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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, 2003
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 [ ] No [X]
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 as of November 12, 2003 27,971,542
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BRIGHAM EXPLORATION COMPANY
THIRD QUARTER 2003 FORM 10-Q REPORT
TABLE OF CONTENTS
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PAGE
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PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Consolidated Balance Sheets - September 30, 2003 and
December 31, 2002 . . . . . . . . . . . . . . . . . . . . . . . . .1
Consolidated Statements of Operations - Three and
nine months ended September 30, 2003 and 2002 . . . . . . . . . . .2
Consolidated Statements of Stockholders' Equity -
Nine months ended September 30, 2003. . . . . . . . . . . . . . . .3
Consolidated Statements of Cash Flows - Nine months
ended September 30, 2003 and 2002 . . . . . . . . . . . . . . . . .4
Notes to the Consolidated Financial Statements. . . . . . . . . . .5
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS . . . . . . . . . . . . . . . 13
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. . . . 23
ITEM 4. CONTROLS AND PROCEDURES . . . . . . . . . . . . . . . . . . . . . 24
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS . . . . . . . . . . . . . . . . . . . . . . . . 25
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K. . . . . . . . . . . . . . . . . 25
SIGNATURES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
SEPTEMBER 30, DECEMBER 31,
2003 2002
--------------- --------------
ASSETS
(Unaudited)
Current assets:
Cash and cash equivalents $ 11,016 $ 15,318
Accounts receivable 9,796 11,361
Gas imbalance receivable 9,193 3,656
Other current assets 1,516 2,987
--------------- --------------
Total current assets 31,521 33,322
--------------- --------------
Oil and natural gas properties, net (full cost method) 183,745 164,980
Other property and equipment, net 1,210 1,234
Deferred loan fees 2,571 2,391
Other noncurrent assets 126 132
--------------- --------------
$ 219,173 $ 202,059
=============== ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 13,709 $ 14,486
Royalties payable 5,442 4,508
Accrued drilling costs 1,674 2,727
Participant advances received 600 1,955
Gas imbalance liability 12,925 5,650
Other current liabilities 3,238 4,684
--------------- --------------
Total current liabilities 37,588 34,010
--------------- --------------
Senior credit facility 13,000 60,000
Senior subordinated notes 22,685 21,797
Other noncurrent liabilities 2,470 186
Commitments and contingencies
Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and
redemption value, 2,250,000 shares authorized, 1,872,884 and 1,765,132 shares
issued and outstanding at September 30, 2003 and December 31, 2002, respectively 21,989 19,540
Series B Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated
and redemption value, 1,000,000 shares authorized, 531,829 and 501,226
shares issued and outstanding at September 30, 2003 and December 31, 2002,
respectively 5,416 4,777
Stockholders' equity:
Preferred stock, $.01 par value, 10 million shares authorized, of which
2,250,000 and 1,000,000 shares are designated as Series A and Series
B, respectively - -
Common stock, $.01 par value, 50 million shares authorized, 29,115,824
and 20,618,161 shares issued and 27,971,542 and 19,479,979 shares outstanding
at September 30, 2003 and December 31, 2002, respectively 291 206
Additional paid-in capital 133,031 93,436
Treasury stock, at cost; 1,144,282 and 1,138,182 shares at September 30,
2003 and December 31, 2002, respectively (4,292) (4,282)
Unearned stock compensation (1,975) (212)
Accumulated other comprehensive (loss) income (1,010) (3,047)
Accumulated deficit (10,020) (24,352)
--------------- --------------
Total stockholders' equity 116,025 61,749
--------------- --------------
$ 219,173 $ 202,059
=============== ==============
The accompanying notes are an integral part of these consolidated financial statements.
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------ ------------------
2003 2002 2003 2002
-------- -------- -------- --------
Revenues:
Oil and natural gas sales $13,181 $ 9,434 $39,947 $24,637
Other revenue 32 15 113 42
-------- -------- -------- --------
13,213 9,449 40,060 24,679
-------- -------- -------- --------
Costs and expenses:
Lease operating 1,793 761 4,037 2,428
Production taxes 553 475 2,297 1,327
General and administrative 1,094 1,099 3,420 3,781
Depletion of oil and natural gas properties 3,952 3,587 11,853 10,118
Depreciation and amortization 192 103 449 307
Accretion of discount on asset retirement obligations 39 - 110 -
-------- -------- -------- --------
7,623 6,025 22,166 17,961
-------- -------- -------- --------
Operating income 5,590 3,424 17,894 6,718
-------- -------- -------- --------
Other income (expense):
Interest income 8 12 36 105
Interest expense (1,110) (1,614) (3,616) (4,684)
Other income (expense) (80) (87) (250) (256)
-------- -------- -------- --------
(1,182) (1,689) (3,830) (4,835)
-------- -------- -------- --------
Income before income taxes and cumulative effect of
change in accounting principle 4,408 1,735 14,064 1,883
Income taxes - - - -
-------- -------- -------- --------
Income before cumulative effect of change in accounting
principle 4,408 1,735 14,064 1,883
Cumulative effect of change in accounting principle - - 268 -
-------- -------- -------- --------
Net income 4,408 1,735 14,332 1,883
Less accretion and dividends on redeemable preferred stock 1,065 746 3,088 2,165
-------- -------- -------- --------
Net income (loss) available to common stockholders $ 3,343 $ 989 $11,244 $ (282)
======== ======== ======== ========
Net income (loss) per share available to common stockholders:
Basic
Income (loss) before cumulative effect of change in
accounting principle $ 0.16 $ 0.06 $ 0.54 $ (0.02)
Cumulative effect of change in accounting principle - - 0.01 -
-------- -------- -------- --------
$ 0.16 $ 0.06 $ 0.55 $ (0.02)
======== ======== ======== ========
Diluted
Income (loss) before cumulative effect of change in
accounting principle $ 0.13 $ 0.06 $ 0.42 $ (0.02)
Cumulative effect of change in accounting principle - - 0.01 -
-------- -------- -------- --------
$ 0.13 $ 0.06 $ 0.43 $ (0.02)
======== ======== ======== ========
Weighted average shares outstanding:
Basic 21,210 16,057 20,340 16,037
======== ======== ======== ========
Diluted 30,751 19,866 32,406 16,037
======== ======== ======== ========
The accompanying notes are an integral part of these consolidated financial statements.
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
(UNAUDITED)
ACCUMULATED
COMMON STOCK ADDITIONAL UNEARNED OTHER TOTAL
---------------- PAID IN TREASURY STOCK COMPREHENSIVE ACCUMULATED STOCKHOLDERS'
SHARES AMOUNTS CAPITAL STOCK COMPENSATION INCOME (LOSS) DEFICIT EQUITY
------ -------- --------- -------- -------------- -------------- --------- ---------
Balance, December 31, 2002 20,618 $ 206 $ 93,436 $(4,282) $ (212) $ (3,047) $(24,352) $ 61,749
Comprehensive income:
Net income - - - - - - 14,332 14,332
Deferred hedge gains and
losses, net of tax:
Unrealized gain on cash
flow hedges - - - - - 1,956 - 1,956
Net losses included in
net income - - - - - 81 - 81
---------
Comprehensive income 16,369
Issuance of common stock 7,384 74 39,926 - - - - 40,000
Exercise of employee stock
options 250 2 658 - - - - 660
Issuance of stock options - - 296 - (296) - - -
Issuance of restricted stock - - 1,831 - (1,831) - - -
Expiration of employee stock
options - - (19) - - - - (19)
Forfeitures of restricted stock - - - (10) 2 - - (8)
Warrants exercised for
common stock 864 9 (9) - - - - -
In kind dividends on Series A
mandatorily redeemable
preferred stock - - (2,155) - - - - (2,155)
Accretion on Series A
mandatorily redeemable
preferred stock - - (294) - - - - (294)
In kind dividends on Series B
mandatorily redeemable
preferred stock - - (612) - - - - (612)
Accretion on Series B
mandatorily redeemable
preferred stock - - (27) - - - - (27)
Amortization of unearned
stock compensation - - - - 362 - - 362
------ -------- --------- -------- -------------- -------------- --------- ---------
Balance, September 30, 2003 29,116 $ 291 $133,031 $(4,292) $ (1,975) $ (1,010) $(10,020) $116,025
====== ======== ========= ======== ============== ============== ========= =========
The accompanying notes are an integral part of these consolidated financial statements.
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
NINE MONTHS ENDED
SEPTEMBER 30,
--------------------
2003 2002
--------- ---------
Cash flows from operating activities:
Net income $ 14,332 $ 1,883
Adjustments to reconcile net income to cash provided by operating
activities:
Depletion of oil and natural gas properties 11,853 10,118
Depreciation and amortization 449 307
Interest paid through issuance of additional senior subordinated notes 888 785
Amortization of deferred loan fees and debt issuance costs 809 888
Market value adjustment for derivative instruments 250 (278)
Accretion of discount on asset retirement obligations 110 -
Cumulative effect of change in accounting principle (268) -
Stock option compensation expense - 596
Changes in operating assets and liabilities:
Accounts receivable 1,565 (2,881)
Gas imbalance receivable and other current assets (4,193) (1,931)
Accounts payable (777) 4,707
Royalties payable 934 6,263
Participant advances received (1,355) 1,058
Gas imbalance and other current liabilities 7,863 685
Other noncurrent assets and liabilities (35) (5)
--------- ---------
Net cash provided by operating activities 32,425 22,195
--------- ---------
Cash flows from investing activities:
Additions to oil and natural gas properties (30,356) (18,737)
Proceeds from sale of oil and natural gas properties 1,183 617
Additions to other property and equipment (247) (218)
Decrease (increase) in drilling advances paid 18 (512)
--------- ---------
Net cash used by investing activities (29,402) (18,850)
--------- ---------
Cash flows from financing activities:
Proceeds from the issuance of common stock, net of issuance costs 40,000 -
Repayment of senior credit facility (47,000) -
Deferred loan fees paid (985) (360)
Proceeds from issuance of senior subordinated notes - 4,000
Proceeds from exercise of employee stock options 660 113
Principal payments on capital lease obligations - (28)
--------- ---------
Net cash provided (used) by financing activities (7,325) 3,725
--------- ---------
Net increase (decrease) in cash and cash equivalents (4,302) 7,070
Cash and cash equivalents, beginning of year 15,318 5,112
--------- ---------
Cash and cash equivalents, end of period $ 11,016 $ 12,182
========= =========
The accompanying notes are an integral part of these consolidated financial statements.
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 Texas Gulf Coast, the Anadarko Basin, and West
Texas.
2. BASIS OF PRESENTATION
The accompanying 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 limited partnerships 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 2002 Annual
Report on Form 10-K/A pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934.
Certain reclassifications have been made to prior year amounts to conform
to current year presentation.
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") for breach of
contract. The Petition claims Massey furnished defective casing to Brigham,
which ultimately led to the casing failure of the Palmer "347" No. 5 well (the
"Palmer #5") and the loss of the Palmer #5 as a producing well. Brigham believes
the amount of damages incurred due to the loss of the Palmer #5 may exceed $5
million. Massey joined as additional defendants to the lawsuit other parties
that had responsibility for the manufacture, importation or fabrication of the
casing for its use in the Palmer #5. Brigham then amended its petition, adding
claims of breach of warranty, negligence, misrepresentation and strict liability
against Massey, and claims of negligence and strict liability against Curley's
Fishing Tools Specialty, one of the additional defendants joined by Massey. A
trial has been set for January 2004.
On February 20, 2002, Massey filed an Original Petition to Foreclose Lien
in Brooks County, Texas. Massey's Petition claims Brigham breached its contract
for failure to pay for the casing it furnished Brigham for the Palmer #5 (and
that Brigham's claim, forming the basis of the lawsuit described in the
paragraph above, is defective). Massey's Petition claims Brigham owes Massey a
total of $445,819. Brigham's Motion to Transfer Venue to Travis County, Texas,
and Motion to Consolidate Massey's claim with Brigham's suit against Massey
pending in Travis County, were recently granted. If Massey is successful in its
claim, and if Brigham does not otherwise satisfy the judgment, Massey would have
the right to foreclose its lien against the well, associated equipment and
Brigham's leasehold interest. At this point in time, Brigham cannot predict the
outcome of either its Travis County case or Massey's claim.
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 signed an agreement to settle
inspection issues for $70,000.
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
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 on
July 11, 2002. Plaintiffs are seeking unspecified actual and punitive damages.
Brigham cannot predict the outcome of this case, however Brigham believes it has
sufficient insurance to cover the claim. Trial has been set to begin December 1,
2003.
The operator of the Stonehocker #1 is disputing Brigham's ownership
interest in the well. Brigham expects the Oklahoma Corporation Commission to
rule on the dispute before year-end. The Stonehocker #1 began producing to sales
in early July 2003 at a rate of approximately 7.0 MMcf of natural gas per day,
or approximately 0.9 MMcfed net to Brigham, if Brigham prevails.
A company that relinquished its working interest in the Nold #1S well as a
result of a non-consent election in the re-completion of the well has asserted
that it did not relinquish its interest, but rather became subject only to a 400
percent payout provision. In September 2003, Brigham responded to this claim.
No other developments have occurred since. If the issue were to be litigated,
and the ruling unfavorable, Brigham would be required to distribute revenues in
excess of expenses for the disputed interest periods subsequent to payout. The
financial statement impact of an unfavorable ruling would be an out of period
reduction in revenue and expenses, with an overall negative impact on net income
of approximately $0.7 million at September 30, 2003.
4. NET INCOME (LOSS) PER SHARE
Basic earnings per share are computed by dividing net income (loss)
available to common stockholders by the weighted average number of common shares
outstanding for the period. The computation of diluted net income (loss) 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 (loss)
available to common stockholders for the three and nine months ended September
30, 2003 and 2002:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------- -----------------
2003 2002 2003 2002
------- ------- ------- --------
(In thousands, except per share amounts)
Basic EPS:
Income (loss) available to common
stockholders before cumulative change
in accounting principle $ 3,343 $ 989 $10,976 $ (282)
Cumulative change in accounting principle - - 268 -
------- ------- ------- --------
Income (loss) available to common
stockholders $ 3,343 $ 989 $11,244 $ (282)
======= ======= ======= ========
Common shares outstanding 21,210 16,057 20,340 16,037
======= ======= ======= ========
Basic EPS
Income (loss) available to common
stockholders before change in
accounting principle $ 0.16 $ 0.06 $ 0.54 $ (0.02)
Cumulative change in accounting principle - - 0.01 -
------- ------- ------- --------
$ 0.16 $ 0.06 $ 0.55 $ (0.02)
======= ======= ======= ========
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Diluted EPS:
Income (loss) available to common
stockholders before cumulative change
in accounting principle $ 3,343 $ 989 $10,976 $ (282)
Cumulative change in accounting principle - - 268 -
------- ------- ------- --------
Income (loss) available to common
stockholders 3,343 989 11,244 (282)
Adjustments for assumed conversions:
Interest on convertible debt - 139 - -
Dividends and accretion on mandatorily
redeemable preferred stock (1) 689 - 2,715 -
------- ------- ------- --------
689 139 2,715 -
------- ------- ------- --------
Income (loss) available to common
stockholders before change in accounting
principle-diluted 4,032 1,128 13,691 (282)
Cumulative change in accounting principle - - 268 -
------- ------- ------- --------
Income (loss) available to common
stockholders-diluted $ 4,032 $ 1,128 $13,959 $ (282)
======= ======= ======= ========
Common shares outstanding 21,210 16,057 20,340 16,037
Effect of dilutive securities:
Warrants - 947 402 -
Mandatorily redeemable preferred stock 8,966 - 11,071 -
Convertible debt - 2,564 - -
Stock options 575 298 593 -
------- ------- ------- --------
Potentially dilutive common shares 9,541 3,809 12,066 -
------- ------- ------- --------
Adjusted common shares outstanding
diluted 30,751 19,866 32,406 16,037
======= ======= ======= ========
Diluted EPS
Income (loss) available to common
stockholders before change in
accounting principle $ 0.13 $ 0.06 $ 0.42 $ (0.02)
Change in accounting principle - - 0.01 -
------- ------- ------- --------
$ 0.13 $ 0.06 $ 0.43 $ (0.02)
======= ======= ======= ========
(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 2.1 million shares and 12.0 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, 2003 and
2002, respectively, and options and warrants to purchase 12,000 shares and 19.1
million 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, 2003 and 2002, respectively, because the effects would have been
antidilutive.
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) support its capital budgeting plans, and
(iii) lock-in prices to protect the economics related to certain capital
projects.
At September 30, 2003, the fair value of hedging contracts included in
other current assets was approximately $0.1 million and the fair value of
hedging contracts included in other liabilities was approximately $1.3 million
of which approximately $0.1 million was classified as noncurrent. For the three
months ended September 30, 2003 and 2002, Brigham recognized cash settlement
losses of $1.1 million and $0.5 million, respectively, which were recorded as a
reduction of oil and natural gas sales. For the nine months ended September 30,
2003 and 2002, Brigham recognized cash settlement losses of $6.1 million and
$0.8 million, respectively, which were recorded as a reduction of oil and
natural gas sales. For the three months ended September 30, 2003 and 2002,
ineffectiveness associated with Brigham's derivative commodity instruments
designated as cash flow hedges decreased earnings by approximately $80,000 and
$0.1 million, respectively. For the nine months ended September 30, 2003 and
2002, ineffectiveness associated with Brigham's derivative commodity instruments
designated as cash flow hedges decreased earnings by approximately $0.3 million
and $0.1 million, respectively. These amounts are included in other income
(expense). Based on market prices at September 30, 2003, approximately $(1.0)
million of the balance in accumulated other comprehensive income (loss) would be
expected to transfer to earnings during the next 12 months.
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, 2003 and 2002, there were no derivatives not qualifying as hedging
contracts. For the three months ended September 30, 2003, and 2002, Brigham did
not recognize any non-cash gains or losses related to changes in the fair values
of these derivative contracts. For the nine months ended September 30, 2003, and
2002, other income (expense) included $0 and $0.4 million, respectively, in
non-cash gains related to changes in the fair values of these derivative
contracts and $0 and $0.6 million, respectively, in cash losses related to cash
settlement payments made by Brigham to the counterparty.
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
DERIVATIVE CONTRACTS
The following table summarizes the hedging contracts which Brigham was a
party to at September 30, 2003, the total natural gas and crude oil production
volumes subject to those contacts and the weighted average NYMEX reference price
for those volumes.
SWAPS COLLARS FLOORS
---------------------------- ----------------------------- ----------------------
Weighted Weighted Average Weighted
Average Floor Ceiling Average
NATURAL GAS Volumes Swap Price Volumes Price Price Volumes Floor Price
--------- ----------------- --------- --------- ------- --------- -----------
(MMbtu) ($/MMbtu) (MMbtu) ($/MMbtu) (MMbtu) ($/MMbtu)
Quarter Ended:
December 31, 2003 414,000 4.039 - - - 460,000 4.500
March 31, 2004 295,750 4.963 455,000 4.100 8.540 - -
June 30, 2004 227,500 4.252 318,500 4.107 5.300 - -
September 30, 2004 138,000 4.180 230,000 4.100 5.266 - -
December 31, 2004 92,000 4.360 184,000 4.125 5.565 - -
March 31, 2005 - - 157,500 4.107 6.671 - -
June 30, 2005 - - 136,500 4.083 5.107 - -
CRUDE OIL (Bbls) ($/Bbl) (Bbls) ($/Bbl) (Bbls) ($/Bbl)
December 31, 2003 41,400 23.21 - - - - -
March 31, 2004 29,575 25.35 31,850 23.00 29.20 - -
June 30, 2004 20,475 24.52 22,750 23.00 28.09 - -
September 30, 2004 13,800 23.91 18,400 23.00 27.00 - -
December 31, 2004 9,200 23.80 16,100 23.00 26.21 - -
March 31, 2005 - - 15,750 23.00 25.85 - -
June 30, 2005 - - 6,825 23.00 26.45 - -
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, 2003
and 2002:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------- -----------------
2003 2002 2003 2002
------- ------- -------- -------
NATURAL GAS
Average price per Mcf as reported (including hedging results) $ 5.27 $ 3.23 $ 5.17 $ 3.02
Average price per Mcf realized (excluding hedging results) $ 5.72 $ 3.29 $ 6.16 $ 3.04
Increase (decrease) in revenue (in thousands) $ (738) $ (87) $(4,584) $ (69)
OIL
Average price per Bbl as reported (including hedging results) $28.08 $24.85 $ 28.31 $23.04
Average price per Bbl realized (excluding hedging results) $30.31 $27.04 $ 31.08 $24.50
Decrease in revenue (in thousands) $ (356) $ (414) $(1,554) $ (735)
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 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
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
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 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.
The following pro forma data summarizes Brigham's net income (loss) and net
income (loss) per share as if Brigham had adopted the provisions of SFAS 143 on
January 1, 2002, including an associated pro forma asset retirement obligation
on that date of $1.8 million:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------- -----------------
2003 2002 2003 2002
------ ------ -------- -------
(In thousands, except per share amounts)
Net income (loss), as reported $3,343 $ 989 $11,244 $ (282)
Pro forma adjustments to reflect retroactive
adoption of SFAS 143 - 21 (268) 63
Pro forma adjustments to reflect accretion
expense - (34) - (100)
------ ------ -------- -------
Pro forma net income (loss) $3,343 $ 976 $10,976 $ (319)
====== ====== ======== =======
Net income (loss) per share:
Basic - as reported $ 0.16 $0.06 $ 0.55 $(0.02)
====== ====== ======== =======
Basic - pro forma $ 0.16 $0.06 $ 0.54 $(0.02)
====== ====== ======== =======
Diluted - as reported $ 0.13 $0.06 $ 0.43 $(0.02)
====== ====== ======== =======
Diluted - pro forma $ 0.13 $0.06 $ 0.42 $(0.02)
====== ====== ======== =======
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, 2003:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, 2003 SEPTEMBER 30, 2003
------------------- -------------------
(In thousands)
Beginning asset retirement obligations $ 2,062 $ 1,931
Liabilities incurred 82 142
Accretion expense 39 110
------------------- -------------------
Ending asset retirement obligations $ 2,183 $ 2,183
=================== ===================
7. STOCK BASED COMPENSATION
Brigham accounts for employee stock-based compensation using the intrinsic
value method prescribed by Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees". Accordingly,
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Brigham has adopted the disclosure-only provisions of Statement of Financial
Accounting Standards No. 123, "Accounting for Stock-Based Compensation" (SFAS
123).
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
(loss) and net income (loss) per share for the three and nine month periods
ended September 30, 2003 and 2002 would have been the pro forma amounts
indicated below:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------- -----------------
2003 2002 2003 2002
------- ------- -------- -------
(In thousands, except per share amounts)
Net income (loss) available to common stockholders - basic:
As reported $3,343 $ 989 $11,244 $ (282)
Add back: Stock compensation expense
previously included in net income 5 3 10 13
Effect of total employee stock-based
compensation expense, determined
under fair value method for all awards (98) (95) (279) (297)
------- ------- -------- -------
Pro forma $3,250 $ 897 $10,975 $ (566)
======= ======= ======== =======
Net income (loss) available to common stockholders - diluted:
As reported $4,032 $1,128 $13,959 $ (282)
Add back: Stock compensation expense
previously included in net income 5 3 10 13
Effect of total employee stock-based
compensation expense, determined
under fair value method for all awards (98) (95) (279) (297)
------- ------- -------- -------
Pro forma $3,939 $1,036 $13,690 $ (566)
======= ======= ======== =======
Net income (loss) per share:
Basic:
As reported $ 0.16 $ 0.06 $ 0.55 $(0.02)
Pro forma 0.15 0.06 0.54 (0.04)
Diluted:
As reported $ 0.13 $ 0.06 $ 0.43 $(0.02)
Pro forma 0.13 0.06 0.42 (0.04)
8. ISSUANCE OF COMMON STOCK
In September 2003, Brigham issued 7,384,090 shares of common stock in a
public offering and received proceeds of approximately $40 million, net of
underwriting commissions and other offering expenses. The proceeds of the
offering will be used to accelerate exploration and development activities and
for general corporate purposes. Following the offering, proceeds were used to
pay down the senior credit facility.
9. RECENT ACCOUNTING PRONOUNCEMENTS
In May 2003, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity''
(SFAS 150). SFAS 150 requires an issuer to classify certain financial
instruments, such as mandatorily redeemable preferred stock, as liabilities (or
assets in some circumstances). Brigham adopted this standard as required on July
1, 2003. Upon adoption, the balance sheet classification of the mandatorily
redeemable Series A and B preferred stock did not change because these
instruments do not meet the criteria of
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
mandatorily redeemable financial instruments as defined by SFAS 150. SFAS 150
defines a financial instrument as mandatorily redeemable if it embodies an
unconditional obligation requiring the issuer to redeem the instrument by
transferring its assets at a specified or determinable date(s) or upon an event
certain to occur. The mandatorily redeemable Series A and B preferred stock do
not embody an unconditional obligation requiring Brigham to transfer its assets
to redeem the instruments.
Statement of Financial Accounting Standards No. 141, "Business
Combinations" (SFAS 141) and Statement of Financial Accounting Standards, No.
142, "Goodwill and Intangible Assets" (SFAS 142) were issued by the FASB in June
2001 and became effective for us on July 1, 2001 and January 1, 2002,
respectively. SFAS 141 requires all business combinations initiated after June
30, 2001 to be accounted for using the purchase method. Additionally, SFAS 141
requires companies to disaggregate and report separately from goodwill certain
intangible assets. SFAS 142 establishes new guidelines for accounting for
goodwill and other intangible assets. Under SFAS 142, goodwill and certain other
intangible assets are not amortized, but rather are reviewed annually for
impairment. The appropriate application of SFAS 141 and 142 to oil and gas
mineral rights held under lease and other contractual arrangements representing
the right to extract such reserves is unclear. Depending on how the accounting
and disclosure literature is clarified, these oil and gas mineral rights held
under lease and other contractual arrangements representing the right to extract
such reserves for both undeveloped and developed leaseholds may be classified
separately from oil and gas properties, as intangible assets on our balance
sheets. Additional disclosures required by SFAS 141 and 142 would be included
in the notes to financial statements. Historically, we, like many other oil and
gas companies, have included these oil and gas mineral rights held under lease
and other contractual arrangements representing the right to extract such
reserves as part of the oil and gas properties, even after SFAS 141 and 142
became effective.
This interpretation of SFAS 141 and 142 would only affect our balance sheet
classification of oil and gas leaseholds. Our results of operations and cash
flows would not be affected, since these oil and gas mineral rights held under
lease and other contractual arrangements representing the right to extract such
reserves would continue to be amortized in accordance with accounting rules for
oil and gas companies provided in Statement of Financial Accounting Standards
No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies".
At September 30, 2003 we had undeveloped leaseholds of approximately $4.2
million that would be classified on our balance sheet as "intangible undeveloped
leasehold" and developed leaseholds of an estimated $0.4 million that would be
classified as "intangible developed leaseholds" if we applied the interpretation
currently being deliberated. This classification would require us to make the
disclosures set forth under SFAS 142 related to these interests.
Brigham will continue to classify our oil and gas leaseholds as tangible
oil and gas properties until further guidance is provided.
10. SUBSEQUENT EVENT
In November 2003, Brigham notified the holder of the Series A warrants of
its intent to exercise its right to force the exercise of warrants to purchase
6.7 million shares of common stock at an exercise price of $3.00 per share.
Brigham will receive no additional proceeds from the exercise of the warrants.
The 6.7 million shares issued upon the exercise of the warrants have not been
registered under the Securities Act of 1933. Subsequent to the exercise,
Brigham will have approximately 34.6 million shares of common shares
outstanding. The exercise will effectively convert 1,000,000 shares of
mandatorily redeemable Series A Preferred Stock to 6.7 million shares of common
stock and will reduce the carrying value of the mandatorily redeemable Series A
Preferred Stock by approximately $9.0 million, increase the common stock balance
by approximately $67,000 and increase additional paid in capital by
approximately $9.0 million.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following updates information as to the Company's financial condition
provided in our 2002 Annual Report on Form 10-K/A, and analyzes the changes in
the results of operations between the three and nine-month periods ended
September 30, 2003, and the comparable periods for 2002.
Overview
In September 2003, we sold 7,384,090 shares of common stock for $5.85 per
share and received net proceeds, after paying the underwriting discount and
other offering expenses, of $40 million. In connection with our common stock
offering we have accelerated our budgeted capital spending for 2003 to $51.5
million up from $39.3 million at the start of 2003. See also "Liquidity and
Capital Resources-Capital Expenditures".
In November 2003, we notified the holder of our Series A warrants of our
intent to exercise our right to force the exercise of warrants to purchase 6.7
million shares of common stock at an exercise price of $3.00 per share. We will
receive no additional proceeds from the exercise of the warrants. The 6.7
million shares issued upon the exercise of the warrants have not been registered
under the Securities Act of 1933. Subsequent to the exercise, we will have
approximately 34.6 million shares of common shares outstanding. The exercise
will effectively convert 1,000,000 shares of mandatorily redeemable Series A
Preferred Stock to 6.7 million shares of common stock and will reduce the
carrying value of our mandatorily redeemable Series A Preferred Stock by
approximately $9.0 million, increase our common stock balance by approximately
$67,000 and increase additional paid in capital by approximately $9.0 million.
For the three-month period ended September 30, 2003, we recorded net income
to common stockholders of $3.3 million, or $0.13 per diluted share, on total
revenues of $13.2 million compared to net income of $1.0 million, or $0.06 per
diluted share, on total revenues of $9.4 million for the three-month period
ended September 30, 2002.
For the nine-month period ended September 30, 2003, our net income to
common stockholders was $11.2 million, or $0.43 per diluted share, on total
revenues of $40.1 million compared to a net loss of $282,000 or $0.02 per
diluted share, on total revenues of $24.7 million for the nine-month period
ended September 30, 2002.
One trend expected by our management to have an effect on our liquidity is
an increased demand for drilling equipment and services, leases, and
economically attractive prospects due to the current environment of higher
commodity prices. This may result in less availability and higher costs for
these resources. In addition, we may face additional competition from both
domestic and international sources of supply, which may exert a downward
pressure on the prices we ultimately receive for our products. See also
"Liquidity and Capital Resources-Senior Credit Facility".
LIQUIDITY AND CAPITAL RESOURCES
Our primary sources of cash during the first nine months of 2003 were net
cash provided by operating activities, net proceeds from the sale of common
stock and proceeds from the exercise of employee stock options. This cash was
used to fund the costs associated with drilling, land acquisition and 3-D
seismic acquisition, processing and interpretation, and to reduce the level of
borrowings outstanding under our senior credit facility. Net cash provided by
operations, along with the remaining availability under our senior credit
facility and our cash balance at September 30, 2003, are projected to be
sufficient to fund our capital expenditures for the remainder of 2003.
Cash Flow from Operating Activities
NINE MONTHS ENDED SEPTEMBER 30,
2003 2002
-------------- ---------------
(In thousands, unaudited)
Net cash provided by operating activities $ 32,425 $ 22,195
Net cash provided by operating activities for the first nine months of 2003
increased 46% when compared to net cash provided by operating activities for the
same period last year. The increase in net cash provided by operating
activities was primarily due to an increase in both commodity prices and
production volumes and lower interest expense on our senior credit facility.
This increase was partially offset by an increase in our production costs. We
had a working capital deficit of $7.0 million at September 30, 2003, compared to
a working capital deficit of $688,000 at December 31, 2002. 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 exploration and
development costs, royalties payable and gas imbalance payables related to
production from six wells in the Home Run Field. Settlement of these payables
will be funded by cash flows from operations or, if necessary, by draw downs on
our senior credit facility. Our gas imbalance payables are partially offset by
gas imbalance receivables related to four wells in the Triple Crown and Floyd
Fault Block Fields. Our gas imbalance related to the wells in the Home Run,
Triple Crown and Floyd Fault Block Fields was partially settled in November
2003. Due to the settlement, we borrowed an additional $4 million under our
senior credit facility. The settlement will reduce the balance of our gas
imbalance payable by approximately $11.3 million and will reduce the balance of
our gas imbalance receivable by approximately $6.3 million. The settlement of
the gas imbalance receivable resulted in an increase to revenue of approximately
$1.0 million due to higher prices received through the settlement. At September
30, 2003, current liabilities included a liability of $1.1 million related to
the fair value of hedging contracts, which was partially offset by a current
asset of $91,000 related to the fair value of hedging contracts.
Cash Flows from Investing Activities
NINE MONTHS ENDED SEPTEMBER 30,
2003 2002
-------------- ---------------
(In thousands, unaudited)
Net cash used by investing activities $ (29,402) $ (18,850)
A 64% increase in net capital expenditures for the first nine months of
2003 over net capital expenditures during the first nine months of 2002 is the
primary reason for the increase in net cash used by investing activities.
Cash Flows from Financing Activities
NINE MONTHS ENDED SEPTEMBER 30,
2003 2002
-------------- ---------------
(In thousands, unaudited)
Net cash provided (used) by financing activities $ (7,325) $ 3,725
Net cash provided (used) by financing activities for the first nine months
of 2003 included $40 million in net proceeds, after paying the underwriting
discount and other offering expenses, from the sale of common stock in September
2003 and approximately $660,000 in proceeds from the exercise of employee stock
options. We used the net proceeds from the sale of common stock to repay $40
million of borrowings that were outstanding under our senior credit facility.
In addition, during the first two quarters of 2003 we repaid $7.0 million of
borrowings outstanding under our senior credit facility and incurred $985,000 in
loan origination fees associated with putting in place our new senior credit
facility in March 2003. During the first nine-month period of 2002 we borrowed
an additional $4.0 million in senior subordinated notes and received $113,000 in
proceeds from the exercise of employee stock options. During this same period we
paid $360,000 in fees associated with our senior credit facility and
subordinated notes and $28,000 in capital lease obligations.
Senior Credit Facility
In March 2003, we replaced our senior credit facility with a new senior
credit facility that provides for a maximum $80 million in commitments and an
initial borrowing base of $70 million and matures in March 2006. However, in
the event that our senior subordinated notes are not retired or refinanced prior
to July 31, 2005, the senior credit facility will mature on August 31, 2005.
Our borrowing base on September 30, 2003, was $68.5 million. Borrowings under
the new credit facility are secured by substantially all of our oil and natural
gas properties and other tangible assets and bear interest at either the base
rate of Soci t G n rale or London Interbank Offered Rate (LIBOR), at our
option, plus a margin that varies according to facility usage. Interest is paid
quarterly. The collateral value and borrowing base are redetermined
semi-annually and are based in part on prevailing oil and natural gas prices.
If, upon redetermination, our borrowing base decreases, we may have to repay a
portion of our borrowings immediately, our access to further borrowings will be
reduced, and we may not have the resources necessary to carry out our planned
drilling activities. The unused portion of the committed borrowing base is
subject to an annual commitment fee of 0.5%. Net proceeds from the sale of our
common stock in September 2003 were used to repay $40 million of borrowings
outstanding under our senior credit facility. In addition, during the first six
months of 2003, we repaid $7.0 million of borrowings outstanding under our
senior credit facility. As of September 30, 2003, we had $13 million of
borrowings outstanding and $55.5 million in additional borrowing capacity under
our senior credit facility. The interest rate on borrowings outstanding under
our credit facility as of September 30, 2003 was 2.62%. Our current ratio at
September 30, 2003 and interest coverage ratio for the twelve-month period
ending September 30, 2003, were 2.3 to 1 and 7.0 to 1, respectively. We were in
compliance with all covenants at September 30, 2003.
Capital Expenditures
Our capital spending budget at the start of 2003 was $39.3 million. Upon
completion of our sale of common stock in September 2003 we increased the amount
that we expect to spend in 2003 to $51.5 million. The majority of our remaining
2003 expenditures will be directed toward the drilling of our exploration and
development inventory consistent with our primary objective of growing reserves,
production volumes and cash flow. Approximately 66% of our 2003 drilling
expenditures will be dedicated to development drilling. For 2003, we plan to
spend $37.7 million in drilling capital expenditures to drill 42 (25 development
and 17 exploratory) wells with an average working interest of approximately 42%.
This is up from our original budget of $27.9 million to drill 41 wells with an
average working interest of 36%. Spending will be funded by our cash flow from
operations, availability under our senior credit facility and our current cash
balance. Our accelerated capital expenditure budget for 2003 represents an
increase of approximately 31% from that of our original 2003 budget. Capital
spending for the three and nine months ending September 30, 2003 and 2002 is
summarized as follows:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------- ------------------
2003 2002 2003 2002
-------- ------- -------- --------
(In thousands, unaudited)
Drilling $ 7,958 $2,311 $20,641 $12,176
Land and geological & geophysical 1,719 1,241 4,195 2,365
Capitalized general & administrative and interest 1,463 1,332 4,623 3,914
Proceeds from participants and sales (831) (653) (1,183) (1,270)
-------- ------- -------- --------
Net capital expenditures on oil and gas activities $10,309 $4,231 $28,276 $17,185
Other property and equipment 38 35 247 218
-------- ------- -------- --------
Total net capital expenditures $10,347 $4,266 $28,523 $17,403
======== ======= ======== ========
Actual capital spending may vary and is subject to changing market
conditions. The 2003 capital expenditure budget and the accelerated capital
budget were developed using certain assumed price levels for the sales of crude
oil and natural gas and forecasted production growth. Changes in commodity
prices or variances from forecasted production growth could impact our cash
flows from operations and funds available for reinvestment. For example,
shortfalls in budgeted cash flows from operations could result in the reduction
of the our capital spending program, increases in borrowing under our new senior
credit facility, issuance of additional equity or debt securities or
divestments of properties. We evaluate our level of capital spending throughout
the year based upon drilling results, commodity prices and cash flows from
operations.
RESULTS OF OPERATIONS
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------- ----------------
2003 2002 2003 2002
------- ------- ------- -------
(In thousands, unaudited)
Production (in thousands):
Natural gas (MMcf) 1,648 1,463 4,648 4,307
Oil (MBbls) 160 189 562 504
Natural gas equivalent (MMcfe) 2,608 2,599 8,019 7,332
% Natural gas 63% 56% 58% 59%
Average sales prices per unit (after hedging)
Natural gas (per Mcf) $ 5.27 $ 3.23 $ 5.17 $ 3.02
Oil (per Bbl) 28.08 24.85 28.31 23.04
Weighted average (per Mcfe) 5.05 3.63 4.98 3.36
Costs and expenses per Mcfe:
Lease operating $ 0.69 $ 0.29 $ 0.50 $ 0.33
Production taxes 0.21 0.18 0.29 0.18
General and administrative 0.42 0.42 0.43 0.52
Depletion of oil and natural gas properties 1.52 1.38 1.48 1.38
Comparison of the three-month and nine-month periods ended September 30, 2003
and 2002
Production. Our production for the three-month period ended September 30,
2003 was up slightly when compared to production for the three-month period
ended September 30, 2002. Our average net equivalent daily production volumes
for the third quarter 2003 were 29.0 MMcfe/d compared to 28.9 MMcfe/d for the
same period of 2002. New production related to recently completed wells was
partially offset by the natural decline of existing production. Natural gas
represented 63% of our total production volumes during the third quarter of 2003
compared to 56% during the third quarter of 2002.
For the nine-month period ended September 30, 2003 compared to the
nine-month period ended September 30, 2002, our net equivalent production volume
increased 9%. Our average net equivalent daily production volumes for the first
nine months of 2003 were 29.7 MMcfe/d compared to 27.2 MMcfe/d for the same
period of 2002. The increase in our production volume was due to production
growth from wells that were drilled and completed during late 2002 or the first
nine months of 2003. New production related to these recently completed wells
was partially offset by the natural decline of existing production. Natural gas
represented 58% of our total production volumes during the first nine months of
2003 compared to 59% during the first nine months of 2002.
Revenues from the sale of oil and natural gas. Revenues from the sale of
oil and natural gas for the three-month period ended September 30, 2003 were 40%
higher than revenues for the three-month period ended September 30, 2002.
Higher commodity prices accounted for approximately all of this increase.
Revenues from the sale of oil and natural gas for the third quarter 2003
including $953,000 in price adjustments due to the settlement of our gas
imbalance were $13.2 million compared to $9.4 million during the third quarter
of 2002. Revenues from the sale of oil and natural gas for the third quarter
2003 included a loss of $1.1 million related to the cash settlement of hedging
transactions compared to a loss of $501,000 during the third quarter of 2002.
Revenues from the sale of oil and natural gas for the nine-month period
ended September 30, 2003 including $953,000 in price adjustments due to the
settlement of our gas imbalance were 62% higher than revenues for the nine-month
period ended September 30, 2002. Higher commodity prices accounted for
approximately all of this increase. Revenues from the sale of oil and natural
gas for the first nine months of 2003 were $39.9 million compared to $24.6
million for the first nine months of 2002. Revenues from the sale of oil and
natural gas for the first nine months of 2003 included a loss of $6.1 million
related to the cash settlement of hedging transactions compared to a loss of
$804,000 during the first nine months of 2002.
Production costs. Production costs include the cost of labor and
supervision to operate the wells and related equipment; repairs and maintenance;
related materials, fuel, and supplies utilized in operating the wells and
related equipment and facilities; property taxes and insurance applicable to
wells and related facilities and equipment; and severance taxes.
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------- --------------
2003 2002 2003 2002
------ ------ ------ ------
(In thousands, unaudited)
Lease operating expenses, excluding ad valorem taxes $1,624 $ 692 $3,538 $2,218
Ad valorem taxes 169 69 499 210
------ ------ ------ ------
Total lease operating expenses $1,793 $ 761 $4,037 $2,428
Production taxes 553 475 2,297 1,327
------ ------ ------ ------
Total production cost $2,346 $1,236 $6,334 $3,755
====== ====== ====== ======
Production costs for the three-month period ended September 30, 2003
increased 90% when compared to production costs during the three-month period
ended September 30, 2002.
- - An increase in our lease operating expenses excluding ad valorem taxes
represented 84% of this increase. Fifty-five percent of this increase was
related to an increase in workover expense due to an increase in workover
activity and 45% was due to well service and repair, insurance, saltwater
disposal and other routine operating expenses.
- - An increase in our ad valorem taxes due to higher property valuations
represented 9% of this increase.
- - An increase in our production taxes represented 7% of this increase.
Production taxes for the third quarter 2003 were higher due to an increase
in our realized sales price of oil and natural gas. Production taxes for
the third quarter 2003 were 4.2% of our total revenues from the sale of oil
and natural gas before hedging effects, compared to 4.8% for the third
quarter 2002.
Production cost for the nine-month period ended September 30, 2003
increased 69% when compared to production cost during the nine-month period
ended September 30, 2002.
- - An increase in our lease operating expenses excluding ad valorem taxes
represented 51% of this increase. Forty-five percent of this increase was
related to an increase in workover expense due to an increase in workover
activity and 55% was due to well service and repair, insurance, compressor
rental and maintenance, electricity, power, and fuel and other routine
operating expenses.
- - An increase in our ad valorem taxes due to higher property valuations
represented 11% of this increase.
- - An increase in our production taxes represented 38% of this increase.
Production taxes for the first nine months of 2003 were higher due to an
increase in our realized price for oil and natural gas. Production taxes
for the first nine months of 2003 were 5.1% of our total revenues from the
sale of oil and natural gas before hedging effects, compared to 5.2% for
the first nine months of 2002.
General and administrative expenses. General and administrative expenses
for the three-month period ended September 30, 2003 were flat when compared to
general and administrative expenses in the third quarter of 2002. Increases in
payroll and benefit expenses, corporate insurance, financial reporting expenses
and fees paid to directors were offset by a decrease in both fess paid for
contract and professional services and travel expenses and an increase in the
industry overhead rate.
General and administrative expenses for the nine-month period ending
September 30, 2003 were 10% lower than general and administrative expenses
during the first nine months of 2002. General and administrative expenses for
the first nine months of 2002 included a non-cash charge for compensation
expense of $596,000 related to vesting of options by an officer who left
Brigham. Excluding this non-cash charge general and administrative expenses for
the first nine months of 2003 were 7% higher than general and administrative
expenses for the first nine months of 2002. Increases in payroll and benefit
expenses, corporate insurance, financial reporting expenses
and fees paid to directors were the primary reasons for the increase. These
increases were partially offset by a decrease in office rent and miscellaneous
office expenses and an increase in the industry overhead rate.
Depletion of oil and natural gas properties. Depletion expenses for the
third quarter 2003 were 10% higher than depletion expenses for the third quarter
of 2002. Approximately 97% of this change was due to an increase in our per
unit depletion rate. The increase in the depletion rate was due to an increase
in future development costs and higher finding and development costs incurred
during the period.
Depletion expenses for the nine-month period ending September 30, 2003 were
17% higher than depletion expenses during the first nine months of 2002.
Approximately 55% of the increase in our depletion expenses for the first nine
months of 2003 was due to higher production volumes and approximately 45% of the
increase was due to the increase in our per unit depletion rate. The increase
in our depletion rate was due to an increase in future development costs and
higher finding and development costs incurred during the period.
Interest expense.
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------ ------------------
2003 2002 2003 2002
-------- -------- -------- --------
(In thousands, unaudited)
Interest on senior credit facility $ 418 $ 925 $ 1,563 $ 2,759
Interest on senior subordinated notes (a) 612 580 1,792 1,656
Commitment fees 10 - 44 3
Amortization of deferred loan and debt issue cost 276 303 809 888
Other general interest expense 6 10 35 33
Capitalized interest expense (212) (204) (627) (655)
-------- -------- -------- --------
Net interest expense $ 1,110 $ 1,614 $ 3,616 $ 4,684
======== ======== ======== ========
Weighted average debt outstanding $71,673 $96,412 $76,865 $95,599
Average interest rate on outstanding indebtedness (b) 5.8% 6.2% 5.9% 6.2%
____________________________________
(a) Fifty percent of the interest expense on our senior subordinated notes has been or will
be paid in kind. The option to pay a portion of this interest expense in kind expires
October 31, 2003.
(b) Calculated using the sum of the interest expense on our senior credit facility, senior
subordinated notes and commitment fees for the period divided by the average debt
outstanding for the period.
Interest expense for the three-month period ended September 30, 2003
decreased 31% when compared to interest expense for the same period last year.
A decrease in the amount of borrowings outstanding under our senior credit
facility during the third quarter 2003 and lower interest rates on borrowings
outstanding under our senor credit facility were the primary reasons for the
decrease in interest expense. This decrease was partially offset by an increase
in the interest expense on our senior subordinated notes.
Interest expense for the nine-month period ended September 30, 2003
decreased 23% when compared to interest expense for the same nine-month period
last year. A decrease in the amount of borrowings outstanding under our senior
credit facility for the first nine months of 2003 and lower interest rates on
borrowings outstanding under our senor credit facility were the primary reasons
for the decrease in interest expense. This decrease was partially offset by an
increase in the interest expense on our senior subordinated notes.
Other income (expense). Other income (expense) consisted primarily of
non-cash gains (losses) resulting from the change in fair market value of oil
and gas derivative contracts that did not qualify as hedges, cash gains (losses)
on the settlement of these contracts and non-cash gains (losses) related to
charges for the ineffective portion of cash flow hedges. Other income (expense)
included:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------- --------------
2003 2002 2003 2002
------ ------ ------ ------
(In thousands, unaudited)
Non-cash gain (loss) due to the change in the fair
market value of derivative contracts that did not
qualify as hedges $ - $ - $ - $ 384
Non-cash gain (loss) for ineffective portion of hedges (80) (106) (250) (106)
Cash settlement of derivatives that did not qualify as
hedges - - - (559)
Other - 19 - 25
------ ------ ------ ------
Total $ (80) $ (87) $(250) $(256)
====== ====== ====== ======
Dividends and accretion of mandatorily redeemable preferred stock. We are
required to pay dividends on our Series A and Series B preferred stock. At our
option, these dividends may 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 during the
first three quarters of 2003 and the first three quarters of 2002. The following
table shows the effect on our balance sheet of the issuance of additional shares
of preferred stock in lieu of cash dividends.
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------- -----------------
2003 2002 2003 2002
------- ------- -------- -------
(In thousands, unaudited)
Dividends $ 950 $ 684 $ 2,767 $ 1,991
Accretion of mandatorily redeemable preferred stock 115 62 321 174
------- ------- -------- -------
Total $ 1,065 $ 746 $ 3,088 $ 2,165
======= ======= ======== =======
Additional preferred shares issued:
Series A 37,024 34,204 107,752 99,546
Series B 10,516 - 30,603 -
OTHER MATTERS
Derivative Contracts
We regularly enter into commodity derivative contracts to reduce the impact
on operations of fluctuations in oil and gas prices. All such contracts are
entered into solely to hedge prices and limit volatility. The contracts, which
are generally placed with major financial institutions or with counterparties
which management believes to be of high credit quality, may take the form of
swaps, collars or floors.
The table below summarizes our total production volumes for both natural
gas and oil that were subject to derivative transactions for the three and nine
months ended September 30, 2003 and 2002 and the weighted average NYMEX
reference price for those volumes.
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------ ----------------------
2003 2002 2003 2002
-------- -------- ---------- ----------
NATURAL GAS SWAPS:
Volumes (MMbtu) 598,000 920,000 2,249,500 2,227,500
Weighted average price ($/MMbtu) $ 3.867 $ 3.165 $ 3.772 $ 3.007
NATURAL GAS FLOORS:
Volumes (MMbtu) 460,000 - 610,000 -
Weighted average floor price ($/MMbtu) $ 4.50 $ - $ 4.50 $ -
NATURAL GAS CAPS:
Volumes (MMbtu) - - - 1,810,000
Weighted average floor price ($/MMbtu) $ - $ - $ - $ 2.633
CRUDE OIL SWAPS:
Volumes (Bbls) 55,200 46,000 184,125 46,000
Weighted average price ($/Bbl) $ 23.77 $ 25.06 $ 24.81 $ 25.06
CRUDE OIL COLLARS:
Volumes (Bbls) - 46,000 45,250 158,500
Weighted average floor price ($/Bbl) $ - $ 18.00 $ 18.00 $ 18.00
Weighted average ceiling price ($/Bbl) - 22.46 22.56 22.34
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 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 June 2001, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Standards No. 143, "Accounting for Asset Retirement
Obligations" (SFAS 143) which establishes accounting requirements for retirement
obligations associated with tangible long-lived assets including the timing of
the liability recognition, initial measurement of the liability, allocation of
asset retirement cost to expense, subsequent measurement of the liability and
financial statement disclosures. SFAS 143 requires that an asset retirement cost
be capitalized as part of the cost of the related long-lived asset and
subsequently allocated to expense using a systematic, rational method. 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 our consolidated statements of operations upon adoption
on January 1, 2003.
In May 2003, the FASB issued Statement of Financial Accounting Standards
No. 150, "Accounting for Certain Financial Instruments with Characteristics of
both Liabilities and Equity'' (SFAS 150). SFAS 150 requires an issuer to
classify certain financial instruments, such as mandatorily redeemable preferred
stock, as liabilities (or assets in some circumstances). We adopted this
standard as required on July 1, 2003. Upon adoption, the balance sheet
classification of the mandatorily redeemable Series A and B preferred stock did
not change because these instruments do not meet the criteria of mandatorily
redeemable financial instruments as defined by SFAS 150. SFAS 150 defines a
financial instrument as mandatorily redeemable if it embodies an unconditional
obligation requiring the issuer to redeem the instrument by transferring its
assets at a specified or determinable date(s) or upon an event certain to occur.
The mandatorily redeemable Series A and B preferred stock do not embody an
unconditional obligation requiring us to transfer our assets to redeem the
instruments.
Statement of Financial Accounting Standards No. 141, "Business
Combinations" (SFAS 141) and Statement of Financial Accounting Standards, No.
142, "Goodwill and Intangible Assets" (SFAS 142) were issued by the FASB in June
2001 and became effective for us on July 1, 2001 and January 1, 2002,
respectively. SFAS 141 requires all business combinations initiated after June
30, 2001 to be accounted for using the purchase method. Additionally, SFAS 141
requires companies to disaggregate and report separately from goodwill certain
intangible assets. SFAS 142 establishes new guidelines for accounting for
goodwill and other intangible assets. Under SFAS 142, goodwill and certain other
intangible assets are not amortized, but rather are reviewed annually for
impairment. The appropriate application of SFAS 141 and 142 to oil and gas
mineral rights held under lease and other contractual arrangements representing
the right to extract such reserves is unclear. Depending on how the accounting
and disclosure literature is clarified, these oil and gas mineral rights held
under lease and other contractual arrangements representing the right to extract
such reserves for both undeveloped and developed leaseholds may be classified
separately from oil and gas properties, as intangible assets on our balance
sheets. Additional disclosures required by SFAS 141 and 142 would be included
in the notes to financial statements. Historically, we, like many other oil and
gas companies, have included these oil and gas mineral rights held under lease
and other contractual arrangements representing the right to extract such
reserves as part of the oil and gas properties, even after SFAS 141 and 142
became effective.
This interpretation of SFAS 141 and 142 would only affect our balance sheet
classification of oil and gas leaseholds. Our results of operations and cash
flows would not be affected, since these oil and gas mineral rights held under
lease and other contractual arrangements representing the right to extract such
reserves would continue to be amortized in accordance with accounting rules for
oil and gas companies provided in Statement of Financial Accounting Standards
No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies".
At September 30, 2003 we had undeveloped leaseholds of approximately $4.2
million that would be classified on our balance sheet as "intangible undeveloped
leasehold" and developed leaseholds of an estimated $0.4 million that would be
classified as "intangible developed leaseholds" if we applied the interpretation
currently being deliberated. This classification would require us to make the
disclosures set forth under FAS 142 related to these interests.
We will continue to classify our oil and gas leaseholds as tangible oil and
gas properties until further guidance is provided.
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 the 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.
- 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.
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/A for the fiscal year ended December 31, 2002. As
such, the information contained herein should be read in conjunction with the
related disclosures in our Annual Report on Form 10-K/A for the fiscal year
ended December 31, 2002.
DERIVATIVE CONTRACTS
The table below summarizes the derivative contracts which we were a party
to at September 30, 2003, the total natural gas and crude oil production volumes
subject to those contacts, the weighted average NYMEX reference price for those
volumes and the unrealized gain (loss) for those contracts.
SWAPS COLLARS FLOORS
----------------------------- ----------------------------------- --------------------------
Weighted Weighted Average Weighted
Average Floor Ceiling Average Unrealized
NATURAL GAS Volumes Swap Price Volumes Price Price Volumes Floor Price gain / (loss)
--------- ------------------ --------- ---------- ------------ --------- --------------- --------------
(MMbtu) ($/MMbtu) (MMbtu) ($/MMbtu) (MMbtu) ($/MMbtu) (In thousands)
Quarter Ended:
December 31, 2003 414,000 $ 4.039 - $ - $ - 460,000 $ 4.500 $ (279)
March 31, 2004 295,750 4.963 455,000 4.100 8.540 - - (66)
June 30, 2004 227,500 4.252 318,500 4.107 5.300 - - (149)
September 30, 2004 138,000 4.180 230,000 4.100 5.266 - - (102)
December 31, 2004 92,000 4.360 184,000 4.125 5.565 - - (72)
March 31, 2005 - - 157,500 4.107 6.671 - - -
June 30, 2005 - - 136,500 4.083 5.107 - - (1)
CRUDE OIL (Bbls) ($/Bbl) (Bbls) ($/Bbl) (Bbls) ($/Bbl) (In thousands)
December 31, 2003 41,400 $ 23.21 - $ - $ - - $ - $ (230)
March 31, 2004 29,575 25.35 31,850 23.00 29.20 - - (97)
June 30, 2004 20,475 24.52 22,750 23.00 28.09 - - (69)
September 30, 2004 13,800 23.91 18,400 23.00 27.00 - - (51)
December 31, 2004 9,200 23.80 16,100 23.00 26.21 - - (35)
March 31, 2005 - - 15,750 23.00 25.85 - - (14)
June 30, 2005 - - 6,825 23.00 26.45 - - (2)
The table below summarizes derivative contracts that we entered into
subsequent to September 30, 2003, the total natural gas and crude oil production
volumes subject to those contacts, the weighted average NYMEX reference price
for those volumes and the unrealized gain (loss) for those contracts.
SWAPS COLLARS FLOORS
----------------------------- ------------------------------- -----------------------
Weighted Weighted Average Weighted
Average Floor Ceiling Average
NATURAL GAS Volumes Swap Price Volumes Price Price Volumes Floor Price
--------- ------------------ --------- ---------- -------- --------- ------------
(MMbtu) ($/MMbtu) (MMbtu) ($/MMbtu) (MMbtu) ($/MMbtu)
Quarter Ended:
March 31, 2004 - $ - 91,000 $ 4.250 $ 7.900 - $ -
June 30, 2004 - - 91,000 4.250 5.700 - -
September 30, 2004 - - 69,000 4.250 5.630 - -
December 31, 2004 - - 46,000 4.250 6.050 - -
March 31, 2005 - - 45,000 4.250 6.500 - -
CRUDE OIL (Bbls) ($/Bbl) (Bbls) ($/Bbl) (Bbls) ($/Bbl)
March 31, 2004 - $ - 13,650 $ 23.00 $ 33.30 - $ -
June 30, 2004 - - 9,100 23.00 31.00 - -
ITEM 4. CONTROLS AND PROCEDURES
Disclosure controls and procedures. As of the end of the period covered by this
report, our principal executive officer (CEO) and principal financial officer
(CFO) carried out an evaluation of the effectiveness of our disclosure controls
and procedures. Based on this evaluation, the CEO and CFO believe that our
disclosure controls and procedures are designed to ensure that information
required to be disclosed by us in the reports it files under the Securities
Exchange Act of 1934 is recorded, processed, summarized and reported within the
time periods specified in the Securities and Exchange Commission's rules and
forms and that such information is accumulated and communicated to our
management, including the CEO and CFO, as appropriate to allow timely decisions
regarding required disclosure; and that our disclosure controls and procedures
are effective.
Internal controls over financial reporting. There have been 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
evaluation of our disclosure controls and procedures.
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, we are party to various legal actions
arising in the ordinary course of business and do not expect these matters to
have a material adverse effect on our financial condition, results of operations
or cash flow.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
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
(b) Reports on Form 8-K:
We submitted a report on Form 8-K on August 12, 2003, to announce our
financial results for the second quarter 2003. The Form 8-K included a copy of
the press release that provided this announcement.
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 12, 2003.
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