Brown Tom 10Q 2002 Q1 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q


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

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2002

OR

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

COMMISSION FILE NUMBER 0-3880

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 NO

APPLICABLE ONLY TO CORPORATE ISSUERS:

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of May 8, 2002.


CLASS OF COMMON STOCK		OUTSTANDING AT MAY 8, 2002

$.10 PAR VALUE		39,208,674

TABLE OF CONTENTS


FINANCIAL INFORMATION
		CONSOLIDATED BALANCE SHEETS
		CONSOLIDATED STATEMENTS OF OPERATIONS
		CONSOLIDATED STATEMENTS OF CASH FLOWS
		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
OTHER INFORMATION
	ITEM 4. Submission of Matters to a Vote of Security Holders
	ITEM 5. Other Information
	ITEM 6. Exhibits and Reports on Form 8K and Form 8-K/A

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

INDEX


		Page No.

Part I.	Item 1. Financial Information (Unaudited)
	Consolidated Balance Sheets, March 31, 2002 and December 31, 2001		4
	Consolidated Statements of Operations, Three months ended March 31, 2002 and 2001		5
	Consolidated Statements of Cash Flows, Three months ended March 31, 2002 and 2001		6
	Notes to Consolidated Financial Statements		7
	Item 2. Management’s Discussion and Analysis of
	Financial Condition and Results of Operations		12
	Item 3. Quantitative and Qualitative Disclosure about Market Risk		15
Part II.	Other information		18
	Item 4. Submission of Matters to a Vote of Security Holders		18
	Item 5. Other Information		18
	Item 6. Exhibits and Reports on Form 8-K		18
	Signature		19

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)


			March 31,			December 31,
			2002			2001

			(Unaudited)
ASSETS
CURRENT ASSETS:
	Cash and cash equivalents		$	9,540		$	15,196
	Accounts receivable			64,112			63,745
	Inventories			1,558			1,689
	Other			2,466			2,332

		Total current assets		77,676			82,962

PROPERTY AND EQUIPMENT, AT COST:
	Gas and oil properties, successful efforts method of accounting			878,717			849,628
	Gas gathering and processing and other plant			93,805			89,343
	Other			34,305			33,689

		Total property and equipment		1,006,827			972,660
	Less: Accumulated depreciation, depletion and amortization			256,459			234,134

		Net property and equipment		750,368			738,526

OTHER ASSETS:
	Goodwill, net			—			18,125
	Other assets			5,487			5,362

			$	833,531		$	844,975

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
	Accounts payable		$	53,182		$	59,172
	Accrued expenses			11,933			12,512

		Total current liabilities		65,115			71,684

BANK DEBT				134,743			120,570
DEFERRED INCOME TAXES				74,454			75,194
OTHER NON-CURRENT LIABILITIES				2,037			2,299
STOCKHOLDERS’ EQUITY
	Convertible preferred stock, $.10 par value Authorized 2,500,000 shares;
	Common Stock, $.10 par value Authorized 55,000,000 shares; Outstanding 39,166,874 and 39,127,649 shares, respectively			3,917			3,913
	Additional paid-in capital			535,307			534,790
	Retained earnings			19,381			37,855
	Accumulated other comprehensive loss			(1,423	)		(1,330	)

		Total stockholders’ equity		557,182			575,228

			$	833,531		$	844,975

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,

			2002			2001

			(Unaudited)
REVENUES:
	Gas, oil and natural gas liquids sales		$	41,518		$	106,806
	Gathering and processing			5,264			7,378
	Marketing and trading, net			(582	)		371
	Drilling			1,831			2,754
	Change in derivative fair value			—			890
	Interest income and other			263			485

		Total revenues		48,294			118,684

COSTS AND EXPENSES:
	Gas and oil production			8,171			7,605
	Taxes on gas and oil production			3,908			10,100
	Gathering and processing costs			1,521			6,241
	Drilling operations			1,938			2,274
	Exploration costs			3,583			6,454
	Impairments of leasehold costs			1,388			1,200
	General and administrative			4,872			9,127
	Depreciation, depletion and amortization			22,527			16,647
	Interest expense and other			1,477			2,348

		Total costs and expenses		49,385			61,996

		(Loss) income before income taxes and cumulative effect of change in accounting principles		(1,091	)		56,688
Income tax benefit (provision):
	Current			124			(6,805	)
	Deferred			596			(14,443	)

Net (loss) income before cumulative effect of change in accounting principles				(371	)		35,440
Cumulative effect of change in accounting principles				(18,103	)		2,026

Net (loss) income attributable to common stock			$	(18,474	)	$	37,466

Weighted average number of common shares outstanding:
	Basic			39,148			38,600

	Diluted			39,148			40,374

(Loss) earnings per common share-Basic:
	(Loss) income before cumulative effect of change in accounting principles		$	(.01	)	$	.92
	Cumulative effect of change in accounting principles			(.46	)		.05

Net (loss) income attributable to common stock			$	(.47	)	$	.97

(Loss) earnings per common share-Diluted:
	(Loss) income before cumulative effect of change in accounting principles		$	(.01	)	$	.88
	Cumulative effect of change in accounting principles			(.46	)		.05

Net (loss) income attributable to common stock			$	(.47	)	$	.93

See accompanying notes to consolidated financial statements.

TOM BROWN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


					Three Months Ended March 31,

					2002			2001

					(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net (loss) income				$	(18,474	)	$	37,466
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation, depletion and amortization				22,527			16,647
		Cumulative effect of change in accounting principles				18,103			(2,026	)
		Change in derivative fair value				—			(890	)
		Accelerated vesting of options				—			3,747
		Deferred tax provision				(596	)		14,443
		Dry hole costs				73			2,008
		Impairments of leasehold costs				1,388			1,200

						23,021			72,595
		Changes in operating assets and liabilities, net of the effects from the purchase of Stellarton:
			(Increase) decrease in accounts receivable			(137	)		21,028
			(Increase) decrease in inventories			130			367
			(Increase) decrease in other current assets			(164	)		278
			Increase (decrease) in accounts payable and accrued expenses			(1,774	)		(1,701	)
			(Increase) decrease in other assets, net			(684	)		(455	)

				Net cash provided by operating activities		20,392			92,112

CASH FLOWS FROM INVESTING ACTIVITIES:
		Proceeds from sales of assets				539			1,971
		Capital and exploration expenditures				(36,223	)		(45,133	)
		Acquisition of Stellarton stock				—			(74,500	)
		Direct costs on Stellarton acquisition				—			(3,700	)
		Changes in accounts payable and accrued expenses for capital expenditures				(5,006	)		3,845

				Net cash used in investing activities		(40,690	)		(117,517	)

CASH FLOWS FROM FINANCING ACTIVITIES:
		Borrowings of long-term bank debt				14,247			74,500
		Repayments of long-term bank debt				—			(35,000	)
		Proceeds from exercise of stock options				397			7,855

				Net cash provided by financing activities		14,644			47,355

Effect of exchange rate changes on cash						(2	)		(126	)
NET CHANGE IN CASH AND CASH EQUIVALENTS						(5,656	)		21,824
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR						15,196			17,534

CASH AND CASH EQUIVALENTS AT END OF YEAR					$	9,540		$	39,358

Supplemental disclosures of cash flow information:
Cash paid (received) during the period for:
		Interest			$	901		$	2,601
		Income taxes				601			—
		Refund received of income tax deposit				(6,000	)		—
Supplemental schedule of non-cash investing and financing activities:
		Debt assumed in Stellarton Acquisition			$	—		$	16,800

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, except for the balance sheet at December 31, 2001 which has been prepared from the audited financial statements at that date. 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 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. The new standard 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 and conducted a fair value based test to evaluate the goodwill originally recorded in conjunction with the January 2001 Stellarton Energy Corporation acquisition. 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 consolidated statements of operations as a cumulative effect of a change in accounting principle. After this write down, the Company has no goodwill recorded on its consolidated balance sheets.

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. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. The Company will adopt SFAS No. 143 on January 1, 2003, but has not yet quantified the effects of adopting SFAS No. 143 on its financial position or results of operations.

In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”. SFAS No. 144 supersedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of”. SFAS No. 121 did not address the accounting for a segment of a business accounted for as a discontinued operation which resulted in two accounting models for long-lived assets to be disposed of. SFAS No. 144 establishes a single accounting model for long-lived assets to be disposed of by sale and requires that those long-lived assets be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. The Company adopted SFAS No. 144 on January 1, 2002 which did not impact its financial position or results of operations.

(2) Acquisitions and Divestitures

Acquisition of Stellarton

On January 12, 2001, the Company completed an acquisition of 97.2% of the outstanding common shares of Stellarton. The remaining shares of Stellarton were then subsequently acquired pursuant to the compulsory acquisition provisions of the Business Corporation Act (Alberta). Including assumed debt of approximately $16.8 million, this business combination had a value of approximately $95 million and was accounted for as a purchase. The purchase price exceeded the fair value of the net assets of Stellarton by $20 million which was recorded as goodwill, and a portion of which was amortized in 2001 on a straight-line basis utilizing a twenty-year life. Effective January 1, 2002 the Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets” and expensed the unamortized goodwill of $18.1 million associated with this change in accounting principle. The net proved reserves associated with the Stellarton properties were estimated to be 75.8 billion cubic feet equivalent of gas (Bcfe) as of the closing date. The results of operations of Stellarton are included with the results of the Company from January 12, 2001 (closing date) forward.

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


Cash paid for acquisition:
	Long-term debt incurred		$	74,500
	Long-term debt assumed			16,800
	Direct acquisition costs			3,107

		Total cash consideration		94,407
Allocation of acquisition costs:
	Oil and gas properties — proved			(117,000	)
	Unproved properties			(9,975	)
	Deferred income taxes			36,375
	Gas sales contracts assumed			10,825
	Net working capital deficit assumed			5,368

		Goodwill	$	20,000

In the acquisition costs identified above, the Company recorded a deferred income tax liability of $36.4 million to recognize the difference between the historical tax basis of the Stellarton assets and the acquisition costs recorded for book purposes. The recorded book value of the proved oil and gas properties was increased to recognize this tax basis differential.

The gas sales contracts assumed in conjunction with the acquisition represented contractual obligations associated with the sale of natural gas at fixed prices below market conditions. These contracts were subsequently purchased (for an amount approximately equal to the original liability recorded) and cancelled in the quarter ended June 30, 2001.

Pro Forma Results of Operations (Unaudited)

The following table reflects the unaudited pro forma results of operations for the three months ended March 31, 2002 and 2001 as though the Stellarton 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.


	Three Months Ended
	March 31,

	2002			2001

	(In thousands, except
	per share data

Revenues	$	48,294		$	120,627
Net (loss) Income		(18,474	)		37,466
Basic net (loss) income per share		(.47	)		.97
Diluted net (loss) income per share		(.47	)		.93

(3) Debt

On March 20, 2001, as part of the final financing of the Stellarton acquisition, the Company repaid and cancelled its previous $125 million revolving credit facility and entered into a new $225 million credit facility (the “Global Credit Facility”). The Global Credit Facility is comprised of: a $75 million line of credit in the U.S. and a $55 million line of credit in Canada which both mature in March 2004, and a $95 million five-year term loan in Canada. The borrowing base under the Global Credit Facility was initially set at $300 million. The Global Credit Facility allows the lenders one scheduled redetermination of the borrowing base each December and as of May 1, 2002 the borrowing base was re-approved at $300 million. 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, 2002, the Company had borrowings outstanding under the Global Credit Facility totaling $134.7 million or 45% of the borrowing base at an average interest rate of 3.4%. The amount available for borrowing under the Global Credit Facility at March 31, 2002 was $90.3 million.

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. Interest on amounts outstanding under the 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 financial covenants of the Global Credit Facility require the Company to maintain a minimum consolidated tangible net worth of not less than $350 million (adjusted upward by 50% of quarterly net income and 50% of the net cash proceeds of any stock offering) and the Company will not permit its ratio of (i) indebtedness to (ii) earnings before interest expense, state and federal taxes and depreciation, depletion and amortization expense and exploration expense to be more than 3.0 to 1.0 as calculated at the end of each fiscal quarter.

(4) 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 is normally required to pay Alternative Minimum Tax (“AMT”) on its U.S. activity. Due to a recent change in U.S. tax policy, (The Job Creation and Worker Assistance Act of 2002 signed into law on March 9, 2002), an AMT liability is not anticipated for 2001 or 2002. This change in the AMT regulations resulted in the Company recognizing the benefit of $.4 million in the current income tax provision for the three months ended March 31, 2002 due to the reversal of an AMT provision originally recorded for 2001.

The components of the net deferred tax liability by geographical segment at March 31, 2002 and December 31, 2001 were as follows:


			March 31,									December 31,
			2002									2001

			United States			Canada			Total			Total

Deferred tax assets:
	Net operating loss carryforward		$	7,875		$	780		$	8,655		$	7,220
	Percentage depletion carryforward			2,178			—			2,178			2,178
	Alternative minimum tax credit carryforward			4,840			—			4,840			5,190
	Other			300			—			300			300

		Total gross deferred tax assets		15,193			780			15,973			14,888
Deferred tax liabilities:
	Property and equipment			(55,639	)		(34,408	)		(90,047	)		(89,677	)
	Other			(380	)		—			(380	)		(405	)

		Total gross deferred tax liabilities		(56,019	)		(34,408	)		(90,427	)		(90,082	)

		Net deferred tax liabilities	$	(40,826	)	$	(33,628	)	$	(74,454	)	$	(75,194	)

The Company evaluated all appropriate factors to determine the need for a valuation allowance for the AMT carryforwards, including any limitations concerning their use, the levels of taxable income necessary for utilization and tax planning. In this regard, based on its recent operating results and its 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 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,

		2002			2001

Current income tax:
	Federal AMT benefit (provision)	$	350		$	(4,134	)
	Canadian provision		(76	)		(1,823	)
	State income and franchise taxes		(150	)		(848	)

	Total current taxes		124			(6,805	)
Deferred income tax:
	Federal and State provision		(12	)		(15,489	)
	Canadian provision		608			1,046

	Total deferred taxes		596			(14,443	)

Total tax provision		$	720		$	(21,248	)

(5) Trading Activities

The Company engages in natural gas trading activities which involve purchasing and selling natural gas with third 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 income associated with these activities is presented on a net basis in the financial statements. The Company’s gross trading activities are summarized below.


	Three Months Ended March 31,

	2002			2001

	(In thousands)
Revenues	$	19,569		$	45,759
Operating expenses		19,801			45,581

Net trading margin	$	(232	)	$	178

(6) Derivative Instruments and Hedging Activities

On January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133 (“SFAS 133”) “Accounting for Derivative Instruments and Hedging Activities.” Under SFAS No. 133, all derivative instruments are recorded on the balance sheet at fair value. If the derivative qualifies for hedge accounting, the gain or loss on the derivative is deferred in other comprehensive income (loss) to the extent the hedge is effective. If the derivative does not qualify for hedge accounting or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. Gains and losses on hedging instruments included in accumulated other comprehensive income (loss) are reclassified to gas and oil sales revenues in the period that the related production is delivered.

The Company had certain cash flow hedges in place (natural gas costless collar arrangements) which were open as of January 1, 2001 when SFAS 133 became effective. Based upon the natural gas index pricing strip in effect as of January 1, 2001, the impact of these hedges at adoption resulted in a charge to Other Comprehensive Loss of $4.5 million (net of the deferred tax benefit of $2.6 million) and the recognition of a derivative liability of $7.1 million. During the three months ended March 31, 2001, losses of $4.4 million (net of the deferred tax benefit of $2.5 million) were transferred back from Other Comprehensive Loss. The Company also received cash settlements of $1.7 million during this period which were recognized as an increase in gas and oil sales.

The Company also entered into natural gas basis swaps covering essentially the same time period of the natural gas costless collars. These transactions were executed in December, 2000 with settlement periods in 2001. Under SFAS 133, these basis swaps did not qualify for hedge accounting. Accordingly, upon adoption these basis swaps resulted in the recognition of derivative gains of $2.0 million, recorded as a cumulative effect of a change in accounting principle, (net of the deferred tax liability of $1.2 million) and a derivative receivable of $3.2 million. A $.9 million gain was recognized in conjunction with the change in the value of these contracts in the three months ended March 31, 2001. Net receipts of $1.4 million were received during the first quarter of 2001 on these contracts.

(7) Segment Information

The Company operates in four reportable segments: (i) gas and oil exploration and development for 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 accounting policies of the segments are the same as those described in Note 1 of the Notes to Consolidated Financial Statements. The Company evaluates performance based on profit or loss from operations before income taxes, accounting changes, nonrecurring items and interest income and expense.

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, 2002

	Gas & Oil			Gas & Oil
	Exploration			Exploration			Marketing,
	&			&			Gathering
	Development			Development			&				Total
	(United States)			(Canada)			Processing		Drilling		Segments

Revenues from external purchasers	$	22,528		$	5,700		$	52,274	$	1,831	$	82,333
Intersegment revenues		13,553			—			1,985		2,392		17,930
Segment profit		(1,036	)		(187	)		2,109		55		941


	Three Months Ended March 31, 2001

	Gas & Oil		Gas & Oil
	Exploration		Exploration		Marketing,
	&		&		Gathering
	Development		Development		&				Total
	(United States)		(Canada)		Processing		Drilling		Segments

Revenues from external purchasers	$	62,745	$	9,492	$	101,810	$	2,754	$	176,801
Intersegment revenues		35,703		—		1,140		3,619		40,462
Segment profit		55,616		3,151		363		1,284		60,414

The following tables reconcile segment information to consolidated totals:


			Three Months Ended
			March 31,

			2002			2001

			(In thousands)
Revenues
	Revenue from external purchasers		$	82,333		$	176,801
	Marketing and trading expenses offset against related revenues for net presentation			(36,240	)		(64,117	)
	Intersegment revenues			17,930			40,462
	Intercompany eliminations			(15,729	)		(34,462	)

		Total consolidated revenues	$	48,294		$	118,684

Profit Total reportable segment profit			$	941		$	60,414
	Interest and other			(1,214	)		(2,348	)
	Eliminations and other			(818	)		(1,378	)

	(Loss) income before income taxes and cumulative effect of change in accounting principles		$	(1,091	)	$	56,688

(8) Comprehensive Income (Loss)

Comprehensive Income (Loss) includes certain items recorded directly to shareholders’ equity and classified as Other Comprehensive Income (Loss). The following table illustrates the change in comprehensive loss for the three months ended March 31, 2002 (in thousands):


Other Comprehensive Loss — December 31, 2001			$	(1,330	)
	Translation loss			(64	)
		Unrealized loss on marketable securities		(29	)

Other Comprehensive Loss — March 31, 2002			$	(1,423	)

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

The following analysis of operations for the first quarter of 2002 and 2001 should be read in conjunction with the Consolidated Financial Statements and associated footnotes included in this 10-Q, and the Consolidated Financial Statements and associated footnotes contained in the December 31, 2001 Annual Report to Stockholders.

Excluding the cumulative effect of changes in accounting principles, the Company realized a net loss for the three months ended March 31, 2002 of $.4 million or ($.01) per share (diluted basis) as compared to net income of $35.4 million or $.88 per share (diluted basis) for the same period in 2001. The majority of this decrease was attributable to lower commodity prices in 2002.

Despite an increase in the Company’s natural gas, natural gas liquids and oil production of 22% in the first quarter of 2002 in comparison to the first quarter of 2001, revenue from gas, oil and natural gas liquids sales decreased $65.3 million or 61% less than the prior year’s comparable period.

The net loss and income recognized in the three months ended March 31, 2002 and 2001 were both impacted by the adoption of new accounting principles during these periods. On January 1, 2002, the Company adopted the new accounting standard, SFAS No. 142 “Goodwill and Other Intangible Assets” (SFAS No. 142). In conjunction with the January 2001 Stellarton Energy acquisition, the Company allocated $20 million of the purchase price to goodwill. The fair value test performed to evaluate the carrying value of this business segment and the recorded goodwill as required by SFAS No. 142 resulted in the recognition of a non-cash charge of $18.1 million. The quarter ended March 31, 2001 was similarly impacted by the adoption of SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” for which a $2.0 million gain (net of tax) was recognized.

Results of Operations

Revenues

During the three month period ended March 31, 2002, revenues from gas, oil and natural gas liquids production decreased 61% to $41.5 million, as compared to $106.8 million in 2001. This decrease was the result of (i) a decrease in average gas prices received by the Company from $6.51 per Mcf in 2001 to $1.89 per Mcf in 2002, which decreased revenues $82.9 million, (ii) a decrease in average oil and natural gas liquids prices received from $22.80 to $12.92 which decreased revenues $5.8 million, (iii) gas sales volumes increased by 21% to 17.9 Bcf which increased revenues by $20.6 million, and (iv) an increase in oil and natural gas liquids sales volumes of 24% to .6 million barrels, which increased revenues by $2.8 million.

Revenues in 2001 were also impacted by cash gains realized from hedging activities. The NYMEX collar and swap transactions considered effective hedges and settled in the first quarter of 2001, resulted in cash gains of $1.7 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 amount of gas, oil and natural gas liquids sold in each of the periods shown:


		Three Months Ended March 31,

		2002			2001

		(In thousands)
Revenues:
	Natural gas sales	$	33,999		$	96,115
	Crude oil sales		4,542			5,852
	Natural gas liquids		2,977			4,839
	Gathering and processing		5,264			7,378
	Marketing and trading, net		(582	)		371
	Drilling		1,831			2,754
	Change in derivative fair value		—			890
	Interest income and other		263			485

	Total revenues	$	48,294		$	118,684

Net (loss) income attributable to common stock		$	(18,474	)	$	37,466

Natural gas production sold (Mmcf)			17,942			14,773
Crude oil production (Mbbls)			235			222
Natural gas liquid production (Mbbls)			347			247
Average natural gas sales price ($/Mcf)		$	1.89		$	6.51
Average crude oil sales price ($/Bbl)		$	19.33		$	26.36
Average natural gas liquid sales price ($/Bbl)		$	8.58		$	19.59

Gathering and processing revenue decreased 29% to $5.3 million as compared to $7.4 million in 2001. A number of non-strategic gathering and processing assets were sold throughout 2001. Gathering and processing revenue was impacted in the first three months of 2002 as a result of these dispositions.

Net marketing and trading income decreased from a profitable gross margin of $.4 million in the first quarter of 2001 to a loss of $.6 million in the first quarter of 2002. This was attributable to reduced trading margins associated with the lower pricing environment in 2002.

Drilling revenue associated with the Company’s wholly-owned subsidiary, Sauer Drilling Company (Sauer) decreased 34% in 2002 or $.9 million. The general decrease in activity within the oil and gas industry attributable to the decline in commodity prices in 2002 impacted the contract drilling business. In the three months ended March 31, 2001, Sauer obtained a 95% rig utilization rate on its seven operating rigs. For the same period in 2002, its eight operating rigs were utilized 58% of the period.

Costs and Expenses

Expenses related to gas and oil production increased 7% from the first quarter of 2001, as compared to the first quarter of 2002, due primarily to increased production levels in the first quarter of 2002. For the year ended December 31, 2001, the Company participated in the drilling of 200 wells in the United States and Canada, 85% of which were successful and contributed to the production increase realized in the first quarter of 2002.

Taxes on gas and oil production decreased by 61% or ($6.2 million) in the first quarter of 2002 due primarily to the decrease in gas and oil prices from the same period in 2001.

Depreciation, depletion and amortization increased $5.9 million in the first quarter of 2002 as compared to 2001. The production increase of 22% on a Mcfe basis for the first quarter of 2002 contributed approximately $3.7 million of this increase. The Company’s effective per unit depletion rate also increased in 2002 as a result of experiencing higher finding costs on the oil and gas reserve additions associated with the 2001 capital program.

Gathering and processing costs principally represent gas purchased in conjunction with the gas gathering operation to replace gas physically lost in the transmission process and all other costs associated with operating and maintaining the gathering and processing systems. This expense decreased in the first quarter of 2002 as compared to the same period in 2001, by $4.7 million, primarily as a result of the Company’s disposition of a number of the gathering and processing assets in 2001. This expense also declined in the 2002 quarterly period, as the cost to purchase the system gas lost in the transmission process declined.

Expenses associated with the Company’s exploration activities were $3.6 million and $6.5 million for the three months ended March 31, 2002 and 2001, respectively. The Company’s decreased exploration efforts in the first quarter of 2002 contributed to decreased dryhole costs and seismic related expenses. Capital expenditures of $39.7 million were incurred in the first quarter of 2002. During the first quarter of 2001 capital expenditures were $146.5 million, which included $95 million associated with the Stellarton acquisition.

General and administrative expenses have increased in the first quarter of 2002 in comparison to the same period in 2001 as a result of the Company’s increased level of operations. On an Mcfe basis, general and administrative expenses were $.23 and $.52 for the three months ended March 31, 2002 and 2001, respectively. Included in the expenses for the first quarter of 2001 was a $5.3 million ($.30 per Mcfe) pre-tax charge associated with the retirement of Donald L. Evans, previously Tom Brown, Inc.’s Chairman and CEO. Mr. Evans received a $1.5 million retirement payment and the Company recognized a $3.8 million non-cash charge in conjunction with the acceleration of Mr. Evans’ stock options.

The Company recorded an income tax benefit of $.7 million associated with the $1.1 million loss before cumulative effect in change of accounting principle for the three months ended March 31, 2002. This tax benefit includes the impact of a recent change in tax law that retroactively eliminated the $.4 million alternative minimum tax provision originally recorded for the year ended December 31, 2001. There was no tax impact associated with the goodwill expensed in conjunction with the change in accounting principle as goodwill is not considered a deductible expense for tax purposes. For the quarter ended March 31, 2001, a tax provision of $21.2 million was provided at an effective tax rate of 37.5%.

Capital Resources and Liquidity

Growth and Acquisitions

The Company continues to pursue opportunities which will add value by increasing its reserve base and presence in significant natural gas areas, and further developing the Company’s ability to control and market the production of natural gas. As the Company continues to evaluate potential acquisitions and property development opportunities, it will benefit from its financing flexibility and the leverage potential of the Company’s overall capital structure. The Company does not conduct its business through special purpose entities or have any exposure to off-balance sheet financing arrangements.

Capital and Exploration Expenditures

The Company’s capital and exploration expenditures and sources of financing for the quarters ended March 31, 2002 and 2001 are as follows:


		2002		2001

		(In millions)
CAPITAL AND EXPLORATION EXPENDITURES:
Acquistions:
	Stellarton	$	—	$	95.0
Exploration costs			7.5		14.2
Development costs			25.2		28.5
Acreage			1.8		4.8
Gas gathering and processing			4.4		2.5
Other			.8		1.5

		$	39.7	$	146.5

FINANCING SOURCES:
	Common stock issued		.4		7.9
	Net long term bank debt		14.2		39.5
	Debt assumed on Stellarton transaction		—		16.8
	Proceeds from sale of assets		.5		2.0
	Cash flow from operations before changes in working capital		23.0		72.6
	Working capital and other		1.6		7.7

		$	39.7	$	146.5

The Company anticipates capital and exploration expenditures between $115 to $125 million in 2002, $104 to $113 million allocated to exploration and 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 Obligation

To assure the availability of a drilling rig in conjunction with the continuing exploration program at the Deep Valley prospect in West Texas, the Company entered into a two-year commitment with a drilling contractor in 2001. The rig became available on March 1, 2002 after which a 90-day period is allowed under the terms of the agreement to mobilize the rig and commence the two-year drilling obligation. Under the terms of this arrangement, the Company is required to pay a daywork rate of $20, 100/day during drilling operations, $16,700/day for rig moves and a special standby fee of $6,000/day during the initial 90-day commencement period.

Bank Credit Facility

On March 20, 2001, as part of the final financing of the Stellarton acquisition, the Company repaid and cancelled its previous $125 million revolving credit facility and entered into a new $225 million credit facility (the “Global Credit Facility”). The Global Credit Facility is comprised of: a $75 million line of credit in the U.S. and a $55 million line of credit in Canada which both mature in March 2004, and a $95 million five-year term loan in Canada. The borrowing base under the Global Credit Facility was initially set at $300 million. The Global Credit Facility allows the lenders one scheduled redetermination of the borrowing base each December, and, as of May 1, 2002 the borrowing base was re-approved at $300 million. 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, 2002, the Company had borrowings outstanding under the Global Credit Facility totaling $134.7 million or 45% of the borrowing base at an average interest rate of 3.4%. The amount available for borrowing under the Global Credit Facility at March 31, 2002 was $90.3 million.

The 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 $350 million (adjusted upward by 50% of quarterly net income and 50% of the net cash proceeds of any stock offering) and the Company will not permit its ratio of (i) indebtedness to (ii) earnings before interest expense, State and Federal taxes and depreciation, depletion and amortization expense and exploration expense to be more than 3.0 to 1.0 as calculated at the end of each fiscal quarter. The Company was in compliance with all covenants during the first quarter of 2002 and at March 31, 2002.

Markets and Prices

The Company’s revenues and associated cash flows are significantly impacted by changes in gas and oil prices. All of the Company’s gas and oil production is currently market sensitive as none of the Company’s gas and oil production has been presold at contractually specified prices. During the first quarter of 2002, the average prices received for gas and oil by the Company were $1.89 per Mcf and $12.92 per barrel, respectively, as compared to $6.51 Mcf and $22.80 per barrel in 2001.

Subsequent to March 31, 2002, the Company believed that the pricing environment provided a strategic opportunity to reduce the price risk on a portion of the Company’s production and decided to implement a hedging program. Accordingly, 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 covering the May through October 2002 contract periods were intended to hedge approximately 15% of the Company’s expected natural gas production for this period. The November 2002 through December 2003 collars are intended to cover approximately 10% of the Company’s natural gas production based upon current production levels.

The terms of these costless collar arrangements are as follows:


	Natural Gas Collars

	Volume in		Weighted Average
Contract Period	MMBtu/d		Floor/Ceiling

May-October, 2002		25,000	$	2.80/$4.03
November 2002-December 2003		15,000	$	3.13/$4.57

The Company also entered into certain financial instruments to lock the basis differential on 15,000 MMBtu/day during the June through October 2002 contract periods. These contracts secured a price differential into the Mid Continent market at a weighted average price $.78 above the price index for a delivery point in the Rocky Mountain area where the Company markets a significant portion of its’ natural gas production.

Forward-Looking Statements and Risk

Certain statements in this report, including statements of the future plans, objectives, and expected performance of the Company, are forward-looking statements that are dependent on certain events, risks and uncertainties that may be outside the Company’s control which could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, political and economic uncertainties, future business decisions, and other uncertainties, all of which are difficult to predict.

There are numerous uncertainties inherent in estimating quantities of proven oil and gas reserves and in projecting future rates of production and timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates. The drilling of exploratory wells can involve significant risks including those related to timing, success rates and cost overruns. Lease and rig availability, complex geology and other factors can affect these risks. Future oil and gas prices also could affect results of operations and cash flows.

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 rate fluctuations. The Company does not conduct its business through any special purpose entities or have any exposure to off-balance sheet financing arrangements.

Price Fluctuations

The Company’s results of operations are highly dependent upon the prices received for oil and natural gas 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 non-speculative hedge arrangements, commodity swap agreements, forward sale contracts, commodity futures, options and other similar agreements relating to natural gas and crude oil.

Derivative Financial Instruments

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 or 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 that a hedged transaction does not occur, future gains and losses, including termination gains or losses, are included in the income statement when incurred.

Interest Rate Risk

At March 31, 2002, the Company had $134.7 million outstanding under the Global Credit Facility at an average interest rate of 3.4%. Borrowings under the Global Credit Facility bear interest, at the election of the Company, at (i) the greater of the agent bank’s prime rate or the federal funds effective rate, plus an applicable margin or (ii) the agent bank’s Eurodollar rate, plus an applicable margin. As a result, the Company’s annual interest cost in 2002 will fluctuate based on short-term interest rates. Assuming no change in the amount outstanding during 2002, the impact on interest expense of a ten percent change in the average interest rate would be approximately $.4 million. As the interest rate is variable and is reflective of current market conditions, the carrying value of the Global Credit Facility approximates the fair value.

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

The Company’s annual meeting of stockholders was held on May 9, 2002. At the meeting, the following persons were elected to serve as Directors of the Company until the annual meeting of stockholders and until their respective successors are duly qualified and elected: (1) Thomas C. Brown, (2) Wayne W. Murdy, (3) Henry Groppe, (4) Edward W. LeBaron, Jr. (5) James B. Wallace, (6) Robert H. Whilden, Jr. (7) David M. Carmichael, (8) James D. Lightner and (9) Kenneth B. Butler.

Set forth below is a tabulation of votes with respect to each nominee for Director:


	Votes		Votes		Broker
	Cast for		Withheld		Non-Votes

Thomas C. Brown		36,991,085		206,900		-
Kenneth B. Butler		36,893,285		304,700		-
David M. Carmichael		37,027,211		170,774		-
Henry Groppe		36,756,647		441,338		-
Edward W. LeBaron, Jr.		36,920,876		277,109		-
James D. Lightner		36,996,035		201,950		-
Robert H. Whilden, Jr.		37,022,126		175,859		-
James B. Wallace		36,893,710		304,275		-
Wayne W. Murdy		36,926,886		271,099		-

ITEM 5.Other Information


	Form 8-A12B Item 2. First Amendment to Certificate of Designation, Rights and Preferences of Series B Preferred Stock filed on April 29, 2002.

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


(a)		Exhibit No		Description

None.

(b) Reports on Form 8-K


	Form 8-K Item 7. 2002 Financial Model Estimates filed on May 9, 2002.

	Form 8-K Item 4. Change in Registrant's Certifying Accountant filed March 22, 2002.

TOM BROWN, INC. AND SUBSIDIARIES
OTHER INFORMATION

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)

		/s/ Daniel G. Blanchard

		Daniel G. Blanchard Executive Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

	May 14, 2002	/s/ Richard L. Satre

		Richard L. Satre Controller (Chief Accounting Officer)

Positive
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Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Avg

Brown Tom Inactive 10-Q2002 Q1 Quarterly report

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