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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 March 31, 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 Classification Code Identification
organization) Number) 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 May 12, 2004 39,625,276
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BRIGHAM EXPLORATION COMPANY
FIRST QUARTER 2004 FORM 10-Q REPORT
TABLE OF CONTENTS
-----------------
PAGE
----
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Consolidated Balance Sheets - March 31, 2004 and December 31, 2003. . . . . . . . . . . . . . 1
Consolidated Statements of Operations - Three months ended March 31, 2004 and 2003. . . . . . 2
Consolidated Statement of Changes in Stockholders' Equity - Three months ended March 31, 2004 3
Consolidated Statements of Cash Flows - Three months ended March 31, 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. . . . . . . . . . . . . . . . . . 26
ITEM 4. CONTROLS AND PROCEDURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
ITEM 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES. . . . . . . 28
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
SIGNATURES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
(UNAUDITED)
MARCH 31, DECEMBER 31,
2004 2003
----------- --------------
ASSETS
Current assets:
Cash and cash equivalents $ 7,659 $ 5,779
Accounts receivable 13,815 11,143
Deferred income taxes - 307
Other current assets 902 3,606
----------- --------------
Total current assets 22,376 20,835
----------- --------------
Oil and natural gas properties, net (full cost method) 209,503 197,311
Other property and equipment, net 1,251 1,219
Deferred income taxes 198 1,890
Deferred loan fees 2,320 2,501
Other noncurrent assets 253 460
----------- --------------
Total assets $ 235,901 $ 224,216
=========== ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 17,236 $ 19,806
Royalties payable 6,123 5,280
Accrued drilling costs 3,681 3,916
Participant advances received 622 1,179
Other current liabilities 4,334 5,398
----------- --------------
Total current liabilities 31,996 35,579
----------- --------------
Senior credit facility 29,200 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, 448,473 and 439,722 shares issued and outstanding at
March 31, 2004 December 31, 2003, respectively 8,969 8,794
Other noncurrent liabilities 2,923 2,498
Commitments and contingencies
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, 40,373,329 and 40,246,729 shares
issued and 39,192,706 and 39,086,096 shares outstanding at March 31, 2004 and December
31, 2003, respectively 404 402
Additional paid-in capital 152,085 151,263
Treasury stock, at cost; 1,180,623 and 1,160,633 shares at March 31, 2004 and December 31,
2003, respectively (4,559) (4,402)
Unearned stock compensation (2,173) (1,816)
Accumulated other comprehensive income (loss) (1,971) (1,040)
Accumulated deficit (973) (6,062)
----------- --------------
Total stockholders' equity 142,813 138,345
----------- --------------
Total liabilities and stockholders' equity $ 235,901 $ 224,216
=========== ==============
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
MARCH 31,
------------------
2004 2003
-------- --------
Revenues:
Oil and natural gas sales $16,819 $14,639
Other revenue 1 38
-------- --------
16,820 14,677
-------- --------
Costs and expenses:
Lease operating 1,409 974
Production taxes 863 938
General and administrative 1,220 1,139
Depletion of oil and natural gas properties 4,880 4,102
Depreciation and amortization 181 97
Accretion of discount on asset retirement obligations 37 34
-------- --------
8,590 7,284
-------- --------
Operating income 8,230 7,393
-------- --------
Other income (expense):
Interest income 14 21
Interest expense, net (782) (1,282)
Other income 127 111
-------- --------
(641) (1,150)
-------- --------
Income before income taxes and cumulative effect of
change in accounting principle 7,589 6,243
-------- --------
Income tax expense:
Current - -
Deferred (2,500) -
-------- --------
(2,500) -
-------- --------
Income before cumulative effect of change in accounting principle 5,089 6,243
Cumulative effect of change in accounting principle - 268
-------- --------
Net income 5,089 6,511
Less accretion and dividends on redeemable preferred stock - 995
-------- --------
Net income available to common stockholders $ 5,089 $ 5,516
======== ========
Net income per share available to common stockholders:
Basic
Income before cumulative effect of change in accounting principle $ 0.13 $ 0.27
Cumulative effect of change in accounting principle - 0.01
-------- --------
$ 0.13 $ 0.28
======== ========
Diluted
Income before cumulative effect of change in accounting principle $ 0.13 $ 0.19
Cumulative effect of change in accounting principle - 0.01
-------- --------
$ 0.13 $ 0.20
======== ========
Weighted average shares outstanding:
Basic 39,166 19,707
======== ========
Diluted 40,211 32,111
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
2
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
(UNAUDITED)
ACCUMULATED
COMMON STOCK ADDITIONAL UNEARNED OTHER
--------------- 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 - - - - - - 5,089
Unrealized gain (losses) on
cash flow hedges - - - - - (1,305) -
Tax benefits related to cash
flow hedges - - - - - 501 -
Net gains included in net
income - - - - - (127) -
Comprehensive income
Exercises of employee stock
options 126 2 308 - - - -
Issuance of restricted stock - - 514 - (514) - -
Forfeitures of restricted stock - - - (1) - - -
Repurchases of common
stock - - - (156) - - -
Amortization of unearned
stock compensation - - - - 157 - -
------ -------- ----------- ---------- -------------- --------------- -------------
Balance, March 31, 2004 40,373 $ 404 $ 152,085 $ (4,559) $ (2,173) $ (1,971) $ (973)
====== ======== =========== ========== ============== =============== =============
TOTAL
STOCKHOLDERS'
EQUITY
---------------
Balance, December 31, 2003 $ 138,345
Comprehensive income:
Net income 5,089
Unrealized gain (losses) on
cash flow hedges (1,305)
Tax benefits related to cash
flow hedges 501
Net gains included in net
income (127)
---------------
Comprehensive income 4,158
Exercises of employee stock
options 310
Issuance of restricted stock -
Forfeitures of restricted stock (1)
Repurchases of common
stock (156)
Amortization of unearned
stock compensation 157
---------------
Balance, March 31, 2004 $ 142,813
===============
The accompanying notes are an integral part of these consolidated financial
statements.
3
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
-------------------
2004 2003
--------- --------
Cash flows from operating activities:
Net income (loss) $ 5,089 $ 6,511
Adjustments to reconcile net income to cash provided by operating
activities:
Depletion of oil and natural gas properties 4,880 4,102
Depreciation and amortization 181 97
Interest paid through issuance of additional senior subordinated notes - 296
Interest paid through issuance of additional mandatorily redeemable preferred stock 175 -
Amortization of deferred loan fees and debt issuance costs 192 253
Market value adjustment for derivative instruments (127) (111)
Accretion of discount on asset retirement obligations 37 34
Deferred income taxes 2,500 -
Cumulative effect of change in accounting principle - (268)
Changes in assets and liabilities:
Accounts receivable (2,672) (3,981)
Other current assets 2,704 1,318
Accounts payable (2,570) 1,470
Royalties payable 843 2,947
Participant advances received (557) (594)
Other current liabilities (2,017) 3,017
Other noncurrent assets and liabilities (64) (29)
--------- --------
Net cash provided by operating activities 8,594 15,062
--------- --------
Cash flows from investing activities:
Additions to oil and natural gas properties (17,135) (8,921)
Proceeds from sale of oil and natural gas properties - 151
Additions to other property and equipment (129) (98)
(Increase) Decrease in drilling advances paid 207 (471)
--------- --------
Net cash used by investing activities (17,057) (9,339)
--------- --------
Cash flows from financing activities:
Increase in senior credit facility 10,200 -
Repayment of senior credit facility - (4,000)
Deferred loan fees paid (11) (988)
Proceeds from exercise of employee stock options 310 432
Repurchases of common stock (156) -
--------- --------
Net cash provided (used) by financing activities 10,343 (4,556)
--------- --------
Net increase in cash and cash equivalents 1,880 1,167
Cash and cash equivalents, beginning of year 5,779 15,318
--------- --------
Cash and cash equivalents, end of period $ 7,659 $16,485
========= ========
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 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 2003 Annual
Report on Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934.
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 agreed in principle to settle 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.
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 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.
5
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
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
may now appeal the ruling to the Oklahoma Supreme Court.
A company 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 has asserted
that it did not relinquish its entire interest, but rather became subject only
to a 400 percent payout provision. In November 2003, the company filed a lawsuit
against Brigham for breach of contract. The parties have reached an agreement in
principal and are working on settlement language. The settlement will result in
Brigham making a payment of approximately $390,000 to the other party in
exchange for an assignment of any interest owned by the other party 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
counterclaim did not specify the amount of damages claimed other than that the
damages exceed $75,000 (the jurisdictional limit). The parties settled the
lawsuit in April 2004 on terms favorable to Brigham. The settlement resulted in
a $50,000 payment to Brigham 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 (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 months ended March 31, 2004 and
2003:
THREE MONTHS ENDED
MARCH 31,
--------------------
2004 2003
--------- ---------
(In thousands, except
per share amounts)
Basic EPS:
Income (loss) available to common stockholders before cumulative
change in accounting principle $ 5,089 $ 5,248
Cumulative change in accounting principle - 268
--------- ---------
Income (loss) available to common stockholders $ 5,089 $ 5,516
========= =========
Common shares outstanding 39,166 19,707
========= =========
Basic EPS
Income (loss) available to common stockholders before change in
accounting principle $ 0.13 $ 0.27
Cumulative change in accounting principle - 0.01
--------- ---------
$ 0.13 $ 0.28
========= =========
6
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Diluted EPS:
Income (loss) available to common stockholders before cumulative
change in accounting principle $ 5,089 $ 5,248
Cumulative change in accounting principle - 268
--------- ---------
Income (loss) available to common stockholders 5,089 5,516
Adjustments for assumed conversions:
Dividends and accretion on mandatorily redeemable preferred stock (1) - 890
--------- ---------
- 890
--------- ---------
Income (loss) available to common stockholders before change in
accounting principle-diluted 5,089 6,138
Cumulative change in accounting principle - 268
--------- ---------
Income (loss) available to common stockholders-diluted $ 5,089 $ 6,406
========= =========
Common shares outstanding 39,166 19,707
Effect of dilutive securities:
Warrants - 744
Mandatorily redeemable preferred stock - 11,071
Stock options 1,045 589
--------- ---------
Potentially dilutive common shares 1,045 12,404
--------- ---------
Adjusted common shares outstanding-diluted 40,211 32,111
========= =========
Diluted EPS
Income (loss) available to common stockholders before change in
accounting principle $ 0.13 $ 0.19
Change in accounting principle - 0.01
--------- ---------
$ 0.13 $ 0.20
========= =========
(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.
At March 31, 2004 and 2003, options and warrants to purchase 61,000 and
13,000 shares of common stock, respectively, were outstanding but were not
included in the computation of diluted income (loss) per share because the
effects would have been antidilutive.
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.
7
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
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 month periods ended March 31, 2004 and 2003:
THREE MONTHS ENDED
MARCH 31,
----------------------
2004 2003
---------- ----------
NATURAL GAS
Average price per Mcf as reported (including hedging results) $ 5.69 $ 5.53
Average price per Mcf realized (excluding hedging results) $ 5.79 $ 7.23
Increase (decrease) in revenue (in thousands) $ (216) $ (2,506)
OIL
Average price per Bbl as reported (including hedging results) $ 30.84 $ 29.16
Average price per Bbl realized (excluding hedging results) $ 34.01 $ 32.88
Increase (decrease) in revenue (in thousands) $ (505) $ (828)
For the three months ended March 31, 2004 and 2003, ineffectiveness
associated with Brigham's derivative commodity instruments designated as cash
flow hedges increased earnings by approximately $0.1 million and $0.1 million,
respectively. These amounts are included in other income and expense.
NATURAL GAS DERIVATIVE CONTRACTS
The following table summarizes the hedging contracts to which Brigham was a
party at March 31, 2004, the total natural gas and crude oil production volumes
subject to those contacts and the weighted average NYMEX reference price for
those volumes:
SWAPS COLLARS
------------------- --------------------------
WEIGHTED AVERAGE
WEIGHTED ----------------
AVERAGE FLOOR CEILING
VOLUMES PRICE VOLUMES PRICE PRICE
-------- --------- -------- --------- -----
NATURAL GAS (MMbtu) ($/MMbtu) (MMbtu) ($/MMbtu)
Quarter Ended:
June 30, 2004 227,500 4.252 509,600 4.112 5.672
September 30, 2004 138,000 4.180 400,200 4.101 5.724
December 31, 2004 92,000 4.360 264,100 4.131 5.813
March 31, 2005 - - 202,500 4.139 6.633
June 30, 2005 - - 136,500 4.083 5.107
CRUDE OIL (Bbls) ($/Bbl) (Bbls) ($/Bbl)
Quarter Ended:
June 30, 2004 20,475 24.52 50,050 24.09 30.60
September 30, 2004 13,800 23.91 36,800 24.50 30.27
December 31, 2004 9,200 23.80 22,300 23.83 28.25
March 31, 2005 - - 15,750 23.00 25.85
June 30, 2005 - - 6,825 23.00 26.45
8
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
The following table summarizes the hedging contracts to which Brigham
entered subsequent to March 31, 2004, the total natural gas and crude oil
production volumes subject to those contacts and the weighted average NYMEX
reference price for those volumes:
COLLARS
---------------------------
WEIGHTED AVERAGE
-----------------
FLOOR CEILING
VOLUMES PRICE PRICE
-------- --------- ------
NATURAL GAS (MMbtu) ($/MMbtu)
Quarter Ended:
September 30, 2004 322,000 5.250 7.410
December 31, 2004 322,000 5.250 7.410
March 31, 2005 315,000 5.000 7.400
June 30, 2005 318,500 5.000 7.400
CRUDE OIL (Bbls) ($/Bbl)
Quarter Ended:
September 30, 2004 11,960 32.00 38.15
December 31, 2004 11,960 32.00 38.15
March 31, 2005 11,700 29.00 36.00
June 30, 2005 11,830 29.00 36.00
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 cash flow hedges 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 March 31, 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 March 31, 2004, approximately $0.7 million
of unrealized losses are included in accumulated other comprehensive income
(loss) on the balance sheet which represents the fair values of the interest
rate swap agreement as of that date. 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.
The fair value of 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 subsequent year.
MARCH 31,
--------------
2004 2003
------ -------
Other current liabilities $3,111 $3,038
Other noncurrent liabilities 374 100
Other current assets - 308
Other noncurrent assets 3 3
------ ------
$3,482 $2,827
====== ======
9
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
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 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 months ended March 31, 2004 and 2003:
THREE MONTHS ENDED
MARCH 31,
---------------------
2004 2003
---------- ---------
(In thousands)
Beginning asset retirement obligations $ 2,320 $ 1,931
Liabilities incurred for new wells placed on production 101 -
Liabilities settled (36) -
Accretion of discount on asset retirement obligations 37 34
---------- ---------
$ 2,422 $ 1,965
========== =========
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 has adopted the
disclosure-only provisions of Statement of Financial Accounting Standards No.
123, "Accounting for Stock-Based Compensation" ("SFAS 123").
10
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
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 month periods ended March
31, 2004 and 2003 would have been the pro forma amounts indicated below:
THREE MONTHS ENDED
MARCH 31,
----------------------
2004 2003
---------- ----------
(In thousands, except
per share amounts)
Net income available to common stockholders - basic:
As reported $ 5,089 $ 5,516
Add back: Stock compensation expense previously included in net
income 121 11
Effect of total employee stock-based compensation expense, determined
under fair value method for all awards (345) (101)
---------- ----------
Pro forma $ 4,865 $ 5,426
========== ==========
Net income (loss) available to common stockholders - diluted:
As reported $ 5,089 $ 6,406
Add back: Stock compensation expense previously included in net
income 121 11
Effect of total employee stock-based compensation expense, determined
under fair value method for all awards (345) (101)
---------- ----------
Pro forma $ 4, 865 $ 6,316
========== ==========
Net income per share:
Basic:
As reported $ 0.13 $ 0.28
Pro forma 0.12 0.28
Diluted:
As reported $ 0.13 $ 0.20
Pro forma 0.12 0.20
8. 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. The provision (benefit) for
income taxes consists of the following (in thousands):
THREE MONTHS ENDED
MARCH 31,
--------------------
2004 2003
--------- ---------
Current income taxes:
Federal . . . . . . . $ - $ -
State . . . . . . . . - -
Deferred income taxes:
Federal . . . . . . . 2,500 -
State . . . . . . . . - -
--------- ---------
$ 2,500 $ -
========= =========
The differences in income taxes provided and the amounts determined by
applying the federal statutory tax rate to income before income taxes result
from the following (in thousands):
11
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
THREE MONTHS ENDED
MARCH 31,
----------------------
2004 2003
---------- ----------
Tax at statutory rate $ 2,656 $ 2,185
Add the effect of:
Deductible stock compensation (174) -
Valuation allowance - (2,185)
Other 18 -
---------- ----------
$ 2,500 $ -
========== ==========
At March 31, 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. Accordingly, Brigham has recognized
$2.5 million of deferred tax expense, a $0.5 million tax effect of unrealized
hedging losses and a $2.0 million reduction in its net deferred tax assets as of
March 31, 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 (in
thousands):
MARCH 31, DECEMBER 31,
2004 2003
----------- --------------
Deferred tax assets
Current:
Net operating loss carryforwards $ - $ 451
Non-current:
Net operating loss carryforwards 35,990 34,409
Capital loss carryforwards 634 634
Stock compensation 869 818
Unrealized hedging losses 1,062 561
Derivative assets 232 276
Asset retirement obligations 848 812
Preferred stock dividends as interest expense 180 119
Other 27 27
----------- --------------
Non-current 39,842 37,656
----------- --------------
39,842 38,107
----------- --------------
Deferred tax liabilities
Current:
Gas imbalances - (144)
Non-current:
Depreciable and depletable property (38,978) (35,132)
Other (32) -
----------- --------------
Non-current (39,010) (35,132)
----------- --------------
(39,010) (35,276)
----------- --------------
Net deferred tax assets 832 2,831
Valuation allowance (634) (634)
----------- --------------
$ 198 $ 2,197
=========== ==============
At March 31, 2004, Brigham has regular tax NOLs of approximately $102.8
million. Additionally, Brigham has approximately $88.5 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.
12
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
In addition, at March 31, 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 limitation on its NOLs under
Internal Revenue Code Section 382 due to a potential 50% change in ownership
among its 5% shareholders over a three-year period.
9. ACCOUNTING PRONOUNCEMENTS
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 Financial
Accounting Standards Board (FASB) in June 2001 and became effective for Brigham
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, Brigham, like many other oil and gas
companies, has 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 Brigham's balance
sheet classification of oil and gas leaseholds. Brigham's 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 March 31, 2004 Brigham had undeveloped leaseholds of approximately $5.1
million that would be classified on its balance sheet as "intangible undeveloped
leasehold" and developed leaseholds of an estimated $1.0 million that would be
classified as "intangible developed leaseholds" if Brigham applied the
interpretation currently being deliberated. This classification would require
the disclosures set forth under SFAS 142 related to these interests.
On April 30, 2004 the FASB staff issued FASB Staff Position (FSP) SFAS
141-1 and 142-1, "Interaction of FASB Statements NO. 141, Business Combinations,
and No. 142, Goodwill and Other Intangible Assets, and Emerging Issues Task
Force (EITF) Issue No. 04-2, Whether Mineral Rights Are Tangible or Intangible
Assets" and the guidance in the FSP shall be applied to the first reporting
period after April 29, 2004. Under the FSP certain use rights may have
characteristics of tangible assets, thus Brigham will continue to classify its
oil and gas leaseholds as tangible oil and gas properties.
13
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 month period ended March 31, 2004, and the
comparable period of 2003. For definitions of commonly used gas and oil 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 QUARTER 2004
The price of natural gas during the first quarter 2004 remained relatively
high to historical prices due to forecasts for continued production declines,
increasing natural gas demand and similarly high crude oil prices, which limits
fuel switching flexibility. The average sales price that we received for our
natural gas sales in the first quarter 2004 was $5.79 per Mcf. During 2003, oil
prices increased in response to political unrest and supply disruptions in the
Middle East as well as other supply and demand factors. The price of oil during
the first quarter 2004 remained high relative to historical prices. The average
sales price that we received for oil in the first quarter of 2004 was $34.01.
For the quarter ended March 31, 2004, our net capital expenditures for oil
and natural gas activities were $17 million. Our drilling capital expenditures
alone for the first quarter 2004 were up 142% over the amount spent in the first
quarter of last year. Our operating performance for the first quarter of 2004
was highlighted by record high production of 33.9 MMcfe/d. This represents a 15%
growth in production over production our production in the fourth quarter of
2003 and a 9% increase over production in the first quarter 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
quarter of 2004.
Net income to common stockholders for the first quarter 2004 was $5.1
million, or $0.13 per diluted share, on total revenues of $16.8 million. This
compares to reported net income of $5.5 million, or $0.20 per diluted share on
revenue of $14.7 million for the first quarter last year. Net cash provided by
operating activities funded approximately 50% of our capital expenditures. We
had to borrow an additional $10.2 million under our senior credit facility to
fund the increase in capital expenditures.
At March 31, 2004, we had $7.7 million in cash, total assets of $235.9
million and a debt to capitalization ratio of 29%.
OUTLOOK FOR THE REMAINDER OF 2004
For the remainder of 2004, will continue to execute our 2004 capital
expenditure plan of $79 million. The majority of our planned expenditures will
be directed toward the drilling of our exploration and development inventory to
focus resources on our primary objective of growing our reserves, production
volumes and cash flow. For 2004, we expect to drill 59 (36 development and 23
exploratory) wells with an average working interest of approximately 42%.
Capitalizing on our prior discoveries, including the Home Run, Mills Ranch,
Triple Crown, Floyd Fault Block, Floyd South Fault Block and Providence Fields,
approximately 67% of our drilling expenditures are allocated to development
drilling. Our cash on hand at March 31, 2004, net cash provided by operating
activities and 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 61% 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.
14
There can be no assurance that the budgeted wells will, if drilled,
encounter commercial quantities of natural gas or oil.
CAPITAL COMMITMENTS
Net cash provided by operating activities and additional borrowings under
our senior credit were our primary sources of cash during the first quarter
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 first quarter 2004, net cash provided
by operating activities 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 quarter of 2004 and 2003.
THREE MONTHS ENDED MARCH 31,
----------------------------------
2004 % CHANGE 2003
--------- ----------- ----------
(dollars in thousands)
Drilling . . . . . . . . . . . . . . . . . . . . . . $ 12,568 142% $ 5,201
Land and G&G . . . . . . . . . . . . . . . . . . . . 2,817 125% 1,252
Capitalized interest and G&A . . . . . . . . . . . . 1,587 (9%) 1,739
Proceeds from participants and sales . . . . . . . . - - (151)
--------- ----------
Net capital expenditures on oil and gas activities. $ 16,972 111% $ 8,041
Other property and equipment . . . . . . . . . . . . 129 32% 98
--------- ----------
Total revenue from the sale of oil and natural gas. $ 17,101 110% $ 8,139
========= ==========
15
LIQUIDITY AND CAPITAL RESOURCES
Cash flows from operating activities
THREE MONTHS ENDED MARCH 31,
---------------------------------
2004 % CHANGE 2003
--------- ----------- ---------
(dollars in thousands)
Net cash provided by operating activities. $ 8,594 (43%) $ 15,062
The change in net cash provided by operating activities is primarily
related to the following:
- - The repayment of accounts payable in excess of collections of accounts
receivable resulted in a $2.7 million decrease;
- - The settlement of our gas imbalance resulted in a $3.7 million decrease;
- - A decline in the average sales price that we received for oil and natural
gas resulted in a $2.8 million decrease;
- - A decrease in our royalties payable resulted in $2.1 million decrease; and,
- - A $441,000 increase in operating cost.
These decreases were partially offset by the following:
- - A $2.4 million increase in revenue from the sale of oil and natural gas;
- - A $2.6 million increase in revenue due to a decline in losses from the
settlement of derivative contracts; and,
- - A $318,00 decrease in the amount of cash interest paid.
Working capital
- ---------------
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, royalties
payable and gas imbalances 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 March 31, 2004, we had a working capital deficit
of $9.6 million compared to a working capital deficit of $14.7 million at
December 31, 2003. Current liabilities at March 31, 2004, included a liability
of $3.1 million related to the fair value of our open derivative contracts.
Cash flows from financing activities
Common stock transactions
- -------------------------
- - In the first quarter of 2004, we issued 126,600 shares of common stock and
received $310,000 in net proceeds related to the exercise of employee stock
options.
- - During January 2004, we acquired 19,596 shares of our common stock 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 the first quarter of 2003, we issued 171,800 shares of common stock and
received $432,000 in net proceeds related to the exercise of employee stock
options.
- - In the first quarter of 2003, we issued 248,028 unregistered shares of our
common stock to a group of institutional investors led by affiliates of two
members of our board of directors. We received no proceeds from the
exercise of the warrant as the group elected to execute a cashless exercise
of the warrants.
Senior credit facility
- ----------------------
Future outstanding balances under our senior credit facility are dependent
primarily on net cash provided by operating activities, the proceeds from other
financing activities and the proceeds generated from the sale of assets. Our
committed borrowing capacity under our senior credit facility at March 31, 2004,
was $80 million, with a $68.5
16
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 $39.3 million at March 31,
2004, and $34.3 million at May 12, 2004. Our senior credit facility matures in
March of 2006.
In the first quarter of 2004 we borrowed $10.2 million of additional debt
from our senior credit facility to fund our working capital obligations and
capital expenditures resulting from the increase in our capital expenditures
activity. In the first quarter 2003, we repaid $4 million of the debt
outstanding under our senior credit facility. We also paid $988,000 in fees
related to the amendment of our senior credit facility in March 2003.
Our current ratio, as defined by the senior credit facility, at March 31,
2004 and interest coverage ratio for the twelve-month period ending March 31,
2004, were 1.9 to 1 and 9.6 to 1, respectively.
Senior subordinated notes
- -------------------------
Our current ratio, as defined by the senior subordinated notes, at March
31, 2004 and interest coverage ratio for the twelve-month period ending March
31, 2004, were 1.9 to 1 and 9.6 to 1, respectively. Our ratio of risked net
present value (as defined) discounted at 9% to total debt at December 31, 2003,
was 2.7 to 1, and were in compliance with the subordinated notes covenant that
requires us to maintain a ratio of 1.5 to 1.
RESULTS OF OPERATIONS
Comparison of the three-month periods ended March 31, 2004 and 2003
Production.
THREE MONTHS ENDED MARCH 31,
---------------------------------
2004 % CHANGE 2003
NET PRODUCTION VOLUMES:
Natural gas (MMcf). . . . . . . . . 2,093 42% 1,472
Oil (MBbls) . . . . . . . . . . . . 160 (28%) 223
Natural gas equivalent (MMcfe). . 3,050 9% 2,808
Average daily production (MMcfe/d) 33.9 9% 31.2
% Natural gas . . . . . . . . . . 69% 31% 52%
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 quarter of 2004. New production related to these recently completed wells
was partially offset by the natural decline of existing production.
Revenue 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 qualify for hedge accounting
treatment under SFAS 133.
We utilize commodity swap, collar 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. All
of our open derivative commodity contracts at March 31, 2004, qualified for
hedge accounting treatment under SFAS 133.
The effective portions of changes in the fair values of our derivative
commodity contracts that qualify for hedge accounting treatment under SFAS 133
are deferred as increases or decreases to stockholders' equity until the
underlying contract is settled. Consequentially, changes in the effective
portions of our derivative commodity contracts that qualify for hedge accounting
treatment under SFAS 133 add volatility to our reported stockholders' equity
until the contract is settled or is terminated.
17
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 do not qualify for hedge accounting
treatment under SFAS 133 are recognized in other income (expense).
The table below shows revenue that we have realized from the sale of oil
and natural gas during the first quarter of 2004 and 2003.
THREE MONTHS ENDED MARCH 31,
-----------------------------------
2004 % CHANGE 2003
---------- ----------- ----------
REVENUE FROM THE SALE OF OIL AND NATURAL GAS: (dollars in thousands)
Oil sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 5,427 (25%) $ 7,324
Gain / (loss) due to hedging. . . . . . . . . . . . . . . . . . . . (505) (40%) (828)
---------- ----------
Total revenue from the sale of oil. . . . . . . . . . . . . . . . $ 4,922 (25%) $ 6,496
========== ==========
Natural gas sales . . . . . . . . . . . . . . . . . . . . . . . . . $ 12,113 14% $ 10,649
Gain / (loss) due to hedging. . . . . . . . . . . . . . . . . . . . (216) (91%) (2,506)
---------- ----------
Total revenue from the sale of natural gas. . . . . . . . . . . . $ 11,897 41% $ 8,413
========== ==========
Oil and natural gas sales . . . . . . . . . . . . . . . . . . . . . $ 17,540 2% $ 17,973
Gain / (loss) due to hedging. . . . . . . . . . . . . . . . . . . . (721) (78%) (3,334)
---------- ----------
Total revenue from the sale of oil and natural gas. . . . . . . . $ 16,819 15% $ 14,639
========== ==========
AVERAGE PRICES:
($per Bbl)
Oil sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 34.01 3% $ 32.88
Gain/(loss) due to hedging. . . . . . . . . . . . . . . . . . . . . (3.17) (15%) (3.71)
---------- ----------
Realized Oil price. . . . . . . . . . . . . . . . . . . . . . . . $ 30.84 6% $ 29.17
========== ==========
($per Mcf)
Natural gas sales . . . . . . . . . . . . . . . . . . . . . . . . . $ 5.79 (20%) $ 7.23
Gain/(loss) due to hedging. . . . . . . . . . . . . . . . . . . . . (0.10) (94%) (1.70)
---------- ----------
Realized natural gas price. . . . . . . . . . . . . . . . . . . . $ 5.69 3% $ 5.53
========== ==========
($per Mcfe)
Natural gas equivalent sales. . . . . . . . . . . . . . . . . . . . $ 5.75 (10%) $ 6.40
Gain/(loss) due to hedging. . . . . . . . . . . . . . . . . . . . . (0.24) (80)% (1.19)
---------- ----------
Realized natural gas equivalent price . . . . . . . . . . . . . . $ 5.51 6% $ 5.21
========== ==========
The change in our total revenue from the sale of oil and natural gas from
the first quarter 2004 to the first quarter 2003 was due to the following:
- - A $2.4 million increase to total revenue due to a 9% increase in production
volumes for the first quarter 2004;
- - The increase in revenue related to increased production was offset by a
loss of $2.8 million due to a $0.65 per Mcfe decrease in the average sales
price we received for our production. The decrease in the average sales
price that we received was due to a $1.44 per Mcf decrease in the sales
price we received for natural gas.
- - A decrease in losses on the settlement of hedging contracts resulted in a
$2.6 million increase in total revenue from the sale of oil and natural
gas.
18
The table below shows the type of derivative commodity contracts, the
volumes, the weighted average NYMEX reference price for those volumes, and the
associated gain /(loss) upon settlement of those hedges during the first quarter
of 2004 and 2003.
THREE MONTHS ENDED MARCH 31,
-----------------------------------
2004 % CHANGE 2003
---------- ----------- ----------
OIL SWAPS
Volumes (Bbls). . . . . . . . . . . . . . . . 29,575 (56%) 67,500
Average swap price ($per Bbl) . . . . . . . . $ 25.35 0% $ 25.29
Gain / (loss) upon settlement ($in thousands) $ (290) (50%) $ (575)
OIL COLLARS
Volumes (Bbls). . . . . . . . . . . . . . . . 45,500 102% 22,500
Average floor price ($per Bbl) $ 23.00 28% $ 18.00
Average ceiling price ($per Bbl) $ 30.43 35% $ 22.56
Gain / (loss) upon settlement ($in thousands) $ (215) (15%) $ (253)
NATURAL GAS SWAPS
Volumes (MMbtu) . . . . . . . . . . . . . . . 295,750 (64%) 832,500
Average swap price ($per MMbtu) . . . . . . . $ 4.96 37% $ 3.63
Gain / (loss) upon settlement ($in thousands) $ (216) (91%) $ (2,506)
NATURAL GAS COLLARS
Volumes (MMbtu) . . . . . . . . . . . . . . . 546,000 - -
Average floor price ($per MMbtu) $ 4.13 - $ -
Average ceiling price ($per MMbtu) $ 8.43 - $ -
Gain / (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 is 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 first
quarter of 2004 was $1,000 compared to $38,000 for the first quarter last year.
19
Production cost. Production costs include lease operating expenses and
production taxes.
THREE MONTHS ENDED MARCH 31,
---------------------------------
2004 % CHANGE 2003
--------- ----------- ---------
(dollars in thousands)
Operating and maintenance expenses. $ 1,026 16% $ 881
Workover expenses . . . . . . . . . 221 256% 62
Ad valorem taxes. . . . . . . . . . 162 423% 31
--------- ---------
Lease operating expenses. . . . . $ 1,409 45% $ 974
Production taxes. . . . . . . . . . 863 (8%) 938
--------- ---------
Total production cost . . . . . . $ 2,272 19% $ 1,912
========= =========
($per Mcfe)
Operating and maintenance expenses. $ 0.34 10% $ 0.31
Workover expenses . . . . . . . . . 0.07 250% 0.02
Ad valorem taxes. . . . . . . . . . 0.05 150% 0.02
--------- ---------
Total lease operating expenses. . $ 0.46 31% $ 0.35
Production taxes. . . . . . . . . . 0.28 (15%) 0.33
--------- ---------
Total production cost . . . . . . $ 0.74 9% $ 0.68
========= =========
Lease operating expenses
- ------------------------
Lease operating expenses are generally 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.
The increase in our total lease operating expenses for the first quarter of
2004 over the first quarter 2003 was primarily due to:
- - An increase in operating and maintenance expenses due to increase in number
of producing wells in the first quarter 2004;
- - An increase in workover costs due to an increase in workover activity for
the first quarter 2004; and,
- - An increase in ad valorem taxes due to an increase projected 2004 property
valuations due to higher average commodity prices in 2003.
On a per unit basis, an increase in compressor rental and maintenance
expense and fees paid for overhead represented approximately $0.03 per Mcfe of
the increase in our per unit lease operating expense, while the increase in
workover costs and ad valorem taxes represented $0.08 of the increase.
Production taxes
- ----------------
In the U.S. there are a variety of state and federal taxes levied on the
production of 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.
20
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.
A 10% decline in the average pre-hedge sales price that we received for our
oil and natural gas in the first quarter 2004 was primary reason for the
decrease in production taxes. Production taxes for the first quarter 2004 were
4.9% of revenue before gains and losses due to hedging, compared to 5.2% in the
first quarter 2003.
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.
THREE MONTHS ENDED MARCH 31,
---------------------------------
2004 % CHANGE 2003
--------- ----------- ---------
(dollars in thousands)
General and administrative expenses $ 1,220 7% $ 1,139
($per Mcfe)
General and administrative expenses $ 0.40 (2%) $ 0.41
Approximately 48% of the increase in our general and administrative
expenses was due to a decrease in the percentage of our total general and
administrative costs that we capitalized during the first quarter 2004 when
compared to the first quarter last year. Other changes were as follows:
- - An increase in payroll and employee benefit expenses net of amounts charged
to joint ventures to cover the costs of managing these joint operations, an
increase in franchise taxes and increase in the cost of corporate insurance
were the primary reasons for the increase in general and administrative
expenses; and,
- - The increases were partially offset by a decline in fees paid to third
party consultants and a decline office rent expense.
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.
THREE MONTHS ENDED MARCH 31,
---------------------------------
2004 % CHANGE 2003
--------- ----------- ---------
(dollars in thousands)
Depletion of oil and natural gas properties. $ 4,850 18% $ 4,102
($per Mcfe)
Depletion rate . . . . . . . . . . . . . . . $ 1.60 9% $ 1.46
Increased production volumes combined with an increase in our per unit
depletion rate resulted in an 18% increase in our depletion expense. Higher
production volumes accounted for approximately 45% of the increase in depletion
expense while an increase in our depletion rate accounted for 55% of the
increase. The increase in our depletion rate was due to an increase in our oil
and natural gas finding and development costs incurred in 2003 and an increase
in future development costs associated with our year-end 2003 reserves.
21
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.
THREE MONTHS ENDED MARCH 31,
------------------------------------
2004 % CHANGE 2003
---------- ------------ ----------
(dollars in thousands)
Interest on senior credit facility . . . . . . . . . . . . . . . . . . . . $ 185 (71%) $ 636
Interest on senior subordinated notes (a). . . . . . . . . . . . . . . . . 438 (25%) 583
Commitment fees. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54 1250% 4
Dividend on Series A mandatorily redeemable preferred stock (b). . . . . . 175 - -
Amortization of deferred loan and debt issuance cost . . . . . . . . . . . 192 (24%) 253
Other general interest expense . . . . . . . . . . . . . . . . . . . . . . 9 (40%) 15
Capitalized interest expense . . . . . . . . . . . . . . . . . . . . . . . (271) 30% (209)
---------- ----------
Net interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 782 (39%) $ 1,282
========== ==========
Weighted average debt outstanding. . . . . . . . . . . . . . . . . . . . . $ 54,671 (33%) $ 81,502
Average interest rate on outstanding indebtedness (c). . . . . . . . . . . 6.2% 6.0%
(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. . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ - $ 292
(b) Dividend on Series A preferred stock paid in kind through the
issuance of preferred stock in lieu of cash. Our option to pay
dividends in kind on our Series A preferred stock expires in October
2005 175 -
(c) 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.
The change in our net interest expense for the first quarter 2004 when
compared to the first quarter 2003 was primarily due to the following:
- - A decrease in outstanding debt drawn under our senior credit facility
combined with a decrease in the interest rate that we pay on the borrowings
outstanding under our senior credit facility resulted in a $451,000
decrease in net interest expense. This decrease was offset by a $50,000
increase in the commitment fees paid on the unused portion of our borrowing
base;
- - A decrease in the amount of subordinated notes outstanding and a decrease
in the interest rate paid on our senior subordinated notes resulted in a
$145,000 decrease in net interest expense; and,
- - 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, the dividends on our mandatorily must be reported as
interest expense. The dividend on our mandatorily redeemable for the first
quarter of 2003 was reported as dividends in dividend and accretion of
mandatorily redeemable preferred stock. Excluding the dividend and weighted
average mandatorily redeemable preferred balance outstanding for the first
quarter 2004, our average interest rate on outstanding indebtedness was
5.9%.
22
Other income (expense). Other income (expense) primarily includes 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 portions of cash flow hedges.
THREE MONTHS ENDED MARCH 31,
---------------------------------
2004 % CHANGE 2003
--------- ----------- ---------
(dollars in thousands)
Non-cash charge for ineffective portion of hedges. $ 127 14% $ 111
--------- ---------
Total other income (expense) . . . . . . . . . . $ 127 14% $ 111
========= =========
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
$102.8 million, and our alternative minimum tax NOLs are $88.5 million. To date,
we have not utilized any of our NOLs. In future periods, our NOLs will be used
to offset taxable income.
Since 1998 through year-end 2003, we have not been required to recognize
any deferred income tax expense. Due to the level of projected net income, we
expect to evolve from a net deferred tax asset to a net deferred tax liability
position. 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, as of March 31, 2004, we have recognized
$2.5 million of deferred tax expense, a $0.5 million tax effect of unrealized
hedging losses and a $2.0 million reduction in our net deferred tax assets.
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 in each
quarter of 2004 and 2003.
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 that must be settled with our assets 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.
23
The following table shows the effect on our balance sheet, for the three
months ended March 31, 2004 and 2003, of the issuance of additional shares of
preferred stock in lieu of paying cash dividends.
THREE MONTHS ENDED MARCH 31,
--------------------------------
2004 % CHANGE 2003
--------- ---------- ---------
(dollars in thousands)
Dividends. . . . . . . . . . . . . . . . $ - - $ 894
Accretion of redeemable preferred stock. - - 101
--------- ---------
Total other income (expense) . . . . . $ - - $ 995
========= =========
Additional preferred shares issued
Series A - 34,823
Series B - 9,890
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 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
On April 30, 2004 the Financial Accounting Standards Board (FASB) staff
issued FASB Staff Position (FSP) SFAS 141-1 and 142-1, "Interaction of FASB
Statements NO. 141, Business Combinations, and No. 142, Goodwill and Other
Intangible Assets, and Emerging Issues Task Force (EITF) Issue No. 04-2, Whether
Mineral Rights Are Tangible or Intangible Assets" and the guidance in the FSP
shall be applied to the first reporting period after April 29, 2004. Under the
FSP certain use rights may have characteristics of tangible assets, thus we will
continue to classify our oil and gas leaseholds as tangible oil and gas
properties.
Forward Looking Information
We or our representatives may make forward looking statements, oral or
written, including statements in this report, press releases and filings with
the SEC, regarding estimated future net revenues from oil and natural gas
reserves and the present value thereof, planned capital expenditures (including
the amount and nature thereof), increases in oil and gas production, the number
of wells we anticipate drilling during 2004 and our financial position, business
strategy and other plans and objectives for future operations. Although we
believe that the expectations reflected in these forward looking statements are
reasonable, there can be no assurance that the actual results or developments
anticipated by us will be realized or, even if substantially realized, that they
will have the
24
expected effects on our business or operations. Among the factors that could
cause actual results to differ materially from our expectations are general
economic conditions, inherent uncertainties in interpreting engineering data,
operating hazards, delays or cancellations of drilling operations for a variety
of reasons, competition, fluctuations in oil and gas prices, availability of
sufficient capital resources to us or our project participants, government
regulations and other factors set forth among the risk factors noted in the
description of our business in Item 1 of our Form 10-K report for the year ended
December 31, 2003 or in our Management's Discussion Analysis of Financial
Condition in Item 7 of our Form 10-K report for the year ended December 31,
2003. All subsequent oral and written forward looking statements attributable to
us or persons acting on our behalf are expressly qualified in their entirety by
these factors. We assume no obligation to update any of these statements.
25
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
The following table reflects our open natural gas derivative contracts at
March 31, 2004, the volumes associated with those contracts and the
corresponding weighted average NYMEX reference price by quarter.
2004 2005
---------------------------- --------------------------------------
SECOND THIRD FOURTH FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER
-------- -------- -------- -------- -------- -------- --------
NATURAL GAS SWAPS:
Volumes (MMbtu). . . . . . 227,500 138,000 92,000 - - - -
Average price ($per MMBtu) $ 4.252 $ 4.180 $ 4.360 $ - $ - $ - $ -
NATURAL GAS COLLARS:
Volumes (MMbtu). . . . . . 509,600 400,200 264,100 202,500 136,500 - -
Average price ($per MMBtu)
Floor. . . . . . . . . . . $ 4.112 $ 4.101 $ 4.131 $ 4.139 $ 4.083 $ - $ -
Ceiling. . . . . . . . . . 5.672 5.724 5.813 6.633 5.107 - -
The following table reflects natural gas derivative contracts that were
entered into subsequent to March 31, 2004, the volumes associated with those
contracts and the corresponding weighted average NYMEX reference price by
quarter.
2004 2005
------------------ ------------------
THIRD FOURTH FIRST SECOND
QUARTER QUARTER QUARTER QUARTER
-------- -------- -------- --------
NATURAL GAS COLLARS:
Volumes (MMbtu). . . . . . 322,000 322,000 315,000 318,500
Average price ($per MMBtu)
Floor. . . . . . . . . . . $ 5.250 $ 5.250 $ 5.000 $ 5.000
Ceiling. . . . . . . . . . 7.410 7.410 7.400 7.400
26
The following table reflects our open oil derivative contracts at March
31, 2004, the associated volumes and the corresponding weighted average NYMEX
reference price by quarter.
2004 2005
---------------------------- --------------------------------------
SECOND THIRD FOURTH FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER
-------- -------- -------- -------- -------- -------- --------
OIL SWAPS:
Volumes (Bbls) . . . . . 20,475 13,800 9,200 - - - -
Average price ($per Bbl) $ 24.52 $ 23.91 $ 23.80 $ - $ - $ - $ -
OIL COLLARS:
Volumes (Bbls) . . . . . 50,050 36,800 22,300 15,750 6,825 - -
Average price ($per Bbl)
Floor. . . . . . . . . . $ 24.09 $ 24.50 $ 23.83 $ 23.00 $ 23.00 $ - $ -
Ceiling. . . . . . . . . 30.60 30.27 28.25 25.85 26.45 - -
The following table reflects oil derivative contracts that were entered
into subsequent to March 31, 2004, the volumes associated with those contracts
and the corresponding weighted average NYMEX reference price by quarter.
2004 2005
------------------ ------------------
THIRD FOURTH FIRST SECOND
QUARTER QUARTER QUARTER QUARTER
-------- -------- -------- --------
OIL COLLARS:
Volumes (Bbls) . . . . . 11,960 11,960 11,700 11,830
Average price ($per Bbl)
Floor. . . . . . . . . . $ 32.00 $ 32.00 $ 29.00 $ 29.00
Ceiling. . . . . . . . . 38.15 38.15 36.00 36.00
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.
27
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. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY
SECURITIES
Issuer Purchases of Equity Securities
TOTAL NUMBER OF AVERAGE PRICE PAID
PERIOD SHARES PURCHASED PER SHARE
- ---------------------------------- ---------------- -------------------
January 1, 2004 - January 31, 2004 19,596 $ 7.970
No purchases were made under a publicly announced plan.
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
32.1 Certification of Chief Financial Officer of the Company pursuant to 18
U.S.C. Sec. 1350
(b) Brigham Exploration Company filed the following reports on Form 8-K during
the quarter covered by this Quarterly Report on Form 10-Q:
(1) Filed February 23, 2004 on Item 12. Regulation FD Disclosure, Brigham
issued a press release announcing its 2004 capital expenditure plan.
(2) Filed March 5, 2004 on Item 12. Regulation FD Disclosure, Brigham
issued a press release announcing its financial results for the fiscal
year end and quarter ended December 31, 2003, and provided its
forecast for first quarter 2004 financial results results.
28
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 May 13, 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
29