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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 September 30, 2004
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission File Number: 000-22433
BRIGHAM EXPLORATION COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE 1311 75-2692967
(State of other jurisdiction (Primary Standard Industrial (I.R.S. Employer
of incorporation or organization) Classification Code Number) Identification Number)
6300 BRIDGE POINT PARKWAY, BUILDING 2, SUITE 500, AUSTIN, TEXAS 78730
(Address of principal executive offices)
(512) 427-3300
(Registrant's telephone number, including area code)
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 twelve 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 [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12 b-2 of the Act).
Yes [X] No [ ]
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
CLASS OUTSTANDING
----- -----------
Common Stock, par value $.01 per share 42,313,625
as of November 5, 2004
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BRIGHAM EXPLORATION COMPANY
THIRD QUARTER 2004 FORM 10-Q REPORT
TABLE OF CONTENTS
-----------------
PAGE
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PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Consolidated Balance Sheets - September 30, 2004 and December 31, 2003 . . . . . . . . . . . . . 1
Consolidated Statements of Operations - Three and nine months ended September 30, 2004 and 2003. 2
Consolidated Statement of Stockholders' Equity - Nine months ended September 30, 2004. . . . . . 3
Consolidated Statements of Cash Flows - Nine months ended September 30, 2004 and 2003. . . . . . 4
Notes to the Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . 5
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK . . . . . . . . . . . . . . . . . . 32
ITEM 4. CONTROLS AND PROCEDURES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS. . . . . . . . . . . . . . . . . . 34
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
SIGNATURES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
(UNAUDITED)
SEPTEMBER 30, DECEMBER 31,
2004 2003
--------------- --------------
ASSETS
(Unaudited)
Current assets:
Cash and cash equivalents $ 8,951 $ 5,779
Accounts receivable 11,191 11,143
Deferred income taxes 1,188 307
Other current assets 1,179 3,606
--------------- --------------
Total current assets 22,509 20,835
--------------- --------------
Oil and natural gas properties, net (full cost method) 245,312 197,311
Other property and equipment, net 1,114 1,219
Deferred income taxes - 1,890
Deferred loan fees 1,937 2,501
Other noncurrent assets 597 460
--------------- --------------
Total assets $ 271,469 $ 224,216
=============== ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 16,557 $ 19,806
Royalties payable 5,894 5,280
Accrued drilling costs 6,519 3,916
Participant advances received 551 1,179
Other current liabilities 4,512 5,398
--------------- --------------
Total current liabilities 34,033 35,579
--------------- --------------
Senior credit facility 23,500 19,000
Senior subordinated notes 20,000 20,000
Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption
value, 2,250,000 shares authorized, 466,599 and 439,722 shares issued and outstanding at
September 30, 2004 and December 31, 2003, respectively 9,332 8,794
Deferred income taxes 5,871 -
Other noncurrent liabilities 3,269 2,498
Commitments and contingencies
Stockholders' equity:
Preferred stock, $.01 par value, 10 million shares authorized, of which 2,250,000 shares are
designated as Series A and zero and 1,000,000 shares are designated as Series B, at
September 30, 2004 and December 31, 2003, respectively - -
Common stock, $.01 par value, 50 million shares authorized, 43,152,893 and 40,246,729 shares
issued and 41,971,535 and 39,086,096 shares outstanding at September 30, 2004 and
December 31, 2003, respectively 432 402
Additional paid-in capital 174,432 151,263
Treasury stock, at cost; 1,181,358 and 1,160,633 shares at September 30, 2004 and December
31, 2003, respectively (4,562) (4,402)
Unearned stock compensation (1,722) (1,816)
Accumulated other comprehensive income (loss) (1,698) (1,040)
Retained earnings (Accumulated deficit) 8,582 (6,062)
--------------- --------------
Total stockholders' equity 175,464 138,345
--------------- --------------
Total liabilities and stockholders' equity $ 271,469 $ 224,216
=============== ==============
<FN>
The accompanying notes are an integral part of these consolidated financial statements.
1
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------ -----------------------
2004 2003 2004 2003
----------- ----------- ----------- ----------
Revenues:
Oil and natural gas sales $ 17,240 $ 13,181 $ 51,975 $ 39,947
Other revenue 27 32 69 113
----------- ----------- ----------- ----------
17,267 13,213 52,044 40,060
----------- ----------- ----------- ----------
Costs and expenses:
Lease operating 1,648 1,793 4,362 4,037
Production taxes 675 553 2,434 2,297
General and administrative 1,304 1,094 3,723 3,420
Depletion of oil and natural gas properties 5,871 3,952 16,374 11,853
Depreciation and amortization 179 192 544 449
Accretion of discount on asset retirement obligations 40 39 117 110
----------- ----------- ----------- ----------
9,717 7,623 27,554 22,166
----------- ----------- ----------- ----------
Operating income 7,550 5,590 24,490 17,894
----------- ----------- ----------- ----------
Other income (expense):
Interest income 26 8 55 36
Interest expense (872) (1,271) (2,508) (3,777)
Other income (expense) (168) (80) (159) (250)
----------- ----------- ----------- ----------
(1,014) (1,343) (2,612) (3,991)
----------- ----------- ----------- ----------
Income before income taxes and cumulative effect of
change in accounting principle 6,536 4,247 21,878 13,903
----------- ----------- ----------- ----------
Income tax expense:
Current - - - -
Deferred (2,051) - (7,234) -
----------- ----------- ----------- ----------
(2,051) - (7,234) -
----------- ----------- ----------- ----------
Income before cumulative effect of change in accounting
principle 4,485 4,247 14,644 13,903
Cumulative effect of change in accounting principle - - - 268
----------- ----------- ----------- ----------
Net income 4,485 4,247 14,644 14,171
Less accretion and dividends on redeemable preferred stock - 904 - 2,927
----------- ----------- ----------- ----------
Net income available to common stockholders $ 4,485 $ 3,343 $ 14,644 $ 11,244
=========== =========== =========== ==========
Net income per share available to common stockholders:
Basic
Income before cumulative effect of change in accounting
principle $ 0.11 $ 0.16 $ 0.37 $ 0.54
Cumulative effect of change in accounting principle - - - 0.01
----------- ----------- ----------- ----------
$ 0.11 $ 0.16 $ 0.37 $ 0.55
=========== =========== =========== ==========
Diluted
Income before cumulative effect of change in accounting
principle $ 0.11 $ 0.13 $ 0.36 $ 0.42
Cumulative effect of change in accounting principle - - - 0.01
----------- ----------- ----------- ----------
$ 0.11 $ 0.13 $ 0.36 $ 0.43
=========== =========== =========== ==========
Weighted average shares outstanding:
Basic 41,227 21,210 39,921 20,340
=========== =========== =========== ==========
Diluted 42,340 30,751 41,078 32,406
=========== =========== =========== ==========
<FN>
The accompanying notes are an integral part of these consolidated financial statements.
2
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
(UNAUDITED)
ACCUMULATED RETAINED
COMMON STOCK ADDITIONAL UNEARNED OTHER EARNINGS
---------------- PAID IN TREASURY STOCK COMPREHENSIVE (ACCUMULATED
SHARES AMOUNTS CAPITAL STOCK COMPENSATION INCOME (LOSS) DEFICIT)
------ -------- ------------ ---------- -------------- --------------- --------------
Balance, December 31, 2003 40,247 $ 402 $ 151,263 $ (4,402) $ (1,816) $ (1,040) $ (6,062)
Comprehensive income:
Net income - - - - - - 14,644
Unrealized gain (losses) on
cash flow hedges - - - - - (1,217) -
Tax provisions related to
cash flow hedges - - - - - 354 -
Net losses realized and
included in net income - - - - - 205 -
Comprehensive income
Issuance of common stock 2,599 26 22,106 - - - -
Exercises of incentive stock
options 235 3 681 - - - -
Issuance of restricted stock - - 514 - (514) - -
Vesting of restricted stock 72 1 (1) - - - -
Forfeitures of restricted stock - - (131) (4) 131 - -
Repurchases of common
stock - - - (156) - - -
Amortization of unearned
stock compensation - - - - 477 - -
------ -------- ------------ ---------- -------------- --------------- --------------
Balance, September 30, 2004 43,153 $ 432 $ 174,432 $ (4,562) $ (1,722) $ (1,698) $ 8,582
====== ======== ============ ========== ============== =============== ==============
TOTAL
STOCKHOLDERS'
EQUITY
---------------
Balance, December 31, 2003 $ 138,345
Comprehensive income:
Net income 14,644
Unrealized gain (losses) on
cash flow hedges (1,217)
Tax provisions related to
cash flow hedges 354
Net losses realized and
included in net income 205
---------------
Comprehensive income 13,986
Issuance of common stock 22,132
Exercises of incentive stock
options 684
Issuance of restricted stock -
Vesting of restricted stock -
Forfeitures of restricted stock (4)
Repurchases of common
stock (156)
Amortization of unearned
stock compensation 477
---------------
Balance, September 30, 2004 $ 175,464
===============
<FN>
The accompanying notes are an integral part of these consolidated financial statements.
3
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
NINE MONTHS ENDED
SEPTEMBER 30,
-----------------------
2004 2003
----------- ----------
Cash flows from operating activities:
Net income $ 14,644 $ 14,171
Adjustments to reconcile net income to cash provided by operating
activities:
Depletion of oil and natural gas properties 16,374 11,853
Depreciation and amortization 544 449
Interest paid through issuance of additional senior subordinated notes - 888
Interest paid through issuance of additional mandatorily redeemable preferred stock 538 161
Amortization of deferred loan fees and debt issuance costs 574 809
Market value adjustment for derivative instruments 227 250
Accretion of discount on asset retirement obligations 117 110
Cumulative effect of change in accounting principle - (268)
Deferred income taxes 7,234 -
Changes in operating assets and liabilities:
Accounts receivable (48) 1,565
Gas imbalance receivable 2,435 (5,537)
Other current assets (8) 1,344
Accounts payable (3,249) (777)
Royalties payable 614 934
Participant advances received (628) (1,355)
Gas imbalance liability (2,064) 7,275
Other current liabilities 327 588
Other noncurrent assets and liabilities (126) (35)
----------- ----------
Net cash provided by operating activities 37,505 32,425
----------- ----------
Cash flows from investing activities:
Additions to oil and natural gas properties (61,160) (30,356)
Proceeds from sale of oil and natural gas properties - 1,183
Additions to other property and equipment (186) (247)
Decrease (Increase) in drilling advances paid (137) 18
----------- ----------
Net cash used by investing activities (61,483) (29,402)
----------- ----------
Cash flows from financing activities:
Proceeds from the issuance of common stock, net of issuance costs 22,132 40,000
Increase in senior credit facility 28,000 -
Repayment of senior credit facility (23,500) (47,000)
Deferred loan fees paid (10) (985)
Proceeds from exercise of incentive stock options 684 660
Repurchases of common stock (156) -
----------- ----------
Net cash provided (used) by financing activities 27,150 (7,325)
----------- ----------
Net increase (decrease) in cash and cash equivalents 3,172 (4,302)
Cash and cash equivalents, beginning of year 5,779 15,318
----------- ----------
Cash and cash equivalents, end of period $ 8,951 $ 11,016
=========== ==========
<FN>
The accompanying notes are an integral part of these consolidated financial statements.
4
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. ORGANIZATION AND NATURE OF OPERATIONS
Brigham Exploration Company ("Brigham"), a Delaware corporation formed on
February 25, 1997, explores and develops onshore domestic oil and natural gas
properties using 3-D seismic imaging and other advanced technologies. Brigham
focuses its exploration and development of onshore oil and natural gas
properties primarily in the onshore Gulf Coast, the Anadarko Basin, and West
Texas.
2. BASIS OF PRESENTATION
The accompanying consolidated financial statements include the accounts of
Brigham and its wholly-owned subsidiaries, and its proportionate share of
assets, liabilities and income and expenses of the joint operations in which
Brigham, or any of its subsidiaries, has a participating interest. All
significant intercompany accounts and transactions have been eliminated.
The accompanying consolidated financial statements are unaudited, and in
the opinion of management, reflect all adjustments that are necessary for a fair
presentation of the financial position and results of operations for the periods
presented. All such adjustments are of a normal and recurring nature. The
results of operations for the periods presented are not necessarily indicative
of the results to be expected for the entire year. The unaudited consolidated
financial statements should be read in conjunction with Brigham's 2003 Annual
Report on Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934.
STOCK BASED COMPENSATION
Brigham accounts for employee incentive stock-based compensation using the
intrinsic value method prescribed by Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees". Accordingly, Brigham has adopted the
disclosure-only provisions of Statement of Financial Accounting Standards No.
123, "Accounting for Stock-Based Compensation" ("SFAS 123") as amended by SFAS
148.
Had compensation cost for Brigham's stock options been determined based on
the fair market value at the grant dates of the awards consistent with the
methodology prescribed by SFAS 123, as amended by SFAS 148, Brigham's net income
and net income per share for the three and nine month periods ended September
30, 2004 and 2003 would have been the pro forma amounts indicated below:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------- --------------------------
2004 2003 2004 2003
------------ ----------- ------------- -----------
(in thousands, except per share amounts)
Net income available to common
stockholders - basic:
As reported $ 4,485 $ 3,343 $ 14,644 $ 11,244
Add back: Stock compensation expense
previously included in net income 103 5 340 10
Effect of total incentive stock-based
compensation expense, determined
under fair value method for all awards (916) (98) (1,908) (279)
------------ ----------- ------------- -----------
Pro forma $ 3,672 $ 3,250 $ 13,076 $ 10,975
============ =========== ============= ===========
5
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------- --------------------------
2004 2003 2004 2003
------------ ----------- ------------- -----------
(in thousands, except per share amounts)
Net income available to common
stockholders - diluted:
As reported $ 4,485 $ 4,032 $ 14,644 $ 13,959
Add back: Stock compensation expense
previously included in net income 103 5 340 10
Effect of total incentive stock-based
compensation expense, determined
under fair value method for all awards (916) (98) (1,908) (279)
------------ ----------- ------------- -----------
Pro forma $ 3,672 $ 3,939 $ 13,076 $ 13,690
============ =========== ============= ===========
Net income per share:
Basic:
As reported $ 0.11 $ 0.16 $ 0.37 $ 0.55
Pro forma 0.09 0.15 0.33 0.54
Diluted:
As reported $ 0.11 $ 0.13 $ 0.36 $ 0.43
Pro forma 0.09 0.13 0.32 0.42
3. COMMITMENTS AND CONTINGENCIES
Brigham is, from time to time, party to certain lawsuits and claims arising
in the ordinary course of business. While the outcome of lawsuits and claims
cannot be predicted with certainty, management does not expect these matters to
have a materially adverse effect on the financial condition, results of
operations or cash flows of Brigham.
On November 20, 2001, Brigham filed a lawsuit in the District Court of
Travis County, Texas, against Steve Massey Company, Inc. ("Massey"). The
Petition claims Massey furnished defective casing to Brigham, which ultimately
led to the casing failure of the Palmer 347 #5 well and the loss of the Palmer
#5 as a producing well. In 2004, the parties settled the case on terms favorable
to Brigham. Brigham received approximately $440,000 as a result of this
settlement, which reduced capitalized well costs. In addition, Massey dropped
its $445,819 counterclaim.
On July 11, 2002, an employee of a contractor on Brigham's Burkhart #1-R
location, Matagorda County, Texas, was involved in a fatal accident. The United
States Department of Labor Occupational Safety & Health Administration conducted
an inspection and, in October 2003, Brigham settled all issues resulting from
that inspection for $70,000.
On October 8, 2002, relatives of the contractor's employee filed a wrongful
death action in the district court for Matagorda County, Texas, against Brigham
and three of Brigham's contractors in connection with his accidental death.
Plaintiffs were seeking unspecified actual and punitive damages. On March 23,
2004, a jury determined that Brigham had no liability in the accidental death of
the contractor's employee. The plaintiffs filed a motion for a new trial. In
late October 2004, the judge granted plaintiffs a new trial. Brigham has not
recorded a contingent liability for this suit.
In September 2002, Brigham filed suit in the district court of Matagorda
County, Texas, against one of its contractors in connection with the drilling of
the Burkhart #1-R well. The suit claims that the contractor breached its
contract with Brigham and negligently performed services on the well, resulting
in damages of approximately $650,000. The contractor filed a counterclaim for
the recovery of approximately $315,000. The parties settled the case in April
2004 resulting in a payment by the contractor to Brigham and its
co-participants. In addition, the contractor dropped its counterclaim. Based on
the amount of the settlement, the
6
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
additional costs that were covered by insurance, and the insurer being
subrogated to Brigham's claim, Brigham's incremental recovery as a result of the
settlement was diminimus.
The operator of the Stonehocker #1 disputed Brigham's ownership interest in
the well. In January 2004, the Oklahoma Corporation Commission ruled in favor of
Brigham. The operator of the Stonehocker #1 appealed the ruling and the Oklahoma
Corporation Commission affirmed its original ruling in March 2004. The operator
has appealed the ruling to the Oklahoma Supreme Court.
A working interest owner that relinquished its ownership interest in the
Nold #1S well as a result of a non-consent election in the re-completion of the
well asserted that it did not relinquish its entire interest, but rather became
subject only to a 400 percent payout provision. In November 2003, the working
interest owner filed a lawsuit against Brigham for breach of contract. In April
2004, the parties negotiated a settlement that resulted in Brigham making a
payment of approximately $390,000 to the working interest owner in exchange for
an assignment of any interest owned by the working interest owner in this well.
In December 2003, Brigham filed a lawsuit in the United States District
Court for the Western District of Texas against another company and a former
employee concerning the defendants' misappropriation of Brigham's trade secrets
and breach of confidentiality obligations. Defendants denied any wrongdoing and
asserted a counterclaim against Brigham for alleged tortuous interference with
an existing business relationship between the company and its employee. The
parties settled the lawsuit in April 2004 on terms favorable to Brigham. The
settlement resulted in a $50,000 payment to Brigham, a small overriding royalty
interest assignment to Brigham in three tracts and an agreement to not compete
in specific areas covered by the confidential information. In addition, the
other company has dropped its counterclaim against Brigham.
4. NET INCOME PER SHARE
Basic earnings per share are computed by dividing net income available to
common stockholders by the weighted average number of common shares outstanding
for the period. The computation of diluted net income per share reflects the
potential dilution that could occur if securities or other contracts to issue
common stock were exercised or converted into common stock or resulted in the
issuance of common stock that would then share in the earnings of Brigham.
The following table reconciles the numerators and denominators of the basic
and diluted earnings per common share computations for net income available to
common stockholders for the three and nine months ended September 30, 2004 and
2003:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------- -------------------------
2004 2003 2004 2003
----------- ---------- ------------ -----------
(in thousands, except per share amounts)
Basic EPS:
Income (loss) available to common
stockholders before cumulative change
in accounting principle $ 4,485 $ 3,343 $ 14,644 $ 10,976
Cumulative change in accounting principle - - - 268
----------- ---------- ------------ -----------
Income (loss) available to common
stockholders $ 4,485 $ 3,343 $ 14,644 $ 11,244
=========== ========== ============ ===========
Common shares outstanding 41,227 21,210 39,921 20,340
=========== ========== ============ ===========
Basic EPS
Income (loss) available to common
stockholders before change in
accounting principle $ 0.11 $ 0.16 $ 0.37 $ 0.54
Cumulative change in accounting principle - - - 0.01
----------- ---------- ------------ -----------
$ 0.11 $ 0.16 $ 0.37 $ 0.55
=========== ========== ============ ===========
7
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------- -------------------------
2004 2003 2004 2003
----------- ---------- ------------ -----------
(in thousands, except per share amounts)
Diluted EPS:
Income (loss) available to common
stockholders before cumulative change
in accounting principle $ 4,485 $ 3,343 $ 14,644 $ 10,976
Cumulative change in accounting principle - - - 268
----------- ---------- ------------ -----------
Income (loss) available to common
stockholders 4,485 3,343 14,644 11,244
Adjustments for assumed conversions:
Dividends and accretion on mandatorily
redeemable preferred stock (1) - 689 - 2,715
----------- ---------- ------------ -----------
Income (loss) available to common
stockholders before change in
accounting principle-diluted 4,485 4,032 14,644 13,691
Cumulative change in accounting principle - - - 268
----------- ---------- ------------ -----------
Income (loss) available to common
stockholders-diluted $ 4,485 $ 4,032 $ 14,644 $ 13,959
=========== ========== ============ ===========
Common shares outstanding 41,227 21,210 39,921 20,340
Effect of dilutive securities:
Warrants - - - 402
Mandatorily redeemable preferred stock - 8,966 - 11,071
Stock options 1,113 575 1,157 593
----------- ---------- ------------ -----------
Potentially dilutive common shares 1,113 9,541 1,157 12,066
----------- ---------- ------------ -----------
Adjusted common shares outstanding
diluted 42,340 30,751 41,078 32,406
=========== ========== ============ ===========
Diluted EPS
Income (loss) available to common
stockholders before change in
accounting principle $ 0.11 $ 0.13 $ 0.36 $ 0.42
Change in accounting principle - - - 0.01
----------- ---------- ------------ -----------
$ 0.11 $ 0.13 $ 0.36 $ 0.43
=========== ========== ============ ===========
(1) The amount of dividends included in dividends and accretion on mandatorily
redeemable preferred stock includes only the dividends paid in kind on the
$40 million of mandatorily redeemable preferred stock (2.0 million shares)
that were issued with warrants whose exercise price is payable in either
cash or in shares of mandatorily redeemable preferred stock.
Options and warrants to purchase 656,000 shares and 2.1 million shares of
common stock were outstanding but not included in the calculation of diluted
earnings (loss) per share for the three months ended September 30, 2004 and
2003, respectively, and options and warrants to purchase 676,000 shares and
12,000 shares of common stock were outstanding but not included in the
calculation of diluted earnings (loss) per share for the nine months ended
September 30, 2004 and 2003, respectively, because the effects would have been
antidilutive.
8
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Brigham utilizes various commodity swap and option contracts to (i) reduce
the effects of volatility in price changes on the oil and natural gas
commodities it produces and sells, (ii) reduce commodity price risk and (iii)
provide a base level of cash flow in order to assure it can execute at least a
portion of its capital spending plans.
Brigham reports average oil and natural gas prices and revenues including
the net results of hedging activities. The following table sets forth Brigham's
oil and natural gas prices including and excluding the hedging gains and losses
and the increase or decrease in oil and natural gas revenues as a result of the
hedging activities for the three and nine month periods ended September 30, 2004
and 2003:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------ -----------------------
2004 2003 2004 2003
----------- ----------- ----------- ----------
NATURAL GAS
Average price per Mcf as reported (including hedging results) $ 5.44 $ 5.27 $ 5.68 $ 5.17
Average price per Mcf realized (excluding hedging results) $ 5.62 $ 5.72 $ 5.87 $ 6.16
Decrease in revenue (in thousands) $ (390) $ (738) $ (1,250) $ (4,584)
OIL
Average price per Bbl as reported (including hedging results) $ 36.82 $ 28.08 $ 33.51 $ 28.31
Average price per Bbl realized (excluding hedging results) $ 42.50 $ 30.30 $ 38.01 $ 31.08
Decrease in revenue (in thousands) $ (843) $ (356) $ (2,018) $ (1,554)
For the three months ended September 30, 2004 and 2003, ineffectiveness
associated with Brigham's derivative commodity instruments designated as cash
flow hedges decreased earnings by approximately $146,000 and $80,000,
respectively. For the nine months ended September 30, 2004 and 2003,
ineffectiveness associated with Brigham's derivative commodity instruments
designated as cash flow hedges decreased earnings by approximately $206,000 and
$250,000, respectively. These amounts are included in other income (expense).
9
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NATURAL GAS AND CRUDE OIL DERIVATIVE CONTRACTS
CASH-FLOW HEDGES
Brigham's cash-flow hedges consisted of fixed-price swaps and costless
collars (purchased put options and written call options). The fixed-price swap
agreements are used to fix the prices of anticipated future oil and natural gas
production. The costless collars are used to establish floor and ceiling prices
on anticipated future oil and natural gas production. There were no net premiums
received when Brigham entered into these option agreements. As of September 30,
2004, Brigham had entered into derivative contracts that qualify as cash flow
hedges with respect to future production as follows:
2004 2005
-------- --------------------------------------
FOURTH FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER QUARTER
-------- -------- -------- -------- --------
NATURAL GAS SWAPS:
Volumes (MMbtu). . . . . . 92,000 - - - -
Average price ($per MMBtu) $ 4.360 $ - $ - $ - $ -
NATURAL GAS COLLARS:
Volumes (MMbtu). . . . . . 726,100 727,500 455,000 - -
Average price ($per MMBtu)
Floor. . . . . . . . . . . $ 5.065 $ 5.164 $ 4.725 $ - $ -
Ceiling. . . . . . . . . . 6.873 7.256 6.712 - -
CRUDE OIL SWAPS:
Volumes (Bbls) . . . . . . 9,200 - - - -
Average price ($per Bbl) . $ 23.80 $ - $ - $ - $ -
CRUDE OIL COLLARS:
Volumes (Bbls) . . . . . . 34,260 27,450 18,655 - -
Average price ($per Bbl)
Floor. . . . . . . . . . . $ 26.38 $ 25.56 $ 26.80 $ - $ -
Ceiling. . . . . . . . . . 31.71 30.18 32.51 - -
As of September 30, 2004, Brigham's derivative positions included an option
contract that is not designated as a hedge. This contract was entered into to
offset the cost of other options that are designated as hedges.
2004 2005
-------- --------------------------------------
FOURTH FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER QUARTER
-------- -------- -------- -------- --------
NATURAL GAS WRITTEN PUTS:
Volumes (MMbtu). . . . . . 140,000 210,000 - - -
Average price ($per MMBtu) $ 5.500 $ 5.500 $ - $ - $ -
Derivative instruments not qualifying as hedging contracts are recorded at
fair value on the balance sheet. At each balance sheet date, the value of
derivatives not qualifying as hedging contracts is adjusted to reflect current
fair value and any gains or losses are recognized as other income or expense. At
September 30, 2004 and 2003, the fair value of these derivatives included in
other current liabilities was approximately $22,000 and $0, respectively. For
the three and nine months ended September 30, 2004, and 2003, other income
(expense) included approximately $21,000 and $0, respectively, in non-cash
losses related to changes in the fair values of these derivative contracts.
There were no cash settlement payments made by Brigham to the counterparty for
the three and nine months ended September 30, 2004 and 2003.
10
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
INTEREST RATE SWAP
Periodically, Brigham may use interest rate swap contracts to adjust the
proportion of its total debt that is subject to variable interest rates. Under
such an interest rate swap contract, Brigham agrees to pay an amount equal to a
specified fixed-rate of interest for a certain notional amount and receive in
return an amount equal to a variable-rate. The notional amounts of the contract
are not exchanged. No other cash payments are made unless the contract is
terminated prior to maturity. Although no collateral is held or exchanged for
the contract, the interest rate swap contract is entered into with a major
financial institution in order to minimize Brigham's counterparty credit risk.
The interest rate swap contract is designated as a cash flow hedge against
changes in the amount of future cash flows associated with Brigham's interest
payments on variable-rate debt. The effect of this accounting on operating
results is that interest expense on a portion of variable-rate debt being hedged
is recorded based on fixed interest rates.
At September 30, 2004, Brigham had an interest rate swap contract to pay a
fixed-rate of interest of 8.76% on $20.0 million notional amount of senior
subordinated notes. The $20.0 million notional amount of the outstanding
contract matures in March 2009. As of September 30, 2004, approximately $79,000
of unrealized losses are included in accumulated other comprehensive income
(loss) on the balance sheet and the fair value of the interest rate swap
agreement represents approximately $191,000 of other noncurrent liabilities. The
fair value of the interest rate swap contract is based on quoted market prices
and third-party provided calculations, which reflect the present values of the
difference between estimated future variable-rate receipts and future fixed-rate
payments.
FAIR VALUES
The fair value of commodity hedging and interest rate swap contracts is
reflected on the consolidated balance sheets as detailed in the following table.
The current asset and liability amounts represent the fair values expected to be
included in the results of operations for the next twelve months.
SEPTEMBER 30,
--------------------
2004 2003
--------- ---------
(in thousands)
Other current liabilities $ (2,970) $ (1,134)
Other noncurrent liabilities (428) (136)
Other current assets - 91
Other noncurrent assets 3 12
--------- ---------
$ (3,395) $ (1,167)
========= =========
6. ASSET RETIREMENT OBLIGATIONS
On January 1, 2003, Brigham adopted the provisions of Statement of
Financial Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations" ("SFAS 143"). 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 and a corresponding increase in the carrying amount of the
related long-lived asset. The liability is accreted to its present value each
period, and the capitalized cost is depreciated over the useful life of the
related asset. If the liability is settled for an amount other than the recorded
amount, a gain or loss is recognized. Brigham has asset retirement obligations
associated with the future plugging and abandonment of proved properties and
related facilities. Prior to the adoption of SFAS 143, Brigham assumed salvage
value approximated plugging and abandonment costs. As such, estimated salvage
value was not excluded from depletion and plugging and abandonment costs were
not accrued for over the life of the oil and gas properties.
The estimated liability is based on historical experience in plugging and
abandoning wells, estimated remaining lives of those wells, estimates as to the
cost to plug and abandon the wells in the future, and federal and state
regulatory requirements. The liability is discounted using an assumed
credit-adjusted risk-free interest
11
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
rate of 7.5%. Revisions to the liability could occur due to changes in estimates
of plugging and abandonment costs, changes in the risk-free interest rate or
remaining lives of the wells, or if federal or state regulators enact new
plugging and abandonment requirements.
The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect
adjustment to record (i) a $1.4 million increase in the carrying values of
proved properties, (ii) a $0.8 million decrease in accumulated depletion of oil
and natural gas properties and (iii) a $1.9 million increase in noncurrent
abandonment liabilities. The net impact of items (i) through (iii) was to record
a gain of $0.3 million as a cumulative effect adjustment of a change in
accounting principle in Brigham's consolidated statements of operations upon
adoption on January 1, 2003.
Brigham has no assets that are legally restricted for purposes of settling
asset retirement obligations. The following table summarizes Brigham's asset
retirement obligation transactions recorded in accordance with the provisions of
SFAS 143 during the three and nine months ended September 30, 2004:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------- ----------------------
2004 2003 2004 2003
----------- ---------- ----------- ---------
(in thousands)
Beginning asset retirement obligations $ 2,665 $ 2,062 $ 2,320 $ 1,931
Liabilities incurred for new wells placed on
production 58 82 394 142
Liabilities settled (24) - (92) -
Accretion of discount on asset retirement
obligations 40 39 117 110
----------- ---------- ----------- ---------
Ending asset retirement obligations $ 2,739 $ 2,183 $ 2,739 $ 2,183
=========== ========== =========== =========
7. INCOME TAXES
The provision for income taxes was computed in accordance with
Interpretation No. 18 of Accounting Principles Board Opinion (APB) No. 28 on
reporting taxes for interim periods and accordingly was based on the projection
of total 2004 pretax income. Interpretation No. 18 of APB 28 provides that
interim income taxes should be computed using the projected effective tax rate
on the total projected pretax income for the year.
At September 30, 2004, management believes that Brigham will (i) begin to
utilize net operating losses (NOLs) and (ii) have reversals of existing
temporary differences between book and taxable income sufficient to result in a
deferred tax liability at year-end 2004. Management also believes that it is
more likely than not that capital loss carryforwards of approximately $1.8
million may expire unused and, accordingly, has established a valuation
allowance of $0.6 million. The components of deferred income tax assets and
liabilities are as follows:
SEPTEMBER 30, DECEMBER 31,
2004 2003
-------------- --------------
(in thousands)
Deferred tax assets
Current:
Net operating loss carryforwards $ - $ 451
Unrealized hedging losses 914 -
Derivative assets 274 -
-------------- --------------
1,188 451
-------------- --------------
12
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
SEPTEMBER 30, DECEMBER 31,
2004 2003
--------------- --------------
(in thousands)
Non-current:
Net operating loss carryforwards 35,614 34,409
Capital loss carryforwards 642 634
Stock compensation 680 818
Unrealized hedging losses - 561
Derivative assets - 276
Asset retirement obligations 958 812
Preferred stock dividends as interest expense 307 119
Other 27 27
--------------- --------------
Non-current 38,228 37,656
--------------- --------------
39,416 38,107
--------------- --------------
Deferred tax liabilities
Current:
Gas imbalances - (144)
Non-current:
Depreciable and depletable property (43,279) (35,132)
Other (186) -
--------------- --------------
Non-current (43,465) (35,132)
--------------- --------------
(43,465) (35,276)
--------------- --------------
Net deferred tax assets (liabilities) (4,049) 2,831
Valuation allowance (634) (634)
--------------- --------------
$ (4,683) $ 2,197
=============== ==============
At September 30, 2004, Brigham has regular tax NOLs of approximately $101.8
million. Additionally, Brigham has approximately $87.6 million of alternative
minimum tax ("AMT") NOLs available as a deduction against future taxable income.
The NOLs expire from 2012 through 2024. The value of these NOLs depends on the
ability of Brigham to generate taxable income.
In addition, at September 30, 2004, Brigham has capital loss carryforwards
of approximately $1.8 million that expire in varying years through 2007.
Brigham believes it has a $4.5 million annual limitation on the utilization
of certain of its NOLs under Internal Revenue Code Section 382 due to a
potential 50% change in ownership among its 5% stockholders over a three-year
period.
8. ISSUANCE OF COMMON STOCK
During July and August 2004, Brigham completed the sale of 2,598,500 shares
of its common stock under a universal shelf registration statement declared
effective by the Securities and Exchange Commission in June 2004. Net proceeds
from the stock sale of approximately $22.1 million were used to repay
outstanding borrowings under the senior credit facility. Brigham plans to
reborrow the repaid amounts under the senior credit facility as necessary to
fund future exploration and development activities and for general corporate
purposes.
9. ACCOUNTING PRONOUNCEMENTS
In September 2004, the Securities and Exchange Commission (SEC) issued
Staff Accounting Bulletin No. 106. This pronouncement will require companies
that use the full cost method for accounting for their oil and gas producing
13
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
activities to include an estimate of future asset retirement costs to be
incurred as a result of future development activities on proved reserves in
their calculation of depreciation, depletion and amortization. This
pronouncement will also require these companies to exclude any future cash
outflows associated with settling asset retirement liabilities from their full
cost ceiling test calculation. This standard will also require these companies
to disclose the impact of their asset retirement obligations on their oil and
gas producing activities, ceiling test calculations and depreciation, depletion
and amortization calculations. Brigham will adopt the provisions of this
pronouncement in the fourth quarter of 2004 and is currently evaluating the
impact, if any, on our consolidated financial statements.
14
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following updates information as to our financial condition provided in
our 2003 Annual Report on Form 10-K, and analyzes the changes in the results of
operations between the three and nine month periods ended September 30, 2004,
and the comparable periods of 2003. For definitions of commonly used oil and gas
terms as used in this Form 10-Q, please refer to the "Glossary of Oil and Gas
Terms" provided in our 2003 Annual Report on Form 10-K.
OVERVIEW OF FIRST NINE MONTHS OF 2004
For the quarter and nine-month periods ended September 30, 2004, our net
capital expenditures for oil and natural gas activities were $24.4 million and
$64 million, respectively. Our drilling capital expenditures alone for the
third quarter 2004 were up approximately 122% over the amount we spent in the
third quarter of last year. For the nine months ended September 30, 2004, our
net capital expenditures for oil and natural gas activities are up approximately
126% when compared to the first nine months of last year. Our operating
performance for the third quarter and first nine months of 2004 was highlighted
by production of 34 MMcfe/d and 34.1 MMcfe/d, respectively. This represents a
17% growth in production over the amount we produced in the third quarter of
2003 and a 15% increase over the amount we produced in the first nine months of
2003. The increase in our production is primarily the result of the increase in
drilling capital expenditures during the fourth quarter of last year and the
first nine months of 2004.
Net income to common stockholders for the third quarter 2004 was $4.5
million, or $0.11 per diluted share, on total revenues of $17.3 million. This
compares to reported net income of $3.3 million, or $0.13 per diluted share on
total revenues of $13.2 million in the third quarter last year.
For the nine month period ended September 30, 2004, our reported net income
to common stockholders was $14.6 million, or $0.36 per diluted share, on total
revenues of $52 million. This compares to reported net income of $11.2 million,
or $0.43 per diluted share, on revenue of $40.1 million for the first nine
months of last year. Net cash provided by operating activities funded
approximately 61% of the cash used in our capital expenditure program during the
first nine months of 2004. During the third quarter of 2004, we sold 2,598,500
shares of our common stock under a universal shelf registration statement
declared effective by the Securities and Exchange Commission in June 2004. Net
proceeds from the stock sale were approximately $22.1 million and were used to
repay outstanding indebtedness under our senior credit facility. "Net proceeds"
is the amount we received after paying the underwriting discount and other
expenses related to offering. We intend to reborrow the repaid amount to fund
future exploration and development activities, including taking advantage of
opportunities to retain larger working interests in wells and in 3-D seismic
programs and for general corporate purposes.
At September 30, 2004, we had $9 million in cash, total assets of $271.5
million and a debt to total book capitalization ratio of 23%.
15
OUTLOOK FOR THE REMAINDER OF 2004
ESTIMATED ORIGINAL
2004 2004
SPENDING BUDGET % CHANGE
---------- --------- ---------
(IN THOUSANDS)
Drilling . . . . . . . . . . . . . . . . . . . . . . . $ 69,280 $ 61,432 13%
Land and G&G . . . . . . . . . . . . . . . . . . . . . 16,589 11,973 39%
Capitalized interest and G&A . . . . . . . . . . . . . 6,085 5,535 10%
---------------------
Net capital expenditures on oil and gas activities $ 91,954 $ 78,940 16%
Other property and equipment . . . . . . . . . . . . . 474 473 0%
---------------------
Net capital expenditures . . . . . . . . . . . . . $ 92,428 $ 79,413 16%
=====================
Current Estimated Capital Expenditures for 2004
Approximately $40.2 million, or 58%, of our estimated drilling capital
expenditures for 2004 will be allocated to drill 23 wells in our onshore Texas
Gulf Coast region. For 2004, our drilling activities in our onshore Gulf Coast
region will be focused on the Vicksburg and Frio Trends where we will drill 11
development wells with an average working interest of 61% and 12 exploratory
wells with an average working interest of 68%. Of the wells we currently plan
to drill in 2004, 14 of the wells had reached total depth as of September 30,
2004.
In the Vicksburg, we currently estimate that we will spend approximately
$19.4 million to drill four development wells with an average working interest
of 51% and three exploration wells with an average working interest of 71%. As
of September 30, 2004, four of the wells budgeted for 2004 had reached total
depth and one well was drilling. We currently plan to spud the remaining two
Vicksburg wells in our 2004 drilling program in the fourth quarter of this year.
In the Frio, we currently estimate that we will spend approximately $20.7
million to drill seven development wells with an average working interest of 66%
and nine exploration wells with an average working interest of 67%. As of
September 30, 2004, ten of the wells in budgeted for 2004 had reached total
depth and one was drilling. We currently plan to spud the remaining five Frio
wells in the fourth quarter of this year.
Approximately $26.8 million, or 39%, of our currently estimated drilling
capital expenditures for 2004 will be allocated to drill 37 wells in our
Anadarko Basin region. The majority of our drilling capital allocated to our
Anadarko Basin region will be focused on the Hunton/Arbuckle, Springer Channel
and Springer Bar Trends. For 2004, we currently plan to drill 30 development
wells with an average working interest of 29% and seven exploratory wells with
an average working interest of 16% in our Anadarko Basin region. Of the wells
currently plan to drill in 2004, 24 had reached total depth as of September 30,
2004.
We currently estimate that we will spend approximately $13.1 million to
drill two Hunton/Arbuckle development wells with an average working interest of
96%. As of September 30, 2004, one well had reached total depth and we expect
to spud the remaining well in the fourth quarter of this year.
For the Springer Channel, we currently estimate that we will spend
approximately $4.7 million to drill seven development wells with an average
working interest of 41% and five exploratory wells with an average working
interest of 18%. As of September 30, 2004, nine of these wells had reached
total depth of which three were completing and one well was drilling. We
currently plan to spud the remaining two wells in the fourth quarter of this
year.
For the Springer Bar, we currently estimate that we will spend
approximately $2.3 million to drill seven development wells with an average
working interest of 12%. As of September 30, 2004, one well was drilling and
four wells, of which two were completing, had reached total depth. We currently
plan to spud the remaining three wells in the fourth quarter of this year.
16
Additional estimated capital expenditures for the Anadarko Basin region in
2004 includes $4 million to drill 13 development wells in the granite wash
formation with and average working interest of 22%. As of September 30, 2004,
eight of these granite wash wells reached total depth and two were drilling. We
currently plan to spud the remaining two wells in the fourth quarter. We also
plan to spend $2.5 million to drill two Grady County Bromide tests with an
average working interest of 16%, a combined Hunton/Springer Channel test with a
17% working interest and for other various drilling activities. As of September
30, 2004, one of the Bromide tests and the combined Hunton/Springer Channel test
had reached total depth. The other Bromide test was drilling at September 30,
2004.
We currently plan to spend approximately $2.3 million, or 3%, of our
estimated 2004 drilling capital expenditures, to drill two exploratory wells in
our West Texas region with an average working interest of 94%. As of September
30, 2004, one well had reached total depth and was completing. The other well
was drilling at the end of the third quarter.
Approximately 18% of current estimated 2004 capital expenditures will be
used to fund land and seismic acquisitions in an effort to add to our inventory
of drilling projects in current focus plays. We believe that our cash on hand at
September 30, 2004, net cash provided by operating activities, net proceeds from
our sale of common stock in July and August 2004 and the remaining availability
under our senior credit facility will fund our spending for the remainder of the
year. Our estimated net capital expenditures for 2004 represent an increase of
approximately 96% over the amount that we spent in 2003.
The final determination with respect to our 2004 budgeted expenditures will
depend on a number of factors, including:
- commodity prices;
- production from our existing producing wells;
- the results of our current exploration and development drilling
efforts;
- economic and industry conditions at the time of drilling, including
the availability of drilling equipment; and
- the availability of more economically attractive prospects.
There can be no assurance that the budgeted wells will, if drilled,
encounter commercial quantities of natural gas or oil.
17
CAPITAL COMMITMENTS
Net cash provided by operating activities, net proceeds from the sale of
common stock and additional borrowings from our senior credit facility were our
primary sources of cash during the first nine months of 2004. This cash was used
to fund the costs associated with drilling, land acquisition and 3-D seismic
acquisition, processing and interpretation. We believe our cash on hand at the
end of the third quarter 2004, net cash provided by operating activities, net
proceeds from our sale of common stock in July and August 2004 and the remaining
availability under our senior credit facility will be sufficient to fund our
budgeted capital expenditures for the remainder of 2004.
Capital Expenditures
The timing of most of our capital expenditures is discretionary because we
have no material long-term capital expenditure commitments. Consequently, we
have a significant degree of flexibility to adjust the level of our capital
expenditures as circumstances warrant. The table below lists our capital
expenditures for the first nine months of 2004 and 2003.
NINE MONTHS ENDED SEPTEMBER 30,
----------------------------------------
2004 2003 % CHANGE
---------- -------------- ------------
(IN THOUSANDS)
Drilling . . . . . . . . . . . . . . . . . . . . . . . $ 48,638 $ 20,542 137%
Land and G&G . . . . . . . . . . . . . . . . . . . . . 10,749 3,135 243%
Capitalized interest and G&A . . . . . . . . . . . . . 4,595 4,622 (1%)
Proceeds from the sale of oil and gas properties . . . - (23) (100%)
--------------------------
Net capital expenditures on oil and gas activities $ 63,982 $ 28,276 126%
Other property and equipment . . . . . . . . . . . . . 186 247 (25%)
--------------------------
Net capital expenditures . . . . . . . . . . . . . $ 64,168 $ 28,523 125%
==========================
LIQUIDITY AND CAPITAL RESOURCES
Cash flows from operating activities
During the first nine months of 2004, net cash provided by operating
activities, net proceeds from the sale of common stock and additional borrowings
from our senior credit facility were our primary source of cash. This cash was
used to fund the costs associated with drilling, land acquisition and 3-D
seismic acquisition, processing and interpretation.
NINE MONTHS ENDED SEPTEMBER 30,
--------------------------------------
2004 2003 % CHANGE
---------- ------------- -----------
(IN THOUSANDS)
Net cash provided by operating activities $ 37,505 $ 32,425 16%
The 16% increase in net cash provided by operating activities is primarily
related to the following:
- - An increase in oil and natural gas sales resulted in a $9.1 million
increase in net cash provided by operating activities.
- - An increase in revenue due to a decline in losses from the settlement of
derivative contracts resulted in a $2.9 million increase in net cash
provided by operating activities.
These increases were partially offset by the following:
- - The repayment of accounts payable in excess of collections of accounts
receivable reduced net cash provided by
18
operating activities by $4.1 million.
- - The settlement of the gas imbalance with our industry participant in our
Diablo project reduced net cash provided by operating activities by $1.4
million.
- - An increase in production costs and general and administrative expenses
reduced net cash provided by operating activities by $765,000.
- - A decrease in royalties payable of $320,000.
Working capital is the amount by which current assets exceed current
liabilities. It is normal for us to report a working capital deficit at the end
of a period. These deficits are primarily the result of accounts payable related
to lease operating expenses, exploration and development costs, liabilities
related to derivative contracts and royalties payable. Settlement of these
payables will be funded by cash flows from operations or, if necessary, by
additional borrowing under our senior credit facility. At September 30, 2004,
we had a working capital deficit of $11.5 million compared to a working capital
deficit of $14.7 million at December 31, 2003. Current liabilities at September
30, 2004, included a liability of $3 million related to the fair value of our
open derivative contracts.
Cash flows from financing activities
Common stock transactions
- -------------------------
- - During the third quarter 2004, we sold 2,598,500 shares of our common stock
under a universal shelf registration statement declared effective by the
Securities and Exchange Commission in June 2004. We received net proceeds
of approximately $22.1 million and used the net proceeds from the offering
to repay outstanding indebtedness under our senior credit facility. "Net
proceeds" is the amount we received after paying the underwriting discount
and other expenses related to offering.
- - We issued 126,600 shares of common stock and received $310,000 in net
proceeds related to the exercise of employee and director stock options in
the first quarter of 2004, issued 81,481 shares of common stock and
received $288,000 in net proceeds in the second quarter of 2004 and issued
27,500 shares of common stock and received $86,000 in net proceeds in the
third quarter 2004.
- - During January and June of 2004, we acquired 19,596 and 821 shares of our
common stock, respectively, from certain employees to satisfy
tax-withholding obligations associated with the vesting of stock grants.
The transferred shares were valued at fair market value as of the date of
surrender.
- - In September 2003, we sold 7,384,090 shares of common stock and received
$40 million in net proceeds. The net proceeds from the sale were used to
increase the amount of capital spent on our exploration and development
activities. Pending such use, the net proceeds were used to repay $40
million of the borrowings outstanding under our senior credit facility.
- - We issued 171,800 shares of common stock and received $432,000 in net
proceeds related to the exercise of employee and director stock options in
the first quarter of 2003, issued 52,793 and received net proceeds of
$162,000 in the second quarter of 2003 and issued 25,042 shares of common
stock and received net proceed of $66,000 in the third quarter of 2003.
- - In the first quarter of 2003, we issued 248,028 unregistered shares of our
common stock to a group of institutional investors. The shares were issued
to the group in connection with the cashless exercise of warrants that it
owned and we received no proceeds from the exercise of the warrants.
- - In June 2003, we issued 408,928 and 206,982 unregistered shares of our
common stock to the Bank of Montreal and Soci t G n rale, respectively. We
received no proceeds from the exercise of these warrants as both parties
elected to execute a cashless exercise of the warrants. Both parties sold
the shares from this exercise in our common stock sale in September 2003.
We received no proceeds from the sale.
Senior credit facility
- ----------------------
Future outstanding balances under our senior credit facility are dependent
primarily on our level of capital expenditures, net cash provided by operating
activities and the proceeds from other financing activities. Our committed
borrowing capacity under our senior credit facility at September 30, 2004, was
$23.5 million, with a $68.5 million borrowing base that is subject to adjustment
on the basis of the present value of estimated future net cash flows from proved
oil and gas reserves (as determined by the lender's petroleum engineer). Our
unused committed borrowing base capacity under our senior credit facility was
$44.5 million at November 5, 2004.
During the first nine months of 2004 we borrowed $28 million of additional
debt from our senior credit facility to fund our working capital obligations and
capital expenditures and repaid $23.5 million. During the first nine
19
months of 2003, we repaid $47 million of the debt outstanding under our senior
credit facility and paid $985,000 in fees related to our new credit facility
that was put in place in March 2003.
Our current ratio, as defined by the senior credit facility, at September
30, 2004 and interest coverage ratio for the twelve-month period ending
September 30, 2004, were 2 to 1 and 13.7 to 1, respectively. As of September
30, 2004, we were in compliance with the covenants of our senior credit
facility.
Senior subordinated notes
- -------------------------
Our current ratio, as defined by the senior credit facility, at September
30, 2004 and interest coverage ratio for the twelve-month period ending
September 30, 2004, were 2 to 1 and 13.7 to 1, respectively. Our ratio of
risked net present value (as defined) discounted at 9% to total debt at June 30,
2004, was 2.3 to 1, and was in compliance with the subordinated notes covenant
that requires us to maintain a ratio of 1.5 to 1. As of September 30, 2004, we
were in compliance with the covenants of our senior subordinated notes.
RESULTS OF OPERATIONS
Comparison of the three and nine month periods ended September 30, 2004 and 2003
Production.
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
----------------------------------------- -----------------------------------------
2004 2003 % CHANGE 2004 2003 % CHANGE
---------- ------------- -------------- ---------- ------------- --------------
Oil (MBbls). . . . . . . . . . . . . 148 160 (7%) 449 562 (20%)
Natural gas (MMcf) . . . . . . . . . 2,167 1,648 31% 6,506 4,648 40%
Natural gas equivalent (MMcfe) . . 3,057 2,608 17% 9,199 8,019 15%
Average daily production (MMcfe/d) 34.0 29.0 17% 34.1 29.7 15%
% Natural gas. . . . . . . . . . . 71% 63% 71% 58%
The increase in our production volumes was due to organic production growth
from wells that we drilled and completed in the fourth quarter of 2003 and the
first nine months of 2004. New production related to these recently completed
wells was partially offset by the natural decline of existing production.
Revenues from the sale of oil and natural gas. Reported revenues from the
sale of oil and natural gas are based on the market price we receive for our
commodities, adjusted for marketing charges and the results from the settlement
of our derivative commodity contracts that have been designated as cash flow
hedges under SFAS 133.
We utilize fixed price swaps, costless collars, three way costless collars
and floor contracts to (i) reduce the effect of price volatility on the
commodities that we produce and sell, (ii) reduce commodity price risk and (iii)
provide a base level of cash flow in order to assure we can execute at least a
portion of our capital spending plans. See "Item 3. Quantitative and
Qualitative Disclosures About Market Risk" for a list of our open derivative
commodity contracts at September 30, 2004."
The effective portions of changes in the fair values of our derivative
commodity contracts that are designated as cash flow hedges is recorded as
increases or decreases to stockholders' equity until the underlying contract is
settled. Consequentially, these changes could add volatility to our reported
stockholders' equity until the contract is settled or is terminated.
Derivative commodity contracts that do not meet the hedge criteria of SFAS
133 are not designated as hedges. Gains or losses related to the settlement,
the ineffective portion of changes in the fair market value and the changes in
the fair values of our derivative commodity contracts that are not designated as
cash flow hedges are recognized in other income (expense).
20
The following table presents revenues that we realized from the sale of oil
and natural gas during the third quarter and first nine months of 2004 and 2003.
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
----------------------------------- --------------------------------------
2004 2003 % CHANGE 2004 2003 % CHANGE
--------- ---------- ------------ ---------- ------------ ------------
(IN THOUSANDS)
Oil sales . . . . . . . . . . . . . . . . . . . . . . $ 6,304 $ 4,847 30% $ 17,058 $ 17,459 (2%)
Loss due to hedging . . . . . . . . . . . . . . . . . (843) (356) 137% (2,018) (1,554) 30%
--------- ---------- ------------------------
Total revenues from the sale of oil . . . . . . . . $ 5,461 $ 4,491 22% $ 15,040 $ 15,905 (5%)
========= ========= ========================
Natural gas sales . . . . . . . . . . . . . . . . . . $ 12,169 $ 9,428 29% $ 38,185 $ 28,627 33%
Loss due to hedging . . . . . . . . . . . . . . . . . (390) (738) (47%) (1,250) (4,585) (73%)
--------- ---------- ------------------------
Total revenues from the sale of natural gas . . . . $ 11,799 $ 8,690 36% $ 36,935 $ 24,042 54%
========= ========= ========================
Oil and natural gas sales . . . . . . . . . . . . . . $ 18,473 $ 14,275 29% $ 55,243 $ 46,086 20%
Loss due to hedging . . . . . . . . . . . . . . . . . (1,233) (1,094) 13% (3,268) (6,139) (47%)
--------- ---------- ------------------------
Total revenues from the sale of oil and natural gas $ 17,240 $ 13,181 31% $ 51,975 $ 39,947 30%
========= ========= ========================
AVERAGE PRICES:
(PER BBL)
Oil sales . . . . . . . . . . . . . . . . . . . . . . $ 42.50 $ 30.30 40% $ 38.01 $ 31.08 22%
Loss due to hedging . . . . . . . . . . . . . . . . . (5.68) (2.22) 156% (4.50) (2.77) 62%
--------- ---------- ------------------------
Realized Oil price. . . . . . . . . . . . . . . . . $ 36.82 $ 28.08 31% $ 33.51 $ 28.31 18%
========= ========= ========================
(PER MCF)
Natural gas sales . . . . . . . . . . . . . . . . . . $ 5.62 $ 5.72 (2%) $ 5.87 $ 6.16 (5%)
Loss due to hedging . . . . . . . . . . . . . . . . . (0.18) (0.45) (60%) (0.19) (0.99) (81%)
--------- ---------- ------------------------
Realized natural gas price. . . . . . . . . . . . . $ 5.44 $ 5.27 3% $ 5.68 $ 5.17 10%
========= ========= ========================
(PER MCFE)
Natural gas equivalent sales. . . . . . . . . . . . . $ 6.04 $ 5.47 10% $ 6.01 $ 5.75 5%
Loss due to hedging . . . . . . . . . . . . . . . . . (0.40) (0.42) (5%) (0.36) (0.77) (53%)
--------- ---------- ------------------------
Realized natural gas equivalent price . . . . . . . $ 5.64 $ 5.05 12% $ 5.65 $ 4.98 13%
========= ========= ========================
Total revenues from the sale of oil and natural gas for the third quarter
2004 were 31% higher than revenues in same period of 2003. The increase was
primarily due the following:
- - A $2.6 million increase to total revenues from the sale of oil and natural
gas due to a 17% increase in production volumes for the third quarter 2004.
- - A $1.6 million increase to total revenues from the sale of oil and natural
gas due to a 10% increase in the average sales price we received for oil
and natural gas.
- - A 13% increase in losses related to the settlement of hedging contracts
resulted in a $139,000 decrease in total revenues from the sale of oil and
natural gas.
Total revenues from the sale of oil and natural gas for the first nine
months of 2004 were 30% higher than revenues in the same period of 2003. The
increase was primarily due to the following:
21
- - An $7.9 million increase to total revenues from the sale of oil and natural
gas due to a 15% increase in production volumes during the first nine
months of 2004.
- - A $1.2 million increase in total revenues from the sale of oil and natural
gas due to a 5% increase in the average sales price we received for oil and
natural gas during the first nine months of 2004.
- - A 47% decrease in losses related to the settlement of hedging contracts
resulted in a $2.9 million increase in total revenues from the sale of oil
and natural gas.
The table below presents our derivative commodity contracts, the volumes,
the weighted average NYMEX reference price for those volumes, and the associated
gain or loss upon settlement of those contracts during the third quarter and
first nine months of 2004 and 2003.
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
--------------------------------------- --------------------------------------
% %
2004 2003 CHANGE 2004 2003 CHANGE
-------------- --------- ------------ ----------- ----------- ------------
OIL SWAPS
Volumes (Bbls). . . . . . . . . . . 13,800 55,200 (75%) 63,850 184,125 (65%)
Average swap price (per Bbl). . . . $ 23.91 $ 23.77 1% $ 24.77 $ 24.81 (0%)
Loss upon settlement (in thousands) $ (275) $ (356) (23%) $ (848) $ (1,157) (27%)
OIL COLLARS
Volumes (Bbls). . . . . . . . . . . 48,760 - - 144,310 45,250 219%
Average floor price (per Bbl) . . . $ 26.43 $ - - $ 24.51 $ 18.00 36%
Average ceiling price (per Bbl) . . 32.20 - - 31.09 22.56 38%
Loss upon settlement (in thousands) $ (568) $ - - $ (1,170) $ (397) 195%
NATURAL GAS SWAPS
Volumes (MMbtu) . . . . . . . . . . 138,000 598,000 (77%) 661,250 2,249,500 (71%)
Average swap price (per MMbtu). . . $ 4.180 $ 3.867 8% $ 4.555 $ 3.772 21%
Loss upon settlement (in thousands) $ (230) $ (738) (69%) $ (836) $ (4,585) (82%)
NATURAL GAS COLLARS
Volumes (MMbtu) . . . . . . . . . . 722,200 - - 1,777,800 - -
Average floor price (per MMbtu) $ 4.613 $ - - $ 4.319 $ - -
Average ceiling price (per MMbtu) 6.476 - - 6.847 - -
Loss upon settlement (in thousands) $ (160) $ - - $ (414) $ - -
NATURAL GAS FLOORS
Volumes (MMbtu) . . . . . . . . . . - 460,000 (100%) - 610,000 (100%)
Average floor price (per MMbtu) . . $ - $ 4.50 (100%) $ - $ 4.500 (100%)
Loss upon settlement (in thousands) $ - $ - - $ - $ - -
Other revenue. Fees that we charge other parties who use our two gas
gathering systems to move their production from the wellhead to third party gas
pipeline systems are recorded as other revenue. These gathering systems are
owned by us and located in the Texas Gulf Coast. One of the gathering systems
connects a single well and the other connects two wells. Other revenue for the
third quarter of 2004 was $27,000 compared to $32,000 in the third quarter last
year. Other revenue for the nine months of 2004 was $69,000 compared to
$113,000 during the first nine months of 2003.
22
Production cost. Production costs include lease operating expenses and
production taxes. The following table presents our production cost for the
third quarter and first nine months of 2004 and 2003.
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
------------------------------------------- ------------------------------------------
% %
2004 2003 CHANGE 2004 2003 CHANGE
------------ ------------- -------------- ----------- ------------- --------------
(IN THOUSANDS)
Operating and maintenance expenses $ 1,201 $ 1,061 13% $ 3,248 $ 2,678 21%
Workover expenses. . . . . . . . . 278 563 (51%) 617 860 (28%)
Ad valorem taxes . . . . . . . . . 169 169 0% 497 499 (0%)
------------ ------------- --------------------------
Lease operating expenses . . . $ 1,648 $ 1,793 (8%) $ 4,362 $ 4,037 8%
Production taxes . . . . . . . . . 675 553 22% 2,434 2,297 6%
------------ ------------- --------------------------
Total production cost. . . . . $ 2,323 $ 2,346 (1%) $ 6,796 $ 6,334 7%
============ ============= ==========================
(PER MCFE)
Operating and maintenance expenses $ 0.39 $ 0.41 (5%) $ 0.35 $ 0.33 6%
Workover expenses. . . . . . . . . 0.09 0.22 (59%) 0.07 0.11 (36%)
Ad valorem taxes . . . . . . . . . 0.06 0.06 0% 0.05 0.06 (17%)
------------ ------------- --------------------------
Lease operating expenses . . . $ 0.54 $ 0.69 (22%) $ 0.47 $ 0.50 (6%)
Production taxes . . . . . . . . . 0.22 0.21 5% 0.26 0.29 (10%)
------------ ------------- --------------------------
Total production cost. . . . . $ 0.76 $ 0.90 (16%) $ 0.73 $ 0.79 (8%)
============ ============= ==========================
Lease operating expenses
- ------------------------
Lease operating expenses are comprised of several components which include:
the cost of labor and supervision to operate the wells and related equipment;
repairs and maintenance; related materials, supplies, fuel, and supplies
utilized in operating the wells and related equipment and facilities; insurance
applicable to wells and related facilities and equipment; workover cost; and ad
valorem taxes. Lease operating expenses are driven in part by the type of
commodity produced, the level of workover activity and the geographical location
of the properties. Oil is inherently more expensive to produce than natural gas.
Local taxing authorities such as school districts, cities, and counties or
boroughs generally impose the ad valorem taxes we pay. The amount of the tax is
based on the value of the property assessed or determined by the taxing
authority on an annual basis, and a percent of value. When oil and natural gas
commodity prices rise, the value of our underlying property interests increase.
This results in higher ad valorem taxes.
Lease operating expenses for the third quarter 2004 were 8% lower than
lease operating expenses in the third quarter last year. The change was
primarily due to the following:
- - A decrease in the cost of expensed workovers led to a 51% decrease in
workover costs for the third quarter of this year.
- - This decrease was partially offset by an increase in our operating and
maintenance expenses due to an increase in the number of producing wells.
On a unit basis, lease operating expenses for the third quarter 2004 were
22% lower than in the third quarter last year due to the decrease in workover
cost and an increase in production volumes.
23
Lease operating expenses for the first nine months of 2004 were 8% higher
than lease operating expenses during the first nine months of 2003. The change
was primarily due to the following:
- - An increase in the number of producing wells in the first nine months of
2004.
- - An increase in the amount spent for compressor rental and maintenance and
saltwater disposal.
- - These increases were partially offset by a decrease in the cost of expensed
workovers during the first nine months of 2004.
On a unit basis, lease operating expenses for the first nine months of 2004
were 6% lower than our per unit lease operating expenses in the same period of
the prior year. The change in our per unit lease operating expense was
primarily due an increase in production volumes during the first nine months of
2004 combined with the following:
- - A decrease in the cost of expensed workovers during the first nine months
of 2004.
- - A $0.01 increase in our unit cost for both compressor and rental
maintenance and saltwater disposal.
Production taxes
- ----------------
There are a variety of state and federal taxes levied on the production of
our oil and natural gas. These are commonly grouped together and referred to as
production taxes. The majority of our production tax expense is based on a
percent of gross value at the well at the time the production is sold or removed
from the lease. As a result, our production tax expense increases with increases
in crude oil and natural gas commodity prices.
Historically, taxing authorities have occasionally encouraged oil and gas
industry to explore for new oil and natural gas reserves, or develop high cost
reserves through reduced tax rates or credits. These incentives have been narrow
in scope and short-lived. A small number of our wells currently qualify for
reduced production taxes because they are discoveries based on the use of 3-D
seismic or high cost wells.
An increase in our third quarter 2004 production volumes combined with a
10% increase in the average pre-hedge sales price that we received for our oil
and natural gas in the third quarter 2004 were the primary reasons for the
increase in production taxes. These increases were partially offset by reduced
tax rates or tax credits on certain wells. Production taxes for the third
quarter 2004 were 3.7% of revenue from the sale of oil and natural gas before
gains and losses due to hedging, compared to 3.9% in the third quarter last
year.
The increase in production taxes for the first nine months of 2004 was
primarily due to an increase in production volumes during the first nine months
of 2004. This increase was partially offset by reduced tax rates or tax credits
on certain wells. Production taxes for the first nine months of 2004 were 4.4%
of revenue from the sale of oil and natural gas before gains and losses due to
hedging, compared to 5% in the first nine months of last year.
24
General and administrative expenses. We capitalize a portion of our general and
administrative costs. The costs capitalized represent the cost of technical
employees, who work directly on capital projects. An engineer designing a well
is an example of a technical employee working on a capital project. The cost of
a technical employee includes associated technical organization costs such as
supervision, telephone and postage. The following table presents general and
administrative expenses for the third quarter and first nine months of 2004 and
2003.
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
----------------------------------------- -------------------------------------------
% %
2004 2003 CHANGE 2004 2003 CHANGE
---------- ------------- -------------- ------------ ------------- --------------
(IN THOUSANDS)
General and administrative expenses. $ 1,304 $ 1,094 19% $ 3,723 $ 3,420 9%
(PER MCFE)
General and administrative expenses. $ 0.43 $ 0.42 2% $ 0.40 $ 0.43 (7%)
General and administrative expenses for the third quarter of 2004 were 19%
higher than general and administrative expenses in the third quarter last year.
The change in our general and administrative expenses for the for the third
quarter 2004 was due to the following:
- - A 19% increase in payroll and employee benefit expenses net of amounts
charged to joint ventures to cover the costs of managing these joint
operations represented approximately 35% of the total increase.
- - A 162% increase in expenses paid to outside consultants and our independent
public accountants. These increases, which were represented approximately
40% of the total increase in our general and administrative expenses, were
related to additional costs associated with the implementation of
Sarbanes-Oxley Section 404.
- - An increase in expenses paid to our external reserve engineers represented
approximately 11% of the total increase in our general and administrative
expenses.
- - These increases were partially offset by a decrease in financial reporting
expenses, a decrease in office rent and a decrease in legal fees.
General and administrative expenses for the first nine months of 2004
increased by 9% over general and administrative expenses during the first nine
months of 2003. The change in our general and administrative expenses for the
for the first nine months of 2004 was due to the following:
- - An 11% increase in payroll and employee benefit expenses net of amounts
charged to joint ventures to cover the costs of managing these joint
operations represented approximately 58% of the total increase.
- - A 60% increase in expenses paid to our independent public accountants
primarily related to additional cost associated with the implementation of
Sarbanes-Oxley Section 404 represented approximately 14% of the total
increase.
- - An increase in expenses paid to our external reserve engineers represented
approximately 12% of the total increase in general and administrative
expenses.
- - An increase in expenses for corporate insurance expense represented
approximately 5% of the increase.
- - These increases were partially offset by a decrease in cost for financial
reporting and fees paid to our directors.
25
Depletion of oil and natural gas properties. Our full-cost depletion expense is
driven by many factors including certain costs spent in the exploration and
development of producing reserves, production levels, and estimates of proved
reserve quantities and future developmental costs at the end of the year. The
following table presents depletion expense for the third quarter and first nine
months of 2004 and 2003.
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------------- --------------------------------------
% %
2004 2003 CHANGE 2004 2003 CHANGE
----------- --------- -------------- ---------------------- --------------
(IN THOUSANDS)
Depletion of oil and natural gas properties. $ 5,871 $ 3,952 49% $ 16,374 $ 11,853 38%
(PER MCFE)
Depletion rate . . . . . . . . . . . . . . . $ 1.92 $ 1.52 26% $ 1.78 $ 1.48 20%
Increased production volumes combined with a $0.40 increase in our
depletion rate resulted in a 49% increase in our third quarter 2004 depletion
expense. Higher production volumes accounted for approximately 36% of this
increase while the increase in our depletion rate accounted for 64% of the
increase. The increase in our depletion rate was primarily the result of
increased cost of reserve additions during the first nine months of 2004.
Increased production volumes combined with a $0.30 increase in our
depletion rate resulted in a 20% increase in our depletion expense for the first
nine months of 2004. Higher production volumes accounted for approximately 39%
of the increase while the increase in our depletion rate accounted for the
remaining 61%. The increase in our depletion rate was primarily the result of
increased cost of reserve additions during the first nine months of 2004.
26
Net interest expense. We capitalize interest expense on borrowings associated
with major capital projects prior to their completion. Capitalized interest is
added to the cost of the underlying assets and is amortized over the lives of
the assets. The following table presents interest expense for the third quarter
and first nine months of 2004 and 2003.
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED
---------------------------------------- -----------------------
%
2004 2003 CHANGE 2004 2003
------------ ---------- -------------- ----------- ----------
(IN THOUSANDS)
Interest on senior credit facility. . . . . . . . . . . . $ 215 $ 418 (49%) $ 649 $ 1,563
Interest on senior subordinated notes (a) . . . . . . . . 436 612 (29%) 1,320 1,792
Commitment fees . . . . . . . . . . . . . . . . . . . . . 64 10 540% 171 45
Dividend on mandatorily redeemable
preferred stock (b)(c). . . . . . . . . . . . . . . . 184 161 14% 538 161
Amortization of deferred loan and debt issuance cost. . . 191 276 (31%) 574 809
Other general interest expense. . . . . . . . . . . . . . 6 6 0% 20 34
Capitalized interest expense. . . . . . . . . . . . . . . (224) (212) 6% (764) (627)
------------ ---------- -----------------------
Net interest expense. . . . . . . . . . . . . . . . . . . $ 872 $ 1,271 (31%) $ 2,508 $ 3,777
============ ========== =======================
Weighted average debt outstanding . . . . . . . . . . . . $ 54,508 $ 79,659 (32%) $ 57,275 $ 77,070
Average interest rate on outstanding indebtedness (d) . . 6.6% 6.0% 6.2% 6.2%
(a) Interest expense on our senior subordinated notes
paid in kind through the issuance of additional
debt in lieu of cash. Our option to pay interest in
kind on our senior subordinated notes expired in
October 2003. . . . . . . . . . . . . . . . . . . . . $ - $ 306 $ - $ 896
(b) Shares of mandatorily redeemable Series A
preferred stock issued to satisfy dividends paid in
kind. The dividend on our Seri1es A preferred
stock in the first two quarters of 2003 was
recorded as dividends in dividends and accretion.
Our option to pay dividends in kind on our Series
A preferred stock expires in October 2005. See
further discussion later in net interest expense
section and in dividends and accretion section. . . . 9,202 37,024 26,877 107,852
(c) Shares of mandatorily redeemable Series
Bpreferred stock issued to satisfy dividends paid
in kind. The dividend on our Series B preferred
stock in the first two quarters of 2003 was
recorded as dividends in dividends and accretion.
In the fourth quarter of 2003, CSFB Private
Equity used a portion of our mandatorily
redeemable Series B preferred stock that it held
to pay for the exercise of warrants. We
redeemed the remaining balance of Series B
preferred stock that was not used to pay for the
exercise. See further discussion later in net
interest expense section and in dividends and
accretion section . . . . . . . . . . . . . . . . . . - 10,086 - 30,603
SEPTEMBER 30,
--------------
%
CHANGE
--------------
Interest on senior credit facility. . . . . . . . . . . . (58%)
Interest on senior subordinated notes (a) . . . . . . . . (26%)
Commitment fees . . . . . . . . . . . . . . . . . . . . . 280%
Dividend on mandatorily redeemable
preferred stock (b)(c). . . . . . . . . . . . . . . . 234%
Amortization of deferred loan and debt issuance cost. . . (29%)
Other general interest expense. . . . . . . . . . . . . . (41%)
Capitalized interest expense. . . . . . . . . . . . . . . 22%
Net interest expense. . . . . . . . . . . . . . . . . . . (34%)
Weighted average debt outstanding . . . . . . . . . . . . (26%)
Average interest rate on outstanding indebtedness (d)
(a) Interest expense on our senior subordinated notes
paid in kind through the issuance of additional
debt in lieu of cash. Our option to pay interest in
kind on our senior subordinated notes expired in
October 2003.
(b) Shares of mandatorily redeemable Series A
preferred stock issued to satisfy dividends paid in
kind. The dividend on our Seri1es A preferred
stock in the first two quarters of 2003 was
recorded as dividends in dividends and accretion.
Our option to pay dividends in kind on our Series
A preferred stock expires in October 2005. See
further discussion later in net interest expense
section and in dividends and accretion section
(c) Shares of mandatorily redeemable Series
Bpreferred stock issued to satisfy dividends paid
in kind. The dividend on our Series B preferred
stock in the first two quarters of 2003 was
recorded as dividends in dividends and accretion.
In the fourth quarter of 2003, CSFB Private
Equity used a portion of our mandatorily
redeemable Series B preferred stock that it held
to pay for the exercise of warrants. We
redeemed the remaining balance of Series B
preferred stock that was not used to pay for the
exercise. See further discussion later in net
interest expense section and in dividends and
accretion section
(d) Calculated as the sum of interest expense on outstanding indebtedness,
commitment fees and dividend on our Series A mandatorily redeemable
preferred stock divided by the weighted average debt and preferred stock
outstanding for the period.
27
Interest expense for the third quarter 2004 was 34% lower than interest
expense in the same quarter of the prior year. The change in interest expense
was primarily due to the following:
- - A decrease in the weighted average debt outstanding under our senior credit
facility resulted in a $203,000 decrease in interest expense for the third
quarter of 2004. This decrease was offset by a $54,000 increase in the
commitment fees we paid on the unused portion of our borrowing base.
- - A decrease in the amount of subordinated notes outstanding during the third
quarter this year combined with a decrease in the interest rate we paid on
our senior subordinated notes resulted in a $176,000 decrease in interest
expense.
- - An increase in the amount of interest we capitalized.
- - An increase in the dividend that we paid on our mandatorily redeemable
preferred stock.
Interest expense for the first nine months of 2004 was 34% lower than
interest expense during the first nine months of 2003. The change was due to
the following:
- - A decrease in the weighted average debt outstanding under our senior credit
facility combined with a decrease in the interest rate that we paid on
those borrowings resulted in a $914,000 decrease in interest expense. This
decrease was partially offset by a $126,000 increase in the commitment fees
that we paid on the unused portion of our borrowing base.
- - A decrease in the amount of subordinated notes outstanding combined with a
decrease in the interest rate we paid on our senior subordinated notes
resulted in a $472,000 decrease in interest expense.
- - An increase in the amount of interest we capitalized.
- - An increase in the dividend that we paid on our manadatorily redeemable
preferred stock. Upon our adoption of SFAS 150 in July 2003, we
reclassified approximately $8 million of our then outstanding mandatorily
redeemable Series A and Series B preferred stock, which had no equity
conversion features and must be settled with our assets, to long-term debt.
As part of this reclassification, we now report the dividends on the
mandatorily redeemable preferred stock that was reclassified as interest
expense. Prior to this reclassification, the dividend on our mandatorily
redeemable preferred stock was reported as dividends in dividend and
accretion of mandatorily redeemable preferred stock.
Other income (expense). Other income (expense) primarily includes non-cash
gains (losses) resulting from the change in fair market value of oil and natural
gas derivative contracts that were not designated as cash flow hedges, cash
gains (losses) on the settlement of these contracts and non-cash gains (losses)
related to charges for the ineffective portions of cash flow hedges.
THREE MONTHS ENDED SEEMBER 30, NNE MONTHS ENDED SEEMBER 30,
-------------------------------------- ------------------------------------
% %
2004 2003 CHANGE 2004 2003 CHANGE
------------ ---------- ------------ ---------------------- ------------
(IN THOUSANDS)
Market value adjustment for derivative contracts. $ (167) $ (80) 109% $ (227) $ (250) (9%)
Other income. . . . . . . . . . . . . . . . . . . (1) - - 68 - -
------------ ---------- ----------------------
Total other income (expense). . . . . . . . . . $ (168) $ (80) 110% $ (159) $ (250) (36%)
============ ========== ======================
28
Income taxes. Since inception, we have not been required to recognize any
current income taxes. Furthermore, we do not expect to recognize significant,
if any, current income taxes in 2004. Since inception, we have generated net
operating losses (NOLs) due mainly to intangible drilling and other property
related deductions, which have exceeded taxable income. Our regular NOLs are
$101.8 million, and our alternative minimum tax NOLs are $87.6 million. To
date, we have not utilized any of our NOLs. In future periods, our NOLs will be
used to offset taxable income.
Since 1997 through the third quarter of 2003, we have not been required to
recognize any deferred income taxes. Due to the level of projected net taxable
income, we expect to evolve from a net deferred tax asset to a net deferred tax
liability position during 2004. It is management's belief that we will begin to
utilize our NOLs and will have reversals of existing temporary differences
between book and taxable income such that a net deferred tax liability is
expected at year-end 2004, as well as in future years. Accordingly, we
recognized deferred tax expense of $7.2 million during the first nine months of
2004.
Dividends and accretion of mandatorily redeemable preferred stock. We are
required to pay dividends on our Series A and were required to pay dividends on
our Series B preferred stock prior to its redemption. At our option, these
dividends could be paid in cash at a rate of 6% per annum or paid in kind
through the issuance of additional shares of preferred stock in lieu of cash at
a rate of 8% per annum. We elected to pay dividends in kind in each quarter of
2004 and 2003.
Upon our adoption of SFAS 150 in July 2003, approximately $8 million of our
then outstanding mandatorily redeemable Series A and Series B preferred stock
that must be settled with our assets, was reclassified to long-term debt. As
part of the reclassification, the dividend paid on the reclassified amount since
July 2003 has been reported as interest expense.
In November and December 2003, CSFB Private Equity used a portion of our
mandatorily redeemable Series A and Series B preferred stock that it held to pay
for the exercise of the associated warrants. We also redeemed the remaining
balance of Series B preferred stock that was not used to pay for the exercise.
The following table shows the effect for the three and nine-month periods
ended September 30, 2004 and 2003, of the issuance of additional shares of
preferred stock in lieu of paying cash dividends.
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
------------------------------------ ------------------------------------
% %
2004 2003 CHANGE 2004 2003 CHANGE
----------- --------- ------------ ---------------------- ------------
(IN THOUSANDS)
Dividends . . . . . . . . . . . . . . . $ - $ 789 - $ - $ 2,606 -
Accretion of redeemable preferred stock - 115 - - 321 -
----------- --------- ----------------------
Total dividends and accretion . . . . $ - $ 904 - $ - $ 2,927 -
=========== ========= ======================
OTHER MATTERS
Effects of Inflation and Changes in Prices
Our results of operations and cash flows are affected by changing oil and
gas prices. If the price of oil and natural gas increases (decreases), there
could be a corresponding increase (decrease) in revenues as well as the
operating costs that we are required to bear for operations. Inflation has had a
minimal effect on us.
Environmental and Other Regulatory Matters
Our business is subject to certain federal, state and local laws and
regulations relating to the exploration for and the development, production and
marketing of oil and natural gas, as well as environmental and safety matters.
Many
29
of these laws and regulations have become more stringent in recent years,
often imposing greater liability on a larger number of potentially responsible
parties. Although we believe we are in substantial compliance with all
applicable laws and regulations, the requirements imposed by laws and
regulations are frequently changed and subject to interpretation, and we cannot
predict the ultimate cost of compliance with these requirements or their effect
on our operations. Any suspensions, terminations or inability to meet applicable
bonding requirements could materially adversely affect our financial condition
and operations. Although significant expenditures may be required to comply with
governmental laws and regulations applicable to us, compliance has not had a
material adverse effect on our earnings or competitive position. Future
regulations may add to the cost of, or significantly limit, drilling activity.
New Accounting Pronouncements
In September 2004, the Securities and Exchange Commission (SEC) issued
Staff Accounting Bulletin No. 106. This pronouncement will require companies
that use the full cost method for accounting for their oil and gas producing
activities to include an estimate of future asset retirement costs to be
incurred as a result of future development activities on proved reserves in
their calculation of depreciation, depletion and amortization. This
pronouncement will also require these companies to exclude any future cash
outflows associated with settling asset retirement liabilities from their full
cost ceiling test calculation. This standard will also require these companies
to disclose the impact of their asset retirement obligations on their oil and
gas producing activities, ceiling test calculations and depreciation, depletion
and amortization calculations. We will adopt the provisions of this
pronouncement in the fourth quarter of 2004 and are currently evaluating the
impact, if any, on our consolidated financial statements.
Risk Factors Related to Our Business
- Our level of indebtedness may adversely affect our cash available for
operations, thus limiting our growth, our ability to make interest and
principal payments on our indebtedness as they become due and our
flexibility to respond to market changes.
- We have substantial capital requirements for which we may not be able
to obtain adequate financing.
- Oil and natural gas prices fluctuate widely and low prices could have
a material adverse impact on our business and financial results by
limiting our liquidity and flexibility to accelerate our drilling
program.
- Our hedging transactions could reduce revenues in a rising commodity
price environment or expose us to other risks.
- Exploratory drilling is a speculative activity that may not result in
commercially productive reserves and may require expenditures in
excess of budgeted amounts.
- We are subject to various operating and other casualty risks that
could result in liability exposure or the loss of production and
revenues.
- We may not have enough insurance to cover all of the risks we face,
which could result in significant financial exposure.
- We cannot control the activities on properties we do not operate and
are unable to ensure their proper operation and profitability.
- The marketability of our natural gas production depends on facilities
that we typically do not own or control, which could result in a
curtailment of production and revenues.
- Lower oil and natural gas prices may cause us to record ceiling
limitation write-downs which would reduce our stockholders' equity.
- We have had operating losses in the past and may not be profitable in
the future.
- Our future operating results may fluctuate and significant declines in
them would limit our ability to invest in projects.
- The failure to replace reserves in the future would adversely affect
our production and cash flows.
- We are subject to uncertainties in reserve estimates and future net
cash flows.
- We face significant competition, and many of our competitors have
resources in excess of our available resources.
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- We are subject to various governmental regulations and environmental
risks which may cause us to incur substantial costs.
- Our business may suffer if we lose key personnel.
Disclosure Regarding Forward-Looking Statements
Statements included in this report which are not historical facts
(including any statements concerning plans and objectives of management for
future operations or economic performance, or assumptions or forecasts related
thereto), are forward-looking statements. These statements can be identified by
the use of forward-looking terminology including "may," "believe," "will,"
"expect," "anticipate," "estimate," "continue" or other similar words. These
statements discuss future expectations, contain projections of results of
operations or of financial condition or state other "forward-looking"
information.
These forward-looking statements are made based upon management's current
plans, expectations, estimates, assumptions and beliefs concerning future events
impacting us and therefore involve a number of risks and uncertainties. We
caution that forward-looking statements are not guarantees and that actual
results could differ materially from those expressed or implied in the
forward-looking statements.
Because these forward-looking statements involve risks and uncertainties,
actual results could differ materially from those expressed or implied by these
forward-looking statements for a number of important reasons, including those
discussed under "Risk Factors Related to Our Business," and elsewhere in this
report.
You should read these statements carefully because they discuss our
expectations about our future performance, contain projections of our future
operating results or our future financial condition, or state other
"forward-looking" information. You should be aware that the occurrence of any of
the events described in "Risk Factors Related to Our Business" and elsewhere in
this report could substantially harm our business, results of operations and
financial condition and that upon the occurrence of any of these events, the
trading price of our common shares could decline.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The following quantitative and qualitative disclosures about market risk
are supplementary to the quantitative and qualitative disclosures provided in
our Annual Report on Form 10-K for the fiscal year ended December 31, 2003. As
such, the information contained herein should be read in conjunction with the
related disclosures in our Annual Report on Form 10-K for the fiscal year ended
December 31, 2003.
DERIVATIVE CONTRACTS
CASH-FLOW HEDGES
Our cash-flow hedges consisted of fixed-price swaps and costless collars
(purchased put options and written call options). The fixed-price swap
agreements are used to fix the prices of anticipated future oil and natural gas
production. The costless collars are used to establish floor and ceiling prices
on anticipated future oil and natural gas production. There were no net premiums
received when we entered into these option agreements.
DERIVATIVES NOT DESIGNATED AS HEDGES
Our derivative positions included option contracts that are not designated
as hedges. These positions were entered into to offset the cost of other option
positions that are designated as hedges.
NOTIONAL AMOUNT
-------------------- NYMEX
SETTLEMENT DERIVATIVE HEDGE GAS OIL REFERENCE
PERIOD INSTRUMENT STRATEGY (MMBTU) (BARRELS) PRICE
- ----------------- ------------- ------------ --------- --------- ----------
10/01/04-12/31/04 Swap Cash flow 92,000 $ 4.36
10/01/04-12/31/04 Swap Cash flow 9,200 23.80
COSTLESS COLLARS
10/01/04-10/31/04 Purchased put Cash flow 34,100 $ 4.00
Written call Cash flow 34,100 6.83
10/01/04-10/31/04 Purchased put Cash flow 6,200 26.00
Written call Cash flow 6,200 33.50
10/01/04-12/31/04 Purchased put Cash flow 92,000 4.00
Written call Cash flow 92,000 5.62
10/01/04-12/31/04 Purchased put Cash flow 92,000 4.25
Written call Cash flow 92,000 5.51
10/01/04-12/31/04 Purchased put Cash flow 46,000 4.25
Written call Cash flow 46,000 6.05
10/01/04-12/31/04 Purchased put Cash flow 322,000 5.25
Written call Cash flow 322,000 7.41
10/01/04-12/31/04 Purchased put Cash flow 9,200 23.00
Written call Cash flow 9,200 25.39
10/01/04-12/31/04 Purchased put Cash flow 6,900 23.00
Written call Cash flow 6,900 27.30
10/01/04-12/31/04 Purchased put Cash flow 11,960 32.00
Written call Cash flow 11,960 38.15
01/01/05-03/31/05 Purchased put Cash flow 90,000 4.00
Written call Cash flow 90,000 7.25
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NOTIONAL AMOUNT
-------------------- NYMEX
SETTLEMENT DERIVATIVE HEDGE GAS OIL REFERENCE
PERIOD INSTRUMENT STRATEGY (MMBTU) (BARRELS) PRICE
- ----------------- ------------- ------------ --------- --------- ----------
01/01/05-03/31/05 Purchased put Cash flow 67,500 4.25
Written call Cash flow 67,500 5.90
01/01/05-03/31/05 Purchased put Cash flow 45,000 4.25
Written call Cash flow 45,500 6.50
01/01/05-03/31/05 Purchased put Cash flow 9,000 23.00
Written call Cash flow 9,000 25.07
01/01/05-03/31/05 Purchased put Cash flow 6,750 23.00
Written call Cash flow 6,750 26.90
01/01/05-06/30/05 Purchased put Cash flow 633,500 5.00
Written call Cash flow 633,500 7.40
01/01/05-06/30/05 Purchased put Cash flow 23,530 29.00
Written call Cash flow 23,530 36.00
04/01/05-06/30/05 Purchased put Cash flow 91,000 4.00
Written call Cash flow 91,000 5.40
04/01/05-06/30/05 Purchased put Cash flow 45,500 4.25
Written call Cash flow 45,500 4.52
04/01/05-06/30/05 Purchased put Cash flow 6,825 23.00
Written call Cash flow 6,825 26.45
THREE WAY COSTLESS
11/01/04-3/31/05 Purchased put Cash flow 350,000 $ 6.40
Written call Cash flow 350,000 7.64
Written put Undesignated 350,000 5.50
ITEM 4. CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
As of the end of period covered by this report, our principal executive
officer and principal financial officer carried out an evaluation of the
effectiveness of our disclosure controls and procedures. Based on their
evaluation, they have concluded that our disclosure controls and procedures
effectively ensure that the information required to be disclosed in the reports
we file with the SEC is recorded, processed, summarized and reported within the
time periods specified by the SEC.
CHANGES IN INTERNAL CONTROLS
There were no changes in our internal controls or in other factors that
have materially affected, or are reasonably likely to materially affect, our
internal controls subsequent to the date of their evaluation of our disclosure
controls and procedures.
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PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
As discussed in Note 3 of Notes to the Consolidated Financial Statements
included in Part I. Financial Information, Brigham is party to various legal
actions arising in the ordinary course of business and does not expect these
matters to have a material adverse effect on its financial condition, results of
operations or cash flow.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
No purchases were made under a publicly announced plan.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
31.1 Certification of Chief Executive Officer of the Company pursuant to Rule 13a-14(a) of the Securities
Exchange Act of 1934
31.2 Certification of Chief Financial Officer of the Company pursuant to Rule 13a-14(a) of the Securities
Exchange Act of 1934
32.1 Certification of Chief Executive Officer of the Company pursuant to 18 U.S.C. Sec. 1350
32.2 Certification of Chief Financial Officer of the Company pursuant to 18 U.S.C. Sec. 1350
34
SIGNATURES
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 on November 9, 2004.
BRIGHAM EXPLORATION COMPANY
By: /s/ BEN M. BRIGHAM
------------------
Ben M. Brigham
Chief Executive Officer, President
and Chairman of the Board
By: /s/ EUGENE B. SHEPHERD, JR.
---------------------------
Eugene B. Shepherd, Jr.
Executive Vice President and
Chief Financial Officer
35