================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2004
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission File Number: 000-22433
Brigham Exploration Company
(Exact name of registrant as specified in its charter)
Delaware 1311 75-2692967
(State of other jurisdiction (Primary Standard Industrial (I.R.S. Employer
of incorporation or organization) Classification Code Number) Identification
Number)
6300 Bridge Point Parkway, Building 2, Suite 500, Austin, Texas 78730
(Address of principal executive offices)
(512) 427-3300
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding twelve months (or for such shorter period that the registrant was
required to file such reports) and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12 b-2 of the Act).
Yes [ ] 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 August 13, 2004 41,985,615
================================================================================
Brigham Exploration Company
Second Quarter 2004 Form 10-Q Report
TABLE OF CONTENTS
-----------------
Page
----
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Consolidated Balance Sheets - June 30, 2004 and
December 31, 2003. . . . . . . . . . . . . . . . . . . . . . . . . . 1
Consolidated Statements of Operations - Three and
six months ended June 30, 2004 and 2003 . . . . . . . . . . . . . 2
Consolidated Statement of Stockholders' Equity - Six
months ended June 30, 2004. . . . . . . . . . . . . . . . . . . . . 3
Consolidated Statements of Cash Flows - Six months ended
June 30, 2004 and 2003. . . . . . . . . . . . . . . . . . . . . . . 4
Notes to the Consolidated Financial Statements. . . . . . . . . 5
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS . . . . . . . . . . . . . . 14
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. . 31
ITEM 4. CONTROLS AND PROCEDURES. . . . . . . . . . . . . . . . . . . . . . 32
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS . . . . . . . . . . . . . . . . . . . . . . . . .33
ITEM 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER
PURCHASES OF EQUITY SECURITIES. . . . . . . . . . . . . . . . . . .33
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS. . . . . .33
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K. . . . . . . . . . . . . . . .35
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .36
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
(unaudited)
June 30, December 31,
2004 2003
------------ --------------
ASSETS
(Unaudited)
Current assets:
Cash and cash equivalents $ 11,111 $ 5,779
Accounts receivable 14,972 11,143
Deferred income taxes 842 307
Other current assets 738 3,606
------------ --------------
Total current assets 27,663 20,835
------------ --------------
Oil and natural gas properties, net (full cost method) 226,715 197,311
Other property and equipment, net 1,195 1,219
Deferred income taxes - 1,890
Deferred loan fees 2,128 2,501
Other noncurrent assets 562 460
------------ --------------
Total assets $ 258,263 $ 224,216
============ ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 19,240 $ 19,806
Royalties payable 7,505 5,280
Accrued drilling costs 5,270 3,916
Participant advances received 698 1,179
Other current liabilities 3,553 5,398
------------ --------------
Total current liabilities 36,266 35,579
------------ --------------
Senior credit facility 36,700 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, 457,397 and 439,722 shares issued and outstanding at
June 30, 2004 and December 31, 2003, respectively 9,148 8,794
Deferred income taxes 3,844 -
Other noncurrent liabilities 3,017 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, 40,526,893 and 40,246,729 shares
issued and 39,345,541 and 39,086,096 shares outstanding at June 30, 2004 and December 31,
2003, respectively 405 402
Additional paid-in capital 152,241 151,263
Treasury stock, at cost; 1,181,352 and 1,160,633 shares at June 30, 2004 and December 31,
2003, respectively (4,562) (4,402)
Unearned stock compensation (1,881) (1,816)
Accumulated other comprehensive income (loss) (1,012) (1,040)
Retained earnings (Accumulated deficit) 4,097 (6,062)
------------ --------------
Total stockholders' equity 149,288 138,345
------------ --------------
Total liabilities and stockholders' equity $ 258,263 $ 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 Six Months Ended
June 30, June 30,
--------------------------------------
2004 2003 2004 2003
-------- -------- -------- --------
Revenues:
Oil and natural gas sales $17,916 $12,127 $34,735 $26,766
Other revenue 41 43 42 81
-------- -------- -------- --------
17,957 12,170 34,777 26,847
-------- -------- -------- --------
Costs and expenses:
Lease operating 1,305 1,270 2,714 2,244
Production taxes 896 806 1,759 1,744
General and administrative 1,199 1,187 2,419 2,326
Depletion of oil and natural gas properties 5,623 3,799 10,503 7,901
Depreciation and amortization 184 160 365 257
Accretion of discount on asset retirement obligations 40 37 77 71
-------- -------- -------- --------
9,247 7,259 17,837 14,543
-------- -------- -------- --------
Operating income 8,710 4,911 16,940 12,304
-------- -------- -------- --------
Other income (expense):
Interest income 15 7 29 28
Interest expense (854) (1,224) (1,636) (2,506)
Other income (expense) (118) (281) 9 (170)
-------- -------- -------- --------
(957) (1,498) (1,598) (2,648)
-------- -------- -------- --------
Income before income taxes and cumulative effect of
change in accounting principle 7,753 3,413 15,342 9,656
-------- -------- -------- --------
Income tax expense:
Current - - - -
Deferred (2,683) - (5,183) -
-------- -------- -------- --------
(2,683) - (5,183) -
-------- -------- -------- --------
Income before cumulative effect of change in accounting
principle 5,070 3,413 10,159 9,656
Cumulative effect of change in accounting principle - - - 268
-------- -------- -------- --------
Net income 5,070 3,413 10,159 9,924
Less accretion and dividends on redeemable preferred stock - 1,028 - 2,023
-------- -------- -------- --------
Net income available to common stockholders $ 5,070 $ 2,385 $10,159 $ 7,901
======== ======== ======== ========
Net income per share available to common stockholders:
Basic
Income before cumulative effect of change in accounting
principle $ 0.13 $ 0.12 $ 0.26 $ 0.39
Cumulative effect of change in accounting principle - - - 0.01
-------- -------- -------- --------
$ 0.13 $ 0.12 $ 0.26 $ 0.40
======== ======== ======== ========
Diluted
Income before cumulative effect of change in accounting
principle $ 0.13 $ 0.10 $ 0.25 $ 0.29
Cumulative effect of change in accounting principle - - - 0.01
-------- -------- -------- --------
$ 0.13 $ 0.10 $ 0.25 $ 0.30
======== ======== ======== ========
Weighted average shares outstanding:
Basic 39,287 20,087 39,261 19,898
======== ======== ======== ========
Diluted 40,391 30,037 40,354 32,090
======== ======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
2
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(in thousands)
(unaudited)
Accumulated Retained
Common Stock Additional Unearned Other Earnings
--------------------- Paid In Treasury Stock Comprehensive (Accumulated
Shares Amounts Capital Stock Compensation Income (Loss) Deficit)
----------- --------- -------- ---------------- -------------- --------------- ----------
Balance, December 31, 2003 40,247 $ 402 $151,263 $ (4,402) $ (1,816) $ (1,040) $ (6,062)
Comprehensive income:
Net income - - - - - - 10,159
Unrealized gain (losses) on
cash flow hedges - - - - - (16) -
Tax provisions related to
cash flow hedges - - - - - (16) -
Net losses realized and
included in net income - - - - - 60 -
Comprehensive income
Exercises of employee stock
options 208 2 596 - - - -
Issuance of restricted stock - - 514 - (514) - -
Vesting of restricted stock 72 1 (1) - - - -
Forfeitures of restricted stock - - (131) (4) 131 - -
Repurchases of common
stock - - - (156) - - -
Amortization of unearned
stock compensation - - - - 318 - -
----------- --------- -------- --------------- -------------- --------------- ----------
Balance, June 30, 2004 40,527 $ 405 $152,241 $ (4,562) $ (1,881) $ (1,012) $ 4,097
=========== ========= ======== ================ ============== =============== =========
Total
Stockholders'
Equity
-------------
Balance, December 31, 2003 $ 138,345
Comprehensive income:
Net income 10,159
Unrealized gain (losses) on
cash flow hedges (16)
Tax provisions related to
cash flow hedges (16)
Net losses realized and
included in net income 60
-------------
Comprehensive income 10,187
Exercises of employee stock
options 598
Issuance of restricted stock -
Vesting of restricted stock -
Forfeitures of restricted stock (4)
Repurchases of common
stock (156)
Amortization of unearned
stock compensation 318
-------------
Balance, June 30, 2004 $ 149,288
=============
The accompanying notes are an integral part of these consolidated financial
statements.
3
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)
Six Months Ended
June 30,
--------------------
2004 2003
--------- ---------
Cash flows from operating activities:
Net income $ 10,159 $ 9,924
Adjustments to reconcile net income to cash provided by operating activities:
Depletion of oil and natural gas properties 10,503 7,901
Depreciation and amortization 365 257
Interest paid through issuance of additional senior subordinated notes - 585
Interest paid through issuance of additional mandatorily redeemable preferred stock 354 -
Amortization of deferred loan fees and debt issuance costs 383 533
Market value adjustment for derivative instruments 60 170
Accretion of discount on asset retirement obligations 77 71
Cumulative effect of change in accounting principle - (268)
Deferred income taxes 5,183 -
Changes in operating assets and liabilities:
Accounts receivable (3,829) 2,310
Gas imbalance receivable - (2,669)
Other current assets 2,911 1,903
Accounts payable (566) (3,603)
Royalties payable 2,225 1,968
Participant advances received (481) (616)
Gas imbalance liability - 5,639
Other current liabilities (1,902) (549)
Other noncurrent assets and liabilities (92) (38)
--------- ---------
Net cash provided by operating activities 25,350 23,518
--------- ---------
Cash flows from investing activities:
Additions to oil and natural gas properties (38,072) (18,841)
Proceeds from sale of oil and natural gas properties - 352
Additions to other property and equipment (172) (209)
Decrease (Increase) in drilling advances paid 137 (516)
--------- ---------
Net cash used by investing activities (38,107) (19,214)
--------- ---------
Cash flows from financing activities:
Increase in senior credit facility 19,700 -
Repayment of senior credit facility (2,000) (7,000)
Deferred loan fees paid and equity costs (53) (985)
Proceeds from exercise of employee stock options 598 594
Repurchases of common stock (156) -
--------- ---------
Net cash provided (used) by financing activities 18,089 (7,391)
--------- ---------
Net increase (decrease) in cash and cash equivalents 5,332 (3,087)
Cash and cash equivalents, beginning of year 5,779 15,318
--------- ---------
Cash and cash equivalents, end of period $ 11,111 $ 12,231
========= =========
The accompanying notes are an integral part of these consolidated financial
statements
4
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
1. ORGANIZATION AND NATURE OF OPERATIONS
Brigham Exploration Company ("Brigham"), a Delaware corporation formed on
February 25, 1997, explores and develops onshore domestic oil and natural gas
properties using 3-D seismic imaging and other advanced technologies. Brigham
focuses its exploration and development of onshore oil and natural gas
properties primarily in the onshore Gulf Coast, the Anadarko Basin, and West
Texas.
2. BASIS OF PRESENTATION
The accompanying consolidated financial statements include the accounts of
Brigham and its wholly-owned subsidiaries, and its proportionate share of
assets, liabilities and income and expenses of the 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.
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") as amended by SFAS
148.
Had compensation cost for Brigham's stock options been determined based on
the fair market value at the grant dates of the awards consistent with the
methodology prescribed by SFAS 123, as amended by SFAS 148, Brigham's net income
and net income per share for the three and six month periods ended June 30, 2004
and 2003 would have been the pro forma amounts indicated below:
Three Months Ended Six Months Ended
June 30, June 30,
-----------------------------------
2004 2003 2004 2003
------- ------- -------- -------
(In thousands, except per share amounts)
Net income available to common
stockholders - basic:
As reported $5,070 $2,385 $10,159 $7,901
Add back: Stock compensation expense
previously included in net income 116 3 237 6
Effect of total employee stock-based
compensation expense, determined under fair
value method for all awards (647) (117) (991) (159)
------- ------- -------- -------
Pro forma $4,539 $2,271 $ 9,405 $7,748
======= ======= ======== =======
5
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
-----------------------------------
2004 2003 2004 2003
------- ------- -------- -------
(In thousands, except per share amounts)
Net income available to common
stockholders - diluted:
As reported $5,070 $3,062 $10,159 $9,696
Add back: Stock compensation expense
previously included in net income 116 3 237 6
Effect of total employee stock-based
compensation expense, determined under fair
value method for all awards (647) (117) (991) (159)
------- ------- -------- -------
Pro forma $4,539 $2,948 $ 9,405 $9,543
======= ======= ======== =======
Net income per share:
Basic:
As reported $ 0.13 $ 0.12 $ 0.26 $ 0.40
Pro forma 0.12 0.11 0.24 0.39
Diluted:
As reported $ 0.13 $ 0.10 $ 0.25 $ 0.30
Pro forma 0.11 0.10 0.23 0.30
3. COMMITMENTS AND CONTINGENCIES
Brigham is, from time to time, party to certain lawsuits and claims arising
in the ordinary course of business. While the outcome of lawsuits and claims
cannot be predicted with certainty, management does not expect these matters to
have a materially adverse effect on the financial condition, results of
operations or cash flows of Brigham.
On November 20, 2001, Brigham filed a lawsuit in the District Court of
Travis County, Texas, against Steve Massey Company, Inc. ("Massey"). The
Petition claims Massey furnished defective casing to Brigham, which ultimately
led to the casing failure of the Palmer 347 #5 well and the loss of the Palmer
#5 as a producing well. In 2004, the parties settled the case on terms favorable
to Brigham. Brigham received approximately $440,000 as a result of this
settlement, which reduced capitalized well costs. In addition, Massey dropped
its $445,819 counterclaim.
On July 11, 2002, an employee of a contractor on Brigham's Burkhart #1-R
location, Matagorda County, Texas, was involved in a fatal accident. The United
States Department of Labor Occupational Safety & Health Administration conducted
an inspection and, in October 2003, Brigham settled all issues resulting from
that inspection for $70,000.
On October 8, 2002, relatives of the contractor's employee filed a wrongful
death action in the district court for Matagorda County, Texas, against Brigham
and three of Brigham's contractors in connection with his accidental death.
Plaintiffs were seeking unspecified actual and punitive damages. On March 23,
2004, a jury determined that Brigham had no liability in the accidental death of
the contractor's employee. The plaintiffs have filed a motion for a new trial,
which the trial judge has taken under advisement.
In September 2002, Brigham filed suit in the district court of Matagorda
County, Texas, against one of its contractors in connection with the drilling of
the Burkhart #1-R well. The suit claims that the contractor breached its
contract with Brigham and negligently performed services on the well, resulting
in damages of approximately $650,000. The contractor filed a counterclaim for
the recovery of approximately $315,000. The parties settled the case in April
2004 resulting in a payment by the contractor to Brigham and its
co-participants. In addition, the contractor dropped its counterclaim. Based on
the amount of the settlement, the
6
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
additional costs that were covered by insurance, and the insurer being
subrogated to Brigham's claim, Brigham's incremental recovery as a result of the
settlement was diminimus.
The operator of the Stonehocker #1 disputed Brigham's ownership interest in
the well. In January 2004, the Oklahoma Corporation Commission ruled in favor of
Brigham. The operator of the Stonehocker #1 appealed the ruling and the Oklahoma
Corporation Commission affirmed its original ruling in March 2004. The operator
has appealed the ruling to the Oklahoma Supreme Court.
A working interest owner that relinquished its ownership interest in the
Nold #1S well as a result of a non-consent election in the re-completion of the
well asserted that it did not relinquish its entire interest, but rather became
subject only to a 400 percent payout provision. In November 2003, the working
interest owner filed a lawsuit against Brigham for breach of contract. In April
2004, the parties negotiated a settlement that resulted in Brigham making a
payment of approximately $390,000 to the working interest owner in exchange for
an assignment of any interest owned by the working interest owner in this well.
In December 2003, Brigham filed a lawsuit in the United States District
Court for the Western District of Texas against another company and a former
employee concerning the defendants' misappropriation of Brigham's trade secrets
and breach of confidentiality obligations. Defendants denied any wrongdoing and
asserted a counterclaim against Brigham for alleged tortuous interference with
an existing business relationship between the company and its employee. The
parties settled the lawsuit in April 2004 on terms favorable to Brigham. The
settlement resulted in a $50,000 payment to Brigham, a small overriding royalty
interest assignment to Brigham in three tracts and an agreement to not compete
in specific areas covered by the confidential information. In addition, the
other company has dropped its counterclaim against Brigham.
4. NET INCOME PER SHARE
Basic earnings per share are computed by dividing net income available to
common stockholders by the weighted average number of common shares outstanding
for the period. The computation of diluted net income per share reflects the
potential dilution that could occur if securities or other contracts to issue
common stock were exercised or converted into common stock or resulted in the
issuance of common stock that would then share in the earnings of Brigham.
The following table reconciles the numerators and denominators of the basic
and diluted earnings per common share computations for net income available to
common stockholders for the three and six months ended June 30, 2004 and 2003:
Three Months Ended Six Months Ended
June 30, June 30,
----------------------------------
2004 2003 2004 2003
------- ------- ------- -------
(In thousands, except per share amounts)
Basic EPS:
Income (loss) available to common
stockholders before cumulative change in
accounting principle $ 5,070 $ 2,385 $10,159 $ 7,633
Cumulative change in accounting principle - - - 268
------- ------- ------- -------
Income (loss) available to common
stockholders $ 5,070 $ 2,385 $10,159 $ 7,901
======= ======= ======= =======
Common shares outstanding 39,287 20,087 39,261 19,898
======= ======= ======= =======
Basic EPS
Income (loss) available to common
stockholders before change in
accounting principle $ 0.13 $ 0.12 $ 0.26 $ 0.39
Cumulative change in accounting principle - - - 0.01
------- ------- ------- -------
$ 0.13 $ 0.12 $ 0.26 $ 0.40
======= ======= ======= =======
7
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
---------------- ----------------
2004 2003 2004 2003
------- ------- ------- -------
(In thousands, except per share amounts)
Diluted EPS:
Income (loss) available to common
stockholders before cumulative change in
accounting principle $ 5,070 $ 2,385 $10,159 $ 7,633
Cumulative change in accounting principle - - - 268
------- ------- ------- -------
Income (loss) available to common
stockholders 5,070 2,385 10,159 7,901
Adjustments for assumed conversions:
Dividends and accretion on mandatorily
redeemable preferred stock (1) - 677 - 1,795
------- ------- ------- -------
Income (loss) available to common
stockholders before change in accounting
principle-diluted 5,070 3,062 10,159 9,428
Cumulative change in accounting principle - - - 268
------- ------- ------- -------
Income (loss) available to common
stockholders-diluted $ 5,070 $ 3,062 $10,159 $ 9,696
======= ======= ======= =======
Common shares outstanding 39,287 20,087 39,261 19,898
Effect of dilutive securities:
Warrants - 459 - 600
Mandatorily redeemable preferred stock - 8,966 - 11,071
Stock options 1,104 525 1,093 521
------- ------- ------- -------
Potentially dilutive common shares 1,104 9,950 1,093 12,192
------- ------- ------- -------
Adjusted common shares outstanding
diluted 40,391 30,037 40,354 32,090
======= ======= ======= =======
Diluted EPS
Income (loss) available to common
stockholders before change in accounting
principle $ 0.13 $ 0.10 $ 0.25 $ 0.29
Change in accounting principle - - - 0.01
------- ------- ------- -------
$ 0.13 $ 0.10 $ 0.25 $ 0.30
======= ======= ======= =======
(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 1,000 shares and 2.1 million shares of
common stock were outstanding but not included in the calculation of diluted
earnings (loss) per share for the three months ended June 30, 2004 and 2003,
respectively, and options and warrants to purchase 21,000 shares and 13,000
shares of common stock were outstanding but not included in the calculation of
diluted earnings (loss) per share for the six months ended June 30, 2004 and
2003, respectively, because the effects would have been antidilutive.
8
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Brigham utilizes various commodity swap and option contracts to (i) reduce
the effects of volatility in price changes on the oil and natural gas
commodities it produces and sells, (ii) reduce commodity price risk and (iii)
provide a base level of cash flow in order to assure it can execute at least a
portion of its capital spending plans.
Brigham reports average oil and natural gas prices and revenues including
the net results of hedging activities. The following table sets forth Brigham's
oil and natural gas prices including and excluding the hedging gains and losses
and the increase or decrease in oil and natural gas revenues as a result of the
hedging activities for the three and six month periods ended June 30, 2004 and
2003:
Three Months Six Months
Ended June 30, Ended June 30,
-------------------------------------
2004 2003 2004 2003
------- -------- -------- --------
NATURAL GAS
Average price per Mcf as reported (including hedging results) $ 5.90 $ 4.72 $ 5.80 $ 5.12
Average price per Mcf realized (excluding hedging results) $ 6.19 $ 5.60 $ 6.00 $ 6.40
Decrease in revenue (in thousands) $ (644) $(1,341) $ (860) $(3,847)
OIL
Average price per Bbl as reported (including hedging results) $33.05 $ 27.45 $ 31.88 $ 28.39
Average price per Bbl realized (excluding hedging results) $37.81 $ 29.52 $ 35.79 $ 31.37
Decrease in revenue (in thousands) $ (670) $ (370) $(1,175) $(1,198)
For the three months ended June 30, 2004 and 2003, ineffectiveness
associated with Brigham's derivative commodity instruments designated as cash
flow hedges decreased earnings by approximately $0.2 million and $0.2 million,
respectively. For the six months ended June 30, 2004 and 2003, ineffectiveness
associated with Brigham's derivative commodity instruments designated as cash
flow hedges decreased earnings by approximately $0.1 million and $0.1 million,
respectively. These amounts are included in other income (expense).
NATURAL GAS AND CRUDE OIL DERIVATIVE CONTRACTS
The following table summarizes the hedging contracts to which Brigham was a
party at June 30, 2004, the total natural gas and crude oil production volumes
subject to those contacts and the weighted average NYMEX reference price for
those volumes:
SWAPS COLLARS
-------------------- ---------------------------
WEIGHTED WEIGHTED AVERAGE
----------------
AVERAGE FLOOR CEILING
VOLUMES PRICE VOLUMES PRICE PRICE
-------- --------- -------- --------- -----
NATURAL GAS (MMbtu) ($/MMbtu) (MMbtu) ($/MMbtu)
Quarter Ended:
September 30, 2004 138,000 4.180 722,200 4.613 6.476
December 31, 2004 92,000 4.360 586,100 4.746 6.690
March 31, 2005 - - 517,500 4.663 7.100
June 30, 2005 - - 455,000 4.725 6.712
CRUDE OIL (Bbls) ($/Bbl) (Bbls) ($/Bbl)
Quarter Ended:
September 30, 2004 13,800 23.91 48,760 26.34 32.20
December 31, 2004 9,200 23.80 34,260 26.68 31.71
March 31, 2005 - - 27,450 25.56 30.18
June 30, 2005 - - 18,655 26.80 32.51
9
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
INTEREST RATE SWAP
Periodically, Brigham may use interest rate swap contracts to adjust the
proportion of its total debt that is subject to variable interest rates. Under
such an interest rate swap contract, Brigham agrees to pay an amount equal to a
specified fixed-rate of interest for a certain notional amount and receive in
return an amount equal to a variable-rate. The notional amounts of the contract
are not exchanged. No other cash payments are made unless the contract is
terminated prior to maturity. Although no collateral is held or exchanged for
the contract, the interest rate swap contract is entered into with a major
financial institution in order to minimize Brigham's counterparty credit risk.
The interest rate swap contract is designated as a cash flow hedge against
changes in the amount of future cash flows associated with Brigham's interest
payments on variable-rate debt. The effect of this accounting on operating
results is that interest expense on a portion of variable-rate debt being hedged
is recorded based on fixed interest rates.
At June 30, 2004, Brigham had an interest rate swap contract to pay a
fixed-rate of interest of 8.76% on $20.0 million notional amount of senior
subordinated notes. The $20.0 million notional amount of the outstanding
contract matures in March 2009. As of June 30, 2004, approximately $0.4 million
of unrealized gains are included in accumulated other comprehensive income
(loss) on the balance sheet and the fair value of the interest rate swap
agreement represents approximately $0.2 million of other noncurrent assets. The
fair value of the interest rate swap contract is based on quoted market prices
and third-party provided calculations, which reflect the present values of the
difference between estimated future variable-rate receipts and future fixed-rate
payments.
FAIR VALUES
The fair value of hedging and interest rate swap contracts is reflected on
the consolidated balance sheets as detailed in the following table. The current
asset and liability amounts represent the fair values expected to be included in
the results of operations for the next twelve months.
JUNE 30,
------------------
2004 2003
-------- --------
(In thousands)
Other current liabilities $(2,198) $(2,734)
Other noncurrent liabilities (237) (276)
Other current assets - 133
Other noncurrent assets 242 -
-------- --------
$(2,193) $(2,877)
======== ========
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
10
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
depletion of oil and natural gas properties and (iii) a $1.9 million increase in
noncurrent abandonment liabilities. The net impact of items (i) through (iii)
was to record a gain of $0.3 million as a cumulative effect adjustment of a
change in accounting principle in Brigham's consolidated statements of
operations upon adoption on January 1, 2003.
Brigham has no assets that are legally restricted for purposes of settling
asset retirement obligations. The following table summarizes Brigham's asset
retirement obligation transactions recorded in accordance with the provisions of
SFAS 143 during the three and six months ended June 30, 2004:
Three Months Ended Six Months Ended
June 30, June 30,
2004 2003 2004 2003
------- ------ ------- ------
(In thousands)
Beginning asset retirement obligations $2,422 $1,965 $2,320 $1,931
Liabilities incurred for new wells placed on production 235 60 336 60
Liabilities settled (32) - (68) -
Accretion of discount on asset retirement obligations 40 37 77 71
------- ------ ------- ------
Ending asset retirement obligations $2,665 $2,062 $2,665 $2,062
======= ====== ======= ======
7. INCOME TAXES
The provision for income taxes was computed in accordance with
Interpretation No. 18 of Accounting Principles Board Opinion (APB) No. 28 on
reporting taxes for interim periods and accordingly was based on the projection
of total 2004 pretax income. Interpretation No. 18 of APB 28 provides that
interim income taxes should be computed using the projected effective tax rate
on the total projected pretax income for the year.
At June 30, 2004, management believes that Brigham will (i) begin to
utilize net operating losses (NOLs) and (ii) have reversals of existing
temporary differences between book and taxable income sufficient to result in a
deferred tax liability at year-end 2004. Management also believes that it is
more likely than not that capital loss carryforwards of approximately $1.8
million may expire unused and, accordingly, has established a valuation
allowance of $0.6 million. The components of deferred income tax assets and
liabilities are as follows:
June 30, December 31,
2004 2003
-------- ------------
(In thousands)
Deferred tax assets
Current:
Net operating loss carryforwards $ - $ 451
Unrealized hedging losses 545 -
Derivative assets 297 -
-------- ------------
842 451
-------- ------------
11
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
JUNE 30, DECEMBER 31,
2004 2003
--------- ----------
(In thousands)
Non-current:
Net operating loss carryforwards 37,639 34,409
Capital loss carryforwards 634 634
Stock compensation 925 818
Unrealized hedging losses - 561
Derivative assets - 276
Asset retirement obligations 933 812
Preferred stock dividends as interest expense 243 119
Other 27 27
--------- ---------
Non-current 40,401 37,656
--------- ---------
41,243 38,107
--------- ---------
Deferred tax liabilities
Current:
Gas imbalances - (144)
Non-current:
Depreciable and depletable property (43,423) (35,132)
Other (188) -
--------- ---------
Non-current (43,611) (35,132)
--------- ---------
(43,611) (35,276)
--------- ---------
Net deferred tax assets (liabilities) (2,368) 2,831
Valuation allowance (634) (634)
--------- ---------
$ (3,002) $ 2,197
========= =========
At June 30, 2004, Brigham has regular tax NOLs of approximately $107.5
million. Additionally, Brigham has approximately $93.3 million of alternative
minimum tax ("AMT") NOLs available as a deduction against future taxable income.
The NOLs expire from 2012 through 2024. The value of these NOLs depends on the
ability of Brigham to generate taxable income.
In addition, at June 30, 2004, Brigham has capital loss carryforwards of
approximately $1.8 million that expire in varying years through 2007.
Brigham believes it has a $4.5 million annual limitation on the utilization
of certain of its NOLs under Internal Revenue Code Section 382 due to a
potential 50% change in ownership among its 5% shareholders over a three-year
period.
8. 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. 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.
12
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
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.
In July 2004, the FASB issued proposed FASB Staff Position (FSP) FAS 142-b,
"Application of FASB Statement No. 142, Goodwill and Other Intangible Assets to
Oil and Gas Producing Entities." This proposed FSP confirms the Staff's position
that SFAS No. 142 did not change the balance sheet classification or disclosure
requirements for drilling and mineral rights of oil and gas producing entities
that are within the scope of SFAS No. 19, "Financial Accounting and Reporting by
Oil and Gas Producing Companies." Brigham classifies the cost of oil and gas
drilling and mineral rights as properties and equipment, which is consistent
with SFAS No. 19 and proposed FSP FAS 142-b.
9. SUBSEQUENT EVENT
During July 2004, Brigham completed the sale of 2,300,000 shares of its
common stock under a universal shelf registration statement declared effective
by the Securities and Exchange Commission in June 2004. Net proceeds from the
equity offering of approximately $19.5 million were used to repay outstanding
borrowings under the senior credit facility. The balance of the senior credit
facility at August 12, 2004 is $19.2 million. Brigham plans to reborrow the
repaid amounts under the senior credit facility as necessary to fund future
exploration and development activities and for general corporate purposes.
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 and six month periods ended June 30, 2004, and the
comparable period of 2003. For definitions of commonly used oil and gas terms as
used in this Form 10-Q, please refer to the "Glossary of Oil and Gas Terms"
provided in our 2003 Annual Report on Form 10-K.
OVERVIEW OF FIRST SIX MONTHS OF 2004
For the quarter and six month period ended June 30, 2004, our net capital
expenditures for oil and natural gas activities were $22.6 million and $39.6
million, respectively. Our drilling capital expenditures alone for the second
quarter 2004 were up approximately 150% over the amount we spent in the second
quarter of last year. For the six months ended June 30, 2004, our net capital
expenditures for oil and natural gas activities are up approximately 120% when
compared to the first six months of last year. Our operating performance for the
second quarter and first six months of 2004 was highlighted by record high
production of 34.4 MMcfe/d and 34.1 MMcfe/d, respectively. This represents a 19%
growth in production over the amount we produced in the second quarter of 2003
and a 13% increase over the amount we produced in the first six months of 2003.
The increase in our production is primarily the result of the increase in
drilling capital expenditures during the fourth quarter of last year and the
first six months of 2004.
Net income to common stockholders for the second quarter 2004 was $5.1
million, or $0.13 per diluted share, on total revenues of $18 million. This
compares to reported net income of $2.4 million, or $0.10 per diluted share on
total revenues of $12.2 million in the second quarter last year.
For the six month period ended June 30, 2004, our reported net income to
common stockholders is $10.2 million, or $0.25 per diluted share, on total
revenues of $34.8 million. This compares to reported net income of $7.9 million,
or $0.30 per diluted share, on revenue of $26.8 million for the first six months
of last year. Net cash provided by operating activities funded approximately 67%
of our capital expenditures. We borrowed an additional $19.7 million in
additional debt under our senior credit facility to fund the bulk of our
remaining capital expenditures. As of June 30, 2004, we repaid $2 million of the
additional amount borrowed during the first six months on 2004.
At June 30, 2004, we had $11.1 million in cash, total assets of $258.3
million and a debt to total capitalization ratio of 31%.
OUTLOOK FOR THE REMAINDER OF 2004
On July 23, 2004, we sold 2,300,000 shares of our common stock under a
universal shelf registration statement declared effective by the Securities and
Exchange Commission in June 2004. We received net proceeds of approximately
$19.5 million and used the net proceeds from the offering to repay outstanding
indebtedness under our senior credit facility. "Net proceeds" is the amount we
received after paying the underwriting discount and other expenses related to
offering. We intend to reborrow the repaid amount to fund future exploration and
development activities, including taking advantage of opportunities to retain
larger working interests in wells and in 3-D seismic programs and for general
corporate purposes.
14
Also on July 23, 2004, we announced that we had increased our 2004 capital
expenditure budget approximately 13% to $89.9 million, up from our previously
announced 2004 capital expenditure budget of $79.4 million. The following table
presents our original capital budget for 2004 and our recently announced revised
capital budget for 2004.
Revised Original
2004 2004
Budget Budget % Change
------- ------- ---------
(in thousands)
Drilling. . . . . . . . . . . . . . . . . . . . . . . . . . $68,483 $61,432 11%
Land and G&G. . . . . . . . . . . . . . . . . . . . . . . . 15,075 11,973 26%
Capitalized interest and G&A. . . . . . . . . . . . . . . . 5,851 5,535 6%
------- -------
Net capital expenditures on oil and gas activities . $89,409 $78,940 13%
Other property and equipment. . . . . . . . . . . . . . . . 473 473 -
------- -------
Total revenue from the sale of oil and natural gas . $89,882 $79,413 13%
======= =======
Revised 2004 Budget Overview
Approximately $41.1 million, or 60%, of the budgeted drilling capital
expenditures from our revised 2004 budget will be allocated to drill 23 wells in
our onshore Texas Gulf Coast region. For 2004, our drilling activities in our
onshore Gulf Coast region will be focused on the Vicksburg and Frio Trends where
we will drill ten development wells with an average working interest of 63% and
13 exploratory wells with an average working interest of 63%. Of the wells
budgeted for 2004, eleven wells had reached total depth as of June 30, 2004.
In the Vicksburg, we are currently budgeted to spend approximately $18.4
million to drill three development wells with an average working interest of 56%
and three exploration wells with an average working interest of 68%. As of June
30, 2004, three of the wells in our revised 2004 budget had reached total depth
and one well was drilling. We currently plan to spud the remaining two Vicksburg
wells in our 2004 drilling program in the third and fourth quarter of this year.
For the Frio we are currently budgeted to spend approximately $22.4 million
to drill seven development wells with an average working interest of 66% and ten
exploration wells with an average working interest of 65%. As of June 30, 2004,
eight of the wells in our revised 2004 budget had reached total depth. We
currently plan to spud seven of the remaining Frio wells in the third quarter of
this year and the remaining two wells in the fourth quarter.
Approximately $25.2 million, or 37%, of the budgeted drilling capital
expenditures from our revised 2004 budget will be allocated to drill 39 wells in
our Anadarko Basin region. The majority of our drilling capital allocated to our
Anadarko Basin region will be focused on the Hunton/Arbuckle, Springer Channel
and Springer Bar Trends. For 2004, we currently plan to drill 34 development
wells with an average working interest of 23% and five exploratory wells with an
average working interest of 17% in our Anadarko Basin region. Of the wells
currently budgeted for 2004, 14 had reached total depth as of June 30, 2004.
We are currently budgeted to spend approximately $12.8 million to drill
three Hunton/Arbuckle development wells with an average working interest of 73%.
As of June 30, 2004, we had one well drilling and currently plan to spud one
well in both the third and fourth quarter of this year.
For the Springer Channel we are currently budgeted to spend approximately
$4.5 million to drill seven development wells with an average working interest
of 41% and four exploratory wells with an average working interest of 16%. As of
June 30, 2004, five of the wells in our revised 2004 budget had reached total
depth and two wells were drilling. We currently plan to spud three of the
remaining Springer Channel wells in our 2004 drilling program in the third
quarter and one well in fourth quarter of this year.
15
For the Springer Bar we are currently budgeted to spend approximately $3.3
million to drill ten development wells with an average working interest of 10%.
As of June 30, 2004, three of the wells in our revised 2004 budget had reached
total depth and one well was drilling. We currently plan to spud four of the
remaining Springer Bar wells in our 2004 drilling program in the third quarter
and two wells in fourth quarter of this year.
Additional budgeted capital expenditures for the Anadarko Basin region
includes $1.8 million to drill 13 development wells in the granite wash
formation with and average working interest of 11%. As of June 30, 2004, five of
the wells in our revised 2004 budget had reached total depth. We currently plan
to spud four of the remaining wells in the third quarter of 2004 and four wells
in the fourth quarter. We have also budgeted $2.8 million to drill a Grady
County Bromide test with a 29% working interest, a combined Hunton/Springer
Channel test with a 17% working interest and for other various drilling
activities. As of June 30, 2004, the Bromide test had reached total depth and
the combined Hunton/Springer Channel test was planned for an August 2004 spud.
Approximately $2.2 million, or 3%, of the budgeted drilling capital
expenditures from our revised 2004 budget will be allocated to drill three
exploratory wells in our West Texas region with an average working interest of
74%. We currently plan to spud two of these wells in the third quarter of 2004
and one well scheduled for the fourth quarter.
Approximately 17% of our revised capital expenditure budget will be used to
fund land and seismic acquisitions in an effort to add to our inventory of
drilling projects in current focus plays. We believe that our cash on hand at
June 30, 2004, net cash provided by operating activities, net proceeds from our
sale of common stock in July 2004 and the remaining availability under our
senior credit facility will fund our spending for the remainder of the year. Our
estimated net capital expenditures for 2004 represent an increase of
approximately 91% over the amount that we spent in 2003.
The final determination with respect to our 2004 budgeted expenditures will
depend on a number of factors, including:
- commodity prices;
- production from our existing producing wells;
- the results of our current exploration and development drilling
efforts;
- economic and industry conditions at the time of drilling, including
the availability of drilling equipment; and
- the availability of more economically attractive prospects.
There can be no assurance that the budgeted wells will, if drilled,
encounter commercial quantities of natural gas or oil.
16
CAPITAL COMMITMENTS
Net cash provided by operating activities and additional borrowings from
our senior credit were our primary sources of cash during the first six months
of 2004. This cash was used to fund the costs associated with drilling, land
acquisition and 3-D seismic acquisition, processing and interpretation. We
believe our cash on hand at the end of the second quarter 2004, net cash
provided by operating activities, the net proceeds from our sale of common stock
in July 2004 and the remaining availability under our senior credit facility
will be sufficient to fund our budgeted capital expenditures for the remainder
of 2004.
Capital Expenditures
The timing of most of our capital expenditures is discretionary because we
have no material long-term capital expenditure commitments. Consequently, we
have a significant degree of flexibility to adjust the level of our capital
expenditures as circumstances warrant. The table below lists our capital
expenditures for the first six months of 2004 and 2003.
SIX MONTHS ENDED JUNE 30,
------------------------------
2004 2003 % Change
------- ------------- ------
(in thousands)
Drilling . . . . . . . . . . . . . . . . . . . . . . . . . $31,190 $ 12,669 146%
Land and G&G . . . . . . . . . . . . . . . . . . . . . . . 5,221 2,138 144%
Capitalized interest and G&A . . . . . . . . . . . . . . . 3,161 3,160 0%
------- -------------
Net capital expenditures on oil and gas activities. $39,572 $ 17,967 120%
Other property and equipment . . . . . . . . . . . . . . . 172 209 (18%)
------- -------------
Net capital expenditures. . . . . . . . . . . . . . $39,744 $ 18,176 119%
======= =============
Liquidity and Capital Resources
Cash flows from operating activities
During the first six months of 2004, net cash provided by operating
activities and additional borrowings from our senior credit facility were our
primary source of cash. This cash was used to fund the costs associated with
drilling, land acquisition and 3-D seismic acquisition, processing and
interpretation.
Six months ended June 30,
--------------------------------
2004 2003 % Change
------- ------------- --------
(in thousands)
Net cash provided by operating activities. $25,350 $ 23,518 8%
The 8% increase in net cash provided by operating activities is primarily
related to the following:
- - An increase in oil and natural gas sales resulted in a $5 million increase
in net cash provided by operating activities.
- - An increase in revenue due to a decline in losses from the settlement of
derivative contracts resulted in a $3 million increase in net cash provided
by operating activities.
These increases were partially offset by the following:
- - The repayment of accounts payable in excess of collections of accounts
receivable reduced net cash provided by operating activities by $3.1
million.
17
- - The settlement of the gas imbalance with our industry participant in our
Diablo project reduced net cash provided by operating activities by $2.6
million.
- - An increase in production costs reduced net cash provided by operating
activities by $485,000.
Working capital is the amount by which current assets exceed current
liabilities. It is normal for us to report a working capital deficit at the end
of a period. These deficits are primarily the result of accounts payable related
to lease operating expenses, exploration and development costs, 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 June 30, 2004, we had a working capital deficit
of $8.6 million compared to a working capital deficit of $14.7 million at
December 31, 2003. Current liabilities at June 30, 2004, included a liability of
$2.2 million related to the fair value of our open derivative contracts.
Cash flows from financing activities
Common stock transactions
- -------------------------
- - We issued 126,600 shares of common stock and received $310,000 in net
proceeds related to the exercise of employee stock options in the first
quarter of 2004 and issued 81,481 shares of common stock and received
$288,000 in net proceeds in the second quarter of 2004.
- - During January and June of 2004, we acquired 19,596 and 821 shares of our
common stock, respectively, from certain employees to satisfy
tax-withholding obligations associated with the vesting of stock grants.
The transferred shares were valued at fair market value as of the date of
surrender.
- - 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 and issued 52,793 and received net proceeds of $162,000 in
the second quarter of 2003.
- - In the first quarter of 2003, we issued 248,028 unregistered shares of our
common stock to a group of institutional investors. The shares were issued
to the group in connection with the cashless exercise of warrants that it
owned and we received no proceeds from the exercise of the warrants.
- - In June 2003, we issued 408,928 and 206,982 unregistered shares of our
common stock to the Bank of Montreal and Soci t G n rale, respectively. We
received no proceeds from the exercise of these warrants as both parties
elected to execute a cashless exercise of the warrants. Both parties sold
the shares from this exercise in our common stock sale in September 2003.
We received no proceeds from the subsequent sale.
Senior credit facility
- ----------------------
Future outstanding balances under our senior credit facility are dependent
primarily on our level of capital expenditures, net cash provided by operating
activities and the proceeds from other financing activities. Our committed
borrowing capacity under our senior credit facility at June 30, 2004, was $80
million, with a $68.5 million borrowing base that is subject to adjustment on
the basis of the present value of estimated future net cash flows from proved
oil and gas reserves (as determined by the lender's petroleum engineer). Our
unused committed borrowing base capacity under our senior credit facility was
$31.8 million at June 30, 2004, and $49.3 million at August 12, 2004. Our senior
credit facility matures in March of 2006.
During the first six months of 2004 we borrowed $19.7 million of additional
debt from our senior credit facility to fund our working capital obligations and
capital expenditures and repaid $2 million. In July 2004, we used the net
proceeds from the sale of common stock to repay $19.5 million of debt
outstanding under our senior credit facility. During the first six months of
2003, we repaid $7 million of the debt outstanding under our senior credit
facility and paid $985,000 in fees related to our new credit facility that was
put in place in March 2003.
Our current ratio, as defined by the senior credit facility, at June 30,
2004 and interest coverage ratio for the twelve-month period ending June 30,
2004, were 1.6 to 1 and 11.9 to 1, respectively. As of June 30, 2004, we were in
compliance with the covenants of our senior credit facility.
18
Senior subordinated notes
- -------------------------
Our current ratio, as defined by the senior subordinated notes, at June 30,
2004 and interest coverage ratio for the twelve-month period ending June 30,
2004, were 1.6 to 1 and 11.9 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. As of June 30, 2004, we were in compliance
with the covenants of our senior subordinated notes.
RESULTS OF OPERATIONS
Comparison of the three and six month periods ended June 30, 2004 and 2003
Production.
Three months ended June 30, Six months ended June 30,
--------------------------- -------------------------
% %
2004 2003 Change 2004 2003 Change
------ ------ ------- ------ ----- -------
Oil (MBbls). . . . . . . . . . . . . . . 141 179 (21%) 300 402 (25%)
Natural gas (MMcf) . . . . . . . . . . . 2,246 1,528 47% 4,339 3,000 45%
Natural gas equivalent (MMcfe) . . 3,092 2,602 19% 6,142 5,412 13%
Average daily production (MMcfe/d) 34.4 28.9 19% 34.1 30.1 13%
% Natural gas . . . . . . . . . . 73% 59% 71% 55%
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 six months of 2004. New production related to these recently completed
wells was partially offset by the natural decline of existing production.
Revenues from the sale of oil and natural gas. Reported revenues from the
sale of oil and natural gas are based on the market price we receive for our
commodities, adjusted for marketing charges and the results from the settlement
of our derivative commodity contracts that qualify for cashflow 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 June 30, 2004, qualified for
cashflow hedge accounting treatment under SFAS 133.
The effective portions of changes in the fair values of our derivative
commodity contracts that qualify for cashflow hedge accounting treatment under
SFAS 133 are recorded 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 cashflow hedge
accounting treatment under SFAS 133 add volatility to our reported stockholders'
equity until the contract is settled or is terminated.
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 cashflow hedge accounting
treatment under SFAS 133 are recognized in other income (expense).
The following table presents revenues that we realized from the sale of oil
and natural gas during the second quarter and first six months of 2004 and 2003.
19
THREE MONTHS ENDED, JUNE 30, SIX MONTHS ENDED JUNE 30,
---------------------------- -------------------------
% %
2004 2003 CHANGE 2004 2003 CHANGE
-------- -------- ------- -------- -------- -------
(IN THOUSANDS)
Oil sales . . . . . . . . . . . . . . . . . . . . . . $ 5,327 $ 5,288 1% $10,754 $12,612 (15%)
Loss due to hedging . . . . . . . . . . . . . . . . . (670) (370) 81% (1,175) (1,198) (2%)
-------- -------- ------------------
Total revenues from the sale of oil . . . . . . . . $ 4,657 $ 4,918 (5%) $ 9,579 $11,414 (16%)
======== ======== ==================
Natural gas sales . . . . . . . . . . . . . . . . . . $13,903 $ 8,550 63% $26,016 $19,199 36%
Loss due to hedging . . . . . . . . . . . . . . . . . (644) (1,341) (52%) (860) (3,847) (78%)
-------- -------- ------------------
Total revenues from the sale of natural gas . . . . $13,259 $ 7,209 84% $25,156 $15,352 64%
======== ======== ==================
Oil and natural gas sales . . . . . . . . . . . . . . $19,230 $13,838 39% $36,770 $31,811 16%
Loss due to hedging . . . . . . . . . . . . . . . . . (1,314) (1,711) (23%) (2,035) (5,045) (60%)
-------- -------- -------- --------
Total revenues from the sale of oil and natural gas $17,916 $12,127 48% $34,735 $26,766 30%
======== ======== ==================
AVERAGE PRICES:
(PER BBL)
Oil sales . . . . . . . . . . . . . . . . . . . . . . $ 37.81 $ 29.52 28% $ 35.79 $ 31.39 14%
Loss due to hedging . . . . . . . . . . . . . . . . . (4.76) (2.07) 130% (3.91) (3.00) 30%
-------- -------- ------------------
Realized Oil price. . . . . . . . . . . . . . . . . $ 33.05 $ 27.45 20% $ 31.88 $ 28.39 12%
======== ======== ==================
(PER MCF)
Natural gas sales . . . . . . . . . . . . . . . . . . $ 6.19 $ 5.60 11% $ 6.00 $ 6.40 (6%)
Loss due to hedging . . . . . . . . . . . . . . . . . (0.29) (0.88) (67%) (0.20) (1.28) (84%)
-------- -------- ------------------
Realized natural gas price. . . . . . . . . . . . . $ 5.90 $ 4.72 25% $ 5.80 $ 5.12 13%
======== ======== ==================
(PER MCFE)
Natural gas equivalent sales. . . . . . . . . . . . . $ 6.22 $ 5.32 17% $ 5.99 $ 5.88 2%
Loss due to hedging . . . . . . . . . . . . . . . . . (0.43) (0.66) (35%) (0.33) (0.93) (65%)
-------- -------- ------------------
Realized natural gas equivalent price . . . . . . . $ 5.79 $ 4.66 24% $ 5.66 $ 4.95 14%
======== ======== ==================
Total revenues from the sale of oil and natural gas for the second quarter
2004 were 48% higher than revenues in same period of 2003. The increase was
primarily due the following:
- - A $2.9 million increase to total revenues from the sale of oil and natural
gas due to a 19% increase in production volumes for the second quarter
2004.
- - A $2.5 million increase to total revenues from the sale of oil and natural
gas due to a 28% increase in the average sales price we received for oil
and an 11% increase in the average sales price we received for natural gas.
- - A 23% decrease in losses related the settlement of hedging contracts
resulted in a $397,000 increase in total revenues from the sale of oil and
natural gas.
20
Total revenues from the sale of oil and natural gas for the first six
months of 2004 were 30% higher than revenues in the same period of 2003. The
increase was primarily due to the following:
- - A $5.4 million increase to total revenues from the sale of oil and natural
gas due to a 13% increase in production volumes for first six months of
2004.
- - A $432,000 decline in total revenues from the sale of oil and natural gas
due to a 6% decline in the average sales price we received for natural gas
offset the increase in total revenue from the increase in production.
- - A 60% decrease in losses related the settlement of hedging contracts
resulted in a $3 million increase in total revenues from the sale of oil
and natural gas.
The table below presents our derivative commodity contracts, the volumes,
the weighted average NYMEX reference price for those volumes, and the associated
loss upon settlement of those contracts during the second quarter and first six
months of 2004 and 2003.
THREE MONTHS ENDED, JUNE 30, SIX MONTHS ENDED, JUNE 30,
---------------------------- --------------------------
% %
2004 2003 CHANGE 2004 2003 CHANGE
--------- --------- ------- ----------- ----------- -------
OIL SWAPS
Volumes (Bbls). . . . . . . . . . . 20,475 61,425 (67%) 50,050 128,925 (61%)
Average swap price (per Bbl). . . . $ 24.52 $ 25.22 (3%) $ 25.01 $ 25.25 (1%)
Loss upon settlement (in thousands) $ (283) $ (226) 25% $ (573) $ (801) (28%)
OIL COLLARS
Volumes (Bbls). . . . . . . . . . . 50,050 22,750 120% 95,550 45,250 111%
Average floor price (per Bbl) . . . $ 24.09 $ 18.00 34% $ 23.57 $ 18.00 31%
Average ceiling price (per Bbl) . . 30.60 22.56 36% 30.52 22.56 35%
Loss upon settlement (in thousands) $ (387) $ (144) 168% $ (602) $ (397) 52%
NATURAL GAS SWAPS
Volumes (MMbtu) . . . . . . . . . . 227,500 819,000 (72%) 523,250 1,651,500 (68%)
Average swap price (per MMbtu). . . $ 4.252 $ 3.846 11% $ 4.654 $ 3.738 25%
Loss upon settlement (in thousands) $ (391) $ (1,341) (71%) $ (607) $ (3,847) (84%)
NATURAL GAS COLLARS
Volumes (MMbtu) . . . . . . . . . . 509,600 - - 1,055,600 - -
Average floor price (per MMbtu) . . $ 4.112 $ - - $ 4.119 $ - -
Average ceiling price (per MMbtu) . 5.672 - - 7.100 - -
Loss upon settlement (in thousands) $ (253) $ - - $ (253) $ - -
NATURAL GAS FLOORS
Volumes (MMbtu) . . . . . . . . . . - 150,000 (100%) - 150,000 (100%)
Average swap price (per MMbtu). . . $ - $ 4.500 (100%) $ - $ 4.500 (100%)
Loss upon settlement (in thousands) $ - $ - - $ - $ - -
Other revenue. Fees that we charge other parties who use our two gas
gathering systems to move their production from the wellhead to third party gas
pipeline systems are recorded as other revenue. These gathering systems are
owned by us and located in the Texas Gulf Coast. One of the gathering systems
connects a single well and the other connects two wells. Other revenue for the
second quarter of 2004 was $41,000 compared to $43,000 in the second quarter
last year. Other revenue for the six months of 2004 was $42,000 compared to
$81,000 during the first six months of 2003.
21
Production cost. Production costs include lease operating expenses and
production taxes. The following table presents our production cost for the
second quarter and first six months of 2004 and 2003.
THREE MONTHS ENDED, JUNE 30, SIX MONTHS ENDED, JUNE 30,
---------------------------- --------------------------
% %
2004 2003 CHANGE 2004 2003 CHANGE
------ ------ ------- ------ ------ -------
(IN THOUSANDS)
Operating and maintenance expenses. $1,021 870 17% 2,047 $1,617 27%
Workover expenses . . . . . . . . . 118 235 (50%) 339 297 14%
Ad valorem taxes. . . . . . . . . . 166 165 1% 328 330 (1%)
------ ------ --------------
Lease operating expenses. . . . . 1,305 $1,270 3% $2,714 $2,244 21%
Production taxes. . . . . . . . . . 896 806 11% 1,759 1,744 1%
------ ------ ------ ------
Total production cost . . . . . . $2,201 $2,076 6% $4,473 $3,988 12%
====== ====== ==============
(PER MCFE)
Operating and maintenance expenses. $ 0.33 $ 0.33 - $ 0.33 $ 0.30 10%
Workover expenses . . . . . . . . . 0.04 0.09 (56%) 0.06 0.05 20%
Ad valorem taxes. . . . . . . . . . 0.05 $ 0.06 (17%) $ 0.05 $ 0.06 (17%)
------ ------ --------------
Lease operating expenses. . . . . $ 0.42 $ 0.48 (13%) $ 0.44 $ 0.41 7%
Production taxes. . . . . . . . . . 0.29 0.31 (6%) 0.29 0.32 (9%)
------ ------ --------------
Total production cost . . . . . . $ 0.71 $ 0.79 (10%) $ 0.73 $ 0.73 0%
====== ====== ==============
Lease operating expenses
- ------------------------
Lease operating expenses are comprised of several components which include:
the cost of labor and supervision to operate the wells and related equipment;
repairs and maintenance; related materials, supplies, fuel, and supplies
utilized in operating the wells and related equipment and facilities; insurance
applicable to wells and related facilities and equipment; workover cost; and ad
valorem taxes. Lease operating expenses are driven in part by the type of
commodity produced, the level of workover activity and the geographical location
of the properties. Oil is inherently more expensive to produce than natural gas.
Local taxing authorities such as school districts, cities, and counties or
boroughs generally impose the ad valorem taxes we pay. The amount of the tax is
based on the value of the property assessed or determined by the taxing
authority on an annual basis, and a percent of value. When oil and natural gas
commodity prices rise, the value of our underlying property interests increase.
This results in higher ad valorem taxes.
Lease operating expenses for the second quarter 2004 were 3% higher than
lease operating expenses in the second quarter 2003. The change was primarily
due to the following:
- - An increase in the number of producing wells during the second quarter 2004
combined with higher cost for compressor rental and maintenance, saltwater
disposal, electricity and fuel and contract pumping services resulted in a
17% increase in operating and maintenance expenses.
- - This increase was partially offset by a 50% decrease in workover costs.
On a per unit basis, lease operating expenses for the second quarter 2004
were 13% lower than in the same period of the prior year due to an increase in
production volumes.
22
Lease operating expenses for the first six months of 2004 were 21% higher
than lease operating expenses during the first six months of 2003. The change
was primarily due to the following:
- - An increase in the number of producing wells in the first six months of
2004 combined with higher cost for compressor rental and maintenance,
saltwater disposal, electricity and fuel, contract pumping services and
overhead resulted in a 27% increase in operating and maintenance expense.
- - A 14% increase in workover costs primarily due to workover activity in the
first quarter 2004.
On a per unit basis, lease operating expenses for the first six months of
2004 were 10% higher than per unit lease operating expenses in the same period
of the prior year. The increase in our per unit lease operating expense was
primarily due to the following:
- - An increase in compressor rental and maintenance expenses and overhead fees
resulted in a 10% increase in our per unit operating and maintenance
expenses.
- - An increase in workover costs primarily related to workovers performed in
the first quarter 2004 resulted in a 20% increase in our per unit workover
cost for the first six month of 2004.
Production taxes
- ----------------
There are a variety of state and federal taxes levied on the production of
our oil and natural gas. These are commonly grouped together and referred to as
production taxes. The majority of our production tax expense is based on a
percent of gross value at the well at the time the production is sold or removed
from the lease. As a result, our production tax expense increases with increases
in crude oil and natural gas commodity prices.
Historically, taxing authorities have occasionally encouraged oil and gas
industry to explore for new oil and natural gas reserves, or develop high cost
reserves through reduced tax rates or credits. These incentives have been narrow
in scope and short-lived. A small number of our wells currently qualify for
reduced production taxes because they are discoveries based on the use of 3-D
seismic or high cost wells.
A 17% increase in the average pre-hedge sales price that we received for
our oil and natural gas in the second quarter 2004 was the primary reason for
the increase production taxes for the second quarter 2004. This increase in
production taxes was partially offset by reduced tax rates or tax credits on
certain wells. Production taxes for the second quarter 2004 were 4.7% of revenue
from the sale of oil and natural gas before gains and losses due to hedging,
compared to 5.8% in the second quarter last year.
Production taxes for the first six months of 2004 were flat relative to
production taxes in the first six months of 2003. Production taxes for the first
six months of 2004 were 4.8% of revenue from the sale of oil and natural gas
before gains and losses due to hedging, compared to 5.5% in the first six months
of last year.
23
General and administrative expenses. We capitalize a portion of our general and
administrative costs. The costs capitalized represent the cost of technical
employees, who work directly on capital projects. An engineer designing a well
is an example of a technical employee working on a capital project. The cost of
a technical employee includes associated technical organization costs such as
supervision, telephone and postage. The following table presents general and
administrative expenses for the second quarter and first six months of 2004 and
2003.
THREE MONTHS ENDED, JUNE 30, SIX MONTHS ENDED, JUNE 30,
--------------------------- --------------------------
% %
2004 2003 CHANGE 2004 2003 CHANGE
------ ------ ------- ------ ------ -------
(IN THOUSANDS)
General and administrative expenses. $1,199 $1,187 1% $2,419 $2,326 4%
(PER MCFE)
General and administrative expenses. $ 0.39 $ 0.46 (15%) $ 0.39 $ 0.43 (9%)
General and administrative expenses for the second quarter of 2004 were
flat relative to general and administrative expenses in the second quarter last
year.
An increase in production volumes was the primary reason for the 15%
decrease in our second quarter 2004 general and administrative expenses on a per
unit basis.
General and administrative expenses for the first six months of 2004
increased by 4% over general and administrative expenses during the first six
months of 2003. The change in our general and administrative expenses for the
for the first six months of 2004 was due to the following:
- - An 8% increase in payroll and employee benefit expenses net of amounts
charged to joint ventures to cover the costs of managing these joint
operations represented 40% of the total increase.
- - An increase in expenses for external reserve engineering services and
outside legal services represented 19% and 6% of the total increase,
respectively.
- - Increases in expenses for corporate insurance represented 11% of the total
increase, for franchise taxes represented 8% of the total increase and for
software maintenance and supply represented 4% of the total increase.
- - These increases were partially offset by decrease in a 35% reduction in
financial reporting and director fees, a 26% reduction in fees for outside
consulting services and a 5% reduction in rent expense.
The 9 % decrease in general and administrative expenses on a per unit basis
for the first six months of 2004 was due the increase in production volumes for
the first six months of 2004.
24
Depletion of oil and natural gas properties. Our full-cost depletion expense is
driven by many factors including certain costs spent in the exploration and
development of producing reserves, production levels, and estimates of proved
reserve quantities and future developmental costs at the end of the year. The
following table presents depletion expense for the second quarter and first six
months of 2004 and 2003.
THREE MONTHS ENDED, JUNE 30, SIX MONTHS ENDED, JUNE 30,
--------------------------- --------------------------
% %
2004 2003 CHANGE 2004 2003 CHANGE
------ ------ ------- ------- ------ -------
(IN THOUSANDS)
Depletion of oil and natural gas properties. $5,623 $3,799 48% $10,503 $7,901 33%
(PER MCFE)
Depletion rate . . . . . . . . . . . . . . . $ 1.82 $ 1.46 25% $ 1.71 $ 1.46 17%
Increased production volumes combined with an increase in our per unit
depletion rate resulted in an 48% increase in our second quarter 2004 depletion
expense. Higher production volumes accounted for approximately 39% of the
increase in depletion expense while a 25% increase in our depletion rate
accounted for 61% of the increase. The increase in our depletion rate was
primarily the result of increased cost of reserve additions during the first
half of 2004.
Increased production volumes combined with an increase in our per unit
depletion rate resulted in an 33% increase in our depletion expense for the
first six months of 2004. Higher production volumes accounted for approximately
41% of the increase in depletion expense while a 17% increase in our depletion
rate accounted for 59% of the increase. The increase in our depletion rate was
primarily the result of increased cost of reserve additions during the first
half of 2004.
25
Net interest expense. We capitalize interest expense on borrowings associated
with major capital projects prior to their completion. Capitalized interest is
added to the cost of the underlying assets and is amortized over the lives of
the assets. The following table presents interest expense for the second
quarter and first six months of 2004 and 2003.
THREE MONTHS ENDED, JUNE 30, SIX MONTHS ENDED, JUNE 30,
----------------------------- ---------------------------
% %
2004 2003 CHANGE 2004 2003 CHANGE
-------- -------- -------- -------- -------- -------
(IN THOUSANDS)
Interest on senior credit facility. . . . . . . . . . . . $ 249 $ 509 (51%) $ 434 $ 1,145 (62%)
Interest on senior subordinated notes (a) . . . . . . . . 445 597 (25%) 884 1,180 (25%)
Commitment fees . . . . . . . . . . . . . . . . . . . . . 53 31 71% 107 35 206%
Dividend on Series A mandatorily redeemable
preferred stock (b) . . . . . . . . . . . . . . . . . 179 - - 354 - -
Amortization of deferred loan and debt issuance cost. . . 191 280 (32%) 383 533 (28%)
Other general interest expense. . . . . . . . . . . . . . 6 13 (54%) 14 28 (50%)
Capitalized interest expense. . . . . . . . . . . . . . . (269) (206) 31% (540) (415) 30%
-------- -------- ------------------
Net interest expense. . . . . . . . . . . . . . . . . . . $ 854 $ 1,224 (30%) $ 1,636 $ 2,506 (35%)
======== ======== ==================
Weighted average debt outstanding . . . . . . . . . . . . $62,674 $77,528 (19%) $58,673 $79,504 (26%)
Average interest rate on outstanding indebtedness (c) . . 5.9% 5.9% 6.1% 5.9%
(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. . . . . . . . . . . . . . . . . . . $ - $ 299 $ - $ 590
(b) Dividend on Series A preferred stock paid in kind
through the issuance of preferred stock in lieu of
cash. The dividend on our mandatorily redeemable
preferred stock in the second quarter and first
six months of 2003 was recorded as dividends in
dividends and accretion. Our option to pay
dividends in kind on our Series A preferred stock
expires in October 2005. . . . . . . . . . . . . . . 179 - 354 -
(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.
Net interest expense for the second quarter 2004 was 30% lower than
interest in the same quarter of the prior year. The change in interest expense
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 paid on those
outstanding borrowings resulted in a $260,000 decrease in net interest
expense. This decrease was offset by a $22,000 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
$152,000 decrease in net interest expense.
- - An increase in the amount of interest capitalized.
- - These decreases were partially offset by an increase in dividend related to
our mandatorily redeemable preferred stock. Upon our adoption of SFAS 150
in July 2003, we reclassified approximately $8 million of our then
outstanding mandatorily redeemable Series A and Series B preferred stock,
which had no equity conversion
26
features and must be settled with our assets, to long-term debt. As part of
this reclassification, we now report the dividends on the mandatorily
redeemable preferred stock that was reclassified as interest expense. Prior
to this reclassification, the dividend on our mandatorily redeemable
preferred stock was reported as dividends in dividend and accretion of
mandatorily redeemable preferred stock. Excluding the dividend and weighted
average mandatorily redeemable preferred balance outstanding for the second
quarter 2004, our average interest rate on outstanding indebtedness was
5.6%.
Net interest expense for the first six months of 2004 was 35% lower than
interest expense during the first six months of 2003. The change was 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 paid on those
borrowings resulted in a $711,000 decrease in net interest expense. This
decrease was offset by a $72,000 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
$296,000 decrease in net interest expense.
- - An increase in the amount of interest capitalized.
- - These decreases were partially offset by an increase in dividend related to
our manadatorily redeemable preferred stock. Excluding the dividend and
weighted average mandatorily redeemable preferred balance outstanding for
the first six months of 2004, our average interest rate on outstanding
indebtedness was 5.7%.
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, JUNE 30, SIX MONTHS ENDED, JUNE 30,
------------------------------------ ------------------------------------
% %
2004 2003 CHANGE 2004 2003 CHANGE
----------- ----------- ---------- ----------- ----------- ----------
(IN THOUSANDS)
Non-cash loss for ineffective portion of hedges. $ (187) $ (281) (33%) $ (60) $ (170) (65%)
Other income . . . . . . . . . . . . . . . . . . 69 - - 69 -
----------- ----------- ----------- -----------
Total other income (expense). . . . . . . . $ (118) $ (281) (58%) $ 9 $ (170) -
=========== =========== =========== ===========
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
$107.5 million, and our alternative minimum tax NOLs are $93.3 million. To
date, we have not utilized any of our NOLs. In future periods, our NOLs will be
used to offset taxable income.
Since 1997 through year-end 2003, we have not been required to recognize
any deferred income taxes. 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, we recognized deferred tax expense of
$5.2 million during the first six months of 2004.
27
Dividends and accretion of mandatorily redeemable preferred stock. We are
required to pay dividends on our Series A and were required to pay dividends on
our Series B preferred stock prior to its redemption. At our option, these
dividends 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, 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, was reclassified to
long-term debt. As part of the reclassification, the dividend paid on the
reclassified amount since July 2003 has been reported as interest expense.
In November and December 2003, CSFB Private Equity used a portion of our
mandatorily redeemable Series A and Series B preferred stock that it held to pay
for the exercise of the associated warrants. We also redeemed the remaining
balance of Series B preferred stock that was not used to pay for the exercise.
The following table shows the effect for the three and six month periods
ended June 30, 2004 and 2003, of the issuance of additional shares of preferred
stock in lieu of paying cash dividends.
THREE MONTHS ENDED, JUNE 30, SIX MONTHS ENDED, JUNE 30,
----------------------------- -----------------------------
% %
2004 2003 CHANGE 2004 2003 CHANGE
-------- --------- -------- -------- --------- --------
(IN THOUSANDS)
Dividends. . . . . . . . . . . . . . . . $ - $ 923 - $ - $ 1,817 -
Accretion of redeemable preferred stock. - 105 - - 206 -
-------- --------- -------- ---------
Total dividends and accretion . . . $ - $ 1,028 - $ - $ 2,023 -
======== ========= ======== =========
Additional preferred shares issued
Series A . . . . . . . . . . . . . . . . 8,924 35,905 (75%) 17,675 70,728 (75%)
Series B . . . . . . . . . . . . . . . . - 10,197 - - 20,087 -
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.
28
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.
Risk Factors Related to Our Business
- - Our level of indebtedness may adversely affect our cash available for
operations, thus limiting our growth, our ability to make interest and
principal payments on our indebtedness as they become due and our
flexibility to respond to market changes.
- - We have substantial capital requirements for which we may not be able to
obtain adequate financing.
- - Oil and natural gas prices fluctuate widely and low prices could have a
material adverse impact on our business and financial results by limiting
our liquidity and flexibility to accelerate our drilling program.
- - Our hedging transactions could reduce revenues in a rising commodity price
environment or expose us to other risks.
- - Exploratory drilling is a speculative activity that may not result in
commercially productive reserves and may require expenditures in excess of
budgeted amounts.
- - We are subject to various operating and other casualty risks that could
result in liability exposure or the loss of production and revenues.
- - We may not have enough insurance to cover all of the risks we face, which
could result in significant financial exposure.
- - We cannot control the activities on properties we do not operate and are
unable to ensure their proper operation and profitability.
- - The marketability of our natural gas production depends on facilities that
we typically do not own or control, which could result in a curtailment of
production and revenues.
- - Lower oil and natural gas prices may cause us to record ceiling limitation
write-downs which would reduce our stockholders' equity.
- - We have had operating losses in the past and may not be profitable in the
future.
- - Our future operating results may fluctuate and significant declines in them
would limit our ability to invest in projects.
- - The failure to replace reserves in the future would adversely affect our
production and cash flows.
- - We are subject to uncertainties in reserve estimates and future net cash
flows.
- - We face significant competition, and many of our competitors have resources
in excess of our available resources.
- - 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.
29
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.
30
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
June 30, 2004, the volumes associated with those contracts and the corresponding
weighted average NYMEX reference price by quarter.
2004 2005
---------------- ----------------------------------------
THIRD FOURTH FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER
------- -------- -------- -------- -------- ---------
NATURAL GAS SWAPS:
Volumes (MMbtu). . . . . . 138,000 92,000 - - - -
Average price ($per MMBtu) $ 4.180 $ 4.360 $ - $ - $ - $ -
NATURAL GAS COLLARS:
Volumes (MMbtu). . . . . . 722,200 586,100 517,500 455,000 - -
Average price ($per MMBtu)
Floor. . . . . . . . . . . $ 4.613 $ 4.746 $ 4.663 $ 4.725 $ - $ -
Ceiling. . . . . . . . . . 6.476 6.690 7.100 6.712 - -
The following table reflects our open oil derivative contracts at June 30,
2004, the associated volumes and the corresponding weighted average NYMEX
reference price by quarter.
2004 2005
------------------ --------------------------------------
THIRD FOURTH FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER
-------- -------- -------- -------- -------- --------
OIL SWAPS:
Volumes (Bbls) . . . . . 13,800 9,200 - - - -
Average price ($per Bbl) $ 23.91 $ 23.80 $ - $ - $ - $ -
OIL COLLARS:
Volumes (Bbls) . . . . . 48,760 34,260 27,450 18,655 - -
Average price ($per Bbl)
Floor. . . . . . . . . . $ 26.34 $ 26.38 $ 25.56 $ 26.80 $ - $ -
Ceiling. . . . . . . . . 32.20 31.71 30.18 32.51 - -
31
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.
32
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
June 1, 2004 - June 30, 2004 821 $ 8.560
No purchases were made under a publicly announced plan.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS
(a) We held our Annual Stockholders meeting on Thursday, June 3, 2004, in
Austin, Texas at 1 p.m. local time.
(b) Proxies were solicited by the Board of Directors of Brigham pursuant to
Regualtion 14A under the Securities Exchange Act of 1934. There were no
solicitations in opposition to the Board of Directors' nominees as listed
in the proxy statement and all of such nominees were duly elected.
(c) Out of the total 39,625,276 shares of our common stock and outstanding and
entitled to vote, 33,064,686 shares were present in person or by proxy,
representing approximately 83%. They only matters voted on by our
stockholders, as fully described in the definitive proxy materials for the
annual meeting, are set forth below. The results were as follows:
1. To elect eight directors to serve until the Annual Meeting of
Stockholders in 2005.
NUMBER OF SHARES
NUMBER OF SHARES NUMBER OF SHARES WITHHOLDING
VOTING FOR ELECTION AS VOTING AGAINST AUTHORITY TO VOTE FOR
NOMINEE DIRECTOR ELECTION AS DIRECTOR ELECTION AS DIRECTOR
- -------------------- ---------------------- -------------------- ---------------------
Ben M. "Bud" Brigham 28,588,524 4,476,162 -
David T. Brigham 28,521,124 4,476,162 -
Harold D. Carter 27,836,693 5,160,593 -
Stephen C. Hurley 32,097,666 967,020 -
Stephen P. Reynolds 32,097,666 967,020 -
Hobart A. Smith 32,036,066 967,020 -
Steven A. Webster 28,423,421 4,476,162 -
R. Graham Whaling 32,097,666 967,020 -
2. To approve the appointment of PricewaterhouseCoopers LLP as
independent auditors of Brigham for the year ending December 31, 2004.
For 32,752,485
Against 263,946
Abstained 48,255
33
3. To consider and vote on a proposal to approve an amendment to the 1997
Incentive Plan to increase the number of shares of common stock
available under the Plan.
For 18,629,721
Against 8,672,397
Abstained 104,645
Not Voted 5,657,923
34
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) 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 May 11, 2004 on Item 12, Brigham issued a press release
announcing its financial results for the first quarter 2004, and
provided its forecast for second quarter 2004 financial results.
35
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 August 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
36