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

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

COMMISSION FILE NUMBER 001-31308

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)

        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

APPLICABLE ONLY TO CORPORATE ISSUERS:

        Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of August 7, 2002.

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

INDEX

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)

See accompanying notes to consolidated financial statements.

TOM BROWN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

See accompanying notes to consolidated financial statements.

TOM BROWN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

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 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 or associated amortization expense recorded on its consolidated statements of operations. Had SFAS No. 142 been effective for the six months ended June 30, 2001, the Company's net income would have increased by $.2 million, or $.01 per share, as the result of the elimination of goodwill amortization.

        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):

        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 six months ended June 30, 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.

Property Sales

        In April 2002, the Company sold its interest in oil and gas properties, located in the Powder River Basin of Wyoming, , for net cash proceeds of $7.1 million. These properties had a net book value of $3.1 million which resulted in a $4.0 million gain on the sale. During the second quarter of 2002, the Company also sold certain oil and gas properties located primarily in Louisiana for $1.7 million. As this represented a partial interest in this proved property, the proceeds were recorded as a reduction to the recorded cost of the oil and gas property.

        During May 2001, the Company sold its interest in oil and gas properties primarily located in Oklahoma, with a net book value of $14.4 million, for net cash proceeds of $24.5 million. The resulting gain of $10.1 million is reflected in the Consolidated Statement of Operations.

        In June 2001, the Company sold certain of the gathering and processing assets originally received in the Wildhorse distribution completed in November 2000. The systems sold were considered non-strategic to the Company's operations and as this divestiture was part of the Wildhorse integration process, the net cash proceeds of $14.0 million were recorded as a reduction to the investment in gathering assets.

(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 June 30, 2002, the Company had borrowings outstanding under the Global Credit Facility totaling $151.8 million or 51% of the borrowing base at an average interest rate of 4.5%. The amount available for borrowing under the Global Credit Facility at June 30, 2002 was $73.2 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 indebtedness to 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 provision for the six months ended June 30, 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 June 30, 2002 and December 31, 2001 were as follows:

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

(5) 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 income associated with these activities is presented on a net basis in the financial statements. The Company's gross trading activities are summarized below.

(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. As of June 30, 2001 the fair value of these hedges increased to result in a derivative asset of $8.2 million with $5.2 million of income (net of the deferred tax liability of $3.0 million) recorded in Other Comprehensive Income.

        The Company also entered into natural gas basis swaps covering essentially the same time period as 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 asset of $3.2 million. A $1.9 million gain was recognized in conjunction with the change in the value of these contracts in the six months ended June 30, 2001. The value of the basis swaps resulted in a remaining derivative asset of $2.2 million at June 30, 2001. Net receipts of $2.9 million were received during the first six months of 2001 on these contracts.

        In April 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. As of June 30, 2002, the fair value of these cash flow hedges increased to result in a derivative asset of $1.4 million with $.9 million of income (net of deferred tax liability of $.5 million) recorded in Other Comprehensive Income. No cash settlements have occurred on these hedges as of June 30, 2002.

        At June 30, 2002, the terms of these costless collar arrangements were as follows:

        The Company also entered into certain financial instruments to lock in the basis differential on 15,000 Mmbtu/day of production during the June through October 2002 contract periods. These contracts effectively fixed 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. After transportation costs, the Company realizes a net margin of $.29/Mmbtu. Under SFAS 133, these basis swaps did not qualify for hedge accounting. Accordingly, these basis swaps result in the recognition of derivative gains and losses currently in earnings. As of June 30, 2002, the Company recognized derivative losses of $1.7 million of which $.3 million was cash settled in June, 2002 and $1.4 million was recorded as a derivative liability based upon the market value of these contracts.

(7) Segment Information

        The Company operates in the following 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 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):

        The following tables reconcile segment information to consolidated totals:

(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 income (loss) for the six months ended June 30, 2002 and 2001 (in thousands):

        During the quarter ended June 30, 2002, the Company recognized a loss of $.6 million on a marketable security previously marked to market through Other Comprehensive Loss. The market decline on this security was determined to be other than temporary in nature.

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

        The following analysis of operations for the three and six months ended June 30, 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 net income for the six months ended June 30, 2002 of $4.4 million or $.11 per share (diluted basis) as compared to net income of $61.7 million or $1.53 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 17% and 19% in the three and six months ended June 30, 2002 and 2001, respectively, revenue from gas, oil and natural gas liquids sales decreased $18.3 million and $83.6 million, or 26% and 47% less than the prior year's comparable periods, due to the declines experienced in natural gas and oil prices in these periods.

        The net loss and income recognized in the six months ended June 30, 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 six months ended June 30, 2001 was similarly impacted by the January 2001 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 June 30, 2002, revenues from gas, oil and natural gas liquids production decreased 26% to $53.4 million, as compared to $71.7 million in 2001. This decrease was the result of (i) a decrease in average gas prices received by the Company from $3.89 per Mcf in 2001 to $2.36 per Mcf in 2002, which decreased revenues $28.7 million, (ii) a decrease in average oil and natural gas liquids prices received from $19.44 to $15.59 per barrel which decreased revenues $2.3 million, (iii) gas sales volumes increased by 20% to 18.7 Bcf which increased revenues by $12.4 million, and (iv) an increase in oil and natural gas liquids sales volumes of 3% to ..6 million barrels, which increased revenues by $.3 million.

        During the six month period ended June 30, 2002, revenues from gas, oil and natural gas liquids production decreased 47% to $94.9 million, as compared to $178.5 million in 2001. This decrease was the result of (i) a decrease in average gas prices received by the Company from $5.17 per Mcf in 2001 to $2.13 per Mcf in 2002, which decreased revenues $111.4 million, (ii) a decrease in average oil and natural gas liquids prices received from $20.93 to $14.27 per barrel which decreased revenues $7.9 million, (iii) gas sales volumes increased by 21% to 36.6 Bcf which increased revenues by $32.8 million, and (iv) an increase in oil and natural gas liquids sales volumes of 12% to 1.2 million barrels, which increased revenues by $2.9 million.

        Revenues in 2001 were also impacted by cash gains realized from hedging activities. The natural gas collar transactions considered effective hedges and settled in the first six months of 2001, resulted in cash gains of $2.2 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:

(1)

Includes the effects of hedging.

        Gathering and processing revenue decreased 35% to $4.7 million, and 51% to $10 million as compared to $7.2 million and $14.6 million for the three and six months ended June 30, 2002 and 2001, respectively. A number of non-strategic gathering and processing assets were sold throughout 2001. Gathering and processing revenue was impacted in 2002 as a result of these dispositions.

        Net marketing and trading income increased in the second quarter of 2002 to $1.3 million after the recognition of a $.6 million loss in the first quarter of 2002. This improvement was principally related to the realization of increased profits in the second quarter on gas transported by the Company into the Mid Continent region to take advantage of higher gas prices in this market. The Company had previously entered into certain financial instruments to lock the basis differential for the June through October contract periods and take advantage of higher gas prices in the Mid Continent market. However, as these financial instruments were considered trading derivatives under SFAS No. 133, the cash settlement of $.3 million in June 2002 and the marked to market valuation loss of $1.3 million were recognized as derivative losses during the second quarter. The net impact of these financial instruments for the quarter ended June 30, 2002 was that the Company was successful in locking a $.29 Mmbtu margin ($.78/Mmbtu before transportation costs) on gas moved into the Mid Continent region. Thus, the cash profits realized on the physical sales included in marketing and trading income were partially offset by the $.3 million cash settlement on the trading derivatives.

        Drilling revenue associated with the Company's wholly-owned subsidiary, Sauer Drilling Company (Sauer) decreased 26% in the second quarter of 2002 or $1 million, and decreased 30%, or $2.0 million for the six months ended June 30, 2002, as compared to the same periods in 2001. 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. For the three and six months ended June 30, 2002, Sauer obtained a 71% and 65% rig utilization rate on its eight operating rigs, respectively. For the same periods in 2001, rig utilization exceeded 90%.

        The Company recognized a gain of $4.0 million in the second quarter of 2002 on the sale of its oil and gas properties located in the Powder River Basin of Wyoming. In May of 2001, oil and gas properties located primarily in Oklahoma were sold at a gain of $10.1 million. These sales were part of the Company's ongoing efforts to dispose of properties not considered to be located within the main focus areas.

        During the quarter ended June 30, 2002, the Company recognized a loss of $.6 million on a marketable security previously marked to market through Other Comprehensive Loss. The market decline on this security was determined to be other than temporary in nature.

Costs and Expenses

        Expenses related to gas and oil production for the three and six months ended June 30, 2002 remained relatively unchanged from the expenses incurred during the same periods in 2001. Despite an increase in production of 19% in 2002 as measured based on gas equivalents, the Company was able to effectively reduce its per unit operating expenses due to operational efficiencies. For the six months ended June 30, 2001, the operating expense per Mcfe was $.43 per unit which reduced to $.37 per unit in the same period 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 are now beginning to contribute to the production increase realized in the first six months of 2002.

        Taxes on gas and oil production decreased by 23% or ($1.5 million) and 46% or ($7.6 million) for the three and six months ended June 30, 2002 due primarily to the decrease in gas and oil prices from the same periods in 2001.

        Depreciation, depletion and amortization increased $5.4 million and $11.3 million for the three and six months ended June 30, 2002 as compared to the same periods in 2001. The production increase of 17% and 19% on an Mcfe basis, for the same periods, contributed approximately $3.2 million and $6.8 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 for the three and six months ended June 30, 2002, as compared to the same periods in 2001, by $1.2 million and $5.9 million, respectively, 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 2002, as the cost to purchase the system gas lost in the transmission process declined.

        Expenses associated with the Company's exploration activities were $7.6 million and $11.2 million for the three and six months ended June 30, 2002, as compared to $7.7 million and $14.1 million for the same periods in 2001. The Company's decreased exploration efforts in the first six months of 2002 contributed to a decline in dryhole costs. Capital expenditures of $91.3 million were incurred in the first six months of 2002. During the first six months of 2001 capital expenditures were $202.5 million, which included $95 million associated with the Stellarton acquisition.

        General and administrative expenses have decreased in the three and six months ended June 30, 2002, in comparison to the same periods in 2001. On an Mcfe basis, general and administrative expenses were $.20 and $.25 for the three months ended June 30, 2002 and 2001, respectively, and $.21 and $.38 for the six months ended June 30, 2002 and 2001, respectively. Included in the expenses for the first quarter of 2001 was a $5.3 million 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 provision of $1.1 million associated with the $5.5 million income before the cumulative effect in change of accounting principle for the six months ended June 30, 2002. This tax provision includes the impact of approximately $.8 million in state tax credits associated with drilling incentives in Colorado and Utah that the Company was able to obtain which reduced the effective tax rate to 20%. 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 six months ended June 30, 2001, a tax provision of $36.4 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 attempt to 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 six months ended June 30, 2002 and 2001 are as follows:

        The Company anticipates capital and exploration expenditures between $145 to $155 million in 2002, with $132 to $141 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 was allowed under the terms of the agreement to mobilize the rig and commence the two-year drilling obligation. On May 29, 2002, the Company commenced drilling operations with this rig which was the start of the two-year obligation. Under the terms of this arrangement, the Company is obligated to ultimately pay a daywork rate of $20,100/day during drilling operations and $16,700/day for rig moves. The Company paid a special standby fee of $.5 million to delay the commencement of the contract to May 29, 2002 which was expensed.

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 June 30, 2002, the Company had borrowings outstanding under the Global Credit Facility totaling $151.8 million or 51% of the borrowing base at an average interest rate of 4.5%. The amount available for borrowing under the Global Credit Facility at June 30, 2002 was $73.2 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 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 indebtedness to 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 six months of 2002 and at June 30, 2002.

Markets and Prices

        The Company's revenues and associated cash flows are significantly impacted by changes in gas and oil prices. The Company's gas and oil production is generally market sensitive as the majority of the Company's gas and oil production has not been presold at contractually specified prices. During the three and six months ended June 30, 2002, the average prices received for gas and oil by the Company were $2.36 and $2.13 per Mcf and $23.70 and $21.45 per barrel, respectively, as compared to $3.89 and $5.17 per Mcf and $24.48 and $25.46 per barrel in 2001.

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 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 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.

        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.

        Subsequent to June 30, 2002, the Company entered into several natural gas swap transactions and corresponding basis swap transactions that together fix the price the Company will receive for a portion of gas sold in certain of the regions where the Company physically delivers its gas. These transactions will be accounted for as hedges and are summarized below:

        Including the above transactions, the Company has natural gas hedges, in the form of costless collars and swaps (including related basis swaps) as follows:

        The above financial instruments pertain to the Company's direct sales of its natural gas production. The Company has also entered into certain financial instruments associated with its marketing and trading operations. These transactions were entered into to lock in the basis differential on 15,000 Mmbtu/day of production during the June through October 2002 contract periods for gas transported into the Mid Continent market. The contracts effectively fixed a price differential 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. After transportation costs, the Company realizes a net margin of $.29/Mmbtu. Under SFAS 133, these basis swaps did not qualify for hedge accounting. Accordingly, these basis swaps result in the recognition of derivative gains and losses currently in earnings.

Interest Rate Risk

        At March 31, 2002, the Company had $151.8 million outstanding under the Global Credit Facility at an average interest rate of 4.5%. 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 $.7 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

        None.

ITEM 5. Other Information

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

(a)

(b)

Reports on Form 8-K

        Form 8-K Item 7. 2002 Financial Model Estimates filed on August 6, 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.