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SECURITIES AND EXCHANGE
Washington, D.C. 20549

FORM 8-K

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

Date of Report (Date of earliest event reported) May 8, 2003

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

(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)

ITEM 12. RESULTS OF OPERATIONS AND FINANCIAL CONDITION.

        Tom Brown, Inc. press release dated May 8, 2003, entitled "TOM BROWN, INC. REPORTS FIRST QUARTER 2003 FINANCIAL AND OPERATING RESULTS"

TOM BROWN, INC.
REPORTS FIRST QUARTER 2003 FINANCIAL AND OPERATING RESULTS

        DENVER, May 8, 2003—Tom Brown, Inc. (NYSE:TBI) today reported results from operations for the first quarter ended March 31, 2003. The Company reported net income for the three months ended March 31, 2003 of $19.9 million or $0.49 per share (all per share amounts noted herein are on a diluted basis) as compared to a net loss of $18.5 million or $0.47 per share in the first quarter of 2002. Before the cumulative effect of changes in accounting principles, the Company reported income of $20.8 million or $0.51 per share as compared to a loss of $0.4 million or $0.01 per share for the comparable quarter of 2002. The majority of the increase in earnings is attributable to higher natural gas and oil prices. Discretionary cash flow for the first quarter of 2003 totaled $62.4 million (see reconciliation to net cash provided by operating activities below), an increase of 135% from the $26.5 million in the corresponding period of 2002.

        Tom Brown, Inc.'s Chairman, CEO and President, Jim Lightner, commented that, "First quarter earnings and discretionary cash flow were very strong in large part due to strong commodity prices. Additionally, our production results were better than we originally expected. Now that Rockies gas prices have improved and seasonal drilling restrictions have been lifted we are on track to achieve our projected 14% volume growth from the first quarter average rate of 224 Mmcfepd to the fourth quarter rate of 255 Mmcfepd."

        The following table summarizes the Company's production and commodity price realizations for the 2003 and 2002 quarter ended March 31:

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(1)

Includes the effects of hedging.

        First quarter 2003 production averaged 224 million cubic feet equivalent per day (MMcfepd), a 6% decrease over the comparable period of 2002. The first quarter 2003 production was impacted by decreased drilling activities beginning in the second half of 2002 through the first quarter of 2003, as a result of low natural gas prices in the Rocky Mountain regions and seasonal drilling restrictions. Gas, oil and natural gas liquids sales for the three months ended March 31, 2003 totaled $80.5 million, an increase of $39.0 million or 93% greater than the prior year's comparable period due to higher commodity prices in the current quarter.

        Production expense for the current quarter and the comparable prior year's quarter averaged $0.41 per Mcfe and $0.38 per Mcfe, respectively, while production taxes of $0.33 per Mcfe were $0.15 per Mcfe higher than in the corresponding period of the prior year. The increase in production taxes is a result of higher commodity prices. Combined cash costs (production expense, production taxes, interest expense and general and administrative—excluding non-cash costs) totaled $1.15 per Mcfe in the first quarter of 2003, $0.29 per Mcfe higher than in the prior year's comparable period. Net cash margin totaled $2.84 per Mcfe in the most recently completed quarter as compared to $1.08 per Mcfe in the prior year's comparable period.

        The Company's marketing, gathering and processing margins totaled $4.8 million in the most recently completed quarter compared to $3.2 million in the corresponding period in the prior year. Marketing margin for the first quarter of 2003 was $0.7 million as compared to a loss of $0.6 million in the prior year's first quarter. The gathering and processing margin was $4.1 million for the first quarter of this year as compared to $3.8 million for the previous year's first quarter.

First Quarter 2003 Exploration and Development Program

        For the three months ended March 31, 2003, the Company drilled or participated in a total of 18 wells in the U.S. and six in Canada. Of the 18 wells drilled in the U.S., at quarter end 12 wells had been completed, three wells were in the process of being completed and three were abandoned. Of the six wells drilled in Canada, at quarter end three wells had been completed and three wells were in the process of being completed. At quarter-end, ten wells were drilling in the U.S.

Wind River Basin

        In the first quarter of 2003, the Company drilled one well in the Wind River Basin at the Frenchie Draw field. The Company produced an average of 52.4 Mmcfepd net for the three months ended March 31, 2003 from the Wind River Basin, a decrease of 18% over the comparable period of the prior year. The decrease in production is due to a lack of drilling in the Basin. There was no drilling activity in the first quarter on the Wind River Indian Reservation due to finalization of certain contractual issues with the Northern Arapahoe and Eastern Shoshone Indian tribes.

        The Company has entered into a purchase and sale agreement with an undisclosed seller to acquire additional working interests in the Muddy Ridge field for $17.4 million which is expected to close in May of 2003. The acquired interests include an estimated 19.4 billion cubic feet of gas equivalent (100% proved developed), resulting in a purchase price of $0.90 per Mcfe.

Piceance Basin

        The Company did not drill any wells in the Piceance Basin in the first quarter of 2003. The Company produced an average of 29.3 Mmcfepd net for the three months ended March 31, 2003 from the Piceance Basin, a decrease of 11% over the comparable period of the prior year. The drilling program in the Piceance has begun now that the seasonal restrictions have been lifted.

Paradox Basin

        The Company drilled two wells in the Paradox Basin in the first quarter of 2003. The Company produced an average of 50.7 Mmcfepd net for the three months ended March 31, 2003 from the Paradox Basin, an increase of 12% over the comparable period of the prior year.

Southern Region (Permian and East Texas Basins)

        In the first three months of the 2003, the Company drilled or participated in 14 gross wells in the Southern Region and another six wells were drilling at quarter-end. The Company produced an average of 44.8 Mmcfepd net for the three months ended March 31, 2003 from the Southern Region, a decrease of 4% over the comparable period of the prior year.

        In the Mimms Creek field (TBI 55% working interest) in the East Texas basin, the Company participated in three wells in the first quarter of 2003 and one well was drilling at quarter end. During the quarter, two wells were completed in the Bossier sand and one well was completed in the Cotton Valley formation. Both Bossier sand wells have produced at rates in excess of 6 Mmcfpd and the Cotton Valley well has produced up to 2 Mmcfpd. As a result of its successful drilling program, the Company's average net daily production from the Mimms Creek field grew to 14 Mmcfepd in the first quarter of 2003, an increase of 40% over the average 2002 daily rate.

        In the Deep Valley project area in the Permian Basin, the Company is drilling horizontally in a re-entry of the Frost #3 (TBI 37.5% working interest). This well is near the Trees Estate #4H, the Company's previously announced discovery. The Company finished fracture stimulating the Beefmaster #1H (TBI 50% working interest) lateral in four individual sections. TBI production tested the individual sections of the lateral where two of the intervals tested at greater than 3 Mmcfpd, one interval tested at greater than 1.5 Mmcfpd and the fourth interval tested at 300 Mcfpd. The well was placed to sales on April 18, 2003 producing from all four intervals at a combined rate of approximately 2 Mmcfpd and 300-400 barrels of water per day. Technical work is currently being performed to analyze the discrepancy between the tested rates of the four individual intervals and the current combined production results.

Canada

        In the first three months of 2003, the Company drilled six wells in Canada primarily in the Carrot Creek and Edson fields. The Company produced an average of 23.5 Mmcfepd net for the three months ended March 31, 2003 from Canada, a decrease of 4% over the comparable period of the prior year.

Outlook for 2003

        The following statements provide a summary of certain estimates for the second quarter and full-year of 2003 based on current expectations. These estimates exclude any impact related to the discussions with Matador as previously announced on May 7, 2003. Tom Brown's exploration and development capital expenditures (excluding acquisitions) for first quarter 2003 totaled $35.7 million. For the full-year 2003, the Company is forecasting exploration and development capital expenditures in the range of $175-185 million (excluding the anticipated $17.4 million acquisition of the working interest at the Muddy Ridge field discussed above), which includes approximately 70%-75% for development activities and the remainder for land acquisitions and exploration.

        Based upon this anticipated range of capital spending and the June closing of the Muddy Ridge acquisition, Tom Brown expects 2003 production to total approximately 85-88 Bcfe. The mid-point estimate of the range for the second quarter 2003 production is approximately 20.3 Bcfe. Average daily production volumes are expected to grow over 14% from the first quarter 2003 average rate of 224 Mmcfepd to the fourth quarter average rate of 255 Mmcfepd as a more active drilling program takes effect. The following table summarizes the mid-point values of the estimated production level for the second quarter of 2003.

        Preliminary estimates for exploration expense are $12-$14 million for the second quarter of 2003 and $33-$35 million for the entire year, including estimated dry hole expense. Actual dry hole expense could differ based on timing and results of wells. Other operating expenses for 2003 are expected to fall within the ranges summarized below:

        The Company's management will hold a conference call today, Thursday, May 8, 2003 at 1:00 p.m. Mountain Time to review the first quarter 2003 results. The dial-in number to participate in the call is 800-399-0117 (U.S.) or 706-679-3393 (International), or the call can be accessed live in a listen-only mode by following the link from the Company's website www.tombrown.com.

        Tom Brown, Inc. is a Denver, Colorado based independent energy company engaged in the exploration for, and the acquisition, development, production and marketing of, natural gas, natural gas liquids and crude oil in North America. The Company's common stock is traded on the NYSE under the symbol TBI.

        This news release 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. These statements are based on certain assumptions and analyses made by the Company in light of its experience, on general economic and business conditions and expected future developments, many of which are beyond the control of the Company. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and gas, environmental risks, operating risks, risks related to exploration and development, the ability of the Company to meet its stated business goals and other risk factors as described in the Company's 2002 Annual Report and Form 10-K as filed with the Securities and Exchange Commission. As a result of those factors, the Company's actual results may differ materially from those indicated in or implied by such forward-looking statements.

# # # #

TOM BROWN, INC. AND SUBSIDIARIES

Consolidated Summary Income Statement (Unaudited)

Three Months ended March 31, 2003 and 2002

				Three months ended March 31,
				2003			2002
				(in thousands, except per share amounts)
Revenues:
	Gas, oil and natural gas liquids sales			$	80,480		$	41,518
	Gathering and processing				6,076			5,264
	Marketing and trading, net				713			(582	)
	Drilling				3,077			1,831
	Interest income and other				551			263
		Total revenues		$	90,897		$	48,294
Costs and expenses:
	Gas and oil production			$	8,185		$	8,171
	Taxes on gas and oil production				6,538			3,908
	Gathering and processing costs				2,034			1,521
	Drilling operations				2,934			1,938
	Exploration costs				6,874			3,583
	Impairments of leasehold costs				1,474			1,388
	General and administrative				4,847			4,872
	Depreciation, depletion and amortization				21,417			22,527
	Bad debts				152			108
	Accretion expense				292			—
	Interest expense and other				3,556			1,369
		Total costs and expenses		$	58,303		$	49,385
Income (loss) before income taxes and cumulative effect of change in accounting principles					32,594			(1,091	)
Income tax (provision) benefit:
	Current				(222	)		124
	Deferred				(11,575	)		596
Income (loss) before cumulative effect of change in accounting principles					20,797			(371	)
Cumulative effect of change in accounting principles					(929	)		(18,103	)
Net income (loss)				$	19,868		$	(18,474	)
Weighted average number of common shares outstanding:
	Basic				39,482			39,148
	Diluted				40,442			39,148
Income (loss) per common share before cumulative effect of change in accounting principles:
	Basic			$	0.53		$	(0.01	)
	Diluted			$	0.51		$	(0.01	)
Net income (loss) per common share:
	Basic			$	0.50		$	(0.47	)
	Diluted			$	0.49		$	(0.47	)

TOM BROWN, INC. AND SUBSIDIARIES

Supplemental Financial Information (Unaudited)

Three Months ended March 31, 2003 and 2002

				Three months ended March 31, (in thousands)
				2003			2002
Reconciliation to net cash provided by operating activities:
	Discretionary cash flow(1)			$	62,429		$	26,531
	Exploration costs				(6,874	)		(3,583	)
		Add back only dry hole cost			3,037			73
	Changes in current assets and liabilities, net				(21,678	)		(2,629	)
Net cash provided by operating activities				$	36,914		$	20,392

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(1)

Discretionary cash flow is presented herein because of its wide acceptance as a financial indicator of a company's ability to internally fund exploration and development activities and to service or incur debt. Discretionary cash flow represents net income or loss before depreciation and amortization, exploration costs, leasehold impairments, accretion, deferred taxes, and cumulative effect of changes in accounting principle. Discretionary cash flow should not be considered as an alternative to net cash provided by operating activities, net income (loss) or income (loss) from continuing operations, as defined by generally accepted accounting principles. Discretionary cash flow should also not be considered as an indicator of the Company's financial performance, as an alternative to cash flow, as a measure of liquidity or as being comparable to other similarly titled measures of other companies.

		March 31, 2003			December 31, 2002
		(in thousands)
Balance Sheet Data:
Total assets		$	914,225		$	850,952
Net working capital			6,909			(8,887	)
Total debt			135,241			133,172
Shareholders' equity			581,078			563,618
Net debt/total book capital			18	%		20	%

TOM BROWN, INC. AND SUBSIDIARIES

Supplemental Operational Data (Unaudited)

Three Months ended March 31, 2003 and 2002

				Three months ended March 31,
				2003			2002
Production (net of royalties)
	Natural Gas (Bcf)
		United States			15.3			16.3
		Canada			1.5			1.6
					16.8			17.9
	Oil (MBbls)
		United States			126.5			181.8
		Canada			53.8			53.0
					180.3			234.8
	NGLs (MBbls)
		United States			330.4			303.6
		Canada			48.2			43.6
					378.6			347.2
Average daily production (net of royalties)
	Natural Gas (Mmcf)
		United States			169.9			181.4
		Canada			16.7			17.9
					186.6			199.3
	Oil (Bbls)
		United States			1,406			2,020
		Canada			598			589
					2,004			2,609
	NGLs (Bbls)
		United States			3,671			3,373
		Canada			536			484
					4,207			3,857
Average realized price (including hedging):
	Natural Gas ($/Mcf)
		United States		$	3.97		$	1.82
		Canada			4.74			2.62
		Combined			4.04			1.89
	Oil ($/Bbl)
		United States		$	29.68		$	19.71
		Canada			33.18			18.07
		Combined			30.72			19.33
	NGLs ($/Bbl)
		United States		$	17.41		$	8.10
		Canada			28.28			11.92
		Combined			18.79			8.58

SIGNATURE

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

Date: May 8, 2003		Tom Brown, Inc.
		By:		/s/  DANIEL G. BLANCHARD       Daniel G. Blanchard Executive Vice President and Chief Financial Officer (Principal Financial Officer)
		By:		/s/  RICHARD L.SATRE       Richard L.Satre Controller (Principal Accounting Officer)

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ITEM 12. RESULTS OF OPERATIONS AND FINANCIAL CONDITION.

TOM BROWN, INC. AND SUBSIDIARIES Consolidated Summary Income Statement (Unaudited) Three Months ended March 31, 2003 and 2002
TOM BROWN, INC. AND SUBSIDIARIES Supplemental Financial Information (Unaudited) Three Months ended March 31, 2003 and 2002
TOM BROWN, INC. AND SUBSIDIARIES Supplemental Operational Data (Unaudited) Three Months ended March 31, 2003 and 2002
SIGNATURE