UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

 

 

 

COMMISSION FILE NUMBER 001-31308

 

 

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

 

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

 

APPLICABLE ONLY TO CORPORATE ISSUERS:

 

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of August 7, 2003.

 

 

 

TOM BROWN, INC. AND SUBSIDIARIES

QUARTERLY REPORT FORM 10-Q

 

INDEX

 

Part I.	Item 1. Financial Information (Unaudited)
	Consolidated Balance Sheets, June 30, 2003 and December 31, 2002
	Consolidated Statements of Operations, Three and Six Months Ended June 30, 2003 and 2002
	Consolidated Statements of Cash Flows, Six Months Ended June 30, 2003 and 2002
	Notes to Consolidated Financial Statements
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 3. Quantitative and Qualitative Disclosure about Market Risk
Part II.	Other Information
	Item 4. Controls and Procedures
	Item 6. Exhibits and Reports on Form 8-K
	Signatures

 

2

 

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

 

3

 

TOM BROWN INC. AND SUBSIDIARIES

 

CONSOLIDATED BALANCE SHEETS

 

(In thousands, except per share data)

 

		June 30, 2003			December 31, 2002
		(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	24,108		$	13,555
Accounts receivable, net of allowance for doubtful accounts		101,275			47,414
Inventories		1,657			1,808
Other		4,793			3,988
Total current assets		131.833			66,765
PROPERTY AND EQUIPMENT, AT COST:
Gas and oil properties, successful efforts method of accounting		1,455,649			959,807
Gas gathering, processing and other plant		108,371			101,054
Other		40,323			35,930
Total property and equipment		1,604,343			1,096,791
Less: Accumulated depreciation, depletion and amortization		366,191			320,306
Net property and equipment		1,238,152			776,485
OTHER ASSETS:
Goodwill		84,484			—
Other assets		20,586			7,702
Total other assets		105,070			7,702
		$	1,475,055		$	850,952
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable		$	82,587		$	42,773
Accrued expenses		28,434			21,993
Fair value of derivative instruments		14,615			10,886
Total current liabilities		125,636			75,652
BANK DEBT		543,652			133,172
DEFERRED INCOME TAXES		171,943			73,967
OTHER NON-CURRENT LIABILITIES		27,352			4,543
STOCKHOLDERS’ EQUITY:
Convertible preferred stock, $.10 par value Authorized 2,500,000 shares; none issued		—			—
Common Stock, $.10 par value Authorized 55,000,000 shares; Outstanding 39,537,759 and 39,261,191 shares, respectively		3,954			3,926
Additional paid-in capital		542,944			537,449
Retained earnings		70,904			29,678
Deferred compensation		(2,269		)	—
Accumulated other comprehensive loss		(9,061		)	(7,435		)
Total stockholders’ equity		606,472			563,618
		$	1,475,055		$	850,952

 

See accompanying notes to consolidated financial statements.

 

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TOM BROWN, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF OPERATIONS

 

(In thousands, except per share amounts)

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2003			2002			2003			2002
		(Unaudited)						(Unaudited)
REVENUES:
Gas, oil and natural gas liquids sales		$	78,480		$	53,412		$	158,960		$	94,930
Gathering and processing		4,792			4,725			10,868			9,989
Marketing and trading		8,794			16,813			22,648			36,032
Drilling		3,878			2,750			6,955			4,581
Gain on sale of property		—			4,004			—			4,004
Unrealized gains (losses) on derivatives		1,913			(1,341		)	1,913			(1,341		)
Realized losses on derivatives		—			(312		)	—			(312		)
Loss on marketable security		—			(600		)	—			(600		)
Interest income and other		76			63			627			326
Total revenues		97,933			79,514			201,971			147,609
COSTS AND EXPENSES:
Gas and oil production		8,505			8,148			16,690			16,319
Taxes on gas and oil production		7,085			4,892			13,623			8,800
Gathering and processing costs		2,037			1,703			4,071			3,224
Trading		8,449			15,539			21,590			35,340
Drilling operations		3,097			3,001			6,031			4,939
Exploration costs		3,805			7,601			10,679			11,184
Impairments of leasehold costs		1,489			1,393			2,963			2,781
General and administrative		5,803			4,493			10,650			9,365
Depreciation, depletion and amortization		23,153			23,496			44,570			46,023
Accretion of asset retirement obligation		296			—			588			—
Bad debts		100			108			252			216
Interest expense and other		2,262			2,536			5,818			3,905
Total costs and expenses		66,081			72,910			137,525			142,096
Income before income taxes and cumulative effect of change in accounting principles		31,852			6,604			64,446			5,513
Income tax benefit (provision):
Current		777			(211		)	555			(87		)
Deferred		(11,273		)	(1,638		)	(22,848		)	(1,042		)
Income before cumulative effect of change in accounting principles		21,356			4,755			42,153			4,384
Cumulative effect of change in accounting principles		—			—			(929		)	(18,103		)
Net income (loss) attributable to common stock		$	21,356		$	4,755		$	41,224		$	(13,719	)
Weighted average number of common shares outstanding:
Basic		39,473			39,188			39,478			39,168
Diluted		40,532			40,530			40,487			40,425
Earnings per common share—Basic:
Income before cumulative effect of change in accounting principles		$	.54		$	.12		$	1.07		$	.11
Cumulative effect of change in accounting principles		—			—			(.03		)	(.46		)
Net income (loss) attributable to common stock		$	.54		$	.12		$	1.04		$	(.35	)
Earnings per common share—Diluted:
Income before cumulative effect of change in accounting principles		$	.53		$	.12		$	1.04		$	.11
Cumulative effect of change in accounting principles		—			—			(.02		)	(.45		)
Net income (loss) attributable to common stock		$	.53		$	.12		$	1.02		$	(.34	)

 

See accompanying notes to consolidated financial statements.

 

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TOM BROWN, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

		Six Months Ended June 30,
		2003			2002
		(In thousands – unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$	41,224		$	(13,719	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		44,570			46,023
Cumulative effect of change in accounting principles		929			18,103
Change in fair value of derivatives		(1,913		)	1,341
Loss on marketable security		—			600
Gain on sale of property		—			(4,004		)
Accretion of asset retirement obligation		588			—
Stock compensation		433			—
Dry hole costs		4,268			2,842
Impairments of leasehold costs		2,963			2,781
Deferred tax provision		22,848			1,042
Changes in operating assets and liabilities, net of the effects from the purchase of Matador:
(Increase) decrease in accounts receivable		(31,593		)	5,476
Decrease in inventories		252			187
Increase in other current assets		(311		)	(1,292		)
Increase in accounts payable and accrued expenses		1,889			284
Increase in other assets, net		(659		)	(2,183		)
Net cash provided by operating activities		85,488			57,481
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sales of assets		707			8,761
Capital expenditures		(90,833		)	(82,991		)
Cash paid for Matador stock and options		(267,473		)	—
Transaction costs for the Matador acquisition		(4,085		)	—
Payments on non-compete agreements		(2,991		)	—
Cash acquired in Matador acquisition		3,596			—
Changes in accounts payable and accrued expenses for capital expenditures		10,589			(6,899		)
Net cash used in investing activities		(350,490		)	(81,129		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings of long-term bank debt		438,000			26,177
Repayments of long-term bank debt		(158,292		)	—
Deferred loan fees		(7,052		)	—
Proceeds from exercise of stock options		2,253			1,160
Net cash provided by financing activities		274,909			27,337
Effect of exchange rate changes on cash		646			26
NET CHANGE IN CASH AND CASH EQUIVALENTS		10,553			3,715
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		13,555			15,196
CASH AND CASH EQUIVALENTS AT END OF PERIOD		$	24,108		$	18,911
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest		$	3,075		$	1,693
Income taxes		345			1,030
Refund received of income tax deposit		—			6,000

 

See accompanying notes to consolidated financial statements.

 

6

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

 

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

 

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

 

 

The reclassification of these amounts would not effect the method in which such costs are amortized or the manner in which the Company assesses impairment of capitalized costs.  As a result, net income would not be affected by the reclassification.

 

In July 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially

 

7

 

recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for the recorded amount or incurs a gain or loss upon settlement to the extent the actual costs differ from the recorded liability.  SFAS No. 143 was effective for fiscal years beginning after June 15, 2002. The Company adopted SFAS No. 143 on January 1, 2003, and recorded a discounted liability of $14.5 million for the future retirement obligation, an increase to property and equipment of $13.0 million and a charge of $.9 million (net of a deferred tax benefit of $.6 million) as the cumulative effect of change in accounting principle.  The majority of the asset retirement obligation recognized related to the projected cost to plug and abandon gas and oil wells.  An asset retirement obligation was also recorded for processing plants, compressors and other field facilities.

 

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

 

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

 

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

 

In October 2002, Emerging Issues Task Force reached a consensus on EITF 02-03.  The consensus rescinded EITF 98-10 and as a consequence the Company no longer reports the revenues from its trading activities on a net basis, unless the contracts entered into are

 

8

 

considered derivatives.  The prior period’s financial statements have been reclassified to report the amount of trading revenues from third parties on a gross basis.  The margins earned by the Company’s marketing subsidiary on the sale of the Company’s production are reported as a component of marketing and trading revenues.

 

(2)           Acquisitions

 

Acquisition of Matador

 

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

 

Under the terms of the definitive merger agreement, the Matador shareholders received a net price of $17.53 per common share and all option holders received $17.53 per option share less the exercise price of the options.  Tom Brown also assumed approximately $121 million in net debt at closing, for an aggregate purchase price of $388 million.  Transaction costs of approximately $6.0 million were incurred by the Company and Matador for investment banking, legal, accounting and other direct merger-related costs.  In addition, $7.7 million was incurred for payments made to officers and employees of Matador pursuant to a change in control arrangement previously entered into by Matador and $1.3 million was incurred for payments made to Matador employees under the terms of a stock appreciation plan, which provided for payments in the event of a change in control of Matador.

 

The allocation of the purchase price to the Matador assets resulted in a difference between the book and tax basis of the Matador assets of approximately $214 million.  Based upon an effective tax rate of 35 percent, deferred income taxes of $71.8 million were recorded.  The deferred taxes recorded represent the majority of the $84.5 million of goodwill recorded in conjunction with the acquisition. 

 

The other non-current liabilities of Matador that were assumed principally represent the asset retirement obligation accounted for under SFAS No. 143.  Matador adopted SFAS No. 143 effective January 1, 2003 by recording a cumulative effect adjustment to recognize transition amounts for asset retirement obligations.  The asset retirement obligation related to the Matador assets at June 30, 2003 was $4.8 million. 

 

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

 

 

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

9

 

Pro Forma Results of Operations (Unaudited)

 

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

 

		Six Months Ended June 30,
		2003			2002
		(In thousands, except per share data)
Revenues		$	260,804		$	173,967
Net income (loss)		$	49,593		$	(20,329	)
Basic net income (loss) per share		$	1.26		$	(.52	)
Diluted net income (loss) per share		$	1.22		$	(.50	)

 

Acquisition of Rocky Mountain Assets

 

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

 

(3)  Stock Based Compensation

 

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

 

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

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2003			2002			2003			2002
		(In thousands, except per share amounts)
Net income (loss) as reported		$	21,356		$	4,755		$	41,224		$	(13,719	)
Deduct:  Stock-based employee compensation expense determined under fair value based method for all awards (net of tax)		(1,735		)	(1,272		)	(2,702		)	(2,872		)
Add:Compensation cost included in reported net income (net of tax)		273			—			273			—
Pro forma		$	19,894		$	3,483		$	38,795		$	(16,591	)
Basic net income (loss) per common share:
As reported		$	.54		$	.12		$	1.04		$	(.35	)
Pro forma		$	.51		$	.09		$	.98		$	(.42	)
Diluted net income (loss) per common share:
As reported		$	.53		$	.12		$	1.02		$	(.34	)
Pro forma		$	.50		$	.09		$	.96		$	(.41	)

 

The weighted average fair value of options granted during the six months ended June 30, 2003 and 2002 was $24.56 and $24.80, respectively.  The fair value of each option is estimated as of the date of grant using the Black-Scholes options-pricing model with the following weighted-average assumptions used for grants in the 2003 and 2002 periods, respectively:  (i) risk-free interest rates of 3.03 and 4.52 percent, (ii) expected lives of 7.0 and 7.0 years, (iii) expected volatility of 125.8 and 126.7 percent, and (iv) no dividend yield.

 

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(4)           Debt

 

Credit Facility

 

On March 20, 2001, the Company entered into a $225 million credit facility (the “Global Credit Facility”). The Global Credit Facility was comprised of: a $75 million line of credit in the U.S. and a $55 million line of credit in Canada which both had maturity dates of March 20, 2004, and a $95 million five-year term loan in Canada which had a maturity date of March 21, 2006. The borrowing base established to support the $225 million line of credit was initially set at $300 million, which was re-approved as of May 1, 2002. In conjunction with Matador acquisition in June 2003, the Company entered into a “New Global Credit Facility” with an increased line of credit and initial borrowing base of $425 million.  The terms of the New Global Credit Facility provides for:  a $290 million line of credit in the U.S. and a $25 million line of credit in Canada which both mature on June 27, 2007, and a $110 million five-year term loan in Canada which matures on March 21, 2006.  The terms of the New Global Credit Facility allow the lenders one scheduled redetermination of the borrowing base each December.  In addition, the lenders may elect to require one unscheduled redetermination in the event the borrowing base utilization exceeds 50% of the borrowing base at any time for a period of 15 consecutive business days. At June 30, 2003, the Company had borrowings outstanding under the New Global Credit Facility totaling $387.6 million or 92% of the borrowing base at an average interest rate of 2.8%. The amount available for borrowing under the New Global Credit Facility at June 30, 2003 was $37.4 million.

 

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

 

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

 

Senior Subordinated Credit Facility

 

In connection with the consummation of the Matador Petroleum acquisition, the Company entered into an unsecured senior subordinated credit facility (the “Subordinated Facility”) with a group of lender banks that also participate in the Company’s New Global Credit Facility.  The $155 million loan matures in seven years.  The initial interest rate on the loan was set at 8.5%, but provides for quarterly increases of 0.5%.  The facility provides for an exchange to transferable notes after one year.  Interest on the Subordinated Facility is based on LIBOR plus a margin, subject to a minimum rate of 8.5% and maximum amount of 14% and currently bears interest at 8.5% per annum.

 

The Subordinated Facility contains certain financial covenants that could limit the Company from incurring additional indebtedness beyond the New Global Credit Facility.  Additionally, the facility restricts certain types of payments, including payment of dividends or repurchase or redemption of the Company’s common stock which are prohibited for the first year.  After the first year, or after the initial maturity date, the Company may make such restricted payments if it is not in default and it passes the additional indebtedness test under the facility.  The Company was in compliance with all covenants at June 30, 2003.

 

(5)           Income Taxes

 

The Company has not paid Federal income taxes due to the availability of net operating loss carryforwards and the deductibility of intangible drilling and development costs. The Company has historically been required to pay Alternative Minimum Tax (“AMT”) on its U.S. activity, but due to a change in U.S. tax policy (The Job Creation and Worker Assistance Act of 2002), an AMT liability was not created in 2002.

 

11

 

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

 

		June 30, 2003									December 31, 2002
		United States			Canada			Total			Total
Deferred tax assets:
Net operating loss carryforward		$	4,884		$	1,841		$	6,725		$	12,122
Net operating loss carryforward—Matador		3,127			—			3,127			—
Percentage depletion carryforward		2,520			—			2,520			2,520
Alternative minimum tax credit carryforward		5,085			—			5,085			4,831
Derivative contracts to be settled in a future period		4,777			—			4,777			3,975
State income tax credits		741			—			741			698
Other		555			—			555			333
Total gross deferred tax assets		21,689			1,841				23,530			24,479
Deferred tax liabilities:
Property and equipment		(76,987		)	(43,574		)	(120,561		)	(98,243		)
Property and equipment—Matador Acquisition		(74,912		)	—			(74,912		)	—
Other		—			—			—			(203		)
Total gross deferred tax liabilities		(151,899		)	(43,574		)	(195,473		)	(98,446		)
Net deferred tax liabilities		$	(130,210	)	$	(41,733	)	$	(171,943	)	$	(73,967	)

 

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

 

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

 

		Six Months Ended June 30,
		2003			2002
Current income tax:
Federal AMT (provision) benefit		$	(254	)	$	350
Canadian benefit (provision)		1,209			(153		)
State income and franchise taxes		(400		)	(284		)
Total current tax benefit (provision)		555			(87		)
Deferred income tax:
Federal and State provision		(20,589		)	(1,801		)
Canadian (provision) benefit		(2,259		)	759
Total deferred tax (provision) benefit		(22,848		)	(1,042		)
Total tax provision		$	(22,293	)	$	(1,129	)

 

12

 

(6)           Marketing and Trading Activities

 

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

 

(7)           Derivative Instruments and Hedging Activities

 

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

 

At June 30, 2003, the Company had a current derivative liability of $14.6 million, a deferred tax asset of $5.4 million and accumulated other comprehensive loss of approximately $9.0 million.  As of June 30, 2002, the Company had a current derivative asset of $1.4 million, a deferred tax liability of $.5 million and accumulated other comprehensive income of $.9 million.

 

In April and May 2002, the Company entered into several natural gas costless collars (put and call options) that were based on separate regional price indexes where the Company physically delivers its natural gas.  The collars are designated as hedges of production from May 2002 through December 2003.  In July and August 2002, the Company entered into several natural gas price swaps and corresponding basis swap transactions that together fixed the price the Company will receive for a portion of its natural gas production.  These swaps were designed as hedges of production from September 2002 through October 2003 in certain of the regions where the Company physically delivers its gas.  A derivative loss of $0.4 million was recognized on the basis portion of these transactions prior to designating the basis contracts as hedges when the corresponding natural gas price swap contracts were executed.  In December 2002, the Company entered into additional costless collar arrangements (put and call options) that were based on several of the regional price indexes where the Company physically delivers its natural gas.  The collars are designated as hedges of production from January 2003 through October 2003.

 

In anticipation of the Matador acquisition, the Company entered into several new natural gas costless collars (put and call options) in May 2003 that were based on separate regional price indexes.  These contracts were based upon the areas that Matador physically delivers its natural gas and related to production from June 2003 to December 2004.  For the quarter ended June 30, 2003, the change in fair value of these derivative contracts resulted in income of $1.9 million being reflected in the Consolidated Statements of Operations.  After the Matador acquisition closed on June 27, 2003, these contracts were designated as hedges of future production, and future cash settlements will be offset against the realized prices for this natural gas production.

 

As a result of the above transactions, the Company has natural gas hedges, in the form of costless collars and swaps (including related basis swaps) as follows as of June 30, 2003:

 

		Natural Gas Collars					Natural Gas Swaps
		Mmbtu/d		Weighted Average Floor/Ceiling			Mmbtu/d		Weighted Average Swap Price
Period
Third Quarter 2003		80,000		$	3.96/6.88		55,800		$	3.04
Fourth Quarter 2003		58,500		$	4.12/7.67		18,500		$	3.04
First Quarter 2004		32,500		$	4.78/10.08		—		—
Second Quarter 2004		27,500		$	4.08/6.30		—		—
Third Quarter 2004		27,500		$	4.08/6.30		—		—
Fourth Quarter 2004		25,800		$	4.07/6.56		—		—

 

13

 

(8)           Segment Information

 

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

 

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

 

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

 

		Six Months Ended June 30, 2003
		Gas & Oil Exploration & Development (United States)			Gas & Oil Exploration & Development (Canada)			Gas & Oil Exploration & Development (Total)			Marketing, Gathering & Processing			Drilling			Total Segments
Revenues from external purchasers		$	74,095		$	21,249		$	95,344		$	137,550		$	6,955		$	239,849
Intersegment revenues		63,616			—			63,616			5,136			3,720			72,472
Total revenues		137,711			21,249			158,960			142,686			10,675			312,321
Marketing and trading expenses offset against related revenues for net presentation		—			—			—			(40,417		)				(40,417		)
Intersegment eliminations		—			—			—			(68,753		)	(3,720		)	(72,473		)
Total segment revenue		137,711			21,249			158,960			33,516			6,955			199,431
Unrealized gains on derivatives		1,913			—			1,913			—			—			1,913
Interest income and other		47			3			50			443			134			627
Total consolidated revenues		$	139,671		$	21,252		$	160,923		$	33,959		$	7,089		$	201,971
Profit
Total reportable segment profit		$	54,817		$	8,080		$	62,897		$	7,705		$	570		$	71,172
Interest expense and other		(3,297		)	(2,526		)	(5,823		)	5			—			(5,818		)
Eliminations		—			—			—			—			(908		)	(908		)
Income (loss) before income taxes and cumulative effect of change in accounting principle		$	51,520		$	5,554		$	57,074		$	7,710		$	(338	)	$	64,446

 

14

 

		Six Months Ended June 30, 2002
		Gas & Oil Exploration & Development (United States)			Gas & Oil Exploration & Development (Canada)			Gas & Oil Exploration & Development (Total)			Marketing Gathering & Processing			Drilling			Total Segments
Revenues from external purchasers		$	46,324		$	12,727		$	59,051		$	97,976		$	4,581		$	161,608
Intersegment revenues		35,879			—			35,879			5,032			4,719			45,630
Total revenues		82,203			12,727			94,930			103,008			9,300			207,238
Marketing and trading expenses offset against related revenues for net presentation		—			—			—			(16,076		)	—			(16,076		)
Intersegment eliminations		—			—			—			(40,911		)	(4,719		)	(45,630		)
Total segment revenue		82,203			12,727			94,930			46,021			4,581			145,532
Gain on sale of property		4,004			—			4004			—			—			4,004
Realized and unrealized losses on derivatives		—			—			—			(1,653		)	—			(1,653		)
Loss on marketable security		(600		)	—			(600		)	—			—			(600		)
Interest income and other		288			—			288			28			10			326
Total consolidated revenues		$	85,895		$	12,727		$	98,622		$	44,396		4,591			$	147,609
Profit
Total reportable segment profit		$	3,367		$	651		$	4,018		$	3,721		$	(7	)	$	7,732
Interest expense and other		(1,438		)	(2,204		)	(3,642		)	(153		)	(326		)	(4,121		)
Gain on sale of property		4,004			—			4004			—			—			4,004
Loss on marketable security		(600		)	—			(600		)	—			—			(600		)
Eliminations		—			—			—			—			(1,502		)	(1,502		)
Income (loss) before income taxes and cumulative effect of change in accounting principle		$	5,333		$	(1,553	)	$	3,780		$	3,568		$	(1,835	)	$	5,513

 

(9)           Comprehensive Loss

 

Comprehensive loss includes certain items recorded directly to stockholders’ equity and classified as Accumulated Other Comprehensive Loss.  The following table illustrates the change in comprehensive loss for the six months ended June 30, 2003 and 2002:

 

		Six Months Ended June 30,
		2003			2002
Accumulated Other Comprehensive Loss – beginning of period		$	(7,435	)	$	(1,330	)
Translation gain		897			109
Changes in fair value of outstanding hedging positions		(24,202		)	858
Reclassification adjustment for settled contracts		21,682			—
Unrealized loss on marketable security		(3		)	(60		)
Reclassification adjustment for realized loss on marketable security		—			600
Accumulated Other Comprehensive (Loss) Income – end of period		$	(9,061	)	$	177

 

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

 

Effective January 1, 2003, the Company adopted SFAS 143, “Accounting for Asset Retirement Obligations.”  SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made.  The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset.  Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the asset’s useful life.  The adoption of SFAS 143 resulted in an increase of total liabilities as retirement obligations were required to be recognized, the recorded cost of assets increased to include the retirement costs added to the carrying amount of the asset and operating expenses increased subsequent to January 1, 2003 due to the accretion of the retirement obligation.  Depletion and depreciation recognized in 2003 and subsequent periods

 

15

 

will decrease since the salvage values assigned to these assets (now excluded from depreciation and depletion) exceeded the asset retirement costs recorded.  The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of gas and oil wells.  Asset retirement obligations were also recorded for processing plants and compressors.  The Company adopted SFAS No. 143 on January 1, 2003, and recorded a discounted liability of $14.5 million for the future retirement obligation, an increase to property and equipment of $13.0 million and a charge of $.9 million (net of a deferred tax benefit of $.6 million) as the cumulative effect of change in accounting principle.  There was no impact on the Company’s cash flows as a result of adopting SFAS 143.  Subsequent to the adoption of SFAS 143, additional asset retirement liabilities of $.4 million were recognized on new gas and oil properties and $4.8 million in conjunction with the Matador acquisition.  Accretion expense of $.6 million was recognized in the six months ended June 30, 2003.  The settlement of retirement liabilities and revisions of previous estimates relating to the asset retirement obligations were not significant during the period.

 

The following unaudited pro forma information has been prepared to give effect to the adoption of SFAS 143 as if it had been adopted on January 1, 2000.

 

		Six Months Ended			Year Ended
		June 30, 2002			December 31, 2002			December 31, 2001			December 31, 2000
		(In thousands, except per share amounts)
Net (loss) income
As reported		$	(13,719	)	$	(8,177	)	$	69,503		$	65,703
Accretion of retirement obligation (net of tax)		(338		)	(675		)	(615		)	(429		)
Reduction of depreciation and depletion (net of tax)		224			447			434			281
Pro forma		$	(13,833	)	$	(8,405	)	$	69,322		$	65,555
Basic net income (loss) per common share:
As reported		$	(.35	)	$	(.21	)	$	1.78		$	1.79
Pro forma		$	(.35	)	$	(.21	)	$	1.78		$	1.79
Diluted net income (loss) per common share:
As reported		$	(.34	)	$	(.20	)	$	1.73		$	1.76
Pro forma		$	(.34	)	$	(.20	)	$	1.72		$	1.75

 

(11)         Commitments and Contingencies

 

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

 

The Company is a party to an action brought in Sweetwater County, Wyoming by three overriding royalty interest owners seeking certification as a class of all non-governmental entities which are paid royalties or overriding royalties by the Company in Wyoming. This action is one of more than a dozen virtually identical class action lawsuits filed in various Wyoming courts against producers and operators in Wyoming. The complaint alleges that the Company violated the Wyoming Royalty Payment Act (the “Act”) by improperly deducting gas transportation costs in calculating royalties and overriding royalties on Wyoming production and by failing to properly itemize all deductions taken on its payee reports.  The complaint does not allege specific money damages.  The issue in the case is whether transportation of natural gas off the lease to market is deductible transportation or nondeductible gathering within the meaning of the Act.  In January 2003, the Wyoming Supreme Court agreed to answer two certified questions in a separate lawsuit which are (1) what is meant by the term “gathering” as that term is employed in the Act in defining nondeductible “costs of production,” and (2) when do the causes of action for recovery of the reporting penalty and for improper deductions under the Act accrue.  Because of the preliminary nature of these proceedings, it is not possible to fully determine the ultimate loss exposure or probable outcome of this litigation.

 

16

 

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

 

Forward-Looking Statements and Risks

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way.  The accuracy of any reserve estimate depends on the quality of available data and the interpretation of that data by geological engineers.  In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously.  If significant, these revisions would change the schedule of any further production and development drilling.  Accordingly, reserve estimates are generally different from the quantities of natural gas and oil that are ultimately recovered.

 

Overview

 

The following analysis of operations for the three and six months ended June 30, 2003 and 2002 should be read in conjunction with the Consolidated Financial Statements and associated footnotes included in this Quarterly Report on Form 10-Q, and the Consolidated Financial Statements and associated footnotes contained in the December 31, 2002 Annual Report to Stockholders.

 

Excluding the cumulative effect of changes in accounting principles, the Company reported net income for the three months and six months ended June 30, 2003 of $21.4 million and $42.2 million or $.53 and $1.04 per share (diluted basis) as compared to net income of $4.8 million and $4.4 million or $.12 and $.11 per share (diluted basis) for the same periods in 2002.

 

The Company’s natural gas, natural gas liquids and oil production decreased 9% and 7% in the three and six months ended June 30, 2003 as compared to the same periods in 2002.  However, revenue from gas, oil and natural gas liquids sales increased $25.1 million and $64.0 million or 47% and 67% compared to the prior year’s comparable periods, due to the increases experienced in natural gas and oil prices in 2003. This increase in gas, oil and natural gas liquids revenues resulted in corresponding increases in taxes on gas and oil production and deferred income tax expense.  After these expenses, the impact of the increased natural gas and oil prices in 2003 directly correlates with the increased earnings reported in these periods.

 

17

 

The net income and loss recognized in the six months ended June 30, 2003 and 2002 were both impacted by the adoption of new accounting principles during these periods.  On January 1, 2003, the Company adopted the new accounting standard SFAS No. 143 “Accounting for Asset Retirement Obligations” (SFAS No. 143).  SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation.  As a result of adopting SFAS 143, the Company recorded a non-cash charge of $.9 million (net of a deferred tax benefit of $.6 million) as the cumulative effect of the change in accounting principle.  On January 1, 2002, the Company adopted the accounting standard SFAS No. 142 “Goodwill and Other Intangible Assets” (SFAS No. 142). The Company conducted a fair value based test effective January 1, 2002 to evaluate the goodwill originally recorded in conjunction with the January 2001 Stellarton Energy Corporation acquisition.  The fair value of the reporting unit was determined with reference to the estimated discounted future net revenues of the underlying gas and oil reserves as of the date of the test and other financial considerations including going-concern value. This test resulted in the Company recording a non-cash charge of $18.1 million in the quarter ended March 31, 2002.

 

On June 27, 2003, the Company completed the acquisition of Matador Petroleum Corporation.  As the closing date of this transaction was close to the end of the reporting period, the Company will include the operating results of this entity from June 30, 2003 forward.

 

 Results of Operations

 

Revenues

 

During the three month period ended June 30, 2003, revenues from gas, oil and natural gas liquids production increased 47% to $78.5 million, as compared to $53.4 million in 2002.  This increase was primarily the result of (i) an increase in average gas prices received by the Company from $2.36 per Mcf in 2002 to $3.90 per Mcf in 2003, which increased revenues $26.1 million, (ii) a decrease in gas sales volumes of 9% to 17.0 Bcf, which decreased revenues by $4.1 million and (iii) an increase in the average oil and natural gas liquids prices received from $15.59 to $22.14 which increased revenues $3.1 million.

 

During the six month period ended June 30, 2003, revenues from gas, oil and natural gas liquids production increased 68% to $159.0 million, as compared to $94.9 million in 2002.  This increase was primarily the result of (i) an increase in average gas prices received by the Company from $2.13 per Mcf in 2002 to $3.97 per Mcf in 2003, which increased revenues $62.1 million, (ii) a decrease in gas sales volumes of 8% to 33.8 Bcf, which decreased revenues by $6.1 million and (iii) an increase in the average oil and natural gas liquids prices received from $14.27 to $23.03 which increased revenues $8.1 million.

 

Revenues in 2003 were reduced by cash settlements on hedging activities. The natural gas collar and swap transactions considered effective hedges and settled in the three and six months ended June 30, 2003 resulted in cash settlements of $7.6 million and $18.8 million, respectively, which are included in gas and oil sales.  For the three and six month periods ended June 30, 2002, the Company made cash settlements on natural gas hedging instruments of $0.3 million which were included in gas and oil sales.

 

18

 

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

 

		Three Months Ended June 30,						Six Months Ended June 30
		2003			2002			2003			2002
		(In thousands)
Revenues:
Natural gas sales		$	66,259		$	44,078		$	134,083		$	78,077
Crude oil sales		5,661			5,228			11,201			9,770
Natural gas liquids sales		6,560			4,106			13,676			7,083
Gathering and processing		4,792			4,725			10,868			9,989
Marketing and trading		8,794			16,813			22,648			36,032
Drilling		3,878			2,750			6,955			4,581
Gain on sale of property		—			4,004			—			4,004
Change in derivative fair value and cash settlements		1,913			(1,653		)	1,913			(1,653		)
Loss on marketable security		—			(600		)	—			—
Interest income and other		76			63			627			(274		)
Total revenues		$	97,933		$	79,514		$	201,971		$	147,609
Natural gas production (Mmcf)		16,970			18,696			33,764			36,639
Crude oil production (Mbbls)		209			221			389			455
Natural gas liquid production (Mbbls)		368			378			747			725
Natural Gas ($/Mmcf):
Price received		$	4.35		$	2.36		$	4.53		$	2.13
Effect of hedges		$	(.45	)	$	—		$	(.56	)	$	—
Net sales price		$	3.90		$	2.36		$	3.97		$	2.13
Average crude oil sales price ($/Bbl)		$	27.14		$	23.70		$	28.80		$	21.45
Average natural gas liquid sales price ($/Bbl)		$	17.82		$	10.86		$	18.31		$	9.76

 

Gathering and processing revenue for the six months ended June 30, 2003 was $10.9 million, an increase of $1.0 million from the same period in 2002.  The Company processed additional third-party liquids and benefited from the increase in the natural gas liquids prices on retained products in 2003.  A new processing plant was operational in the Paradox Basin of Colorado in the first quarter 2003.  Gathering and processing revenue for the quarter ended June 30, 2003 was essentially unchanged from the same period in 2002 as the incremental revenue from the new plant offset the impact of declining volumes in other areas.

 

The Company reduced the natural gas volumes associated with trading contracts in 2003 which resulted in a reduction in trading revenue (and associated trading expenses) in the quarter and six months ended June 30, 2003 as compared to the same periods in 2002.  Net marketing and trading margins have increased in 2003 due to the Company transporting gas into the Mid Continent region to take advantage of higher gas prices in this market.  This opportunity resulted from natural gas price differentials between the Rocky Mountain region and the Mid Continent markets in excess of the Company’s cost to transport a portion of the Company’s natural gas production into the Mid Continent market.  These margins were profitable in the first quarter of 2003 but this profit opportunity began to diminish by the end of the second quarter of 2003.  This marketing opportunity was not available in the six months ended June 30, 2002.

 

Drilling revenue associated with the Company’s wholly-owned subsidiary, Sauer Drilling Company (Sauer) increased 41% and 52% for the three and six month periods of 2003 or $1.1 million and $2.4 million as compared to the same periods in 2002.  In the three and six month periods ended June 30, 2003, Sauer generated a higher percentage of its contract drilling revenue from third-parties, as compared to the same periods in 2002.  Contract drilling revenues associated with wells operated by the Company and drilled by Sauer are eliminated in consolidation.  This change in mix resulted in higher drilling revenues despite a general decrease in rig utilization rates in 2003 compared to 2002.  For the three and six months ended June 30, 2003, Sauer achieved a 64% and 61% rig utilization rate, respectively, on its eight operating rigs.  For the same periods in 2002, rig utilization rates were 71% and 65%.  The demand for drilling rigs has increased over the six month period ended June 30, 2003 and in response to this demand, Sauer purchased an additional rig at a cost of $2.2 million in June 2003 that will commence drilling operations in August 2003.

 

19

 

Costs and Expenses

 

Expenses related to gas and oil production for the three and six months ended June 30, 2003 increased $0.4 million from the expenses incurred during the same periods in 2002.  On an Mcfe basis, gas and oil production costs increased to $0.42 for the six months ended June 30, 2003 from $0.37 for the same period in 2002.  In the second quarter of 2003, the gas and oil production expenses increased by $0.3 million as a result of certain workover expenses being incurred on the Company’s Piceance Basin wells in Colorado.  The impact of these additional expenses together with the impact of spreading these relatively fixed costs over production that declined 7% between these periods resulted in the increased per unit rate in 2003.

 

Taxes on gas and oil production increased by 45% (or $2.2 million) and 55% (or $4.8 million) for the three and six months ended June 30, 2003 in comparison to the same periods in 2002.  This increase was attributable to the impact of increased gas, oil and natural gas liquids prices for the periods ended June 30, 2003, as compared to the same periods in 2002.

 

Depreciation, depletion and amortization decreased $0.3 million and $1.5 million for the three and six months ended June 30, 2003 as compared to the same periods in 2002. The production decrease of 7% for the six month period, was the primary reason for the overall decrease.  On an Mcfe basis, the effective depreciation, depletion and amortization rate actually increased to $1.10 for the six months ended June 30, 2003 compared to $1.05 for the same period in 2002.  This increase was attributable to the higher finding costs incurred by the Company in recent periods to replace the production declines from the older gas and oil properties.

 

Gathering and processing costs principally represent costs associated with operating and maintaining the field systems. This expense increased for the three and six months ended June 30, 2003, as compared to the same periods in 2002, by $0.3 million and $0.8 million which was attributable to incremental processing costs associated with marketing third-party liquids through the Lisbon plant in the Paradox Basin.

 

Expenses associated with the Company’s exploration activities were $3.8 million and $10.7 million for the three and six months ended June 30, 2003, as compared to $7.6 million and $11.2 million for the same periods in 2002.  A major component of the exploration expenses was $1.3 million and $4.3 million of dry hole expense for the three and six month periods ended June 30, 2003, as compared to $2.9 million and $3.0 million in the same periods of 2002. Capital expenditures (excluding acquisitions) of $79.2 million were incurred in the first six months of 2003.  During the first six months of 2002, capital expenditures were $91.3 million.  As of June 30, 2003, the Company has capitalized $10.9 million of costs on exploratory wells in process pending the evaluation of drilling results.

 

General and administrative expenses increased in the three and six months ended June 30, 2003 by $1.3 million, in comparison to the same periods in 2002.  On an Mcfe basis, general and administrative expenses were $0.28 and $0.26 for the three and six months ended June 30, 2003 and $0.20 and $0.21 for the same periods in 2002.  General and administrative expenses in the second quarter of 2003 included a $0.4 million pretax charge associated with the benefit a retiring director received from an earlier amendment to the terms of an option grant.  The Company’s cost of general corporate insurance and the insurance cost relative to personnel coverage also increased by approximately $0.4 million in the three months ended June 30, 2003 compared to the same period in 2002.  The impact of these increased costs together with the 7% decline in production for the six months ended June 30, 2003 compared to the same period in 2002 resulted in an increase in the per Mcfe costs between these periods.

 

The Company recorded an income tax provision of $22.3 million associated with the $64.4 million income before the cumulative effect of change in accounting principle for the six months ended June 30, 2003, which represented an effective tax rate of 34.6 percent.  In the three months ended June 30, 2003, the tax provision was reduced by a $1.2 million refund due the Company as a result of a change in the Canadian tax law not previously utilized in a year 2000 tax filing.  For the six months ended June 30, 2002, an income tax provision of $1.1 million was recorded associated with the $5.5 million income before cumulative effect of change in accounting principle.  This tax provision included the impact of $0.8 million in state tax credits associated with drilling incentives in Colorado and Utah.

 

Capital Resources and Liquidity

 

Growth and Acquisitions

 

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

 

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The Company entered into a definitive merger agreement on May 13, 2003 to acquire Matador Petroleum Corporation (“Matador”), after arm’s-length negotiations.  Matador was a privately held exploration and production company, active primarily in the East Texas Basin and Permian Basin of Southeastern New Mexico and West Texas, areas complementary to the Company’s current areas of interest.  The merger was approved by Matador’s shareholders on June 13, 2003, and the transaction closed on June 27, 2003.  The Company initially funded the acquisition with borrowings under a new $425.0 million senior unsecured bank credit facility and a $155.0 million loan under a senior subordinated credit facility.  The new $425.0 million bank credit facility replaced the existing credit facilities of the Company and Matador.

 

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

 

Capital and Exploration Expenditures

 

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

 

		2003			2002
		(In millions)
CAPITAL AND EXPLORATION EXPENDITURES:
Acquisitions:
Matador		$	388.0		$	—
Other		18.0			8.1
Exploration costs		17.2			19.6
Development costs		51.5			49.5
Acreage		5.0			6.3
Gas gathering and processing		2.4			6.3
Other		3.1			1.5
		$	485.2		$	91.3
FINANCING SOURCES:
Common stock issued		$	2.3		$	1.2
Net long term bank debt		279.7			26.2
Debt assumed on Matador acquisition		114.5			—
Proceeds from sale of assets		.7			8.8
Cash flow provided by operating activities		85.5			55.0
Other		2.5			.1
		$	485.2		$	91.3

 

The Company anticipates exploration and development expenditures between $245 to $255 million in 2003, with approximately 70% to 75% allocated to development activity.  The timing of most of the Company’s capital expenditures is discretionary and there are no material long-term commitments associated with the Company’s capital expenditure plans.  Consequently, the Company is able to adjust the level of its capital expenditures as circumstances warrant.  The level of capital expenditures by the Company will vary in future periods depending on energy market conditions and other related economic factors.

 

Drilling Rig Obligation

 

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

 

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Bank Credit Facility

 

On March 20, 2001, the Company entered into a $225 million credit facility (the “Global Credit Facility”). The Global Credit Facility was comprised of: a $75 million line of credit in the U.S. and a $55 million line of credit in Canada which both had maturity dates of March 20, 2004, and a $95 million five-year term loan in Canada which had a maturity date of March 21, 2006. The borrowing base established to support the $225 million line of credit was initially set at $300 million, which was re-approved as of May 1, 2002. In conjunction with Matador acquisition in June 2003, the Company entered into a “New Global Credit Facility” with an increased line of credit and initial borrowing base of $425 million.  The terms of the New Global Credit Facility provides for:  a $290 million line of credit in the U.S. and a $25 million line of credit in Canada which both mature on June 27, 2007, and a $110 million five-year term loan in Canada which matures on March 21, 2006.  The terms of the New Global Credit Facility allow the lenders one scheduled redetermination of the borrowing base each December.  In addition, the lenders may elect to require one unscheduled redetermination in the event the borrowing base utilization exceeds 50% of the borrowing base at any time for a period of 15 consecutive business days. At June 30, 2003, the Company had borrowings outstanding under the New Global Credit Facility totaling $387.6 million or 92% of the borrowing base at an average interest rate of 2.8%.  The amount available for borrowing under the New Global Credit Facility at June 30, 2003 was $37.4 million.

 

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

 

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

 

Senior Subordinated Credit Facility

 

In connection with the consummation of the Matador Petroleum acquisition, the Company entered into an unsecured senior subordinated credit facility (the “Subordinated Facility”) with a group of lender banks that also participate in the Company’s New Global Credit Facility.  The $155 million loan matures in seven years.  The initial interest rate on the loan was set at 8.5%, but provides for quarterly increases of 0.5%.  The facility provides for an exchange to transferable notes after one year.  Interest on the Subordinated Facility is based on LIBOR plus a margin, subject to a minimum rate of 8.5% and maximum amount of 14% and currently bears interest at 8.5% per annum.

 

The Subordinated Facility contains certain financial covenants that could limit the Company from incurring additional indebtedness beyond the New Global Credit Facility.  Additionally, the Subordinated Facility restricts certain types of payments, including payment of dividends or repurchase or redemption of the Company’s common stock, which are prohibited for the first year.  After the first year, or after the initial maturity date, the Company may make such restricted payments if it is not in default and it passes the additional indebtedness test under the facility.  The Company was in compliance with all covenants at June 30, 2003.

 

Markets and Prices

 

The Company’s revenues and associated cash flows are significantly impacted by changes in gas, oil and natural gas liquids prices.  The Company’s gas, oil and natural gas liquids production is generally market sensitive as the majority of the Company’s production has not been presold at contractually specified prices.  During the three and six months ended June 30, 2003, the average prices received for gas and oil by the Company were $3.90 and $3.97 per Mcf and $27.14 and $28.80 per barrel, respectively, as compared to $2.36 and $2.13 per Mcf and $23.70 and $21.45 per barrel, respectively, in 2002.  For natural gas liquids, the average prices received were $17.82 and $18.31 per barrel in the three and six months ended June 30, 2003 as compared to $10.86 and $9.76 per barrel for the same periods in 2002.

 

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ITEM 3. Quantitative and Qualitative Disclosure About Market Risk

 

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

 

Commodity Price Fluctuations

 

The Company’s results of operations are highly dependent upon the prices received for 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 hedging arrangements, including commodity swap agreements, forward sale contracts, commodity futures, options and other similar agreements relating to natural gas and crude oil expected to be produced.  The Company has also entered into certain financial instruments that did not qualify as hedging arrangements.  These transactions have principally involved basis contracts entered into to secure a pricing differential into markets where the Company has transportation agreements.

 

Financial instruments designated as hedges are accounted for on the accrual basis with gains and losses being recognized based on the type of contract and exposure being hedged.  Gains and losses on natural gas and crude oil swaps designated as hedges of anticipated transactions, including accrued gains 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 it becomes probable that a hedged transaction will not occur, gains and losses, including gains or losses upon early termination of contracts, are included in the income statement immediately.

 

The Company has natural gas hedges, in the form of costless collars and swaps (including related basis swaps), as follows as of June 30, 2003:

 

		Natural Gas Collars					Natural Gas Swaps
Period		Mmbtu/d		Weighted Average Floor/Ceiling			Mmbtu/d		Weighted Average Swap Price
Third Quarter 2003		80,000		$	3.96/6.88		55,800		$	3.04
Fourth Quarter 2003		58,500		$	4.12/7.67		18,500		$	3.04
First Quarter 2004		32,500		$	4.78/10.08		—		—
Second Quarter 2004		27,500		$	4.08/6.30		—		—
Third Quarter 2004		27,500		$	4.08/6.30		—		—
Fourth Quarter 2004		25,800		$	4.07/6.56		—		—

 

Interest Rate Risk

 

At June 30, 2003, the Company had $387.6 million outstanding under the New Global Credit Facility at an average interest rate of 2.8%.  Borrowings under the New Global Credit Facility are unsecured and bear interest, at the election of the Company, at a rate equal to (i) the greater of the global administrative agents prime rate or the federal funds effective rate, plus an applicable margin (ii) adjusted LIBOR for Eurodollar loans plus applicable margin, or (iii) Bankers’ Acceptances plus applicable margin for Canadian dollar loans.  As a result, the Company’s annual interest cost in 2003 will fluctuate based on short-term interest rates.  Assuming no change in the amount outstanding during 2003, the impact on interest expense of a ten percent change in the average interest rate would be approximately $1.1 million.  As the interest rate is variable and is reflective of current market conditions, the carrying value of the New Global Credit Facility approximates its fair value.

 

At June 30, 2003, the Company also had $155 million outstanding under the Subordinated Facility.  The initial interest rate on the loan was set at 8.5%, but provides for quarterly increases of 0.5%.  The facility provides for an exchange to transferable notes after one year.  Interest on the bridge facility is based on LIBOR plus a margin, subject to a minimum rate of 8.5% and maximum amount of 14% and currently bears interest at 8.5% per annum.  Assuming no change in the amount outstanding during 2003, the impact on interest expense of a ten percent change in the average interest rate would be approximately $1.3 million.  This facility was entered into on June 27, 2003 and the carrying value of the Subordinated Facility approximates its fair value.

 

 

23

 

Foreign Currency Exchange Risk

 

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

 

ITEM 4. Controls and Procedures

 

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

 

24

 

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

 

25

 

TOM BROWN, INC. AND SUBSIDIARIES

OTHER INFORMATION

 

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

 

None

 

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

 

(a)
		Exhibit No.		Description
		10.1*		U.S. Revolving Credit Agreement dated June 27, 2003.
		10.2*		Canadian Revolving Credit Agreement dated June 27, 2003.
		10.3*		Canadian Term Credit Agreement dated June 27, 2003.
		10.4*		Senior Subordinated Credit Agreement dated June 27, 2003.
		31.1*		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
		31.2*		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
		32.1*		Certification Pursuant to 18 U.S. C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
		32.2*		Certification Pursuant to 18 U.S. C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

*Filed herewith

 

(b)                                 Reports on Form 8-K

 

Form 8-K Item 5.  Press release dated May 14, 2003, entitled “Tom Brown, Inc. Announces Agreement to Acquire Matador Petroleum” filed on May 16, 2003.

 

Form 8-K Item 5.  Press release dated June 13, 2003, entitled “Tom Brown, Inc. Announces Matador Petroleum Corporation Shareholders Approve Acquisition” filed on June 18, 2003.

 

Form 8-K Item 5.  Press release dated June 27, 2003, entitled “Tom Brown, Inc. Announces Closing of the Matador Petroleum Acquisition” filed on July 7, 3003.

 

Form 8-K Item 2.  Acquisition or Disposition of Assets filed on July 11, 2003.

 

Form 8-K/A Item 7.  Financial Statements and Exhibits filed on August 1, 2003.

 

Form 8-K Item 12.  Press release dated August 7, 2003, entitled “Tom Brown, Inc. Reports Second Quarter 2003 Financial and Operating Results” filed on August 8, 2003.

 

26

 

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)
	By:	/s/ DANIEL G. BLANCHARD
		Daniel G. Blanchard
		Executive Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
August 14, 2003	By:	/s/ RICHARD L. SATRE
		Richard L. Satre
		Controller
		(Chief Accounting Officer)

 

27