1
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 0-3880
TOM BROWN, INC
--------------
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
<Table>
DELAWARE 95-1949781
-------------------------------- -------------------
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
555 SEVENTEENTH STREET, SUITE 1850
DENVER, COLORADO 80202
- ---------------------------------------- ----------
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
</Table>
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 X NO
--- ---
APPLICABLE ONLY TO CORPORATE ISSUERS:
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of August 10, 2001.
<Table>
<Caption>
CLASS OF COMMON STOCK OUTSTANDING AT AUGUST 10, 2001
--------------------- ------------------------------
$.10 PAR VALUE 39,053,257
</Table>
2
TOM BROWN, INC. AND SUBSIDIARIES
QUARTERLY REPORT FORM 10-Q
INDEX
<Table>
<Caption>
Page No.
Part I. Item 1. Financial Information (Unaudited)
Consolidated Balance Sheets,
June 30, 2001 and December 31, 2000 4
Consolidated Statements of Operations,
Three and six months ended June 30, 2001 and 2000 6
Consolidated Statements of Cash Flows,
Six months ended June 30, 2001 and 2000 8
Notes to Consolidated Financial Statements 10
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations 15
Item 3. Quantitative and Qualitative Disclosure about
Market Risk 18
Part II. Other information
Item 4. Submission of Matters to a Vote of Security Holders 20
Item 6. Exhibits and Reports on Form 8-K 20
Signature 21
</Table>
2
3
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
4
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
(IN THOUSANDS)
<Table>
<Caption>
June 30, December 31,
2001 2000
----------- ------------
(Unaudited)
CURRENT ASSETS:
Cash and cash equivalents $ 31,669 $ 17,534
Accounts receivable 108,059 95,878
Inventories 1,571 521
Other 3,144 2,307
-------- --------
Total current assets 144,443 116,240
-------- --------
PROPERTY AND EQUIPMENT, AT COST:
Gas and oil properties, based on the successful
efforts accounting method 753,361 575,991
Gas gathering and processing and other plant 82,489 81,873
Other equipment 35,588 28,746
-------- --------
Total property and equipment 871,438 686,610
Less: Accumulated depreciation, depletion and amortization 199,885 176,848
-------- --------
Net property and equipment 671,553 509,762
-------- --------
OTHER ASSETS:
Other assets, net 17,088 3,533
-------- --------
$833,084 $629,535
======== ========
</Table>
(continued)
See accompanying notes to consolidated financial statements.
4
5
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND STOCKHOLDERS' EQUITY
(IN THOUSANDS, EXCEPT SHARE DATA)
<Table>
<Caption>
June 30, December 31,
2001 2000
----------- ------------
(Unaudited)
CURRENT LIABILITIES:
Accounts payable $ 74,571 $ 55,982
Accrued expenses 9,682 22,119
----------- -----------
Total current liabilities 84,253 78,101
----------- -----------
BANK DEBT 97,359 54,000
DEFERRED INCOME TAXES 74,225 5,475
OTHER NON-CURRENT LIABILITIES 3,224 3,066
STOCKHOLDERS' EQUITY:
Convertible preferred stock,
at $ .10 par value
Authorized 2,500,000 shares -- --
Common stock, at $.10 par value
Authorized 55,000,000 shares;
outstanding 39,051,257 and
38,351,860 shares, respectively 3,905 3,835
Additional paid-in capital 533,250 516,911
Retained earnings (accumulated deficit) 32,052 (31,648)
Other comprehensive income (loss) 4,816 (205)
----------- -----------
Total stockholders' equity $ 574,023 $ 488,893
----------- -----------
$ 833,084 $ 629,535
=========== ===========
</Table>
See accompanying notes to consolidated financial statements.
5
6
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS)
<Table>
<Caption>
Three months ended Six months ended
June 30, June 30,
------------------------ ------------------------
2001 2000 2001 2000
--------- --------- --------- ---------
(Unaudited)
Revenues:
Gas and oil sales $ 71,696 $ 44,537 $ 178,507 $ 81,281
Gathering and processing 7,215 4,203 14,593 8,668
Marketing and trading, net 1,059 2,523 1,430 3,580
Drilling 3,803 1,996 6,557 5,398
Gain on sale of property 10,078 -- 10,078 --
Change in derivative fair value 979 -- 1,869 --
Interest income and other 556 129 1,036 142
--------- --------- --------- ---------
Total Revenues 95,386 53,388 214,070 99,069
--------- --------- --------- ---------
Costs and expenses:
Gas and oil production 8,241 5,884 15,846 12,400
Taxes on gas and oil production 6,345 4,582 16,445 8,354
Gathering and processing costs 2,924 1,291 9,165 3,317
Drilling operations 3,159 1,729 5,433 4,528
Exploration costs 7,677 2,024 14,131 3,863
Impairments of leasehold costs 1,200 900 2,400 1,800
General and administrative 4,720 2,845 13,847 5,322
Depreciation, depletion and amortization 18,054 11,977 34,701 23,230
Interest expense and other 1,704 1,710 4,052 3,079
--------- --------- --------- ---------
Total costs and expenses 54,024 32,942 116,020 65,893
--------- --------- --------- ---------
Income before income taxes and cumulative effect of change in
accounting principle 41,362 20,446 98,050 33,176
Income tax provision:
Current (4,560) (657) (11,365) (1,107)
Deferred (10,568) (7,187) (25,011) (11,758)
--------- --------- --------- ---------
Net income before cumulative effect of change in accounting principle 26,234 12,602 61,674 20,311
Cumulative effect of change in accounting principle -- -- 2,026 --
--------- --------- --------- ---------
Net income 26,234 12,602 63,700 20,311
Preferred stock dividends -- (437) -- (875)
--------- --------- --------- ---------
Net income attributable to common stock $ 26,234 $ 12,165 $ 63,700 $ 19,436
========= ========= ========= =========
</Table>
(continued)
See accompanying notes to consolidated financial statements.
6
7
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<Table>
<Caption>
Three months ended Six months ended
June 30, June 30,
------------------------- -------------------------
2001 2000 2001 2000
---------- ---------- ---------- ----------
(Unaudited)
Weighted average number of common shares outstanding:
Basic 39,030 35,811 38,815 35,562
========== ========== ========== ==========
Diluted 40,333 37,207 40,354 36,512
========== ========== ========== ==========
Earnings per common share - Basic:
Income before cumulative effect of change in
accounting principle $ .67 $ .34 $ 1.59 $ .55
Cumulative effect of change in accounting principle -- -- .05 --
---------- ---------- ---------- ----------
Net income attributable to common stock $ .67 $ .34 $ 1.64 $ .55
========== ========== ========== ==========
Earnings per common share - Diluted:
Income before cumulative effect of change in
accounting principle $ .65 $ .33 $ 1.53 $ .53
Cumulative effect of change in accounting principle -- -- .05 --
---------- ---------- ---------- ----------
Net income attributable to common stock $ .65 $ .33 $ 1.58 $ .53
========== ========== ========== ==========
</Table>
See accompanying notes to consolidated financial statements.
7
8
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<Table>
<Caption>
Six months ended
June 30,
------------------------
2001 2000
--------- ---------
(Unaudited)
Cash flows from operating activities:
Net income $ 63,700 $ 20,311
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation, depletion and amortization 34,701 23,230
Cumulative effect of change in accounting principle (2,026) --
Change in derivative fair value (1,869) --
Gain on sale of property (10,078) --
Accelerated vesting of options 3,747 --
Dry hole costs 6,198 231
Impairments of leasehold costs 2,400 1,800
Deferred income taxes 25,011 11,758
--------- ---------
121,784 57,330
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable 11,675 (336)
Decrease in inventories 58 98
(Increase) decrease in other current assets (236) 170
Decrease in accounts payable and accrued expenses (16,778) (7,315)
Increase in other assets, net (2,379) (605)
--------- ---------
Net cash provided by operating activities $ 114,124 $ 49,342
--------- ---------
</Table>
(continued)
See accompanying notes to consolidated financial statements.
8
9
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<Table>
<Caption>
Six months ended
June 30,
------------------------
2001 2000
--------- ---------
(Unaudited)
Cash flows from investing activities:
Capital and exploration expenditures $(100,519) $ (55,412)
Changes in accounts payable and accrued expenses
for oil and gas expenditures 6,059 --
Acquisition of Stellarton stock (74,500) --
Direct costs on Stellarton acquisition (3,700) --
Proceeds from sales of assets 42,049 --
--------- ---------
Net cash used in investing activities (130,611) (55,412)
--------- ---------
Cash flows from financing activities:
Repayments of long-term bank debt (54,000) (7,000)
Borrowings of long-term bank debt 74,500 6,000
Preferred stock dividends -- (875)
Proceeds from exercise of stock options 10,116 5,757
--------- ---------
Net cash provided by financing activities 30,616 3,882
--------- ---------
Effect of exchange rate changes on cash 6 --
Net increase (decrease) in cash and cash equivalents 14,135 (2,188)
--------- ---------
Cash and cash equivalents at beginning of period 17,534 12,510
--------- ---------
Cash and cash equivalents at end of period $ 31,669 $ 10,322
========= =========
Cash paid during the period for:
Interest $ 4,502 $ 3,262
Taxes 6,631 969
Debt assumed in Stellarton acquisition 16,800 --
</Table>
See accompanying notes to consolidated financial statements.
9
10
TOM BROWN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The consolidated financial statements included herein have been prepared by
Tom Brown, Inc. (the "Company") and are unaudited, except for the balance sheet
at December 31, 2000 which has been prepared from the audited financial
statements at that date. The financial statements reflect necessary adjustments,
all of which were of a recurring nature, and are, in the opinion of management,
necessary for a fair presentation. Certain information and footnote disclosures
normally included in financial statements prepared in accordance with generally
accepted accounting principles have been omitted pursuant to the rules and
regulations of the Securities and Exchange Commission. The Company believes that
the disclosures presented are adequate to allow the information presented not to
be misleading. Users of financial information produced for interim periods are
encouraged to refer to the footnotes contained in the Annual Report to
Stockholders when reviewing interim financial results. Certain reclassifications
have been made to amounts reported in previous periods to conform to the current
presentation.
(2) DEBT
On June 30, 2000, the Company entered into a new $125 million credit
facility (the "New Credit Facility") that was to mature in June 2003. Under the
terms of the New Credit Facility, the borrowing base was established at $225
million.
On March 20, 2001, as part of the final financing of the Stellarton Energy
Corporation ("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 set at $300 million. The Global Credit Facility allows 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, 2001, the
Company had borrowings outstanding under the Global Credit Facility totaling
$97.4 million or 32% of the borrowing base at an average interest rate of 5.65%.
The amount available for borrowing under the Global Credit Facility at June 30,
2001 was $127.6 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 similar to the limitations associated with the cancelled credit
facility. The financial covenants of the Global Credit Facility require the
Company to maintain a minimum consolidated tangible net worth of not less than
$350 million (adjusted upward by 50% of quarterly net income and 50% of the net
cash proceeds of any stock offering) and the Company will not permit its ratio
of (i) indebtedness to (ii) earnings before interest expense, state and Federal
taxes and depreciation, depletion and amortization expense and exploration
expense to be more than 3.0 to 1.0 as calculated at the end of each fiscal
quarter.
(3) 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 required to pay alternative minimum tax
("AMT").
Temporary differences and carryforwards which gave rise to significant
portions of deferred tax assets (liabilities) are as follows (in thousands):
<Table>
<Caption>
JUNE 30, DECEMBER 31,
2001 2000
------------ ------------
Net operating loss carryforwards $ -- $ 4,845
Gas and oil acquisition, exploration and development
costs deductible for tax purposes over book (78,538) (17,877)
AMT credit carryforwards 2,685 5,343
Other 1,628 2,214
----------- -----------
Net deferred tax liability $ (74,225) $ (5,475)
=========== ===========
</Table>
10
11
In conjunction with the acquisition of Stellarton in January 2001, the
purchase price allocation resulted in a difference between the book and tax
basis of approximately $63 million. Based upon Stellarton's historical tax rate
of 45%, a deferred tax liability of approximately $42 million was recognized.
The Company evaluated all appropriate factors to determine the need for a
valuation allowance for the AMT carryforwards, including any limitations
concerning their use, the levels of taxable income necessary for utilization and
tax planning. In this regard, based on its recent operating results and its
expected levels of future earnings, the Company believes it will, more likely
than not, generate sufficient taxable income to realize the benefit attributable
to the AMT carryforwards and the other deferred tax assets for which valuation
allowances were not provided.
The components of the Company's current and deferred tax provisions are as
follows (in thousands):
<Table>
<Caption>
SIX MONTHS ENDED
JUNE 30,
-----------------------
2001 2000
-------- --------
Current income tax provision:
Federal AMT provision $ (6,693) $ (664)
Canadian provision (3,440) --
State income and franchise taxes (1,232) (443)
-------- --------
Total current taxes (11,365) (1,107)
-------- --------
Deferred income tax benefit (provision):
Federal and State provision (27,049) (11,758)
Canadian benefit 2,038 --
-------- --------
Total deferred taxes (25,011) (11,758)
-------- --------
Total tax provision $(36,376) $(12,865)
======== ========
</Table>
(4) SEGMENT INFORMATION
The Company operates in three reportable segments: (i) gas and oil
exploration and development, (ii) marketing, gathering and processing and (iii)
drilling. The gas and oil exploration and development is conducted in the United
States and Canada. The following tables present information related to these
segments (in thousands):
<Table>
<Caption>
Six months ended
June 30, 2001
-------------------------------------------------------------------------------------
Gas & Oil Gas & Oil
Exploration & Exploration & Marketing,
Development Development Gathering & Total
(Domestic) (Canada) Processing Drilling Segments
------------- ------------- ------------- ------------- -------------
Revenues from external purchasers $ 105,823 $ 19,059 $ 181,827 $ 6,557 $ 313,266
Intersegment revenues 56,025 -- 3,071 7,140 66,236
Segment profit 81,174 5,970 4,645 2,572 94,361
</Table>
<Table>
<Caption>
Six months ended
June 30, 2000
-------------------------------------------------------------------
Gas & Oil
Exploration & Marketing,
Development Gathering & Total
(Domestic) Processing Drilling Segments
------------- ------------- ------------- -------------
Revenues from external purchasers $ 61,777 $ 94,703 $ 5,398 $ 161,878
Intersegment revenues 17,511 -- 1,947 19,458
Segment profit 29,799 6,061 608 36,468
</Table>
11
12
<Table>
<Caption>
Six months ended
June 30,
------------------------
2001 2000
--------- ---------
Revenues
Revenues from external purchasers $ 313,266 $ 161,878
Marketing and trading expenses offset against related
revenues for net presentation (118,370) (64,802)
Gain on sale of property 10,078 --
Intersegment revenues 66,236 19,458
Intercompany eliminations (57,140) (17,465)
--------- ---------
Total consolidated revenues $ 214,070 $ 99,069
========= =========
Profit
Total reportable segment income $ 94,361 $ 36,468
Interest expense (4,052) (3,079)
Gain on sale of property 10,078 --
Elimination and other (2,337) (213)
--------- ---------
Income before income taxes and cumulative
effect of change in accounting principle $ 98,050 $ 33,176
========= =========
</Table>
(5) ACQUISITIONS AND DISPOSITIONS
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 $10.8 million which will be
amortized on a straight-line basis over twenty years. 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):
<Table>
Acquisition Costs:
Long-term debt incurred $ 74,500
Deferred income taxes 42,000
Gas sales contracts assumed 10,825
Direct acquisition costs 3,700
Long-term debt assumed 16,800
--------
Total acquisition costs $147,825
========
Allocation of Acquisition Costs:
Oil and gas properties - proved $127,106
Undeveloped properties 9,975
Goodwill 10,744
--------
Total $147,825
========
</Table>
In the acquisition costs identified above, the Company recorded a deferred
income tax liability of $42 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.
12
13
Pro Forma Results of Operations (Unaudited)
The following table reflects the unaudited pro forma results of operations
for the six months ended June 30, 2001 and 2000 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.
<Table>
<Caption>
SIX MONTHS ENDED
JUNE 30,
---------------------------
2001 2000
----------- -----------
(IN THOUSANDS, EXCEPT
PER SHARE DATA)
Revenues $ 216,013 $ 110,172
Net Income 63,700 17,879
Basic net income per share 1.64 .50
Diluted net income per share 1.58 .49
</Table>
Property Sales
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.
(6) COMMODITY DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
In order to increase 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.
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 future 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 received cash settlements of $2.2 million during this period
which were recognized as an increase in gas and oil sales.
The Company also entered into natural gas basis swaps covering essentially
the same time period of the natural gas costless collars. These transactions
were executed in December, 2000 with settlement periods in 2001. Under SFAS 133,
these basis swaps did not qualify for hedge accounting. Accordingly, upon
adoption these basis swaps resulted in the recognition of derivative gains of
$2.0 million, recorded as a cumulative effect of a change in accounting
principle, (net of the deferred tax liability of $1.2 million) and a derivative
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.
13
14
As of June 30, 2001, the Company had open natural gas costless price collars
and basis swaps on its production as follows:
<Table>
<Caption>
NATURAL GAS COLLARS
---------------------------------------------
2001 VOLUME IN BASIS
CONTRACT PERIOD MMBtu/d FLOOR/CEILING SWAPS
- --------------- --------- ------------- --------------
Third Quarter 60,000 $4.03/$6.73 $ (.28)
Fourth Quarter 40,000 $4.14/$6.76 $ (.27)
</Table>
Certain of the Company's Canadian natural gas production was subject to
physical delivery contracts at a price of approximately $2.00 per Mcf. These
contracts originally were scheduled to expire at various intervals through 2004.
During the quarter ended June 30, 2001, these contracts were terminated through
settlement payments with the gas purchasers.
(7) COMPREHENSIVE INCOME
Comprehensive income includes net income and certain items recorded directly
to shareholders' equity and classified as Other Comprehensive Income. The
following table illustrates the components of the comprehensive income for the
six months ended June 30, 2001 (in thousands):
<Table>
Other Comprehensive Income (net of tax)
Cumulative effect of change in accounting principle -
January 1, 2001 $(4,449)
Reclassification adjustment for settled contracts 1,405
Changes in fair value of outstanding hedging positions 8,182
Translation gain 10
Unrealized loss on marketable securities (332)
-------
Other Comprehensive Income $ 4,816
=======
</Table>
As of December 31, 2000, Other Comprehensive Loss included a net loss of $.2
million related to the unrealized loss on marketable securities.
(8) 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 (in thousands).
<Table>
<Caption>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------- -------------------
2001 2000 2001 2000
------- ------- ------- -------
Revenues $39,469 $28,826 $85,228 $52,645
Operating expenses 38,907 27,287 84,488 50,419
------- ------- ------- -------
Net trading margin $ 562 $ 1,539 $ 740 $ 2,226
======= ======= ======= =======
</Table>
(9) RECENTLY-ISSUED ACCOUNTING STANDARDS
In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 141, "Business
Combinations," which addresses financial accounting and reporting for business
combinations. SFAS No. 141 is effective for all business combinations initiated
after June 30, 2001 and for all business combinations accounted for under the
purchase method initiated before but completed after June 30, 2001. The adoption
of SFAS No. 141 is not expected to have a material impact on the Company's
financial position or results of operations.
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. SFAS No. 142 is required to be
adopted on January 1, 2002. The Company is analyzing the impairment provisions
of SFAS No. 142, and has not yet determined whether those provisions will impact
its financial statements upon adoption.
14
15
TOM BROWN, INC. AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
The Company's results of operations were favorably impacted in the three and
six months ended June 30, 2001 by the acquisition of Stellarton in January 2001.
Increased production and higher commodity prices also contributed significantly
to the operating results for the period.
Net income attributable to common stock for the three and six months ended
June 30, 2001 was $26.2 million, or $.65 per share (diluted) and $63.7 million,
or $1.58 per share (diluted), respectively. Net income for the three and six
months ended June 30, 2001 included gains of $1.0 million and $1.9 million,
respectively, realized from the change in the fair value of derivatives under
the newly adopted SFAS 133 and a $10.1 million gain on sale of property.
Additionally, net income for the six months ended June 30, 2001 was impacted by
the $2.0 million gain (net of tax) recognized as a cumulative effect of a change
in accounting principle associated with the SFAS 133 adoption.
Revenues
During the three month period ended June 30, 2001, revenue from gas, oil and
natural gas liquids production increased 61% or $27.2 million compared to the
same period in 2000. This increase resulted from (i) an increase in the average
gas prices received by the Company from $2.86 per Mcf to $3.89 per Mcf which
increased revenues by approximately $16.0 million, (ii) a decrease in the
average price received for oil and natural gas liquids from $20.20 per barrel to
$19.44 per barrel which decreased revenues by $.4 million, (iii) a 24% increase
in the quantity of gas sold to 15.5 Bcf, which contributed incremental revenues
of $8.8 million and (iv) a 27% increase in the quantity of oil and natural gas
liquids sold to 581.6 MBbl, which contributed incremental revenues of $2.8
million. The Stellarton acquisition completed in January 2001 contributed 1.8
Bcf and 80.6 MBbl of the increased production quantities realized during the
three months ended June 30, 2001.
During the six month period ended June 30, 2001, revenue from gas, oil and
natural gas liquids production increased 120% or $97.2 million compared to the
same period in 2000. This increase resulted from (i) an increase in the average
gas prices received by the Company from $2.61 per Mcf to $5.17 per Mcf which
increased revenues by approximately $77.5 million, (ii) an increase in the
average price received for oil and natural gas liquids from $20.48 per barrel to
$20.93 per barrel which increased revenues by $.5 million, (iii) a 26% increase
in the quantity of gas sold to 30.3 Bcf, which contributed incremental revenues
of $16.5 million, and (iv) a 13% increase in the quantity of oil and natural gas
liquids sold to 1,051.1MBbl, which contributed incremental revenues of $2.7
million. For the six months ended June 30, 2001, the Stellarton acquisition
contributed 3.5 Bcf and 152.9 MBbl of the increased production.
Gathering and processing revenue increased 72% or $3.0 million, and 68% or
$5.9 million, for the three and six month periods ended June 30, 2001. In
November 2000 certain gathering and processing assets were distributed to the
Company from Wildhorse Energy Partners, LLC ("Wildhorse"). Incremental revenues
were recognized in 2001 as a result of the 100% ownership of these gathering and
processing assets which previously were 45% owned by the Company through the
Wildhorse partnership. TBI Field Services, Inc. ("TBIFS") was formed as a
wholly-owned subsidiary of Tom Brown, Inc. to administer the gathering and
processing assets. Incremental volumes gathered by TBIFS from the Wind River
Basin where the Company has a significant production base also contributed to
the increase in revenues.
Net marketing and trading income decreased $1.5 million, and $2.2 million,
for the three and six months ended June 30, 2001 compared to the same periods in
2000. This was attributable to reduced trading margins and increased
transportation costs.
Drilling operations are conducted through the Company's wholly owned
subsidiary, Sauer Drilling Company. Drilling revenue compared to the cost of
drilling produced a gross margin of $.6 million and $1.1 million for the three
and six months ended June 30, 2001 compared to gross margins of $.3 million and
$.9 million for the same periods in 2000. Rig utilization rates have continued
to remain at nearly full capacity in 2001.
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Selected Operating Data
<Table>
<Caption>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
--------------------- ---------------------
2001 2000 2001 2000
-------- -------- -------- --------
Revenues (in thousands):
Natural gas sales $ 60,361 $ 35,578 $156,481 $ 62,559
Crude oil sales 5,505 5,051 11,357 10,513
NGL sales 5,830 3,908 10,669 8,209
Gathering and processing 7,215 4,203 14,593 8,668
Marketing and trading, net 1,059 2,523 1,430 3,580
Drilling 3,803 1,996 6,557 5,398
Gain on sale of property 10,078 -- 10,078 --
Change in derivative fair value 979 -- 1,869 --
Other 556 129 1,036 142
-------- -------- -------- --------
Total revenues $ 95,386 $ 53,388 $214,070 $ 99,069
======== ======== ======== ========
Net income attributable to common
stock (in thousands) $ 26,234 $ 12,165 $ 63,700 $ 19,436
======== ======== ======== ========
Natural gas production (MMcf) 15,516 12,452 30,288 23,967
Crude oil production (MBbls) 224 189 446 387
NGL production (MBbls) 358 269 605 544
Average natural gas sales price ($/Mcf) $ 3.89 $ 2.86 $ 5.17 $ 2.61
Average crude oil sales price ($/Bbl) $ 24.48 $ 26.69 $ 25.46 $ 27.18
Average natural gas liquids price ($/Bbl) $ 16.29 $ 15.64 $ 17.63 $ 15.64
</Table>
Costs and Expenses
Costs and expenses for the three and six months ended June 30, 2001
increased approximately 64% to $54 million and 76% to $116 million as compared
to the same periods in 2000. This was generally attributable to increased
production levels, the impact of the Stellarton acquisition, increased gathering
and processing activity after the Wildhorse asset distribution and a general
increase in capital expenditure programs.
Expenses related to gas and oil production increased 28% from 2000 to 2001
due to the acquisition of Stellarton and increased production.
Taxes on gas and oil production increased by $1.8 million (39%) and $8.1
(97%) for the three and six months ended June 30, 2001 in comparison to the same
periods in 2000. This increase was directly related to the increase in gas and
oil sales in these periods.
Depreciation, depletion and amortization increased $6.1 million and $11.5
million for the three and six months ended June 30, 2001 in comparison to the
2000 periods. Approximately $3.7 million and $7.2 million of this increase was
associated with the depletion recorded for the three and six months ended June
30, 2001 on the Stellarton assets acquired in January 2001. Production increased
by 10% and 9% on an Mcfe basis, for the same periods, on the domestic properties
which also contributed to the increase in depreciation, depletion and
amortization.
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 gathering and
processing. This expense increased in 2001 due to the 100% ownership of the
gathering operations after the Wildhorse distribution and as a result of the
increase in the commodity price for natural gas during this period.
Expenses associated with the Company's exploration activities were $7.7
million and $14.1 million for the three and six months ended June 30, 2001 and
$2.0 million and $3.9 million for the same periods in 2000. The Company's
increased exploration efforts in 2001 resulted in dry hole costs ($6.2 million)
and increased seismic related expenses.
General and administrative expenses increased by $1.9 million and $8.5
million on a comparative basis for the three and six months ended June 30, 2001.
Included in the expenses for 2001 was a $5.3 million pre-tax charge recorded in
the first quarter of 2001 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. In addition,
general and administrative expenses related to Stellarton contributed $1.6
million to the six month increase from 2000.
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The Company recorded an income tax provision of $15.1 million and $36.4
million for the three and six months ended June 30, 2001 as compared to a
provision of $7.8 million for the 2000 periods. The current portions of these
provisions were $4.6 million and $11.4 million, respectively, compared to $.7
million and $1.1 million for the same periods in 2000. Although the total
provisions have increased in direct relation to the increase in earnings between
these periods, the current portion estimated to be payable in 2001 has been
impacted by the utilization of net operating loss carryforwards previously
available to reduce taxes currently payable. The Company had a $13.8 million net
operating loss carryforward available to offset taxable income as of the
beginning of 2001. As taxable income exceeded this carryforward in the quarter
ended March 31, 2001, the current tax provision increased accordingly. Current
taxes also increased due to the Stellarton acquisition which resulted in an
estimated $3.4 million of current taxes attributable to operations subsequent to
the acquisition and the gain on the sale of the oil and gas properties resulted
in taxes currently payable.
CAPITAL RESOURCES AND LIQUIDITY
Growth and Acquisitions
Most of the growth of the Company has resulted from recent acquisitions and
from the Company's successful development drilling. The Company continues to
pursue opportunities which will add value by increasing its reserve base and
presence in significant natural gas areas, and further developing the Company's
ability to control and market the production of natural gas. As the Company
continues to evaluate potential acquisitions and property development
opportunities, it will benefit from its financing flexibility and the leverage
potential of the Company's overall capital structure.
Property Sales
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.
Capital Expenditures
The Company's capital and exploration expenditures for the three and six
month periods ended June 30, 2001 were approximately $57 million and $203
million, including approximately $95 million for the purchase of Stellarton. For
the same periods in 2000, $41 million and $59 million were incurred.
The Company has historically funded capital expenditures and working capital
requirements with internally generated cash and borrowings. During the six
months ended June 30, 2001, net cash provided by operating activities before the
impact of changes in working capital was $121.8 million as compared to $57.3
million for the same period of 2000. The increase in 2001 was due to higher
commodity prices, increased production and the impact of the acquisition of
Stellarton.
Bank Credit Facility
The Company's new Global Credit Facility provides for a $225 million
revolving line of credit with a current borrowing base of $300 million. The
amount of the borrowing base may be re-determined as of December of each
calendar year at the sole discretion of the lenders.
At June 30, 2001, the aggregate outstanding balance under the Global Credit
Facility was $97.4 million. The amount available for borrowing under the Global
Credit Facility at June 30, 2001 was $127.6 million. The Global Credit Facility
contains certain financial covenants which require the Company to maintain a
minimum consolidated tangible net worth as well as certain financial ratios. The
Company was in compliance with the covenants contained in the Global Credit
Facility, at June 30, 2001. 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.
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Markets and Prices
In December 2000, the Company believed that the pricing environment provided
a strategic opportunity to significantly reduce the price risk on a portion of
the Company's production and decided to implement a hedging program.
Accordingly, the Company entered into several natural gas costless collars (put
and call options) and natural gas basis swaps to correlate the NYMEX based
costless collars back to the various index delivery points where the Company's
gas is produced. These positions were intended to hedge approximately 40% of the
Company's expected 2001 domestic gas production.
The Company's revenues and associated cash flows are significantly impacted
by changes in gas and oil prices. Substantially all of the Company's gas and oil
production is currently market sensitive. During the three and six months ending
June 30, 2001, the average prices received for gas, oil and natural gas liquids
by the Company were $3.89 and $5.17 per Mcf, $24.48 and $25.46 per barrel and
$16.29 and $17.63 per barrel, respectively. For the six months ended June 30,
2001, the impact of settlements received on the gas hedge contracts increased
the realized gas price by approximately $.07.
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
gas and oil 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 gas and oil prices also
could affect results of operations and cash flows.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
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.
Interest Rate Risk
At June 30, 2001, the Company had $97.4 million outstanding under its Global
Credit Facility at an average interest rate of 5.65%. Borrowings under the
Company's 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. As a result, the
Company's annual interest cost in 2001 will fluctuate based on short-term
interest rates. Assuming no change in the amount outstanding during 2001, the
impact on interest expense of a ten percent change in the average interest rate
would be approximately $.5 million. As the interest rate is variable and is
reflective of current market conditions, the carrying value approximates the
fair value.
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TOM BROWN, INC.
555 Seventeenth Street, Suite 1850
Denver, Colorado 80202
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QUARTERLY REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
FORM 10-Q
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PART II OF TWO PARTS
OTHER INFORMATION
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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 8-K and Form 8-K/A
(a) Exhibit No. Description
None.
(b) Reports on Form 8-K
Form 8-K Item 7. 2001 Financial Model Estimates filed on
August 8, 2001
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TOM BROWN, INC. AND SUBSIDIARIES
OTHER INFORMATION
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
TOM BROWN, INC.
-----------------------------------
(Registrant)
/s/ Daniel G. Blanchard
-----------------------------------
Daniel G. Blanchard
Executive Vice President, Chief
Financial Officer and Treasurer
(Principal Financial Officer)
August 13, 2001 /s/ Richard L. Satre
- --------------- -----------------------------------
Date Richard L. Satre
Controller
(Chief Accounting Officer)
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