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 SEPTEMBER 30, 2003

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 November 5, 2003.

CLASS OF COMMON STOCK		OUTSTANDING AT NOVEMBER 5, 2003

$.10 PAR VALUE		45,594,797

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

INDEX

Part I.	Item 1. Financial Information (Unaudited)
	Consolidated Balance Sheets, September 30, 2003 and December 31, 2002
	Consolidated Statements of Operations, Three and Nine Months Ended September 30, 2003 and 2002
	Consolidated Statements of Cash Flows, Nine Months Ended September 30, 2003 and 2002
	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
Part II.	Other Information
	Item 4. Controls and Procedures
	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 data)

	September 30, 2003			December 31, 2002
	(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	29,861		$	13,555
Accounts receivable, net of allowance for doubtful accounts	102,585			47,414
Fair value of derivative instruments	4,077			—
Inventories	1,392			1,808
Other	4,940			3,988

Total current assets	142,855			66,765

PROPERTY AND EQUIPMENT, AT COST:
Gas and oil properties, successful efforts method of accounting	1,533,302			959,807
Gas gathering, processing and other plant	111,888			101,054
Other	42,799			35,930

Total property and equipment	1,687,989			1,096,791
Less: Accumulated depreciation, depletion and amortization	398,342			320,306

Net property and equipment	1,289,647			776,485

OTHER ASSETS:
Goodwill	84,484			—
Other assets	19,948			7,702

Total other assets	104,432			7,702
	$	1,536,934		$	850,952

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	84,774		$	42,773
Accrued expenses	44,740			21,993
Fair value of derivative instruments	911			10,886

Total current liabilities	130,425			75,652

BANK DEBT	184,080			133,172
SENIOR SUBORDINATED NOTES	225,000			—
DEFERRED INCOME TAXES	187,351			73,967
OTHER NON-CURRENT LIABILITIES	28,017			4,543

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; Outstanding 45,583,472 and 39,261,191 shares, respectively	4,558			3,926
Additional paid-in capital	690,880			537,449
Retained earnings	86,913			29,678
Deferred compensation	(2,092		)	—
Accumulated other comprehensive income (loss)	1,802			(7,435		)

Total stockholders’ equity	782,061			563,618
	$	1,536,934		$	850,952

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 September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
	(Unaudited)						(Unaudited)
REVENUES:
Gas, oil and natural gas liquids sales	$	110,902		$	40,749		$	269,862		$	135,679
Gathering and processing	4,133			4,459			15,001			14,448
Marketing and trading	5,186			11,007			27,834			47,039
Drilling	5,799			5,036			12,754			9,617
Gain on sale of property	—			—			—			4,004
Unrealized gains (losses) on derivatives	—			299			1,913			(1,042		)
Realized losses on derivatives	—			(1,126		)	—			(1,438		)
Loss on marketable security	—			—			—			(600		)
Interest income and other	189			105			816			431

Total revenues	126,209			60,529			328,180			208,138

COSTS AND EXPENSES:
Gas and oil production	13,246			7,999			29,936			24,318
Taxes on gas and oil production	9,504			3,029			23,127			11,829
Gathering and processing costs	1,239			1,356			5,310			4,580
Trading.	5,812			8,364			27,402			43,704
Drilling operations	4,937			4,354			10,968			9,293
Exploration costs	10,674			4,150			21,353			15,334
Impairments of leasehold costs	1,853			1,392			4,816			4,173
General and administrative	6,962			3,812			17,612			13,177
Depreciation, depletion and amortization	32,296			22,823			76,866			68,846
Accretion of asset retirement obligation	417			—			1,005			—
Bad debts	102			6,262			354			6,478
Interest expense	11,365			1,474			14,717			4,558
Other	2,277			358			4,743			1,179
Total costs and expenses	100,684			65,373			238,209			207,469

Income (loss) before income taxes and cumulative effect of change in accounting principles	25,525			(4,844		)	89,971			669

Income tax (provision) benefit:
Current	(98		)	(257		)	457			(344		)
Deferred	(9,416		)	3,270			(32,264		)	2,228

Income before cumulative effect of change in accounting principles	16,011			(1,831		)	58,164			2,553
Cumulative effect of change in accounting principles	—			—			(929		)	(18,103		)

Net income (loss) income attributable to common stock	$	16,011		$	(1,831	)	$	57,235		$	(15,550	)

Weighted average number of common shares outstanding:
Basic	40,391			39,245			39,782			39,194
Diluted	41,465			39,245			40,813			40,449

Earnings per common share—Basic:
Income before cumulative effect of change in accounting principles	$	.40		$	(.05	)	$	1.46		$	.06
Cumulative effect of change in accounting principles	—			—			(.02		)	(.46		)

Net income (loss) attributable to common stock	$	.40		$	(.05	)	$	1.44		$	(.40	)

Earnings per common share—Diluted:
Income before cumulative effect of change in accounting principles	$	.39		$	(.05	)	$	1.43		$	.06
Cumulative effect of change in accounting principles	—			—			(.03		)	(.44		)

Net income (loss) attributable to common stock	$	.39		$	(.05	)	$	1.40		$	(.38	)

See accompanying notes to consolidated financial statements.

TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine Months Ended September 30,
	2003			2002
	(In thousands – unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	57,235		$	(15,550	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	76,866			68,846
Cumulative effect of changes in accounting principles	929			18,103
Change in fair value of derivatives	(1,913		)	1,042
Loss on marketable security	—			600
Gain on sale of property	—			(4,004		)
Accretion of asset retirement obligation	1,005			—
Stock compensation	686			—
Dry hole costs	8,713			3,010
Impairments of leasehold costs	4,816			4,173
Deferred tax provision	32,264			(2,228		)
Changes in operating assets and liabilities, net of the effects from the purchase of Matador:
(Increase) decrease in accounts receivable	(34,819		)	13,037
Decrease in inventories	521			434
Increase in other current assets	(744		)	(3,984		)
Increase (decrease) in accounts payable and accrued expenses	9,088			(4,157		)
Increase (decrease) in other assets, net	5,086			(14		)
Net cash provided by operating activities	159,733			79,308

CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sales of assets	707			9,056
Capital expenditures	(180,084		)	(112,778		)
Cash paid for Matador stock and options	(267,473		)	—
Transaction costs for the Matador acquisition	(4,085		)	—
Payments on non-compete agreements	(2,991		)	—
Cash acquired in Matador acquisition	3,596			—
Changes in accounts payable and accrued expenses for capital expenditures	21,849			(5,732		)
Net cash used in investing activities	(428,481		)	(109,454		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings of long-term bank debt	438,000			36,184
Repayments of long-term bank debt	(517,279		)	(3,184		)
Proceeds from issuance of subordinated notes	225,000			—
Issuance costs subordinated debt	(5,019		)	—
Proceeds from issuance of stock	154,500			—
Issuance costs common stock	(6,580		)	—
Deferred loan fees	(7,052		)	—
Proceeds from exercise of stock options	2,722			1,695

Net cash provided by financing activities	284,292			34,695
Effect of exchange rate changes on cash	762			(374		)
NET CHANGE IN CASH AND CASH EQUIVALENTS	16,306			4,175
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	13,555			15,196

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	29,861		$	19,371

Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest	$	8,122		$	3,857
Income taxes	436			1,086
Refund received of income tax deposit	—			6,000

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.

Recently Issued Accounting Standards

In June 2001, the FASB issued SFAS No. 142, “Goodwill and Other Intangible Assets,” which addresses, among other things, the financial accounting and reporting for goodwill subsequent to an acquisition. This eliminates the requirement to amortize acquired goodwill; instead, such goodwill shall be reviewed at least annually for impairment. The Company adopted SFAS No. 142 on January 1, 2002, designating its reporting units as (i) gas and oil exploration and development in the United States, (ii) gas and oil exploration and development in Canada, (iii) marketing, gathering and processing and (iv) drilling. The first two reporting units are included in the gas and oil exploration and development segment. A fair value based test was conducted effective January 1, 2002, to evaluate the goodwill originally recorded in conjunction with the January 2001 Stellarton Energy Corporation acquisition. The fair value of the reporting unit was determined with reference to the estimated discounted future net revenues of the underlying gas and oil reserves as of the date of the test and other financial considerations including going-concern value. This test resulted in the Company recording a non-cash charge of $18.1 million in the quarter ended March 31, 2002. This expense has been reflected in the 2002 consolidated statements of operations as a cumulative effect of a change in accounting principle. After this write down, the Company had no goodwill recorded on its consolidated balance sheet. In conjunction with the Company’s acquisition of Matador Petroleum Corporation on June 27, 2003, the Company recorded goodwill of $84.5 million (see note 2).

In connection with a review of the Company’s financial statements by the staff of the Securities and Exchange Commission, the Company has been made aware that an issue has arisen within the industry regarding the application of provisions of SFAS No. 142 and SFAS No. 141, “Business Combinations,” to companies in the extractive industries, including gas and oil companies. The issue is whether SFAS No. 142 requires registrants to reclassify costs associated with mineral rights, including both proved and unproved leasehold acquisition costs, as intangible assets in the balance sheet, apart from other capitalized gas and oil property costs. Historically, the Company and other gas and oil companies have included the cost of these gas and oil leasehold interests as part of gas and oil properties. Also under consideration is whether SFAS No. 142 requires registrants to provide the additional disclosures prescribed by SFAS No. 142 for intangible assets for costs associated with mineral rights.

If it is ultimately determined that SFAS No. 142 requires the Company to reclassify costs associated with mineral rights from property and equipment to intangible assets, the amounts that would be reclassified are as follows:

	September 30, 2003		December 31, 2002
	(In thousands)

INTANGIBLE ASSETS:
Proved leasehold acquisition costs	$	696,512	$	340,058
Unproved leasehold acquisition costs	99,263		62,645
Total leasehold acquisition costs	795,775		402,703
Less: Accumulated depletion	134,917		107,158
Net leasehold acquisition costs	$	660,858	$	295,545

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.

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 either settles the obligation for the recorded amount or incurs a gain or loss upon settlement to the extent the actual costs differ from the recorded liability. SFAS No. 143 was effective for fiscal years beginning after June 15, 2002. 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. An asset retirement obligation was also recorded for processing plants, compressors and other field facilities.

In November 2002, the FASB issued Financial Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, including Indirect Guarantee of Indebtedness of Others” (FIN 45). FIN 45 requires that upon issuance of a guarantee, the guarantor must recognize a liability for the fair value of the obligation it assumes under that guarantee. FIN 45’s provisions for initial recognition and measurement should be applied on a prospective basis to guarantees issued or modified after December 31, 2002. The guarantor’s previous accounting for guarantees that were issued before the date of FIN 45’s initial application may not be revised or restated to reflect the effect of the recognition and measurement provisions of the Interpretation. The disclosure requirements are effective for financial statements of both interim and annual periods that end after December 15, 2002. The Company is not a guarantor under any significant guarantees and thus this interpretation did not have a significant effect on our financial position or results of operations.

In December 2002, the FASB issued SFAS 148, “Accounting for Stock-Based Compensation — Transition and Disclosure.” SFAS No. 148 amends FASB Statement No. 123, “Accounting for Stock-Based Compensation” to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure for stock-based employee compensation and the effect of the method used on the reported results. The provisions of SFAS 148 are effective for financial statements with fiscal years ending after December 15, 2002. The adoption of this statement did not impact the Company’s financial position or results of operations because the Company has not adopted the fair value method of accounting for stock-based compensation.

In January 2003, the FASB issued Financial Interpretation No. 46, “Consolidation of Variable Interest Entities—an interpretation of ARB No. 51” (FIN 46). FIN 46 is an interpretation of Accounting Research Bulletin 51, “Consolidated Financial Statements”, and addresses consolidation by business enterprises of variable interest entities (VIEs). The primary objective of FIN 46 is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. FIN 46 requires an enterprise to consolidate a variable interest entity if that enterprise has a variable interest that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual return if they occur, or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. This guidance applies immediately to variable interest entities created after January 31, 2003, and to variable interest entities in which an enterprise obtains an interest after that date. It applies in the first fiscal year or interim period beginning after June 15, 2003, to variable interest entities in which an enterprise holds a variable interest that it acquired before February 1, 2003. The Company does not hold any interest in VIEs that would be impacted by FIN 46. Therefore, the adoption of this interpretation did not impact the Company’s financial position or results of operations.

In October 2002, Emerging Issues Task Force reached a consensus on EITF 02-03. The consensus rescinded EITF 98-10 and as a consequence the Company no longer reports the revenues from its trading activities on a net basis, unless the contracts entered into are considered derivatives. The prior period’s financial statements have been reclassified to report the amount of trading revenues from third parties on a gross basis. The margins earned by the Company’s marketing subsidiary on the sale of the Company’s production are reported as a component of marketing and trading revenues.

In April 2003, the FASB issued SFAS 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts and hedging activities under SFAS 133. The amendments set forth in SFAS 149 require that contracts with comparable characteristics be accounted for similarly. SFAS 149 is generally effective for contracts entered into or modified after June 30, 2003 (with a few exceptions) and for hedging relationships designated after June 30, 2003. The guidance is to be applied prospectively only. The adoption of SFAS 149 did not have an impact on the Company’s consolidated financial statements.

In May 2003, the FASB issued SFAS 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” This Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or

an asset in some circumstances). Many of those instruments were previously classified as equity. This Statement was developed in response to concerns expressed by preparers, auditors, regulators, investors, and other users of financial statements about issuers’ classification in the statement of financial position of certain financial instruments that have characteristics of both liabilities and equity but that have been presented either entirely as equity or between the liabilities section and the equity section of the statement of financial position. This Statement also addresses questions about the classification of certain financial instruments that embody obligations to issue equity shares. The Company has not issued any financial instruments that would be impacted by SFAS 150 thus the adoption of this standard did not have an impact on our results of operations, financial position or cash flow.

(2) Acquisitions

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).

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 represent the asset retirement obligation accounted for 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

Included in the net working capital deficit are accrued transaction costs incurred by Matador of $3.3 million.

Pro Forma Results of Operations (Unaudited)

The following table reflects the unaudited pro forma results of operations for the nine months ended September 30, 2003 and 2002 as though the Matador acquisition had occurred on January 1 of each period presented. The pro forma amounts are not necessarily representative of the results that may be reported in the future.

	Nine Months Ended September 30,
	2003		2002
	(In thousands, except per share data)
Revenues	$	387,013	$	249,899
Net income (loss)	$	65,604	$	(23,647	)
Basic net income (loss) per share	$	1.65	$	(.60	)
Diluted net income (loss) per share	$	1.61	$	(.60	)

Acquisition of Rocky Mountain Assets

In May 2003, the Company purchased additional working interests from an unrelated third party in a field operated by the Company in the Wind River Basin of Wyoming. The acquired interests included an estimated 19.0 Bcfe of proved reserves purchased for total consideration of $17.4 million, net of normal closing adjustments.

(3) Stock Based Compensation

SFAS 123, “Accounting for Stock-Based Compensation”, as amended by SFAS 148, “Accounting for Stock-Based Compensation – Transition and Disclosure,” outlines a fair value based method of accounting for stock options or similar equity instruments. The Company has opted to continue using the intrinsic value based method, as provided for in Accounting Principles Board (APB) Opinion 25, to measure compensation cost for its stock option plans.

The following table illustrates the effect on net income (loss) and earnings (loss) per share if the Company had applied the fair value recognition provisions of SFAS 123 to stock-based employee compensation.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
	(In thousands, except per share amounts)

Net income (loss) as reported	$	16,011		$	(1,831	)	$	57,235		$	(15,550	)
Deduct: Stock-based employee compensation expense determined under fair value based method for all awards, (net of tax)	(1,666		)	(1,278		)	(4,368		)	(4,150		)
Add: Compensation cost included in reported net income (loss) (net of tax)	—			—			273			—
Pro forma	$	14,345		$	(3,109	)	$	53,140		$	(19,700	)

Basic net income (loss) per common share:
As reported	$	.40		$	(.05	)	$	1.44		$	(.40	)
Pro forma	$	.36		$	(.08	)	$	1.34		$	(.50	)
Diluted net income (loss) per common share:
As reported	$	.39		$	(.05	)	$	1.40		$	(.38	)
Pro forma	$	.35		$	(.08	)	$	1.30		$	(.49	)

The weighted average fair value of options granted during the nine months ended September 30, 2003 and 2002 was $24.14 and $24.74, 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 2003 and 2002 periods, respectively: (i) risk-free interest rates of 3.41 and 3.25 percent, (ii) expected lives of 7.0 and 7.0 years, (iii) expected volatility of 126.6 and 126.7 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 and commissions and estimated offering expenses. The proceeds from this offering were utilized by the Company to retire debt (see note 5).

(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 will 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 September 30, 2003.

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.

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.

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 September 30, 2003, the Company had borrowings outstanding under the New Global Credit Facility totaling $183 million or 52% of the new borrowing base at an average interest rate of 2.8%. The amount available for borrowing under the New Global Credit Facility at September 30, 2003 was $132 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.

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 September 30, 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.

(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, but due to a change in U.S. tax policy (The Job Creation and Worker Assistance Act of 2002), an AMT liability was not created in 2002.

The components of the net deferred tax liability by geographical segment at September 30, 2003 and December 31, 2002 were as follows (in thousands):

	September 30, 2003									December 31, 2002
	United States			Canada			Total			Total

Deferred tax assets:
Net operating loss carryforward	$	27,756		$	1,745		$	29,501		$	12,122
Percentage depletion carryforward	2,534			—			2,534			2,520
Alternative minimum tax credit carryforward	5,081			—			5,081			4,831
Derivative contracts to be settled in a future period	—			—			—			3,975
State income tax credits	871			—			871			698
Other	455			—			455			333

Total gross deferred tax assets	36,697			1,745			38,442			24,479
Deferred tax liabilities:
Property and equipment	(180,506		)	(44,602		)	(225,108		)	(98,243		)
Derivative contracts to be settled in a future period	(685		)	—			(685		)	—
Other	—			—			—			(203		)
Total gross deferred tax liabilities	(181,191		)	(44,602		)	(225,793		)	(98,446		)
Net deferred tax liabilities	$	(144,494	)	$	(42,857	)	$	(187,351	)	$	(73,967	)

The Company evaluated all appropriate factors to determine the need for a valuation allowance for the net operating losses and AMT credit 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 AMT credit carryforwards and the other deferred tax assets for which valuation allowances were not provided.

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

	Nine Months Ended September 30,
	2003			2002

Current income tax:
Federal AMT (provision) benefit	$	(250	)	$	350
Canadian benefit (provision)	1,107			(209		)
State income and franchise taxes	(400		)	(485		)
Total current tax benefit (provision)	457			(344		)
Deferred income tax:
Federal and State provision	(29,487		)	1,190
Canadian (provision) benefit	(2,777		)	1,038
Total deferred tax (provision) benefit	(32,264		)	2,228
Total tax provision	$	(31,807	)	$	1,884

(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 counter parties 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 September 30, 2003, the Company had a net current derivative asset of $1.6 million, a deferred tax liability of $.6 million and accumulated other comprehensive income of approximately $1.0 million on the open contracts. As of December 31, 2002, the unsettled contracts on that date resulted in a current derivative liability of $10.9 million, a deferred tax asset of $4.0 million and accumulated other comprehensive loss of $6.5 million.

In April and May 2002, 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 collars are designated as hedges of production from May 2002 through December 2003. 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. A derivative loss of $0.4 million was recognized on the basis portion of these transactions prior to designating the basis contracts as hedges when the corresponding natural gas price swap contracts were executed. 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 are designated as hedges of production from January 2003 through October 2003.

In anticipation of the Matador acquisition, the Company entered into several new 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. For the quarter ended June 30, 2003, the change in fair value of these derivative contracts resulted in income of $1.9 million being reflected in the Consolidated Statements of Operations. After the Matador acquisition was closed on June 27, 2003, these contracts were re-designated as hedges of future production, and future cash settlements will be offset against the realized prices for this natural gas production. At September 30, 2003, the Company had a net current derivative asset of $1.6 million to be amortized against future production.

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 September 30, 2003:

	Natural Gas Collars			Natural Gas Swaps
Period	Mmbtu/d	Weighted Average Floor/Ceiling		Mmbtu/d	Weighted Average Swap Price
Fourth Quarter 2003	58,500	$	4.12/7.67	18,500	$	3.04
First Quarter 2004	32,500	$	4.78/10.08	—	—
Second Quarter 2004	27,500	$	4.08/6.30	—	—
Third Quarter 2004	27,500	$	4.08/6.30	—	—
Fourth Quarter 2004	25,800	$	4.07/6.56	—	—

(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.

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):

	Nine Months Ended September 30, 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	$	134,025		$	30,759		$	164,784		$	208,877		$	12,754		$	386,415
Intersegment revenues	105,078			—			105,078			7,588			6,203			118,869
Total revenues	239,103			30,759			269,862			216,465			18,957			505,284
Marketing and trading expenses offset against related revenues for net presentation	—			—			—			(60,963		)	—			(60,963		)
Intersegment eliminations	—			—			—			(112,667		)	(6,203		)	(118,870		)
Total segment revenue	239,103			30,759			269,862			42,835			12,754			325,451
Change in derivative fair value	1,913			—			1,913			—			—			1,913
Interest income and other	160			25			185			451			180			816
Total consolidated revenues	$	241,176		$	30,784		$	271,960		$	43,286		$	12,934		$	328,180

Profit
Total reportable segment profit	$	91,573		$	10,487		$	102,060		$	7,410		$	1,671		$	111,141
Interest expense and other	(14,987		)	(4,478		)	(19,465		)	5			—			(19,460		)
Eliminations	—			—			—			—			(1,710		)	(1,710		)
Income before income taxes and cumulative effect of change in accounting principle	$	76,586		$	6,009		$	82,595		$	7,415		$	(39	)	$	89,971

	Nine Months Ended September 30, 2002
	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	$	68,362		$	18,952		$	87,314		$	130,987		$	9,617		$	227,918
Intersegment revenues	48,365			—			48,365			8,506			6,329			63,200
Total revenues	116,727			18,952			135,679			139,493			15,946			291,118
Marketing and trading expenses offset against related revenues for net presentation	—			—			—			(21,134		)	—			(21,134		)
Intersegment eliminations	—			—			—			(56,872		)	(6,329		)	(63,201		)
Total segment revenue	116,727			18,952			135,679			61,487			9,617			206,783
Cash paid on derivatives	—			—			—			(1,438		)	—			(1,438		)
Gain on sale of property	4,004			—			4,004			—			—			4,004
Change in derivative fair value	852			—			852			(1,894		)	—			(1,042		)
Loss on marketable security	(600		)	—			(600		)	—			—			(600		)
Interest income and other	349			29			378			16			37			431
Total consolidated revenues	$	121,332		$	18,981		$	140,313		$	58,171		$	9,654		$	208,138

Profit
Total reportable segment profit	$	(4,868	)	$	1,337		$	(3,531	)	$	7,971		$	598		$	5,038
Interest expense and other	(2,019		)	(3,394		)	(5,413		)	2			(326		)	(5,737		)
Gain on sale of property	4,004			—			4,004			—			—			4,004
Loss on marketable security	(600		)	—			(600		)	—			—			(600		)
Eliminations	—			—			—			—			(2,036		)	(2,036		)
Income before income taxes and cumulative effect of change in accounting principle	$	(3,483	)	$	(2,057	)	$	(5,540	)	$	7,973		$	(1,764	)	$	669

(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 nine months ended September 30, 2003 and 2002 (in thousands):

	Nine Months Ended September 30,
	2003			2002

Accumulated Other Comprehensive Loss – beginning of period	$	(7,435	)	$	(1,330	)
Translation gain (loss)	1,701			(70		)
Changes in fair value of outstanding hedging positions	(21,935		)	(4,304		)
Reclassification adjustment for settled contracts	29,474			—
Unrealized loss on marketable security	(3		)	(99		)
Realized loss on marketable security	—			600

Accumulated Other Comprehensive Income (Loss) – end of period	$	1,802		$	(5,203	)

(11) 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 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. 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 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 143. Subsequent to the adoption of SFAS 143, additional asset retirement liabilities of $.7 million were recognized on new gas and oil properties and accretion expense of $1.0 million was recognized in the nine months ended September 30, 2003. The settlement of retirement liabilities and revisions of previous estimates relating to the asset retirement obligations were not significant during the period.

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.

	Nine Months Ended			Year Ended
	September 30, 2002			December 31, 2002			December 31, 2001			December 31, 2000
	(In thousands, except per share amounts)

Net (loss) income
As reported	$	(15,550	)	$	(8,177	)	$	69,503		$	65,703
Reduction of accretion of retirement obligation (net of tax)	(506		)	(675		)	(615		)	(429		)
Reduction of depreciation and depletion (net of tax)	335			447			434			281
Pro forma	$	(15,721	)	$	(8,405	)	$	69,322		$	65,555

Basic net income (loss) per common share:
As reported	$	(.40	)	$	(.21	)	$	1.78		$	1.79
Pro forma	$	(.40	)	$	(.21	)	$	1.78		$	1.79
Diluted net income (loss) per common share:
As reported	$	(.38	)	$	(.20	)	$	1.73		$	1.76
Pro Forma	$	(.39	)	$	(.20	)	$	1.72		$	1.75

(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.

The Company is a party to an action brought in Sweetwater County, Wyoming by three overriding royalty interest owners seeking certification as a class of all non-governmental entities which are paid royalties or overriding royalties by the Company in Wyoming. This action is one of more than a dozen virtually identical class action lawsuits filed in various Wyoming courts against producers and operators in Wyoming. The complaint alleges that the Company violated the Wyoming Royalty Payment Act (the “Act”) by improperly deducting gas transportation costs in calculating royalties and overriding royalties on Wyoming production and by failing to properly itemize all deductions taken on its payee reports. The complaint does not allege specific monetary damages. The issue in the case is whether transportation of natural gas off the lease to market is deductible transportation or nondeductible gathering within the meaning of the Act. In January 2003, the Wyoming Supreme Court agreed to answer two certified questions in a separate lawsuit which are (1) what is meant by the term “gathering” as that term is employed in the Act in defining nondeductible “costs of production,” and (2) when do the causes of action for recovery of the reporting penalty and for improper deductions under the Act accrue. These questions are currently under consideration by the Wyoming Supreme Court. Although management believes that the Company has complied with the Act, the Company has entered into negotiations with the plaintiffs to mitigate the uncertainties of litigation and resolve the issues. Pending such resolution and court approval of any proposed settlement, the Company has established a reserve we believe is adequate to cover a reasonable settlement of this matter.

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.

Overview

The following analysis of operations for the three and nine months ended September 30, 2003 and 2002 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, 2002 Annual Report to Stockholders.

Excluding the cumulative effect of changes in accounting principles, the Company reported net income for the three and nine months ended September 30, 2003 of $16.0 million and $58.2 million or $.39 and $1.43 per share (diluted basis) as compared to a net loss of $1.8 million and net income of $2.6 million or $(.05) and $.06 per share (diluted basis) for the same periods in 2002.

The Company’s natural gas, natural gas liquids and oil production increased 29% and 4% in the three and nine months ended September 30, 2003 as compared to the same periods in 2002. Revenue from gas, oil and natural gas liquids sales increased $70.2 million and $134.2 million or 172% and 99% compared to the prior year’s comparable periods, due to the increases experienced in natural gas and oil prices in 2003 as well as increased production from the acquisition of Matador Petroleum Corporation in June 2003 and from active drilling programs on the Company’s properties.

The Matador Petroleum Corporation acquisition on June 27, 2003 also impacted the expenses incurred by the Company in 2003. Gas and oil production expenses increased $5.2 million and $5.6 million in the three and nine months ended September 30, 2003 as compared to the same periods of 2002 of which $3.6 million related to the newly acquired properties in this acquisition. Interest and financing costs incurred on this acquisition caused interest expense for the three and nine months ended September 30, 2003 to increase approximately $10 million compared to the same periods in 2002. 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 September 30, 2003.

The net income and loss recognized in the nine months ended September 30, 2003 and 2002 were both impacted by the adoption of new accounting principles during these periods. 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 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. On January 1, 2002, the Company adopted the accounting standard SFAS No. 142 “Goodwill and Other Intangible Assets” (SFAS No. 142). The Company conducted a fair value based test effective January 1, 2002 to evaluate the goodwill originally recorded in conjunction with the January 2001 Stellarton Energy Corporation acquisition. The fair value of the reporting unit was determined with reference to the estimated discounted future net revenues of the underlying gas and oil reserves as of the date of the test and other financial considerations including going-concern value. This test resulted in the Company recording a non-cash charge of $18.1 million in the quarter ended March 31, 2002 as the cumulative effect of a change in accounting principle.

Results of Operations

Revenues

During the three month period ended September 30, 2003, revenues from gas, oil and natural gas liquids production increased 172% to $110.9 million, as compared to $40.7 million in 2002. This increase was primarily the result of (i) an increase in average gas prices received by the Company from $1.77 per Mcf in 2002 to $4.10 per Mcf in 2003, which increased revenues $53.9 million, (ii) an increase in gas sales volumes of 29% to 23.1 Bcf, which increased revenues by $9.3 million (iii) an increase in the average oil and natural gas liquids prices received from $16.71 per barrel to $23.37 per barrel which increased revenues $4.6 million and (iv) an increase in oil and natural gas liquids sales volumes of 27% to 687.4 Mbbls, which increased revenues by $2.4 million.

During the nine month period ended September 30, 2003, revenues from gas, oil and natural gas liquids production increased 99% to $269.9 million, as compared to $135.7 million in 2002. This increase was primarily the result of (i) an increase in average gas prices received by the Company from $2.01 per Mcf in 2002 to $4.02 per Mcf in 2003, which increased revenues $114.3 million, (ii) an increase in gas sales volumes of 4% to 56.9 Bcf, which increased revenues by $4.8 million, (iii) an increase in the average oil and natural gas liquids prices received from $15.07 per barrel to $22.46 per barrel which increased revenues $13.5 million and (iv) an increase in oil and natural gas liquids sales volumes of 6% to 1,823.1 Mbbls, which increased revenues by $1.6 million.

Revenues in 2003 were reduced by cash settlements on hedging activities. The natural gas collar and swap transactions considered effective hedges and settled in the three and nine months ended September 30, 2003 resulted in cash settlements of $7.9 million and $26.7 million, respectively, were included in gas and oil sales. For the three and nine month periods ended September 30, 2002, the Company received cash settlements on natural gas hedging instruments of $1.3 million which were included in gas and oil sales.

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 September 30,								Nine Months Ended September 30
	2003					2002			2003			2002
	(In thousands)

Revenues:
Natural gas sales	$	94,837				$	31,641		$	228,920		$	109,718
Crude oil sales	9,711					4,910			20,912			14,680
Natural gas liquids	6,354					4,198			20,030			11,281
Gathering and processing	4,133					4,459			15,001			14,448
Marketing and trading	5,186					11,007			27,834			47,039
Drilling	5,799					5,036			12,754			9,617
Gain on sale of property	—					—			—			4,004
Change in derivative fair value and cash settlements	—					(827		)	1,913			(2,480		)
Loss on marketable security	—					—			—			(600		)
Interest income and other	189					105			816			431

Total revenues	$	126,209				$	60,529		$	328,180		$	208,138

Natural gas production sold (Mmcf)	23,126					17,886			56,890			54,524
Crude oil production sold (Mbbls)	332					187			721			642
Natural gas liquid production sold (Mbbls)	356					356			1,102			1,081
Natural Gas (Mmcf):
Price received	$	4.44				$	1.70		$	4.49		$	1.99
Effect of hedges	$	(.34			)	$	.07		$	(.47	)	$	.02
Net sales price	$		4.10			$	1.77		$	4.02		$	2.01

Average crude oil sales price ($/Bbl)	$			29.27		$	26.05		$	29.02		$	22.85
Average natural gas liquid sales price ($/Bbl)	$			17.87		$	11.80		$	18.17		$	10.44

Gathering and processing revenue for the nine months ended September 30, 2003 was $15.0 million, an increase of $.6 million from the same period in 2002. A new processing plant was operational in the Paradox Basin of Colorado in the first quarter 2003 and increasing gas volumes processed through this plant contributed additional gathering revenue. Gathering and processing revenue for the quarter ended September 30, 2003 declined by approximately $.3 million compared to the same period in 2002 as the gas volumes processed through the Company’s Wind River facilities declined in 2003.

The Company reduced the natural gas volumes associated with trading contracts in 2003 which resulted in a reduction in trading revenue (and associated trading expenses) in the quarter and nine months ended September 30, 2003 as compared to the same periods in 2002. In 2002, gas price differentials between the Rocky Mountain region and the Mid Continent markets offered a profitable opportunity for the Company to utilize its firm transportation capacities to transport a portion of the Company’s natural gas production into the Mid Continent market. This marketing margin allowed the Company to realize a net profit (after trading) from marketing and trading of $3.3 million for the nine months ended September 30, 2002 as compared to a net profit of $.4 million for the same period in 2003. The profit margins offered by this market differential continued into the first quarter of 2003 but began to diminish prior to the quarter ended September 30, 2003. This resulted in a net trading loss of $.6 million being recognized in the third quarter of 2003 as compared to a net trading profit of $2.6 million for the same quarter in 2002.

Drilling revenue associated with the Company’s wholly-owned subsidiary, Sauer Drilling Company (Sauer) increased 15% and 33% for the three and nine month periods of 2003 or $.8 million and $3.1 million as compared to the same periods in 2002. In the three and nine month periods ended September 30, 2003, Sauer generated a higher percentage of its contract drilling revenue from third-party contracts not affiliated with Tom Brown, as compared to the same periods in 2002. 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 revenue also benefited from a slight increase in rig utilization rates in 2003 compared to 2002. For the three months ended September 30, 2003, Sauer obtained a 81% rig utilization rate on its nine operating rigs. For the same period in 2002, the rig utilization rate was 80%. The demand for drilling rigs has increased in 2003 and in response to this demand, Sauer purchased an additional rig at a cost of $2.2 million in June 2003 that commenced drilling operations in August 2003.

Costs and Expenses

Expenses related to gas and oil production for the three and nine months ended September 30, 2003 increased $5.2 million and $5.6 million, respectively, from the expenses incurred during the same periods in 2002. On an Mcfe basis, gas and oil production costs increased to $.44 for the nine months ended September 30, 2003 from $.37 for the same period in 2002. In the third quarter of 2003, the gas and oil production expenses included incremental expenses of $3.6 million (per Mcfe basis of $.62) as a result of the Matador acquisition that closed on June 27, 2003. In addition, the September 2003 quarter included workover expenses incurred on the Company’s Paradox Basin wells and plant turnaround expenses on a Canadian facility.

Taxes on gas and oil production increased by 214% (or $6.5 million) and 96% (or $11.3 million) for the three and nine months ended September 30, 2003 in comparison to the same periods in 2002. This increase was attributable to the impact of increased production and gas, oil and natural gas liquids prices for the periods ended September 30, 2003, as compared to the same periods in 2002. Taxes on gas and oil production as a percentage of gas, oil and natural gas liquids sales remained relatively constant at 8. 6% for the nine months ended September 30, 2003 as compared to 8.7% for the same period in 2002.

Depreciation, depletion and amortization expense increased $9.5 million and $8.0 million for the three and nine months ended September 30, 2003 as compared to the same periods in 2002. The acquisition of Matador and the resulting incremental production was the primary reason for the overall increase. On an Mcfe basis, the effective depreciation, depletion and amortization rate increased to $1.13 for the nine months ended September 30, 2003 compared to $1.06 for the same period in 2002. This increase for the nine months was generally attributable to the acquisition of the Matador properties which have a depreciation, depletion and amortization rate of $1.34 Mcfe.

Gathering and processing costs principally represent costs associated with operating and maintaining the field systems. This expense decreased for the three months ended September 30, 2003, as compared to the same period in 2002, by $.1 million and increased by $.7 million for the nine month period ended September 30, 2003, as compared to the same period in 2002. The increase was attributable to incremental processing costs associated with marketing third-party liquids through the Lisbon plant in the Paradox Basin.

Expenses associated with the Company’s exploration activities were $10.7 million and $21.4 million for the three and nine months ended September 30, 2003, as compared to $4.2 million and $15.3 million for the same periods in 2002. A major component of the exploration expenses was $4.4 million and $8.7 million of dry hole expense for the three and nine month periods ended September 30, 2003, as compared to $.2 million and $3.0 million in the same periods of 2002. Capital expenditures (excluding acquisitions) of $173.9 million were incurred in the first nine months of 2003. During the first nine months of 2002, capital expenditures were $116 million. As of September 30, 2003, the Company has $6.4 million of costs on exploratory wells in process pending the evaluation of drilling results.

General and administrative expenses increased in the three and nine months ended September 30, 2003 by $3.2 million and $4.4 million, in comparison to the same periods in 2002. On an Mcfe basis, general and administrative expenses were $.26 for both the three and nine months ended September 30, 2003 as compared to $.18 and $.20 for the same periods in 2002. The $3.2 million increase in general and administrative expenses recognized in the September 2003 quarter was primarily related to the Matador acquisition. This increase recognizes the additional personnel cost associated with this new area of the Company’s business as well as the incremental transition related expenses incurred by Tom Brown to integrate the new gas and oil properties into the Company’s operations. General and administrative expenses for the nine months ended September 30, 2003 also included a pre-tax charge of $.4 million associated with the benefit a retiring director received from an earlier amendment to the terms of an option grant and increased general corporate insurance costs of $.7 million.

Interest expense increased approximately $10 million for the three and nine months ended September 30, 2003 as compared to the same periods in 2002. 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. Interest expense for the September 2003 quarter also included the write off of $3.6 million in loan origination costs incurred to establish the Senior Subordinated Credit Facility which was repaid and retired in September 2003 and $.4 million of unamortized origination costs associated with the retired 5-year term loan.

Other expenses increased for the three and nine months ended September 30, 2003 by $1.9 million and $3.6 million, respectively, compared to the same periods in 2002. Expenses recognized by the Company associated with the non-compete agreements entered into with certain of the former officers of Matador were $1.6 million in the quarter ended September 30, 2003.

The Company recorded an income tax provision of $31.8 million associated with the $90.0 million income before the cumulative effect of change in accounting principle for the nine months ended September 30, 2003, which represented an effective tax rate of 35.3 percent. In the nine months ended September 30, 2003, the tax provision was reduced by the benefit of a $1.2 million adjustment due the

Company as a result of a change in the Canadian tax laws not previously utilized in a year 2000 tax filing. For the nine months ended September 30, 2002, an income tax benefit of $1.9 million was recorded associated with the $.7 million income before cumulative effect in change of accounting principle. This tax benefit included the impact of a $1.6 million tax reduction associated with certain Canadian expenses deductible in the United States and $0.7 million in state tax credits associated with drilling incentives in Colorado and Utah.

Capital Resources and Liquidity

Growth and Acquisitions

The Company continues to pursue opportunities which should add value by increasing its reserve base and presence in significant oil and natural gas producing areas, and further developing the Company’s ability to control and market the production of hydrocarbons. As the Company continues to evaluate potential acquisitions and property development opportunities, it expects to benefit from its financing flexibility and the additional leverage potential given the Company’s existing capital structure.

The Company entered into a definitive merger agreement on May 13, 2003 to acquire Matador Petroleum Corporation and the transaction closed on June 27, 2003. Matador was a privately held exploration and production company, active primarily in the East Texas Basin and Permian Basin of Southeastern New Mexico and West Texas, areas complementary to the Company’s current areas of interest. The Company initially funded the acquisition with borrowings under a new $425.0 million senior unsecured bank credit facility and a $155.0 million loan under a senior subordinated credit facility. The Company subsequently issued 6 million shares of common stock for net proceeds of $147.9 million and also issued $225 million of 7.25% senior subordinated notes in September 2003 to repay the $155 million bridge loan and reduce the borrowings outstanding under the bank credit facility.

In May 2003, the Company also purchased additional working interests from an unrelated third party in a field operated by the Company in the Wind River Basin of Wyoming. The acquired interests included an estimated 19.0 Bcfe of proved reserves purchased for total consideration of $17.4 million net of normal closing adjustments.

Capital and Exploration Expenditures

The Company’s capital and exploration expenditures and sources of financing for the nine months ended September 30, 2003 and 2002 are as follows:

	2003			2002
	(In millions)

CAPITAL AND EXPLORATION EXPENDITURES:
Acquisitions:
Matador	$	388.0		$	—
Other	18.7			9.1
Exploration costs	32.7			27.4
Development costs	122.2			71.1
Acreage	8.9			8.0
Gas gathering and processing	4.4			7.7
Other	5.7			1.8

	$	580.6		$	125.1

FINANCING SOURCES:
Common stock issued	$	147.9		$	—
Proceeds from exercise of stock options	2.7			1.7
Net proceeds from issuance of senior subordinated notes	220.0			—
Net long term bank debt (repayments) borrowings	(79.3		)	33.0
Debt assumed on Matador acquisition	114.5			—
Proceeds from sale of assets	.7			9.1
Cash flow provided by operating activities	159.7			74.0
Other	14.4			7.3

	$	580.6		$	125.1

The Company anticipates exploration and development expenditures of $245 to $255 million in 2003 (excluding the cost to acquire Matador), with approximately 70% to 75% allocated to development activity. 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 and other related economic factors.

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.

Common Stock

7.25% Senior Subordinated Notes

Bank Credit Facility

Senior Subordinated Credit Facility

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

ITEM 3. Quantitative and Qualitative Disclosure About Market Risk

The Company utilizes various financial instruments which inherently have some degree of market risk. The primary sources of market risk include fluctuations in commodity prices and interest rates. The Company does not conduct its business through any special purpose entities or have any exposure to off-balance sheet financing arrangements.

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 September 30, 2003:

	Natural Gas Collars			Natural Gas Swaps
Period	Mmbtu/d	Weighted Average Floor/Ceiling		Mbtu/d	Weighted Average Swap Price

Fourth Quarter 2003	58,500	$	4.12 /7.67	18,500	$	3.04
First Quarter 2004	32,500	$	4.78 /10.08	—	—
Second Quarter 2004	27,500	$	4.08/6.30	—	—
Third Quarter 2004	27,500	$	4.08/6.30	—	—
Fourth Quarter 2004	25,800	$	4.07/6.56	—	—

In October 2003, the Company entered into a basis swap for 17,000 Mmbtu per day from April-October 2004 of Rocky Mountain production to be delivered into Northwest pipeline at a basis differential of $0.67/Mmbtu under the NYMEX gas price. In addition, the Company entered into natural gas collars in the Rocky Mountain region in October 2003. These collars (put and call options) are for the November 2003 through March 2004 period, and are intended to hedge 45,000 Mmbtu/d at an average floor/ceiling price of $4.12/$7.08

Mcf. The contracts were based upon separate regional price indexes in the Rocky Mountain area where the Company physically delivers its natural gas.

Interest Rate Risk

At September 30, 2003, the Company had $183.0 million outstanding under the New Global Credit Facility at an average interest rate of 2.8%. 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 2003 will fluctuate based on short-term interest rates. Assuming no change in the amount outstanding during 2003, 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 September 30, 2003, the Company also had $255.0 million of 7.25% Senior Subordinated Notes outstanding. These notes were issued on September 16, 2003 and the carrying value of the notes at September 30, 2003 approximates the fair value.

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

The Company’s management, including the Chief Executive Officer and Chief Financial Officer, have conducted an evaluation of the effectiveness of disclosure controls and procedures pursuant to Exchange Act Rule 13a-14. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures were effective as of the period covered by this report. As required by Rule 13a-15(d), the Company’s management, including the Chief Executive Officer and Chief Financial Officer, also conducted an evaluation of the Company’s internal control over financial reporting to determine whether any changes occurred during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. Based on that evaluation, there has been no such change during the quarter covered by this report.

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 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 Pursuant to 18 U.S. C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	32.2*	Certification 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. Update filed on pro forma information through June 30, 2003 for the Matador Petroleum Corporation Acquisition filed on August 14, 2003.

Form 8-K Item 5. Press release dated September 4, 2003 entitled “Tom Brown, Inc. Announces Public Offering of Common Stock and Units of Senior Subordinated Notes” filed on September 9, 2003.

Form 8-K Item 5 and Item 7. “Underwriting Agreements and Other Amendments Relative to the Public Offering of the Common Stock and Subordinated Notes” filed on September 16, 2003.

Form 8-K Item 5. Press release dated September 10, 2003 entitled “Tom Brown, Inc. Announces Pricing of Public Offering of Common Stock” filed on September 16, 2003.

Form 8-K Item 5. Press release dated September 14, 2003 entitled “Tom Brown, Inc. Announces Pricing of Public Offering of Units of Senior Subordinated Notes” filed on September 16, 2003.

Form 8-K Item 5. Press release dated September 16, 2003 entitled “Tom Brown, Inc. Announces Exercise of Over-Allotment Option” filed on September 19, 2003.

Form 8-K Item 12. Press release dated November 6, 2003, entitled “Tom Brown, Inc. Reports Third Quarter 2003 Financial and Operating Results” filed on November 6, 2003.

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)

November 13, 2003	By:	/s/ RICHARD L. SATRE
		Richard L. Satre
		Controller
		(Chief Accounting Officer)