’s proved reserves by an estimated 269 billion cubic feet equivalent (Bcfe) (unaudited).

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.

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 of $71.8 million were recorded. The deferred taxes recorded represent the majority of the $84.5 million of goodwill recorded in conjunction with the acquisition.

The other non-current liability of Matador that was assumed principally represents the asset retirement obligation accounted for under SFAS No. 143. The asset retirement obligation related to the Matador assets at June 30, 2003 was $4.8 million.

The purchase price was allocated as follows (in thousands):

Acquisition costs:
Cash paid to stock and option holders	$	267,473
Long-term debt assumed	114,480
Other non-current liabilities assumed	5,733
Direct transaction costs incurred by the Company	800

Total consideration	388,486
Allocation of acquisition costs:
Oil and gas properties-proved	(360,000		)
Unproved properties	(25,000		)
Other property and equipment	(1,185		)
Cash acquired in the transaction	3,596
Deferred income taxes	71,785
Net working capital deficit	6,802

Goodwill	$	84,484

Pro Forma Results of Operations (Unaudited)

The following table reflects the unaudited pro forma results of operations for the three months ended March 31, 2003 as though the Matador acquisition had occurred on January 1 in that period. The pro forma amounts are not necessarily representative of the results that may be reported in the future.

	Three Months Ended March 31,
	2003
	(In thousands, except per share data)
Revenues	$	135,679
Net income	$	27,860
Basic net income per share	$	.71
Diluted net income per share	$	.69

Property Sales

In February 2004, the Company sold its interest in gas and oil properties located in West Virginia to an unrelated third party for net cash proceeds of $3.4 million. A pretax loss of $.6 million was recognized on this sale.

(3) Stock Based Compensation

The Company accounts for employee stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board (APB) Opinion No. 25 “Accounting for Stock Issued to Employees” and related interpretations under which no compensation cost is recognized for grants of options at the market price under the Company’s stock option plans unless there is a modification to the original terms of the option grant.

If compensation costs for these plans had been determined in accordance with SFAS No. 123, the Company’s net income and net income per common share would approximate the following pro forma amounts:

	Three Months Ended March 31,
	2004			2003
	(In thousands, except per share amounts)

Net income
As reported	$	42,157		$	19,868
Deduct: Stock-based employee compensation expense determined under fair value based method for all awards, (net of tax)	(1,268		)	(1,240		)
Add: Compensation cost included in reported net income (net of tax)	—			—
Pro forma	$	40,889		$	18,628

Basic net income per common share:
As reported	$	.91		$	.51
Pro forma	$	.88		$	.47
Diluted net income per common share:
As reported	$	.88		$	.49
Pro forma	$	.85		$	.46

The weighted average fair value of options granted during the three months ended March 31, 2004 and 2003 was $30.19 and $22.37 per share, respectively. The fair value of each option is estimated as of the date of grant using the Black-Scholes options-pricing model with the following weighted-average assumptions used for grants in these 2004 and 2003 periods, respectively: (i) risk-free interest rates of 3.33 and 3.35 percent, (ii) expected lives of 7.0 and 7.0 years, (iii) expected volatility of 119.11 and 125.6 percent, and (iv) no dividend yields.

(4) Common Stock

In September 2003, the Company issued 6 million shares of common stock at a price of $25.75 per share. Net proceeds from this offering were $147.9 million after deducting underwriting discounts, commissions and estimated offering expenses. The proceeds from this offering were utilized by the Company to retire a portion of the debt incurred in conjunction with the acquisition of Matador.

(5) Debt

7.25% Senior Subordinated Notes

In September 2003, the Company issued $225 million principal amount 7.25% Senior Subordinated Notes (the 7.25% Notes) at par for proceeds of $220 million (net of related offering costs). The 7.25% Notes are due on September 15, 2013 with interest payable on March 15 and September 15 of each year.

The 7.25% Notes are unsecured senior subordinated obligations that rank junior in right of payment to all of the Company’s existing and future secured debt. The indenture contains covenants restricting the ability of the Company to incur additional indebtedness, pay dividends or sell significant assets or subsidiaries. The Company was in compliance with all of these covenants at March 31, 2004.

The proceeds from the issuance of the 7.25% Notes and proceeds received from the September 2003 issuance of common stock were utilized to retire the $110 million five-year Canadian term loan within the Company’s unsecured credit facility and retire the $155 million unsecured senior subordinated credit facility originally established to consummate the Matador acquisition in June 2003.

Senior Subordinated Credit Facility

In connection with the consummation of the Matador Petroleum acquisition in June 2003, the Company entered into an unsecured senior subordinated credit facility (the “Subordinated Facility”) with a group of lender banks that also participated in the Company’s New Global Credit Facility. The initial interest rate on the $155 million loan was established at 8.5%, but provided for quarterly increases of 0.5%.

In September 2003, the Company repaid this $155 million Subordinated Facility utilizing funds received from the issuance of additional common stock and issuance of the 7.25% Notes. The loan origination costs of $3.6 million incurred to establish this facility were expensed in this period.

Credit Facility

On March 20, 2001, the Company entered into a $225 million credit facility (the “Global Credit Facility”). The Global Credit Facility was comprised of: a $75 million line of credit in the U.S. and a $55 million line of credit in Canada which both had maturity dates of March 20, 2004, and a $95 million five-year term loan in Canada which had a maturity date of March 21, 2006. The borrowing base established to support the $225 million line of credit was initially set at $300 million, which was re-approved as of May 1, 2002. In conjunction with Matador acquisition in June 2003, the Company entered into a “New Global Credit Facility” and the borrowing base and line of credit were increased to $425 million. The terms of the New Global Credit Facility provided for: a $290 million line of credit in the U.S. and a $25 million line of credit in Canada which both now mature on June 27, 2007, and a $110 million five-year term loan in Canada which was to mature on March 21, 2006. The terms of the New Global Credit Facility allow the lenders one scheduled redetermination of the borrowing base each December. In addition, the lenders may elect to require one unscheduled redetermination in the event the borrowing base utilization exceeds 50% of the borrowing base at any time for a period of 15 consecutive business days.

At March 31, 2004, the Company had borrowings outstanding under the New Global Credit Facility totaling $138 million or 29% of the new borrowing base at an average interest rate of 3.3%. The amount available for borrowing under the New Global Credit Facility at March 31, 2004 was $177 million. Borrowings under the New Global Credit Facility are unsecured and bear interest, at the election of the Company, at a rate equal to (i) the greater of the global administrative agents prime rate or the federal funds effective rate plus an applicable margin, (ii) adjusted London InterBank Offered Rate (LIBOR) for Eurodollar loans plus an applicable margin, or (iii) Bankers’ Acceptances plus an applicable margin for Canadian dollar loans. Interest on amounts outstanding under the New Global Credit Facility is due on the last day of each quarter for prime based loans, and in the case of Eurodollar loans with an interest period of more than three months, interest is due at the end of each three month interval.

The New Global Credit Facility contains certain financial covenants and other restrictions that require the Company to maintain a minimum consolidated tangible net worth of not less than $450 million (adjusted upward by 50% of quarterly net income subsequent to June 30, 2003 and 80% of the net cash proceeds of any stock offering). The Company must also maintain a ratio of indebtedness to earnings before interest expense, state and federal taxes and depreciation, depletion and amortization expense and exploration expense of not more than 3.0 to 1.0 as calculated at the end of each fiscal quarter. The Company was in compliance with all covenants at March 31, 2004.

(6) Income Taxes

The Company has not paid Federal income taxes due to the availability of net operating loss carryforwards and the deductibility of intangible drilling and development costs. The Company has historically been required to pay Alternative Minimum Tax (“AMT”) on its U.S. activity.

The components of the net deferred tax liability by geographical segment at March 31, 2004 and in total as of December 31, 2003 were as follows (in thousands):

	March 31, 2004									December 31, 2003
	United States			Canada			Total			Total

Deferred tax assets:
Net operating loss carryforward	$	24,134		$	—		$	24,134		$	21,349
Percentage depletion carryforward	3,039			—			3,039			2,534
Alternative minimum tax credit carryforward	5,507			—			5,507			5,222
Derivative contracts to be settled in a future period	5,795			—			5,795			—
Other	761			—			761			1,837

Total gross deferred tax assets	39,236			—			39,236			30,942

Deferred tax liabilities:
Property and equipment	(205,834		)	(36,793		)	(242,627		)	(219,638		)
Other	(364		)	—			(364		)	(435		)
Total gross deferred tax liabilities	(206,198		)	(36,793		)	(242,991		)	(220,073		)
Net deferred tax liabilities	$	(166,962	)	$	(36,793	)	$	(203,755	)	$	(189,131	)

The Company evaluated all appropriate factors to determine the need for a valuation allowance for the net operating losses and AMT carryforwards, including any limitations concerning their use, the levels of taxable income necessary for utilization and tax planning. In this regard, based on recent operating results and expected levels of future earnings, the Company believes it will, more likely than not, generate sufficient taxable income to realize the benefit attributable to the net operating loss and AMT carryforwards and the other deferred tax assets for which valuation allowances were not provided.

The components of the Company’s current and deferred tax provisions are as follows (in thousands):

	Three Months Ended March 31,
	2004			2003

Current income tax:
Federal AMT provision	$	(285	)	$	—
Canadian provision	(102		)	(76		)
State income and franchise taxes	(150		)	(146		)
Total current tax provision	(537		)	(222		)
Deferred income tax:
Federal and State provision	(22,009		)	(10,522		)
Canadian provision	(600		)	(1,053		)
Total deferred tax (provision) benefit	(22,609		)	(11,575		)
Total tax provision	$	(23,146	)	$	(11,797	)

(7) Marketing and Trading Activities

The Company engages in natural gas trading activities which involve purchasing natural gas from third parties and selling natural gas to other parties. These transactions are typically short-term in nature and involve positions whereby the underlying quantities generally offset. The Company also markets a significant portion of its own production. Marketing and trading revenue presented in the financial statements includes the net marketing margin on the Company’s production together with the gross trading activity with third parties.

(8) Derivative Instruments and Hedging Activities

The Company periodically enters into natural gas and crude oil futures contracts with counterparties to hedge the price risk associated with a portion of its production. These derivatives are not held for trading purposes. To the extent that changes occur in the market prices of natural gas and oil, the Company is exposed to market risk on these open contracts. This market risk exposure is generally offset by the gain or loss recognized upon the ultimate sale of the commodity hedged.

At March 31, 2004, the Company had a net current derivative liability of $16.3 million, a deferred tax asset of $5.5 million and accumulated other comprehensive loss of approximately $10.8 million on the open contracts. As of December 31, 2003, the unsettled contracts on that date resulted in a current derivative liability of $2.3 million, a deferred tax asset of $.9 million and accumulated other comprehensive loss of approximately $1.4 million.

In July and August 2002, the Company entered into several natural gas price swaps and corresponding basis swap transactions that together fixed the price the Company will receive for a portion of its natural gas production. These swaps were designated as hedges of production from September 2002 through October 2003 in certain of the regions where the Company physically delivers its gas. In December 2002, the Company entered into additional costless collar arrangements (put and call options) that were based on several of the regional price indexes where the Company physically delivers its natural gas. The collars were designated as hedges of production from January 2003 through October 2003.

In anticipation of the Matador acquisition, the Company entered into several natural gas costless collars (put and call options) in May 2003 that were based on separate regional price indexes. These contracts were based upon the areas that Matador physically delivered its natural gas and related to production from June 2003 to December 2004. A derivative gain of $1.9 million was recognized on the change in the fair value of these instruments prior to the completion of the Matador transaction on June 27, 2003 after which these contracts were re-designated as hedges of future production, and future cash settlements were offset against the realized prices for this natural gas production. At March 31, 2004, the Company had a net current derivative asset of $1.0 million associated with these costless collars to be amortized against future production.

In October and December 2003, the Company entered into several additional natural gas collars (put and call options) that were based on separate regional price indexes where the Company physically delivers its natural gas. The collars were designated as hedges of production from January through March 2004. In December 2003, the Company entered into several natural gas price swaps and corresponding basis swaps transactions that together fixed the price the Company will receive for a portion of its natural gas production. These swaps were designated as hedges of production from January through October 2004 in certain of the regions where the Company physically delivers its gas.

In January and March 2004, the Company entered into several natural gas costless collars (put and call options) that were based on separate regional price indexes where the Company physically delivers its natural gas. The January collars were designated as hedges of production from April through October 2004 and covered approximately 24,500 Mmbtu/d with a weighted average floor/ceiling price of $4.32/$5.44. The January 2004 transaction also covered approximately 2,100 GJ/d of the Company’s Canadian production at a weighted average floor/ceiling price of $5.10/$6.25 (Canadian). The March transactions established costless collars on approximately 20,000 Mmbtu/d with a weighted average floor/ceiling of $4.40/$5.66 for the November 2004 through March 2005 production period.

As a result of the above transactions, the Company has natural gas hedges, in the form of costless collars and swaps (including related basis swaps) as follows as of March 31, 2004:

	Natural Gas Collars			Natural Gas Swaps
Period	Mmbtu/d	Weighted Average Floor/Ceiling		Mmbtu/d	Weighted Average Swap Price
Second Quarter 2004	114,000	$	4.02/5.45	55,100	$	4.48
Third Quarter 2004	114,000	$	4.02/5.45	45,100	$	4.48
Fourth Quarter 2004	73,900	$	4.17/6.19	15,200	$	4.48
First Quarter 2005	28,500	$	4.59/7.25	—	$	—

For the three months ended March 31, 2004, cash settlements received on cash flow hedges increased gas and oil sales by $4.4 million. For the same period in 2003, cash settlements paid on cash flow hedges decreased gas and oil sales by $11.2 million.

(9) Segment Information

The Company operates in three reportable segments: (i) gas and oil exploration and development in the United States and Canada, (ii) marketing, gathering and processing and (iii) drilling. The long-term financial performance of each of the reportable segments is affected by similar economic conditions.

Through 2003, the Company marketed a majority of its operated gas production and some third party gas in the Rocky Mountains through Retex Inc. (“Retex”), the Company’s wholly-owned marketing subsidiary. Effective January 1, 2004, the Company began to directly market its operated gas production to third party purchasers.

The Company’s gas and oil exploration and development segment operates primarily in the Wind River and Green River Basins of Wyoming, the Piceance Basin of Colorado, the Paradox Basin of Utah and Colorado, the Val Verde Basin of west Texas, the Permian Basin of west Texas and southwestern New Mexico, the east Texas Basin and the western sedimentary basin of Canada. The marketing, gathering and processing activities of the Company are conducted primarily in the Rocky Mountain region. The drilling segment operates under the name of Sauer Drilling Company and serves the drilling needs of operators in the central Rocky Mountain region in addition to drilling for the Company.

The Company accounts for intersegment sales transfers as if the sales or transfers were to third parties, that is, at current prices.

The following tables present information related to the Company’s reportable segments (in thousands):

	Three Months Ended March 31, 2004
	Gas & Oil Exploration & Development (United States)			Gas & Oil Exploration & Development (Canada)			Gas & Oil Exploration & Development (Total)			Marketing, Gathering & Processing		Drilling			Total Segments

Revenues from external purchasers	$	131,166		$	12,177		$	143,343		$	8,932	$	4,789		$	157,064
Intersegment revenues	—			—			—			2,521		1,738			4,259
Total revenues	131,166			12,177			143,343			11,453		6,527			161,323
Intersegment eliminations	—			—			—			——		(1,738		)	(1,738		)
Total segment revenue	131,166			12,177			143,343			11,453		4,789			159,585
Loss on sale of properties	(632		)	—			(632		)	—		—			(632		)
Interest income and other	37			12			49			—		(7		)	42
Total consolidated revenues	$	130,571		$	12,189		$	142,760		$	11,453	$	4,782		$	158,995

Profit
Total reportable segment profit	$	64,882		$	4,297		$	69,179		$	2,488	$	297		$	71,964
Interest expense and other	(4,118		)	(2,053		)	(6,171		)	—		—			(6,171		)
Eliminations	—			—			—			—		(490		)	(490		)
Income (loss) before income taxes	$	60,764		$	2,244		$	63,008		$	2,488	$	(193	)	$	65,303

	Three Months Ended March 31, 2003
	Gas & Oil Exploration & Development (United States)			Gas & Oil Exploration & Development (Canada)			Gas & Oil Exploration & Development (Total)			Marketing, Gathering & Processing			Drilling			Total Segments

Revenues from external purchasers	$	41,809		$	10,257		$	52,066		$	73,575		$	3,077		$	128,718
Intersegment revenues	28,414			—			28,414			2,706			1,244			32,364
Total revenues	70,223			10,257			80,480			76,281			4,321			161,082
Marketing and trading expenses offset against related revenues for net presentation	—			—			—			(25,231		)	—			(25,231		)
Intersegment eliminations	—			—			—			(31,120		)	(1,244		)	(32,364		)
Total segment revenue	70,223			10,257			80,480			19,930			3,077			103,487
Interest income and other	46			—			46			386			119			551
Total consolidated revenues	$	70,269		$	10,257		$	80,526		$	20,316		$	3,196		$	104,038

Profit
Total reportable segment profit	$	29,133		$	3,749		$	32,882		$	3,760		$	(247	)	$	36,395
Interest expense and other	(2,372		)	(1,187		)	(3,559		)	3			—			(3,556		)
Eliminations	—			—			—			—			(245		)	(245		)
Income before income taxes and cumulative effect of change in accounting principle	$	26,761		$	2,562		$	29,323		$	3,763		$	(492	)	$	32,594

(10) Comprehensive Loss

Comprehensive loss includes certain items recorded directly to stockholders’ equity and classified as Accumulated Other Comprehensive Loss. The following table illustrates the change in Accumulated Other Comprehensive Loss for the three months ended March 31, 2004 and 2003 (in thousands):

	Three Months Ended March 31,
	2004			2003

Accumulated Other Comprehensive Income (Loss) – beginning of period	$	4,704		$	(7,435	)
Translation loss	(1,554		)	(278		)
Changes in fair value of outstanding hedging positions	(6,595		)	(12,160		)
Settlements of derivative hedging instruments reclassified to income (net of tax)	(2,794		)	8,452
Unrealized loss on marketable security	—			(3		)

Accumulated Other Comprehensive Loss – end of period	$	(6,239	)	$	(11,424	)

(11) Adoption of SFAS 143, “Accounting for Asset Retirement Obligations”

Effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 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 No. 143 resulted in an increase of 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. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of gas and oil wells. Asset retirement obligations were also recorded for processing plants and compressors.

The Company adopted SFAS No. 143 on January 1, 2003, and recorded a discounted liability of $14.5 million for the future retirement obligation, an increase to property and equipment of $13.0 million and a charge of $.9 million (net of a deferred tax benefit of $.6 million) as the cumulative effect of the change in accounting principle. There was no impact on the Company’s cash flows as a result of adopting SFAS No. 143.

The following is a reconciliation of the Company’s asset retirement obligation for the quarters ended March 31, 2004 and 2003.

	Three Months Ended
	March 31, 2004			March 31, 2003
	(In thousands)

Asset retirement obligation-beginning of period	$	21,203		$	—
Adoption of SFAS No. 143	—			14,475
Obligations incurred	277			66
Obligations on sold properties	(231		)	—
Accretion expense	432			292

Asset retirement obligation-end of period	$	21,681		$	14,833

(12) Commitments and Contingencies

The Company's operations are subject to numerous governmental regulations that may give rise to claims against the Company. In addition, the Company is a defendant in various lawsuits generally incidental to its business. The Company does not believe that the ultimate resolution of such litigation will have a material adverse effect on the Company's financial position, results of operations or cash flows.

(13) Subsequent Event

On April 14, 2004, the Company, EnCana Corporation (EnCana) and a wholly-owned acquisition subsidiary of EnCana entered into a merger agreement which provided for EnCana, through its subsidiary, to acquire the Company for $48 per share in cash. Under the terms of the merger agreement, the transaction is structured as a first step tender offer for all the common stock of the Company followed by a cash merger in which any shares of common stock not tendered will be converted into the right to receive $48 per share in cash. The tender offer was commenced on April 21, 2004. This offer will expire on May 18, 2004 but may be extended pursuant to the terms of the merger agreement and tender offer. Closing of the tender offer is subject to customary closing conditions, including valid tender of at least a majority of the common stock on a fully diluted basis and regulatory approvals. If EnCana is successful in acquiring a majority of the common stock and the regulatory and other conditions set forth in the tender offer and merger agreement are satisfied, the Company and EnCana's subsidiary will proceed with the consummation of a merger. A vote of the Company's stockholders will be required only if less than 90% of the outstanding shares of the Company's common stock is acquired in the tender offer.

ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements and Risks

The information in this Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical or present facts, that address activities, events, outcomes and other matters that the Company plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in the Company's Annual Report on Form 10-K.

Forward-looking statements may appear in a number of places and include statements with respect to, among other things:

• any expected results or benefits associated with the Company's acquisitions;

• estimates of the Company's future natural gas, crude oil and natural gas liquids production, including estimates of any increases in production;

• planned capital expenditures and the availability of capital resources to fund capital expenditures;

• estimates of the Company's gas and oil reserves;

• the impact of U.S. and Canadian political and regulatory developments;

• the Company's future financial condition or results of operations and future revenues and expenses; and

• the Company's business strategy and other plans and objectives for future operations.

Forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond the Company's control, incident to the exploration for and acquisition, development, production, marketing and sale of natural gas, natural gas liquids and crude oil in North America. These risks include, but are not limited to, commodity price volatility, third party interruption of sales to market, inflation, lack of availability of goods and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved natural gas and oil reserves and in projecting future rates of production and timing of development expenditures and the other risks described in the Company's Annual Report on Form 10-K.

Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data and the interpretation of that data by geological engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were

made previously. If significant, these revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different from the quantities of natural gas and oil that are ultimately recovered.

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. The Company specifically disclaims all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaims any resulting liability for potentially related damages.

All forward-looking statements attributable to the Company are expressly qualified in their entirety by this cautionary statement.

Pending Merger

This is neither an offer to purchase nor a solicitation of an offer to sell securities of Tom Brown. The tender offer is being made solely by an Offer to Purchase and related Letter of Transmittal that have been disseminated to the stockholders. Tom Brown stockholders are advised to read the Offer to Purchase on Schedule TO and the Solicitation/Recommendation of the Board of Directors of Tom Brown on Schedule 14D-9, each of which have been filed with the Securities and Exchange Commission because they will contain important information. The Offer to Purchase, the Solicitation/Recommendation Statement and any other relevant documents filed with the Securities and Exchange Commission are being made available to stockholders of Tom Brown at no expense to them. These documents are also available without charge at the Securities and Exchange Commission's website at www.sec.gov.

As a result of the pending merger with EnCana, the Company has elected to defer the potential sale of Sauer Drilling Company, the Company's wholly-owned drilling subsidiary.

Overview

The following analysis of operations for the three months ended March 31, 2004 and 2003 should be read in conjunction with the Consolidated Financial Statements and associated footnotes included in this Quarterly Report on Form 10-Q, and the Consolidated Financial Statements and associated footnotes contained in the December 31, 2003 Annual Report to Stockholders.

The Company is engaged primarily in the exploration for, and the acquisition, development, production, marketing, and sale of, natural gas, natural gas liquids and crude oil in North America. The Company's activities are conducted principally in the Wind River and Green River Basins of Wyoming, the Piceance Basin of Colorado, the Paradox Basin of Utah and Colorado, the Val Verde Basin and Permian Basin of west Texas and southeastern New Mexico, the east Texas Basin and the western Canadian Sedimentary Basin. The Company also, to a lesser extent, conducts exploration and development activities in other areas of the continental United States and Canada.

On a reserve volume basis, as of December 31, 2003, approximately 56% of the Company's proved reserves are located in the Rocky Mountain Region which are managed from the Denver Division, approximately 37% of the proved reserves are located in the southern area and managed by the Dallas and Midland Divisions and 7% of the Company's proved reserves are located within the Canadian Rocky Mountain Region managed from the Calgary office.

In June 2003, the Company completed its acquisition of Matador Petroleum Corporation (“Matador”), an exploration and production company active primarily in the east Texas Basin and Permian Basin of southeastern New Mexico and west Texas.

The Company operates in three segments: (i) gas and oil exploration and development in the United States and Canada, (ii) marketing, gathering and processing and (iii) drilling. The revenue and segment profit attributable to each reportable segment are set forth in the Segment Information in the Notes to the Company's Consolidated Financial Statements. The factors that individually influenced the Company's reported results of each of these business segments are set forth below

Excluding the cumulative effect of changes in accounting principle, the Company reported net income for the three months ended March 31, 2004 of $42.2 million or $.88 per share (diluted basis) as compared to a net income of $20.8 million or $.51 per share (diluted basis) for the same period in 2003.

The Company's natural gas, natural gas liquids and oil production increased 46% in the three months ended March 31, 2004 as compared to the same period in 2003. Revenue from gas, oil and natural gas liquids sales increased $62.8 million or 78% compared to the prior year's comparable period, due primarily to the increased production from the acquisition of Matador in June 2003 and from incremental production realized from the Company's active drilling programs. An increase of 23% in the realized natural gas price in the first quarter of 2004 as compared to the same period in 2003 also contributed to the increase in revenue.

The Matador acquisition on June 27, 2003 also impacted the expenses incurred by the Company in 2004. Gas and oil production expenses increased $3.2 million in the three months ended March 31, 2004 as compared to the same period of 2003 which principally related to the newly acquired properties. Interest, financing costs and other expenses incurred on this acquisition caused these expenses for the three months ended March 31, 2004 to increase approximately $2.6 million compared to the same period in 2003. Additionally, this acquisition impacted general and administrative expenses and the incremental production caused a corresponding increase in depreciation,

depletion and amortization expense in the quarter ended March 31, 2004.

The net income recognized in the three months ended March 31, 2003 was impacted by the adoption of a new accounting principle. On January 1, 2003, the Company adopted the new accounting standard SFAS No. 143 “Accounting for Asset Retirement Obligations” (SFAS No. 143). SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation. As a result of adopting SFAS No. 143, the Company recorded a non-cash charge of $.9 million (net of a deferred tax benefit of $.6 million) as the cumulative effect of the change in accounting principle.

Results of Operations

Revenues

During the three month period ended March 31, 2004, revenues from gas, oil and natural gas liquids production increased 78% to $143.3 million, as compared to $80.5 million in 2003. This increase was primarily the result of (i) an increase in average gas prices received by the Company from $4.04 per Mcf in 2003 to $4.95 per Mcf in 2004, which increased revenues $15.3 million, (ii) an increase in gas sales volumes of 52% to 25.6 Bcf, which increased revenues by $43.4 million (iii) an increase in the average oil and natural gas liquids prices received from $22.64 to $26.35 per barrel which increased revenues $2.1 million and (iv) an increase in oil and natural gas liquids sales volumes of 13% to 632.4 Mbbls, which increased revenues by $2.0 million.

Revenues in 2004 were increased by cash settlements on hedging activities. The natural gas collar and swap transactions considered effective hedges and settled in the three months ended March 31, 2004 resulted in the receipt of cash settlements of $4.4 million, which were included in gas and oil sales. For the three month period ended March 31, 2003, the Company paid cash settlements on natural gas hedging instruments of $11.2 million which reduced gas and oil sales in that period.

The following table reflects the Company's revenues, average prices received for gas, oil and natural gas liquids, and volumes of gas, oil and natural gas liquids sold in each of the periods shown:

	Three Months Ended March 31,
	2004			2003
	(In thousands)
Revenues:
Natural gas sales	$	126,682		$	67,824
Crude oil sales	9,181			5,540
Natural gas liquids	7,480			7,116
Gathering and processing	5,936			6,076
Marketing and trading	5,517			13,854
Drilling	4,789			3,077
(Loss) on sale of properties	(632		)	—
Interest income and other	42			551

Total revenues	$	158,995		$	104,038

Natural gas production sold (Mmcf)	25,569			16,794
Crude oil production sold (Mbbls)	286			180
Natural gas liquid production sold (Mbbls)	347			379
Natural Gas (Mmcf):
Price received	$	4.79		$	4.71
Effect of hedges	.16			(0.67		)
Net sales price	$	4.95		$	4.04
Average crude oil sales price ($/Bbl)	$	32.15		$	30.72
Average natural gas liquid sales price ($/Bbl)	$	21.57		$	18.79

Gathering and processing revenue for the three months ended March 31, 2004 was $5.9 million as compared to $6.1 million for the same period in 2003. The decline in gathering and processing revenue was attributable to a decrease in the gas volumes processed through the Company's Wind River facilities in 2004.

The Company reduced the natural gas volumes associated with third-party trading contracts in 2004 which caused a reduction in

trading revenue (and associated trading expenses) in the quarter ended March 31, 2004 as compared to the same period in 2003. The net margin from marketing and trading activities for the three months ended March 31, 2004 was a net loss of $.2 million as compared to a profit of $.7 million in the same period of 2003. The margin decreased in 2004 as the Company did not benefit from profitable basis differentials previously realized from transporting a portion of the Company's natural gas production into the Mid Continent market.

Drilling revenue associated with the Company's wholly-owned subsidiary, Sauer Drilling Company (Sauer), increased 56% for the three month period ended March 31, 2004 or $1.7 million as compared to the same period in 2003. In the three month period ended March 31, 2004, Sauer generated a higher percentage of its contract drilling revenue from third-party contracts not affiliated with Tom Brown, as compared to the same period in 2003. Contract drilling revenues associated with wells operated by the Company and drilled by Sauer are eliminated in consolidation. This change in mix resulted in higher drilling revenues. Drilling revenues also benefited from a increase in the first quarter of rig utilization rates in 2004 compared to the same period in 2003. For the three months ended March 31, 2004, Sauer achieved an 81% rig utilization rate on its nine operating rigs. For the same period in 2003, the rig utilization rate was 54%.

Costs and Expenses

Expenses related to gas and oil production for the three months ended March 31, 2004 increased $3.2 million from the expenses incurred during the same period in 2003. On an Mcfe basis, gas and oil production costs decreased to $.39 for the three months ended March 31, 2004 from $.41 for the same period in 2003. In the first quarter of 2004, the gas and oil production expenses increased primarily as a result of the Matador acquisition in 2003. Taxes on gas and oil production increased by $4.8 million or 73% for the three months ended March 31, 2004 in comparison to the same period in 2003. This increase was attributable to the increased gas, oil and natural gas liquids sales for the period ended March 31, 2004, as compared to the same period in 2003.

Depreciation, depletion and amortization expense increased $15 million for the three months ended March 31, 2004 as compared to the same period in 2003. The acquisition of Matador and the resulting incremental production was the primary reason for the overall increase.

Gathering and processing costs principally represent costs associated with operating and maintaining the field systems. This expense remained unchanged at $2.0 million for the three months ended March 31, 2004, as compared to the same period in 2003.

Expenses associated with the Company's exploration activities were $5.9 million for the three months ended March 31, 2004, as compared to $6.9 million for the same period in 2003. Included in exploration expenses was $.2 million of dry hole expense for the three month period ended March 31, 2004, as compared to $3.0 million in the same period of 2003.

General and administrative expenses increased in the three months ended March 31, 2004 by $2.8 million, in comparison to the same period in 2003. On an Mcfe basis, general and administrative expenses were $.26 for the three months ended March 31, 2004 as compared to $.24 for the same period in 2003. The increase in general and administrative expenses recognized in the March 31, 2004 quarter was primarily related to the Matador acquisition. This increase recognizes the additional personnel and office related expenses associated with this new area of the Company's business.

Interest expense increased approximately $4.1 million for the three months ended March 31, 2004 as compared to the same period in 2003. Incremental interest expense was incurred on the funds borrowed under the New Global Credit Facility and the Senior Subordinated Credit Facility to finance the Matador acquisition closed in June 2003.

Other expenses decreased for the three months ended March 31, 2004 by $1.5 million as compared to the same period in 2003. Expenses recognized by the Company associated with the non-compete agreements entered into with certain of the former officers of Matador were $.5 million in the quarter ended March 31, 2004. In the quarter ended March 31, 2003, the Company incurred $2.0 million associated with the Wyoming Royalty class action lawsuit that was settled in 2003.

The Company recorded an income tax provision of $23.1 million associated with the $65.3 million pre tax income in the quarter ended March 31, 2004 which represented an effective tax rate of 35 percent. For the three months ended March 31, 2003, an income tax provision of $11.8 million was recorded at an effective tax rate of 36 percent. The effective tax rate decreased in 2004 as a result of the enactment of a Canadian Federal tax reduction in 2003 that gradually reduces the Canadian Federal tax rate over a five-year period.

Capital Resources and Liquidity

Capital and Exploration Expenditures

The Company's capital and exploration expenditures and sources of financing for the three months ended March 31, 2004 and 2003 are as follows:

	2004		2003
	(In millions)
CAPITAL AND EXPLORATION EXPENDITURES:
Exploration costs	$15.9		$10.1
Development costs	70.1		22.7
Acreage	6.9		2.9
Gas gathering and processing	1.0		1.1
Other	1.9		.7

	$95.8		$37.5

FINANCING SOURCES:
Proceeds from exercise of stock options	$9.0		$1.3
Net long term bank debt repayments	(31.1	)	(5.3	)
Proceeds from sale of assets	3.4		.1
Cash flow provided by operating activities	96.4		36.9
Change in available cash and other	18.1		4.5

	$95.8		$37.5

The timing of most of the Company's capital expenditures is discretionary and there are no material long-term commitments associated with the Company's capital expenditure plans. Consequently, the Company is able to adjust the level of its capital expenditures as circumstances warrant. The level of capital expenditures by the Company will vary in future periods depending on energy market conditions, the impact of the pending EnCana merger and other related economic factors.

Subject to changes resulting from the impact of the pending merger with a subsidiary of EnCana, managment of the Company expects funds generated from operations, funds available under existing credit facilites and cash available to be sufficent to fund the company's operations, scheduled debt retirement and planned capital expenditures for the next twelve months.

Drilling Rig Obligation

To assure the availability of a drilling rig in conjunction with an exploration program in west Texas, the Company entered into a two-year commitment with a drilling contractor in 2001. The rig became available in 2002 and the two-year drilling obligation commenced on May 29, 2002. Under the terms of this arrangement, the Company is required to pay a day rate of $20,100 per day during drilling operations and $16,700 per day for rig moves. The Company anticipates that the rig will continue drilling through the expiration of this agreement in 2004.

Common Stock Issuance

In September 2003, the Company issued six million shares of common stock at a price of $25.75 per share. Net proceeds from this offering were $147.9 million after deducting underwriting discounts and commissions and estimated offering expenses. The proceeds from this offering were utilized by the Company to retire debt.

7.25% Senior Subordinated Notes

In September 2003, the Company issued $225 million principal amount of 7.25% Senior Subordinated Notes (the "7.25% Notes") at par for proceeds of $220 million (net of related offering costs). The 7.25% Notes are due on September 15, 2013 with interest payable on March 15 and September 15 of each year. If the with the pending merger with a subsidiary of EnCana or the related tender offer is consummated, under the terms of the 7.25% Notes the Company will be required within 30 days of the change of control to offer to purchase each holder's 7.25% Notes at a price equal to 101% of the principal amount thereof, together with accrued and unpaid interest.

The 7.25% Notes are unsecured senior subordinated obligations that rank junior in right of payment to all of the Company's existing and future secured debt. The indentures contain covenants restricting the ability of the Company to incur additional indebtedness, pay dividends or sell significant assets or subsidiaries. The Company was in compliance with all of these covenants at March 31, 2004.

The proceeds from the issuance of the 7.25% Notes and proceeds received from the September 2003 issuance of common stock

were utilized to retire a portion of the $110 million five-year Canadian term loan within the Company's unsecured credit facility and retire the $155 million unsecured senior subordinated credit facility originally established to consummate the Matador Petroleum acquisition in June, 2003.

Bank Credit Facility

In September 2003, the $110 million five-year Canadian term loan was repaid and retired upon issuance of the 7.25% Notes. Pursuant to the terms of the New Global Credit Facility, the borrowing base of $425 million was then readjusted to $357.5 million and the line of credit was reduced by $110 million to $315 million. At March 31, 2004, the Company had borrowings outstanding under the New Global Credit Facility totaling $138 million or 39% of the new borrowing base at an average interest rate of 3.3%. The amount available for borrowing under the New Global Credit Facility at March 31, 2004 was $177 million. In 2004, the lenders increased the borrowing base from $357.5 million to $482.5 million in conjunction with the annual borrowing base redetermination. The line of credit remained unchanged at $315 million.

Borrowings under the New Global Credit Facility are unsecured and bear interest, at the election of the Company, at a rate equal to (i) the greater of the global administrative agents prime rate or the federal funds effective rate plus an applicable margin, (ii) adjusted LIBOR for Eurodollar loans plus applicable margin, or (iii) Bankers' Acceptances plus applicable margin for Canadian dollar loans. Interest on amounts outstanding under the New Global Credit Facility is due on the last day of each quarter for prime based loans, and in the case of Eurodollar loans with an interest period of more than three months, interest is due at the end of each three month interval.

If the pending merger with a subsidiary of EnCana or the related tender offer is consummated, under the terms of the Company's Global Credit Facility these events are considered an event of default under the terms of the Facility. The Company has requested a waiver of such events of default, that will be issued in the event that the merger or the tender offer is consummated.

ITEM 3. Quantitative and Qualitative Disclosure About Market Risk

Commodity Price Fluctuations

The Company's results of operations are highly dependent upon the prices received for natural gas and oil production. Accordingly, in order to increase the financial flexibility and to protect the Company against commodity price fluctuations, the Company may, from time to time in the ordinary course of business, enter into hedging arrangements, including commodity swap agreements, forward sale contracts, commodity futures, options and other similar agreements relating to natural gas and crude oil expected to be produced. The Company has also entered into certain financial instruments that did not qualify as hedging arrangements. These transactions have principally involved basis contracts entered into to secure a pricing differential into markets where the Company has transportation agreements.

Financial instruments designated as hedges are accounted for on the accrual basis with gains and losses being recognized based on the type of contract and exposure being hedged. Gains and losses on natural gas and crude oil swaps designated as hedges of anticipated transactions, including accrued gains and losses upon maturity or termination of the contract, are deferred and recognized in income when the associated hedged commodities are produced. In order for natural gas and crude oil swaps to qualify as a hedge of an anticipated transaction, the derivative contract must identify the expected date of the transaction, the commodity involved, and the expected quantity to be purchased or sold among other requirements. In the event it becomes probable that a hedged transaction will not occur, gains and losses, including gains and losses upon early termination of contracts, are included in the income statement when incurred.

The Company has natural gas hedges, in the form of costless collars and swaps (including related basis swaps), as follows as of March 31, 2004:

	Natural Gas Collars			Natural Gas Swaps
Period	Mmbtu/d	Weighted Average Floor/Ceiling		Mmbtu/d	Weighted Average Swap Price
Second Quarter 2004	114,000	$	4.02/5.45	55,100	$	4.48
Third Quarter 2004	114,000	$	4.02/5.45	45,100	$	4.48
Fourth Quarter 2004	73,900	$	4.17/6.19	15,200	$	4.48
First Quarter 2005	28,500	$	4.59/7.25	—	—

Interest Rate Risk

At March 31, 2004, the Company had $138 million outstanding under the New Global Credit Facility at an average interest rate of 3.3%. Borrowings under the Global Credit Facility are unsecured and bear interest, at the election of the Company, at a rate equal to (i) the greater of the global administrative agents prime rate or the federal funds effective rate, plus an applicable margin (ii) adjusted LIBOR for Eurodollar loans plus applicable margin, or (iii) Bankers' Acceptances plus applicable margin for Canadian dollar loans. As a result, the Company's annual interest cost in 2004 will fluctuate based on short-term interest rates. Assuming no change in the amount outstanding during 2004, the impact on interest expense of a ten percent change in the average interest rate would be approximately $.5 million. As the interest rate is variable and is reflective of current market conditions, the carrying value of the New Global Credit Facility approximates the fair value.

At March 31, 2004, the Company also had $225 million of 7.25% Senior Subordinated Notes outstanding. These notes were issued on September 16, 2003 and subsequently the market interest rate for financial instruments of comparable quality and term declined to 6.80%. Based upon this market interest rate, the fair value of the notes at March 31, 2004 is estimated to be approximately $240 million.

Foreign Currency Exchange Risk

The Company conducts business in Canada where the Canadian dollar has been designated as the functional currency. This subjects the Company to foreign currency exchange risk on cash flows related to sales, expenses, financing and investing transactions. The Company has not entered into any foreign currency forward contracts or other similar financial instruments to manage this risk.

ITEM 4. Controls and Procedures

As of the end of the period covered by this report, our management, with the participation of each of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures. These disclosure controls and procedures are designed to provide us with a reasonable assurance that all of the information required to be disclosed by us in our periodic reports filed with the SEC is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed and maintained to ensure that all of the information required to be disclosed by us in our reports is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow those persons to make timely decisions regarding required disclosure.

Based on their evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures are effective to ensure that material information relating to our company is made known to management on a timely basis. Our Chief Executive Officer and Chief Financial Officer noted no significant deficiencies or material weaknesses in the design or operation of our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that are likely to adversely affect our ability to record, process, summarize and report financial information. There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

TOM BROWN, INC.

555 Seventeenth Street, Suite 1850

Denver, Colorado 80202

QUARTERLY REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

FORM 10-Q

PART II OF TWO PARTS

OTHER INFORMATION

TOM BROWN, INC. AND SUBSIDIARIES

OTHER INFORMATION

ITEM 4. Submission of Matters to a Vote of Security Holders

None

ITEM 5. Other Information

ITEM 6. Exhibits and Reports on Form 8K and Form 8-K/A

(a)	Exhibit No.	Description

	31.1*	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2*	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32.1*	Certification of CEO Pursuant to 18 U.S. C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	32.2*	Certification of CFO Pursuant to 18 U.S. C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*Filed herewith

(b)		Reports on Form 8-K

		Form 8-K Item 5. Press release dated February 12, 2004 entitled “Tom Brown, Inc. Announces Year-End Reserves and Operations Update; Proved Reserves Increase by 52%” filed on February 13, 2004.

		Form 8-K Item 12. Press release dated February 18, 2004 entitled “Tom Brown, Inc. Reports Record Production and Earnings for the Fourth Quarter and Full Year 2003; Fourth Quarter and Full Year 2003; Fourth Quarter Production Increases by 37%, Earnings Increase by 245%” filed on February 19, 2004.

		Form 8-K Item 5. Press release dated February 19, 2004 entitled “Tom Brown, Inc. Announces Potential Sale of Sauer Drilling Company” filed on February 20, 2004.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	TOM BROWN, INC. (Registrant)
	By:	/s/ Daniel G. Blanchard
		Daniel G. Blanchard
		Executive Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)


May 10, 2004	By:	/s/ Richard L. Satre
		Richard L. Satre
		Controller (Chief Accounting Officer)